10-Q 1 mehc9302003.txt MIDAMERICAN ENERGY HOLDINGS COMPANY 9/30/2003 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2003 Commission File No. 0-25551 MIDAMERICAN ENERGY HOLDINGS COMPANY ----------------------------------- (Exact name of registrant as specified in its charter) Iowa 94-2213782 ------------------------------- ------------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 666 Grand Avenue, Des Moines, Iowa 50309 ---------------------------------------- ----- (Address of principal executive offices) (Zip Code) (515) 242-4300 -------------- (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: N/A Securities registered pursuant to Section 12(g) of the Act: N/A Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [x] No [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [x] All of the shares of MidAmerican Energy Holdings Company are held by a limited group of private investors. As of October 31, 2003, 9,281,087 shares of common stock were outstanding. TABLE OF CONTENTS ----------------- PART I - FINANCIAL INFORMATION Item 1. Financial Statements............................................... 3 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations............................................19 Item 3. Quantitative and Qualitative Disclosures About Market Risk.........31 Item 4. Controls and Procedures............................................31 PART II - OTHER INFORMATION Item 1. Legal Proceedings..................................................32 Item 2. Changes in Securities and Use of Proceeds..........................32 Item 3. Defaults Upon Senior Securities....................................32 Item 4. Submission of Matters to a Vote of Security Holders................32 Item 5. Other Information..................................................32 Item 6. Exhibits and Reports on Form 8-K...................................32 SIGNATURES ...................................................................33 EXHIBIT INDEX.................................................................34 -2- PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS. INDEPENDENT ACCOUNTANTS' REPORT Board of Directors and Stockholders 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, 2003, and the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2003 and 2002, and of cash flows for the nine-month periods ended September 30, 2003 and 2002. These interim financial statements are the responsibility of the Company's management. We conducted our reviews 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 and 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 reviews, we are not aware of any material modifications that should be made to such consolidated interim 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, 2002, and the related consolidated statements of operations, stockholders' equity and cash flows for the year then ended (not presented herein); and in our report dated January 24, 2003, 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, 2002 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived. /s/ Deloitte & Touche LLP DELOITTE & TOUCHE LLP Des Moines, Iowa November 3, 2003 -3- MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED BALANCE SHEETS (In thousands)
AS OF ------------------------------ SEPTEMBER 30, DECEMBER 31, 2003 2002 ------------- ------------ (UNAUDITED) ASSETS Current assets: Cash and cash equivalents ........................................................ $ 754,416 $ 844,430 Restricted cash and short-term investments ....................................... 86,876 50,808 Accounts receivable, net ......................................................... 614,950 707,731 Inventories ...................................................................... 122,599 126,938 Other current assets ............................................................. 216,612 212,888 ----------- ----------- Total current assets ........................................................... 1,795,453 1,942,795 ----------- ----------- Properties, plants and equipment, net .............................................. 10,420,091 9,898,796 Goodwill ........................................................................... 4,258,175 4,258,132 Regulatory assets, net ............................................................. 534,650 415,804 Other investments .................................................................. 221,082 446,732 Equity investments ................................................................. 266,432 273,707 Deferred charges and other assets .................................................. 778,239 779,420 ----------- ----------- TOTAL ASSETS ....................................................................... $18,274,122 $18,015,386 =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable ................................................................. $ 299,510 $ 462,960 Accrued interest ................................................................. 216,203 192,015 Accrued taxes .................................................................... 39,098 75,097 Other accrued liabilities ........................................................ 518,133 457,058 Short-term debt .................................................................. 33 79,782 Current portion of long-term debt ................................................ 242,967 470,213 ----------- ----------- Total current liabilities ...................................................... 1,315,944 1,737,125 ----------- ----------- Parent company debt ................................................................ 2,776,850 2,323,387 Subsidiary and project debt ........................................................ 6,890,323 7,077,087 Deferred income taxes .............................................................. 1,363,122 1,238,421 Other long-term liabilities ........................................................ 1,279,646 1,100,917 ----------- ----------- Total liabilities ................................................................ 13,625,885 13,476,937 ----------- ----------- Deferred income .................................................................... 70,933 80,078 Minority interest .................................................................. 9,301 7,351 Company-obligated mandatorily redeemable preferred securities of subsidiary trusts . 1,871,643 2,063,412 Preferred securities of subsidiaries ............................................... 92,439 93,325 Commitments and contingencies (Notes 7 and 10) Stockholders' equity: Zero-coupon convertible preferred stock - authorized 50,000 shares, no par value, 41,263 shares outstanding ........................................................ - - Common stock - authorized 60,000 shares, no par value, 9,281 shares issued and - outstanding ...................................................................... - - Additional paid-in capital ......................................................... 1,956,887 1,956,509 Retained earnings .................................................................. 904,316 584,009 Accumulated other comprehensive loss ............................................... (257,282) (246,235) ----------- ----------- Total stockholders' equity ....................................................... 2,603,921 2,294,283 ----------- ----------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ......................................... $18,274,122 $18,015,386 =========== ===========
The accompanying notes are an integral part of these financial statements. -4- MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands)
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, ------------------------- ------------------------- 2003 2002 2003 2002 ---------- ---------- ---------- ---------- (UNAUDITED) REVENUE: Operating revenue ........................................... $1,476,851 $1,256,051 $4,385,925 $3,447,099 Income on equity investments ................................ 19,385 10,939 40,386 29,863 Interest and dividend income ................................ 6,747 21,770 39,932 40,865 Other income ................................................ 6,834 10,944 56,704 74,483 ---------- ---------- ---------- ---------- Total revenue ............................................. 1,509,817 1,299,704 4,522,947 3,592,310 ---------- ---------- ---------- ---------- COSTS AND EXPENSES: Cost of sales ............................................... 567,316 460,732 1,768,846 1,325,803 Operating expense ........................................... 399,185 343,303 1,123,470 948,913 Depreciation and amortization ............................... 135,693 129,362 438,324 386,531 Interest expense ............................................ 176,943 168,450 546,821 462,998 Capitalized interest ........................................ (2,921) (9,152) (26,069) (24,128) ---------- ---------- ---------- ---------- Total costs and expenses .................................. 1,276,216 1,092,695 3,851,392 3,100,117 ---------- ---------- ---------- ---------- INCOME BEFORE PROVISION FOR INCOME TAXES ...................... 233,601 207,009 671,555 492,193 Provision for income taxes .................................. 65,909 26,788 171,380 80,226 ---------- ---------- ---------- ---------- INCOME BEFORE MINORITY INTEREST AND PREFERRED DIVIDENDS ....... 167,692 180,221 500,175 411,967 Minority interest and preferred dividends ................... 57,962 45,344 179,868 105,167 ---------- ---------- ---------- ---------- NET INCOME AVAILABLE TO COMMON AND PREFERRED STOCKHOLDERS ..... $ 109,730 $ 134,877 $ 320,307 $ 306,800 ========== ========== ========== ==========
The accompanying notes are an integral part of these financial statements. -5- MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
NINE MONTHS ENDED SEPTEMBER 30, -------------------------- 2003 2002 ----------- ---------- (UNAUDITED) CASH FLOWS FROM OPERATING ACTIVITIES: Net income ......................................................................... $ 320,307 $ 306,800 Adjustments to reconcile net income to net cash flows from operating activities: Gains on disposals ............................................................... (10,174) (57,480) Distributions less income on equity investments .................................. 9,214 (14,828) Depreciation and amortization .................................................... 438,324 386,531 Amortization of deferred financing costs ......................................... 22,844 19,557 Amortization of regulatory assets and liabilities ................................ (8,781) 5,733 Provision for deferred income taxes .............................................. 184,508 40,518 Other ............................................................................ 33,182 15,810 Changes in other items: Accounts receivable and other current assets ................................... 126,264 (29,128) Accounts payable and other accrued liabilities ................................. (94,640) 11,881 Deferred income ................................................................ (7,775) (2,612) ----------- ----------- Net cash flows from operating activities ......................................... 1,013,273 682,782 ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures relating to operating projects ................................ (450,823) (328,544) Construction and other development costs ........................................... (435,413) (450,206) Acquisitions, net of cash acquired ................................................. (50,893) (1,463,314) Purchase of affiliate notes ........................................................ (35,029) - Sale (purchase) of convertible preferred securities ................................ 288,750 (275,000) Decrease in restricted cash and investments ........................................ 4,150 16,746 Proceeds from sales of assets ...................................................... 3,377 210,767 Other .............................................................................. (45,987) 25,895 ----------- ----------- Net cash flows from investing activities ......................................... (721,868) (2,263,656) ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from subsidiary and project debt .......................................... 1,148,719 780,142 Proceeds from parent company debt .................................................. 449,295 - Proceeds from issuance of trust preferred securities ............................... - 1,273,000 Proceeds from issuance of common and preferred stock ............................... - 402,000 Net proceeds on parent company short-term debt ..................................... - 13,500 Repayments of subsidiary and project debt .......................................... (1,389,872) (377,644) Repayment of parent company debt ................................................... (215,000) - Purchase and retirement of preferred securities of subsidiary trusts ............... (198,958) - Net repayment of subsidiary short-term debt ........................................ (79,750) (77,585) Redemption of preferred securities of subsidiaries ................................. (882) (127,613) Increase in restricted cash ........................................................ (35,974) (25,901) Other .............................................................................. (72,537) (44,999) ----------- ----------- Net cash flows from financing activities ......................................... (394,959) 1,814,900 ----------- ----------- Effect of exchange rate changes .................................................... 13,540 41,290 ----------- ----------- NET CHANGE IN CASH AND CASH EQUIVALENTS .............................................. (90,014) 275,316 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ..................................... 844,430 386,745 ----------- ----------- CASH AND CASH EQUIVALENTS AT END OF PERIOD ........................................... $ 754,416 $ 662,061 =========== =========== SUPPLEMENTAL DISCLOSURE: Interest paid on debt, net of interest capitalized ................................. $ 489,051 $ 404,288 =========== =========== Income taxes paid .................................................................. $ 7,376 $ 55,437 =========== ===========
The accompanying notes are an integral part of these financial statements. -6- MIDAMERICAN ENERGY HOLDINGS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. GENERAL In the opinion of management of MidAmerican Energy Holdings Company and subsidiaries ("MEHC" or 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, 2003, and the results of operations for the three-month and nine-month periods ended September 30, 2003 and 2002, and of cash flows for the nine-month periods ended September 30, 2003 and 2002. The results of operations for the three-month and nine-month periods ended September 30, 2003 are not necessarily indicative of the results to be expected for the full year. The unaudited 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 prior year financial statements and supporting note disclosures have been reclassified to conform to the current year presentation. Such reclassifications did not impact previously reported net income or retained earnings. The unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. 2. NEW ACCOUNTING PRONOUNCEMENTS Effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards ("SFAS') No. 143, "Accounting for Asset Retirement Obligations". This statement provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. The cumulative effect of initially applying this statement by the Company was immaterial. The Company's review of its regulated entities identified legal retirement obligations for nuclear decommissioning, wet and dry ash landfills and offshore and minor lateral pipeline facilities. On January 1, 2003, the Company recorded $289.3 million of asset retirement obligation ("ARO") liabilities; $13.9 million of ARO assets, net of accumulated depreciation; $114.6 million of regulatory assets; and reclassified $1.0 million of accumulated depreciation to the ARO liability. The initial ARO liability recognized includes $266.5 million that pertains to obligations associated with the decommissioning of the Quad Cities nuclear station. The $266.5 million includes a $159.8 million nuclear decommissioning liability that had been recorded at December 31, 2002. The adoption of this statement did not have a material impact on the operations of the regulated entities, as the effects were offset by the establishment of regulatory assets, totaling $114.6 million, pursuant to SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation". During the nine-month period ended September 30, 2003, the Company recorded, as a regulatory asset, accretion related to the ARO liability of $12.5 million, resulting in an ARO liability balance of $301.8 million at September 30, 2003. On April 30, 2003, the Financial Accounting Standards Board ("FASB") issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" ("SFAS 149"). SFAS 149 amends SFAS No. 133 for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. SFAS 149 also amends certain other existing pronouncements. It will require contracts with comparable characteristics to be accounted for similarly. In particular, SFAS 149 clarifies when a contract with an initial net -7- investment meets the characteristic of a derivative and clarifies when a derivative that contains a financing component will require special reporting in the statement of cash flows. SFAS 149 is effective for the Company for contracts entered into or modified after June 30, 2003. The adoption of SFAS 149 did not have a material effect on the Company's financial position, results of operations or cash flows. In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" ("SFAS 150"). SFAS 150 established standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). The standard is effective for the Company for fiscal periods beginning after December 15, 2003. The Company is currently evaluating certain financial instruments in order to determine if SFAS 150 will impact their classification. In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities" ("FIN 46"). On October 8, 2003, the FASB deferred the implementation of FIN 46 to the fourth quarter of 2003. The Company is currently evaluating certain investments in order to determine if FIN 46 will impact their classification. 3. PROPERTIES, PLANTS AND EQUIPMENT, NET Properties, plants and equipment, net comprise the following (in thousands):
SEPTEMBER 30, DECEMBER 31, 2003 2002 ------------ ------------ Properties, plants and equipment, net: Utility generation and distribution systems ....... $ 8,514,747 $ 8,165,140 Interstate pipelines' assets ...................... 3,456,825 2,260,799 Independent power plants .......................... 1,421,375 1,410,170 Mineral and gas reserves and exploration assets ... 540,790 500,422 Utility non-operational assets .................... 402,192 370,811 Other assets ...................................... 143,147 131,577 ------------ ------------ Total operating assets .......................... 14,479,076 12,838,919 Accumulated depreciation and amortization ......... (4,508,944) (4,110,608) ------------ ------------ Net operating assets .............................. 9,970,132 8,728,311 Construction in progress .......................... 449,959 1,170,485 ------------ ------------ Properties, plants and equipment, net ............... $ 10,420,091 $ 9,898,796 ============ ============
Construction in Progress ------------------------ Kern River Gas Transmission Company ("Kern River") completed the construction of its expansion for which it filed an application with the Federal Energy Regulatory Commission on August 1, 2001 (the "2003 Expansion Project") at a total cost of approximately $1.2 billion. The expansion, which was placed into operation on May 1, 2003, increased the design capacity of the existing Kern River pipeline by 885,626 decatherms ("dth") per day to 1,755,626 dth per day. 4. INVESTMENT IN CE GENERATION The equity investment in CE Generation LLC ("CE Generation") at September 30, 2003 and December 31, 2002 was approximately $232.4 million and $244.9 million, respectively. During the three-month periods ended September 30, 2003 and 2002, the Company recorded income from its investment in CE Generation of $11.4 million and $12.4 million, respectively. During the nine-month periods ended September 30, 2003 and 2002, the Company recorded income from its investment in CE Generation of $19.0 million and $21.2 million, respectively. -8- 5. DEBT ISSUANCES AND REDEMPTIONS On January 14, 2003, MidAmerican Energy Company ("MidAmerican Energy") issued $275.0 million of 5.125% medium-term notes due in 2013. The proceeds were used to refinance existing debt and for other corporate purposes. On May 1, 2003, Kern River Funding Corporation, a wholly owned subsidiary of Kern River, issued $836 million of its 4.893% Senior Notes with a final maturity on April 30, 2018. The proceeds were used to repay all of the approximately $815 million of outstanding borrowings under Kern River's $875 million credit facility. Kern River entered into this credit facility in 2002 to finance the construction of the 2003 Expansion Project. The credit facility was canceled and a completion guarantee issued by the Company in favor of the lenders as part of the credit facility terminated upon completion of the 2003 Expansion Project. On May 16, 2003, the Company issued $450 million of its 3.5% Senior Notes with a final maturity on May 15, 2008. The proceeds were used for general corporate purposes. On May 23, 2003, the Company terminated a $150 million credit facility, and reduced a separate $250 million credit facility to $100 million. The remaining $100 million facility was due to expire on June 23, 2003. On June 6, 2003, the Company terminated the $100 million facility and closed on a new $100 million revolving credit facility which expires on June 6, 2006. On June 9, 2003, Yorkshire Power Group Limited, a wholly owned subsidiary of MEHC, completed the redemption in full of the outstanding shares of the Yorkshire Capital Trust I, 8.08% trust securities, due June 30, 2038, and paid $243.4 million in principal amount ($25 liquidation amount per each trust security) plus accrued distributions of $0.381555555 per trust security to the redemption date. The redemption price was paid to holders of the trust security on the redemption date. At December 31, 2002, $249.7 million of the 8.08% trust securities and related fair value adjustments were included in subsidiary and project debt. 6. OTHER INVESTMENTS On June 10, 2003, The Williams Companies, Inc. ("Williams") repurchased, for approximately $289 million, plus accrued dividends, all of the shares of its 9-7/8% Cumulative Convertible Preferred Stock originally acquired by MEHC in March 2002 for $275 million. 7. COMMITMENTS AND CONTINGENCIES MidAmerican Energy Manufactured Gas Plants ------------------------------------------ The United States Environmental Protection Agency ("EPA") and the 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 such 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 a health or environmental risk, and whether MidAmerican Energy has any responsibility for remedial action. MidAmerican Energy is actively working with the regulatory agencies and has received regulatory closure on four sites. MidAmerican Energy is continuing to evaluate several of the sites to determine the future liability, if any, for conducting site investigations or other site activity. MidAmerican Energy estimates the range of possible costs for investigation, remediation and monitoring for the sites discussed above to be approximately $15 million to $54 million. As of September 30, 2003, MidAmerican Energy has recorded a $15.9 million liability for these sites and a corresponding regulatory asset for future -9- recovery through the regulatory process. MidAmericanEnergy projects that these amounts will be incurred or paid over the next four years. The estimated liability is determined through a site-specific cost evaluation process. First, a determination is made as to whether MidAmerican Energy has potential legal liability for a site and whether information exists to indicate that contaminated wastes remain at the site. If so, the costs of performing a preliminary investigation and the costs of removing known contaminated soil are accrued. If it is determined during the preliminary investigation that remedial action is required, then the best estimate of the costs is accrued. The estimate includes incremental direct costs of remediation, site monitoring costs and costs of compensation to employees for time expected to be spent directly on the remediation effort. The estimated recorded liabilities for these properties are based upon preliminary data. Thus, actual costs could vary significantly from the estimates. The estimate 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 ("IUB"), and are recorded as a regulatory liability. Although the timing of potential incurred costs and recovery of such 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 MidAmerican Energy's financial position, results of operations or cash flows. MidAmerican Energy Air Quality ------------------------------ 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, the 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 monitored data to determine attainment status. The impact of the standards on MidAmerican Energy 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, 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 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 the Clear Skies Initiative 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. On April 1, 2002, in accordance with Iowa law passed in 2001, MidAmerican Energy filed with the IUB its first multi-year plan and budget for managing regulated emissions from its generating facilities in a cost-effective manner. An administrative law judge issued a ruling approving MidAmerican Energy's plan but disallowing the proposed recovery of plan costs through a tracker mechanism. MidAmerican Energy and the Iowa Office of Consumer Advocate each appealed the administrative law judge's ruling. On July 17, 2003, the IUB issued an order affirming the administrative law judge's decision. Accordingly, the IUB has rejected the future application of a tracker mechanism to recover emission reduction costs. However, the approved expenditures will not be subject to a subsequent prudence review in a future electric rate case. -10- In recent years, the EPA has requested from several utilities information and support regarding their capital projects for various generating plants. The requests were issued as part of an industry-wide investigation to assess compliance with the New Source Review and the New Source Performance Standards of the Clean Air Act. In December 2002 and April 2003, MidAmerican Energy received requests from the EPA to provide documentation related to its capital projects from January 1, 1980, to the present for a number of its generating plants. MidAmerican Energy has submitted information to the EPA in responses to these requests, and there are currently no outstanding data requests pending from the EPA. MidAmerican Energy cannot predict the outcome of these requests at this time. MidAmerican Energy Nuclear Decommissioning Costs ------------------------------------------------ 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 to safely remove the facility from service and restore the property to a condition allowing unrestricted use by the operator. MidAmerican Energy currently contributes $8.3 million annually to external trusts established for the investment of funds for decommissioning Quad Cities Station. Approximately 65% of the fair value of the trusts' funds is now invested in domestic corporate debt and common equity securities. The remainder is invested in investment grade municipal and U.S. Treasury bonds. Funding for the Quad Cities Station nuclear decommissioning is reflected as depreciation expense in the Consolidated Statements of Operation. Quad Cities Station decommissioning costs charged to Iowa customers are included in base rates, and recovery of increases in those amounts must be sought through the normal ratemaking process. Kern River and Northern Natural Gas 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. On October 9, 2002, the United States District Court for the District of Wyoming dismissed Grynberg's royalty valuation claims. On November 19, 2002, the United States District Court for the District of Wyoming denied Grynberg's motion for clarification and dismissed his royalty valuation claims. Grynberg appealed this dismissal to the United States Court of Appeals for the Tenth Circuit and on May 13, 2003, the Tenth Circuit Court dismissed his appeal. In connection with the purchase of Kern River from Williams in March 2002, Williams agreed to indemnify MEHC 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. The Company believes 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 indemnification, and Northern Natural Gas, intend 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 -11- 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. The court denied this motion. 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. On January 13, 2003, oral arguments were heard on coordinating defendants' opposition to class certification. On April 10, 2003, the court entered an order denying the plaintiffs' motion for class certification. On May 12, 2003, the plaintiffs filed a motion for leave to file a fourth amended petition alleging a class of gas royalty owners in Kansas, Colorado and Wyoming. The court granted the motion for leave to amend on July 28, 2003. Kern River was not a named defendant in the amended complaint and has been dismissed from the action. Northern Natural Gas filed an answer on the fourth amended petition on August 22, 2003. Williams has agreed to indemnify MEHC 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. Similar to the June 8, 2001 matter referenced above, the plaintiffs have filed a new companion action against a number of parties, including Northern Natural Gas but excluding Kern River, in a Kansas state district court for damages for mismeasurement of British thermal unit content, resulting in lower royalties. The action was filed on May 12, 2003, shortly after the state district court dismissed the plaintiffs' third amended petition in the original litigation which sought to certify a nationwide class. The new companion action which seeks to certify a class of royalty owners in Kansas, Colorado and Wyoming, tracking the fourth amended petition in the action referenced above, was not served until August 4, 2003. A motion to dismiss was filed on August 25, 2003. On October 9, 2003, the state district court denied the motion to dismiss; Northern Natural Gas' answer date is November 10, 2003. Northern Natural Gas believes that this claim is without merit and that Northern Natural Gas' gas measurement techniques have been in accordance with industry standards and its tariff. Philippines ----------- Casecnan Construction Contract The CE Casecnan Water and Energy Company, Inc. ("CE Casecnan") Project (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, CE Casecnan terminated the Hanbo Contract due to defaults by Hanbo and HECC including the insolvency of both companies. On the same date, CE Casecnan 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 was conducted by a consortium consisting of Cooperativa Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa. (collectively, the "Contractor"), working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd. 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 lenders' independent engineer under the Trust Indenture. On February 12, 2001, the Contractor filed a Request for Arbitration with the International Chamber of Commerce ("ICC") seeking schedule relief of 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 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 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 in -12- December 2001 amounted to a repudiation of the Replacement Contract and has filed a claim for unspecified quantum meruit damages, and has further alleged that the delay liquidated damages clause which provides for payments of $125,000 per day for each day of delay in completion of the Casecnan Project for which the Contractor is responsible is unenforceable. The arbitration is being conducted applying New York law and pursuant to the rules of the ICC. Hearings have been held in connection with this arbitration in July 2001, September 2001, January 2002, March 2002, November 2002, January 2003 and July 2003. 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, 2003, 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. The $6.0 million was recorded as a reduction in construction costs. On November 7, 2002, the ICC 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. The $3.8 million is shown as part of the other accrued liabilities balance at September 30, 2003 and December 31, 2002. All of the Contractor's other claims with respect to force majeure and geologic conditions were denied. If the Contractor were to prevail on its claim that the delay liquidated damages clause is unenforceable, CE Casecnan would not be entitled to collect such delay damages for the period from March 31, 2001 through December 11, 2001. If the Contractor were to prevail in its repudiation claim and prove quantum meruit damages in excess of amounts paid to the Contractor, CE Casecnan could be liable to make additional payments to the Contractor. CE Casecnan believes all of such allegations and claims are without merit and is vigorously contesting the Contractor's claims. Casecnan Stockholder Litigation Pursuant to the share ownership adjustment mechanism in the CE Casecnan stockholder agreement, which is based upon pro forma financial projections of the Casecnan Project prepared following commencement of commercial operations, in February 2002, MEHC through its indirect wholly owned subsidiary CE Casecnan Ltd., advised the minority stockholder, LaPrairie Group Contractors (International) Ltd. ("LPG"), that MEHC's 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, among others, CE Casecnan Ltd. and MEHC. In the complaint, LPG seeks compensatory and punitive damages for alleged breaches of the stockholder agreement and alleged breaches of fiduciary duties allegedly owed by CE Casecnan Ltd. and MEHC 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 CE Casecnan cannot be determined at this time. In February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. ("San Lorenzo"), an original shareholder substantially all of whose shares in CE Casecnan were purchased by MEHC in 1998, threatened to initiate legal action in the Philippines in connection with certain aspects of its option to repurchase such shares on or prior to commercial operation of the Casecnan Project. CE Casecnan believes that San Lorenzo has no valid basis for any claim and, if named as a defendant in any action that may be commenced by San Lorenzo, will vigorously defend such action. -13- 8. COMPREHENSIVE INCOME The differences from net income to total comprehensive income for the Company are due to minimum pension liability adjustments, 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 Company is shown in the table below (in thousands):
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, ----------------------- ---------------------- 2003 2002 2003 2002 -------- -------- -------- -------- Net income .......................................................... $109,730 $134,877 $320,307 $306,800 Other comprehensive income: Minimum pension liability adjustment, net of tax of $(220); $0; $(1,685) and $0, respectively ............. (514) - (3,931) - Foreign currency translation ...................................... 5,117 39,437 (19,095) 120,905 Marketable securities, net of tax of $160; $221; $382 and $(1,902), respectively ........................................ 240 332 565 (3,337) Cash flow hedges, net of tax of $(1,367); $(1,560); $5,048 and $(10,685), respectively ....................................... (3,245) (3,694) 11,414 (24,496) -------- -------- -------- -------- Total comprehensive income .......................................... $111,328 $170,952 $309,260 $399,872 ======== ======== ======== ========
-14- 9. SEGMENT INFORMATION The Company has identified seven reportable operating segments based on management structure: MidAmerican Energy, Kern River, Northern Natural Gas, CE Electric UK Funding, Inc. ("CE Electric UK"), CalEnergy Generation-Domestic, CalEnergy Generation-Foreign, and HomeServices of America, Inc. ("HomeServices"). Information related to the Company's reportable operating segments is shown below (in thousands):
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, ------------------------- ------------------------- 2003 2002 2003 2002 ---------- ---------- ---------- ---------- OPERATING REVENUE: MidAmerican Energy ................................... $ 577,281 $ 556,284 $1,929,637 $1,625,175 Kern River ........................................... 78,793 39,867 182,267 87,048 Northern Natural Gas ................................. 77,869 39,098 333,052 39,098 CE Electric UK ....................................... 188,143 193,360 602,334 596,958 CalEnergy Generation - Domestic ...................... 12,237 13,717 34,441 27,627 CalEnergy Generation - Foreign ....................... 89,245 84,227 246,137 234,686 HomeServices ......................................... 459,007 340,692 1,112,627 855,919 ---------- ---------- ---------- ---------- Segment operating revenue .......................... 1,482,575 1,267,245 4,440,495 3,423,945 Corporate/other ...................................... (5,724) (11,194) (54,570) (19,412) ---------- ---------- ---------- ---------- Total operating revenue ............................ $1,476,851 $1,256,051 $4,385,925 $3,447,099 ========== ========== ========== ========== INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES: MidAmerican Energy ................................... $ 104,683 $ 108,577 $ 241,809 $ 218,565 Kern River ........................................... 36,234 16,774 98,367 39,387 Northern Natural Gas ................................. (4,517) (1,015) 69,308 (1,015) CE Electric UK ....................................... 59,475 39,968 204,761 197,223 CalEnergy Generation - Domestic ...................... 4,903 14,649 (2,912) 12,983 CalEnergy Generation - Foreign ....................... 38,379 40,208 109,722 103,994 HomeServices ......................................... 44,518 26,475 91,216 52,506 ---------- ---------- ---------- ---------- Segment income before provision for income taxes ... 283,675 245,636 812,271 623,643 Corporate/other ...................................... (50,074) (38,627) (140,716) (131,450) ---------- ---------- ---------- ---------- Total income before provision for income taxes ..... $ 233,601 $ 207,009 $ 671,555 $ 492,193 ========== ========== ========== ==========
SEPTEMBER 30, DECEMBER 31, 2003 2002 ------------- ------------ TOTAL ASSETS: MidAmerican Energy .................................... $ 6,159,531 $ 6,025,452 Kern River ............................................ 2,175,979 1,797,850 Northern Natural Gas .................................. 2,161,061 2,162,367 CE Electric UK ........................................ 4,664,205 4,714,459 CalEnergy Generation - Domestic ....................... 887,159 881,633 CalEnergy Generation - Foreign ........................ 991,987 974,852 HomeServices .......................................... 627,798 488,324 ----------- ----------- Segment total assets ................................ 17,667,720 17,044,937 Corporate/other ....................................... 606,402 970,449 ----------- ----------- Total assets ........................................ $18,274,122 $18,015,386 =========== ===========
The remaining differences from the segment amounts to the consolidated amounts described as "Corporate/other" relate principally to the corporate functions including administrative costs, corporate cash and related interest income, intersegment eliminations, and fair value adjustments relating to acquisitions. Total assets by segment includes the allocation of goodwill. -15- Goodwill as of December 31, 2002 and changes for the period from January 1, 2003 through September 30, 2003 by segment are as follows (in thousands):
Northern CalEnergy MidAmerican Kern Natural CE Electric Generation- Home- Energy River Gas UK Domestic Services Total ----------- ------- -------- ----------- ----------- -------- ---------- Goodwill at December 31, 2002.... $2,149,282 $32,547 $414,721 $1,195,321 $126,440 $339,821 $4,258,132 Goodwill from acquisitions during the year ............. - - - - - 23,631 23,631 Other goodwill adjustments(1).. - 1,353 (24,457) (484) - - (23,588) ---------- ------- -------- ---------- -------- -------- ---------- Goodwill at September 30, 2003... $2,149,282 $33,900 $390,264 $1,194,837 $126,440 $363,452 $4,258,175 ========== ======= ======== ========== ======== ======== ==========
(1) Other goodwill adjustments include deferred tax, foreign currency translation and purchase price adjustments. The Company completed the allocation of the Kern River purchase price, to the assets and liabilities acquired, during the first quarter of 2003 and the Northern Natural Gas purchase price, to the assets and liabilities acquired, during the third quarter of 2003. 10. SUBSEQUENT EVENT Casecnan NIA Arbitration Settlement ----------------------------------- Under the terms of the CE Casecnan Project Agreement (the "Project Agreement"), the Philippine National Irrigation Administration ("NIA") had the option of timely reimbursing CE Casecnan directly for certain taxes CE Casecnan paid. If NIA did not so reimburse CE Casecnan, certain taxes paid by CE Casecnan would result in an increase in the Water Delivery Fee. The payment of certain other taxes by CE Casecnan would have resulted automatically in an increase in the Water Delivery Fee. As of September 30, 2003, CE Casecnan had paid approximately $59.1 million in taxes, which pursuant to the foregoing provisions resulted in an increase in the Water Delivery Fee. NIA failed to pay the portion of the Water Delivery Fee each month related to the payment of these taxes by CE Casecnan. As a result of the non-payment of the tax compensation portion of the Water Delivery Fees, on August 19, 2002, CE Casecnan filed a Statement of Claim against NIA pursuant to the Rules of Arbitration of the ICC (the "NIA Arbitration"), seeking payment of such portion of the Water Delivery Fee and enforcement of the relevant provision of the Project Agreement going forward. The NIA Arbitration was conducted in accordance with the rules of the ICC. NIA filed its Answer and Counterclaim on March 31, 2003. In its Answer, NIA asserted, among other things, that most of the taxes which CE Casecnan had factored into the Water Delivery Fee compensation formula did not fall within the scope of the relevant section of the Project Agreement, that the compensation mechanism itself was invalid and unenforceable under Philippine law and that the Project Agreement was inconsistent with the Philippine build-operate-transfer law. As such, NIA sought dismissal of CE Casecnan's claims and a declaration from the arbitral tribunal that the taxes which have been taken into account in the Water Delivery Fee compensation mechanism were not recoverable thereunder and that, at most, certain taxes may be directly reimbursed (rather than compensated for through the Water Delivery Fee) by NIA. NIA also counterclaimed for approximately $7 million which it alleges is due to it as a result of the delayed completion of the Casecnan Project. On April 23, 2003, NIA filed a Supplemental Counterclaim in which it asserted that the Project Agreement was contrary to Philippine law and public policy and by way of relief sought a declaration that the Project Agreement was void from the beginning or should be cancelled, or alternatively, an order for reformation of the Project Agreement or any portions or sections thereof which may be determined to be contrary to such law and or public policy. On May 23, 2003 CE Casecnan filed its reply to NIA's counterclaims. On October 15, 2003, CE Casecnan closed a transaction settling the NIA Arbitration. In connection with the settlement, CE Casecnan entered into an agreement (the "Supplemental Agreement") with NIA which, in addition -16- to providing for the dismissal with prejudice of all claims by CE Casecnan and counterclaims by NIA in the NIA Arbitration, supplements and amends the Project Agreement in certain respects as summarized below: Payment in Cash and Delivery of Note As part of the settlement, on October 15, 2003, NIA paid to CE Casecnan the sum of $17.7 million plus Philippine pesos of 39.9 million (approximately $0.7 million) and delivered to CE Casecnan the Republic of the Philippines ("ROP") $97.0 million 8.375% Note due 2013 (the "ROP Note"). Also at closing, CE Casecnan paid to the Philippine Bureau of Internal Revenue ("BIR") approximately $24.4 million in respect of Philippine income taxes on the foregoing consideration. The ROP Note is governed by New York law and constitutes a direct, unconditional, unsecured and general obligation of the ROP. The ROP Note is non-transferable until January 15, 2004, but may be exchanged, at the option of the ROP, for a new note forming part of a series of direct, unconditional, unsecured and general debt obligations of the Philippines with a yield of 8.375% or lower. If the Philippines issues a series of direct, unconditional, unsecured and general debt obligations having a yield in excess of 8.375%, CE Casecnan has agreed to accept a series of such new debt with a yield no greater than 8.375%. If not exchanged prior to January 15, 2004, CE Casecnan has the option, between January 15, 2004 and February 15, 2004, to put the ROP Note to the ROP for a price of par plus accrued interest. The ROP Note has default provisions substantially identical to those set forth in other recent issuances of direct, unconditional, unsecured and general obligation of the ROP. Modifications to Water Delivery Fee Under the Project Agreement, the Water Delivery Rate increased by $0.00043 per cubic meter for each $1,000,000 of certain taxes paid by CE Casecnan. The Supplemental Agreement amends the per cubic meter Water Delivery Fee calculation by eliminating this increase, such that the per cubic meter Water Delivery Rate remains at $0.029 per cubic meter, escalated at 7.5% annually from January 1, 1994 through the first five years of the Cooperation Period, extending through December 25, 2006. In lieu of such increase, CE Casecnan will be reimbursed for certain taxes it pays during the remainder of the Cooperation Period. Under the Project Agreement, the Water Delivery Fee payable monthly was a fixed monthly payment based on an average water delivery of 801.9 million cubic meters per year, pro-rated to approximately 66.8 million cubic meters per month, multiplied by the per cubic meter rate as described above. Under the Supplemental Agreement the Water Delivery Fee is equal to the Guaranteed Water Delivery Fee plus the Variable Delivered Water Delivery Fee minus the Water Delivery Fee Credit. Guaranteed Water Delivery Fee. For the sixty-month period from December 25, 2003 through December 25, 2008, the Guaranteed Water Delivery Fee shall equal the Water Delivery Rate, as described above, multiplied by approximately 66.8 million cubic meters (corresponding to the 801.9 million cubic meters per year). For each month beginning after December 25, 2008 through the remainder of the Cooperation Period, the Guaranteed Water Delivery Fee shall equal the Water Delivery Rate multiplied by approximately 58.3 million cubic meters (corresponding to 700.0 million cubic meters per year). Variable Delivered Water Delivery Fee. Variable Delivered Water Delivery Fees will be earned for months beginning after December 25, 2008. For each month beginning after December 25, 2008 through the end of the Cooperation Period, the Variable Delivered Water Delivery Fee shall be payable only from the date when the cumulative Total Available Water (total delivered water plus the water volume not delivered to NIA as a result of NIA's failure to accept energy deliveries at a capacity up to 150 MW) for each contract year exceeds 700.0 million cubic meters. Variable Delivered Water Delivery Fees will be earned up to an aggregate maximum of 1,324.7 million cubic meters for the period from December 25, 2008 through the end of the Cooperation Period. No additional variable water delivery fees will be earned over the 1,324.7 million cubic meter threshold. Water Delivery Credit. The Water Delivery Credit shall be applicable only for each of the sixty-months from December 25, 2008 through December 25, 2013 and shall equal the Water Delivery Rate as of December 25, -17- 2008 multiplied by the sum of each Annual Water Credit divided by sixty. The Annual Water Credit for each contract year starting from December 25, 2003 and ending on December 25, 2008 shall equal 801.9 million cubic meters minus the Total Available Water for each contract year. The Total Available Water in any such year will equal actual deliveries with a minimum threshold of 700.0 million cubic meters. Modifications to Excess Energy Delivery Fee Under the Project Agreement, the Excess Energy Delivery Fee was a variable amount based on actual electrical energy delivered in each month in excess of 19 gigawatt-hour ("GWh"), payable at a rate of $0.1509 per kilowatt-hour ("kWh"). Under the Supplemental Agreement, the per kWh rate for energy deliveries in excess of 19 GWh per month has been reduced, commencing in 2009, to $0.1132 (escalating at 1% per annum thereafter), provided that any deliveries of energy in excess of 490 GWh but less than 550 GWh per year are paid for at a rate of 1.3 Philippine pesos per kWh and deliveries in excess of 550 GWh per year are at no cost to NIA. The Supplemental Agreement provides that the unpaid portion of the excess energy available for generation, but not generated from the commencement of commercial operations through September 28, 2003 will not be paid. For periods after September 28, 2003, the Supplemental Agreement provides that if the Casecnan project is not dispatched up to 150 MW whenever water is available, NIA will pay for excess energy that could have been generated but was not as a result of such dispatch constraint. Other Provisions of the Supplemental Agreement In connection with the settlement of the NIA Arbitration and as part of the Supplemental Agreement transaction, CE Casecnan paid to NIA $1.6 million in respect of alleged late completion of the Project. This amount had been accrued as of September 30, 2003 and December 31, 2002. In addition, CE Casecnan received opinions from the Philippine Office of Government Corporate Counsel as to the due authorization and enforceability of Supplemental Agreement and received confirmation from the Philippine Department of Finance that the ROP Note had been duly and validly issued and was enforceable in accordance with its terms. CE Casecnan also received an opinion from Allen & Overy, counsel to the Republic of the Philippines, as to the enforceability of the ROP Note under New York law. CE Casecnan also received written confirmation from the Private Sector Assets and Liabilities Management Corporation that the issues with respect to the Casecnan Project that had been raised by the interagency review of independent power producers in the Philippines or that may have existed with respect to the Project under the Electric Power Industry Reform Act of 2001 have been satisfactorily addressed by the Supplemental Agreement. The Guaranteed Energy Delivery Fee, Force Majeure, Buyout and Dispute Resolution provisions of the Project Agreement, as well as the Performance Undertaking provided by the ROP, remain unaffected by the Supplemental Agreement and are in full force and effect. -18- ITEM 2. 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 ("MEHC" or the "Company"), during the periods included in the accompanying statements of operations. This discussion should be read in conjunction with the Company's historical financial statements and the notes to those statements. The Company's actual results in the future could differ significantly from the historical results. FORWARD-LOOKING STATEMENTS From time to time, MEHC may make forward-looking statements within the meaning of the federal securities laws that involve judgments, assumptions and other uncertainties beyond the control of the Company or any of its subsidiaries individually. These forward-looking statements may include, among others, statements concerning revenue and cost trends, cost recovery, cost reduction strategies and anticipated outcomes, pricing strategies, changes in the utility industry, planned capital expenditures, financing needs and availability, statements of MEHC's expectations, beliefs, future plans and strategies, anticipated events or trends and similar comments concerning matters that are not historical facts. These types of forward-looking statements are based on current expectations and involve a number of known and unknown risks and uncertainties that could cause the actual results and performance of the Company to differ materially from any expected future results or performance, expressed or implied, by the forward-looking statements. In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, MEHC has identified important factors that could cause actual results to differ materially from those expectations, including weather effects on revenues and other operating uncertainties, uncertainties relating to economic and political conditions and uncertainties regarding the impact of regulations, changes in government policy and competition. The Company does not assume any responsibility to update forward-looking information contained herein. BUSINESS The Company 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 seven distinct platforms: MidAmerican Energy Company ("MidAmerican Energy"), Kern River Gas Transmission Company ("Kern River"), Northern Natural Gas Company ("Northern Natural Gas"), CE Electric UK Funding, Inc. ("CE Electric UK") (which includes Northern Electric Distribution Ltd ("NED") and Yorkshire Electricity Distribution plc ("YED")), CalEnergy Generation - Domestic, CalEnergy Generation - Foreign and HomeServices of America, Inc. ("HomeServices"). These platforms are discussed in detail in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. 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 Company's consolidated financial statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2002 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 effects of certain types of regulation, impairment of long-lived assets, contingent liabilities and the accounting for revenue. Actual results could differ from these estimates. For additional discussion of the Company's critical accounting policies, see "Management's Discussion and Analysis of Financial Condition and Results of Operations included in the Company's Annual Report on Form 10-K for the year ended December 31, 2002. -19- NEW ACCOUNTING PRONOUNCEMENTS Effective January 1, 2003 the Company adopted Statement of Financial Accounting Standards ("SFAS') No. 143, "Accounting for Asset Retirement Obligations". This statement provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. The cumulative effect of initially applying this statement was immaterial. The Company's review of legal retirement obligations identified obligations for nuclear decommissioning, wet and dry ash landfills and offshore and minor lateral pipeline facilities. On January 1, 2003, the Company recorded $289.3 million of asset retirement obligation ("ARO") liabilities; $13.9 million of ARO assets, net of accumulated depreciation; $114.6 million of regulatory assets; and reclassified $1.0 million of accumulated depreciation to the ARO liability. The initial ARO liability recognized includes $266.5 million that pertains to obligations associated with the decommissioning of the Quad Cities nuclear station. The $266.5 million includes a $159.8 million nuclear decommissioning liability that had been recorded at December 31, 2002. The adoption of this statement did not have a material impact on the statement of operations, as the effects were offset by the establishment of regulatory assets, totaling $114.6 million, pursuant to SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation". During the nine-month period ended September 30, 2003, the Company recorded, as a regulatory asset, accretion related to the ARO liability of $12.5 million, resulting in an ARO liability balance of $301.8 million at September 30, 2003. On April 30, 2003, the Financial Accounting Standards Board ("FASB") issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" ("SFAS 149"). SFAS 149 amends SFAS No. 133 for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. SFAS 149 also amends certain other existing pronouncements. It will require contracts with comparable characteristics to be accounted for similarly. In particular, SFAS 149 clarifies when a contract with an initial net investment meets the characteristic of a derivative and clarifies when a derivative that contains a financing component will require special reporting in the statement of cash flows. SFAS 149 is effective for the Company for contracts entered into or modified after June 30, 2003. The adoption of SFAS 149 did not have a material effect on the Company's financial position, results of operations or cash flows. In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" ("SFAS 150"). SFAS 150 established standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). The standard is effective for the Company for fiscal periods beginning after December 15, 2003. The Company is currently evaluating certain financial instruments in order to determine if SFAS 150 will impact their classification. In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities" ("FIN 46"). On October 8, 2003, the FASB deferred the implementation of FIN 46 to the fourth quarter of 2003. The Company is currently evaluating certain investments in order to determine if FIN 46 will impact their classification. RESULTS OF OPERATIONS FOR THE THREE-MONTH PERIODS ENDED SEPTEMBER 30, 2003 AND 2002 Operating revenue for the three months ended September 30, 2003, increased $220.8 million, or 17.6%, to $1,476.9 million from $1,256.1 million for the same period in 2002. MidAmerican Energy operating revenue for the three months ended September 30, 2003, increased $21.0 million, or 3.8%, to $577.3 million. Gas revenues increased $22.1 million, or 19.7%, to $134.4 million for the three months ended September 30, 2003, primarily due to higher gas prices partially offset by lower volumes. -20- Kern River operating revenue for the three months ended September 30, 2003, increased $38.9 million to $78.8 million. The increase is primarily due to the completion and beginning of operation, on May 1, 2003, of the expansion for which Kern River filed an application with the Federal Energy Regulatory Commission (the "FERC") on August 1, 2001 (the "2003 Expansion Project"). Northern Natural Gas operating revenue for the three months ended September 30, 2003, increased $38.8 million to $77.9 million. During 2002, operating revenue for Northern Natural Gas was included from August 16, 2002, the acquisition date. CE Electric UK operating revenue for the three months ended September 30, 2003, decreased $5.3 million to $188.1 million, due mainly to the sale of the retail business in 2002 partially offset by the impact of exchange rates. HomeServices' operating revenue for the three months ended September 30, 2003, increased $118.3 million, or 34.7%, to $459.0 million. The increase was mainly due to growth from existing operations reflecting higher unit sales and average sales prices totaling $80.4 million and acquisitions totaling $37.9 million. Income on equity investments for the three months ended September 30, 2003, increased $8.5 million to $19.4 million, mainly due to increased mortgage activity at HomeServices' mortgage joint ventures and the impact of impairments of alternative energy project funds in 2002. Interest and dividend income for the three months ended September 30, 2003, decreased $15.1 million to $6.7 million. The decrease is mainly due to the sale of The Williams Cumulative Convertible Preferred Stock in the second quarter of 2003, amounts received in 2002 from investments and decreased interest income at CE Electric UK as a result of lower cash balances. Other income for the three months ended September 30, 2003, decreased $4.1 million to $6.8 million, primarily due to a working capital settlement related to the Yorkshire Swap in 2002 and lower allowance for equity funds used during the construction related to the Kern River 2003 Expansion Project. Cost of sales for the three months ended September 30, 2003, increased $106.6 million, or 23.1%, to $567.3 million. HomeServices' cost of sales increased $82.5 million due to higher commission expense on incremental sales at existing business units and acquisitions. MidAmerican Energy cost of sales increased $30.8 million, due to increased gas prices and, to a lesser extent, higher retail fuel costs and the restructuring of the Cooper Nuclear Station ("Cooper") contract effective August 1, 2002. Operating expenses for the three months ended September 30, 2003, increased $55.9 million, or 16.3%, to $399.2 million. Northern Natural Gas operating expenses increased $37.4 million as expenses for Northern Natural Gas were included from August 16, 2002, the acquisition date. HomeServices' operating expenses increased $23.4 million, primarily due to increased compensation expenses and acquisitions. CE Electric UK operating expenses decreased $11.5 million, primarily due to the sale of their retail business and cost savings. Depreciation and amortization for the three months ended September 30, 2003, increased $6.3 million, or 4.9%, to $135.7 million. This was mainly due to increased depreciation of $6.5 million at Kern River due to the completion of the 2003 Expansion Project, increased depreciation at CE Electric UK of $2.9 million due to an increased asset base and Minerals depreciation of $3.6 million. These increases were partially offset by decreased depreciation at MidAmerican Energy of $10.3 million due primarily to lower revenue sharing. Interest expense for the three months ended September 30, 2003, increased $8.4 million, or 5.0%, to $176.9 million. The increase was due to additional interest expense totaling $13.6 million on the Company's debt issuances of $700.0 million (October 2002) and $450.0 million (May 2003), increased interest expense of $5.0 million at Northern Natural Gas due to a full quarter of operations and increased interest expense at Kern River of $3.1 million due to additional borrowings related to the 2003 Expansion Project. The increases were partially offset by decreased interest, totaling $11.9 million, due to the redemption of the YED trust securities which were -21- redeemed in June 2003, and reductions in the corporate revolver and CalEnergy Generation - Foreign project debt. Capitalized interest for the three months ended September 30, 2003, decreased $6.3 million to $2.9 million. The decrease is primarily due to the discontinuance of capitalizing interest at the Minerals and Kern River Expansion projects. The income tax provision for the three months ended September 30, 2003, increased $39.1 million to $65.9 million mainly due to the $21.1 million tax benefit related to the CE Gas asset sale in 2002 and increased tax expense related to higher earnings at Kern River, HomeServices and CE Electric UK Funding in 2003. Minority interest and preferred dividends for the three months ended September 30, 2003 increased $12.7 million to $58.0 million primarily due to the August 2002 issuance of $950.0 million of 11% trust preferred securities partially offset by reduced dividends on subsidiary preferred securities resulting from lower outstanding balances. Net income available to common and preferred stockholders for the three months ended September 30, 2003, decreased $25.2 million to $109.7 million. RESULTS OF OPERATIONS FOR NINE-MONTH PERIODS ENDED SEPTEMBER 30, 2003 AND 2002 Operating revenue for the nine months ended September 30, 2003 increased $938.8 million or 27.2% to $4,385.9 million from $3,447.1 million for the same period in 2002. MidAmerican Energy operating revenue for the nine months ended September 30, 2003, increased $304.4 million or 18.7% to $1,929.6 million. Gas revenues increased $287.4 million, or 56.0%, to $800.4 million for the nine months ended September 30, 2003, primarily due to higher gas prices. Kern River operating revenue for the nine months ended September 30, 2003, increased $95.3 million to $182.3 million. The increase was primarily due to the completion and beginning of operation, on May 1, 2003, of the 2003 Expansion Project and, to a lesser degree, operating revenue in 2002 being recorded for Kern River beginning on March 27, 2002, the acquisition date. Northern Natural Gas operating revenue for the nine months ended September 30, 2003 increased $294.0 million to $333.1 million as Northern Natural Gas was acquired on August 16, 2002. HomeServices operating revenue for the nine months ended September 30, 2003, increased $256.7 million, or 30.0%, to $1,112.6 million. The increase was due to the impact of acquisitions, totaling $134.5 million, and growth from existing operations, reflecting higher unit sales and average home sales prices. Income on equity investments for the nine months ended September 30, 2003 increased $10.5 million or 35.1% to $40.4 million. The increase was primarily due to increased mortgage activity at HomeServices mortgage joint ventures. This was partially offset by decreased equity income due to a common stock distribution from an energy investment fund in 2002, partially offset by impairments of alternative energy project funds in 2002. Interest and dividend income for the nine months ended September 30, 2003 decreased $1.0 million, or 2.4%, to $39.9 million. The decrease is mainly due to interest received from RACOM in 2002, decreased interest income at CE Electric UK as a result of lower cash balances following the redemption of the YED trust securities in June 2003 partially offset by dividends received on the investment in The Williams Cumulative Convertible Preferred Stock. Other income for the nine months ended September 30, 2003 decreased $17.8 million to $56.7 million. The decrease was primarily due to the $53.3 million gain on sale of various CE Gas assets in May 2002, partially -22- offset by the $13.8 million gain on sale of The Williams Cumulative Convertible Preferred Stock in June 2003 and the allowance for equity funds used during construction at Kern River and MidAmerican Energy in 2003. Cost of sales for the nine months ended September 30, 2003 increased $443.0 million or 33.4% to $1,768.8 million. MidAmerican Energy's cost of sales increased $309.1 million due primarily to increased gas prices and the restructuring of the Cooper contract which increased cost of sales and decreased operating expenses. HomeServices cost of sales increased $172.9 million due to the prior year acquisitions and higher commission expense on incremental sales at existing business units. Operating expenses for the nine months ended September 30, 2003 increased $174.6 million or 18.4% to $1,123.5 million. The increase was mainly due to the inclusion of Northern Natural Gas and Kern River for the entire nine month period in 2003 of $167.2 million and increased operating expenses at HomeServices of $63.0 million, primarily due to the impact of acquisitions and increased compensation expenses. These increases were partially offset by lower operating expenses at CE Electric UK of $36.2 million primarily due to the sale of the retail business in 2002 and lower operating expenses at MidAmerican Energy of $28.7 million primarily due to the restructuring of the Cooper contract. Depreciation and amortization for the nine months ended September 30, 2003 increased $51.8 million or 13.4% to $438.3 million. The increase was mainly due to the inclusion of Northern Natural Gas for the entire nine month period in 2003, of $26.8 million, increased depreciation at Kern River of $13.3 million due to the completion of the 2003 Expansion Project and the inclusion of Kern River's operations for the entire nine-month period ended September 30, 2003 and increased depreciation of $5.2 million at MidAmerican Energy from higher utility plant depreciation partially offset by lower revenue sharing. Interest expense for the nine months ended September 30, 2003 increased $83.8 million or 18.1% to $546.8 million. The increase was primarily comprised of a $35.2 million increase due to the acquisition of Northern Natural Gas, $30.6 million of increased interest expense at Kern River as a result of additional borrowings related to the 2003 Expansion Project and additional interest expense totaling $34.9 million on the Company's $700.0 million (October 2002) and $450.0 million (May 2003) debt issuances, partially offset by reductions in the corporate revolver, CalEnergy Generation - Foreign project debt and YED trust securities which were redeemed in June 2003. Capitalized interest for the nine months ended September 30, 2003 increased $2.0 million to $26.1 million. The increase is primarily due to the capitalization of interest on Kern River's 2003 Expansion Project partially offset by the discontinuance of capitalizing interest at the Zinc Recovery Project. The income tax provision for the nine months ended September 30, 2003, increased $91.2 million to $171.4 million mainly due to the $35.7 million benefit in 2002 from the Teeside Power Limited consortium relief, the $21.1 million tax benefit related to the CE Gas asset sale in 2002 and increased tax expense related to higher earnings at Kern River, HomeServices and CE Electric UK in 2003. Minority interest and preferred dividends for the nine months ended September 30, 2003 increased $74.7 million to $179.9 million. The increase was primarily due to the August 2002 issuance of $950.0 million of 11% trust preferred securities partially offset by reduced dividends on subsidiary preferred securities resulting from lower outstanding balances. Net income available to common and preferred stockholders for the nine-month period ended September 30, 2003 increased $13.5 million to $320.3 million. -23- 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 $754.4 million at September 30, 2003, compared to $844.4 million at December 31, 2002. Each of the Company's direct or indirect subsidiaries is organized as a legal entity separate and apart from MidAmerican Energy Holdings 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. In addition, the Company recorded separately, in restricted cash and short-term investments and deferred charges and other assets, restricted cash and investments of $122.8 million and $58.7 million at September 30, 2003, and December 31, 2002, respectively. The restricted cash balance for both periods is comprised primarily of amounts deposited in restricted accounts which are reserved for the service of debt obligations and customer deposits held in escrow. Cash flows from operating activities for the nine months ended September 30, 2003 increased $330.5 million to $1,013.3 million from $682.8 million for the same period in 2002. The increase was primarily due to timing of distributions from equity investments and changes in working capital, deferred taxes and the positive impacts of the Kern River, Northern Natural Gas and HomeServices acquisitions. The decrease to cash and cash equivalents is primarily due to construction and development costs, capital expenditures related to operating projects and repayments and redemption of debt and other obligations offset by the issuance of debt and the sale of The Williams Cumulative Convertible Preferred Stock. The Williams Cumulative Convertible Preferred Stock --------------------------------------------------- On June 10, 2003, Williams repurchased, for approximately $289 million, plus accrued dividends, all of the shares of its 9-7/8% Cumulative Convertible Preferred Stock originally acquired by MEHC in March 2002 for $275 million. Kern River's 2003 Expansion Project ----------------------------------- Kern River has completed the construction of its 2003 Expansion Project at a total cost of approximately $1.2 billion. The expansion, which was placed into operation on May 1, 2003, increased the design capacity of the existing Kern River pipeline by 885,626 decatherms ("dth") per day to 1,755,626 dth per day. Kern River Funding Corporation, a wholly owned subsidiary of Kern River, issued $836 million of its 4.893% Senior Notes with a final maturity on April 30, 2018. The proceeds were used to repay all of the approximately $815 million of outstanding borrowings under Kern River's $875 million credit facility. Kern River entered into this credit facility in 2002 to finance the construction of the 2003 Expansion Project. The credit facility was canceled and a completion guarantee issued by the Company in favor of the lenders as part of the credit facility terminated upon completion of the 2003 Expansion Project. -24- MidAmerican Energy Operating Projects and Construction and Development Costs ---------------------------------------------------------------------------- MidAmerican Energy's primary need for capital is utility construction expenditures. For the first nine months of 2003, utility construction expenditures totaled $226.7 million, including allowance for funds used during construction and Quad Cities Station nuclear fuel purchases. Forecasted utility construction expenditures, including allowance for funds used during construction, are $366 million for 2003. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews. Through 2007, MidAmerican Energy plans to develop and construct three electric generating projects in Iowa. The projects would provide service to regulated retail electricity customers and, subject to regulatory approvals, be included in regulated rate base in Iowa, Illinois and South Dakota. Wholesale sales may also be made from the projects to the extent the power is not needed for regulated retail service. MidAmerican Energy expects to invest approximately $1.44 billion in the three projects. The first project is a natural gas-fired combined cycle unit with an estimated cost of $357 million, plus allowance for funds used during construction. MidAmerican Energy will own 100% of the plant and operate it. Commercial operation of the simple cycle mode began on May 5, 2003. The plant will be operated in simple cycle mode during 2003 and 2004, resulting in 327 megawatts ("MW") of accredited capacity. The combined cycle operation is expected to commence in December 2004, resulting in an expected additional 190 MW of accredited capacity. The second project is currently under construction and will be a 790-MW (based on expected accreditation) super-critical-temperature, low-sulfur coal-fired plant. MidAmerican Energy will operate the plant and own approximately 475 MW of the plant. MidAmerican Energy expects to invest approximately $759 million in the project, plus allowance for funds used during construction. Municipal, cooperative and public power utilities will own the remainder, which is a typical ownership arrangement for large base-load plants in Iowa. On May 29, 2003, the Iowa Utilities Board ("IUB") issued an order that approves the ratemaking principles for the plant, and on June 27, 2003, MidAmerican Energy received a certificate from the IUB allowing MidAmerican Energy to construct the plant. On February 12, 2003, MidAmerican Energy executed a contract with Mitsui & Co. Energy Development, Inc. for the engineering, procurement and construction of the plant. On September 9, 2003, MidAmerican Energy began construction of the plant, which it expects to be completed in the summer of 2007. MidAmerican Energy is also seeking an order from the IUB approving construction of the associated transmission facilities. The third project is currently under development and is expected to be wind power facilities totaling 310 MW based on the nameplate rating. Generally speaking, accredited capacity ratings for wind power facilities are considerably less than the nameplate ratings due to the varying nature of wind. The current projected accredited capacity for these wind power facilities is approximately 53 MW. If constructed, MidAmerican Energy will own and operate these facilities, which are expected to cost approximately $323 million. MidAmerican Energy's plan to construct the wind project is in conjunction with a settlement agreement that extends through December 31, 2010, an Iowa retail electric rate freeze that was previously scheduled to expire at the end of 2005. The settlement agreement, which was filed with the IUB as part of MidAmerican Energy's application for ratemaking principles for the wind project, was approved by the IUB on October 17, 2003. The obligation of MidAmerican Energy to construct the wind project may be terminated by MidAmerican Energy if the Federal production tax credit applicable to the wind energy facilities is not available at a rate of 1.8 cents per kilowatt-hour ("kWh") for a period of at least ten years after the facilities begin generating electricity. MidAmerican Energy has also received authorization from the IUB to construct the wind power project. Casecnan NIA Settlement ----------------------- Under the terms of the CE Casecnan Water and Energy Company, Inc. ("CE Casecnan") Project Agreement (the "Project Agreement"), the Philippine National Irrigation Administration ("NIA") had the option of timely -25- reimbursing CE Casecnan directly for certain taxes CE Casecnan paid. If NIA did not so reimburse CE Casecnan, certain taxes paid by CE Casecnan would result in an increase in the Water Delivery Fee. The payment of certain other taxes by CE Casecnan would have resulted automatically in an increase in the Water Delivery Fee. As of September 30, 2003, CE Casecnan had paid approximately $59.1 million in taxes, which pursuant to the foregoing provisions resulted in an increase in the Water Delivery Fee. NIA failed to pay the portion of the Water Delivery Fee each month related to the payment of these taxes by CE Casecnan. As a result of the non-payment of the tax compensation portion of the Water Delivery Fees, on August 19, 2002, CE Casecnan filed a Statement of Claim against NIA pursuant to the Rules of Arbitration of the International Chamber of Commerce (the "NIA Arbitration"), seeking payment of such portion of the Water Delivery Fee and enforcement of the relevant provision of the Project Agreement going forward. The NIA Arbitration was conducted in accordance with the rules of the International Chamber of Commerce ("ICC"). NIA filed its Answer and Counterclaim on March 31, 2003. In its Answer, NIA asserted, among other things, that most of the taxes which CE Casecnan had factored into the Water Delivery Fee compensation formula did not fall within the scope of the relevant section of the Project Agreement, that the compensation mechanism itself was invalid and unenforceable under Philippine law and that the Project Agreement was inconsistent with the Philippine build-operate-transfer law. As such, NIA sought dismissal of CE Casecnan's claims and a declaration from the arbitral tribunal that the taxes which have been taken into account in the Water Delivery Fee compensation mechanism were not recoverable thereunder and that, at most, certain taxes may be directly reimbursed (rather than compensated for through the Water Delivery Fee) by NIA. NIA also counterclaimed for approximately $7 million which it alleges is due to it as a result of the delayed completion of the Casecnan Project. On April 23, 2003, NIA filed a Supplemental Counterclaim in which it asserted that the Project Agreement was contrary to Philippine law and public policy and by way of relief sought a declaration that the Project Agreement was void from the beginning or should be cancelled, or alternatively, an order for reformation of the Project Agreement or any portions or sections thereof which may be determined to be contrary to such law and or public policy. On May 23, 2003 CE Casecnan filed its reply to NIA's counterclaims. On October 15, 2003, CE Casecnan closed a transaction settling the NIA Arbitration. In connection with the settlement, CE Casecnan entered into an agreement (the "Supplemental Agreement") with NIA which, in addition to providing for the dismissal with prejudice of all claims by CE Casecnan and counterclaims by NIA in the NIA Arbitration, supplements and amends the Project Agreement in certain respects as summarized below: Payment in Cash and Delivery of Note As part of the settlement, on October 15, 2003, NIA paid to CE Casecnan the sum of $17.7 million plus Philippine pesos of 39.9 million (approximately $0.7 million) and delivered to CE Casecnan the Republic of the Philippines ("ROP") $97.0 million 8.375% Note due 2013 (the "ROP Note"). Also at closing, CE Casecnan paid to the Philippine Bureau of Internal Revenue ("BIR") approximately $24.4 million in respect of Philippine income taxes on the foregoing consideration. The ROP Note is governed by New York law and constitutes a direct, unconditional, unsecured and general obligation of the ROP. The ROP Note is non-transferable until January 15, 2004, but may be exchanged, at the option of the ROP, for a new note forming part of a series of direct, unconditional, unsecured and general debt obligations of the Philippines with a yield of 8.375% or lower. If the Philippines issues a series of direct, unconditional, unsecured and general debt obligations having a yield in excess of 8.375%, CE Casecnan has agreed to accept a series of such new debt with a yield no greater than 8.375%. If not exchanged prior to January 15, 2004, CE Casecnan has the option, between January 15, 2004 and February 15, 2004, to put the ROP Note to the ROP for a price of par plus accrued interest. The ROP Note has default provisions substantially identical to those set forth in other recent issuances of direct, unconditional, unsecured and general obligation of the ROP. Modifications to Water Delivery Fee Under the Project Agreement, the Water Delivery Rate increased by $0.00043 per cubic meter for each $1,000,000 of certain taxes paid by CE Casecnan. The Supplemental Agreement amends the per cubic meter -26- Water Delivery Fee calculation by eliminating this increase, such that the per cubic meter Water Delivery Rate remains at $0.029 per cubic meter, escalated at 7.5% annually from January 1, 1994 through the first five years of the Cooperation Period, extending through December 25, 2006. In lieu of such increase, CE Casecnan will be reimbursed for certain taxes it pays during the remainder of the Cooperation Period. Under the Project Agreement, the Water Delivery Fee payable monthly was a fixed monthly payment based on an average water delivery of 801.9 million cubic meters per year, pro-rated to approximately 66.8 million cubic meters per month, multiplied by the per cubic meter rate as described above. Under the Supplemental Agreement the Water Delivery Fee is equal to the Guaranteed Water Delivery Fee plus the Variable Delivered Water Delivery Fee minus the Water Delivery Fee Credit. Guaranteed Water Delivery Fee. For the sixty-month period from December 25, 2003 through December 25, 2008, the Guaranteed Water Delivery Fee shall equal the Water Delivery Rate, as described above, multiplied by approximately 66.8 million cubic meters (corresponding to the 801.9 million cubic meters per year). For each month beginning after December 25, 2008 through the remainder of the Cooperation Period, the Guaranteed Water Delivery Fee shall equal the Water Delivery Rate multiplied by approximately 58.3 million cubic meters (corresponding to 700.0 million cubic meters per year). Variable Delivered Water Delivery Fee. Variable Delivered Water Delivery Fees will be earned for months beginning after December 25, 2008. For each month beginning after December 25, 2008 through the end of the Cooperation Period, the Variable Delivered Water Delivery Fee shall be payable only from the date when the cumulative Total Available Water (total delivered water plus the water volume not delivered to NIA as a result of NIA's failure to accept energy deliveries at a capacity up to 150 MW) for each contract year exceeds 700.0 million cubic meters. Variable Delivered Water Delivery Fees will be earned up to an aggregate maximum of 1,324.7 million cubic meters for the period from December 25, 2008 through the end of the Cooperation Period. No additional variable water delivery fees will be earned over the 1,324.7 million cubic meter threshold. Water Delivery Credit. The Water Delivery Credit shall be applicable only for each of the sixty-months from December 25, 2008 through December 25, 2013 and shall equal the Water Delivery Rate as of December 25, 2008 multiplied by the sum of each Annual Water Credit divided by sixty. The Annual Water Credit for each contract year starting from December 25, 2003 and ending on December 25, 2008 shall equal 801.9 million cubic meters minus the Total Available Water for each contract year. The Total Available Water in any such year will equal actual deliveries with a minimum threshold of 700.0 million cubic meters. Modifications to Excess Energy Delivery Fee Under the Project Agreement, the Excess Energy Delivery Fee was a variable amount based on actual electrical energy delivered in each month in excess of 19 gigawatt-hour ("GWh"), payable at a rate of $0.1509 per kWh. Under the Supplemental Agreement, the per kWh rate for energy deliveries in excess of 19 GWh per month has been reduced, commencing in 2009, to $0.1132 (escalating at 1% per annum thereafter), provided that any deliveries of energy in excess of 490 GWh but less than 550 GWh per year are paid for at a rate of 1.3 Philippine pesos per kWh and deliveries in excess of 550 GWh per year are at no cost to NIA. The Supplemental Agreement provides that the unpaid portion of the excess energy available for generation, but not generated from the commencement of commercial operations through September 28, 2003 will not be paid. For periods after September 28, 2003, the Supplemental Agreement provides that if the Casecnan project is not dispatched up to 150 MW whenever water is available, NIA will pay for excess energy that could have been generated but was not as a result of such dispatch constraint. Other Provisions of the Supplemental Agreement In connection with the settlement of the NIA Arbitration and as part of the Supplemental Agreement transaction, CE Casecnan paid to NIA $1.6 million in respect of alleged late completion of the Project. This amount had been accrued as of September 30, 2003 and December 31, 2002. In addition, CE Casecnan received opinions from the Philippine Office of Government Corporate Counsel as to the due authorization and enforceability of -27- Supplemental Agreement and received confirmation from the Philippine Department of Finance that the ROP Note had been duly and validly issued and was enforceable in accordance with its terms. CE Casecnan also received an opinion from Allen & Overy, counsel to the Republic of the Philippines, as to the enforceability of the ROP Note under New York law. CE Casecnan also received written confirmation from the Private Sector Assets and Liabilities Management Corporation that the issues with respect to the Casecnan Project that had been raised by the interagency review of independent power producers in the Philippines or that may have existed with respect to the Project under the Electric Power Industry Reform Act of 2001 have been satisfactorily addressed by the Supplemental Agreement. The Guaranteed Energy Delivery Fee, Force Majeure, Buyout and Dispute Resolution provisions of the Project Agreement, as well as the Performance Undertaking provided by the ROP, remain unaffected by the Supplemental Agreement and in full force and effect. Casecnan Construction Contract ------------------------------ 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, CE Casecnan terminated the Hanbo Contract due to defaults by Hanbo and HECC including the insolvency of both companies. On the same date, CE Casecnan 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 was conducted by a consortium consisting of Cooperativa Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa. (collectively, the "Contractor"), working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd. 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 lenders' independent engineer under the Trust Indenture. On February 12, 2001, the Contractor filed a Request for Arbitration with the ICC seeking schedule relief of 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 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 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 in December 2001 amounted to a repudiation of the Replacement Contract and has filed a claim for unspecified quantum meruit damages, and has further alleged that the delay liquidated damages clause which provides for payments of $125,000 per day for each day of delay in completion of the Casecnan Project for which the Contractor is responsible is unenforceable. The arbitration is being conducted applying New York law and pursuant to the rules of the ICC. Hearings have been held in connection with this arbitration in July 2001, September 2001, January 2002, March 2002, November 2002, January 2003 and July 2003. 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, 2003, 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. The $6.0 million was recorded as a reduction in construction costs. On November 7, 2002, the ICC 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. The $3.8 million is shown as part -28- of the other accrued liabilities balance at September 30, 2003 and December 31, 2002. All of the Contractor's other claims with respect to force majeure and geologic conditions were denied. If the Contractor were to prevail on its claim that the delay liquidated damages clause is unenforceable, CE Casecnan would not be entitled to collect such delay damages for the period from March 31, 2001 through December 11, 2001. If the Contractor were to prevail in its repudiation claim and prove quantum meruit damages in excess of amounts paid to the Contractor, CE Casecnan could be liable to make additional payments to the Contractor. CE Casecnan believes all of such allegations and claims are without merit and is vigorously contesting the Contractor's claims. Casecnan Stockholder Litigation ------------------------------- Pursuant to the share ownership adjustment mechanism in the CE Casecnan stockholder agreement, which is based upon pro forma financial projections of the Casecnan Project prepared following commencement of commercial operations, in February 2002, MEHC through its indirect wholly owned subsidiary CE Casecnan Ltd., advised the minority stockholder, LaPrairie Group Contractors (International) Ltd. ("LPG"), that MEHC's 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, among others, CE Casecnan Ltd. and MEHC. In the complaint, LPG seeks compensatory and punitive damages for alleged breaches of the stockholder agreement and alleged breaches of fiduciary duties allegedly owed by CE Casecnan Ltd. and MEHC 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 CE Casecnan cannot be determined at this time. In February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. ("San Lorenzo"), an original shareholder substantially all of whose shares in CE Casecnan were purchased by MEHC in 1998, threatened to initiate legal action in the Philippines in connection with certain aspects of its option to repurchase such shares on or prior to commercial operation of the Casecnan Project. CE Casecnan believes that San Lorenzo has no valid basis for any claim and, if named as a defendant in any action that may be commenced by San Lorenzo, will vigorously defend such action. Other Debt Issuances and Redemptions ------------------------------------ On January 14, 2003, MidAmerican Energy issued $275.0 million of 5.125% medium-term notes due in 2013. The proceeds were used to refinance existing debt and for other corporate purposes. On May 16, 2003, the Company issued $450 million of its 3.5% Senior Notes with a final maturity on May 15, 2018. The proceeds were used for general corporate purposes. On May 23, 2003, the Company terminated a $150 million credit facility, and reduced a separate $250 million credit facility to $100 million. The remaining $100 million facility was due to expire on June 23, 2003. On June 6, 2003, the Company terminated the $100 million facility and closed on a new $100 million revolving credit facility which expires on June 6, 2006. The facility supports letters of credit of which $73.9 million were outstanding at September 30, 2003. On June 9, 2003, Yorkshire Power Group Limited, a wholly owned subsidiary of MEHC, completed the redemption in full of the outstanding shares of the Yorkshire Capital Trust I, 8.08% trust securities, due June 30, 2038, and paid $243.4 million in principal amount ($25 liquidation amount per each trust security) plus accrued distributions of $0.381555555 per trust security to the redemption date. The redemption price was paid to holders of the trust security on the redemption date. -29- Contractual Obligations and Commercial Commitments -------------------------------------------------- There have been no material changes in the contractual obligations and commercial commitments from the information provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2002 other than as discussed in this "Liquidity and Capital Resources" section. -30- ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. For quantitative and qualitative disclosures about market risk affecting MEHC, see Item 7A "Qualitative and Quantitative Disclosures About Market Risk" of MEHC's Annual Report on Form 10-K for the year ended December 31, 2002. MEHC's exposure to market risk has not changed materially since December 31, 2002. ITEM 4. CONTROLS AND PROCEDURES. An evaluation was performed under the supervision and with the participation of the Company's management, including the Chief Executive Officer and Chief Financial Officer, regarding the effectiveness of the design and operation of the Company's disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, as amended) as of September 30, 2003. Based on that evaluation, the Company's management, including the Chief Executive Officer and Chief Financial Officer, concluded that the Company's disclosure controls and procedures were effective. There have been no significant changes in the Company's internal controls or in other factors that could significantly affect internal controls. -31- PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS. See Notes 7 and 10 to the financial statements and discussion in management's discussion and analysis. ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS. Not applicable. ITEM 3. DEFAULTS UPON SENIOR SECURITIES. Not applicable. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. Not applicable. ITEM 5. OTHER INFORMATION. Not applicable. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K. (a) Exhibits: The exhibits listed on the accompanying Exhibit Index are filed as part of this Quarterly Report. (b) Reports on Form 8-K: None. -32- SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. MIDAMERICAN ENERGY HOLDINGS COMPANY ----------------------------------- (Registrant) Date: November 12, 2003 /s/ Patrick J. Goodman ------------------------------------------------ Patrick J. Goodman Senor Vice President and Chief Financial Officer -33- EXHIBIT INDEX Exhibit No. ----------- 31.1 Chief Executive Officer's Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Chief Financial Officer's Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Chief Executive Officer's Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Chief Financial Officer's Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. -34-