10-Q 1 mehc20012nd.txt 2ND QUARTER MEHC UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON D.C. 20549 FORM 10-Q [X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period ended June 30, 2001 [ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from ____________ to___________. 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, IA 50309 ---------------------------------------- ---------------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (515) 242-4300 -------------- 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 require- ments for the past 90 days. Yes X No ------- ------- All of the shares of MidAmerican Energy Holdings Company are held by a limited group of private investors. As of August 14, 2001, 9,281,087 shares of common stock were outstanding. MIDAMERICAN ENERGY HOLDINGS COMPANY FORM 10-Q TABLE OF CONTENTS Part I: Financial Information Page No. ITEM 1. Financial Statements Independent Accountants' Report........................... 1 Consolidated Balance Sheets............................... 2 Consolidated Statements of Operations..................... 3 Consolidated Statements of Cash Flows..................... 4 Notes to Consolidated Financial Statements................ 5 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 14 Part II: Other Information ITEM 1. Legal Proceedings......................................... 29 ITEM 2. Changes in Securities and Use of Proceeds................. 30 ITEM 3. Defaults on Senior Securities............................. 30 ITEM 4. Submission of Matters to a Vote of Security Holders....... 30 ITEM 5. Other Information......................................... 30 ITEM 6. Exhibits and Reports on Form 8-K.......................... 31 Signatures .......................................................... 32 Exhibit Index .......................................................... 33 INDEPENDENT ACCOUNTANTS' REPORT Board of Directors and Shareholders MidAmerican Energy Holdings Company Des Moines, Iowa We have reviewed the accompanying consolidated balance sheet of MidAmerican Energy Holdings Company (successor to MidAmerican Energy Holdings Company (Predecessor), referred to as "MEHC (Predecessor)") and subsidiaries (the "Company") as of June 30, 2001, and the related consolidated statements of operations for the three-month and six-month periods ended June 30, 2001 for the Company; for the period January 1, 2000 to March 13, 2000 for MEHC (Predecessor); for the period March 14, 2000 to June 30, 2000 for the Company; and for the three-month period ended June 30, 2000 for the Company; and the related consolidated statements of cash flows for the six-month period ended June 30, 2001 for the Company; for the period January 1, 2000 to March 13, 2000 for MEHC (Predecessor); and for the period March 14, 2000 to June 30, 2000 for the Company. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and of making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to such consolidated financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of the Company as of December 31, 2000, and the related consolidated statements of operations, shareholders' equity, and cash flows for the period January 1, 2000 to March 13, 2000 for MEHC (Predecessor) and for the period March 14, 2000 to December 31, 2000 for the Company (not presented herein); and in our report dated January 18, 2001 (March 27, 2001 as to Notes 17 and 19.A.), 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, 2000 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived. DELOITTE & TOUCHE LLP Des Moines, Iowa August 6, 2001 MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED BALANCE SHEETS (In thousands)
As of ------------------------------------ June 30, December 31, 2001 2000 ---------------- ---------------- (Unaudited) Assets Current Assets: Cash and cash equivalents............................ $ 41,315 $ 38,152 Restricted cash and short-term investments........... 36,914 42,129 Marketable securities............................... 51,965 5,419 Accounts receivable.................................. 606,560 903,469 Inventory........................................... 60,000 81,943 Other current assets................................. 103,123 91,365 ------------ ------------- Total Current Assets............................... 899,877 1,162,477 Property, plant, contracts and equipment, net........... 5,318,836 5,348,647 Excess of cost over fair value of net assets acquired, net......................................... 3,617,892 3,673,150 Regulatory assets....................................... 223,356 240,934 Long-term restricted cash and investments............... 2,574 48,747 Nuclear decommissioning trust fund and other marketable securities................................. 161,338 202,227 Equity investments...................................... 259,634 246,466 Deferred charges, other investments and other assets.... 822,202 758,003 ------------ ------------- Total Assets............................................ $ 11,305,709 $ 11,680,651 ============ ============= Liabilities and Shareholders' Equity Current Liabilities: Accounts payable..................................... $ 429,505 $ 656,356 Accrued interest.................................... 130,578 107,726 Accrued taxes....................................... 106,207 125,645 Other accrued liabilities............................ 263,984 250,975 Short-term debt..................................... 102,262 251,656 Current portion of long-term debt.................... 232,448 438,978 ------------ ------------- Total Current Liabilities.......................... 1,264,984 1,831,336 Other long-term accrued liabilities..................... 950,835 976,030 Parent company debt..................................... 1,832,221 1,829,971 Subsidiary and project debt............................. 3,527,601 3,398,696 Deferred income taxes................................... 969,296 945,028 ------------ ------------- Total Liabilities.................................... 8,544,937 8,981,061 ------------ ------------- Deferred income......................................... 84,708 79,489 Minority interest....................................... 13,359 11,491 Company-obligated mandatorily redeemable preferred securities of subsidiary trusts............ 787,561 786,523 Subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts............ 100,000 100,000 Preferred securities of subsidiary...................... 131,771 145,686 Commitments and contingencies (Note 8) Shareholders' Equity: Zero coupon convertible preferred stock - authorized 50,000 shares, no par value, 34,563 shares issued and outstanding................. - - Common stock - authorized 60,000 shares, no par value; 9,281 shares issued and outstanding....... - - Additional paid in capital.............................. 1,553,073 1,553,073 Retained earnings....................................... 155,401 81,257 Accumulated other comprehensive loss, net............... (65,101) (57,929) ------------ ------------- Total Shareholders' Equity........................... 1,643,373 1,576,401 ------------ ------------- Total Liabilities and Shareholders' Equity.............. $ 11,305,709 $ 11,680,651 ============ =============
The accompanying notes are an integral part of these financial statements. MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands) (Unaudited)
MEHC (Predecessor) Three Months Six Months March 14, 2000 January 1,2000 Ended June 30, Ended Through Through 2001 2000 June 30, 2001 June 30, 2000 March 13,2000 ----- ---- ------------- ------------- ------------- Revenues: Operating revenue...................... $1,184,747 $1,123,233 $2,779,952 $1,332,706 $1,049,523 Interest and other income.............. 38,186 29,441 55,871 33,807 13,033 ---------- ---------- ----------- ---------- ---------- Total revenues............................ 1,222,933 1,152,674 2,835,823 1,366,513 1,062,556 ---------- ---------- ----------- ---------- ---------- Costs and expenses: Cost of sales.......................... 641,798 612,280 1,671,807 722,294 561,386 Operating expense...................... 284,406 273,087 550,909 324,193 219,303 Depreciation and amortization.......... 121,551 120,129 237,767 142,439 97,278 Interest expense....................... 120,676 124,726 242,354 148,024 101,330 Less interest capitalized.............. (23,646) (27,048) (52,133) (30,694) (15,516) Loss on non-recurring item............. - - - - 7,605 ----------- ----------- ----------- ---------- ---------- Total costs and expenses.................. 1,144,785 1,103,174 2,650,704 1,306,256 971,386 ----------- ----------- ----------- ---------- ---------- Income before provision for income taxes.. 78,148 49,500 185,119 60,257 91,170 Provision for income taxes................ 19,870 11,516 54,215 13,817 31,008 ----------- ----------- ----------- ---------- ---------- Income before minority interest........... 58,278 37,984 130,904 46,440 60,162 Minority interest......................... 27,445 26,935 52,156 31,955 8,850 ----------- ----------- ----------- ---------- ---------- Income before cumulative effect of change inaccounting principle................ 30,833 11,049 78,748 14,485 51,312 Cumulative effect of change in accounting principle, net of tax................. - - (4,604) - - ----------- ----------- ------------ ---------- ---------- Net income available to common shareholders........................... $ 30,833 $ 11,049 $ 74,144 $ 14,485 $ 51,312 =========== =========== =========== ========== ==========
The accompanying notes are an integral part of these financial statements. MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) (Unaudited)
MEHC (Predecessor) Six March 14, 2000 January 1, 2000 Months Through Through Ended June 30, March 13, June 30, 2001 2000 2000 ------------- -------------- --------------- Net income........................................................... $ 74,144 $ 14,485 $ 51,312 Adjustments to reconcile to net cash flows from operating activities: Cumulative effect of change in accounting principle, net of tax...... 4,604 - - Depreciation and amortization........................................ 187,778 112,595 83,097 Amortization of excess of cost over fair value of net assets acquired............................................... 49,989 29,844 14,181 Amortization of deferred financing costs and other costs............. 10,799 7,656 4,075 Provision for deferred income taxes.................................. 34,885 (4,938) 7,735 Undistributed earnings on equity investments......................... (17,290) (11,218) (3,459) Changes in other items: Accounts receivable and other current assets...................... 316,236 82,015 440 Accounts payable, accrued liabilities, deferred income and other......................................................... (265,793) (151,906) 13,702 ----------- ---------- ---------- Net cash flows from operating activities............................. 395,352 78,533 171,083 ----------- ---------- ---------- Cash flows from investing activities: Purchase of MEHC (Predecessor) net of cash acquired................. - (2,048,266) - Purchase of marketable securities.................................... - (15,326) (8,251) Proceeds from sale of marketable securities.......................... - 21,800 12,562 Acquisition of realty companies...................................... (29,963) - - Capital expenditures relating to operating projects.................. (151,553) (94,880) (44,355) Construction and other development costs............................. (43,299) (73,225) (56,450) Philippine-construction in progress.................................. (40,197) (15,284) (22,736) Change in restricted investments..................................... 46,173 32,140 48,788 Change in other assets............................................... 27,680 (18,739) 15,568 ----------- ---------- --------- Net cash flows from investing activities............................. (191,159) (2,211,780) (54,874) ----------- ---------- --------- Cash flows from financing activities: Proceeds from issuances of common and preferred stock................ - 1,428,024 - Proceeds from issuance of trust preferred securities................. - 454,772 - Net repayment of short- debt......................................... (145,722) (56,387) (118,718) Repayment of subsidiary and project debt............................. (250,937) (56,574) (3,135) Repayment of parent company debt..................................... - (4,225) - Redemption of preferred trust securities of subsidiaries............. - (19,686) - Proceeds from subsidiary and project debt............................ 206,158 87,421 - Change in restricted investments-debt service........................ 5,215 30,197 (6,033) Other................................................................ (15,988) (3,247) (615) ----------- ---------- --------- Net cash flows from financing activities............................. (201,274) 1,860,295 (128,501) ----------- ---------- --------- Effect of exchange rate changes on cash.............................. 244 (621) (424) ----------- ---------- --------- Net increase (decrease) in cash and cash equivalents............... 3,163 (273,573) (12,716) Cash and cash equivalents at beginning of period................... 38,152 303,611 316,327 ----------- ---------- --------- Cash and cash equivalents at end of period........................... $ 41,315 $ 30,038 $ 303,611 =========== ========== ========= Interest paid, net of amount capitalized............................. $ 167,370 $ 155,437 $ 35,057 =========== ========== ========= Income taxes paid.................................................... $ 52,114 $ 61,495 $ - =========== ========== =========
The accompanying notes are an integral part of these financial statements. MIDAMERICAN ENERGY HOLDINGS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. General In the opinion of management of MidAmerican Energy Holdings Company (successor to MidAmerican Energy Holdings Company (Predecessor), referred to as "MEHC (Predecessor)") and subsidiaries (collectively referred to as the "Company"), the accompanying unaudited consolidated financial statements contain all adjustments (consisting only of normal recurring accruals) necessary to present fairly the financial position as of June 30, 2001 and the results of operations for the three and six months ended June 30, 2001 and for the three months ended June 30, 2000 and for the period March 14, 2000 to June 30, 2000 for the Company and for the period January 1, 2000 to March 13, 2000 for MEHC (Predecessor) and the related consolidated statements of cash flows for the six months ended June 30, 2001 and for the period March 14, 2000 to June 30, 2000 for the Company and for the period January 1, 2000 to March 13, 2000 for MEHC (Predecessor). The results of operations for the three and six months ended June 30, 2001, and for the three months ended June 30, 2000 and the period March 14, 2000 to June 30, 2000 for the Company and for the period January 1, 2000 to March 13, 2000 for MEHC (Predecessor) are not necessarily indicative of the results to be expected for the full year. The consolidated financial statements include the accounts of the 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 2000 financial statements and supporting note disclosures have been reclassified to conform to the 2001 presentation. Such reclassification did not impact previously reported net income or retained earnings. Reference is made to the Company's most recently issued annual report on Form 10-K that included information necessary or useful to the understanding of the Company's business and financial statement presentations. 2. Property, Plant, Contracts and Equipment Property, plant, contracts and equipment comprise the following (in thousands):
June 30, December 31, 2001 2000 -------------- -------------- Operating assets: Utility generation and distribution system......... $ 6,184,998 $ 6,157,482 Independent power plants........................... 931,171 698,069 Power sales agreement.............................. 78,428 82,231 Other assets....................................... 469,867 421,231 ------------- ------------- Total operating assets............................. 7,664,464 7,359,013 Less accumulated depreciation and amortization..... (3,456,582) (3,312,019) ------------- ------------- Net operating assets............................... 4,207,882 4,046,994 Mineral and gas reserves and exploration assets, net............................................ 376,541 373,742 Construction in process: Casecnan........................................ 428,595 388,398 Zinc recovery project........................... 177,101 166,406 Utility generation and distribution system...... 110,377 141,160 Cordova......................................... - 224,514 Other development............................... 18,340 7,433 ------------ ------------ Total.............................................. $ 5,318,836 $ 5,348,647 ============ ============
3. Equity Investments CE Generation, the Company's 50% owned subsidiary, has interests in ten operating geothermal plants in Imperial Valley, California and three operating natural gas-fired cogeneration plants in New York, Texas and Arizona. The following is summarized financial information for CE Generation (in thousands): Three Months Ended Six Months Ended June 30, June 30, June 30, June 30, 2001 2000 2001 2000 --------- --------- -------- -------- Revenues $129,405 $112,505 $279,092 $206,975 Income before cumulative effect of change in accounting principle 17,372 16,939 37,546 18,905 Net income 17,372 16,939 22,160 18,905 4. Accounting Policy Change Effective January 1, 2001, the Company has changed its accounting policy regarding major maintenance and repairs for nonregulated gas projects, nonregulated plant overhaul costs and geothermal well rework costs to the direct expense method from the former policy of monthly accruals based on long-term scheduled maintenance plans for the gas projects and deferral and amortization of plant overhaul costs and geothermal well rework costs over the estimated useful lives. The cumulative effect of the change in accounting principle was $4.6 million, net of taxes of $.7 million. 5. Accounting Pronouncements On January 1, 2001, the Company adopted Statement of Financial Accounting Standards Nos. 133 and 138 (SFAS 133/138) pertaining to the accounting for derivative instruments and hedging activities. SFAS 133/138 requires an entity to recognize all of its derivatives as either assets or liabilities in its statement of financial position and measure those instruments at fair value. If the conditions specified in SFAS 133/138 are met, those instruments may be designated as hedges. Changes in the value of hedge instruments would not impact earnings, except to the extent that the instrument is not perfectly effective as a hedge. At January 1, 2001, the Company recognized $55.6 million and $53.3 million of energy-related assets and liabilities, respectively, as being subject to fair value accounting pursuant to SFAS 133/138, all of which are accounted for as hedges. Additionally, on January 1, 2001, the Company's portfolio of preferred stock investments was transferred from the available for sale category to the trading category, as permitted by SFAS 133. Initial adoption of SFAS 133/138 did not have a material impact on the results of operations for the Company. The Financial Accounting Standards Board ("FASB") has approved guidance that, in general, option contracts and forward contracts with optionality features cannot qualify for the normal purchases and normal sales exception under SFAS 133/138 as amended. However, the FASB has also issued guidance that energy capacity contracts that include certain characteristics of purchased and written options could qualify as normal purchases and sales as long as certain criteria are met. The Company has performed a preliminary review of its contracts with the above characteristics and believes that these contracts are not subject to the financial reporting requirements of SFAS 133/138. Another issue, which included tentative guidance as of the filing of the first quarter 2001 Form 10-Q, stated that derivative contracts which do not result in physical delivery of power because of transmission scheduling, referred to as bookouts, cannot meet the normal purchases and normal sales exception. This issue was abandoned by the FASB during the second quarter of 2001. The FASB's Derivatives Implementation Group continues to identify and provide guidance on various implementation issues related to SFAS 133/138 that are in varying stages of review and clearance by the Derivatives Implementation Group and the FASB. The Company is monitoring the issues being reviewed by the Derivatives Implementation Group and the FASB to determine what, if any, impact they may have on the Company's financial statements. In July 2001, the FASB issued SFAS No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets" which establish accounting and reporting for business combinations. SFAS No. 141 requires all business combinations entered into subsequent to June 30, 2001, to be accounted for using the purchase method of accounting. SFAS No. 142 provides that goodwill and other intangible assets with indefinite lives will not be amortized but will be tested for impairment on an annual basis. These standards are effective for the Company beginning on January 1, 2002. The Company is evaluating the impact resulting from the adoption of these standards. 6. Comprehensive Income (Loss) Comprehensive income (loss) for the three months ended June 30, 2001 and 2000 was $91.1 million and ($33.2) million, respectively. Comprehensive income for the six months ended June 30, 2001 was $69.4 million, which includes the transition loss of $3.3 million related to the initial adoption of SFAS 133. Comprehensive loss for the period March 14, 2000 to June 30, 2000 was ($29.8) million. Comprehensive income of MEHC (Predecessor) for the period January 1, 2000 to March 13, 2000 was $26.0 million. Comprehensive income differs from net income due primarily to foreign currency translation adjustments, unrealized gains and losses from marketable securities, and fair value adjustments of cash flow hedges. 7. Accounting for Derivatives MidAmerican Energy MidAmerican Energy uses a variety of derivative financial instruments to hedge the effect of price changes on cash flows from expected future physical transactions (cash flow hedges) and the fair value of physical purchase and sale commitments (fair value hedges) and to minimize price volatility for regulated gas purchases. The objective of MidAmerican Energy's hedging program is to minimize the impact of changing prices for natural gas and electricity on its cash flows. Instruments used for gas hedging transactions include futures contracts, swaps and options. Instruments used for electric hedging transactions include forward contracts and options. Small volumes of derivative financial instruments are traded from time to time to profit from price arbitrage opportunities. Unrealized gains and losses on cash flow hedges of future transactions are recorded in other comprehensive income. Only hedges that are highly effective in offsetting the risk of variability in future cash flows are accounted for in this manner. Future transactions include purchases of gas for resale to regulated and nonregulated customers, purchases of gas for storage, and purchases and sales of wholesale electric energy. When the associated hedged future transaction occurs or if a hedging relationship is no longer appropriate, the unrealized gains and losses are reversed from other comprehensive income and recognized in net income. Realized gains on cash flow hedges are recorded in operating revenues or cost of sales, depending upon the nature of the physical transaction being hedged. For the six months ended June 30, 2001, a net gain of $.4 million, representing the ineffectiveness of cash flow hedges, was reflected in cost of sales. During the twelve months beginning July 1, 2001, it is anticipated that all of net unrealized gains (losses) on cash flow hedges presently recorded as accumulated other comprehensive income will be realized and recorded in earnings. Unrealized gains and losses on fair value hedges are recognized in income as either operating revenues or cost of sales, depending upon the nature of the item being hedged. Purchase and sales commitments hedged by fair value hedges are recorded at fair value, with the changes in values also recognized in income and substantially offsetting the impact of the hedges on earnings. For the six months ended June 30, 2001, the net income statement impact realized from the ineffectiveness of fair value hedges was immaterial. Unrealized gains and losses on derivatives held for trading purposes are recognized in income each reporting period as operating revenues. As of June 30, 2001, the following instruments were held as hedges: Notional Unit of Fair Value Amount Measure Asset (Liability) ------ ------- ----------------- Natural Gas Futures - Net Short 4,930,000 MMBtu $9,905,000 Natural Gas Swaps 419,000 MMBtu (4,465,000) Natural Gas Options-Long 950,000 MMBtu (1,676,000) Natural Gas Options-Short 950,000 MMBtu 1,000 Electricity Forward Contracts - Net Short 306,000 MWh 588,000 Northern On March 27, 2001, the New Electricity Trading Arrangements ("NETA") came into effect and replaced the previous Pooling & Settlement arrangements that had been in place since 1990. A key feature of NETA is the ability provided to participants to trade bi-lateral contracts for physical energy delivery under the new industry governance arrangements set out in the Balancing & Settlement Code. This is significantly different from the Pooling & Settlement arrangements that previously existed whereby prices were determined centrally with participants being required to sell and buy physical energy through the Pool and use financial instruments in the form of Contracts for Difference ("CfDs") and Electricity Forward Agreements ("EFAs") to manage risk associated with volatility of the centrally determined "Pool" price. As a result of NETA, all of the previous CfD and EFA agreements were replaced with bi-lateral contracts which fall under the normal purchases and normal sales exception and therefore are not subject to the financial reporting requirements of SFAS 133/138. At June 30, 2001, CE Electric UK Funding Company had fixed-rate obligations denominated in U.S. dollars that exposed CE Electric UK Funding Company to losses in the event of increases in the exchange rate of U.S. dollars to Sterling pounds. When this obligation was issued, CE Electric UK Funding Company entered into certain currency rate swap agreements that effectively convert the U.S. dollar fixed interest rate to a fixed rate in Sterling pounds. At June 30, 2001, these currency rate swap agreements had an aggregate notional amount of $362 million, which the Company would receive approximately $47.2 million if terminated. 8. Commitments and Contingencies Financial Condition of Edison Southern California Edison ("Edison"), a wholly-owned subsidiary of Edison International, is a public utility primarily engaged in the business of supplying electric energy to retail customers in Central and Southern California, excluding the city of Los Angeles. The Company is aware that there have been public announcements that Edison's financial condition has deteriorated as a result of reduced liquidity. Edison's senior unsecured debt obligations are currently rated Caa2 by Moody's and D by S&P. Edison failed to pay approximately $119 million due under the Power Purchase Agreements of indirect subsidiaries of the Company's 50% owned subsidiary, CE Generation, for power delivered in November and December 2000 and January, February and March 2001, although the Power Purchase Agreements provide for billing and payment on a schedule where payments would have normally been received in early January, February, March, April and May 2001. On February 21, 2001, the Imperial Valley Projects (excluding Salton Sea Unit V and CE Turbo), subsidiaries of CE Generation, filed a lawsuit against Edison in California's Imperial County Superior Court seeking a court order requiring Edison to make the required payments under the Power Purchase Agreements. The lawsuit also requested, among other things, that the court order permit the Imperial Valley Projects to suspend deliveries of power to Edison and to permit the Imperial Valley Projects to sell such power to other purchasers in California. On March 22, 2001, the Superior Court granted the Imperial Valley Projects' Motion for Summary Adjudication and a Declaratory Judgment ordering that: 1) under the Power Purchase Agreements, the Imperial Valley Projects have the right to temporarily suspend deliveries of capacity and energy to Edison, 2) the Imperial Valley Projects are entitled to resell the energy and capacity to other purchasers and 3) the interim suspension of deliveries to Edison shall not in any respect result in the modifications or termination of the Power Purchase Agreements and the Power Purchase Agreements shall in all respects continue in full force and effect other than the temporary suspension of deliveries to Edison. As a result of the March 22, 2001 Declaratory Judgment, the Imperial Valley Projects suspended deliveries of energy to Edison and entered into a transaction agreement with El Paso Merchant Energy, L.P. ("EPME") in which the Imperial Valley Projects' available power was sold to EPME based on percentages of the Dow Jones SP-15 Index. On June 18, 2001 the Superior Court terminated the Imperial Valley Projects' right to resell power pursuant to the Declaratory Judgment. On June 20, 2001, the Imperial Valley Projects (excluding Salton Sea Unit V and CE Turbo) entered into Agreements Addressing Renewable Energy Pricing and Payment Issues with Edison ("Settlement Agreements"). The Settlement Agreements require Edison make a series of payments to repay the past due balances under the Power Purchase Agreements (the "stipulated amounts"). The first payment of approximately $11.6 million, which represented 10% of the stipulated amounts, was received June 22, 2001. A second partial payment of 10% is payable within 5 days following the MOU Effective Date. The "MOU Effective Date" means the first day on which both of the following have occurred: (a) all legislation implementing the Memorandum of Understanding between Edison and the California Department of Water Resources dated April 9, 2001 ("MOU") or such other legislation based on the MOU or otherwise, that restores Edison to creditworthiness has become effective, and (b) the California Public Utilities Commission ("Commission") has issued all orders that are necessary to implement the MOU or other mechanisms contained in such legislation based on the MOU or otherwise which are designed to restore Edison to creditworthiness. The final payment, representing the remaining stipulated amounts, shall be paid on the 5th business day after Edison receives proceeds from the financing resulting from the MOU or other mechanisms contained in such other legislation based on the MOU or otherwise restore Edison to creditworthiness. In addition to these payments, Edison is required to make monthly interest payments calculated at a rate of 7% per annum on the outstanding stipulated amounts. The Settlement Agreements also provide a revised energy pricing structure, whereby Edison elects to pay the Imperial Valley Projects a fixed energy price of 5.37 cents/kilowatt hour in lieu of the Commission-approved SRAC Methodology under the Power Purchase Agreements, commencing on the first day of the month following the MOU Effective Date and expiring five years from such date. All other contract terms remain unchanged. As a result of the aforementioned Settlement Agreements, the Imperial Valley Projects resumed power sales to Edison on June 22, 2001. Energy payments are currently calculated using the SRAC formulas set forth in the Power Purchase Agreements until the fixed rate period begins. As a result of Edison's failure to make the payments due under the Power Purchase Agreements and the recent downgrades of Edison's credit ratings, Moody's downgraded the ratings for the Salton Sea Funding Corporation (the "Funding Corporation") Securities to Caa2 (negative outlook) and S&P downgraded the ratings for the Funding Corporation Securities to BBB- and placed the Securities on "credit watch negative". Moody's downgraded the ratings for the CE Generation Securities to B1 from Baa3 (review for possible downgrade). Following the execution of the Settlement Agreements, Moody's placed the Salton Sea Funding and CE Generation securities on "credit watch positive". The Imperial Valley Projects are contractually entitled to receive payments under the Power Purchase Agreements and Settlement Agreements. However, due to the uncertainties associated with Edison's financial condition and failure to pay contractual obligations, CE Generation has established an allowance for doubtful accounts of approximately $82 million at June 30, 2001. Minerals Extraction The Company owns the rights to proprietary processes for the extraction of minerals from elements in solution in the geothermal brine and fluids utilized at its Imperial Valley plants. A pilot plant has successfully produced commercial quality zinc at the Company's Imperial Valley Projects. The Company intends to sequentially develop facilities for the extraction of manganese, silver, gold, lead, boron, lithium and other products as it further develops the extraction technology. CalEnergy Minerals LLC, an indirect wholly owned subsidiary of the Company, is constructing the Zinc Recovery Project which will recover zinc from the geothermal brine (the "Zinc Recovery Project"). Facilities are being installed near the Imperial Valley Project's sites to extract a zinc chloride solution from the geothermal brine through an ion exchange process. This solution will be transported to a central processing plant where zinc ingots will be produced through solvent extraction, electrowinning and casting processes. The Zinc Recovery Project is designed to have a capacity of approximately 30,000 metric tons per year and is scheduled to commence commercial operations in late 2002. In September 1999, CalEnergy Minerals LLC entered into a sales agreement whereby all zinc produced by the Zinc Recovery Project will be sold to Cominco, Ltd. The initial term of the agreement expires in December 2005. The Zinc Recovery Project was being constructed by Kvaerner U.S. Inc. ("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering, procure, construct and manage contract (the "Zinc Recovery Project EPC Contract"). On June 14, 2001, CalEnergy Minerals, LLC issued notices of default, termination and demand for payment of damages to Kvaerner under the Zinc Recovery Project EPC Contract due to failure to meet performance obligations. As a result of Kvaerner's failure to pay monetary obligations under the Zinc Recovery Project EPC Contract, CalEnergy Minerals, LLC drew $29.7 million under the EPC Contract Letter of Credit on July 20, 2001. CalEnergy Minerals, LLC has entered into a time and materials reimbursable engineer, procure and construction management contract with AMEC E&C Services, Inc. to complete the Zinc Recovery Project. Casecnan CE Casecnan Water and Energy Company, Inc., a Philippine corporation ("CE Casecnan") which at completion of the Casecnan Project is expected to be at least 70% indirectly owned by the Company, is constructing the Casecnan Project, a combined irrigation and 150 net MW hydroelectric power generation project (the "Casecnan Project") located in the central part of the island of Luzon in the Republic of the Philippines. CE Casecnan has entered into a fixed-price, date certain, turnkey engineering, procurement and construction contract to complete the construction of the Casecnan Project (the "Casecnan Construction Contract"). The work under the Casecnan Construction Contract is being conducted by a consortium consisting of Cooperative Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd. (collectively, the "Contractor"). On November 20, 1999, the Casecnan Construction Contract was amended to extend the Guaranteed Substantial Completion Date for the Casecnan Project to March 31, 2001. This amendment was approved by the lender's independent engineer under the Casecnan Indenture. In January 2001, CE Casecnan received a new working schedule from the Contractor that showed a completion date of August 31, 2001. Furthermore, in July 2001, CE Casecnan received new schedule information from the Contractor which extends the expected Substantial Completion Date for the Casecnan Project from August 31, 2001 to October 6, 2001. The receipt of the working schedule does not change the Guaranteed Substantial Completion Date under the Replacement Contract, and the Contractor is still contractually obligated either to complete the Casecnan Project by March 31, 2001 or to pay delay liquidated damages. As a result of receipt of the working schedule, however, CE Casecnan has sought and obtained from the lender's independent engineer approval for a revised construction schedule under the Casecnan Indenture. In connection with the revised schedule, the Company agreed to make available up to $11.6 million of additional funds under certain conditions pursuant to a Shareholder Support Letter dated February 8, 2001 (the "Shareholder Support Letter") to cover additional costs resulting from the Contractor's schedule delay. As agreed in the Shareholder Support Letter and assuming payments are received under the bank guaranty supporting the Contractor's obligation to pay delay liquidated damages prior to October 6, 2001, CE Casecnan believes that the funds available to it are reasonably expected to be sufficient to fund the costs of reaching completion of the Casecnan Project. However, due to the delay in completion of the project, CE Casecnan does not presently expect that it will receive significant operating revenues from the Casecnan Project prior to November 15, 2001. As a result, CE Casecnan presently expects that it will have insufficient funds available to it for purposes of making the principal and interest payments which will become due on November 15, 2001 on the debt securities issued by CE Casecnan in November 1995 (the "Debt Securities"), unless the Company agrees to fund the expected shortfall amount which is currently estimated to be approximately $24.6 million. CE Casecnan has been advised that the willingness of the Company to fund such November 15, 2001 shortfall will principally depend upon the progress of the pending arbitration proceedings involving the Contractor, including any orders issued in the future by the arbitration panel; completion of the Casecnan Project in substantial compliance with the revised construction schedule; and performance by the National Irrigation Administration ("NIA") of its obligations under the Project Agreement. Subject to these same assumptions, CE Casecnan does not presently expect that any additional funding will be required to be provided to it by the Company in order for CE Casecnan to make future principal and interest payments on the Debt Securities following the November 15, 2001 payments. CE Casecnan's ability to make payments on any of its existing and future obligations is dependent on NIA's and the Republic of the Philippines' ("RP") performance of their obligations under the Project Agreement and the Performance Undertaking, respectively. Except to the extent expressly provided for in the Shareholder Support Letter, no shareholders, partners or affiliates of CE Casecnan, including the Company, and no directors, officers or employees of the Company will guarantee or be in any way liable for payment of CE Casecnan's obligations. As a result, payment of CE Casecnan's obligations depends upon the availability of sufficient revenues from CE Casecnan's business after the payment of operating expenses. Cordova Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned subsidiary of the Company, completed construction of a 537 MW gas-fired power plant in the Quad Cities, Illinois area (the "Cordova Project"). The Cordova Project became operational June 19, 2001. MidAmerican On July 10, 2001, MidAmerican Energy announced plans to develop and construct two electric generating plants in Iowa, requiring an investment of approximately $1.5 billion. Participation by others in a portion of the second plant is being discussed. The two plants will provide approximately 1,400 megawatts of generating capacity. MidAmerican Energy expects to begin construction in Spring 2002 on the first project, a 540-megawatt natural gas-fired combined cycle unit which has an estimated cost of $340 million. It is anticipated that the first phase of the project will be completed in 2003 with the remainder being completed in 2005. MidAmerican Energy presently expects that all utility construction expenditures for the next five years will be met with the issuance of long-term debt and cash generated from utility operations, net of dividends. The actual level of cash generated from utility operations is affected by, among other things, economic conditions in the utility service territory, weather and federal and state regulatory actions. 9. Segment Information The Company has identified five reportable business segments principally based on management structure: CalEnergy Generation-Domestic, CalEnergy Generation-Foreign (primarily the Philippines), MidAmerican (domestic utility operations), Northern (foreign utility operations), and HomeServices (real estate operations). Information related to the Company's reportable operating segments is shown below (in thousands).
MEHC (Predecessor) Three Months Six Months March 14, 2000 January 1, 2000 Ended June 30, Ended Through Through 2001 2000 June 30, 2001 June 30, 2000 March 13, 2000 ---- ---- ------------- ------------- --------------- Revenue: CalEnergy Generation - Domestic $ 18,411 $ 9,955 $ 26,586 $ 9,944 $ 4,520 CalEnergy Generation - Foreign. 52,038 48,632 104,750 58,692 42,726 MidAmerican.................... 614,108 481,477 1,511,185 564,696 447,583 Northern....................... 355,785 477,174 912,602 577,058 499,017 HomeServices................... 180,864 139,175 280,905 160,194 66,880 ----------- ---------- ---------- ---------- ------------ Segment revenue................ 1,221,206 1,156,413 2,836,028 1,370,584 1,060,726 Corporate...................... 1,727 (3,739) (205) (4,071) 1,830 ---------- ----------- ---------- ---------- ------------ $1,222,933 $1,152,674 $2,835,823 $1,366,513 $ 1,062,556 ========== ========== ========== ========== ============ Income before provision for income taxes: CalEnergy Generation - Domestic $ 10,015 $ 7,229 $ 14,389 $ 6,854 $ 2,877 CalEnergy Generation - Foreign. 22,714 16,107 45,573 20,293 15,976 MidAmerican.................... 46,717 34,384 123,895 42,612 63,315 Northern....................... 24,581 28,580 96,763 38,193 58,673 HomeServices................... 15,881 12,496 12,612 13,003 (4,929) ---------- --------- ---------- ---------- ------------ Segment operating income....... 119,908 98,796 293,232 120,955 135,912 Corporate...................... (41,760) (49,296) (108,113) (60,698) (44,742) ---------- --------- ---------- ---------- ------------ $ 78,148 $ 49,500 $ 185,119 $ 60,257 $ 91,170 ========== ========== ========== ========== ============
June 30, December 31, 2001 2000 ------------- ------------- Identifiable assets: CalEnergy Generation - Domestic.... $ 1,019,827 $ 968,444 CalEnergy Generation - Foreign..... 1,127,271 1,188,445 MidAmerican........................ 5,085,046 5,392,273 Northern........................... 2,829,231 2,929,665 HomeServices....................... 221,701 163,101 ----------- ----------- Segment identifiable assets........ 10,283,076 10,641,928 Corporate.......................... 1,022,633 1,038,723 ----------- ------------ $11,305,709 $11,680,651 =========== =========== The remaining differences from the segment amounts to the consolidated amounts described as "Corporate" relate principally to the corporate functions including administrative costs, corporate cash and related interest income, unallocated goodwill and related goodwill amortization, intersegment eliminations and fair value adjustments relating to acquisitions. 10. Subsequent Event On August 6, 2001, the Company and Innogy, plc reached an agreement to exchange Northern's electricity and gas supply and metering business for Innogy's Yorkshire Electricity distribution business. The transaction is expected to close in approximately two to three months. The acquisition of Yorkshire's distribution business by Northern Electric plc will create a company serving more than 3.6 million customers in the United Kingdom throughout an area of approximately 10,000 square miles. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following is management's discussion and analysis of certain significant factors that have affected the Company's financial condition and results of operations during the periods included in the accompanying statements of operations. Teton Transaction On March 14, 2000, the Company and entities representing an investor group comprised of Berkshire Hathaway Inc., Walter Scott, Jr., a director of the Company, David L. Sokol, Chairman and Chief Executive Officer of the Company, and Gregory E. Abel, Chief Operating Officer of the Company closed on a definitive agreement and plan of merger whereby the investor group acquired all of the outstanding common stock of the Company (the "Teton Transaction"). As a result of the Teton Transaction, Berkshire Hathaway, Mr. Scott, Mr. Sokol and Mr. Abel own approximately 9.7%, 86%, 3% and 1% of the voting stock respectively. Business of MEHC MidAmerican Energy Holdings Company (the "Company" or "MEHC"), is a United States-based privately owned global energy company with publicly traded fixed income securities that generates, distributes and supplies energy to utilities, government entities, retail customers and other customers located throughout the world. Through its subsidiaries the Company is organized and managed on four separate platforms: MidAmerican, Northern, CalEnergy Generation and HomeServices. MidAmerican MidAmerican Energy Company ("MidAmerican Energy") is a regulated public utility principally engaged in the business of generating, transmitting, distributing and selling electric energy and in distributing, selling and transporting natural gas. MidAmerican Energy distributes electricity at the retail level in Iowa, Illinois and South Dakota. It also distributes natural gas at the retail level in Iowa, Illinois, South Dakota and Nebraska. As of June 30, 2001, MidAmerican Energy had approximately 669,000 retail electric customers and 646,000 retail natural gas customers. In addition to retail sales, MidAmerican Energy delivers electric energy to other utilities, marketers and municipalities who distribute it to end-use customers. These sales are referred to as sales for resale or off-system sales. It also transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. Most of MidAmerican Energy's business is conducted in a rate-regulated environment and accordingly, many of its decisions as to the source and use of resources and other strategic matters are evaluated from a utility business perspective. MidAmerican Energy's operations are seasonal in nature with a disproportionate percentage of revenues and earnings historically being earned in the Company's first and third quarters. Northern The operations of Northern Electric plc ("Northern"), an indirect wholly owned subsidiary of the Company, consist primarily of the distribution and supply of electricity, supply of natural gas and other auxiliary businesses in the United Kingdom. Northern's operations are seasonal in nature with a disproportionate percentage of revenues and earnings historically being earned in the Company's first and fourth quarters. Northern receives electricity from the national grid transmission system and distributes it to customers' premises using its network of transformers, switchgear and cables. Substantially all of the customers in Northern's authorized area are connected to Northern's network and can only be delivered electricity through Northern's distribution system, regardless of whether it is supplied by Northern's own supply business or by other suppliers, thus providing Northern with distribution volume that is stable from year to year. Northern charges access fees for the use of the distribution system. The prices for distribution are controlled by a prescribed formula that limits increases (and may require decreases) based upon the rate of inflation in the United Kingdom and other regulatory action. Northern's supply business primarily involves the bulk purchase of electricity, previously through a central pool and from March 27, 2001 on through the New Electricity Trading Agreements ("NETA"), and subsequent resale to individual customers throughout the U.K. The supply business generally is a high volume business that tends to operate at lower profitability levels than the distribution business. As of June 30, 2001, Northern supplied electricity to approximately 1.1 million customers. Northern also competes to supply gas inside and outside its authorized area. As of June 30, 2001, Northern supplied gas to approximately 467,000 customers. On August 6, 2001, the Company and Innogy, plc reached an agreement to exchange Northern's electricity and gas supply and metering business for Innogy's Yorkshire Electricity distribution business. The transaction is expected to close in approximately two to three months. The acquisition of Yorkshire's distribution business by Northern Electric plc will create a company serving more than 3.6 million customers in the United Kingdom throughout an area of approximately 10,000 square miles. CalEnergy Generation The Company indirectly owns the Upper Mahiao, Malitbog and Mahanagdong Projects (collectively, the "Philippine Projects"), which are geothermal power plants located on the island of Leyte in the Philippines. For purposes of consistent presentation, capacity amounts for Upper Mahiao, Malitbog and Mahanagdong are 119, 216 and 165 net MW, respectively. Each plant possesses an operating margin that allows for production in excess of the amount listed above. Utilization of this operating margin is based upon a variety of factors and can be expected to vary between calendar quarters, under normal operating conditions. On June 19, 2001, Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned subsidiary of the Company, commenced operation of a 537 MW gas-fired power plant in the Quad Cities, Illinois area (the "Cordova Project"). Cordova Energy has entered into a power purchase agreement with a unit of El Paso Energy Corporation ("El Paso") in which El Paso will purchase all of the capacity and energy from the project until December 31, 2019. Cordova Energy has exercised an option under the El Paso Power Purchase Agreement to callback 50% of the project output for sales to others for the contract years ending on or prior to May 14, 2004. Cordova Energy subsequently entered into a power purchase agreement with MidAmerican Energy whereby MidAmerican Energy will purchase 50% of the capacity and energy from the Cordova Project until May 14, 2004. The Company has a 50% ownership interest in CE Generation LLC ("CE Generation") which has interests in ten geothermal plants in the Imperial Valley, California and three natural gas-fired cogeneration plants. For purposes of consistent presentation, plant capacity factors for Vulcan, Hoch (Del Ranch), Turbo, Elmore and Leathers (collectively the "Partnership Projects") are based on capacity amounts of 34, 38, 10, 38, and 38 net MW, respectively, and for Salton Sea I, Salton Sea II, Salton Sea III, Salton Sea IV and Salton Sea V plants (collectively the "Salton Sea Projects") are based on capacity amounts of 10, 20, 50, 40 and 49 net MW, respectively (the Partnership Projects and the Salton Sea Projects are collectively referred to as the "Imperial Valley Projects"). Plant capacity factors for Saranac, Power Resources and Yuma (collectively the "Gas Plants") are based on capacity amounts of 240, 200, and 50 net MW, respectively. Each plant possesses an operating margin that allows for production in excess of the amount listed above. Utilization of this operating margin is based upon a variety of factors and can be expected to vary between calendar quarters, under normal operating conditions. Due to its 50% ownership interest in CE Generation, the Company accounts for CE Generation as an equity investment. HomeServices The Company owns approximately 83% of HomeServices.Com, Inc. ("HomeServices"), the second largest residential real estate brokerage firm in the United States based on aggregate closed transaction sides in 2000 for its various brokerage firm operating subsidiaries. Closed transaction sides mean either the buy side or sell side of any closed home purchase and is the standard term used by industry participants and publications to rank real estate brokerage firms. In addition to providing traditional residential real estate brokerage services, HomeServices cross sells to its existing real estate customers preclosing services, such as mortgage origination and title services, including title insurance, title search, escrow and other closing administrative services, assists in securing other preclosing and postclosing services provided by third parties, such as home warranty, home inspection, home security, property and casualty insurance, home maintenance, repair and remodeling and is developing various related e-commerce services. HomeServices currently operates in the following twelve states: Minnesota, Iowa, Arizona, Kansas, Missouri, Kentucky, Nebraska, Wisconsin, Indiana, Maryland, North Dakota and South Dakota. HomeServices occupies the number one or number two market share position in each of its major markets based on aggregate closed transaction sides for the year ended December 31, 2000. HomeServices' major markets consist of the following metropolitan areas: Minneapolis and St. Paul, Minnesota; Des Moines, Iowa; Omaha, Nebraska; Kansas City, Kansas; Louisville, Kentucky; Springfield, Missouri; Tucson, Arizona and Annapolis, Maryland. Results of Operations for the Quarters Ended June 30, 2001 and 2000: Operating revenue increased in the second quarter of 2001 to $1,184.7 million from $1,123.2 million for the same period in 2000, a 5.5% increase. MidAmerican operating revenue increased in the second quarter of 2001 to $600.4 million from $470.1 million for the same period in 2000, primarily due to increases in volumes and prices of non-regulated gas. Northern's operating revenue decreased in the second quarter of 2001 to $350.1 million from $470.2 million for the same period in 2000, primarily due to lower volumes and rates of electricity supplied inside and outside its authorized area partially offset by higher volumes and rates of external access charges. Operating revenue of HomeServices increased in the second quarter of 2001 to $180.1 million from $137.8 million for the same period in 2000, primarily due to acquisitions and the inclusion of a joint venture which was previously accounted for as an equity investment. The following data represents sales from MidAmerican Energy: Three Months Ended June 30, ---------------------- 2001 2000 ---- ---- Electric Retail Sales (GWh)..................... 4,008 3,940 Electric Sales for Resale (GWh)................. 1,890 1,362 Regulated and Non-regulated Gas Supplied (Thousands of MMBtus)........................ 53,103 31,706 MidAmerican Energy retail electric sales increased in the second quarter 2001 from the second quarter 2000 due to warmer temperatures and non-weather related sales increases. MidAmerican Energy electric sales for resale increased in the second quarter as higher production at the Cooper and Neal power plants increased available sales volumes. MidAmerican Energy regulated and non-regulated gas supplied increased in the second quarter due to growth in the non-regulated markets. The following data represents the supply and distribution operations in the U.K.: Three Months Ended June 30, ------------------------ 2001 2000 ---- ---- Electricity Supplied (GWh)...................... 4,054 4,691 Electricity Distributed (GWh)................... 4,051 3,790 Gas Supplied (Thousands of MMBtus).............. 8,060 8,721 The decrease in electricity supplied for the three months ended June 30, 2001 from the same periods in 2000 is due to the decrease in supply volumes both inside and outside the authorized area. The increase in electricity distributed for the three months ended June 30, 2001 from the same period in 2000 is due to changes in demand in the authorized area. The decrease in gas supplied in 2001 from 2000 reflects lower volume in the U.K. industrial and commercial markets. Interest and other income increased in the second quarter of 2001 to $38.2 million from $29.4 million for the same period in 2000, a 29.7% increase. The increase is primarily due to gains on the sales of Western States Geothermal, an indirect wholly owned subsidiary of the Company and other investments, partially offset by lower income from cost and equity investments. Cost of sales increased in the second quarter of 2001 to $641.8 million from $612.3 million for the same period in 2000, a 4.8% increase. The increase is primarily due to higher volumes of non-regulated gas supplied at MidAmerican and increased cost at HomeServices due to acquisitions and the inclusion of a joint venture which was previously accounted for as an equity investment, partially offset by lower costs at Northern due to a decrease in the exchange rate and lower electricity purchase costs, partially offset by higher gas costs. Operating expenses increased to $284.4 million in the three months ended June 30, 2001 from $273.1 million in the same period in 2000. MidAmerican's operating expenses increased to $165.4 million in 2001 from $157.6 million in the same period in 2000 primarily due to higher bad debt, pension and Cooper costs. Northern's operating expenses decreased $15.6 million due primarily to lower foreign exchange rate and lower bad debt and pension costs. HomeServices' operating expenses increased $11.9 million due primarily to acquisitions and the inclusion of a joint venture which was previously accounted for as an equity investment. Depreciation and amortization increased $1.5 million to $121.6 million in the three months ended June 30, 2001 from $120.1 million in the same period in 2000. The increase is primarily due to higher goodwill and purchase accounting amortization relating to the Teton and HomeServices' acquisitions. Interest expense, less amounts capitalized, decreased marginally in the second quarter of 2001 to $97.0 million from $97.7 million for the same period in 2000. The decreases are due to the lower average outstanding debt balances and increased capitalized interest at Casecnan, Cordova and Zinc Recovery Project, partially offset by decreased capitalized interest on the mineral extraction process. The provision for income taxes increased in the second quarter of 2001 to $19.9 million from $11.5 million for the same period in 2000. The increase is due primarily to higher pretax income. Minority interest increased marginally in the second quarter of 2001 to $27.4 million from $26.9 million for the same period in 2000. The increase is primarily due to the increase in minority interest at HomeServices. Net income increased in the second quarter of 2001 to $30.8 million from $11.0 million for the same period in 2000. Results of Operations for the Six Months Ended June 30, 2001 and the Periods March 14, 2000 through June 30, 2000, and January 1, 2000 through March 13, 2000: The following is a discussion of the historical results of the Company for the six months ended June 30, 2001 and the period March 14, 2000 through June 30, 2000, and of its predecessor (referred to as "MEHC (Predecessor)") for the period January 1, 2000, through March 13, 2000. Results for the Company include the results of MEHC (Predecessor) beginning March 14, 2000, in conjunction with the Teton Transaction. The impact of the transaction is reflected in the Company's results of operations, predominately minority interest costs on issuance of Company-obligated mandatorily redeemable preferred securities of subsidiary trust and the effects of purchase accounting, including goodwill amortization and fair value adjustments to the carrying value of assets and liabilities. In order to provide comparability between periods, the Company has prepared pro forma results as if the Teton Transaction had occurred at the beginning of each year after giving effect to pro forma adjustments related to the acquisition, including the issuance of the 11% trust preferred securities. The discussion therefore will highlight any significant variances on a pro forma basis from the six months ended June 30, 2000 to the six months ended June 30, 2001. Pro forma operating revenue for the six months ended June 30, 2001 was $2,780.0 million compared with $2,382.2 million for the same period in 2000, an increase of 16.7%. MidAmerican Energy operating revenue increased for the six months ended June 30, 2001 to $1,489.9 million from $992.7 million for the same period in 2000, primarily due to increases in volumes and prices of regulated and non-regulated gas. Northern operating revenue decreased for the six months ended June 30, 2001 to $906.1 million from $1,068.1 million for the same period in 2000, primarily due to changes in foreign exchange rates and lower volumes and rates of electricity supplied. The remaining increase primarily relates to the increase of revenue at HomeServices due to acquisitions and the inclusion of a joint venture which was previously accounted for as an equity investment. The following data represents sales from MidAmerican Energy: Six Months Ended June 30, ------------------------------ 2001 2000 --------------- ----------- Electricity Retail Sales (GWh)............... 8,029 7,905 Electricity Sales for Resale (GWh)........... 4,391 3,443 Regulated and Non-Regulated Gas Supplied (Thousands of MMBtus)........................ 123,268 82,571 MidAmerican Energy electric retail sales increased for the six months ended June 30, 2001 from the same period in 2000 due to more extreme temperatures partially offset by a decrease in non-weather related sales. Electric sales for resale increased for the six months ended June 30, 2001 from the same period in 2000 due to higher production at the Cooper and Neal power plants and favorable market conditions. Regulated and non-regulated gas supplied increased due to growth in the non-regulated markets for the six months ended June 30, 2001 compared to the same period in 2000. The following data represents the supply and distribution operations in the U.K.: Six Months Ended June 30, ------------------------------- 2001 2000 ------------ ---------- Electricity Supplied (GWh).............. 9,176 9,915 Electricity Distributed (GWh)........... 8,559 8,210 Gas Supplied (Thousands of MMBtus)...... 34,688 25,443 The decrease in electricity supplied for the six months ended June 30, 2001 is due to the decreases in volumes both inside and outside the authorized area. The increase in electricity distributed for the six months ended June 30, 2001 is due to changes in demand in the distribution area. The increase in gas supplied in 2001 from 2000 reflects higher volume in the U.K. industrial and commercial markets. Pro forma interest and other income for the six months ended June 30, 2001 was $55.9 million compared with $46.8 million for the same period in 2000. The increase was due primarily to gains on the sales of Western States Geothermal, an indirect wholly owned subsidiary of the Company and other investments, partially offset by reduced interest income and lower income from equity investments. Pro forma cost of sales for the six months ended June 30, 2001 was $1,671.8 million compared with $1,283.7 million for the same period in 2000, an increase of 30.2%. The increase relates primarily to increased volumes and prices for both regulated and non-regulated gas at MidAmerican Energy, and acquisitions at HomeServices, partially offset by decreased cost of sales at Northern due to a lower foreign exchange rate and lower electricity volumes and prices. Pro forma operating expenses for the six months ended June 30, 2001 was $550.9 million compared with $542.8 million for the same period in 2000. The increase was primarily due to higher costs at HomeServices due to acquisitions and the inclusion of a joint venture which was previously accounted for as an equity investment and higher costs at MidAmerican due to costs related to Cooper, accounts receivable discounts and bad debts, partially offset by lower costs at Northern due to lower exchange rate and lower costs related to bad debt, marketing and pensions. Pro forma depreciation and amortization for the six months ended June 30, 2001 was $237.8 million compared with $242.5 million for the same period in 2000. This decrease was due to lower depreciation at Northern primarily due to lower foreign exchange rates, partially offset by higher depreciation at MidAmerican Energy due to an increase in depreciation rates implemented in 2001 and utility capital expenditures. Pro forma interest expense, less amounts capitalized, for the six months ended June 30, 2001 was $190.2 million compared with $204.0 million for the same period in 2000, a decrease of 7.3%. This decrease is due to lower average outstanding debt balances, an increase in capitalized interest related to the construction of Casecnan, Cordova and Zinc Recovery Project and lower foreign exchange rates at Northern, partially offset by lower capitalized interest on the mineral extraction process. The loss on non-recurring item of $7.6 million in the period from January 1, 2000 through March 13, 2000 represents the costs related to the Teton Transaction. Pro forma tax expense for the six months ended June 30, 2001 was $54.2 million compared with $40.7 million for the same period in 2000. The increase is due to higher pre-tax income. Pro forma minority interest for the six months ended June 30, 2001 was $52.2 million compared with $51.5 million for the same period in 2000. The increase is primarily due to increased minority interest at HomeServices. Pro forma net income for the six months ended June 30, 2001 was $74.1 million compared with $56.4 million for the same period in 2000. 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's cash and cash equivalents were $41.3 million at June 30, 2001 compared to $38.2 million at December 31, 2000. In addition, the Company recorded separately restricted cash and investments of $39.5 million and $90.9 million at June 30, 2001 and December 31, 2000, respectively. The restricted cash balance as of June 30, 2001 is comprised primarily of amounts deposited in restricted accounts from which the Company will fund the various projects under construction. Additionally, the Philippine Projects' restricted cash is reserved for the service of debt obligations. On March 1, 2001 MidAmerican Funding, LLC retired $200 million of 5.85% Senior Secured Notes due 2001. On March 19, 2001 MidAmerican Funding, LLC issued $200 million of 6.75% Senior Secured Notes due March 1, 2011. Construction Minerals Extraction The Company owns the rights to proprietary processes for the extraction of minerals from elements in solution in the geothermal brine and fluids utilized at its Imperial Valley plants. A pilot plant has successfully produced commercial quality zinc at the Company's Imperial Valley Projects. The Company intends to sequentially develop facilities for the extraction of manganese, silver, gold, lead, boron, lithium and other products as it further develops the extraction technology. CalEnergy Minerals LLC, an indirect wholly owned subsidiary of the Company, is constructing the Zinc Recovery Project which will recover zinc from the geothermal brine (the "Zinc Recovery Project"). Facilities are being installed near the Imperial Valley Project's sites to extract a zinc chloride solution from the geothermal brine through an ion exchange process. This solution will be transported to a central processing plant where zinc ingots will be produced through solvent extraction, electrowinning and casting processes. The Zinc Recovery Project is designed to have a capacity of approximately 30,000 metric tons per year and is scheduled to commence commercial operations in 2002. In September 1999, CalEnergy Minerals LLC entered into a sales agreement whereby all zinc produced by the Zinc Recovery Project will be sold to Cominco, Ltd. The initial term of the agreement expires in December 2005. The Zinc Recovery Project was being constructed by Kvaerner U.S. Inc. ("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering, procure, construct and manage contract (the "Zinc Recovery Project EPC Contract"). On June 14, 2001, CalEnergy Minerals, LLC issued notices of default, termination and demand for payment of damages to Kvaerner under the Zinc Recovery Project EPC Contract due to failure to meet performance obligations. As a result of Kvaerner's failure to pay monetary obligations under the Zinc Recovery Project EPC Contract, CalEnergy Minerals, LLC drew $29.7 million under the EPC Contract Letter of Credit on July 20, 2001. CalEnergy Minerals, LLC has entered into a time and materials reimbursable engineer, procure and construction management contract with AMEC E&C Services, Inc. to complete the Zinc Recovery Project. Casecnan CE Casecnan Water and Energy Company, Inc., a Philippine corporation ("CE Casecnan") which at completion of the Casecnan Project is expected to be at least 70% indirectly owned by the Company, is constructing the Casecnan Project, a combined irrigation and 150 net MW hydroelectric power generation project (the "Casecnan Project") located in the central part of the island of Luzon in the Republic of the Philippines. CE Casecnan has entered into a fixed-price, date certain, turnkey engineering, procurement and construction contract to complete the construction of the Casecnan Project (the "Casecnan Construction Contract"). The work under the Casecnan Construction Contract is being conducted by a consortium consisting of Cooperative Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd. (collectively, the "Contractor"). On November 20, 1999, the Casecnan Construction Contract was amended to extend the Guaranteed Substantial Completion Date for the Casecnan Project to March 31, 2001. This amendment was approved by the lender's independent engineer under the Casecnan Indenture. In January 2001, CE Casecnan received a new working schedule from the Contractor that showed a completion date of August 31, 2001. Furthermore, in July 2001, CE Casecnan received new schedule information from the Contractor which extends the expected Substantial Completion Date for the Casecnan Project from August 31, 2001 to October 6, 2001. The receipt of the working schedule does not change the Guaranteed Substantial Completion Date under the Replacement Contract, and the Contractor is still contractually obligated either to complete the Casecnan Project by March 31, 2001 or to pay delay liquidated damages. As a result of receipt of the working schedule, however, CE Casecnan has sought and obtained from the lender's independent engineer approval for a revised construction schedule under the Casecnan Indenture. In connection with the revised schedule, the Company agreed to make available up to $11.6 million of additional funds under certain conditions pursuant to a Shareholder Support Letter dated February 8, 2001 (the "Shareholder Support Letter") to cover additional costs resulting from the Contractor's schedule delay. As agreed in the Shareholder Support Letter and assuming payments are received under the bank guaranty supporting the Contractor's obligation to pay delay liquidated damages prior to October 6, 2001, CE Casecnan believes that the funds available to it are reasonably expected to be sufficient to fund the costs of reaching completion of the Casecnan Project. However, due to the delay in completion of the project, CE Casecnan does not presently expect that it will receive significant operating revenues from the Casecnan Project prior to November 15, 2001. As a result, CE Casecnan presently expects that it will have insufficient funds available to it for purposes of making the principal and interest payments which will become due on November 15, 2001 on the debt securities issued by CE Casecnan in November 1995 (the "Debt Securities"), unless the Company agrees to fund the expected shortfall amount which is currently estimated to be approximately $24.6 million. CE Casecnan has been advised that the willingness of the Company to fund such November 15, 2001 shortfall will principally depend upon the progress of the pending arbitration proceedings involving the Contractor, including any orders issued in the future by the arbitration panel; completion of the Casecnan Project in substantial compliance with the revised construction schedule; and performance by the National Irrigation Administration ("NIA") of its obligations under the Project Agreement. Subject to these same assumptions, CE Casecnan does not presently expect that any additional funding will be required to be provided to it by the Company in order for CE Casecnan to make future principal and interest payments on the Debt Securities following the November 15, 2001 payments. CE Casecnan's ability to make payments on any of its existing and future obligations is dependent on NIA's and the Republic of the Philippines' ("RP") performance of their obligations under the Project Agreement and the Performance Undertaking, respectively. Except to the extent expressly provided for in the Shareholder Support Letter, no shareholders, partners or affiliates of CE Casecnan, including the Company, and no directors, officers or employees of the Company will guarantee or be in any way liable for payment of CE Casecnan's obligations. As a result, payment of CE Casecnan's obligations depends upon the availability of sufficient revenues from CE Casecnan's business after the payment of operating expenses. Cordova Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned subsidiary of the Company, completed construction of a 537 MW gas-fired power plant in the Quad Cities, Illinois area (the "Cordova Project"). The Cordova Project became operational June 19, 2001. MidAmerican On July 10, 2001, MidAmerican Energy announced plans to develop and construct two electric generating plants in Iowa, requiring an investment of approximately $1.5 billion. Participation by others in a portion of the second plant is being discussed. The two plants will provide approximately 1,400 megawatts of generating capacity. MidAmerican Energy expects to begin construction in Spring 2002 on the first project, a 540-megawatt natural gas-fired combined cycle unit which has an estimated cost of $340 million. It is anticipated that the first phase of the project will be completed in 2003 with the remainder being completed in 2005. MidAmerican Energy presently expects that all utility construction expenditures for the next five years will be met with the issuance of long-term debt and cash generated from utility operations, net of dividends. The actual level of cash generated from utility operations is affected by, among other things, economic conditions in the utility service territory, weather and federal and state regulatory actions. Domestic Rate Matters: Electric In 1997, pursuant to a rate proceeding before the Iowa Utilities Board, MidAmerican Energy, the Office of Consumer Advocate and other parties entered into a pricing plan settlement agreement establishing MidAmerican Energy's Iowa retail electric rates. That settlement agreement expired on December 31, 2000. On March 14, 2001, the Office of the Consumer Advocate filed a petition with the Iowa Utilities Board to reduce Iowa retail electric rates by approximately $77 million annually. On June 11, 2001, MidAmerican Energy responded to that petition by filing a request with the Iowa Utilities Board to increase MidAmerican Energy's Iowa retail electric rates by $51 million annually. On July 12, 2001, MidAmerican Energy, the Office of Consumer Advocate and other parties jointly filed a settlement agreement with the Iowa Utilities Board that, if approved, will freeze the rates in effect on December 31, 2000 through December 31, 2005, and, with modifications, will reinstate the revenue sharing provisions of the 1997 pricing plan settlement agreement. Under the proposed settlement agreement, 50% of revenues associated with returns on equity between 12% and 14%, and 83.33% of revenues associated with returns on equity above 14%, in each year would be deferred as a regulatory liability to be used to offset a portion of the cost of future generating plant investments. MidAmerican Energy has negotiated individual electric contracts with some of its commercial and industrial customers in Iowa. The negotiated electric contracts have differing terms and conditions as well as prices. The vast majority of the contracts expire during the period 2003 through 2005, although some large customers have contracts extending to 2008. Some of the contracts have price renegotiation and early termination provisions exercisable by either party. Prices are set as fixed prices; however, many contracts allow for potential price adjustments with respect to environmental costs, government imposed public purpose programs, tax changes, and transition costs. While the contract prices are fixed (except for the potential adjustment elements), the costs MidAmerican Energy incurs to fulfill these contracts will vary. On an aggregate basis the annual revenues under contract are approximately $180 million. UK Rate Matters Distribution Northern charges access fees for the use of the distribution system. Most revenue of the distribution business is controlled by a distribution price control formula. The current formula requires that regulated distribution income per unit is increased or decreased each year by RPI-Xd where RPI reflects the average of the twelve months' inflation rates recorded for the previous July to December period and Xd is set at 3%. The formula also takes account of the changes in system electrical losses, the number of customers connected and the voltage at which customers receive the units of electricity distributed. The formula determines the maximum average price per unit of electricity distributed (in pence per kilowatt hour) which a Public Electricity Supplier ("PES") is entitled to charge. The price control does not seek to constrain the profits of a PES from year to year. It is a control on revenue that operates independently of the PES's costs. During the lifetime of the price control, additional cost savings therefore contribute directly to profit. Changes to the formula took effect from April 1, 2000 resulting in a one-off reduction in allowed income per unit distributed of around 24%. As part of the review, the Xd factor remains at 3%. The distribution prices allowable under the current distribution price control formula are expected to be reviewed by the Office of Gas and Electricity Markets ("Ofgem") at the expiration of the formula's scheduled five-year duration in 2005. The formula may be reviewed at other times at the discretion of Ofgem, including in connection with the proposed Information and Incentive Project (IIP) under which it is proposed that 2% of regulated income will depend upon the performance of the PES's distribution system as measured by the number and duration of customer interruptions and upon the level of customer satisfaction monitored by the regulator. Supply In December 1999, Ofgem announced revised electric supply price controls. Since April 2000, these have been applied to most domestic and small commercial customers in the below 100kW market of Northern's designated area, and result in a further lowering of price caps. The new price control applies for two years to March 2002. While the impact of the latest regulatory review varied across companies, the impact on a standard Northern customer was a price reduction of approximately 11%. The supply companies are able to propose and amend the detailed structure of tariffs, but these must be submitted to Ofgem to ensure their consistency with the prescribed price caps. Prices are then monitored on an ongoing basis, and any proposed further amendments must be submitted to Ofgem for review. In addition to the constraint of regulatory price caps, competitive pressures from other suppliers are exerted against Northern's tariffs and contracts. Beginning on March 27, 2001, the New Electricity Trading Arrangements ("NETA") replaced the Pool with market arrangements more reflective of other commodities. The bulk of energy settlement under this system occurs either bilaterally or through power exchanges. Risk mitigation is dependent on the establishment of effective load forecasting tools, addressing short and longer-term requirements. In addition, it is expected that new hedging facilities will be established, although the form of these has yet to be defined. On August 6, 2001, the Company and Innogy, plc reached an agreement to exchange Northern's electricity and gas supply and metering business for Innogy's Yorkshire Electricity distribution business. The transaction is expected to close in approximately two to three months. The acquisition of Yorkshire's distribution business by Northern Electric plc will create a company serving more than 3.6 million customers in the United Kingdom throughout an area of approximately 10,000 square miles. Environmental Matters: Domestic The U.S. Environmental Protection Agency, or EPA, and state environmental agencies have determined that contaminated wastes remaining at decommissioned manufactured gas plant facilities may pose a threat to the public health or the environment if these contaminants are in sufficient quantities and at sufficient concentrations as to warrant remedial action. MidAmerican Energy has evaluated or is evaluating 27 properties which were, at one time, sites of gas manufacturing plants in which it may be a potentially responsible party. The purpose of these evaluations is to determine whether waste materials are present, whether the materials constitute an environmental or health risk, and whether MidAmerican Energy has any responsibility for remedial action. MidAmerican Energy's estimate of the probable costs for these sites as of June 30, 2001, was $24 million. This estimate has been recorded as a liability and a regulatory asset for future recovery through the regulatory process. Although the timing of potential incurred costs and recovery of costs in rates may affect the results of operations in individual periods, management believes that the outcome of these issues will not have a material adverse effect on the Company's financial position or results of operations. On July 18, 1997, the EPA adopted revisions to the National Ambient Air Quality Standards for ozone and a new standard for fine particulate matter. In May 1999, the U.S. Court of Appeals for the District of Columbia Circuit remanded the standards adopted in July 1997 back to the EPA indicating the EPA had not expressed sufficient justification for the basis of establishing the standards and ruling that the EPA has exceeded its constitutionally-delegated authority in setting the standards. On February 27, 2001, the U.S. Supreme Court upheld the standards, ruling that the EPA did not exceed its constitutional delegation of authority in establishing the standard in 1997. The impact of any new standards on the Company is currently unknown. MidAmerican Energy could incur increased costs and a decrease in revenues if its generating stations are located in nonattainment areas. Environmental Matters: U.K. The U.K. Government introduced new contaminated land legislation in April 2000 that requires companies to: o Put in place a program for investigating the company's history to identify problem sites for which it is responsible; o make a clear commitment to meeting responsibilities for cleaning up those sites; o provide funding to make sure that this can happen; and o make commitments public. Northern is in the process of completing the evaluation work on the seven sites which may be subject to the legislation. A compliance strategy will then be developed. Exploratory work with an environmental remediation company is expected to minimize any clean up costs. The Environmental Protection Act (Disposal of PCB's and other Dangerous Substances) Regulations 2000 were introduced on May 5, 2000. The regulations required that transformers containing over 50 parts per million (PPM) be registered with the Environment Agency by July 31, 2000. Transformers containing 500 PPM were required to be de-contaminated by December 31, 2000. Northern has registered 62 items above 50 PPM, de-contaminated 4 items and informed the Environment Agency that it is continuing with its sampling, labeling and registration program. Nuclear Decommissioning 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. Based on information presently available, the Company expects to contribute approximately $41 million during the period 2001 through 2005 to an external trust established for the investment of funds for decommissioning Quad Cities Station. Approximately 60% of the trust's funds are now invested in domestic corporate debt and common equity securities. The remainder is invested in investment grade municipal and U.S. Treasury bonds. Based on information presently available and assuming a September 2004 shutdown of Cooper, MidAmerican Energy expects to accrue approximately $55 million for Cooper decommissioning during the period 2001 through 2004. MidAmerican Energy's obligation, if any, for Cooper decommissioning may be affected by the actual plant shutdown date. In July 1997, the Nebraska Public Power District filed a lawsuit in United States District of Nebraska naming MidAmerican Energy as the defendant and seeking a declaration of MidAmerican Energy's rights and obligations in connection with Cooper nuclear decommissioning funding. Refer to Part II, Item 1. Legal Proceedings, for further discussion of the litigation. Cooper and 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. Cooper decommissioning costs charged to Illinois customers are recovered through a rate rider on customer billings. Development Activity The Company is actively seeking to develop, construct, own and operate new energy projects, both domestically and internationally, the completion of any of which is subject to substantial risk. Development can require the Company to expend significant sums for preliminary engineering, permitting, fuel supply, resource exploration, legal, marketing and other expenses in preparation for competitive bids which the Company may not win or before it can be determined whether a project is feasible, economically attractive or capable of being financed. Successful development and construction is contingent upon, among other things, negotiation on terms satisfactory to the Company of engineering, construction, fuel supply and sales contracts with other project participants, receipt of required governmental permits and consents and timely implementation of construction. There can be no assurance that development efforts on any particular project, or the Company's development efforts generally, will be successful. The financing, construction and development of projects outside the United States entail significant political and financial risks (including, without limitation, uncertainties associated with first time privatization efforts in the countries involved, currency exchange rate fluctuations, currency repatriation restrictions, political instability, civil unrest and expropriation) and other structuring issues that have the potential to cause substantial delays or material impairment of the value of the project being developed, which the Company may not be fully capable of insuring against. The uncertainty of the legal environment in certain foreign countries in which the Company may develop or acquire projects could make it more difficult for the Company to enforce its rights under agreements relating to such projects. In addition, the laws and regulations of certain countries may limit the ability of the Company to hold a majority interest in some of the projects that it may develop or acquire. The Company's international projects may, in certain cases, be terminated by a government. Projects in operation, construction and development are subject to a number of uncertainties more specifically described in the Company's Form 8-K, dated March 26, 1999, filed with the Securities and Exchange Commission. Financial Condition of Edison Southern California Edison ("Edison"), a wholly-owned subsidiary of Edison International, is a public utility primarily engaged in the business of supplying electric energy to retail customers in Central and Southern California, excluding the city of Los Angeles. The Company is aware that there have been public announcements that Edison's financial condition has deteriorated as a result of reduced liquidity. Edison's senior unsecured debt obligations are currently rated Caa2 by Moody's and D by S&P. Edison failed to pay approximately $119 million due under the Power Purchase Agreements of indirect subsidiaries of the Company's 50% owned subsidiary, CE Generation for power delivered in November and December 2000 and January, February and March 2001, although the Power Purchase Agreements provide for billing and payment on a schedule where payments would have normally been received in early January, February, March, April and May 2001. On February 21, 2001, the Imperial Valley Projects (excluding Salton Sea Unit V and CE Turbo), subsidiaries of CE Generation filed a lawsuit against Edison in California's Imperial County Superior Court seeking a court order requiring Edison to make the required payments under the Power Purchase Agreements. The lawsuit also requested, among other things, that the court order permit the Imperial Valley Projects to suspend deliveries of power to Edison and to permit the Imperial Valley Projects to sell such power to other purchasers in California. On March 22, 2001, the Superior Court granted the Imperial Valley Projects' Motion for Summary Adjudication and a Declaratory Judgment ordering that: 1) under the Power Purchase Agreements, the Imperial Valley Projects have the right to temporarily suspend deliveries of capacity and energy to Edison, 2) the Imperial Valley Projects are entitled to resell the energy and capacity to other purchasers and 3) the interim suspension of deliveries to Edison shall not in any respect result in the modifications or termination of the Power Purchase Agreements and the Power Purchase Agreements shall in all respects continue in full force and effect other than the temporary suspension of deliveries to Edison. As a result of the March 22, 2001 Declaratory Judgment, the Imperial Valley Projects suspended deliveries of energy to Edison and entered into a transaction agreement with El Paso Merchant Energy, L.P. ("EPME") in which the Imperial Valley Projects' available power was sold to EPME based on percentages of the Dow Jones SP-15 Index. On June 18, 2001 the Superior Court terminated the Imperial Valley Projects' right to resell power pursuant to the Declaratory Judgment. On June 20, 2001, the Imperial Valley Projects (excluding Salton Sea Unit V and CE Turbo) entered into Agreements Addressing Renewable Energy Pricing and Payment Issues with Edison ("Settlement Agreements"). The Settlement Agreements require Edison make a series of payments to repay the past due balances under the Power Purchase Agreements (the "stipulated amounts"). The first payment of approximately $11.6 million, which represented 10% of the stipulated amounts, was received June 22, 2001. A second partial payment of 10% is payable within 5 days following the MOU Effective Date. The "MOU Effective Date" means the first day on which both of the following have occurred: (a) all legislation implementing the Memorandum of Understanding between Edison and the California Department of Water Resources dated April 9, 2001 ("MOU") or such other legislation based on the MOU or otherwise, that restores Edison to creditworthiness has become effective, and (b) the California Public Utilities Commission ("Commission") has issued all orders that are necessary to implement the MOU or other mechanisms contained in such legislation based on the MOU or otherwise which are designed to restore Edison to creditworthiness. The final payment, representing the remaining stipulated amounts, shall be paid on the 5th business day after Edison receives proceeds from the financing resulting from the MOU or other mechanisms contained in such other legislation based on the MOU or otherwise restore Edison to creditworthiness. In addition to these payments, Edison is required to make monthly interest payments calculated at a rate of 7% per annum on the outstanding stipulated amounts. The Settlement Agreements also provide a revised energy pricing structure, whereby Edison elects to pay the Imperial Valley Projects a fixed energy price of 5.37 cents/kilowatt hour in lieu of the Commission-approved SRAC Methodology under the Power Purchase Agreements, commencing on the first day of the month following the MOU Effective Date and expiring five years from such date. All other contract terms remain unchanged. As a result of the aforementioned Settlement Agreements, the Imperial Valley Projects resumed power sales to Edison on June 22, 2001. Energy payments are currently calculated using the SRAC formulas set forth in the Power Purchase Agreements until the fixed rate period begins. As a result of Edison's failure to make the payments due under the Power Purchase Agreements and the recent downgrades of Edison's credit ratings, Moody's downgraded the ratings for the Salton Sea Funding Corporation (the "Funding Corporation") Securities to Caa2 (negative outlook) and S&P downgraded the ratings for the Funding Corporation Securities to BBB- and placed the Securities on "credit watch negative". Moody's had downgraded the ratings for the CE Generation Securities to B1 from Baa3 (review for possible downgrade). Following the execution of the Settlement Agreements, Moody's placed the Salton Sea Funding and CE Generation securities on "credit watch positive". The Imperial Valley Projects are contractually entitled to receive payments under the Power Purchase Agreements and Settlement Agreements. However, due to the uncertainties associated with Edison's financial condition and failure to pay contractual obligations, CE Generation has established an allowance for doubtful accounts of approximately $82 million at June 30, 2001. New Accounting Pronouncements On January 1, 2001, the Company adopted Statement of Financial Accounting Standards Nos. 133 and 138 (SFAS 133/138) pertaining to the accounting for derivative instruments and hedging activities. SFAS 133/138 requires an entity to recognize all of its derivatives as either assets or liabilities in its statement of financial position and measure those instruments at fair value. If the conditions specified in SFAS 133/138 are met, those instruments may be designated as hedges. Changes in the value of hedge instruments would not impact earnings, except to the extent that the instrument is not perfectly effective as a hedge. Initial adoption of SFAS 133/138 did not have a material impact on the results of operations for the Company. The Financial Accounting Standards Board ("FASB") has approved guidance that, in general, option contracts and forward contracts with optionality features cannot qualify for the normal purchases and normal sales exception under SFAS 133/138 as amended. However, the FASB has also issued guidance that energy capacity contracts that include certain characteristics of purchased and written options could qualify as normal purchases and sales as long as certain criteria are met. The Company has performed a preliminary review of its contracts with the above characteristics and believes that its contracts are not subject to the financial reporting requirements of SFAS 133/138. Another issue which included tentative guidance as of the filing of the first quarter 2001 Form 10-Q, stated that derivative contracts which do not result in physical delivery of power because of transmission scheduling, referred to as bookouts, cannot meet the normal purchases and normal sales exception. This issue was abandoned by the FASB during the second quarter of 2001. The FASB's Derivatives Implementation Group continues to identify and provide guidance on various implementation issues related to SFAS 133/138 that are in varying stages of review and clearance by the Derivatives Implementation Group and the FASB. The Company is monitoring the issues being reviewed by the Derivatives Implementation Group and the FASB to determine what, if any, impact they may have on the Company's financial statements. In July 2001, the FASB issued SFAS No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets" which establish accounting and reporting for business combinations. SFAS No. 141 requires all business combinations entered into subsequent to June 30, 2001, to be accounted for using the purchase method of accounting. SFAS No. 142 provides that goodwill and other intangible assets with indefinite lives will not be amortized but will be tested for impairment on an annual basis. These standards are effective for the Company beginning on January 1, 2002. The Company is evaluating the impact resulting from the adoption of these standards. Forward-looking Statements Certain information included in this report contains forward-looking statements made pursuant to the Private Securities Litigation Reform Act of 1995 ("Reform Act"). Such 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 Reform Act, the Company has identified important factors that could cause actual results to differ materially from such expectations, including development and construction uncertainty, operating uncertainty, acquisition uncertainty, uncertainties relating to doing business outside of the United States, uncertainties relating to geothermal resources, uncertainties relating to domestic and international economic and political conditions and uncertainties regarding the impact of regulations, changes in government policy, industry deregulation and competition. Reference is made to all of the Company's SEC filings, including the Company's Report on Form 8-K dated March 26, 1999, incorporated herein by reference, for a description of such factors. The Company assumes no responsibility to update forward-looking information contained herein. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK The Company is exposed to market risk, including charges in the market price of certain commodities and interest rates. To manage the price volatility relating to these exposures, the Company enters into various financial derivative instruments. Senior management provides the overall direction, structure, conduct and control of the Company's risk management activities, including the use of financial derivative instruments, authorization and communication of risk management policies and procedures, strategic hedging program guidelines, appropriate market and credit risk limits, and appropriate systems for recording, monitoring and reporting the results of transactional and risk management activities. Refer to Note 7 in Notes to Consolidated Financial Statements for further discussion of derivatives used to hedge price risk and currency exchange rate risk. PART II - OTHER INFORMATION Item 1 Legal Proceedings. The Company and its subsidiaries have no material legal proceedings except for the following: Southern California Edison The Imperial Valley Projects have filed a lawsuit seeking a court order requiring Edison to make the required payments under the Power Purchase Agreements. See page 25. Cooper Litigation On July 23, 1997, the Nebraska Public Power District ("NPPD") filed a complaint, in the United States District Court for the District of Nebraska, naming MidAmerican Energy as the defendant and seeking declaratory judgment as to three issues under the parties' long-term power purchase agreement for Cooper capacity and energy. More specifically, the NPPD sought a declaratory judgment in the following respects: (1) that MidAmerican Energy is obligated to pay 50% of all costs and expenses associated with decommissioning Cooper, and that in the event that NPPD continues to operate Cooper after expiration of the power purchase agreement (September 2004), MidAmerican Energy is not entitled to reimbursement of any decommissioning funds it has paid to date or will pay in the future; (2) that the current method of allocating transition costs as a part of the decommissioning cost is proper under the power purchase agreement; and (3) that the current method of investing decommissioning funds is proper under the power purchase agreement. MidAmerican Energy filed its answer and contingent counterclaims. The contingent counterclaims filed by MidAmerican Energy are generally as follows: (1) that MidAmerican Energy has no duty under the power purchase agreement to reimburse or pay 50% of the decommissioning costs unless conditions to reimbursement occur; (2) that the NPPD has the duty to repay all amounts that MidAmerican Energy has prefunded for decommissioning in the event the NPPD operates the plant after the term of the power purchase agreement; (3) that the NPPD is equitably estopped from continuing to operate the plant after the term of the power purchase agreement; (4) that the NPPD has granted MidAmerican Energy an option to con- tinue taking 50% of the power from the plant; (5) that the term "monthly power costs" as defined in the power purchase agreement does not include costs and expenses associated with decommissioning the plant; (6) that MidAmerican Energy has no duty to pay for nuclear fuel, operations and maintenance projects or capital improvements that have useful lives after the term of the power purchase agreement; (7) that transition costs are not included in any decommissioning costs and expenses; (8) that the NPPD has breached its duty to MidAmerican Energy in making investments of decommissioning funds; (9) that reserves in named accounts are excessive and should be refunded to MidAmerican Energy; and (10) that the NPPD must credit MidAmerican Energy for payments by MidAmerican Energy for low-level radioactive waste disposal. On October 6, 1999, the court rendered summary judgment for the NPPD on the above-mentioned issue concerning liability for decommissioning (issue one in the first paragraph above) and the related contingent counterclaims filed by MidAmerican Energy (issues one, two, three and five in the second paragraph above). The court referred all remaining issues in the case to mediation, and cancelled the November 1999 trial date. MidAmerican Energy appealed the court's summary judgment ruling. On December 12, 2000, the United States Court of Appeals for the Eighth Circuit reversed the ruling of the district court and granted summary judgment in favor of MidAmerican Energy issues one and five in the second paragraph above. Additionally, it remanded the case for trial on all other claims and counterclaims. Since the remand to the District Court from the Eighth Circuit Court of Appeals, the NPPD has been granted permission, over MidAmerican Energy's objections, to amend its complaint. The amended complaint asserts that even though the Eighth Circuit Court of Appeals held that MidAmerican Energy has no liability under the power purchase agreement to reimburse or pay the NPPD a 50% share of decommissioning costs unless certain conditions occur, MidAmerican Energy has unconditional liability for a 50% share based on agreements other than the power purchase agreement as originally written. The NPPD's post-remand contentions -- all strongly disputed by MidAmerican Energy -- are that MidAmerican Energy has unconditional liability for a 50% share of decommissioning based on any of the following alternative theories: (i) the parties without written amendment either modified the power purchase agreement or made a separate agreement that imposes unconditional liability on MidAmerican Energy for decommissioning costs; (ii) absent unconditional liability for a 50% share of decommissioning costs, MidAmerican Energy would be unjustly enriched; (iii) MidAmerican Energy has unconditional liability for a 50% share of decommissioning costs based on promissory estoppel; or (iv) the NPPD is entitled to have the power purchase agreement reformed to provide that MidAmerican Energy has unconditional liability for a 50% share of decommissioning costs. MidAmerican Energy will strongly dispute at trial these contentions and theories put forth by the NPPD. Trial in these matters is scheduled to begin on March 4, 2002. Item 2 Changes in Securities and Use of Proceeds. Not applicable. Item 3 Defaults on 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: Exhibits Filed Herewith Exhibit 15 - Awareness Letter of Independent Accountants. (b) Reports on Form 8-K: None 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: August 14, 2001 /s/ Patrick J. Goodman ------------------------------------ Patrick J. Goodman Senior Vice President & Chief Financial Officer EXHIBIT INDEX Exhibit No. Page No. ----------- -------- 15 Awareness Letter of Independent Accountants 33 Exhibit 15 AWARENESS LETTER OF INDEPENDENT ACCOUNTANTS MidAmerican Energy Holdings Company Des Moines, Iowa We have made a review, in accordance with standards established by the American Institute of Certified Public Accountants, of the unaudited consolidated interim financial information of MidAmerican Energy Holdings Company and subsidiaries for the period ended June 30, 2001 and for the period March 14, 2000 to June 30, 2000 for MidAmerican Energy Holdings Company and for the period January 1, 2000 to March 13, 2000 for MidAmerican Energy Holdings Company (Predecessor), as indicated in our report dated August 6, 2001; because we did not perform an audit, we expressed no opinion on that information. We are aware that our report referred to above, which is included in your Quarterly Report on Form 10-Q for the quarter ended June 30, 2001, is incorporated by reference in Registration Statements No. 333-30537, No. 333-45615 and No. 333-62697 on Form S-3. We also are aware that the aforementioned report, pursuant to Rule 436(c) under the Securities Act of 1933, is not considered a part of a Registration Statement prepared or certified by an accountant or a report prepared or certified by an accountant within the meaning of Sections 7 and 11 of that Act. DELOITTE & TOUCHE LLP Des Moines, Iowa August 14, 2001