MIDAMERICAN ENERGY HOLDINGS CO /NEW/ - 10-Q Quarterly Report

HomeServices’ operating revenue, consisting mainly of commission revenue from real estate brokerage transactions, increased $231.0 million, or 20.8%, to $1,343.6 million for the nine months ended September 30, 2004. The increase is due to growth from existing businesses totaling $127.6 million reflecting higher unit sales and average sales prices and acquisitions not included in the comparable 2003 period totaling $103.4 million. During the nine months ended September 30, 2004, HomeServices’ existing businesses closed 143,191 brokerage sides, up 1.7% from 140,825 closed sides in the comparable 2003 period. Closed brokerage volume at existing businesses was $42.4 billion during the nine months ended September 30, 2004, up 16.5%, from $36.4 billion in the comparable 2003 period.

Income on equity investments for the nine months ended September 30, 2004, decreased $12.3 million to $28.1 million. The decrease is mainly due to a $8.4 million reduction in income from power generation equity investments and a $4.9 million reduction in equity income from HomeServices due to lower refinancing activity at its residential mortgage loan joint ventures.

Interest and dividend income for the nine months ended September 30, 2004, decreased $14.4 million to $25.5 million. The decrease is mainly due to $17.2 million of income received in 2003 from the Company’s investment in The Williams Companies Cumulative Convertible Preferred Stock. The investment was sold in June 2003. The decrease was partially offset by higher cash balances and the weaker U.S. dollar.

Other income for the nine months ended September 30, 2004, decreased $8.8 million to $44.5 million. The decrease is mainly due to a $13.8 million gain on the sale of The Williams Companies Cumulative Convertible Preferred Stock and $14.8 million in the allowance for equity funds used during the construction at Kern River, both in 2003. These items were partially offset by a $14.8 million bankruptcy award received by Kern River in May 2004 from Mirant, higher allowance for equity funds used during the construction of MidAmerican Energy’s generation projects throughout 2004 and gains on asset sales at Northern Natural Gas.

Cost of sales for the nine months ended September 30, 2004, increased $258.4 million, or 14.7%, to $2,020.1 million from $1,761.7 million in the comparable 2003 period. HomeServices’ cost of sales, consisting primarily of commissions on real estate brokered transactions, increased $174.8 million due to higher commission expense on incremental sales at existing business units and acquisitions not included in the comparable 2003 period. MidAmerican Energy’s cost of sales increased $35.2 million, primarily due to higher non-regulated electric volumes and higher cost per megawatt-hour, partially offset by lower non-regulated natural gas prices. CE Electric UK’s cost of sales increased $22.6 million mainly due to increased activity at its contracting business and the weaker U.S. dollar, partially offse t by lower exit charges at both NED and YED. Northern Natural Gas’ cost of sales increased $15.2 million due mainly to higher gas and liquids sales.

Operating expenses for the nine months ended September 30, 2004, increased $93.3 million, or 8.3%, to $1,216.5 million from $1,123.2 million in the comparable 2003 period. HomeServices’ operating expenses, consisting mainly of compensation, marketing and other administrative costs, increased $34.0 million due mainly to acquisitions. MidAmerican Energy’s operating expenses increased $27.8 million, primarily due to higher generation maintenance and transmission costs. CE Electric UK’s operating expenses increased $25.4 million, mainly due to higher pension cost amortization and the weaker U.S. dollar. Kern River’s operating expenses increased $12.5 million due to the commencement of operations of the Kern River 2003 Expansion Project. CalEnergy Generation-Foreign’ operating expenses decrea sed $10.5 million mainly due to lower legal costs in 2004.

Depreciation and amortization for the nine months ended September 30, 2004, increased $62.5 million to $496.4 million from $433.9 million in the comparable 2003 period. MidAmerican Energy’s expense increased $19.2 million due primarily to an increase in regulatory expense related to its revenue sharing arrangement. Northern Natural Gas’ expense increased $17.2 million due to higher depreciation rates consistent with the estimated rate settlement. Kern River’s expense increased $13.1 million due to the completion of the Kern River 2003 Expansion Project. CE Electric UK’s expense increased $8.2 million primarily due to the weaker U.S. dollar.

Interest expense for the nine months ended September 30, 2004, increased $139.1 million to $677.8 million. On October 1, 2003, the Company adopted FIN 46R related to certain finance subsidiaries. The adoption required that amounts previously recorded in minority interest and preferred dividends be recorded as interest expense in the accompanying consolidated statement of operations. For the period from January 1, 2004 to September 30, 2004, the Company has recorded $149.5 million of interest expense related to these finance subsidiaries. In accordance with the requirements of FIN 46R, no amounts prior to adoption on October 1, 2003 have been reclassified. The amount included in minority interest and preferred dividends for the nine-month period ended September 30, 2003 was $170.2 million, which included $7.3 mil lion of expense from the purchase and retirement of preferred securities of subsidiary trusts in June 2003.

The remaining $10.4 million decrease in interest expense resulted from decreased interest, totaling $23.8 million, due mainly to the Company's scheduled redemption of $215.0 million of 6.96% Senior Notes (September 2003), redemption in full of the outstanding shares of the Yorkshire Capital Trust I, 8.08% trust securities (June 2003), and reductions in CalEnergy Generation-Foreign project debt. These decreases were partially offset by additional interest expense totaling $13.8 million on the Company’s debt issuances of $450.0 million of 3.5% Senior Notes (May 2003) and $250.0 million of 5.0% Senior Notes (February 2004) and the effects of the weaker U.S. dollar.

Capitalized interest for the nine months ended September 30, 2004, decreased $10.1 million to $16.0 million. The decrease was mainly due to the discontinuance of capitalizing interest on the Kern River 2003 Expansion Project, partially offset by increased construction activity at MidAmerican Energy’s generation projects and CE Gas’ Yolla project.

The income tax provision for the nine months ended September 30, 2004, increased $17.9 million to $202.1 million. The effective tax rate increased for the nine months ended September 30, 2004, mainly due to the effect of the $170.2 million of tax deductible interest on subordinated debt not included in income from continuing operations before income taxes in 2003, higher taxable income at platforms with higher tax rates, including Kern River, Northern Natural Gas and HomeServices, and increased taxes at CalEnergy Generation-Foreign as a result of the expiration of the income tax holiday at a Leyte project.

Minority interest and preferred dividends for the nine months ended September 30, 2004 decreased $170.0 million to $9.9 million. This decrease was due to the adoption of FIN 46R, as previously described.

Liquidity and Capital Resources

The Company has available a variety of sources of liquidity and capital resources, both internal and external. These resources provide funds required for current operations, construction expenditures, debt retirement and other capital requirements. The Company may from time to time seek to retire its outstanding debt through cash purchases in the open market, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

The Company's cash and cash equivalents were $975.8 million at September 30, 2004, compared to $660.2 million at December 31, 2003. Each of MEHC's direct or indirect subsidiaries is organized as a legal entity separate and apart from MEHC and its other subsidiaries. Pursuant to separate financing agreements at each subsidiary, the assets of each subsidiary may be pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. It should not be assumed that any asset of any subsidiary of MEHC will be available to satisfy the obligations of MEHC or any of its other subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements for such parties, b e advanced, loaned, paid as dividends or otherwise distributed or contributed to MEHC or affiliates thereof.

In addition, the Company recorded separately, in restricted cash and short-term investments and deferred charges and other assets, restricted cash and investments of $166.4 million and $119.5 million at September 30, 2004, and December 31, 2003, respectively. The restricted cash balance for both periods is comprised primarily of amounts deposited in restricted accounts which are reserved for the service of debt obligations, customer deposits held in escrow, and unpaid dividends declared obligations.

Cash flows from Operating Activities

The Company generated cash flows from operations of $1,221.8 million for the nine months ended September 30, 2004, compared with $1,013.3 million for the comparable period in 2003. The net increase was mainly due to a tax refund as a result of a 2003 net operating loss from accelerated depreciation. Also contributing to the net increase in cash flows from operations were changes in working capital and higher non-cash charges for depreciation and amortization, partially offset by the timing of distributions from equity investments.

Cash Flows from Investing Activities

Cash flows used in investing activities for the nine months ended September 30, 2004 were $638.9 million, compared with $721.9 million for the same period in 2003. The decrease was mainly due to lower capital expenditures in 2004 along with the collection of the ROP Note and a settlement received from the International Chamber of Commerce (“ICC”), as described below, partially offset by $288.8 million of proceeds from the sale of convertible preferred securities in 2003 and the timing of construction related payments at MidAmerican Energy and Kern River, which comprised the majority of other investing cash flows in both 2004 and 2003.

Put of ROP Note and Receipt of Cash

On January 14, 2004, CE Casecnan exercised its right to put the ROP Note to the ROP and, in accordance with the terms of the put option, CE Casecnan received $99.2 million (representing $97.0 million par value plus accrued interest) from the ROP on January 21, 2004.

ICC Settlement and Receipt of Cash

On April 7, 2004, CE Casecnan entered into an agreement settling the ICC arbitration related to the CE Casecnan construction contract. Pursuant to the settlement agreement, $19.1 million was paid to CE Casecnan on April 14, 2004. A total of $23.9 million (the $19.1 million receipt, less $0.2 million placed in escrow, along with the $3.8 million amount originally recorded for liquidated damages and the $1.2 million accrual for the unpaid portion of the contract) was recorded as a reduction of properties, plants and equipment in the second quarter of 2004, reflecting the receipt of the settlement payment and the release of other costs accrued in connection with the arbitration proceedings.

Capital Expenditures, Construction and Other Development Costs

Capital expenditures, construction and other development costs were $796.4 million for the nine months ended September 30, 2004 as compared with $876.3 million for the same period in 2003. The following table summarizes the expenditures by business segment (in millions):

	Nine Months
	Ended September 30,
	2004		2003
MidAmerican Energy	$	425.7	$	228.5
Kern River		17.2		355.5
Northern Natural Gas		87.7		73.6
CE Electric UK		233.3		198.8
CalEnergy Generation-Domestic		1.2		4.2
CalEnergy Generation-Foreign		2.1		5.5
HomeServices		10.8		10.0
Segment capital expenditures		778.0		876.1
Corporate/other		18.4		0.2
Total capital expenditures	$	796.4	$	876.3

Forecasted capital expenditures, construction and other development costs for fiscal 2004 are estimated to be approximately $1.3 billion, including the partial completion of the wind power project discussed below. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews. The Company expects to meet these capital expenditures with cash flows from operations and the issuance of debt. Capital expenditures relating to operating projects, consisting mainly of recurring expenditures, were $524.8 million for the nine months ended September 30, 2004. Construction and other development costs were $271.6 million for the nine months ended September 30, 2004. These costs consist mainly of expenditures for large scale, generation projects as follows:

MidAmerican Energy

MidAmerican Energy anticipates a continuing increase in demand for electricity from its regulated customers. To meet anticipated demand and ensure adequate electric generation in its service territory, MidAmerican Energy is currently constructing three electric generating projects in Iowa. Upon completion, the projects will provide service to regulated retail electricity customers. MidAmerican Energy has obtained regulatory approval to include the actual costs of the generation projects in its Iowa rate base as long as actual costs do not exceed the agreed caps that MidAmerican Energy has deemed to be reasonable. If the caps are exceeded, MidAmerican Energy has the right to demonstrate the prudence of the expenditures above the caps subject to regulatory review. Wholesale sales may also be made from the projects to the extent the power is not needed for regulated retail service. MidAmerican Energy expects to invest approximately $1.4 billion in the three projects, of which approximately $541 million has been invested through September 30, 2004.

The first project is a natural gas-fired combined cycle unit with an estimated cost of $357 million, excluding allowance for funds used during construction. MidAmerican Energy will own and operate the plant. Commercial operation of the simple cycle mode began on May 5, 2003. The plant, which has operated in simple cycle mode during 2004, resulted in 327 megawatts (“MW”) of accredited capacity in the summer of 2004. The combined cycle operation is expected to commence by December 2004 and achieve an expected additional accredited capacity of 190 MW.

The second project is currently under construction and will be a 790 MW (based on expected accreditation) super-critical-temperature, low-sulfur coal-fired plant. MidAmerican Energy will operate the plant and hold an undivided ownership interest as a tenant in common with the other owners of the plant. MidAmerican Energy’s ownership interest is 60.67%, equating to 479 MW of output. MidAmerican Energy expects its share of the estimated cost of the project to be approximately $713 million, excluding allowance for funds used during construction. Municipal, cooperative and public power utilities will own the remainder, which is a typical ownership arrangement for large base-load plants in Iowa. On May 29, 2003, the Iowa Utilities Board (“IUB”) issued an order approving the ratemaking princip les for the plant, and on June 27, 2003, MidAmerican Energy received a certificate from the IUB allowing MidAmerican Energy to construct the plant. On September 9, 2003, MidAmerican Energy began construction of the plant, which it expects to be completed in the summer of 2007. MidAmerican Energy is also seeking an order from the IUB approving construction of the associated transmission facilities.

The third project consists of wind power facilities totaling 310 MW based on the nameplate rating. Generally speaking, accredited capacity ratings for wind power facilities are considerably less than the nameplate ratings due to the varying nature of wind. The current projected accredited capacity for these wind power facilities is approximately 53 MW. MidAmerican Energy will own and operate these facilities, which are expected to cost approximately $323 million. MidAmerican Energy’s plan to construct the wind project is in conjunction with a settlement agreement that extends through December 31, 2010, an Iowa retail electric rate freeze that was previously scheduled to expire at the end of 2005. The settlement agreement, which was filed with the IUB as part of MidAmerican Energy’s application for ratemaking principles for the wind project, was approved by the IUB on October 17, 2003. MidAmerican Energy has also received authorization from the IUB to construct the wind power project. The settlement agreement provides that the obligation of MidAmerican Energy to construct the wind project may be terminated by MidAmerican Energy if the Federal production tax credit applicable to the wind energy facilities is not available at a rate of 1.8 cents per kilowatt (“kWh”) for a period of at least ten years after the facilities begin generating electricity. On October 4, 2004, the President signed into law legislation that extends the Federal production tax credit to electricity produced by wind energy facilities placed in service prior to January 1, 2006. The credit is allowable for production during the 10-year period after a facility is originally placed in service. Accordingly, MidAmerican Energy has begun construction of the wind power facilities and anticipates approximately one half of the facilities will be generating electricity by the end of 2004. The remaining facilities are expected to be completed by the middle of 2005. Also if MidAmerican Energy does not construct the wind power facilities by December 31, 2006 the rate extension from January 1, 2006 through December 31, 2010 may terminate.

Kern River

On May 1, 2003, Kern River completed the construction of its Kern River 2003 Expansion Project at a total cost of approximately $1.2 billion. The expansion increased the design capacity of the existing Kern River pipeline by 885,626 decatherms per day to 1,755,626 decatherms per day.

Cash Flows from Financing Activities

Cash flows used in financing activities for the nine months ended September 30, 2004 were $268.7 million. During 2004, the Company used cash for financing activities of $469.7 million, which includes $136.4 million of cash flows from discontinued operations, for repayments of subsidiary and parent company obligations, and generated cash from financing activities of $270.8 million from the issuances of subsidiary, project and parent company debt. Cash flows used in financing activities for the nine months ended September 30, 2003 were $395.0 million. During 2003, the Company generated cash from financing activities, totaling $1,598.0 million, from the issuance of subsidiary, project and parent company debt, and used cash for financing activities, totaling $1,883.8 million, for repayments of subsidiary obligations and parent company debt and the retirement of preferred securities of subsidiary trusts.

Recent Debt Issuances, Redemptions and Stock Transactions

On October 1, 2004, MidAmerican Energy issued $350 million of 4.65% medium-term notes due October 1, 2014. The proceeds will be used by MidAmerican Energy for general corporate purposes.

On February 12, 2004, MEHC completed the sale of $250 million in aggregate principal amount of its 5.00% senior notes due February 15, 2014. The proceeds were used to satisfy a demand made by its affiliate, Funding Corporation, for $136.4 million, the amount remaining on MEHC’s guarantee of Funding Corporation’s Series F Bonds, and for other general corporate purposes.

On March 1, 2004, Funding Corporation completed the redemption of an aggregate principal amount of approximately $136.4 million of its Series F Bonds, pro rata, at a redemption price of 100% of such aggregate outstanding principal amount, plus accrued interest to the date of redemption. A demand was also made on MEHC for the full amount remaining on MEHC’s guarantee of the Series F Bonds in order to fund the redemption. MEHC made the requisite payment and, as a result, it has no further liability with respect to its guarantee.

On January 6, 2004, the Company purchased two hundred thousand shares of common stock owned by the Company’s chairman and chief executive officer, for an aggregate purchase price of $20.0 million.

Current Maturities of Debt

The Company’s current portion of long-term debt increased $553.4 million to $1,054.3 million at September 30, 2004, from $500.9 million at December 31, 2003 due to $260.0 million of 7.23% parent company senior notes becoming due in the third quarter of 2005. Additionally, in February 2005, a subsidiary of CE Electric UK has the option (which it currently intends to exercise) to redeem its Variable Rate Reset Trust Securities, due in 2020, at a par value of £155 million.

Restricted Cash and Short-term Investments

During the nine months ended September 30, 2004, CE Casecnan increased its restricted cash related to obligations for debt service and unpaid dividends declared.

Discontinued Operations - Zinc Recovery Project and Mineral Assets

MEHC, through its indirect wholly owned subsidiaries, owns the rights to commercial quantities of extractable minerals from elements in solution in the geothermal brine and fluids utilized at certain geothermal energy generation facilities located in the Imperial Valley of California and a zinc recovery plant constructed near the geothermal energy generation facilities designed to recover zinc from the geothermal brine through an ion exchange, solvent extraction, electrowinning and casting process.

The Zinc Recovery Project began limited production during December 2002 and continued limited production until September 10, 2004. Efforts to increase production had continued since the Zinc Recovery Project was place in service with an emphasis on process modification. Management had been assessing the long-term economic viability of the Zinc Recovery Project in light of continuing cash flow and operating losses and the efforts to increase production, and had continued to evaluate the expected impact of the planned improvements to the extraction process during the third quarter of 2004. Furthermore, management had been exploring other operating alternatives, such as establishing strategic partnerships and consideration of ceasing operations of the Zinc Recovery Project.

On September 10, 2004, management made the decision to cease operations of the Zinc Recovery Project, effective immediately. Based on this decision, a non-cash, after-tax impairment charge of $340.3 million has been recorded to write-off the Mineral Assets.

In connection with ceasing operations, the Zinc Recovery Project’s assets will be sold and certain employees of the operator of the Zinc Recovery Project have been paid one-time termination benefits. As a result of ceasing operations of the Zinc Recovery Project, MEHC expects to make cash expenditures of approximately $13 million, consisting of pre-tax disposal costs, termination benefit costs and property taxes. Substantially all of such costs are expected to relate to disposal activities, and a portion of the disposal costs is expected to be offset by proceeds from sales of the Zinc Recovery Project’s assets. These costs are recognized in the period in which the related liability is incurred. Salvage proceeds will be recognized in the period earned. Implementation of a disposal plan began in Septembe r 2004 and is expected to continue into 2005. MEHC also expects to receive approximately $55 million in future tax benefits.

The operating losses from discontinued operations before income taxes during the nine-month periods ended September 30, 2004 and 2003 were $42.7 million and $31.4 million, respectively.

Enron Note Receivable

In connection with Northern Natural Gas’ sale by Enron Corp. (“Enron”) to Dynegy, Inc. in January 2002, Northern Natural Gas forgave the portion of a note receivable from Enron (the “Enron Note Receivable”) that exceeded a balance of approximately $259 million. Enron and numerous affiliated companies filed for bankruptcy on December 2, 2001. Enron’s disclosures of overstated earnings and previously undisclosed debts, as well as reports in the news media that unsecured creditors could expect to receive little more than a few cents on the dollar, led Northern Natural Gas to write-off the remaining value of the Enron Note Receivable as of December 31, 2001. Enron’s Bankruptcy Court proceedings are continuing. The disclosure statement filed with the Fifth Amended Plan and Disclosure Statement (“Amended Plan”) was approved by the Bankruptcy Court on January 9, 2004. On July 15, 2004, the Bankruptcy Court confirmed the Amended Plan, as modified (the “Plan”). On August 26, 2004, the Bankruptcy Court approved the stipulation between Enron and Northern Natural Gas settling the amount payable on the Enron Note Receivable at $249 million. The Plan will be implemented on the effective date, which will occur when precedent conditions are satisfied or waived, but no earlier than December 31, 2004. Initial distributions to creditors are not expected to occur until late 2004 or 2005. To date, no amounts have been received. Although collection of any amount is uncertain, the Plan referenced above provides an estimated recovery of $0.174 per dollar for unsecured creditors of Enron. Northern Natural Gas expects to reflect any recovery as income in the period payment is received. Additionally, Northern Natural Gas may be able to sell its claim to a th ird party.

Credit Risk Ratings

Debt and preferred securities of the Company may be rated by nationally recognized credit rating agencies. Assigned credit ratings are based on each rating agency’s assessment of the rated company’s ability to, in general, meet the obligations of its debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time. Other than the agreements discussed below, the Company does not have any credit agreements that require termination or a material change in collateral requirements or payment schedule in the event of a downgrade in the credit ratings of the respective company’s securities.

In conjunction with its wholesale marketing and trading activities, MidAmerican Energy must meet credit quality standards as required by counterparties. MidAmerican Energy has energy trading agreements that, in accordance with industry practice, either specifically require it to maintain investment grade credit ratings or provide the right for counterparties to demand ‘‘adequate assurances’’ in the event of a material adverse change in MidAmerican Energy’s creditworthiness. If one or more of MidAmerican Energy’s credit ratings decline below investment grade, MidAmerican Energy may be required to post cash collateral, letters of credit or other similar credit support to facilitate ongoing wholesale marketing and trading activities. As of September 30, 2004, MidAmerican Energy’s estimated potential collateral requirements totaled approximately $87 million. MidAmerican Energy’s collateral requirements could fluctuate considerably due to seasonality, market price volatility, and a loss of key MidAmerican Energy generating facilities or other related factors.

Yorkshire Power Group Limited, a subsidiary of CE Electric UK, entered into certain currency rate swap agreements for its Yankee Bonds with three large multi-national financial institutions. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate in Sterling. For the $281.1 million of the 6.496% Yankee Bonds outstanding at September 30, 2004, the agreements extend until February 25, 2008 and convert the U.S. dollar interest rate to a fixed Sterling rate ranging from 7.3175% to 7.345%. The estimated fair value of these swap agreements at September 30, 2004 was $70.0 million based on quotes from the counterparties to these instruments and represents the estimated amount that the Company would expect to pay if these agreements were terminated. Certain of these counterparties have the option to terminate the swap agreements and demand payment of the fair value of the swaps if Yorkshire Power Group Limited’s credit ratings from the three recognized credit rating agencies decline below investment grade. As of September 30, 2004, Yorkshire Power Group Limited’s credit ratings from the three recognized credit rating agencies were investment grade; however, if the ratings fell below investment grade, payment requirements would have been approximately $32.6 million.

Regulatory Matters

MidAmerican Energy

Rate Matters

Under two settlement agreements approved by the IUB, MidAmerican Energy’s overall Iowa retail electric rates are effectively frozen through December 31, 2010. The settlement agreements specifically allow the filing of electric rate design or cost of service rate changes that could result in changes to rates for specific classes of customers, but are intended to keep MidAmerican Energy’s overall Iowa retail electric revenue unchanged. The settlement agreements also each provide that portions of revenues associated with Iowa retail electric returns on equity within specified ranges will be recorded as a regulatory liability to be used to offset a portion of the cost to Iowa customers of future generating plant investment.

Under the first settlement agreement, which was approved by the IUB on December 21, 2001, and is effective through December 31, 2005, an amount equal to 50% of revenues associated with returns on equity between 12% and 14%, and 83.33% of revenues associated with returns on equity above 14%, in each year is recorded as a regulatory liability. The second settlement agreement, which was filed in conjunction with MidAmerican Energy’s application for ratemaking principles on a wind power project and was approved by the IUB on October 17, 2003, provides that during the period January 1, 2006 through December 31, 2010, an amount equal to 40% of revenues associated with returns on equity between 11.75% and 13%, 50% of revenues associated with returns on equity between 13% and 14%, and 83.3% of revenues associated with returns on equity above 14%, in each year will be recorded as a regulatory liability. An amount equal to the regulatory liability is recorded as a regulatory charge in depreciation and amortization expense when the liability is accrued. Additionally, interest expense is accrued on the portion of the regulatory liability balance recorded in prior years. The liability is being reduced as it is credited against plant in service in amounts equal to the allowance for funds used during construction associated with generating plant additions. Future depreciation will be reduced as a result of the credit applied to generating plant balances from the reduction of the regulatory liability. As of September 30, 2004 and December 31, 2003, the related regulatory liability reflected in the accompanying consolidated balance sheets within other long-term accrued liabilities was $206.1 million and $144.4 million, respectively.

The second settlement agreement also provides that if Iowa retail electric returns on equity fall below 10% in any consecutive 12-month period from January 1, 2006 through December 31, 2010, MidAmerican Energy may seek to file for a general increase in rates. However, prior to filing for a general increase in rates, MidAmerican Energy is required by the settlement agreement to conduct 30 days of good faith negotiations with all of the signatories to the settlement agreement to attempt to avoid a general increase in rates.

Illinois bundled electric rates are frozen until 2007, subject to certain exceptions allowing for increases, at which time bundled rates are subject to cost-based ratemaking. Illinois law provides for Illinois earnings above a computed level of return on common equity to be shared equally between regulated retail electric customers and MidAmerican Energy. MidAmerican Energy’s computed level of return on common equity is based on a rolling two-year average of the Monthly Treasury Long-Term Average Rate, as published by the Federal Reserve System, plus a premium of 8.5% for 2000 through 2004 and a premium of 12.5% for 2005 and 2006. The two-year average above which sharing must occur for 2004 is 13.57%. The law allows MidAmerican Energy to mitigate the sharing of earnings above the threshold return on common equity through accelerated recovery of electric assets.

Transmission Developments

The FERC has undertaken several measures to increase competition in the markets for wholesale electric energy, including efforts to foster the development of regional transmission organizations (“RTO”) in its Order No. 2000 issued December 1999 and its July 2002 proposed rulemaking that would implement a standard market design (“SMD”) for wholesale electric markets.

If implemented, the FERC’s July 2002 proposed rule for SMD would require sweeping changes to the use and expansion of the interstate transmission and wholesale bulk power systems in the United States. However, it is unclear when or even whether the FERC will issue a final rule and what form the final rule would ultimately take. In response to significant criticism of its proposed rule, the FERC subsequently indicated that it had changed its proposal and would adopt a flexible approach to SMD that would accommodate regional differences. Any final rule on SMD or similar FERC action may impact the costs of MidAmerican Energy’s electricity and transmission products. Such FERC action could directly or indirectly influence how transmission services are priced, the availability of transmission services, and how transmission services are obtained. In addition, the FERC could affect how wholesale electricity is bou ght and sold, as well as the geographic scope of the wholesale marketplace in which MidAmerican Energy buys and sells electricity. MidAmerican Energy recognizes there is considerable uncertainty as to the timing and outcome of these transmission policy issues and will continue to evaluate evolving FERC policies. Transferring the operations and control of MidAmerican Energy’s transmission assets to other entities could increase costs for MidAmerican Energy; however, the actual effect of any such transaction on MidAmerican Energy’s future transmission costs, or alternate RTO strategies, is not yet known.

On June 3, 2004, the FERC’s Division of Operational Investigations of the Office of Market Oversight and Investigations informed MidAmerican Energy that it was commencing an audit to determine whether and how MidAmerican Energy and its subsidiaries and affiliates are complying with (1) requirements of the standards of conduct and open access same time information system of the Commission‘s regulations; (2) codes of conduct; and (3) transmission practices. The FERC has commenced several such audits of utilities in 2003 and 2004. The audit is on-going, and MidAmerican Energy does not expect it to be completed for several months.

Generation Matters

On July 13, 2004, the FERC issued an order requiring MidAmerican Energy to conduct a study to determine whether MidAmerican Energy or its affiliates possess generation market power. MidAmerican Energy is being required to show the absence of generation market power in order to be allowed to continue to sell wholesale electric power at market-based rates. The FERC order is intended to have MidAmerican Energy conform to what has become the FERC’s general practice for utilities given authorization to make wholesale market-based sales. Under this general practice, utilities authorized to make market-based electric sales must submit a new market power study to the FERC every three years. In its order, the FERC has stated that MidAmerican Energy’s market-based sales will become subject to refund beginni ng November 1, 2004. The refund obligation will then extend until the conclusion of the proceeding. MidAmerican Energy does not expect any outcome of this issue to have a material effect on its results of operations, financial position or cash flows.

Kern River

Kern River was required to file a general rate case no later than May 1, 2004 pursuant to the terms of its 1998 FERC Docket No. RP99-274 rate case settlement. Kern River filed its rate case on April 30, 2004 which supports a revenue increase of approximately $40.1 million representing a 13% increase from its existing cost of service and a proposed overall cost of service of $347.4 million. Since its last rate case, Kern River has increased the capacity of its system from 724,500 decatherm (“Dth”) per day to 1,755,626 Dth per day at a cost of approximately $1.3 billion resulting in a total rate base of approximately $1.8 billion. The FERC suspended the rate increase until November 1, 2004, and set a procedural order with a hearing scheduled for March 2005.

Northern Natural Gas

Northern Natural Gas has implemented a straight fixed variable rate design which provides that all fixed costs assignable to firm capacity customers, including a return on equity, are to be recovered through fixed monthly demand or capacity reservation charges which are not a function of throughput volumes.

On May 1, 2003, Northern Natural Gas filed a request for increased rates with the FERC. The rate increase is primarily attributable to four main cost areas: the capital investment made by Northern Natural Gas in the five years since its last rate case, an increase in Northern Natural Gas' depreciation rates, increased return on equity, and changes in the level of contract entitlement. The rate filing provides evidence in support of a $71 million increase to Northern Natural Gas’ annual revenue requirement. However, Northern Natural Gas chose to effectuate only $55 million of the increase. Northern Natural Gas’ new rates went into effect November 1, 2003, subject to refund.

Additionally, on January 30, 2004, Northern Natural Gas filed with the FERC to increase its revenue requirement by an incremental $30 million to that requested in the May 1, 2003 filing. The increased rates are primarily attributable to ongoing pipeline integrity initiative costs that Northern Natural Gas has undertaken since the May 1, 2003 rate filing. The FERC suspended the rate increase until August 1, 2004 and consolidated the 2003 and 2004 rate cases due to the similarity of issues in both cases and the updated costs. On July 29, 2004, Northern Natural Gas notified the FERC that, in furtherance of settlement negotiations, Northern Natural Gas was not moving the rate increase into effect on August 1, 2004, but reserved its statutory right to move the suspended rates into effect at a later date. On October 8, 2004, Northern Natural Gas filed a motion to place the rate incr ease into effect on November 1, 2004, subject to refund. A hearing on the consolidated cases is scheduled for March 2005.

CE Electric UK

The majority of the revenue of the Distribution License Holders (“DLH”) in the United Kingdom is controlled by a distribution price control formula which is set out in the license of each DLH. It has been the practice of Ofgem (and its predecessor body, the Office of Electricity Regulation), to review and reset the formula at five-year intervals, although the formula may be further reviewed at other times at the discretion of the regulator. Any such resetting of the formula requires the consent of the DLH. If the DLH does not consent to the formula reset, it is reviewed by the United Kingdom's competition authority, whose recommendations can then be given effect by license modifications made by Ofgem.

The current formula requires that regulated distribution income per unit is increased or decreased each year by RPI-Xd where RPI means the Retail Price Index (‘‘RPI’’), reflecting the average of the 12-month inflation rates recorded for each month in the previous July to December period. The Xd factor in the formula was established by Ofgem at the last price control review (and continues to be set) at 3%. The formula also takes account of the changes in system electrical losses, the number of customers connected and the voltage at which customers receive the units of electricity distributed. The distribution price control formula determines the maximum average price per unit of electricity distributed (in pence per kWh) which a DLH is entitled to charge. The distribution price control formula permits DLHs to receive additional revenue due to increased distribution of units and a predetermined increase in end users. The price control does not seek to constrain the profits of a DLH from year to year. It is a control on revenue that operates independently of most of the DLH’s costs. During the lifetime of the price control, cost savings or additional costs have a direct impact on profit.

The procedure and methodology adopted at a price control review is at the reasonable discretion of Ofgem. At the last such review, concluded in 1999 and effective April 2000, Ofgem's judgment of the future allowed revenue of licensees was based upon, among other things:

·	the actual operating costs of each of the licensees;

·	the operating costs which each of the licensees would incur if it were as efficient as, in Ofgem's judgment, the most efficient licensee;

·	the regulatory value to be ascribed to each of the licensees' distribution network assets;

·	the allowance for depreciation of the distribution network assets of each of the licensees;

·	the rate of return to be allowed on investment in the distribution network assets by all licensees; and

·	the financial ratios of each of the licensees and the license requirement for each licensee to maintain an investment grade status.

As a result of the last review, the allowed revenue of NED's distribution business was reduced by 24%, in real terms, and the allowed revenue of YED's distribution business was reduced by 23%, in real terms, with effect from April 1, 2000. The range of reductions for all licensees in Great Britain was between 4% and 33%.

Ofgem’s process of reviewing each DLH's existing price control formula, with a revised formula for each DLH (including NED and YED) expected to take effect from April 1, 2005 for an expected period of five years, is nearing completion. The process has involved the collection of data from each DLH via written submissions and meetings with representatives of the various companies. On September 27, 2004, Ofgem published its updated proposals, which indicated a reduction in the allowed income on NED and YED of 3% and 13%, respectively, in real terms. The range of allowed revenue adjustments for all DLHs was from an increase of 11% to a reduction of 13%. The Xd factor in the updated proposals was set at zer o. It is expected that Ofgem will issue final proposals on November 29, 2004. Each DLH will then have until December 22, 2004 to accept or reject the proposals, which if accepted will be implemented through a license modification in the first quarter of 2005, having effect from April 1, 2005.

Obligations, Commitments and Contingencies

There have been no material changes in obligations, commitments and contingencies from the information provided in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, other than the items described below. Refer to Note 8 of Notes to the Consolidated Financial Statements for more discussion on commitments and contingencies.

Recent Debt Issuances

On October 1, 2004, MidAmerican Energy issued $350 million of 4.65% medium-term notes due October 1, 2014. The proceeds will be used by MidAmerican Energy for general corporate purposes.

Electric Capacity Commitments

MidAmerican Energy has contracts with non-affiliated companies to purchase electric capacity. In January 2004, MidAmerican Energy and the Nebraska Public Power District (“NPPD”) entered into a series of agreements that will result in MidAmerican Energy purchasing 250 megawatts of NPPD capacity for a five-year period commencing January 1, 2005. As of September 30, 2004, total non-affiliated electric capacity contracts, with expiration dates ranging from 2004 to 2028, required minimum payments of $9.7 million, $28.4 million, $25.1 million, $27.3 million and $35.8 million for October 1 - December 31, 2004, and the years 2005 through 2008, respectively, and $97.8 million for the total of the years thereafter.

CE Casecnan Construction Contract Arbitration

Construction of the Casecnan Project was completed under a fixed-price, date-certain, turnkey engineering, procurement and construction contract by a consortium consisting of Cooperativa Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa. (collectively, the “Contractor”), working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd. On February 12, 2001, the Contractor filed a Request for Arbitration with the ICC seeking schedule relief from various alleged force majeure events. On April 7, 2004, CE Casecnan entered into an agreement with the Contractor settling the ICC arbitration. Pursuant to the settlement agreement, the Contractor paid $19.1 million to CE Casecnan on April 14, 2004, and the Contractor and CE Case cnan executed mutual releases and agreed to dismiss the arbitration. A total of $23.9 million (the $19.1 million receipt, less $0.2 million placed in escrow, along with the $3.8 million amount originally recorded for liquidated damages and the $1.2 million accrual for the unpaid portion of the contract) was recorded as a reduction of properties, plants and equipment in the second quarter of 2004, reflecting the receipt of the Contractor payment and the release of other costs accrued in connection with the arbitration proceedings.

New Accounting Pronouncements

In December 2003, the FASB issued FIN 46R which served to clarify guidance in FASB Interpretation No. 46 "Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51" (‘‘FIN 46’’), and provided additional guidance surrounding the application of FIN 46. The Company adopted and applied the provisions of FIN 46R, related to certain finance subsidiaries, as of October 1, 2003. The adoption required the deconsolidation of certain finance subsidiaries, which resulted in the amounts previously classified as mandatorily redeemable preferred securities of subsidiary trusts, in the amount of $1.9 billion, being reclassified to parent company subordinated debt in the accompanying consolidated balance sheets. In addition, the associated amounts previously re corded in minority interest and preferred dividends are now recorded as interest expense in the accompanying consolidated statements of operations. For the three-month and nine-month periods ended September 30, 2004, the Company has recorded $49.2 million and $149.5 million, respectively, of interest expense related to these securities. In accordance with the requirements of FIN 46R, no amounts prior to adoption on October 1, 2003 have been reclassified. The amounts included in minority interest and preferred dividends related to these securities for the three-month and nine-month periods ended September 30, 2003, were $54.1 million and $170.2 million, respectively. The Company adopted the provisions of FIN 46R related to non-special purpose entities in the first quarter of 2004. The Company has considered the provisions of FIN 46R for all subsidiaries and their related power purchase, power sale, or tolling agreements. Factors considered in the analysis include the duration of the agreements, how capacity and energy payments are determined, source and payment terms for fuel, as well as responsibility and payment for operating and maintenance expenses. As a result of these considerations, the Company has determined its power purchase, power sale and tolling agreements do not represent significant variable interests. Accordingly, the Company has concluded that it is appropriate to continue to consolidate the power plant projects with ownership interests greater than 50% and not to consolidate the power plants from which it purchases power.

In May 2004, the FASB issued FASB Staff Position No. 106-2 ("FSP 106-2"), "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" (the "Act"). The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of postretirement health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. When adopted, FSP 106-2 will supersede FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," which was issued in January 2004 and permitted a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Act until more authoritative guidance on the accounting for the federal subsidy was issued, which the Company so elected. FSP 106-2 provides authoritative guidance on the accounting for the federal subsidy and specifies the disclosure requirements for employers who have adopted FSP 106-2, including those who are unable to determine whether benefits provided under its plan are actuarially equivalent to Medicare Part D. The Company has determined that the effects of the Act are not significant to is postretirement plan and therefore do not constitute a significant event, as that term is defined in Statement of Financial Accounting Standard No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”. As such, the Company will adopt FSP 106-2 at its next measurement date, January 1, 2005.

Critical Accounting Policies

The preparation of financial statements and related documents in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, assumptions and estimates that affect the amounts reported in the consolidated financial statements and accompanying notes. Note 2 to the Company’s consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 describes the significant accounting policies and methods used in the preparation of the consolidated financial statements. Estimates are used for, but not limited to, the effects of certain types of regulation, impairment of long-lived assets, contingent liabilities and the accounting for revenue. Actual results could differ from these esti mates.

For additional discussion of the Company’s critical accounting policies, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003. The Company’s critical accounting policies have not changed materially since December 31, 2003.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

For quantitative and qualitative disclosures about market risk affecting MEHC, see Item 7A “Qualitative and Quantitative Disclosures About Market Risk” of MEHC’s Annual Report on Form 10-K for the year ended December 31, 2003. MEHC’s exposure to market risk has not changed materially since December 31, 2003.

Item 4. Controls and Procedures.

An evaluation was performed under the supervision and with the participation of the Company’s management, including the chief executive officer and chief financial officer, regarding the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, as amended) as of September 30, 2004. Based on that evaluation, the Company’s management, including the chief executive officer and chief financial officer, concluded that the Company’s disclosure controls and procedures were effective. There have been no significant changes during the quarter covered by this report in the Company’s internal controls or in other factors that could significantly affect internal controls.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

For a description of certain legal proceedings affecting the Company, please review Note 8 to the Interim Financial Statements, “Commitments and Contingencies”.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Not applicable.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Submission of Matters to a Vote of Security Holders.

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

The exhibits listed on the accompanying Exhibit Index are filed as part of this Quarterly Report.

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)



	/s/ Patrick J. Goodman
Date: November 4, 2004	Patrick J. Goodman Senior Vice President and Chief Financial Officer

EXHIBIT INDEX

Exhibit No.

31.1	Chief Executive Officer’s Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Chief Financial Officer’s Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Chief Executive Officer’s Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	Chief Financial Officer’s Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Iowa		94-2213782
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)



666 Grand Avenue, Des Moines, Iowa		50309
(Address of principal executive offices)		(Zip Code)

(515) 242-4300
(Registrant’s telephone number, including area code)


Securities registered pursuant to Section 12(b) of the Act: N/A
Securities registered pursuant to Section 12(g) of the Act: N/A

	As of
	September 30,			December 31,
	2004			2003
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	975,762		$	660,213
Restricted cash and short-term investments		124,634			55,281
Accounts receivable, net		553,273			666,063
Inventories		135,426			123,301
Other current assets		264,829			371,855
Total current assets		2,053,924			1,876,713
Properties, plants and equipment, net		11,087,205			11,180,979
Goodwill		4,267,914			4,305,643
Regulatory assets		482,925			512,549
Other investments		235,481			228,896
Equity investments		243,176			234,370
Deferred charges and other assets		857,262			829,039
Total assets	$	19,227,887		$	19,168,189

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	321,340		$	345,237
Accrued interest		217,851			189,635
Accrued property and other taxes		141,623			112,823
Other liabilities		542,054			443,531
Short-term debt		7,691			48,036
Current portion of long-term debt		1,054,322			500,941
Current portion of parent company subordinated debt		121,533			100,000
Total current liabilities		2,406,414			1,740,203
Other long-term accrued liabilities		2,020,163			1,827,633
Parent company senior debt		2,770,842			2,777,878
Parent company subordinated debt		1,652,271			1,772,146
Subsidiary and project debt		6,115,117			6,674,640
Deferred income taxes		1,344,726			1,433,144
Total liabilities		16,309,533			16,225,644

Deferred income		67,845			69,201
Minority interest		12,893			9,754
Preferred securities of subsidiaries		89,834			92,145

Commitments and contingencies (Note 8)

Stockholders' equity:
Zero-coupon convertible preferred stock - authorized 50,000 shares, no par value, 41,263 shares issued and outstanding		-			-
Common stock - authorized 60,000 shares, no par value, 9,081 and 9,281 shares issued and outstanding at September 30, 2004, and December 31, 2003, respectively		-			-
Additional paid-in capital		1,951,094			1,957,277
Retained earnings		970,657			999,627
Accumulated other comprehensive loss, net		(173,969	)		(185,459	)
Total stockholders' equity		2,747,782			2,771,445
Total liabilities and stockholders' equity	$	19,227,887		$	19,168,189

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2004			2003			2004			2003
				(Unaudited)

Revenues:
Operating revenue	$	1,534,057		$	1,474,453		$	4,858,826		$	4,400,778
Income on equity investments		18,792			19,385			28,083			40,386
Interest and dividend income		11,066			6,746			25,528			39,930
Other income		13,217			6,378			44,514			53,302
Total revenue		1,577,132			1,506,962			4,956,951			4,534,396

Costs and expenses:
Cost of sales		591,370			558,869			2,020,132			1,761,686
Operating expense		409,048			399,118			1,216,493			1,123,249
Depreciation and amortization		165,058			133,835			496,354			433,859
Interest expense		225,021			174,238			677,825			538,685
Less interest capitalized		(7,139	)		(2,921	)		(16,041	)		(26,080	)
Total costs and expenses		1,383,358			1,263,139			4,394,763			3,831,399
Income from continuing operations before provision for income taxes		193,774			243,823			562,188			702,997
Provision for income taxes		63,840			70,074			202,127			184,195
Income from continuing operations before minority interest and preferred dividends		129,934			173,749			360,061			518,802
Minority interest and preferred dividends		3,837			57,962			9,865			179,868
Income from continuing operations		126,097			115,787			350,196			338,934
Loss from discontinued operations, net of tax benefits (Note 3)		(346,723	)		(6,057	)		(366,176	)		(18,627	)
Net income (loss) available to common and preferred stockholders	$	(220,626	)	$	109,730		$	(15,980	)	$	320,307

	Nine Months
	Ended September 30,
	2004			2003
	(Unaudited)
Cash flows from operating activities:
Income from continuing operations	$	350,196		$	338,934
Adjustments to reconcile income from continuing operations to cash flows from continuing operations:
Distributions less income on equity investments		(13,011	)		9,214
Gain on other items		(3,886	)		(12,981	)
Depreciation and amortization		496,354			433,859
Amortization of regulatory assets and liabilities and other		(7,188	)		(8,781	)
Amortization of deferred financing costs		15,589			22,646
Provision for deferred income taxes		151,751			184,383
Other		30,798			32,967
Changes in other items:
Accounts receivable and other current assets		101,675			126,222
Accounts payable and other accrued liabilities		129,328			(82,499	)
Deferred income		(862	)		(7,775	)
Net cash flows from continuing operations		1,250,744			1,036,189
Net cash flows from discontinued operations		(28,991	)		(22,916	)
Net cash flows from operating activities		1,221,753			1,013,273
Cash flows from investing activities:
Acquisitions, net of cash acquired		(37,283	)		(50,893	)
Proceeds from note receivable		97,000			-
Proceeds from (purchase of) affiliate notes		12,041			(35,029	)
Capital expenditures relating to operating projects		(524,836	)		(440,841	)
Construction and other development costs		(271,602	)		(435,413	)
Liquidated damages received, net of amounts accrued		18,900			-
Sale of convertible preferred securities		-			288,750
Other		65,924			(38,173	)
Net cash flows from continuing operations		(639,856	)		(711,599	)
Net cash flows from discontinued operations		966			(10,269	)
Net cash flows from investing activities		(638,890	)		(721,868	)
Cash flows from financing activities:
Proceeds from subsidiary and project debt		21,002			1,148,719
Proceeds from parent company senior debt		249,765			449,295
Repayments of subsidiary and project debt		(185,666	)		(1,389,872	)
Repayments of parent company debt and preferred securities of subsidiary trusts		(100,000	)		(413,255	)
Net repayment of subsidiary short-term debt		(45,347	)		(79,750	)
Purchase and retirement of common stock		(20,000	)		-
Increase in restricted cash and investments		(43,849	)		(35,974	)
Redemption of preferred securities of subsidiaries		(2,312	)		(882	)
Other		(5,817	)		(72,537	)
Net cash flows from continuing operations		(132,224	)		(394,256	)
Net cash flows from discontinued operations		(136,505	)		(703	)
Net cash flows from financing activities		(268,729	)		(394,959	)
Effect of exchange rate changes		1,415			13,540
Net change in cash and cash equivalents		315,549			(90,014	)
Cash and cash equivalents at beginning of period		660,213			844,430
Cash and cash equivalents at end of period	$	975,762		$	754,416
Supplemental Disclosure:
Interest paid, net of interest capitalized	$	627,751		$	489,051
Income taxes (refunded) paid	$	(32,877	)	$	7,376

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003

Total revenue	$	564		$	184		$	2,509		$	384

Losses from discontinued operations	$	(9,840	)	$	(10,222	)	$	(42,695	)	$	(31,443	)
Costs of disposal activities		(1,019	)		-			(1,019	)		-
Asset impairment charges, including goodwill		(532,009	)		-			(532,009	)		-
Income tax benefits		196,145			4,165			209,547			12,816
Loss from discontinued operations, net of tax	$	(346,723	)	$	(6,057	)	$	(366,176	)	$	(18,627	)

Item 1.	Financial Statements	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 4.	Controls and Procedures	35

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings	36
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36
Item 3.	Defaults Upon Senior Securities	36
Item 4.	Submission of Matters to a Vote of Security Holders	36
Item 5.	Other Information	36
Item 6.	Exhibits	36
Signatures		37
Exhibit Index		38

Postretirement:
Service cost	$	1,992		$	1,880		$	6,057		$	5,775
Interest cost		3,992			3,694			12,139			11,348
Expected return on plan assets		(2,143	)		(1,382	)		(6,517	)		(4,244	)
Amortization of net transition balance		834			945			2,536			2,904
Amortization of prior service cost		75			136			229			418
Amortization of prior year loss		838			855			2,547			2,625
Net periodic cost	$	5,588		$	6,128		$	16,991		$	18,826

						Northern			CE		CalEnergy
	MidAmerican			Kern		Natural			Electric		Generation			Home-
	Energy			River		Gas			UK		Domestic			Services			Total
Goodwill at January 1, 2004	$	2,139,223		$	33,900	$	379,148		$	1,261,583	$	126,308		$	365,481		$	4,305,643

Goodwill from acquisitions during the year		-			-		-			-		-			31,656			31,656

Impairment losses⁽¹⁾		-			-		-			-		(52,776	)		-			(52,776	)

Other goodwill adjustments⁽²⁾		(8,978	)		-		(17,754	)		12,879		(405	)		(2,351	)		(16,609	)

Goodwill at September 30, 2004	$	2,130,245		$	33,900	$	361,394		$	1,274,462	$	73,127		$	394,786		$	4,267,914

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2004			2003			2004			2003
Operating revenue:
MidAmerican Energy	$	566,447		$	577,281		$	1,982,915		$	1,929,637
Kern River		82,139			78,793			236,126			182,267
Northern Natural Gas		85,999			78,281			383,443			336,395
CE Electric UK		216,109			188,143			694,926			602,334
CalEnergy Generation-Domestic		9,414			12,098			31,132			34,118
CalEnergy Generation-Foreign		85,078			89,245			224,007			246,137
HomeServices		496,088			459,007			1,343,580			1,112,627
Segment operating revenue		1,541,274			1,482,848			4,896,129			4,443,515
Corporate/other⁽¹⁾		(7,217	)		(8,395	)		(37,303	)		(42,737	)
Total operating revenue	$	1,534,057		$	1,474,453		$	4,858,826		$	4,400,778

Interest expense:
MidAmerican Energy	$	30,384		$	31,178		$	92,488		$	94,383
Kern River		19,074			19,959			57,830			59,569
Northern Natural Gas		13,306			13,049			39,676			43,297
CE Electric UK		50,776			37,362			149,198			134,036
CalEnergy Generation-Domestic		4,725			4,911			14,339			14,914
CalEnergy Generation-Foreign		10,703			15,067			33,318			46,432
HomeServices		822			1,048			2,456			3,340
Segment interest expense		129,790			122,574			389,305			395,971
Corporate/other⁽¹⁾		46,026			51,664			139,027			142,714
Parent company subordinated debt⁽²⁾		49,205			-			149,493			-
Total interest expense	$	225,021		$	174,238		$	677,825		$	538,685

Income (loss) from continuing operations before provision for income taxes:
MidAmerican Energy	$	95,429		$	104,151		$	219,039		$	240,243
Kern River		35,182			36,234			111,439			98,367
Northern Natural Gas		201			(4,517	)		86,396			69,308
CE Electric UK		63,757			59,134			231,132			203,820
CalEnergy Generation-Domestic		15,103			15,334			17,964			29,938
CalEnergy Generation-Foreign		49,565			37,738			117,396			107,813
HomeServices		44,666			44,409			106,298			90,896
Segment income from continuing operations before provision for income taxes		303,903			292,483			889,664			840,385
Corporate/other^{(1) (2)}		(110,129	)		(48,660	)		(327,476	)		(137,388	)
Total income from continuing operations before provision for income taxes	$	193,774		$	243,823		$	562,188		$	702,997

	Three Months
	Ended September 30,
	2004			2003			$ Change
Operating revenue:
MidAmerican Energy	$	566.5		$	577.3		$	(10.8	)
Kern River		82.1			78.8			3.3
Northern Natural Gas		86.0			78.3			7.7
CE Electric UK		216.1			188.1			28.0
CalEnergy Generation-Domestic		9.4			12.1			(2.7	)
CalEnergy Generation-Foreign		85.1			89.3			(4.2	)
HomeServices		496.1			459.0			37.1
Segment operating revenue		1,541.3			1,482.9			58.4
Corporate/other		(7.2	)		(8.4	)		1.2
Total operating revenue	$	1,534.1		$	1,474.5		$	59.6

	Nine Months
	Ended September 30,
	2004			2003			$ Change
Operating revenue:
MidAmerican Energy	$	1,982.9		$	1,929.6		$	53.3
Kern River		236.1			182.3			53.8
Northern Natural Gas		383.5			336.4			47.1
CE Electric UK		694.9			602.4			92.5
CalEnergy Generation-Domestic		31.1			34.1			(3.0	)
CalEnergy Generation-Foreign		224.0			246.1			(22.1	)
HomeServices		1,343.6			1,112.6			231.0
Segment operating revenue		4,896.1			4,443.5			452.6
Corporate/other		(37.3	)		(42.7	)		5.4
Total operating revenue	$	4,858.8		$	4,400.8		$	458.0