Item 3.    Legal Proceedings.

In addition to the proceedings described below, the Company is currently party to various items of litigation or arbitration, none of which are reasonably expected by the Company to have a material adverse effect on its financial position, results of operations or cash flows.

Pipeline Litigation

In 1998, the United States Department of Justice informed the then current owners of Kern River and Northern Natural Gas that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against such entities and certain of their subsidiaries including Kern River and Northern Natural Gas. Mr. Grynberg has also filed claims against numerous other energy companies and alleges that the defendants violated the False Claims Act in connection with the measurement and purchase of hydrocarbons. The relief sought is an unspecified amount of royalties allegedly not paid to the federal government, treble damages, civil penalties, attorneys' fees and costs. On April 9, 1999, the United States Department of Justice announced that it declined to intervene in any of the Grynberg qui tam cases, including the actions filed against Kern River and Northern Natural Gas in the United States District Court for the District of Colorado. On October 21, 1999, the Panel on Multi-District Litigation transferred the Grynberg qui tam cases, including the ones filed against Kern River and Northern Natural Gas, to the United States District Court for the District of Wyoming for pre-trial purposes. Motions to dismiss the complaint, filed by various defendants including Northern Natural Gas and The Williams Companies, Inc. ("Williams"), which was the former owner of Kern River, were denied on May 18, 2001. On October 9, 2002, the United States District Court for the District of Wyoming dismissed Grynberg's royalty valuation claims. On November 19, 2002, the United States District Court for the District of Wyoming denied Grynberg's motion for clarification and dismissed his royalty valuation claims. Grynberg appealed this dismissal to the United States Court of Appeals for the Tenth Circuit and on May 13, 2003, the Tenth Circuit Court dismissed his appeal. In connection with the purchase of Kern River from Williams in March 2002, Williams agreed to indemnify MEHC against any liability for this claim; however, no assurance can be given as to the ability of Williams to perform on this indemnity should it become necessary. No such indemnification was obtained in connection with the purchase of Northern Natural Gas in August 2002. The Company believes that the Grynberg cases filed against Kern River and Northern Natural Gas are without merit and that Williams, on behalf of Kern River pursuant to its indemnification, and Northern Natural Gas, intend to defend these actions vigorously.

On June 8, 2001, a number of interstate pipeline companies, including Kern River and Northern Natural Gas, were named as defendants in a nationwide class action lawsuit which had been pending in the 26th Judicial District, District Court, Stevens County Kansas, Civil Department against other defendants, generally pipeline and gathering companies, since May 20, 1999. The plaintiffs allege that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs. In November 2001, Kern River and Northern Natural Gas, along with the coordinating defendants, filed a motion to dismiss under Rules 9B and 12B of the Kansas Rules of Civil Procedure. The court denied this motion. In January 2002, Kern River and most of the coordinating defendants filed a motion to dismiss for lack of personal jurisdiction. The court has yet to rule on these motions. The plaintiffs filed for certification of the plaintiff class on September 16, 2002. On January 13, 2003, oral arguments were heard on coordinating defendants' opposition to class certification. On April 10, 2003, the court entered an order denying the plaintiffs' motion for class certification. On May 12, 2003, the plaintiffs filed a motion for leave to file a fourth amended petition alleging a class of gas royalty owners in Kansas, Colorado and Wyoming. The court granted the motion for leave to amend on July 28, 2003. Kern River was not a named defendant in the amended complaint and has been dismissed from the action. Northern Natural Gas filed an answer on the fourth amended petition on August 22, 2003. Williams has agreed to indemnify MEHC against any liability associated with Kern River for this claim; however, no assurance can be given as to the ability of Williams to perform on this indemnity should it become necessary. Northern Natural Gas anticipates joining with the other defendants in contesting certification of the plaintiff class. Kern River and Northern Natural Gas believe that this claim is without merit and that Kern River's and Northern Natural Gas' gas measurement techniques have been in accordance with industry standards and its tariff.

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Similar to the June 8, 2001 matter referenced above, the plaintiffs in that matter have filed a new companion action against a number of parties, including Northern Natural Gas but excluding Kern River, in a Kansas state district court for damages for mismeasurement of British thermal unit content, resulting in lower royalties. The action was filed on May 12, 2003, shortly after the state district court dismissed the plaintiffs' third amended petition in the original litigation which sought to certify a nationwide class. The new companion action which seeks to certify a class of royalty owners in Kansas, Colorado and Wyoming, tracking the fourth amended petition in the action referenced above, was not served until August 4, 2003. A motion to dismiss was filed on August 25, 2003. On October 9, 2003, the state district court denied the motion to dismiss; Northern Natural Gas filed its answer on November 6, 2003. Northern Natural Gas believes that this claim is without merit and that Northern Natural Gas' gas measurement techniques have been in accordance with industry standards and its tariff.

Natural Gas Commodity Litigation

MidAmerican Energy is one of dozens of companies named as defendants in a January 20, 2004 consolidated class action lawsuit filed in the U.S. District Court for the Southern District of New York. The suit alleges that the defendants have engaged in unlawful manipulation of the prices of natural gas futures and options contracts traded on the New York Mercantile Exchange ("NYMEX") during the period January 1, 2000 to December 31, 2002. MidAmerican Energy is mentioned as a company that has engaged in wash trades on Enron Online (an electronic trading platform) that had the effect of distorting prices for gas trades on the NYMEX. The plaintiffs to the class action do not specify the amount of alleged damages. At this time, MidAmerican Energy does not believe that it has any material exposure in this lawsuit.

The original complaint in this matter, Cornerstone Propane Partners, L.P. v. Reliant, et al. ("Cornerstone"), was filed on August 18, 2003 in the United States District Court, Southern District of New York naming MidAmerican Energy and the Company. On October 1, 2003, a second complaint, Roberto, E. Calle Gracey, et al. ("Calle Gracey"), was filed in the same court but did not name MidAmerican Energy or the Company. On November 14, 2003, a third complaint, Dominick Viola ("Viola"), et al., was filed in the same court and named MidAmerican Energy and MEHC as defendants. On November 19, 2003, an Order of Voluntary Dismissal Without Prejudice of MEHC was entered by the court dismissing MEHC from the Cornerstone and Viola complaints. On December 5, 2003, the court entered Pretrial Order No. 1, which among other procedural matters, ordered the consolidation of the Cornerstone, Calle Gracey and Viola complaints and permitted plaintiffs to file an amended complaint in this matter. On January 20, 2004, plaintiffs filed In Re: Natural Gas Commodity Litigation as the amended complaint reasserting their previous allegations. Unless extended by agreement of the parties or by court order, MidAmerican Energy's answer and/or responsive pleading in this matter is due February 19, 2004. MidAmerican Energy will coordinate with the other defendants and vigorously defend the allegations against it.

Philippines

CE Casecnan NIA Arbitration

The CE Casecnan NIA arbitration was settled on October 15, 2003. See "Item 1. Business — CalEnergy Generation – Foreign" for additional information.

CE Casecnan Construction Contract Arbitration

The Casecnan project was constructed pursuant to a fixed-price, date-certain, turnkey 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.

In 2001, the Contractor filed a Request for Arbitration (and two supplements) with the International Chamber of Commerce ("ICC") seeking schedule relief of up to 153 days, compensation for alleged

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additional costs of approximately $4 million (to the extent it is unable to recover from its insurer) and compensation for damages of approximately $62 million resulting from alleged force majeure events (and geologic conditions). The Contractor further alleged that the circumstances surrounding the placing of the Casecnan project into commercial operation in December 2001 amounted to a repudiation of the Replacement Contract resulting in a claim for unspecified quantum meruit damages, and that the delay liquidated damages clause which provides for payments of $125,000 per day to CE Casecnan for each day of delay in completion of the Casecnan project is unenforceable.

On November 7, 2002, the ICC issued the arbitration tribunal's partial award with respect to the Contractor's force majeure claims. The arbitration panel awarded the Contractor 18 days of schedule relief in the aggregate for all of the force majeure events and awarded the Contractor $3.8 million to the extent losses are not covered by insurance. All of the Contractor's other claims with respect to force majeure and geologic conditions were denied. If the Contractor were to prevail on the Contractor's claim that the delay liquidated damages clause is unenforceable, CE Casecnan would not be entitled to collect such delay damages for the period from March 31, 2001 through December 11, 2001. If the Contractor were to prevail in the Contractor's repudiation claim and prove quantum meruit damages in excess of amounts paid to the Contractor, CE Casecnan could be liable to make additional payments to the Contractor. CE Casecnan believes all of such allegations and claims are without merit and is vigorously contesting the Contractor's claims. CE Casecnan believes that an award will be issued by the ICC in 2004.

CE Casecnan Stockholder Litigation

Pursuant to the share ownership adjustment mechanism in the CE Casecnan stockholder agreement, which is based upon pro forma financial projections of the Casecnan project prepared following commencement of commercial operations, in February 2002, MEHC's indirect wholly owned subsidiary, CE Casecnan Ltd., advised the minority stockholder, LaPrairie Group Contractors (International) Ltd. ("LPG"), that MEHC's ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. In April 2002, CE Casecnan Ltd. and LPG entered into a status quo agreement pursuant to which CE Casecnan Ltd. agreed not to take any action to exercise control over or transfer LPG's shares in CE Casecnan. On July 8, 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco against, among others, CE Casecnan Ltd. and MEHC. In the complaint, LPG seeks compensatory and punitive damages for alleged breaches of the stockholder agreement and alleged breaches of fiduciary duties allegedly owed by CE Casecnan Ltd. and MEHC to LPG. The complaint also seeks injunctive relief against all defendants and a declaratory judgment that LPG is entitled to maintain a 15% interest in CE Casecnan. On January 21, 2004, CE Casecnan Ltd. and LPG entered into a second status quo agreement pursuant to which the parties agreed to set aside certain distributions related to the shares subject to the LPG dispute and not distribute such funds without at least 15 days prior notice to LPG. Accordingly, 15% of the dividend distribution declared on January 21, 2004 was set aside by CE Casecnan in an unsecured CE Casecnan account. The impact, if any, of this litigation on the Company cannot be determined at this time.

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

Not applicable.

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PART II

Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Since March 14, 2000, MEHC's equity securities have been owned by Berkshire Hathaway, Walter Scott, Jr. (together with certain of his family members and family trusts and corporations), David L. Sokol and Gregory E. Abel and have not been registered with the SEC pursuant to the Securities Act of 1933, as amended, listed on a stock exchange or otherwise publicly held or traded.

Item 6.    Selected Financial Data.

The following table sets forth selected consolidated financial data, which should be read in conjunction with the Company's financial statements and the related notes to those statements included in this annual report and with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" appearing elsewhere in this annual report. The selected consolidated financial data, as of and for the years ended December 31, 2003, 2002 and 2001, as of December 31, 2000 and for the periods from March 14, 2000 through December 31, 2000, have been derived from the Company's historical consolidated financial statements. The selected consolidated financial data, from January 1, 2000 through March 13, 2000 and as of and for the year ended December 31, 1999, have been derived from MEHC Predecessor's historical consolidated financial statements.

SELECTED CONSOLIDATED FINANCIAL DATA
(Amounts in millions)

				Year Ended December 31,												March 14, 2000 through December 31, 2000(3)				MEHC (Predecessor)
																				January 1, 2000 through March 13, 2000(4)				Year Ended December 31, 1999(5)
				2003				2002(1)				2001(2)
Statement of Operations Data:
Total revenue				$	6,144.7			$	4,968.1			$	4,973.0			$	4,013.0			$	1,075.8			$	4,368.5
Total costs and expenses					5,294.9				4,325.0				4,469.1				3,793.8				984.7				4,011.5
Income before change in accounting principle					415.6				380.0				147.3				81.3				51.3				167.2
Cumulative effect of change in accounting principle, net of tax					—				—				(4.6	)			—				—				—
Net income				$	415.6			$	380.0			$	142.7			$	81.3			$	51.3			$	167.2
Balance Sheet Data:
Total assets				$	19,168.2			$	18,049.2			$	12,626.7			$	11,610.9				N/A			$	10,766.4
Parent company senior debt(6)					2,777.9				2,323.4				1,834.5				1,830.0				N/A				1,856.3
Parent company subordinated debt(6)					1,772.1				—				—				—				—				—
Company-obligated mandatory redeemable preferred securities of subsidiary trusts					—				2,063.4				788.2				786.5				N/A				450.0
Subsidiary and project debt(6)					6,674.6				7,077.1				4,754.8				3,398.7				N/A				3,642.7
Subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts					—				—				100.0				100.0				N/A				101.6
Preferred securities of subsidiaries					92.1				93.3				121.2				145.7				N/A				146.6
Total stockholders' equity					2,771.4				2,294.3				1,708.2				1,576.4				N/A				994.6

(1)	Reflects the acquisitions of Kern River on March 27, 2002 and Northern Natural Gas on August 16, 2002.

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(2)

Reflects the Yorkshire Swap on September 21, 2001 and includes $15.2 million of after tax income related to the sale of the Northern Electric electricity and gas supply business, the sale of the Telephone Flat Project, the sale of Western States Geothermal, the transfer of Bali Energy Ltd. shares, and the Teesside Power Limited ("TPL") asset valuation impairment charge.

(3)	Reflects the Teton Transaction on March 14, 2000.

(4)	Includes $7.6 million of expenses related to the Teton Transaction.

(5)

Reflects MEHC's acquisition of MidAmerican Energy on March 12, 1999, MEHC's disposition of the Coso Joint Ventures on February 26, 1999, and MEHC's disposition of a 50% ownership interest in CE Generation on March 3, 1999 and includes $81.5 million of after tax income related to the settlement of political risk insurance proceeds related to MEHC's investment in Indonesia, gains on sales of shares of McLeodUSA, CE Electric UK restructuring charges and transaction costs related to MEHC's acquisition by a private investor group.

(6)	Excludes current portion.

Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis should be read in combination with the selected consolidated financial data and the consolidated financial statements included in Items 6 and 8 herein.

General

MEHC is a United States-based privately owned global energy company with publicly held fixed income securities that generates, distributes and supplies energy to utilities, government entities, retail customers and other customers located throughout the world. Through its subsidiaries, its operations are organized and managed on seven distinct platforms: MidAmerican Energy, Kern River, Northern Natural Gas, CE Electric UK (which includes Northern Electric and Yorkshire), CalEnergy Generation-Domestic, CalEnergy Generation-Foreign and HomeServices.

Through these platforms, the Company owns and operates a combined electric and natural gas utility company in the United States, two natural gas pipeline companies in the United States, two electricity distribution companies in the United Kingdom, a diversified portfolio of domestic and international independent power projects and the second largest residential real estate brokerage firm in the United States.

The Company's principal energy subsidiaries generate, transmit, store, distribute and supply energy. The Company's electric and natural gas utility subsidiaries currently serve approximately 4.4 million electricity customers and approximately 670,000 natural gas customers. Its natural gas pipeline subsidiaries operate interstate natural gas transmission systems with approximately 18,200 miles of pipeline in operation and peak delivery capacity of 6.2 Bcf of natural gas per day. The Company has interests in 6,716 net owned MW of power generation facilities in operation and construction, including 5,142 net owned MW in facilities that are part of the regulated return asset base of its electric utility business and 1,574 net owned MW in non-utility power generation facilities. Substantially all of the non-utility power generation facilities have long-term contracts for the sale of energy and/or capacity from the facilities.

During the past several years, the Company completed a number of significant transactions, including the following:

•	Northern Natural Gas was acquired in August 2002 for $882.7 million, net of cash acquired. Northern Natural Gas owns a 16,500 mile interstate natural gas pipeline extending from southwest Texas to the upper Midwest region of the United States with a design capacity of 4.4 Bcf of natural gas per day.

•	Kern River was acquired in March 2002 for $419.7 million, net of cash acquired. At the date of acquisition, Kern River owned 926 miles of interstate natural gas pipeline extending from Wyoming to markets in California, Nevada and Utah and with access to natural gas supplies from large producing regions in the Rocky Mountains and Canada.

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•	In May 2003, Kern River completed a 717 mile expansion of its pipeline system, which increased the design capacity of the system by 885,626 Dth per day to 1,755,626 Dth per day.

•	HomeServices, MEHC's full-service independent residential real estate brokerage company, separately acquired seven real estate companies during 2003 and 2002.

•	CE Casecnan commenced operations on December 11, 2001.

•	On September 2001, CE Electric UK acquired 94.75% of Yorkshire from Innogy Holdings plc and simultaneously sold Northern Electric's electricity and gas supply and metering businesses to Innogy Holdings plc. In August 2002, CE Electric UK acquired the remaining 5.25% of Yorkshire from Xcel.

As a result of these events, the Company's future results may differ from historical results.

Results of Operations for the Year Ended December 31, 2003 and the Year Ended December 31, 2002

In 2003, net income available to common and preferred stockholders was $415.6 million compared with $380.0 million in 2002.

The increase was mainly due to: improved earnings at MidAmerican Energy, higher income at Kern River primarily due to the transportation fees earned in connection with the 2003 Expansion Project and, to a lesser degree, the inclusion of its operations for all of 2003, the acquisition of Northern Natural Gas in August 2002 and the inclusion of its operations for all of 2003, higher income at CE Electric UK due to lower costs and a weaker U.S. dollar and continued improvement at HomeServices due to acquisitions made throughout 2002 and 2003 and growth at existing companies which benefit from the low interest rate environment, a related increase in the mortgage refinance business and strong housing market. Offsetting those benefits were gains recorded, in 2002, of $41.3 million, after tax, from the sale of CE Gas assets and the tax benefits of $35.7 million in connection with the execution of the TPL restructuring agreement.

Operating revenue for the year ended December 31, 2003 increased $1,154.2 million or 24.1% to $5,948.2 million from $4,794.0 million for the same period in 2002. The following table summarizes operating revenue by segment for the years ended December 31 (in millions):

				Year Ended December 31,
				2003				2002				$ Change
Operating revenue:
MidAmerican Energy				$	2,600.2			$	2,240.9			$	359.3
Kern River					260.2				127.3				132.9
Northern Natural Gas					482.2				176.9				305.3
CE Electric UK					830.0				795.4				34.6
CalEnergy Generation – Domestic					45.8				38.5				7.3
CalEnergy Generation – Foreign					326.4				326.3				0.1
HomeServices					1,476.6				1,138.3				338.3
Segment operating revenue					6,021.4				4,843.6				1,177.8
Corporate/other					(73.2	)			(49.6	)			(23.6	)
Total operating revenue				$	5,948.2			$	4,794.0			$	1,154.2

MidAmerican Energy's regulated and non-regulated gas revenue for the year ended December 31, 2003 increased $308.4 million to $1,112.7 million from $804.3 million in 2002 mainly due to higher prices for gas purchased for regulated customers which is passed directly to the customer. Average gas prices increased 59.9% or $2.24 per MMBtu from 2002 to 2003. Regulated electric revenue for the year ended December 31, 2003 increased $44.6 million to $1,398.0 million from $1,353.4 million for the same period in 2002 mainly due to higher prices of off-system sales during 2003.

Operating revenue at both pipelines is principally derived by providing firm or interruptible transportation services under long-term gas transportation service agreements. Northern Natural Gas also

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derives part of its revenue from storing gas. The increase in Kern River's operating revenue was primarily due to the transportation fees earned in connection with the 2003 Expansion Project which began operations May 1, 2003, and to a lesser degree, the inclusion of its operations for all of 2003. Northern Natural Gas was acquired on August 16, 2002. The increase in its operating revenue relates to the timing of that acquisition and inclusion of its operations for all of 2003.

CE Electric UK operating revenue increased during 2003 as a result of the weaker U. S. dollar, higher distribution revenue and higher revenue at its contracting business. This was partially offset by lower revenue caused by the sale of CE Gas assets in 2002.

HomeServices' operating revenue, consisting mainly of commission revenue from real estate brokerage transactions, increased $247.0 million due to acquisitions made throughout 2002 and 2003 and $91.3 million due to growth at existing companies. During 2003, HomeServices closed 185,181 brokerage sides up 22.0% from 151,808 closed sides in 2002. Closed brokerage volume was $48.6 billion in 2003, up 31.7% from $36.9 billion in 2002.

Income on equity investments for the year ended December 31, 2003 decreased $2.3 million to $38.2 million from $40.5 million for the same period in 2002. Equity income from non-regulated generation equity investments decreased $16.6 million to $14.8 million from $31.4 million in 2002 mainly due to the expiration of a contract at an independent power plant and a charge associated with an equity investment. Equity income from HomeServices for the year ended December 31, 2003 increased $14.8 million to $23.6 million from $8.8 million for the same period in 2002 primarily due to increased refinancing activity at mortgage joint ventures.

Interest and dividend income for the year ended December 31, 2003 decreased $8.4 million to $47.9 million from $56.3 million for the same period in 2002. The decrease was primarily due to lower income at CE Electric UK of $9.9 million due to lower cash balances following the redemption of the YED trust securities in June 2003 partially offset by higher dividend income on the investment in Williams' Cumulative Convertible Preferred Stock totaling $4.7 million and interest earned on higher corporate cash balances available during 2003.

Other income for the year ended December 31, 2003 increased $32.9 million to $110.3 million from $77.4 million in 2002. Other income in 2003 resulted mainly from a $31.9 million gain recognized in connection with the NIA Arbitration settlement, equity AFUDC of $26.0 million, $13.8 million gain on sale of Williams' Cumulative Convertible Preferred Stock in June 2003 and $12.7 million of income at CE Electric UK mainly from the gain on sale of a local operational and dispatch facility at NED. Other income in 2002 resulted primarily from the gain on the sale of CE Gas assets of $54.3 million and equity AFUDC of $19.8 million. These items were offset, in 2002, by losses from the write-down of non-regulated investments at MidAmerican Energy of $21.9 million.

Cost of sales for the year ended December 31, 2003 increased $572.1 million, or 31.0%, to $2,416.1 million from $1,844.0 million for the same period in 2002.

MidAmerican Energy cost of sales for the year ended December 31, 2003 increased $345.6 million, or 34.9%, to $1,334.5 million from $988.9 million for the same period in 2002. MidAmerican Energy regulated and non-regulated gas cost of sales for the year ended December 31, 2003 increased $291.1 million to $878.1 million from $587.0 million in 2002 mainly due to the increase in per unit cost of gas discussed in operating revenue. Electric cost of sales increased $51.0 million in 2003 primarily due to the reclassification of costs for energy purchased under the Cooper Nuclear Station restructured contract between MidAmerican Energy and the Nebraska Public Power District which expires in December 2004. Prior to August 1, 2002, the date of the restructuring, only fuel costs for energy purchased from Cooper Nuclear Station were classified as a cost of sales. Consistent with the restructured contract, other costs under the contract are classified as operating expenses. Following the restructuring, all costs for energy and capacity purchased under the contract were included in cost of sales consistent with the new power purchase contract. Operating expenses decreased accordingly.

HomeServices cost of sales, consisting primarily of commissions on real estate brokerage transactions, increased $235.6 million for the year ended December 31, 2003, or 30.7%, to $1,003.2 million from

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$767.6 million for the same period in 2002. Cost of sales increased $178.8 million due to acquisitions made during 2002 and 2003. The remainder of HomeServices' increase was due to growth of existing companies totaling $56.8 million.

Operating expenses for the year ended December 31, 2003 increased $182.3 million, or 13.6%, to $1,527.5 million from $1,345.2 million for the same period in 2002. An increase of $146.6 million was due to Northern Natural Gas, which was owned for the entire period in 2003. Increased operating expenses at HomeServices were $78.8 million, primarily due to the impact of acquisitions and increased compensation expenses. These increases were partially offset by lower operating expenses at CE Electric UK of $30.7 million primarily due to the sale of the retail business in 2002, lower operating expenses of $24.3 million at CalEnergy Generation – Domestic primarily due to start-up costs at the Zinc facility in 2002, partially offset by increased overhaul costs at Cordova and lower operating expenses at MidAmerican Energy of $19.5 million primarily due to the restructuring of the Cooper contract.

Depreciation and amortization for the year ended December 31, 2003 increased $84.0 million, or 16.0%, to $609.9 million from $525.9 million for the same period in 2002. An increase of $34.6 million was due to Northern Natural Gas, which was owned for the entire period in 2003. Increased depreciation at Kern River was $19.6 million mainly due to the completion of the 2003 Expansion Project and the inclusion of Kern River's operations for the entire period. Increased depreciation of $11.6 million at MidAmerican Energy due to higher utility plant depreciation and increased depreciation of $8.2 million at CE Electric UK due to a weaker U.S. dollar and an increased asset base, partially offset by the CE Gas asset sale in 2002.

Interest expense, less amounts capitalized, for the year ended December 31, 2003 increased $131.4 million to $741.3 million from $609.9 million for the same period in 2002. The increase was mainly due to interest on parent company subordinated debt which was $49.8 million for the quarter and year ended December 31, 2003. This amount represents the interest recorded on the parent company subordinated debt for the period from October 1, 2003, the date the Company adopted FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities" ("FIN 46R"), through December 31, 2003. Prior to the adoption of FIN 46R, the parent company subordinated debt was classified as company-obligated mandatorily redeemable preferred securities of subsidiary trusts. Costs associated with those instruments, prior to the adoption of FIN 46R, were classified as minority interest and preferred dividends in the accompanying consolidated statements of operations. In addition, increases resulted from additional interest expense totaling $38.9 million on MEHC's debt issuances of $700.0 million in October 2002 and $450.0 million in May 2003, increased interest expense of $32.5 million at Northern Natural Gas primarily due to a full year of ownership and increased interest expense at Kern River of $32.2 million due to additional borrowings related to the 2003 Expansion Project and a full year of ownership. The increases were partially offset by decreased interest, totaling $27.9 million, due to the combination of the June 2003 redemption of the YED securities, reductions in CalEnergy Generation – Foreign project debt, MEHC's revolving credit facility and the retirement of MEHC's 6.96% Senior Notes.

Provision for income tax for the year ended December 31, 2003 increased $151.4 million to $251.0 million from $99.6 million for the same period in 2002. The effective tax rate was 29.5% and 15.5% for the years ended December 31, 2003 and 2002, respectively. The increase in the effective tax rate was primarily due to increased tax expense on foreign income including the incremental tax expense of $24.4 million in connection with the CE Casecnan NIA Arbitration settlement proceeds. The 2002 effective tax rate was unusually low as the Company recognized tax benefits of $35.7 million in connection with the execution of the TPL restructuring agreement at CE Electric UK.

Minority interest and preferred dividends for the year ended December 31, 2003 increased $19.7 million to $183.2 million from $163.5 million for the same period in 2002. The increase in minority interest and preferred dividends is primarily due to the issuance of Company-obligated mandatorily redeemable preferred securities of subsidiary trusts relating to the Kern River and Northern Natural Gas acquisitions. This increase was partially offset by the adoption of FIN 46R described above and reduced dividends on subsidiary preferred securities resulting from lower outstanding balances.

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Results of Operations for the Year Ended December 31, 2002 and the Year Ended December 31, 2001

In 2002, net income available to common and preferred stockholders was $380.0 million compared with $142.7 million in 2001.

The increase was mainly due to: acquisitions of Kern River in March 2002 and Northern Natural Gas in August 2002, increased income at CE Electric UK, primarily as a result of the gain on the sale of CE Gas assets, increased income at CalEnergy Generation – Foreign due to a full year of operations of the CE Casecnan project, improved earnings at MidAmerican Energy's regulated electric business and continued improvement at HomeServices due to acquisitions made throughout 2002 and growth at existing companies.

Operating revenue for the year ended December 31, 2002 increased $97.2 million or 2.1% to $4,794.0 million from $4,696.8 million for the same period in 2001.

The following table summarizes operating revenue by segment for the years ended December 31 (in millions):

				Year Ended December 31,
				2002				2001				$ Change
Operating revenue:
MidAmerican Energy				$	2,240.9			$	2,388.7			$	(147.8	)
Kern River					127.3				—				127.3
Northern Natural Gas					176.9				—				176.9
CE Electric UK					795.4				1,444.0				(648.6	)
CalEnergy Generation – Domestic					38.5				37.3				1.2
CalEnergy Generation – Foreign					326.3				203.5				122.8
HomeServices					1,138.3				641.9				496.4
Segment operating revenue					4,843.6				4,715.4				128.2
Corporate/other					(49.6	)			(18.6	)			(31.0	)
Total operating revenue				$	4,794.0			$	4,696.8			$	97.2

MidAmerican Energy regulated and non-regulated gas revenue decreased due to lower prices for gas purchased which is passed directly to the customer, partially offset by an increase in regulated electric retail sales for the year ended December 31, 2002 as compared to 2001 due primarily to higher relative temperatures in 2002, which occurred primarily in the third quarter of 2002.

Kern River and Northern Natural Gas were acquired in March 2002 and August 2002, respectively. The increases relate to their inclusion in MEHC's operations in 2002.

CE Electric UK operating revenue decreased primarily due to the sale of the supply business in 2001 partially offset by the acquisition of Yorkshire Electric in September 2001 and changes in the exchange rate. CE Electric UK distributed 41,157 GWh of electricity in the year ended December 31, 2002, compared with 23,770 GWh of electricity in the same period in 2001. The increase in electricity distributed is primarily due to the acquisition of Yorkshire distribution.

CalEnergy Generation – Foreign operating revenue for the year ended December 31, 2002 increased primarily due to commencement of commercial operation of the Casecnan project in December 2001.

HomeServices operating revenue for the year ended December 31, 2002 increased primarily due to contributions from 2002 acquisitions of $431.5 million. The remainder of HomeServices' increase was due to growth of existing companies of $105.3 million partially offset by a decrease of $40.4 million from a joint venture that was consolidated in 2001 and is accounted for under the equity method in 2002.

Interest and dividend income for the year ended December 31, 2002 increased $31.7 million or 128.9% to $56.3 million from $24.6 million for the same period in 2001. The increase was primarily due to increased interest income at CE Electric UK of $15.1 million due to the increased cash balance following the Yorkshire acquisition and increased corporate interest and dividends of $13.4 million primarily due to dividends received on the investment in Williams' Cumulative Preferred Stock.

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Other income for the year ended December 31, 2002 decreased $134.7 million or 63.5% to $77.4 million from $212.1 million for the same period in 2001. Other income in 2002 resulted primarily from the non-recurring gain on the sale of CE Gas of $54.3 million and equity AFUDC of $19.8 million. These items were offset, in 2002, by losses from the write-down of non-regulated investments at MidAmerican Energy of $21.9 million. Other income in 2001 resulted from the non-recurring gains from the sales of Northern Electric's supply business, Telephone Flat and Western States Geothermal of $196.7 million, $20.7 million and $9.8 million, respectively, and a non-recurring gain from the transfer of Bali shares of $10.4 million. These items were partially offset, in 2001, by a charge related to the impairment of the Company's interest in TPL of $58.8 million.

Cost of sales for the year ended December 31, 2002 decreased $497.2 million or 21.2% to $1,844.0 million from $2,341.2 million for the same period in 2001.

MidAmerican Energy cost of sales for the year ended December 31, 2002 decreased $132.4 million or 11.8% to $988.9 million from $1,121.3 million for the same period in 2001, primarily due to decreases in regulated and non-regulated gas costs, caused by lower volumes and prices, partially offset by an increase in regulated electric costs caused by higher volumes, partially offset by the restructuring of the Cooper Nuclear Station contract.

CE Electric UK cost of sales for the year ended December 31, 2002 decreased $713.2 million or 84.6% to $129.5 million from $842.7 million for the same period in 2001. The decrease was primarily due to the sale of the supply business in 2001.

HomeServices cost of sales for the year ended December 31, 2002 increased $371.9 million or 94.0% to $767.6 million from $395.7 million for the same period in 2001. The increase was primarily due to costs at companies acquired during 2002 of $315.6 million, and higher commission expense resulting from increased sales at existing HomeServices businesses.

Operating expenses for the year ended December 31, 2002 increased $168.8 million or 14.3% to $1,345.2 million from $1,176.4 million for the same period in 2001. The increase was primarily due to higher costs at HomeServices of $99.1 million as a result of acquisitions, operating expenses due to the acquisitions of Northern Natural Gas of $95.0 million and Kern River of $27.2 million and plant operating expenses at the Zinc project and CE Casecnan of $33.9 million, partially offset by lower costs at MidAmerican Energy of $57.5 million primarily due to the restructuring of the Cooper Nuclear Station contract and lower energy efficiency expenses and lower costs at CE Electric UK of $28.5 million due to the sale of the supply business.

Depreciation and amortization for the year ended December 31, 2002 decreased $12.8 million or 2.4% to $525.9 million from $538.7 million for the same period in 2001. The decrease was primarily due to discontinuance of amortizing goodwill beginning January 1, 2002 of $96.4 million, partially offset by a full year of operations at CE Casecnan of $22.0 million, higher depreciation at MidAmerican Energy of $17.2 million primarily due to higher Iowa revenue sharing accruals and a change in the estimated useful lives of electric generation plant, depreciation expense due to the acquisitions of Kern River of $17.2 million and Northern Natural Gas of $18.2 million and increased amortization at HomeServices of $9.5 million primarily due to the amortization of the gross margin of pending sales contracts related to acquisitions.

Interest expense, less amounts capitalized, for the year ended December 31, 2002 increased $197.1 million or 47.7% to $609.9 million from $412.8 million for the same period in 2001. The increase was primarily due to the increase of interest expense at CE Electric UK of $71.3 million predominantly due to the debt acquired as part of the Yorkshire acquisition, interest expense due to debt related to the acquisitions of Kern River and Northern Natural Gas of $33.0 million and $23.0 million, respectively and the discontinuance of capitalizing interest related to the Casecnan project, the Cordova project and the Zinc Recovery project of $50.9 million, $9.4 million and $5.3 million, respectively, all partially offset by capitalized interest at Kern River of $14.0 million.

Tax expense for the year ended December 31, 2002 decreased $150.5 million or 60.2% to $99.6 million from $250.1 million for the same period in 2001. The effective tax rate was 15.5% and 49.6% for the years ended December 31, 2002 and 2001, respectively. The decrease is due primarily to the tax expense related

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to the sale of the Northern Electric supply business in September 2001, the release of the tax obligation of $35.7 million in connection with the execution of the TPL restructuring agreement at CE Electric UK in 2002, and the recognition of a tax benefit in connection with the sale of the CE Gas assets in 2002.

Minority interest and preferred dividends for the year ended December 31, 2002 increased $57.0 million or 53.5% to $163.5 million from $106.5 million for the same period in 2001. Minority interest and preferred dividends includes the dividends on Company-obligated mandatorily redeemable preferred securities of subsidiary trusts. The increase in minority interest and preferred dividends is primarily due to the issuance of Company-obligated mandatorily redeemable preferred securities of subsidiary trusts relating to the Kern River and Northern Natural Gas acquisitions.

Effective January 1, 2001, the Company changed its accounting policy regarding major maintenance and repairs for non-regulated gas projects, non-regulated plant overhaul costs and geothermal well rework costs to the direct expense method from the former policy of monthly accruals based on long-term scheduled maintenance plans for the gas projects and deferral and amortization of plant overhaul costs and geothermal well rework costs over the estimated useful lives. The cumulative effect of the change in accounting principle for 2001 was $4.6 million, net of taxes.

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 $660.2 million at December 31, 2003, compared to $844.4 million at December 31, 2002. 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, be 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 in deferred charges and other assets, restricted cash and investments of $119.5 million and $58.7 million at December 31, 2003, and December 31, 2002, respectively. The restricted cash balance for both periods is comprised primarily of amounts deposited in restricted accounts which are reserved for the service of debt obligations and customer deposits held in escrow.

Cash flows from Operating Activities

The Company generated cash flows from operations of $1,217.9 million for the year ended December 31, 2003, compared with $757.7 million for the same period in 2002. The increase was mainly due to the positive impacts of the Kern River, Northern Natural Gas and HomeServices' acquisitions as well as accelerated tax depreciation benefits.

Cash Flows from Investing Activities

Cash flows used in investing activities for 2003 were $1,003.2 million, of which $1,191.0 million was used for capital expenditures, construction and other development costs. Cash flows used in investing activities for 2002 were $2,907.8 million, of which $1,508.1 million was used for capital expenditures, construction and other development costs. Investing activities in 2002 includes $1,416.9 million for acquisitions.

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Capital Expenditures, Construction and Other Development Costs

Capital expenditures, construction and other development costs by business segment for 2003 and 2002 are as follows (in millions):

				Year Ended December 31,
				2003				2002
MidAmerican Energy				$	378.5			$	358.2
Kern River					361.5				769.5
Northern Natural Gas					104.4				62.4
CE Electric UK					301.9				222.6
CalEnergy Generation – Domestic					17.9				61.9
CalEnergy Generation – Foreign					8.5				7.8
HomeServices					18.3				18.3
Segment capital expenditures					1,191.0				1,500.7
Corporate/other					0.1				7.4
Total capital expenditures				$	1,191.1			$	1,508.1

Capital expenditures and construction and other development costs for 2004 are expected to be approximately $1.3 billion.

MidAmerican Energy Capital Expenditures, Construction and Development Costs

MidAmerican Energy's primary need for capital is utility construction expenditures. For 2003, utility construction expenditures totaled $376.2 million, including allowance for funds used during construction and Quad Cities Station nuclear fuel purchases.

Forecasted utility construction expenditures, including allowance for funds used during construction, are $844 million for 2004. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews. MidAmerican Energy expects to meet these capital expenditures with cash flows from operations and the issuance of long-term debt.

In order to address projected capacity needs for its regulated customers, MidAmerican Energy is currently constructing two electric generating projects in Iowa and developing a third. 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 an agreed upon cap that MidAmerican Energy has deemed to be reasonable. 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 $314 million has been invested through December 31, 2003.

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 will continue to be operated in simple cycle mode during 2004, resulted in 327 MW of accredited capacity in the summer of 2003. The combined cycle operation is expected to commence in December 2004 and achieve an expected additional accredited capacity of 190 MW.

The second project is currently under construction and is 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 IUB issued an order that approves the ratemaking principles for the plant, and on June 27, 2003, MidAmerican Energy received a certificate from the IUB allowing MidAmerican Energy to construct the

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plant. On February 12, 2003, MidAmerican Energy executed a contract with Mitsui for the engineering, procurement and construction of the plant. On September 9, 2003, MidAmerican Energy began construction of the plant, which it expects to be completed in the summer of 2007. MidAmerican Energy is also seeking an order from the IUB approving construction of the associated transmission facilities.

The third project is currently under development and is comprised of wind power facilities totaling 310 MW based on the nameplate rating. Generally speaking, accredited capacity ratings for the wind power facilities are considerably less than the nameplate ratings due to the varying nature of wind. The current projected accredited capacity for these wind power facilities is approximately 53 MW. If constructed, MidAmerican Energy will own and operate these facilities, which are expected to cost approximately $323 million. MidAmerican Energy's plan to construct the wind project is in conjunction with a settlement agreement that extends through December 31, 2010, an Iowa retail electric rate freeze that was previously scheduled to expire at the end of 2005. The settlement agreement, which was filed with the IUB as part of MidAmerican Energy's application for ratemaking principles for the wind project, was approved by the IUB on October 17, 2003. The obligation of MidAmerican Energy to construct the wind project may be terminated by MidAmerican Energy if the federal production tax credit applicable to the wind energy facilities is not available at a rate of 1.8 cents per kWh for a period of at least ten years after the facilities begin generating electricity. The production tax credit is available only to wind facilities placed in service before January 1, 2004. MidAmerican Energy has also received authorization from the IUB to construct the wind power project. If MidAmerican Energy does not construct the wind facilities by December 31, 2007, the rate extension from January 1, 2006 through December 31, 2010 may terminate.

Kern River's 2003 Expansion Project

On May 1, 2003, Kern River completed the construction of its 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 Dth per day to 1,755,626 Dth per day.

Also on May 1, 2003, Kern River Funding Corporation, a wholly owned subsidiary of Kern River, issued $836 million of its 4.893% Senior Notes with a final maturity on April 30, 2018. The proceeds were used to repay all of the approximately $815 million of outstanding borrowings under Kern River's $875 million credit facility. Kern River entered into this credit facility in 2002 to finance the construction of the 2003 Expansion Project. The credit facility and a completion guarantee issued by MEHC in favor of the lenders was terminated.

Other Development Costs

Obsidian is evaluating the development of a 185 net MW geothermal facility in the Imperial Valley in California. Substantially all of the output of the facility would be sold to the IID pursuant to a power purchase agreement. TransAlta is currently funding 50% of the development costs of this project. On December 17, 2003, the CEC issued final approval for construction of the facility. If the project is constructed, MEHC expects capital expenditures to total approximately $550.0 million and currently plans to fund its interest in this project with available cash and future issuances of debt.

Acquisitions

Kern River

In March 2002, MEHC acquired Kern River for $419.7 million, net of cash acquired and a working capital adjustment. At the time, Kern River owned a 926-mile interstate natural gas pipeline extending from Wyoming to markets in California, Nevada and Utah and accesses natural gas supplies from large producing regions in the Rocky Mountains and Canada. MEHC used the proceeds from the issuances of $323.0 million of 11% Company-obligated mandatorily redeemable preferred securities of subsidiary trust due March 12, 2012 with scheduled principal payments beginning in 2005 and $127.0 million of no par, zero coupon convertible preferred stock to Berkshire Hathaway to finance the acquisition.

Northern Natural Gas

In August 2002, MEHC acquired Northern Natural Gas for $882.7 million, net of cash acquired and a working capital adjustment. Northern Natural Gas owns a 16,500-mile interstate natural gas pipeline

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extending from southwest Texas to the upper Midwest region of the United States with a design capacity of 4.4 Bcf of natural gas per day. Northern Natural Gas also operates three natural gas storage facilities and two liquefied natural gas peaking units with a total storage capacity of 59 Bcf and peak delivery capability of over 1.3 Bcf of natural gas per day. Northern Natural Gas accesses natural gas supply from many of the larger producing regions in North America, including the Rocky Mountains, Hugoton, Permian, Anadarko and Western Canadian basins. The pipeline system provides transportation and storage services to utilities, municipalities, other pipeline companies, gas marketers and industrial and commercial users. MEHC used the proceeds from a $950.0 million investment in its subsidiary trust's preferred securities by Berkshire Hathaway to finance the acquisition.

HomeServices' Acquisitions

In 2003, HomeServices separately acquired four real estate companies for an aggregate purchase price of approximately $36.7 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2002, these real estate companies had combined revenue of approximately $102.9 million on 16,000 closed sides representing $3.6 billion of sales volume. Additionally, HomeServices is obligated to pay a maximum earnout of $5.2 million based on 2004 and 2005 financial performance measures. These purchases were financed using HomeServices' internally generated cash flows and revolving credit facility. In 2002, HomeServices separately acquired three real estate companies for an aggregate purchase price of approximately $106.1 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2001, these real estate companies had combined revenue of approximately $356.0 million on 42,000 closed sides representing $13.7 billion of sales volume. Additionally, HomeServices was obligated to pay an earnout of $17.3 million based on 2002 financial performance measures. These purchases were financed using HomeServices' internally generated cash flows, revolving credit facility and $40.0 million from MEHC, which was contributed to HomeServices as equity.

Williams' Cumulative Convertible Preferred Stock

On June 10, 2003, Williams repurchased, for approximately $288.8 million, plus accrued dividends, all of the shares of its 9-7/8% Cumulative Convertible Preferred Stock originally acquired by the Company in March 2002 for $275.0 million.

Put of ROP Bond 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, CE Casecnan received $99.2 million (representing $97.0 million par value plus accrued interest) from the ROP on January 21, 2004.

Cash Flows from Financing Activities

Cash flows used in financing activities for 2003 were $426.3 million. During 2003, the Company used cash for financing activities, totaling $1,937.9 million, for repayments of parent and subsidiary long-term obligations, and generated cash from financing activities, totaling $1,606.9 million, from the issuance of subsidiary, project and parent company senior debt. Cash flows from financing activities for 2002 were $2,555.2 million. During 2002, the Company generated cash from financing activities, totaling $3,860.3 million, from the issuance of trust preferred securities, common and preferred stock and subsidiary, project and parent company debt, and used cash for financing activities, totaling $1,243.9 million, for repayments of parent and subsidiary long-term obligations.

Recent Debt Issuances and Redemptions

On January 14, 2003, MidAmerican Energy issued $275.0 million of 5.125% medium-term notes due in 2013. The proceeds were used to refinance existing debt and for other corporate purposes.

On February 10, 2003, MidAmerican Energy redeemed all $75.0 million of its 7.375% series of mortgage bonds, and on March 17, 2003, it redeemed all $6.94 million of its 7.45% series of mortgage bonds. Additionally, MidAmerican Energy's 7.125% series of mortgage bonds totaling $100 million matured on February 3, 2003. On October 17, 2003, MidAmerican Energy redeemed all $12.5 million of its 6.95% series of mortgage bonds at 103.48% of the principal amount.

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On May 16, 2003, MEHC issued $450 million of its 3.5% Senior Notes which mature on May 15, 2008. The proceeds were used for general corporate purposes.

In the second quarter of 2003, MEHC terminated its $400 million credit facility. On June 6, 2003, MEHC closed on a new $100 million revolving credit facility which expires on June 6, 2006. The facility supports letters of credit of which $73.0 million were outstanding at December 31, 2003.

On June 9, 2003, Yorkshire Power Group Limited, a wholly owned indirect subsidiary of CE Electric UK, completed the redemption in full of the outstanding shares of the Yorkshire Capital Trust I, 8.08% trust securities, due June 30, 2038, and paid $243.4 million in principal amount ($25 liquidation amount per each trust security) plus accrued distributions of $0.381555555 per trust security to the redemption date. The redemption price was paid to holders of the trust security on the redemption date.

On September 15, 2003, MEHC repaid its $215.0 million, 6.96% Senior Notes.

During 2003, MEHC purchased approximately $88.3 million of original face amount of debt obligations of its subsidiaries of which $37.5 million is held in other investments with the remainder being retired.

During 2003, CE Electric UK and its subsidiaries purchased and retired approximately $50 million of outstanding indebtedness.

On January 30, 2004, Salton Sea Funding Corporation ("SSFC"), a wholly owned subsidiary of CE Generation, announced its election to redeem an aggregate principal amount of approximately $136.4 million of its 7.475% Senior Secured Series F Bonds due November 30, 2018, pro rata, at a redemption price of 100% of such aggregate outstanding principal amount, plus accrued interest to the date of redemption. The trustee delivered a redemption notice to the holders of the bonds on January 29, 2004. The record date for the redemption is February 15, 2004 and the redemption is expected to be completed on March 1, 2004. SSFC expects to make a demand on MEHC for the full amount remaining on MEHC's guarantee of the Series F Bonds in order to fund the redemption. Upon the expected demand and payment under MEHC's guarantee, MEHC will no longer have any liability with respect to its guarantee.

Credit Ratings Risks

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. 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 December 31, 2003, MidAmerican Energy's estimated potential collateral requirements totaled approximately $89 million. MidAmerican Energy's collateral requirements could fluctuate considerably due to seasonality, market price volatility, 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 December 31, 2003, the agreements extend until February 25, 2008 and convert the U.S. dollar interest rate to a fixed Sterling rate ranging from 7.3175%

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to 7.345%. The estimated fair value of these swap agreements at December 31, 2003 is approximately $62.6 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 December 31, 2003, 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 $29.0 million.

Inflation

Inflation has not had a significant impact on the Company's costs.

Obligations and Commitments

The Company has contractual obligations and commercial commitments that may affect its financial condition. Contractual obligations to make future payments arise from parent company and subsidiary long-term debt and notes payable, preferred equity securities, operating leases and power and fuel purchase contracts. Other obligations arise from unused lines of credit and letters of credit. Material obligations as of December 31, 2003 are as follows (in millions):

				Payments Due By Period
				Total				< 1 Year				2-3 Years				4-5 Years				> 5 Years
Contractual Cash Obligations:
Parent company senior debt				$	2,777.9			$	—			$	260.0			$	1,550.0			$	967.9
Parent company subordinated debt					1,872.1				100.0				422.6				468.0				881.5
Subsidiary and project debt (1)					7,175.6				500.9				864.5				917.6				4,892.6
Preferred securities of subsidiaries					92.1				—				—				—				92.1
Coal, electricity and natural gas contract commitments (2)					593.1				179.0				204.5				101.2				108.4
Operating leases (2)					290.1				53.1				87.9				64.1				85.0
Total contractual cash obligations				$	12,800.9			$	833.0			$	1,839.5			$	3,100.9			$	7,027.5

				Commitment Expiration per Period
				Total				< 1 Year				2-3 Years				4-5 Years				> 5 Years
Other Commercial Commitments:
Unused parent company revolving lines of credit				$	26.4			$	—			$	26.4			$	—			$	—
Parent company letters of credit					73.6				73.0				0.6				—				—
Unused subsidiary lines of credit					138.0				13.0				125.0				—				—
Total other commercial commitments				$	238.0			$	86.0			$	152.0			$	—			$	—

(1)	Total less than one year includes $136.4 million expected to be redeemed on March 1, 2004.

(2)	The Coal, electricity and natural gas contract commitments and operating leases are not reflected on the consolidated balance sheets.

Off-Balance Sheet Arrangements

The Company has certain investments that are accounted for under the equity method in accordance with GAAP. Accordingly, an amount is recorded on the Company's balance sheet as an equity investment and is increased or decreased for the the Company's pro-rata share of earnings or losses, respectively, less any dividend distribution from such investments.

As of December 31, 2003, the Company's investments which are accounted for under the equity method had $924.6 million of debt and $39.5 million in outstanding letters of credit. As of December 31,

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2003, the Company's pro-rata share of such debt, which is non-recourse to MEHC, was $394.1 million. The $394.1 million excludes the $136.4 million of debt which MEHC has guaranteed on the Salton Sea Funding Series F Bonds and which is included in the the Company's consolidated balance sheet at December 31, 2003. This amount is expected to be redeemed on March 1, 2004. As of December 31, 2003, the Company's pro-rata share of its equity investments' outstanding letters of credit was $16.7 million and was non-recourse to MEHC.

MEHC is generally not required to support the debt service obligations of its equity investments. However, default with respect to this non-recourse debt could result in a loss of invested equity.

New Accounting Pronouncements

On January 1, 2003, the Company adopted SFAS No. 143, "Accounting for Asset Retirement Obligations". This statement provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. The cumulative effect of initially applying this statement by the Company was immaterial.

The Company identified legal retirement obligations for nuclear decommissioning, wet and dry ash landfills and offshore and minor lateral pipeline facilities. On January 1, 2003, the Company recorded $289.3 million of asset retirement obligation ("ARO") liabilities; $13.9 million of ARO assets, net of accumulated depreciation; $114.6 million of regulatory assets; and reclassified $1.0 million of accumulated depreciation to the ARO liability. The initial ARO liability recognized includes $266.5 million that pertains to obligations associated with the decommissioning of the Quad Cities nuclear station. The $266.5 million includes a $159.8 million nuclear decommissioning liability that had been recorded at December 31, 2002. The adoption of this statement did not have a material impact on the operations of the regulated entities, as the effects were offset by the establishment of regulatory assets, totaling $114.6 million, pursuant to SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation".

On April 30, 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" ("SFAS 149"). SFAS 149 amends SFAS No. 133 for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. SFAS 149 requires contracts with comparable characteristics to be accounted for similarly. In particular, SFAS 149 clarifies when a contract with an initial net investment meets the characteristic of a derivative and clarifies when a derivative that contains a financing component will require special reporting in the statement of cash flows. SFAS 149 is effective for the Company for contracts entered into or modified after June 30, 2003. The adoption of SFAS 149 did not have a material effect on the Company's financial position, results of operations or cash flows.

In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" ("SFAS 150"). SFAS 150 established standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). The standard is effective for the Company for fiscal periods beginning after December 15, 2003. The adoption of SFAS 150 is not expected to have a material effect on the Company's financial position, results of operations or cash flows.

In December 2003, the FASB issued FIN 46R, which served to clarify guidance in Financial Interpretation No. 46 ("FIN 46"), and provided additional guidance surrounding the application of FIN 46. The Company adopted and applied the provisions of FIN 46R 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, of approximately $1.9 billion, being reclassified to parent company subordinated debt in the accompanying consolidated balance sheet as of December 31, 2003. In addition, the associated amounts previously recorded as minority interest are now recorded as interest expense in the accompanying consolidated statement of operations. For the period from October 1, 2003 to December 31, 2003, the Company has recorded $49.8 million 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 Company will adopt the provisions of FIN 46R related to non-special purpose entities in the first quarter of 2004, in accordance with the

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provisions of FIN 46R. The Company is currently evaluating the impact of FIN 46R on several operating joint ventures that the Company currently does not consolidate.

Critical Accounting Policies

The preparation of financial statements and related documents in conformity with generally accepted accounting principles in the United States of America ("GAAP") requires management to make judgments, assumptions and estimates that affect the amounts reported in the consolidated financial statements and accompanying notes. Note 2 to the consolidated financial statements for the year ended December 31, 2003 included in this annual report describes the significant accounting policies and methods used in the preparation of the consolidated financial statements. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment of long-lived assets, contingent liabilities, accrued pension and post-retirement expense and revenue. Actual results could differ from these estimates. The following critical accounting policies are impacted significantly by judgments, assumptions and estimates used in the preparation of the consolidated financial statements.

Accounting for the Effects of Certain Types of Regulation

MidAmerican Energy, Kern River and Northern Natural Gas prepare their financial statements in accordance with the provisions of Statement of Financial Accounting Standards ("SFAS") No. 71 ("SFAS 71"), which differs in certain respects from the application of generally accepted accounting principles by non-regulated businesses. In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, MidAmerican Energy, Kern River and Northern Natural Gas have deferred certain costs, which will be amortized over various future periods. To the extent that collection of such costs or payment of such obligations is no longer probable as a result of changes in regulation, the associated regulatory asset or liability is charged or credited to income.

A possible consequence of deregulation of the regulated energy industry is that SFAS 71 may no longer apply. If portions of the Company's regulated energy operations no longer meet the criteria of SFAS 71, the Company could be required to write off the related regulatory assets and liabilities from its balance sheet, and thus a material adjustment to earnings in that period could result if regulatory assets or liabilities are not recovered in transition provisions of any deregulation legislation.

The Company continues to evaluate the applicability of SFAS 71 to its regulated energy operations and the recoverability of these assets and liabilities through rates as there are on-going changes in the regulatory and economic environment.

Impairment of Long-Lived Assets

The Company's long-lived assets consist primarily of properties, plants and equipment and acquired goodwill. Depreciation is computed using the straight-line method based on economic lives or regulatorily mandated recovery periods. The Company believes the useful lives assigned to the depreciable assets, which generally range from 3 to 87 years, are reasonable.

The Company's periodically evaluates long-lived assets, including properties, plants and equipment, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. Upon the occurrence of a triggering event, the carrying amount of a long-lived asset is reviewed to assess whether the recoverable amount has declined below its carrying amount. The recoverable amount is the estimated net future cash flows that the Company expects to recover from the future use of the asset, undiscounted and without interest, plus the asset's residual value on disposal. Where the recoverable amount of the long-lived asset is less than the carrying value, an impairment loss would be recognized to write down the asset to its fair value that is based on discounted estimated cash flows from the future use of the asset. The Company also evaluates goodwill for impairment annually, primarily using a discounted cash flow methodology.

The estimate of cash flows arising from future use of the asset that are used in the impairment analysis requires judgment regarding what the Company would expect to recover from future use of the

52

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asset. Any changes in the estimates of cash flows arising from future use of the asset or the residual value of the asset on disposal based on changes in the market conditions, changes in the use of the asset, management's plans, the determination of the useful life of the asset and technology changes in the industry could significantly change the calculation of the fair value or recoverable amount of the asset and the resulting impairment loss, which could significantly affect the results of operations. The determination of whether impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. An impairment analysis of generating facilities requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the facilities. A resulting impairment loss is highly dependent on these underlying assumptions.

On January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142"), which establishes the accounting for acquired goodwill and other intangible assets, and provides that goodwill and indefinite-lived intangible assets will not be amortized, but will be tested for impairment on an annual basis. The Company's related amortization consists solely of goodwill amortization. In accordance with SFAS 142, the Company completed its annual goodwill impairment test, as of October 31, 2003, primarily using a discounted cash flow methodology. No impairment was indicated as a result of the impairment tests.

Contingent Liabilities

The Company establishes reserves for estimated loss contingencies, such as environmental, legal and income taxes, when it is management's assessment that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in operations in the period in which different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Reserves for contingent liabilities are based upon management's assumptions and estimates, and advice of legal counsel or other third parties regarding the probable outcomes of any matters. Should the outcomes differ from the assumptions and estimates, revisions to the estimated reserves for contingent liabilities would be required.

Accrued Pension and Postretirement Expense

Pension and postretirement costs are accrued throughout the year based on results of an annual study performed by external actuaries. In addition to the benefits granted to employees, the timing of the cost of these plans is impacted by assumptions used by the actuaries, including assumptions provided by MEHC for the discount rate and long-term rate of return on assets. Both of these factors require estimates and projections by management and can fluctuate from period to period. Actual returns on assets are significantly affected by stock and bond markets, over which management has little control. The interest rate at which projected benefits are discounted significantly affects amounts expensed.

Revenue Recognition

Revenue is recorded based upon services rendered and electricity, gas and steam delivered, distributed or supplied to the end of the period. The Company records unbilled revenue representing the estimated amounts customers will be billed for services rendered between the meter reading dates in a particular month and the end of that month. The unbilled revenue estimate is reversed in the following month.

Where there is an over recovery of United Kingdom distribution business revenue against the maximum regulated amount, revenue is deferred in an amount equivalent to the over recovered amount. The deferred amount is deducted from revenue and included in other liabilities. Where there is an under recovery, no anticipation of any potential future recovery is made.

Revenue from the transportation and storage of gas are recognized based on contractual terms and the related volumes. Kern River and Northern Natural Gas are subject to the FERC's regulations and, accordingly, certain revenue collected may be subject to possible refunds upon final orders in pending rate cases. Kern River and Northern Natural Gas record rate refund liabilities considering their regulatory proceedings and other third party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks.

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Revenue from water delivery is recorded on the basis of the contractual minimum guaranteed water delivery threshold for the respective contract year. If and when cumulative deliveries within a contract year exceed the minimum threshold, additional revenue is recognized. Revenue from long-term electricity contracts is recorded at the lower of the amount billed or the average of the contract, subject to contractual provisions at each project.

Commission revenue from real estate brokerage transactions and related amounts due to agents are recognized when title has transferred from seller to buyer. Title fee revenue from real estate transactions and related amounts due to the title insurer are recognized at the closing, which is when consideration is received. Fees related to loan originations are recognized at the closing, which is when services have been provided and consideration is received.

To the extent the estimated amount differs from the actual amount, revenue will be affected.

Item 7A.    Quantitative and Qualitative Disclosures about Market Risk.

The Company is exposed to market risk, including changes in the market price of certain commodities and interest rates. To manage the price volatility relating to these exposures, the Company enters into various financial derivative instruments. Senior management provides the overall direction, structure, conduct and control of the Company's risk management activities, including the use of financial derivative instruments, authorization and communication of risk management policies and procedures, strategic hedging program guidelines, appropriate market and credit risk limits, and appropriate systems for recording, monitoring and reporting the results of transactional and risk management activities.

Interest Rate Risk

At December 31, 2003, the Company had fixed-rate long-term debt of $11,369.4 million in aggregate principal amount and having a fair value of $12,015.1 million. These instruments are fixed-rate and therefore do not expose the Company to the risk of earnings loss due to changes in market interest rates. However, the fair value of these instruments would decrease by approximately $387.3 million if interest rates were to increase by 10% from their levels at December 31, 2003. In general, such a decrease in fair value would impact earnings and cash flows only if the Company were to reacquire all or a portion of these instruments prior to their maturity.

At December 31, 2002, the Company had fixed-rate long-term debt and Company-obligated mandatorily redeemable preferred securities of subsidiary trusts of $11,683.2 million in aggregate principal amount and having a fair value of $12,188.8 million. These instruments were fixed-rate and therefore did not expose the Company to the risk of earnings loss due to changes in market interest rates.

At December 31, 2003, the Company had floating-rate obligations of $459.8 million that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. These obligations are not hedged. If the floating rates were to increase by 1% the Company's consolidated interest expense for unhedged floating-rate obligations would increase by approximately $0.4 million each month in which such increase continued based upon December 31, 2003 principal balances.

At December 31, 2002, the Company had floating-rate obligations of $425.1 million that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. These obligations were not hedged.

Currency Exchange Rate Risk

CE Electric UK entered into certain currency rate swap agreements for its Senior Notes with two large multi-national financial institutions. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate in Sterling. For the $117.1 million of 6.853% Senior Notes, the agreements extend until maturity on December 30, 2004 and convert the U.S. dollar interest rate to a fixed Sterling rate of 7.744%. For the $236.2 million of 6.995% Senior Notes, the agreements extend until maturity on December 30, 2007 and convert the U.S. dollar interest rate to a fixed Sterling rate of 7.737%. The estimated fair value of these swap agreements at December 31, 2003 is approximately $16.0 million based on quotes from the counterparty to these instruments and represents the estimated amount that the Company would expect to pay if these agreements were terminated.

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Yorkshire 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 6.496% Yankee Bonds, the agreements extend until February 25, 2008 and convert the U.S. dollar interest rate to a fixed Sterling rate ranging from 7.3175% to 7.345%. The estimated fair value of these swap agreements at December 31, 2003 is approximately $62.6 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.

A decrease of 10% in the December 31, 2003 rate of exchange of Sterling to dollars would increase the amount owed by the Company if these swap agreements were terminated by approximately $97.4 million.

Derivatives

MidAmerican Energy enters into various financial derivative instruments, including futures, over-the-counter swaps and forward physical contracts. Senior management provides the overall direction, structure, conduct and control of MidAmerican Energy's risk management activities, including authorization and communication of risk management policies and procedures, the use of financial derivative instruments, 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.

As of December 31, 2003, MidAmerican Energy held derivative instruments used for non-trading and trading purposes with the following fair values (in thousands):

Contract Type				Maturity in 2004				Maturity in 2005-07				Total
Non-trading:
Regulated electric assets				$	5,924			$	217			$	6,141
Regulated electric (liabilities)					(14,275	)			—				(14,275	)
Regulated gas assets					9,008				—				9,008
Regulated weather (liabilities)					(1,775	)			—				(1,775	)
Nonregulated electric assets					2,953				1,676				4,629
Nonregulated electric (liabilities)					(1,711	)			(1,131	)			(2,842	)
Nonregulated gas assets					11,498				798				12,296
Nonregulated gas (liabilities)					(11,867	)			(739	)			(12,606	)
Total					(245	)			821				576
Trading:
Nonregulated gas assets					389				247				636
Nonregulated gas (liabilities)					(419	)			—				(419	)
Total					(30	)			247				217
Total MidAmerican Energy assets				$	29,772			$	2,938			$	32,710
Total MidAmerican Energy (liabilities)				$	(30,047	)		$	(1,870	)		$	(31,917	)

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Item 8.    Financial Statements and Supplementary Data.

Independent Auditors' Report					57
Consolidated Balance Sheets as of December 31, 2003 and 2002					58
Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001					59
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2003, 2002 and 2001					60
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001					61
Notes to Consolidated Financial Statements					62

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INDEPENDENT AUDITORS' REPORT

Board of Directors and Stockholders
MidAmerican Energy Holdings Company
Des Moines, Iowa

We have audited the accompanying consolidated balance sheets of MidAmerican Energy Holdings Company and subsidiaries (the "Company") as of December 31, 2003 and 2002, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the consolidated financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of MidAmerican Energy Holdings Company and subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, the Company changed its accounting policy for asset retirement obligations and for variable interest entities in 2003, for goodwill and other intangible assets in 2002, and for major maintenance, overhaul and well workover costs in 2001.

/s/ Deloitte & Touche LLP

DELOITTE & TOUCHE LLP
Des Moines, Iowa
February 9, 2004

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MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands)

				As of December 31,
				2003				2002
ASSETS
Current assets:
Cash and cash equivalents				$	660,213			$	844,430
Restricted cash and short-term investments					55,281				50,808
Accounts receivable, net of allowance for doubtful accounts of $26,004 and $39,742					666,063				707,731
Inventories					123,301				126,938
Other current assets					371,855				246,731
Total current assets					1,876,713				1,976,638
Properties, plants and equipment, net					11,180,979				9,898,796
Goodwill					4,305,643				4,258,132
Regulatory assets					512,549				415,804
Other investments					228,896				446,732
Equity investments					234,370				273,707
Deferred charges and other assets					829,039				779,420
Total assets				$	19,168,189			$	18,049,229
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable				$	345,237			$	462,960
Accrued interest					189,635				192,015
Accrued taxes					112,823				108,940
Other accrued liabilities					443,531				457,058
Short-term debt					48,036				79,782
Current portion of long-term debt					500,941				470,213
Current portion of parent company subordinated debt					100,000				—
Total current liabilities					1,740,203				1,770,968
Other long-term accrued liabilities					1,827,633				1,100,917
Parent company senior debt					2,777,878				2,323,387
Parent company subordinated debt					1,772,146				—
Subsidiary and project debt					6,674,640				7,077,087
Deferred income taxes					1,433,144				1,238,421
Total liabilities					16,225,644				13,510,780
Deferred income					69,201				80,078
Minority interest					9,754				7,351
Preferred securities of subsidiaries					92,145				93,325
Company-obligated mandatorily redeemable preferred securities of subsidiary trusts					—				2,063,412
Commitments and contingencies (Note 19)
Stockholders' equity:
Zero coupon convertible preferred stock — authorized 50,000 shares, no par value; 41,263 shares outstanding at December 31, 2003 and 2002					—				—
Common stock — authorized 60,000 shares, no par value; 9,281 shares issued and outstanding at December 31, 2003 and 2002					—				—
Additional paid-in capital					1,957,277				1,956,509
Retained earnings					999,627				584,009
Accumulated other comprehensive loss, net					(185,459	)			(246,235	)
Total stockholders' equity					2,771,445				2,294,283
Total liabilities and stockholders' equity				$	19,168,189			$	18,049,229

The accompanying notes are an integral part of these financial statements.

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MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands)

				Year Ended December 31,
				2003				2002				2001
Revenue:
Operating revenue				$	5,948,224			$	4,794,010			$	4,696,781
Income on equity investments					38,224				40,520				39,565
Interest and dividend income					47,911				56,250				24,552
Other income					110,318				77,359				212,082
Total revenue					6,144,677				4,968,139				4,972,980
Costs and expenses:
Cost of sales					2,416,132				1,844,024				2,341,178
Operating expense					1,527,516				1,345,205				1,176,422
Depreciation and amortization					609,889				525,902				538,702
Interest expense					771,831				647,379				499,263
Less interest capitalized					(30,483	)			(37,469	)			(86,469	)
Total costs and expenses					5,294,885				4,325,041				4,469,096
Income before provision for income taxes					849,792				643,098				503,884
Provision for income taxes					250,971				99,588				250,064
Income before minority interest and preferred dividends					598,821				543,510				253,820
Minority interest and preferred dividends					183,203				163,467				106,547
Income before cumulative effect of change in accounting principle					415,618				380,043				147,273
Cumulative effect of change in accounting principle, net of tax (Note 2)					—				—				(4,604	)
Net income available to common and preferred stockholders				$	415,618			$	380,043			$	142,669

The accompanying notes are an integral part of these financial statements.

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MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Amounts in thousands)

				Outstanding Common Shares				Common Stock				Additional Paid-in Capital				Retained Earnings				Accumulated Other Comprehensive Income (Loss)				Total
Balance, January 1, 2001					9,281			$	—			$	1,553,073			$	81,257			$	(57,929	)		$	1,576,401
Net income					—				—				—				142,669				—				142,669
Other comprehensive income: Foreign currency translation adjustment					—				—				—				—				(22,103	)			(22,103	)
Fair value adjustment on cash flow hedges, net of tax of $8,143					—				—				—				—				18,490				18,490
Minimum pension liability adjustment, net of tax of $(3,448)					—				—				—				—				(4,847	)			(4,847	)
Unrealized losses on securities, net of tax of $(1,315)					—				—				—				—				(2,443	)			(2,443	)
Total other comprehensive income																									131,766
Balance, December 31, 2001					9,281				—				1,553,073				223,926				(68,832	)			1,708,167
Net income					—				—				—				380,043				—				380,043
Other comprehensive income:
Foreign currency translation adjustment					—				—				—				—				166,880				166,880
Fair value adjustment on cash flow hedges, net of tax of $(10,106)					—				—				—				—				(27,623	)			(27,623	)
Minimum pension liability adjustment, net of tax of $(135,707)					—				—				—				—				(313,456	)			(313,456	)
Unrealized losses on securities, net of tax of $(1,813)					—				—				—				—				(3,204	)			(3,204	)
Total other comprehensive income																									202,640
Issuance of zero-coupon convertible preferred stock					—				—				402,000				—				—				402,000
Retirement of stock options					—				—				815				(19,960	)			—				(19,145	)
Other equity transactions					—				—				621				—				—				621
Balance, December 31, 2002					9,281				—				1,956,509				584,009				(246,235	)			2,294,283
Net income					—				—				—				415,618				—				415,618
Other comprehensive income:
Foreign currency translation adjustment					—				—				—				—				58,148				58,148
Fair value adjustment on cash flow hedges, net of tax of $7,202					—				—				—				—				16,769				16,769
Minimum pension liability adjustment, net of tax of $(6,425)					—				—				—				—				(14,989	)			(14,989	)
Unrealized losses on securities, net of tax of $566					—				—				—				—				848				848
Total other comprehensive income																									476,394
Other equity transactions					—				—				768				—				—				768
Balance, December 31, 2003					9,281			$	—			$	1,957,277			$	999,627			$	(185,459	)		$	2,771,445

The accompanying notes are an integral part of these financial statements.

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MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)

				Year Ended December 31,
				2003				2002				2001
Cash flows from operating activities:
Net income				$	415,618			$	380,043			$	142,669
Adjustments to reconcile net cash flows from operating activities:
Distributions less income on equity investments					40,160				(11,383	)			(28,515	)
Gains on asset sales					(24,321	)			(25,329	)			(179,493	)
Depreciation and amortization					609,889				525,902				442,284
Amortization of goodwill					—				—				96,418
Amortization of regulatory assets and liabilities and other					(14,363	)			8,709				23,774
Amortization of deferred financing costs					28,046				28,615				20,737
Provision for deferred income taxes					237,322				(16,228	)			152,920
Cumulative effect of change in accounting principle, net of tax					—				—				4,604
Changes in other items:
Accounts receivable and other current assets					(27,447	)			(201,147	)			571,910
Accounts payable and other accrued liabilities					(46,138	)			64,759				(420,434	)
Deferred income					(9,344	)			(4,839	)			6,428
Other					8,501				8,624				13,696
Net cash flows from operating activities					1,217,923				757,726				846,998
Cash flows from investing activities:
Acquisitions, net of cash acquired					(54,263	)			(1,416,937	)			(81,934	)
Sale (purchase) of convertible preferred securities					288,750				(275,000	)			—
Capital expenditures relating to operating projects					(677,256	)			(542,615	)			(398,165	)
Construction and other development costs					(513,771	)			(965,470	)			(178,587	)
Purchase of affiliates notes					(35,029	)			—				(13,247	)
Proceeds from sale of assets					13,113				214,070				377,396
Decrease in restricted cash and investments					7,415				16,351				24,540
Other					(32,126	)			61,790				31,453
Net cash flows from investing activities					(1,003,167	)			(2,907,811	)			(238,544	)
Cash flows from financing activities:
Proceeds from subsidiary and project debt					1,157,649				1,485,349				200,000
Proceeds from parent company senior debt					449,295				700,000				—
Repayments of subsidiary and project debt					(1,490,986	)			(395,370	)			(437,372	)
Repayment of parent company senior debt					(215,000	)			—				—
Repayment of parent company subordinated debt					(198,958	)			—				—
Net proceeds from (repayment of) parent company revolving credit facility					—				(153,500	)			68,500
Repayment of other obligations					—				(94,297	)			—
Net repayment of subsidiary short-term debt					(31,750	)			(472,835	)			(74,144	)
Proceeds from issuance of trust preferred securities					—				1,273,000				—
Proceeds from issuance of preferred stock					—				402,000				—
Redemption of preferred securities of subsidiaries					(1,176	)			(127,908	)			(24,910	)
Other					(95,411	)			(61,205	)			9,459
Net cash flows from financing activities					(426,337	)			2,555,234				(258,467	)
Effect of exchange rate changes					27,364				52,536				(1,394	)
Net change in cash and cash equivalents					(184,217	)			457,685				348,593
Cash and cash equivalents at beginning of period					844,430				386,745				38,152
Cash and cash equivalents at end of period				$	660,213			$	844,430			$	386,745
Supplemental Disclosure:
Interest paid, net of interest capitalized				$	706,039			$	588,972			$	389,953
Income taxes paid				$	9,911			$	101,225			$	133,139
Non-cash transaction – ROP note received under NIA Arbitration Settlement				$	97,000			$	—			$	—

The accompanying notes are an integral part of these financial statements.

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MIDAMERICAN ENERGY HOLDINGS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.    Organization and Operations

MidAmerican Energy Holdings Company ("MEHC") and its subsidiaries (together with MEHC, the "Company") is a United States-based privately owned global energy company. The Company's operations are organized and managed on seven distinct platforms: MidAmerican Energy Company ("MidAmerican Energy"), Kern River Gas Transmission Company ("Kern River"), Northern Natural Gas Company ("Northern Natural Gas"), CE Electric UK Funding ("CE Electric UK") (which includes Northern Electric plc ("Northern Electric ") and Yorkshire Electricity Group plc ("Yorkshire ")), CalEnergy Generation-Domestic (interests in independent power projects and related operations), CalEnergy Generation-Foreign (the subsidiaries owning the Upper Mahiao, Malitbog and Mahanagdong Projects (collectively the "Leyte Projects") and the Casecnan project) and HomeServices of America, Inc. (collectively with its subsidiaries, "HomeServices"). Through these platforms, the Company owns and operates a combined electric and natural gas utility company in the United States, two natural gas pipeline companies in the United States, two electricity distribution companies in the United Kingdom, a diversified portfolio of domestic and international independent power projects and the second largest residential real estate brokerage firm in the United States.

On March 14, 2000, MEHC and an investor group comprised of Berkshire Hathaway Inc. ("Berkshire Hathaway"), Walter Scott, Jr., a director of MEHC, David L. Sokol, Chairman and Chief Executive Officer of MEHC, and Gregory E. Abel, President and Chief Operating Officer of MEHC, closed on a definitive agreement and plan of merger whereby the investor group, together with certain of Mr. Scott's family members and family trusts and corporations, acquired all of the outstanding common stock of MEHC (the "Teton Transaction").

MEHC initially incorporated in 1971 under the laws of the State of Delaware and was reincorporated in 1999 in Iowa, at which time it changed its name from CalEnergy Company, Inc. to MidAmerican Energy Holdings Company.

In these notes to consolidated financial statements, references to "U.S. dollars," "dollars," "$" or "cents" are to the currency of the United States, references to "pounds sterling," "£," "sterling," "pence" or "p" are to the currency of the United Kingdom and references to "pesos" are to the currency of the Philippines. References to kW means kilowatts, MW means megawatts, GW means gigawatts, kWh means kilowatt hours, MWh means megawatt hours, GWh means gigawatts hours, kV means kilovolts, mmcf means million cubic feet, Bcf means billion cubic feet, Tcf means trillion cubic feet, MMBtus means million British thermal units and Dth means decatherms or MMBtus.

2.    Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of MEHC and its wholly owned subsidiaries excluding entities for which adoption of FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities" ("FIN 46R") was required at December 31, 2003. Subsidiaries which are less than 100% owned but greater than 50% owned are consolidated with a minority interest. Subsidiaries that are 50% owned or less, but where the Company has the ability to exercise significant influence, are accounted for under the equity method of accounting. Investments where the Company's ability to influence is limited are accounted for under the cost method of accounting. All inter-enterprise transactions and accounts have been eliminated. The results of operations of the Company include the Company's proportionate share of results of operations of entities acquired from the date of each acquisition for purchase business combinations.

For the Company's foreign operations whose functional currency is not the U.S. dollar, the assets and liabilities are translated into U.S. dollars at current exchange rates. Resulting translation adjustments are reflected as accumulated other comprehensive income (loss) in stockholders' equity. Revenue and expenses are translated at average exchange rates for the period. Transaction gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency other than the functional currency are included in the results of operations as incurred.

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Reclassifications

Certain amounts in the fiscal 2002 and 2001 consolidated financial statements and supporting note disclosures have been reclassified to conform to the fiscal 2003 presentation. Such reclassification did not impact previously reported net income or retained earnings.

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Accounting for the Effects of Certain Types of Regulation

MidAmerican Energy, Kern River and Northern Natural Gas prepare their financial statements in accordance with the provisions of Statement of Financial Accounting Standards ("SFAS") No. 71 ("SFAS 71"), which differs in certain respects from the application of generally accepted accounting principles by non-regulated businesses. In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, MidAmerican Energy, Kern River and Northern Natural Gas have deferred certain costs, which will be amortized over various future periods. To the extent that collection of such costs or payment of such obligations is no longer probable as a result of changes in regulation, the associated regulatory asset or liability is charged or credited to income.

A possible consequence of deregulation of the regulated energy industry is that SFAS 71 may no longer apply. If portions of the Company's regulated energy operations no longer meet the criteria of SFAS 71, the Company could be required to write off the related regulatory assets and liabilities from its balance sheet, and thus a material adjustment to earnings in that period could result if regulatory assets or liabilities are not recovered in transition provisions of any deregulation legislation.

The Company continues to evaluate the applicability of SFAS 71 to its regulated energy operations and the recoverability of these assets and liabilities through rates as there are on-going changes in the regulatory and economic environment.

Cash and Cash Equivalents

The Company considers all investment instruments purchased with an original maturity of three months or less to be cash equivalents. Investments other than restricted cash are primarily commercial paper and money market securities. Restricted cash is not considered a cash equivalent.

Restricted Cash and Investments

The current restricted cash and short-term investments balance recorded separately in restricted cash and short term investments and in deferred charges and other assets, was $119.5 million and $58.7 million at December 31, 2003 and 2002, respectively, and includes commercial paper and money market securities. The balance is mainly composed of amounts deposited in restricted accounts from which the Company will source its debt service reserve requirements relating to the projects and customer deposits held in escrow. The debt service funds are restricted by their respective project debt agreements to be used only for the related project.

The Company's nuclear decommissioning trust funds and other marketable securities are classified as available for sale and are accounted for at fair value.

Allowance for Doubtful Accounts

The allowance for doubtful accounts is based on the Company's assessment of the collectibility of payments from its customers. This assessment requires judgment regarding the outcome of pending disputes, arbitrations and the ability of customers to pay the amounts owed to the Company.

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Fair Value of Financial Instruments

The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. Although management uses its best judgment in estimating the fair value of these financial instruments, there are inherent limitations in any estimation technique. Therefore, the fair value estimates presented herein are not necessarily indicative of the amounts that the Company could realize in a current transaction.

The methods and assumptions used to estimate fair value are as follows:

Short-term debt — Due to the short-term nature of the short-term debt, the fair value approximates the carrying value.

Debt instruments — The fair value of all debt instruments has been estimated based upon quoted market prices as supplied by third-party broker dealers, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The Company is unable to estimate a fair value for the Leyte debt as there are no quoted market prices available.

Other financial instruments — All other financial instruments of a material nature are short-term and the fair value approximates the carrying amount.

Properties, Plants and Equipment, Net

Properties, plants and equipment are recorded at historical cost. The cost of major additions and betterments are capitalized, while replacements, maintenance, and repairs that do not improve or extend the lives of the respective assets are expensed.

Capitalized costs for gas reserves, other than costs of unevaluated exploration projects and projects awaiting development consent, are depleted using the units of production method. Depletion is calculated based on hydrocarbon reserves of properties in the evaluated pool estimated to be commercially recoverable and include anticipated future development costs in respect of those reserves.

Impairment of Long-Lived Assets

The Company's long-lived assets consist primarily of properties, plants and equipment. Depreciation is computed using the straight-line method based on economic lives or regulatorily mandated recovery periods. The Company believes the useful lives assigned to the depreciable assets, which generally range from 3 to 87 years, are reasonable.

The Company periodically evaluates long-lived assets, including properties, plants and equipment, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. Upon the occurrence of a triggering event, the carrying amount of a long-lived asset is reviewed to assess whether the recoverable amount has declined below its carrying amount. The recoverable amount is the estimated net future cash flows that the Company expects to recover from the future use of the asset, undiscounted and without interest, plus the asset's residual value on disposal. Where the recoverable amount of the long-lived asset is less than the carrying value, an impairment loss would be recognized to write down the asset to its fair value that is based on discounted estimated cash flows from the future use of the asset.

Goodwill

On January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142"), which establishes the accounting for acquired goodwill and other intangible assets, and provides that goodwill and indefinite-lived intangible assets will not be amortized, but will be tested for impairment on an annual basis. The Company's related amortization consisted primarily of goodwill amortization. Following is a reconciliation of net income available to common and preferred stockholders as originally reported for the years ended December 31, 2003, 2002 and 2001 to adjusted net income available to common and preferred stockholders (in thousands):

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				Year Ended December
				2003				2002				2001
Reported net income available to common and preferred stockholders				$	415,618			$	380,043			$	142,669
Amortization of goodwill					—				—				96,418
Tax effect of amortization					—				—				(2,018	)
Adjusted net income available to common and preferred stockholders				$	415,618			$	380,043			$	237,069

The Company completed its annual review pursuant to SFAS 142 for its reporting units during the fourth quarter of 2003 primarily using a discounted cash flow methodology. No impairment was indicated as a result of these assessments.

Capitalization of Interest and Allowance for Funds Used During Construction

Allowance for funds used during construction ("AFUDC") represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases both utility plant and earnings, it is realized in cash through depreciation provisions included in rates for subsidiaries that apply SFAS 71. Interest and AFUDC for subsidiaries that apply SFAS 71 are capitalized as a component of projects under construction and will be amortized over the assets' estimated useful lives.

Deferred Financing Cost

The Company capitalizes costs associated with financings, as deferred financing costs, and amortizes the amounts over the term of the related financing using the effective interest method.

Contingent Liabilities

The Company establishes reserves for estimated loss contingencies, such as environmental, legal and income taxes, when it is management's assessment that a loss is probable and the amount of the loss can be reasonably estimated.

Deferred Income Taxes

The Company recognizes deferred tax assets and liabilities based on the difference between the financial statement and tax basis of assets and liabilities using estimated tax rates in effect for the year in which the differences are expected to reverse. The Company does not intend to repatriate earnings of foreign subsidiaries in the foreseeable future. As a result, deferred United States income taxes are not provided for currency translation adjustments, retained earnings of international subsidiaries or corporate joint ventures unless the earnings are intended to be remitted.

Revenue Recognition

Revenue is recorded based upon services rendered and electricity, gas and steam delivered, distributed or supplied to the end of the period. The Company records unbilled revenue representing the estimated amounts customers will be billed for services rendered between the meter reading dates in a particular month and the end of that month. The unbilled revenue estimate is reversed in the following month.

Where billings result in an overrecovery of United Kingdom distribution business revenue against the maximum regulated amount, revenue is deferred in an amount equivalent to the over recovered amount. The deferred amount is deducted from revenue and included in other accrued liabilities. Where there is an under recovery, no anticipation of any potential future recovery is made.

Revenue from the transportation and storage of gas are recognized based on contractual terms and the related volumes. Kern River and Northern Natural Gas are subject to the Federal Energy Regulatory Commission's ("FERC") regulations and, accordingly, certain revenue collected may be subject to possible refunds upon final orders in pending rate cases. Kern River and Northern Natural Gas record rate refund liabilities, which are included in other accrued liabilities, considering their regulatory proceedings and other third party regulatory proceedings, advice of counsel and estimated total exposure, as well as collection and other risks.

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Revenue from water delivery is recorded on the basis of the contractual minimum guaranteed water delivery threshold for the respective contract year. If and when cumulative deliveries within a contract year exceed the minimum threshold, additional revenue is recognized. Revenue from long-term electricity contracts is recorded at the lower of the amount billed or the average of the contract, subject to contractual provisions at each project.

Commission revenue from real estate brokerage transactions and related amounts due to agents are recognized when title has transferred from seller to buyer. Title fee revenue from real estate transactions and related amounts due to the title insurer are recognized at the closing, which is when consideration is received. Fees related to loan originations are recognized at the closing, which is when services have been provided and consideration is received.

Financial Instruments

The Company currently utilizes swap agreements and forward purchase agreements to manage market risks and reduce its exposure resulting from fluctuation in interest rates, foreign currency exchange rates and electric and gas prices. For interest rate swap agreements, the net cash amounts paid or received on the agreements are accrued and recognized as an adjustment to interest expense. Gains and losses related to gas forward contracts are deferred and included in the measurement of the related gas purchases. These instruments are either exchange traded or with counterparties of high credit quality; therefore, the risk of nonperformance by the counterparties is considered to be negligible.

Accounting Principle Change

Effective January 1, 2001, the Company changed its accounting policy regarding major maintenance and repairs for non-regulated gas projects, non-regulated plant overhaul costs and geothermal well rework costs to the direct expense method from the former policy of 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 $0.7 million.

New Accounting Pronouncements

On January 1, 2003, the Company adopted SFAS No. 143, "Accounting for Asset Retirement Obligations". This statement provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. The cumulative effect of initially applying this statement by the Company was immaterial.

The Company identified legal retirement obligations for nuclear decommissioning, wet and dry ash landfills and offshore and minor lateral pipeline facilities. On January 1, 2003, the Company recorded $289.3 million of asset retirement obligation ("ARO") liabilities; $13.9 million of ARO assets, net of accumulated depreciation; $114.6 million of regulatory assets; and reclassified $1.0 million of accumulated depreciation to the ARO liability. The initial ARO liability recognized includes $266.5 million that pertains to obligations associated with the decommissioning of the Quad Cities nuclear station. The $266.5 million includes a $159.8 million nuclear decommissioning liability that had been recorded at December 31, 2002. The adoption of this statement did not have a material impact on the operations of the regulated entities, as the effects were offset by the establishment of regulatory assets, totaling $114.6 million, pursuant to SFAS 71, "Accounting for the Effects of Certain Types of Regulation".

During the year ended December 31, 2003, the Company recorded, as a regulatory asset and as accretion expense, accretion related to the ARO liability of $16.5 million and $0.1 million, respectively. In addition, as the result of a decommissioning study, the Company reduced its ARO liability associated with the decommissioning of the Quad Cities nuclear station by $21.9 million. As a result, the ARO liability balance is $284.0 million at December 31, 2003.

On April 30, 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" ("SFAS 149"). SFAS 149 amends SFAS No. 133 for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. SFAS 149 requires contracts with comparable characteristics to be accounted for similarly. In

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particular, SFAS 149 clarifies when a contract with an initial net investment meets the characteristic of a derivative and clarifies when a derivative that contains a financing component will require special reporting in the statement of cash flows. SFAS 149 is effective for the Company for contracts entered into or modified after June 30, 2003. The adoption of SFAS 149 did not have a material effect on the Company's financial position, results of operations or cash flows.

In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" ("SFAS 150"). SFAS 150 established standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). The standard is effective for the Company for fiscal periods beginning after December 15, 2003. The adoption of SFAS 150 is not expected to have a material effect on the Company's financial position, results of operations or cash flows.

In December 2003, the FASB issued FASB Interpretation No. 46R which served to clarify guidance in Financial Interpretation No. 46 ("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 sheet as of December 31, 2003. In addition, the associated amounts previously recorded in minority interest and preferred dividends are now recorded as interest expense in the accompanying consolidated statement of operations. For the period from October 1, 2003 to December 31, 2003 the Company has recorded $49.8 million 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 Company will adopt the provisions of FIN 46R related to non-special purpose entities in the first quarter of 2004, in accordance with the provisions of FIN 46R. The Company is currently evaluating the impact of FIN 46R on several operating joint ventures that the Company currently does not consolidate.

3.    Acquisitions

Kern River

On March 27, 2002, the Company acquired Kern River. At the date of acquisition, Kern River owned a 926-mile interstate pipeline transporting Rocky Mountain and Canadian natural gas to markets in California, Nevada and Utah.

The Company paid $419.7 million, net of cash acquired and a working capital adjustment, for Kern River's gas pipeline business. The acquisition has been accounted for as a purchase business combination. The Company completed the allocation of the purchase price to the assets and liabilities acquired during the first quarter of 2003. The results of operations for Kern River are included in the Company's results beginning March 27, 2002.

The recognition of goodwill resulted from various attributes of Kern River's operations and business in general. These attributes include, but are not limited to:

•	Opportunities for expansion;

•	Generally high credit quality shippers contracting with Kern River;

•	Kern River's strong competitive position;

•	Exceptional operating track record and state-of-the-art technology;

•	Strong demand for gas in the Western markets; and

•	An ample supply of low-cost gas.

There is no assurance that these attributes will continue to exist to the same degree as believed at the time of the acquisition.

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In connection with the acquisition of Kern River, MEHC issued $323.0 million of 11% Company-obligated mandatorily redeemable preferred securities of a subsidiary trust due March 12, 2012 with scheduled principal payments beginning in 2005 and $127.0 million of no par, zero coupon convertible preferred stock to Berkshire Hathaway. Each share of preferred stock is convertible at the option of the holder into one share of the Company's common stock subject to certain adjustments as described in the MEHC's Amended and Restated Articles of Incorporation.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition (in millions):

Cash				$	7.7
Properties, plants and equipment					796.8
Goodwill					33.9
Other assets					171.7
Total assets acquired					1,010.1
Current liabilities					(104.3	)
Long-term debt					(482.0	)
Other liabilities					(1.5	)
Total liabilities assumed					(587.8	)
Net assets acquired				$	422.3

Northern Natural Gas Company

On August 16, 2002, the Company acquired Northern Natural Gas from Dynegy Inc. Northern Natural Gas is a 16,500-mile interstate pipeline extending from southwest Texas to the upper Midwest region of the United States.

The Company paid $882.7 million for Northern Natural Gas, net of cash acquired and a working capital adjustment. The acquisition has been accounted for as a purchase business combination. The Company completed the allocation of the purchase price to the assets and liabilities acquired during the third quarter of 2003. The results of operations for Northern Natural Gas are included in the Company's results beginning August 16, 2002.

The recognition of goodwill resulted from various attributes of Northern Natural Gas' operations and business in general. These attributes include, but are not limited to:

•	Generally high credit quality shippers contracting with Northern Natural Gas;

•	Northern Natural Gas' strong competitive position;

•	Strategic location in the high demand Upper Midwest markets;

•	Flexible access to an ample supply of low-cost gas;

•	Exceptional operating track record; and

•	Opportunities for expansion.

There is no assurance that these attributes will continue to exist to the same degree as believed at the time of the acquisition.

In connection with the acquisition of Northern Natural Gas, MEHC issued $950.0 million of 11% Company-obligated mandatorily redeemable preferred securities of a subsidiary trust due August 31, 2011, with scheduled principal payments beginning in 2003, to Berkshire Hathaway.

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The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition (in millions):

Cash				$	1.4
Properties, plants and equipment					1,294.3
Goodwill					416.3
Other assets					340.4
Total assets acquired					2,052.4
Current portion of long-term debt					(450.0	)
Other current liabilities					(195.3	)
Long-term debt					(499.8	)
Other liabilities					(28.2	)
Total liabilities assumed					(1,173.3	)
Net assets acquired				$	879.1

The following pro forma financial information of the Company represents the unaudited pro forma results of operations as if the Kern River and Northern Natural Gas acquisitions, and the related financings, had occurred at the beginning of each period. These pro forma results have been prepared for comparative purposes only and do not profess to be indicative of the results of operations which would have been achieved had these transactions been completed at the beginning of each year, nor are the results indicative of the Company's future results of operations (in millions):

				Year Ended December 31,
				2002				2001
Revenue				$	5,299.4			$	5,688.5
Income before cumulative effect of change in accounting principle					285.5				36.9
Net income available to common and preferred shareholders					285.5				32.3

HomeServices' Acquisitions

In 2003, HomeServices separately acquired four real estate companies for an aggregate purchase price of approximately $36.7 million net of cash plus working capital and certain other adjustments. For the year ended December 31, 2002, these real estate companies had combined revenue of approximately $102.9 million on 16,000 closed sides representing $3.6 billion of sales volume. Additionally, HomeServices is obligated to pay a maximum earnout of $5.2 million based on 2004 and 2005 financial performance measures. These purchases were financed using HomeServices' internally generated cash flows and revolving credit facility. In 2002, HomeServices separately acquired three real estate companies for an aggregate purchase price of approximately $106.1 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2001, these real estate companies had combined revenue of approximately $356.0 million on 42,000 closed sides representing $13.7 billion of sales volume. Additionally in 2003, HomeServices paid an earnout of $17.3 million based on 2002 financial performance measures. These purchases were financed using HomeServices' internally generated cash flows, revolving credit facility and $40.0 million from MEHC, which was contributed to HomeServices as equity.

Yorkshire Swap

On September 21, 2001, CE Electric UK Ltd, an indirect wholly owned subsidiary of MEHC, and Innogy Holdings plc ("Innogy") executed an agreement to exchange Northern Electric's electricity and gas supply and metering assets for Innogy's 94.75% interest in Yorkshire's electricity distribution business. Northern Electric's supply business was valued at approximately $391.0 million (£268.0 million), including working capital of approximately $14.0 million (£10.0 million). 94.75% of Yorkshire's distribution business was valued at approximately $405.0 million (£278.0 million), including working capital of approximately $58.0 million (£40.0 million). The net cash paid by Northern Electric for the exchange was approximately $14.0 million (£10.0 million).

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The 2001 disposition of Northern Electric's supply business created a pre-tax non-recurring gain of $196.7 million and an after-tax gain of $10.8 million which included a write-off of non-deductible goodwill of $504.4 million.

The Company paid $57.4 million, net of cash acquired of $353.8 million and transaction costs, for 94.75% of the Yorkshire electricity distribution business and related indebtedness. The acquisition has been accounted for as a purchase business combination. The results of operations for Yorkshire are included in the Company's results beginning September 21, 2001.

4.    Dispositions and Other Items

CE Gas Asset Sale

In May 2002, CE Gas, an indirect wholly owned subsidiary of the Company, executed the sale of several of its U.K. natural gas assets to Gaz de France for approximately $200.0 million (£137.0 million). CE Gas sold its interest in four natural gas-producing fields located in the southern basin of the U.K. North Sea (Anglia, Johnston, Schooner and Windermere). The transaction also included the sale of rights in four gas fields (in development/construction) and three exploration blocks owned by CE Gas. The Company recorded pre-tax and after-tax income of $54.3 million and $41.3 million, respectively, which includes a write off of non-deductible goodwill of $49.6 million.

Telephone Flat Sale

On October 16, 2001, the Company closed on a transaction that transferred all properties and rights of the Telephone Flat Project, a geothermal development project in northern California to Calpine Corp. The Company recorded a pre-tax gain of $20.7 million and an after-tax gain of $12.2 million on the sale of the Telephone Flat Project.

Western States Sale

On June 30, 2001, the Company closed on a transaction in which the Company sold Western States Geothermal, an indirect wholly owned subsidiary of the Company, to Ormat. The Company recorded a pre-tax gain of $9.8 million and an after-tax gain of $6.4 million on the sale of Western States Geothermal.

Teesside Power Limited ("TPL")

In December 2001, the Company recorded a charge of $20.7 million, net of tax, representing an asset valuation impairment charge under SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets" ("SFAS 121") relating to the Company's 15.4% interest in TPL. TPL owns and operates a 1,875 MW combined cycle gas-fired power plant. Enron Corp. ("Enron"), through its subsidiaries, owned a 42.5% interest, operated the plant, and purchased 668 MW of capacity. Enron's subsidiary, which owns and operates TPL, is now in administration and administrators have been appointed to run its business and are attempting to find a buyer.

Shareholders in TPL had previously utilized TPL's taxable losses with an obligation to reimburse TPL later in the project's life. In May 2002, TPL executed a restructuring and stabilization agreement with its lenders. The contract included an agreement between TPL and its shareholders with respect to the waiver of these repayment obligations. In May 2002, TPL released $35.7 million due to the repayment obligation being waived which is reflected as a tax benefit in the provision for income taxes.

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5.    Properties, Plants and Equipment, Net

Properties, plants and equipment, net comprise the following at December 31 (in thousands):

				Depreciation Life				2003				2002
Utility generation and distribution system					10-50			$	9,154,054			$	8,165,140
Interstate pipelines' assets					3-87				3,483,672				2,260,799
Independent power plants					10-30				1,395,782				1,410,170
Mineral and gas reserves and exploration assets					5-30				554,780				500,422
Utility non-operational assets					3-30				429,228				370,811
Other assets					3-10				146,286				131,577
Total operating assets									15,163,802				12,838,919
Accumulated depreciation and amortization									(4,260,643	)			(4,110,608	)
Net operating assets									10,903,159				8,728,311
Construction in progress									277,820				1,170,485
Properties, plants and equipment, net								$	11,180,979			$	9,898,796

Construction in Progress

MidAmerican Energy is constructing two 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 the actual costs do not exceed an agreed upon cap that MidAmerican Energy has deemed to be reasonable. Wholesale sales may also be made from the projects to the extent the power is not needed for regulated retail service.

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 will continue to be operated in simple cycle mode during 2004, resulted in 327 MW of accredited capacity in the summer of 2003. The combined cycle operation is expected to commence in 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 that approves the ratemaking principles for the plant, and on June 27, 2003, MidAmerican Energy received a certificate from the IUB allowing MidAmerican Energy to construct the plant. On February 12, 2003, MidAmerican Energy executed a contract with Mitsui & Co. Energy Development, Inc. for the engineering, procurement and construction of the plant. On September 9, 2003, MidAmerican Energy began construction of the plant, which it expects to be completed in the summer of 2007. MidAmerican Energy is also seeking an order from the IUB approving construction of the associated transmission facilities.

Kern River completed the construction of its expansion for which it filed an application with the Federal Energy Regulatory Commission on August 1, 2001 (the "2003 Expansion Project") at a total cost of approximately $1.2 billion. The expansion, which was placed into operation on May 1, 2003, increased the design capacity of the existing Kern River pipeline by 885,626 Dth per day to 1,755,626 Dth per day.

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6.    Investment in CE Generation

Since the sale of 50% of its interests in CE Generation, LLC ("CE Generation") on March 3, 1999, the Company has accounted for CE Generation as an equity investment. The equity investment in CE Generation at December 31, 2003 and 2002 was approximately $209.3 million and $244.9 million, respectively. The following is summarized financial information for CE Generation as of and for the years ended December 31 (in thousands):

				2003				2002				2001
Revenue				$	487,422			$	510,082			$	565,838
Income before cumulative effect of change in accounting principle					37,341				58,314				74,194
Net income					34,874				58,314				58,808
Current assets					124,168				202,490
Total assets					1,708,742				1,865,036
Current liabilities					253,240				148,685
Long-term debt, including current portion					924,563				1,011,220

7.    Other Investments

The Williams Companies' Preferred Stock

On March 27, 2002, the Company invested $275.0 million in The Williams Companies, Inc. ("Williams") in exchange for shares of 9 7/8% cumulative convertible preferred stock of Williams. Dividends on Williams preferred stock were received quarterly, commencing July 1, 2002. On June 10, 2003, Williams repurchased, for approximately $288.8 million, plus accrued dividends, all of the shares of its 9-7/8% Cumulative Convertible Preferred Stock originally acquired by the Company in March 2002 for $275.0 million The Company recorded a pre-tax gain of $13.8 million on the transaction.

CE Casecnan NIA Arbitration Settlement

On October 15, 2003, CE Casecnan Water and Energy Company, Inc. ("CE Casecnan") closed a transaction settling the CE Casecnan NIA Arbitration, which arose from a Statement of Claim made by CE Casecnan, on August 19, 2002, against the Republic of the Philippines ("ROP") National Irrigation Administration ("NIA"). As a result of the agreement, CE Casecnan recorded $31.9 million of other income and $24.4 million of associated income taxes. Under the terms of the settlement, CE Casecnan entered into an agreement with NIA which provided for the dismissal with prejudice of all claims by CE Casecnan and counterclaims by NIA in the NIA Arbitration. In connection with the settlement, NIA delivered to CE Casecnan a ROP $97.0 million 8.375% Note due 2013 (the "ROP Note"), which contained a put provision granting CE Casecnan the right to put the ROP Note to the ROP for a price of par plus accrued interest for a 30-day period commencing on January 14, 2004. The ROP Note is included in the other current assets on the December 31, 2003 consolidated balance sheet.

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, CE Casecnan received $99.2 million (representing $97.0 million par value plus accrued interest) from the ROP on January 21, 2004.

8.    Short-Term Debt

Short-term debt comprises the following at December 31 (in thousands):

				2003				2002
MidAmerican Energy commercial paper				$	48,000			$	55,000
HomeServices revolving credit facilities					—				24,750
Other					36				32
Total short-term debt				$	48,036			$	79,782

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Parent Company Revolving Credit Facilities

In the second quarter of 2003, the Company terminated its $400 million credit facility. On June 6, 2003, the Company closed on a new $100 million revolving credit facility which expires on June 6, 2006. The facility supports letters of credit of which $73.6 million were outstanding at December 31, 2003. No borrowings were outstanding at December 31, 2003 or 2002. The facility carries a variable interest rate based on Libor and ranged from 2.02% to 2.255% in 2003 and the prior facility ranged from 2.625% to 2.8625% in 2002.

MidAmerican Energy Short-Term Debt

As of December 31, 2003, MidAmerican Energy had in place a $370.4 million revolving credit facility that supports its $250.0 million commercial paper program and its variable rate pollution control revenue obligations. In addition, MidAmerican Energy has a $5.0 million line of credit. As of December 31, 2003 and 2002, commercial paper totaled $48.0 million and $55.0 million, respectively, for MidAmerican Energy. MHC Inc., an indirect wholly owned subsidiary of the Company, has a $4.0 million line of credit under which no borrowings were outstanding at December 31, 2003 or 2002. The commercial paper, bank notes and outstanding line of credit had a weighted average interest rate of 0.98% and 1.29% at December 31, 2003 and 2002, respectively.

HomeServices Revolving Credit Facilities

Upon the expiration of its $65.0 million senior secured revolving credit facility in November 2002, HomeServices entered into a new $125.0 million senior secured revolving credit agreement. The new revolving credit agreement has a term of three years and is secured by a pledge of the capital stock of all of the existing and future subsidiaries of HomeServices. Amounts outstanding under this revolving credit facility bear interest, at HomeServices' option, at either the prime lending rate or LIBOR plus a fixed spread of 1.25% to 2.25%, which varies based on HomeServices' cash flow leverage ratio. The spread was 1.25% at December 31, 2003 and 2002. No borrowings were outstanding at December 31, 2003 and $24.8 million was outstanding with a weighted average interest rate of 2.6661% at December 31, 2002.

9.    Parent Company Senior Debt

Parent company senior debt is unsecured senior obligations of MEHC and comprises the following at December 31 (in thousands):

				2003				2002
6.96% Senior Notes, due 2003				$	—			$	215,000
7.23% Senior Notes, due 2005					260,000				260,000
4.625% Senior Notes, due 2007					199,225				199,044
7.63% Senior Notes, due 2007					350,000				350,000
3.50% Senior Notes, due 2008					449,373				—
7.52% Senior Notes, due 2008					450,000				450,000
7.52% Senior Notes, due 2008 (Series B)					101,267				101,481
5.875% Senior Notes, due 2012					499,898				499,887
8.48% Senior Notes, due 2028					475,000				475,000
Fair value adjustments and other					(6,885	)			(12,025	)
Total Parent Company Senior Debt					2,777,878				2,538,387
Less current portion					—				(215,000	)
Total Long-Term Parent Company Senior Debt				$	2,777,878			$	2,323,387

On May 16, 2003, MEHC issued $450.0 million, net of discount, of its 3.5% Senior Notes with a final maturity on May 15, 2008. The proceeds were used for general corporate purposes. On September 15, 2003, MEHC repaid its $215.0 million, 6.96% Senior Notes.

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10.	Parent Company Subordinated Debt/Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts

Deconsolidation

In accordance with the provisions of FIN 46R, effective as of October 1, 2003, the Company has recorded its subordinated debt to certain subsidiary finance trusts as long-term debt as a result of the deconsolidation of those trusts pursuant to FIN 46R. In prior years, these amounts were recorded on the consolidated balance sheet as "Company-obligated mandatorily redeemable preferred securities of subsidiary trusts".

The financial terms of MEHC's various subordinated debentures held by such Trusts are essentially identical to the corresponding terms of the trust preferred securities issued by such trusts. The following summarizes the terms and balances of the mandatorily redeemable preferred securities of these unconsolidated trusts.

Finance Trust Subsidiaries

MEHC has organized special purpose Delaware business trusts (collectively, the "Trusts") pursuant to their respective amended and restated declarations of trusts (collectively, the "Declarations").

Pursuant to Preferred Securities Guarantee Agreements (collectively, the "Guarantees"), between MEHC and a trustee, MEHC has agreed irrevocably to pay to the holders of the Trust Securities, to the extent that the applicable Trust has funds available to make such payments, quarterly distributions, redemption payments and liquidation payments on the Trust Securities. Considered together, the undertakings contained in the Declarations, Junior Debentures, Indentures and Guarantees constitute full and unconditional guarantees on a subordinated basis by MEHC of the Trusts' obligations under the Trust Securities.

The balances presented for December 31, 2003 are recorded in the accompanying consolidated balance sheet as "Parent company subordinated debt". The balances presented for December 31, 2002 are recorded in the accompanying consolidated balance sheet as "Company-obligated mandatorily redeemable preferred securities of subsidiary trusts". The following table presents the balances of such Parent company subordinated debt and Company-obligated mandatorily redeemable preferred securities of subsidiary trusts, respectively (in thousands):

				2003				2002
CalEnergy Capital Trust II — 6.25% preferred securities, due 2012				$	104,645			$	155,538
CalEnergy Capital Trust III — 6.5% preferred securities, due 2027					269,980				269,980
MidAmerican Capital Trust I — 11% preferred securities, due 2010					454,772				454,772
MidAmerican Capital Trust II — 11% preferred securities, due 2012					323,000				323,000
MidAmerican Capital Trust III — 11% preferred securities, due 2012					800,000				950,000
Fair value adjustment					(80,251	)			(89,878	)
Total Parent company subordinated debt (2003)/Company-obligated mandatorily redeemable preferred securities of subsidiary trusts (2002)					1,872,146				2,063,412
Less current portion					(100,000	)			—
Long-term Parent company subordinated debt (2003)/Company- obligated mandatorily redeemable preferred securities of subsidiary trusts (2002)				$	1,772,146			$	2,063,412

Dividends related to the company-obligated mandatorily redeemable preferred securities of subsidiary trusts, which were included in minority interest and preferred dividends on the consolidated statements of operations, for the years ended December 31, 2003, 2002 and 2001 were $170.2 million, $147.7 million and $80.1 million, respectively. For the year ended December 31, 2003 an additional $49.8 million, representing the amount of interest on parent company subordinated debt since the adoption of FIN 46R, was recorded as interest expense in the accompanying consolidated statements of operations.

MEHC owns all of the common securities of the Trusts. The Trust Securities have a liquidation preference of $50 each (plus accrued and unpaid dividends thereon to the date of payment) and represent

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undivided beneficial ownership interests in each of the Trusts. The assets of the Trusts consist solely of Subordinated Debentures of MEHC (collectively, the "Junior Debentures") issued pursuant to their respective indentures. The indentures include agreements by MEHC to pay expenses and obligations incurred by the Trusts.

Prior to the Teton Transaction, each Trust Security issued by CalEnergy Capital Trust II and III with a par value of $50 was convertible at the option of the holder at any time into shares of MEHC's common stock based on a specified conversion rate. As a result of the Teton Transaction, in lieu of shares of MEHC's common stock, upon any conversion, holders of Trust Securities will receive $35.05 for each share of common stock it would have been entitled to receive on conversion.

Distributions on the Trust Securities (and Junior Debentures) are cumulative, accrue from the date of initial issuance and are payable quarterly in arrears. The Junior Debentures are subordinated in right of payment to all senior indebtedness of the Company and the Junior Debentures are subject to certain covenants, events of default and optional and mandatory redemption provisions, all as described in the Junior Debenture indentures.

The indentures relating to the CalEnergy Trusts II and III Trust Securities give MEHC the option to defer the interest payments due on the respective Junior Debentures for up to 20 consecutive quarters during which time the corresponding distributions on the respective Trust Securities are deferred (but continue to accumulate and accrue interest). Similarly, the indentures relating to the MidAmerican Capital Trust I, II and III Trust Securities give MEHC the option to defer the 11% interest payment on the respective Junior Debentures for up to 10 consecutive semi-annual periods during which time the corresponding 11% distributions on the respective Trust Securities are deferred (but continue to accumulate and accrue interest at the rate of 13% per annum). In addition, each declaration of trust establishing the MidAmerican Capital Trusts I, II and III Trust Securities and each of the related subscription agreements contains a provision prohibiting Berkshire Hathaway and its affiliates, who are the holders of all of the respective Trust Securities issued by such Trusts, from transferring such Trust Securities to a non-affiliated person absent an event of default.

11.    Subsidiary and Project Debt

Each of MEHC's direct and indirect subsidiaries is organized as a legal entity separate and apart from MEHC and its other subsidiaries. Pursuant to separate project financing agreements, all or substantially all of the assets of each subsidiary are or 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 such subsidiary will be available to satisfy the obligations of MEHC or any of its other such subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements of such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MEHC or affiliates thereof.

The restrictions on distributions at these separate legal entities include various covenants including, but not limited to, leverage ratios, interest coverage ratios and debt service coverage ratios. As of December 31, 2003, the separate legal entities were in compliance with all applicable covenants. However, Cordova Energy's 537 MW gas-fired power plant in the Quad Cities, Illinois area (the "Cordova Project") is currently prohibited from making distributions by the terms of its indenture due to its failure to meet its debt service coverage ratio requirement.

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Long-term debt of subsidiaries and projects comprise the following at December 31 (in thousands):

				2003				2002
MidAmerican Funding				$	700,000			$	700,000
MidAmerican Energy					1,128,647				1,053,418
CE Electric UK					2,467,214				2,573,589
Kern River					1,276,174				1,277,916
Northern Natural Gas					799,472				799,406
Cordova Funding					214,761				223,762
Salton Sea Funding Corporation					136,384				137,789
CE Casecnan					246,458				287,926
Leyte Projects					172,813				244,961
HomeServices					37,558				39,031
Other, including fair value adjustments					(3,900	)			(5,498	)
Total Subsidiary and Project Debt					7,175,581				7,332,300
Less current portion					(500,941	)			(255,213	)
Total Long-Term Subsidiary and Project Debt.				$	6,674,640			$	7,077,087

MidAmerican Funding

The components of MidAmerican Funding, a wholly owned subsidiary of MEHC, Senior Notes and Bonds comprise the following at December 31 (in thousands):

				2003				2002
6.339% Senior Notes, due 2009				$	175,000			$	175,000
6.75% Senior Notes, due 2011					200,000				200,000
6.927% Senior Bonds, due 2029					325,000				325,000
Total MidAmerican Funding				$	700,000			$	700,000

MidAmerican Funding may use distributions that it receives from its subsidiaries to make payments on the Notes and Bonds. These subsidiaries must make payments on their own indebtedness before making distributions to MidAmerican Funding. These distributions are also subject to utility regulatory restrictions agreed to by MidAmerican Energy in March 1999 whereby it committed to the Iowa Utilities Board ("IUB") to use commercially reasonable efforts to maintain an investment grade rating on its long-term debt and to maintain its common equity level above 42% of total capitalization unless circumstances beyond its control result in the common equity level decreasing to below 39% of total capitalization. MidAmerican Energy must seek the approval of the IUB of a reasonable utility capital structure if MidAmerican Energy's common equity level decreases below 42% of total capitalization, unless the decrease is beyond the control of MidAmerican Energy. MidAmerican Energy is also required to seek the approval of the IUB if MidAmerican Energy's equity level decreases to below 39%, even if the decrease is due to circumstances beyond the control of MidAmerican Energy.

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MidAmerican Energy

The components of MidAmerican Energy's Mortgage Bonds, Pollution Control Revenue Obligations and Notes comprise the following at December 31 (in thousands):

				2003				2002
Mortgage bonds:
7.125% Series, due 2003				$	—			$	100,000
7.7% Series, due 2004					55,630				55,630
7% Series, due 2005					90,500				90,500
7.375% Series, due 2008					—				75,000
7.45% Series, due 2023					—				6,940
6.95% Series, due 2025					—				12,500
Pollution control revenue obligations:
5.75% Series, due periodically through 2003					—				4,320
6.7% Series, due 2003					—				1,000
6.1% Series, due 2007					1,000				1,000
5.95% Series, due 2023					29,030				29,030
Variable rate series:
Due 2016 and 2017, 1.26% and 1.64%					37,600				37,600
Due 2023 (secured by general mortgage bond, 1.26% and 1.64%					28,295				28,295
Due 2023, 1.26% and 1.64%					6,850				6,850
Due 2024, 1.26% and 1.64%					34,900				34,900
Due 2025, 1.26% and 1.64%					12,750				12,750
Notes:
6.375% Series, due 2006					160,000				160,000
5.125% Series, due 2013					275,000				—
6.75% Series, due 2031					400,000				400,000
Obligations under capital lease					2,060				2,161
Unamortized debt premium and discount, net					(4,968	)			(5,058	)
Total MidAmerican Energy				$	1,128,647			$	1,053,418

On February 8, 2002, MidAmerican Energy issued $400 million of 6.75% notes due in 2031. The proceeds were used to refinance existing debt and preferred securities and for other corporate purposes. On March 11, 2002, MidAmerican Energy redeemed its MidAmerican Energy-obligated mandatorily redeemable preferred securities of subsidiary trust at 100% of the principal amount plus accrued interest.

On January 14, 2003, MidAmerican Energy issued $275 million of 5.125% medium-term notes due in 2013. The proceeds were used to refinance existing debt and for other corporate purposes.

On February 10, 2003, MidAmerican Energy redeemed all $75.0 million of its 7.375% series of mortgage bonds, and on March 17, 2003, it redeemed all $6.94 million of its 7.45% series of mortgage bonds. Additionally, MidAmerican Energy's 7.125% series of mortgage bonds totaling $100 million matured on February 3, 2003. On October 17, 2003, MidAmerican Energy redeemed all $12.5 million of its 6.95% series of mortgage bonds at 103.48% of the principal amount.

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CE Electric UK

The components of CE Electric UK and its subsidiares' long-term debt comprise the following at December 31 (in thousands):

				2003				2002
6.853% Senior Notes, due 2004				$	117,112			$	124,732
8.625% Bearer bonds, due 2005					178,877				161,451
6.995% Senior Notes, due 2007					236,174				236,081
6.496% Yankee Bonds, due 2008					281,149				300,185
Variable Rate Reset Trust Securities, due 2020 (4.39% and 5.04%)					287,539				260,028
8.875% Bearer bonds, due 2020					178,644				161,360
9.25% Eurobonds, due 2020					458,187				419,145
7.25% Sterling Bonds, due 2022					351,242				316,829
7.25% Eurobonds, due 2028					352,768				344,082
8.08% Trust Securities, due 2038					—				249,696
CE Gas Credit Facility, 6.67%					25,522				—
Total CE Electric UK				$	2,467,214			$	2,573,589

On February 15, 2005, the Variable Rate Reset Trust Securities may be remarketed at the option of the original underwriter at a fixed rate of interest through the maturity date or, CE Electric UK's subsidiary may elect a floating rate obligation for up to one year at which time the obligation would be remarketed at a fixed rate of interest through 2020, or redeemed by Yorkshire at a premium.

On June 9, 2003, Yorkshire Power Group Limited, an indirect wholly owned subsidiary of CE Electric UK, completed the redemption in full of the outstanding shares of the 8.08% Trust Securities, due June 30, 2038, and paid $243.4 million in principal amount plus accrued distributions. The redemption price was paid to holders of the trust security on the redemption date.

During 2003, CE Electric UK and its subsidiaries purchased and retired approximately $50.0 million of outstanding indebtedness.

Kern River

The components of Kern River's long-term debt comprised the following at December 31 (in thousands):

				2003				2002
Construction financing facility				$	—			$	789,916
6.676% Senior Notes, due 2016					464,000				488,000
4.893% Senior Notes, due 2018					812,174				—
Total Kern River				$	1,276,174			$	1,277,916

On August 13, 2001, Kern River issued $510.0 million in debt securities. The offering was in the form of $510.0 million of 15-year amortizing Senior Notes bearing a fixed rate of interest of 6.676%. For the Senior Notes, $405.0 million will be amortized through June 2016, with a final payment of $105.0 million to be made on July 31, 2016.

On May 1, 2003, Kern River Funding Corporation, a wholly owned subsidiary of Kern River, issued $836 million of its 4.893% Senior Notes with a final maturity on April 30, 2018. The proceeds were used to repay all of the approximately $815 million of outstanding borrowings under Kern River's $875 million credit facility. Kern River entered into this credit facility in 2002 to finance the construction of the 2003 Expansion Project. The credit facility was canceled and a completion guarantee issued by MEHC was terminated.

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Northern Natural Gas

The components of Northern Natural Gas' Senior Notes comprise the following at December 31 (in thousands):

				2003				2002
6.875% Senior Notes, due 2005				$	100,000			$	100,000
6.75% Senior Notes, due 2008					150,000				150,000
7.00% Senior Notes, due 2011					250,000				250,000
5.375% Senior Notes, due 2012					300,000				300,000
Unamortized debt discount					(528	)			(594	)
Total Northern Natural Gas				$	799,472			$	799,406

Cordova Funding

On September 10, 1999, Cordova Funding Corporation ("Cordova Funding"), a wholly owned subsidiary of the Company, closed the $225.0 million aggregate principal amount financing for the construction of the Cordova Project. The proceeds were loaned to Cordova Energy and comprise the following at December 31 (in thousands):

				2003				2002
8.48% Senior Secured Bonds, due 2019				$	12,175			$	12,685
8.64% Senior Secured Bonds, due 2019					89,260				93,001
8.79% Senior Secured Bonds, due 2019					29,885				31,137
8.82% Senior Secured Bonds, due 2019					55,476				57,801
9.07% Senior Secured Bonds, due 2019					27,965				29,138
Total Cordova Funding				$	214,761			$	223,762

MEHC has guaranteed a specified portion of the final scheduled principal payment on December 15, 2019 on the Cordova Funding Senior Secured Bonds in an amount up to a maximum of $37.0 million. MEHC also provides a debt service reserve guarantee in an amount equal to the principal, premium, if any, and interest payment due on the bonds on the next scheduled payment date which was equal to $13.5 million at December 31, 2003.

As of December 31, 2003, Cordova Funding is currently prohibited from making distributions by the terms of its indenture due to its failure to meet its debt service coverage ratio requirement.

Salton Sea Funding

Salton Sea Funding Corporation ("SSFC"), an indirect wholly owned subsidiary of CE Generation, had a debt balance of $463.6 million at December 31, 2003. CalEnergy Minerals LLC ("Minerals"), a wholly owned indirect subsidiary of MEHC, which owns a zinc facility, is one of several guarantors of the Salton Sea Funding Corporation's debt. As a result of a note allocation agreement, Minerals is primarily responsible for approximately $136.4 million of the 7.475% Senior Secured Series F Bonds due November 30, 2018 ("Series F Bonds"). In 1999, MEHC guaranteed a specified portion of the scheduled debt service on the Series F Bonds equal to this current principal amount of approximately $136.4 million and associated interest.

On January 30, 2004, SSFC announced its election to redeem an aggregate principal amount of $136.4 million of the 7.475% Senior Secured Series F Bonds due November 30, 2018, pro rata, at a redemption price of 100% of such aggregate outstanding principal amount, plus accrued interest to the date of redemption. The trustee delivered a redemption notice to the holders of the bonds on January 29, 2004. The record date for the redemption is February 15, 2004 and the redemption is expected to be completed on March 1, 2004. SSFC expects to make a demand on MEHC for the full amount remaining under MEHC's 1999 guarantee of the Series F Bonds in order to fund the redemption. Upon the expected demand and payment under MEHC's guarantee, MEHC will no longer have any liability with respect to its guarantee.

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CE Casecnan

On November 27, 1995, CE Casecnan issued $371.5 million of notes and bonds to finance the construction of the CE Casecnan project. The CE Casecnan notes and bonds comprise the following at December 31 (in thousands):

				2003				2002
11.45% Senior Secured Series A Notes, due in 2005				$	91,250			$	125,000
11.95% Senior Secured Series B Bonds, due in 2010					155,208				162,926
Total Casecnan				$	246,458			$	287,926

The CE Casecnan Notes and Bonds are subject to redemption at the Company's option as provided in the Trust Indenture. The CE Casecnan Notes and Bonds are also subject to mandatory redemption based on certain conditions.

Leyte Projects

The Leyte Projects term loans comprise the following at December 31 (in thousands):

				2003				2002
Mahanagdong Project 6.92% Term Loan, due 2007				$	72,151			$	92,766
Mahanagdong Project 7.60% Term Loan, due 2007					16,000				20,571
Malitbog Project 3.67% and 3.84%, due 2005					26,378				40,890
Malitbog Project 9.176% Term Loan, due 2006					14,628				22,677
Upper Mahiao Project 4.42%, due 2003					—				5,000
Upper Mahiao Project 5.95% Term Loan, due 2006					43,656				63,057
Total Leyte Projects				$	172,813			$	244,961

MEHC provides debt service reserve letters of credit in amounts equal to the next semi-annual principal and interest payments due on the loans which was equal to $40.3 million and $47.7 million at December 31, 2003 and 2002, respectively.

HomeServices

In November 1998, HomeServices issued $35.0 million of 7.12% fixed-rate private placement senior notes due in annual increments of $5.0 million beginning in 2004. As of December 31, 2003 and 2002, the balance of the HomeServices Senior Notes was $35.0 million.

In addition to the senior notes, HomeServices' has outstanding notes, with varying interest rates, totaling $2.6 million and $4.0 million at December 31, 2003 and 2002, respectively.

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Annual Repayments of Debt

The annual repayments of debt for the years beginning January 1, 2004 and thereafter are as follows (in thousands):

				2004				2005				2006				2007				2008				Thereafter				Total
Parent, Subsidiary and Project loans:
Parent Company Senior Debt				$	—			$	260,000			$	—			$	550,000			$	1,000,000			$	967,878			$	2,777,878
Parent Company Subordinated Debt					100,000				188,544				234,021				234,021				234,021				881,539				1,872,146
MidAmerican Funding					—				—				—				—				—				700,000				700,000
MidAmerican Energy					56,151				90,500				160,000				1,000				—				820,996				1,128,647
CE Electric UK					117,112				178,877				—				236,174				281,149				1,653,902				2,467,214
Kern River					61,366				62,784				66,128				69,472				72,816				943,608				1,276,174
Northern Natural Gas					—				100,000				—				—				150,000				549,472				799,472
Cordova Funding					8,100				7,875				4,500				4,163				4,725				185,398				214,761
Salton Sea Funding Corporation					136,384				—				—				—				—				—				136,384
CE Casecnan					49,360				54,752				36,016				37,730				37,730				30,870				246,458
Leyte Projects					67,148				63,035				30,037				12,593				—				—				172,813
HomeServices					5,320				5,000				5,000				5,000				5,000				12,238				37,558
Other, including fair value adjustments					—				—				—				—				—				(3,900	)			(3,900	)
Total Parent, Subsidiary and Project Loans				$	600,941			$	1,011,367			$	535,702			$	1,150,153			$	1,785,441			$	6,742,001			$	11,825,605

Fair Value

At December 31, 2003, the Company had fixed-rate long-term debt of $11,369.4 million in principal amount and having a fair value of $12,015.1 million. In addition, at December 31, 2003, the Company had floating-rate obligations of $459.8 million that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates.

12.    Income Taxes

Provision for income taxes was comprised of the following (in thousands):

				Year Ended December 31,
				2003				2002				2001
Current:
Federal				$	(78,066	)		$	46,714			$	51,025
State					3,565				14,516				2,669
Foreign					88,150				54,586				43,450
					13,649				115,816				97,144
Deferred:
Federal					155,237				(7,073	)			(14,004	)
State					14,577				(9,675	)			(342	)
Foreign					67,508				520				167,266
					237,322				(16,228	)			152,920
Total				$	250,971			$	99,588			$	250,064

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A reconciliation of the federal statutory tax rate to the effective tax rate applicable to income before provision for income taxes follows:

				2003				2002				2001
Federal statutory rate					35.0	%			35.0	%			35.0	%
Investment and energy tax credits					(0.5	)			(0.7	)			(1.0	)
State taxes, net of federal tax effect					1.4				1.2				3.2
Goodwill amortization					—				—				5.9
Dividends on preferred securities of subsidiary trusts					(7.0	)			(8.1	)			(6.1	)
Tax effect of foreign income					0.5				(4.8	)			(2.5	)
Non-recurring items on CE Electric UK,
net of tax effect of foreign income					(0.5	)			(8.1	)			19.2
Dividends received deduction					(1.2	)			(1.8	)			(2.6	)
Other items, net					1.8				2.8				(1.5	)
Effective tax rate					29.5	%			15.5	%			49.6	%

The Internal Revenue Service ("IRS") regularly examines the Company's federal income tax returns and, in the course of which, may propose adjustments to the Company's federal income tax liability reported on such returns. Tax years 1995 through 2001 are currently under review. The Company's management does not expect that the outcome of any proposed adjustments presented to date by the IRS, individually or collectively, will have a material adverse effect on the Company's financial position, results of operations, or cash flows.

Deferred tax liabilities (assets) comprise the following at December 31 (in thousands):

				2003				2002
Properties, plants and equipment, net				$	1,721,842			$	1,325,228
Income taxes recoverable through future rates					142,597				159,411
Employee benefits					43,005				65,537
Reacquired debt					5,665				4,914
Fuel cost recoveries					12,864				—
Other					—				121
					1,925,973				1,555,211
Minimum pension liability adjustment					(147,279	)			(140,854	)
Revenue sharing accruals					(64,192	)			(48,861	)
Accruals not currently deductible for tax purposes					(37,672	)			(59,083	)
Nuclear reserve and decommissioning					(35,955	)			(28,411	)
Deferred income					(37,819	)			(21,733	)
Fuel cost recoveries					—				(9,558	)
NOL and credit carryforwards					(161,659	)			(8,290	)
Other					(8,253	)			—
					(492,829	)			(316,790	)
Net deferred income taxes				$	1,433,144			$	1,238,421

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13.    Preferred Securities of Subsidiaries

The total outstanding cumulative preferred securities of MidAmerican Energy not subject to mandatory redemption requirements may be redeemed at the option of MidAmerican Energy at prices which, in the aggregate, total $32.6 million. The aggregate total the holders of all preferred securities outstanding at December 31, 2003 and 2002, are entitled to upon involuntary bankruptcy is $31.8 million plus accrued dividends. Annual dividend requirements for all preferred securities outstanding at December 31, 2003, total $1.3 million.

The total outstanding 8.061% cumulative preferred securities of a subsidiary of CE Electric UK, which are redeemable in the event of the revocation by the Secretary of State of the Company's Public Electricity Supply License, was $56.0 million as of December 31, 2003 and 2002.

During 2002, MidAmerican Energy redeemed all $26.7 million of its $7.80 Series Preferred Shares.

14.    Convertible Preferred Stock

In connection with the Kern River acquisition and the purchase of $275.0 million of Williams' preferred stock, MEHC issued 6.7 million shares of no par, zero-coupon convertible preferred stock valued at $402.0 million to Berkshire Hathaway. In connection with the Teton Transaction, MEHC issued 34.6 million shares of no par, zero coupon convertible preferred stock valued at $1,211.4 million. Each share of preferred stock is convertible at the option of the holder into one share of MEHC's common stock subject to certain adjustments as described in MEHC's Amended and Restated Articles of Incorporation.

While the convertible preferred stock does not vote generally with the common stock in the election of directors, the convertible preferred stock gives Berkshire Hathaway the right to elect 20% of MEHC's Board of Directors. The convertible preferred stock is convertible into common stock only upon the occurrence of specified events, including modification or elimination of the Public Utility Holding Company Act of 1935 so that holding company registration would not be triggered by conversion. Additionally, the prior approval of the holders of convertible preferred stock is required for certain fundamental transactions by MEHC. Such transactions include, among others: (a) significant asset sales or dispositions; (b) merger transactions; (c) significant business acquisitions or capital expenditures; (d) issuances or repurchases of equity securities; and (e) the removal or appointment of the Chief Executive Officer.

MEHC's Articles of Incorporation further provide that the convertible preferred shares: (a) are not mandatorily redeemable by MEHC or at the option of the holder; (b) participate in dividends and other distributions to common shareholders as if they were common shares and otherwise possess no dividend rights; (c) are convertible into common shares on a 1 for 1 basis, as adjusted for splits, combinations, reclassifications and other capital changes by MEHC; and (d) upon liquidation, except for a de minimus first priority distribution of $1 per share, share ratably with the shareholders of common stock. Further, the aforementioned dividend and distribution arrangements cannot be modified without the positive consent of the preferred shareholders.

15.    Stock Transactions

As of December 31, 2003, there were 2,048,329 options outstanding which are exercisable until the end of the term on March 14, 2008 at exercise prices ranging from $15.94 to $35.05 per share.

On March 6, 2002, MEHC purchased 800,000 stock options held by Mr. David L. Sokol, its Chairman and Chief Executive Officer. The options purchased had exercise prices ranging from $18.50 to $29.01. MEHC paid Mr. Sokol an aggregate amount of $27.1 million, which is equal to the difference between the option exercise prices and an agreed upon per share value.

On January 6, 2004, the Company purchased a portion of the shares of common stock owned by Mr. Sokol for an aggregate purchase price of $20.0 million.

16.    Accounting for Derivatives

Currency Exchange Rate Risk

CE Electric UK entered into certain currency rate swap agreements for its Senior Notes with two large multi-national financial institutions. The swap agreements effectively convert the U.S. dollar fixed

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interest rate to a fixed rate in Sterling. For the $117.1 million of 6.853% Senior Notes outstanding at December 31, 2003, the agreements extend until maturity on December 30, 2004 and convert the U.S. dollar interest rate to a fixed Sterling rate of 7.744%. For the $236.2 million of 6.995% Senior Notes, the agreements extend until maturity on December 30, 2007 and convert the U.S. dollar interest rate to a fixed Sterling rate of 7.737%. The estimated fair value of these swap agreements at December 31, 2003 is approximately $16.0 million based on quotes from the counterparty to these instruments and represents the estimated amount that the Company would expect to pay if these agreements were terminated.

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 December 31, 2003, the agreements extend until February 25, 2008 and convert the U.S. dollar interest rate to a fixed Sterling rate ranging from 7.3175% to 7.345%. The estimated fair value of these swap agreements at December 31, 2003 is approximately $62.6 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.

17.    Regulatory Matters

MidAmerican Energy

Under two settlement agreements approved by the IUB, MidAmerican Energy's Iowa retail electric rates in effect on December 31, 2000, 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 are intended to keep MidAmerican Energy's overall Iowa retail electric revenue unchanged, but could result in changes to individual tariffs. 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. Future depreciation will be reduced as a result of the credit applied to generating plant balances as the regulatory liability is reduced. 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. Interest expense is accrued on the portion of the regulatory liability related to prior years.

The 2003 settlement agreement also provides that if Iowa retail electric returns on equity fall below 10% in any consecutive 12-month period after January 1, 2006, 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

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and a premium of 12.5% for 2005 and 2006. The two-year average above which sharing must occur for 2003 was 13.73%. The law allows MidAmerican Energy to mitigate the sharing of earnings above the threshold return on common equity through accelerated recovery of electric assets.

On November 8, 2002, the IUB approved a gas rate settlement agreement previously filed with it by MidAmerican Energy and the Iowa Office of Consumer Advocate. The settlement agreement provided for an increase in rates of $17.7 million annually for MidAmerican Energy's Iowa retail natural gas customers and effectively froze base rates through November 2004. However, MidAmerican Energy will continue collecting fluctuating gas costs through its purchased gas adjustment clause. The new rates were implemented for usage beginning November 25, 2002.

CE Electric UK

Most revenue of each Distribution License Holder ("DLH") is controlled by a distribution price control formula. The current formula requires that regulated distribution income per unit is increased or decreased each year by RPI-Xd where the Retail Price Index ("RPI") reflects the average of the 12-month inflation rates recorded for each month in the previous July to December period. The distribution price control formula also reflects an adjustment factor ("Xd") which was established by the regulatory body, the Office of Gas and Electricity Markets ("Ofgem"), at the last price control review (and continues to be set) at 3%. The formula also takes account of the changes in system electrical losses, the number of customers connected and the voltage at which customers receive the units of electricity distributed. This formula determines the maximum average price per unit of electricity distributed (in pence per 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.

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 filing provides evidence in support of a $71 million increase to Northern Natural Gas' annual revenue requirement. However, Northern Natural Gas is requesting that only $55 million of this increase be effectuated. Northern Natural Gas' new rates went into effect November 1, 2003, subject to refund. Additionally, Northern Natural Gas filed on January 30, 2004 with the FERC to increase its revenue requirement by an incremental $30 million to that requested in the May 1, 2003 filing. Northern Natural Gas requested that the new rates be effective commencing August 1, 2004. Northern Natural Gas has filed to consolidate the two rate proceedings, but the FERC has not yet ruled on Northern Natural Gas' motion.

18.    Pension Commitments

Domestic Operations

MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering MEHC and its domestic energy subsidiaries. Benefit obligations under the plans are based on participants' compensation, years of service and age at retirement. Funding to an external trust is based upon the actuarially determined costs of the plans and the requirements of the Internal Revenue Code and the Employee Retirement Income Security Act. The Company also maintains noncontributory, nonqualified supplemental executive retirement plans for active and retired participants.

MidAmerican Energy also currently sponsors certain postretirement health care and life insurance benefits covering all retired domestic employees of MEHC and its domestic energy subsidiaries. Under the plan, substantially all of MEHC's and its domestic energy subsidiaries' employees may become eligible for these benefits if they reach retirement age while working for the Company. However, the Company retains the right to change these benefits anytime at its discretion, subject to provisions in the union contract.

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Net periodic pension, supplemental retirement and postretirement benefit costs included the following components for the Company and the aforementioned affiliates for the years ended December 31. For purposes of calculating the expected return on pension plan assets, a market-related value is used. Market-related value is equal to fair value except for gains and losses on equity investments which are amortized into market-related value on a straight-line basis over five years.

Components of net periodic benefit cost (in thousands):

				Pension Cost												Postretirement Cost
				2003				2002				2001				2003				2002				2001
Service cost				$	24,693			$	20,235			$	18,114			$	8,175			$	6,028			$	4,357
Interest cost					34,533				34,177				33,027				16,065				13,928				10,418
Expected return on plan assets					(38,396	)			(38,213	)			(36,326	)			(6,008	)			(4,880	)			(4,032	)
Amortization of net transition obligation					(2,591	)			(2,591	)			(2,591	)			4,110				4,110				4,110
Amortization of prior service cost					2,761				2,729				2,729				593				425				425
Amortization of prior year (gain) loss					1,483				(2,482	)			(3,894	)			3,716				2,385				332
Regulatory expense					3,320				6,639				—				—				—				—
Net periodic cost				$	25,803			$	20,494			$	11,059			$	26,651			$	21,996			$	15,610

Weighted-average assumptions used to determine benefit obligations at December 31:

				2003				2002				2001				2003				2002				2001
Discount rate					5.75	%			5.75	%			6.50	%			5.75	%			5.75	%			6.50	%
Rate of compensation increase					5.00	%			5.00	%			5.00	%

Weighted-average assumptions used to determine net benefit cost for years ended December 31:

				2003				2002				2001				2003				2002				2001
Discount rate					5.75	%			6.50	%			7.00	%			5.75	%			6.50	%			7.00	%
Expected return on plan assets					7.00	%			7.00	%			7.00	%			7.00	%			7.00	%			7.00	%
Rate of compensation increase					5.00	%			5.00	%			5.00	%

Assumed health care cost trend rates at December 31:

				2003				2002
Health care cost trend rate assumed for next year					11.00	%			9.75	%
Rate that the cost trend rate gradually declines to					5.00	%			5.25	%
Year that the rate reaches the rate it is assumed to remain at					2010				2006

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Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects in thousands:

				One Percentage-Point Increase				One Percentage-Point Decrease
Effect on total service and interest cost				$	5,484			$	(4,136	)
Effect on postretirement benefit obligation				$	47,583			$	(37,761	)

The following table presents a reconciliation of the beginning and ending balances of the benefit obligation, fair value of plan assets and the funded status of the aforementioned plans to the net amounts measured and recognized in the Consolidated Balance Sheets as of December 31(in thousands):

				Pension Benefits								Postretirement Benefits
				2003				2002				2003				2002
Reconciliation of the fair value of plan assets:
Fair value of plan assets at beginning of year				$	467,773			$	515,890			$	122,655			$	81,129
Employer contributions					5,044				4,681				32,566				24,034
Participant contributions					—				—				6,371				4,505
Actual return on plan assets					105,438				(27,376	)			15,853				(4,528	)
Acquisition					—				—				—				32,500
Benefits paid					(26,687	)			(25,422	)			(19,596	)			(14,985	)
Fair value of plan assets at end of year				$	551,568			$	467,773			$	157,849			$	122,655
Reconciliation of benefit obligation:
Benefit obligation at beginning of year				$	593,179			$	518,208			$	291,441			$	194,917
Service cost					24,693				20,235				8,175				6,028
Interest cost					34,533				34,177				16,065				13,928
Participant contributions					—				—				6,371				4,505
Plan amendments					—				520				—				2,205
Actuarial (gain) loss					(5,670	)			45,461				(5,023	)			31,743
Acquisition					—				—				—				53,100
Benefits paid					(26,687	)			(25,422	)			(19,596	)			(14,985	)
Benefit obligation at end of year				$	620,048			$	593,179			$	297,433			$	291,441
Funded status				$	(68,480	)		$	(125,406	)		$	(139,584	)		$	(168,786	)
Amounts not recognized:
Unrecognized net (gain) loss					(12,907	)			61,289				83,509				102,095
Unrecognized prior service cost					17,915				20,676				5,451				6,043
Unrecognized net transition obligation (asset)					(792	)			(3,383	)			36,992				41,102
Net amount recognized in the Consolidated Balance Sheets				$	(64,264	)		$	(46,824	)		$	(13,632	)		$	(19,546	)
Amounts recognized in the Consolidated Balance Sheets consist of
Prepaid benefit cost				$	39			$	11,825			$	—			$	1,493
Accrued benefit liability					(100,490	)			(99,392	)			(13,632	)			(21,039	)
Intangible assets					17,367				20,082				—				—
Regulatory assets					18,820				20,661				—				—
Net amount recognized				$	(64,264	)		$	(46,824	)		$	(13,632	)		$	(19,546	)

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The accumulated benefit obligation for all defined benefit pension plans was $554.6 million and $526.7 million at December 31, 2003 and 2002, respectively. The projected benefit obligation (included in the table above), accumulated benefit obligation and fair value of plan assets for the supplemental executive retirement plan which had an accumulated benefit obligation in excess of plan assets were $105.1 million, $100.5 million and $ — as of December 31, 2003 and $103.4 million, $99.1 million and $ — as of December 31, 2002, respectively. A minimum liability must be recognized for those plans whose accumulated benefit obligation exceeds plan assets.

Although the supplemental executive retirement plan had no assets as of December 31, 2003, the Company has Rabbi trusts that hold corporate-owned life insurance and other investments to provide funding for the future cash requirements. Because this plan is nonqualified, the fair value of these assets is not included in the plan asset table below. The fair value of the Rabbi trust investments was $88.1 million and $76.2 million at December 31, 2003 and 2002, respectively.

Plan Assets

The Company's investment policy for its domestic pension and postretirement plans is to balance risk and return through a diversified portfolio of high-quality equity and fixed income securities. Equity targets for the pension and postretirement plans are as indicated in the tables below. Maturities for fixed income securities are managed such that sufficient liquidity exists to meet near-term benefit payment obligations. The plans retain outside investment advisors to manage plan investments within the parameters outlined by the Company's Pension Benefits Committee. The weighted average return on assets assumption is based on historical performance for the types of assets in which the plans invest.

The Company's pension plan asset allocation at December 31, 2003 and 2002, are as follows:

				Percentage of Plan Assets
				at December 31								Target Range
Asset Category				2003				2002
Equity securities					70	%			60	%			65-75	%
Debt securities					23				33				20-30
Real estate					7				7				0-10
Other					—				—				0-5
Total					100	%			100	%

The Company's postretirement benefit plan asset allocation at December 31, 2003, and 2002, are as follows:

				Percentage of Plan Assets
				at December 31								Target Range
Asset Category				2003				2002
Equity securities					49	%			34	%			45-55	%
Debt securities					48				48				45-55
Other					3				18				0-10
Total					100	%			100	%

Cash Flows

Employer contributions to the domestic pension and postretirement plans are currently expected to be $5.1 million and $27.6 million, respectively, for 2004 based on current regulations which are subject to change. The Company's policy is to contribute the minimum required amount to the pension plan and the amount expensed to its postretirement plans.

The Company sponsors defined contribution pension plans (401(k) plans) covering substantially all domestic employees. The Company's contributions vary depending on the plan but are based primarily on each participant's level of contribution and cannot exceed the maximum allowable for tax purposes. Total contributions were $12.4 million, $9.8 million and $8.6 million for 2003, 2002 and 2001, respectively.

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In December 2003, the President signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 ("Medicare Act"). The Medicare Act introduces a prescription drug benefit under Medicare as well as a subsidy to sponsors of retiree health care plans that provide a benefit to participants that is at least actuarially equivalent to Medicare Part D. The Medicare Act is expected to ultimately reduce the Company's postretirement costs from what they would have been absent such changes. Detailed regulations pertaining to the Medicare Act have yet to be promulgated, and accordingly, the Company cannot determine precisely how it will implement the Medicare Act's provisions. Additionally, accounting guidance regarding the recognition of the impacts of the Medicare Act is pending. Accordingly, the Company continues to evaluate its options and cannot predict the magnitude or timing of any resulting costs savings. As permitted by FASB Staff Position 106-1, the Company has elected to defer recognizing the effects of the Medicare Act in its post-retirement plan accounting at December 31, 2003.

United Kingdom Operations

CE Electric UK, through a wholly-owned subsidiary, participates in the Electricity Supply Pension Scheme (the "UK Plan"), which provides pension and other related defined benefits, based on final pensionable pay, to substantially all employees throughout the electricity supply industry in the United Kingdom.

Net periodic pension costs included the following components for CE Electric UK for the years ended December 31. For purposes of calculating the expected return on pension plant assets, a market-related value is used. Market-related value is equal to fair value except for gains and losses on equity investments which are amortized into market-related value on a straight-line basis over five years.

Components of net periodic pension cost (in thousands):

				Pension Cost
				2003				2002				2001
Service cost				$	9,485			$	8,718			$	7,781
Interest cost					62,632				56,817				51,440
Expected return on plan assets					(89,124	)			(85,927	)			(78,354	)
Amortization of prior service cost					1,472				1,202				—
Curtailment loss and foreign exchange					537				6,463				7,061
Net periodic benefit				$	(14,998	)		$	(12,727	)		$	(12,072	)

As a result of the distribution price reviews in 1999, CE Electric UK implemented a review of staffing requirements primarily in its distribution business. Following discussions with the trade unions, CE Electric UK put in place a workforce reduction program. The pension curtailment related to this workforce reduction program was $ - million, $6.5 million and $7.1 million in 2003, 2002 and 2001, respectively.

Weighted-average assumptions used to determine benefit obligations at December 31:

				2003				2002				2001
Discount rate					5.5	%			5.75	%			5.75	%
Rate of compensation increase					2.75	%			2.5	%			2.5	%

Weighted-average assumptions used to determine net benefit cost for years ended December 31:

				2003				2002				2001
Discount rate					5.5	%			5.75	%			5.75	%
Expected return on plan assets					7.00	%			7.00	%			7.7	%
Rate of compensation increase					2.75	%			2.5	%			2.5	%

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The following table presents a reconciliation of the beginning and ending balances of the benefit obligation, fair value of plan assets and the funded status of the aforementioned plans to the net amounts measured and recognized in the Consolidated Balance Sheets as of December 31 (in thousands):

				Pension Benefits
				2003				2002
Reconciliation of the fair value of plan assets:
Fair value of plan assets at beginning of year				$	976,427			$	1,070,657
Employer contributions					14,391				3,607
Participant contributions					4,742				3,006
Actual return on plan assets					152,246				(144,298	)
Benefits paid					(57,726	)			(57,719	)
Foreign currency exchange rate changes					116,136				101,174
Fair value of plan assets at end of year				$	1,206,216			$	976,427
Reconciliation of benefit obligation:
Benefit obligation at beginning of year				$	1,102,730			$	974,079
Service cost					9,485				8,718
Interest cost					62,632				56,817
Participant contributions					4,742				3,006
Benefits paid					(57,726	)			(57,719	)
SFAS 88 Curtailment					—				5,712
Prior service cost					—				17,286
Experience gain and change of assumptions					83,890				(11,574	)
Foreign currency exchange rate changes					128,834				106,405
Benefit obligation at end of year				$	1,334,587			$	1,102,730
Funded status					(128,371	)		$	(126,303	)
Unrecognized net loss					507,039				465,211
Net amount recognized in the Consolidated Balance Sheets				$	378,668			$	338,908
Amounts recognized in the Consolidated Balance Sheets consist of:
Prepaid benefit cost				$	378,668			$	338,908
Accrued benefit liability					(496,147	)			(457,317	)
Intangible assets					16,604				16,433
Accumulated other comprehensive income					479,543				440,884
Net amount recognized				$	378,668			$	338,908

The accumulated benefit obligation for the defined benefit pension plan was $1.3 billion and $1.1 billion at December 31, 2003 and 2002, respectively.

The Company recorded a minimum pension liability as of December 31, 2003 and 2002 in the amount of $479.5 million and $440.9 million, respectively. The pension liability resulted from the declining market value of the pension plan assets during 2002 combined with a lower market interest rate used to value the plan's liabilities. As of December 31, 2003 and 2002, the minimum pension liability is measured as the amount of the plan's accumulated benefit obligation that is in excess of the plan's market value of assets at December 31, 2003 and 2002 plus the prepaid asset balance. A charge equal to the excess was recorded to the Company's stockholder's equity, net of income tax benefits, as a component of comprehensive loss in the amount of $27.1 million and $308.6 million in 2003 and 2002, respectively. This adjustment does not impact current year earnings, or the funding requirements of the plan.

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Plan Assets

CE Electric UK's investment policy for its pension and postretirement plans is to balance risk and return through a diversified portfolio of high-quality equity and fixed income securities. Maturities for fixed income securities are managed such that sufficient liquidity exists to meet near-term benefit payment obligations. The plans retain outside investment advisors to manage plan investments within the parameters outlined by the Benefits Committee of subsidiaries of CE Electric UK. The weighted average return on assets assumption is based on historical performance for the types of assets in which the plans invest.

CE Electric UK's pension plan asset allocation comprises the following at December 31:

				Percentage of Plan Assets
				at December 31
Asset Category				2003				2002
Equity securities					64	%			62	%
Debt securities					26				27
Real estate					9				10
Other					1				1
Total					100	%			100	%

Cash Flows

Employer contributions to fund the ongoing liabilities of the UK Plan are expected to be approximately $14.0 million in 2004. The next valuation of the UK Plan will take place as of March 31, 2004 and the results will be known later in the year. This valuation will set a revised level of contributions for the next three years. If the valuation results in a deficit in the UK Plan then an appropriate level of funding to address the deficit will be agreed in accordance with the UK Plan rules. The overall level of contributions paid by the employer is expected to be one of the factors considered by the regulator in setting the revised allowed prices which will take effect from April 1, 2005.

19.    Commitments and Contingencies

Fuel, Energy and Operating Lease Commitments

MidAmerican Energy has supply and related transportation contracts for its fossil fueled generating stations. As of December 31, 2003, the contracts, with expiration dates ranging from 2004 to 2010, require minimum payments of $83.3 million, $69.9 million, $54.5 million, $50.2 million and $16.1 million for the years 2004 through 2008, respectively, and $31.0 million for the total of the years thereafter. MidAmerican Energy expects to supplement these coal contracts with additional contracts and spot market purchases to fulfill its future fossil fuel needs. Additionally, MidAmerican Energy has a supply and transportation contact for a natural gas-fired generating plant. The contract, which expires in 2012, requires minimum payments of $0.8 million for 2004 and $6.2 million for each year thereafter.

MidAmerican Energy also has contracts with non-affiliated companies to purchase electric capacity. As of December 31, 2003, the contracts, with expiration dates ranging from 2004 to 2028, require minimum payments of $38.6 million, $3.6 million, $2.3 million, $2.2 million and $2.2 million for the years 2004 through 2008, respectively, and $40.1 million for the total of the years thereafter.

MidAmerican Energy has various natural gas supply and transportation contracts for its gas operations. As of December 31, 2003, the minimum commitments under these contracts were $56.3 million, $43.8 million, $18.0 million, $13.9 million and $4.2 million for the years 2004 through 2008, respectively, and $12.5 million for the total of the years thereafter.

MidAmerican Energy is the lessee on operating leases for coal railcars that contain guarantees of the residual value of such equipment throughout the term of the leases. Events triggering the residual guarantees include termination of the lease, loss of the equipment or purchase of the equipment. Lease terms are for five years with provisions for extensions. As of December 31, 2003, the maximum amount of such guarantees specified in these leases totaled $31.0 million. These guarantees are not reflected on the Consolidated Balance Sheets.

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MidAmerican Energy, Kern River, Northern Natural Gas, CE Electric UK, CalEnergy Generation – Domestic and HomeServices have non-cancelable operating leases primarily for computer equipment, office space and rail cars. The minimum payments under these leases are $53.1 million, $46.9 million, $41.0 million, $37.1 million and $27.0 million for the years 2004 through 2008, respectively, and $85.0 million for the total of the years thereafter.

Manufactured Gas Plants

The United States Environmental Protection Agency ("EPA") and the state environmental agencies have determined that contaminated wastes remaining at decommissioned manufactured gas plant facilities may pose a threat to the public health or the environment if such contaminants are in sufficient quantities and at such concentrations as to warrant remedial action.

MidAmerican Energy has evaluated or is evaluating 27 properties that were, at one time, sites of gas manufacturing plants in which it may be a potentially responsible party. The purpose of these evaluations is to determine whether waste materials are present, whether the materials constitute a health or environmental risk, and whether MidAmerican Energy has any responsibility for remedial action. MidAmerican Energy is actively working with the regulatory agencies and has received regulatory closure on four sites. MidAmerican Energy is continuing to evaluate several of the sites to determine the future liability, if any, for conducting site investigations or other site activity.

MidAmerican Energy estimates the range of possible costs for investigation, remediation and monitoring for the sites discussed above to be approximately $11 million to $30 million. As of December 31, 2003, MidAmerican Energy has recorded a $14.0 million liability for these sites and a corresponding regulatory asset for future recovery through the regulatory process. MidAmerican Energy projects that these amounts will be incurred or paid over the next four years.

The estimated liability is determined through a site-specific cost evaluation process. The estimate includes incremental direct costs of remediation, site monitoring costs and costs of compensation to employees for time expected to be spent directly on the remediation effort. The estimated recorded liabilities for these properties are based upon preliminary data. Thus, actual costs could vary significantly from the estimates. The estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial action and changes in technology relating to remedial alternatives. Insurance recoveries have been received for some of the sites under investigation. Those recoveries are intended to be used principally for accelerated remediation, as specified by the IUB and are recorded as a regulatory liability.

Although the timing of potential incurred costs and recovery of such costs in rates may affect the results of operations in individual periods, management believes that the outcome of these issues will not have a material adverse effect on MidAmerican Energy's financial position, results of operations or cash flows.

Air Quality

MidAmerican Energy's generating facilities are subject to applicable provisions of the Clean Air Act and related air quality standards promulgated by the United States Environmental Protection Agency ("EPA"). The Clean Air Act provides the framework for regulation of certain air emissions and permitting and monitoring associated with those emissions. MidAmerican Energy believes it is in material compliance with current air quality requirements.

The EPA has in recent years implemented more stringent standards for ozone and fine particulate matter. Designations regarding attainment of the eight-hour ozone standard have recently been reviewed by the EPA, and the EPA has concluded that the entire state of Iowa is in attainment of the standards. On December 4, 2003, the EPA announced the development of its Interstate Air Quality Rule, a proposal to require coal-burning power plants in 29 states and the District of Columbia to reduce emissions of sulfur dioxide ("SO₂") and nitrogen oxides ("NO_X") in an effort to reduce ozone and fine particulate matter in the Eastern United States. It is likely that MidAmerican Energy's coal-burning facilities will be impacted by this proposal.

In December 2000, the EPA concluded that mercury emissions from coal-fired generating stations should be regulated. The EPA is currently considering two regulatory alternatives for the regulation of

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mercury from coal-fired utilities as necessary to protect public health. One of these alternatives would require reductions of mercury from all coal-fired facilities greater than 25 MW through application of Maximum Achievable Control Technology with compliance assessed on a facility basis. The other alternative would regulate the mercury emissions of coal-fired facilities that pose a health hazard through a market based cap-and-trade mechanism similar to the SO₂ allowance system. The EPA is currently under a deadline to finalize the mercury rule by December 2004. Any of these new or stricter standards could, in whole or in part, be superceded or made more stringent by one of a number of multi-pollutant emission reduction proposals currently under consideration at the federal level, including the "Clear Skies Initiative", and other pending legislative proposals that contemplate 70% to 90% reductions of SO₂, NO_X and mercury, as well as possible new federal regulation of carbon dioxide and other gasses that may affect global climate change.

Depending on the outcome of the final regulations, MidAmerican Energy may be required to install control equipment on its generating stations or decrease the number of hours during which its generating stations operate. However, until final regulations are issued, the impact of the regulations on MidAmerican Energy cannot be predicted.

While legislative action is necessary for the Clear Skies Initiative or other multi-pollutant emission reduction legislation to become effective, MidAmerican Energy has implemented a planning process that forecasts the site-specific controls and actions required to meet emissions reductions of this nature. On April 1, 2002, in accordance with an Iowa law passed in 2001, MidAmerican Energy filed with the IUB its first multi-year plan and budget for managing SO₂ and NO_X from its generating facilities in a cost-effective manner. The plan provides specific actions to be taken at each coal-fired generating facility and the related costs and timing for each action. Mercury emissions reductions were not addressed in the plan. On July 17, 2003, the IUB issued an order that affirmed an administrative law judge's approval of the plan, as amended. Accordingly, the IUB order provides that the approved expenditures will not be subject to a subsequent prudence review in a future electric rate case, but it rejected the future application of a tracker mechanism to recover emission reduction costs. However, pursuant to an unrelated rate settlement agreement approved by the IUB on October 17, 2003, if prior to January 1, 2011, capital and operating expenditures to comply with environmental requirements cumulatively exceed $325 million, then MidAmerican Energy may seek to recover the additional expenditures from customers. At this time, MidAmerican Energy does not expect these capital expenditures to exceed such amount.

Under the New Source Review ("NSR") provisions of the Clean Air Act, a utility is required to obtain a permit from the EPA or a state regulatory agency prior to (1) beginning construction of a new major stationary source of an NSR-regulated pollutant or (2) making a physical or operational change (a "major modification") to an existing facility that potentially increases emissions, unless the changes are exempt under the regulations. In general, projects subject to NSR regulations are subject to pre-construction review and permitting under the Prevention of Significant Deterioration ("PSD") provisions of the Clean Air Act. Under the PSD program, a project that emits threshold levels of regulated pollutants must undergo a Best Available Control Technology analysis and evaluate the most effective emissions controls. These controls must be installed in order to receive a permit. Violations of NSR regulations, which may be alleged by the EPA, states and environmental groups, among others, potentially subject a utility to material expenses for fines or other sanctions and remedies including requiring installation of enhanced pollution controls and funding supplemental environmental projects.

In recent years, the EPA has requested from several utilities information and support regarding their capital projects for various generating plants. The requests were issued as part of an industry-wide investigation to assess compliance with the NSR and the New Source Performance Standards of the Clean Air Act. In December 2002 and April 2003, MidAmerican Energy received requests from the EPA to provide documentation related to its capital projects from January 1, 1980, to the present for a number of its generating plants. MidAmerican Energy has submitted information to the EPA in responses to these requests, and there are currently no outstanding data requests pending from the EPA. MidAmerican Energy cannot predict the outcome of these requests at this time. However, on August 27, 2003, the EPA announced changes to its NSR rules that clarify what constitutes routine repair, maintenance and replacement for purposes of triggering NSR requirements. The EPA concluded equipment that is repaired, maintained or replaced with an expenditure not greater than 20 percent of the value of the

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source will not trigger the NSR provisions of the Clean Air Act. After the NSR changes were announced, the EPA's enforcement branch indicated it would apply the clarified routine repair, maintenance and replacement rules to its pending investigation. A number of states and local air districts have challenged the EPA's clarification of the rule and a panel of the U.S. Circuit Court of Appeals for the District of Columbia issued an order on December 24, 2003 staying the EPA's implementation of its clarification of the equipment replacement rule.

On August 29, 2003, the EPA finalized requirements to reduce toxic air emissions from stationary combustion turbines. These requirements apply to turbines used at pipeline compressor stations that are built after January 12, 2003. Kern River and Northern Natural Gas believe the existing turbines are exempt from the rule since the turbines were built and installed at compressor stations built prior to January 12, 2003. New turbine installations will likely require the installation of equipment to reduce formaldehyde emissions and other pollutants to meet the new requirements and could significantly increase the cost of new turbine installations.

On December 19, 2002, the EPA issued proposed emission standards for hazardous air pollutants for stationary reciprocating internal combustion engines, such as those used at pipeline compressor stations. The proposed standards would apply to all new and certain existing reciprocating internal combustion engines above 500 horsepower that are located at facilities characterized under the Clean Air Act as a "major source" of toxic air pollutants. While the emission standards have not yet been finalized, the impact of any new regulation of hazardous air pollutants from stationary reciprocating internal combustion engines could have a significant impact on existing and new facilities.

Decommissioning Costs

Expected decommissioning costs for Quad Cities Station have been developed based on a site-specific decommissioning study that includes decontamination, dismantling, site restoration, dry fuel storage cost and an assumed shutdown date. Quad Cities Station decommissioning costs are included in base rates in Iowa tariffs.

MidAmerican Energy's share of expected decommissioning costs for Quad Cities Station, in 2003 dollars, is $260 million and is the asset retirement obligation for Quad Cities Station. Refer to Note (1)(j) for a discussion of asset retirement obligations. MidAmerican Energy has established external trusts for the investment of funds for decommissioning the Quad Cities Station. The fair value of the assets held in the trusts is reflected in Investments and Nonregulated Property, Net.

MidAmerican Energy's depreciation and amortization expense included costs for Quad Cities Station nuclear decommissioning of $8.3 million for each of the years 2003, 2002 and 2001. The regulatory provision charged to expense is equal to the funding that is being collected in Iowa rates. Realized and unrealized gains and (losses) on the assets in the trust fund were $16.1 million, $(6.9) million and $(3.1) million for 2003, 2002 and 2001, respectively.

Nuclear Insurance

MidAmerican Energy maintains financial protection against catastrophic loss associated with its interest in Quad Cities Station through a combination of insurance purchased by Exelon Generation Company, LLC (the operator and joint owner of Quad Cities Station), insurance purchased directly by MidAmerican Energy, and the mandatory industry-wide loss funding mechanism afforded under the Price-Anderson Amendments Act of 1988. The general types of coverage are: nuclear liability, property coverage and nuclear worker liability.

Exelon Generation purchases nuclear liability insurance for Quad Cities Station in the maximum available amount of $300 million, which includes coverage for MidAmerican Energy's ownership. In accordance with the Price-Anderson Amendments Act of 1988, excess liability protection above that amount is provided by a mandatory industry-wide Secondary Financial Protection program under which the licensees of nuclear generating facilities could be assessed for liability incurred due to a serious nuclear incident at any commercial nuclear reactor in the United States. Currently, MidAmerican Energy's aggregate maximum potential share of an assessment for Quad Cities Station is approximately $50.3 million per incident, payable in installments not to exceed $5 million annually.

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The property insurance covers property damage, stabilization and decontamination of the facility, disposal of the decontaminated material and premature decommissioning arising out of a covered loss. For Quad Cities Station, Exelon Generation purchased primary and excess property insurance protection for the combined interests in Quad Cities Station, with coverage limits totaling $2.1 billion. MidAmerican Energy also directly purchased extra expense or business interruption coverage for its share of replacement power and other extra expenses in the event of a covered accidental outage at Quad Cities Station. The property and related coverages purchased directly by MidAmerican Energy and by Exelon Generation, which includes the interests of MidAmerican Energy, are underwritten by an industry mutual insurance company and contain provisions for retrospective premium assessments should two or more full policy-limit losses occur in one policy year. Currently, the maximum retrospective amounts that could be assessed against MidAmerican Energy from industry mutual policies for its obligations associated with Quad Cities Station total $7.6 million.

The master nuclear worker liability coverage, which is purchased by Exelon Generation for Quad Cities Station, is an industry-wide guaranteed-cost policy with an aggregate limit of $300 million for the nuclear industry as a whole, which is in effect to cover tort claims in nuclear-related industries.

The current Price-Anderson Act expired in August 2002 and is pending congressional action for reauthorization. Its contingent financial obligations still apply to reactors licensed by the Nuclear Regulatory Commission as of its expiration date. It is anticipated that the Price-Anderson Act will be renewed with increased third party financial protection requirements for nuclear incidents.

Natural Gas Commodity Litigation

MidAmerican Energy is one of dozens of companies named as defendants in a January 20, 2004 consolidated class action lawsuit filed in the U.S. District Court for the Southern District of New York. The suit alleges that the defendants have engaged in unlawful manipulation of the prices of natural gas futures and options contracts traded on the New York Mercantile Exchange ("NYMEX") during the period January 1, 2000 to December 31, 2002. MidAmerican Energy is mentioned as a company that has engaged in wash trades on Enron Online (an electronic trading platform) that had the effect of distorting prices for gas trades on the NYMEX. The plaintiffs to the class action do not specify the amount of alleged damages. At this time, MidAmerican Energy does not believe that it has any material exposure in this lawsuit.

The original complaint in this matter, Cornerstone Propane Partners, L.P. v. Reliant, et al. ("Cornerstone"), was filed on August 18, 2003 in the United States District Court, Southern District of New York naming MidAmerican Energy and the Company. On October 1, 2003, a second complaint , Roberto, E. Calle Gracey, et al. ("Calle Gracey"), was filed in the same court but did not name MidAmerican Energy or the Company. On November 14, 2003, a third complaint, Dominick Viola ("Viola"), et al., was filed in the same court and named MidAmerican Energy and MEHC as defendants. On November 19, 2003, an Order of Voluntary Dismissal Without Prejudice of MEHC was entered by the court dismissing MEHC from the Cornerstone and Viola complaints. On December 5, 2003, the court entered Pretrial Order No. 1, which among other procedural matters, ordered the consolidation of the Cornerstone, Calle Gracey and Viola complaints and permitted plaintiffs to file an amended complaint in this matter. On January 20, 2004, plaintiffs filed In Re: Natural Gas Commodity Litigation as the amended complaint reasserting their previous allegations. Unless extended by agreement of the parties or by court order, MidAmerican Energy's answer and/or responsive pleading in this matter is due February 19, 2004. MidAmerican Energy will coordinate with the other defendants and vigorously defend the allegations against it.

Philippines

CE Casecnan Construction Contract Arbitration

The Casecnan project was constructed pursuant to a fixed-price, date-certain, turnkey 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.

In 2001, the Contractor filed a Request for Arbitration (and two supplements) with the International Chamber of Commerce ("ICC") seeking schedule relief of up to 153 days, compensation for alleged

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additional costs of approximately $4 million (to the extent it is unable to recover from its insurer) and compensation for damages of approximately $62 million resulting from alleged force majeure events (and geologic conditions). The Contractor further alleged that the circumstances surrounding the placing of the Casecnan project into commercial operation in December 2001 amounted to a repudiation of the Replacement Contract resulting in a claim for unspecified quantum meruit damages, and that the delay liquidated damages clause which provides for payments of $125,000 per day to CE Casecnan for each day of delay in completion of the Casecnan project is unenforceable.

On November 7, 2002, the ICC issued the arbitration tribunal's partial award with respect to the Contractor's force majeure claims. The arbitration panel awarded the Contractor 18 days of schedule relief in the aggregate for all of the force majeure events and awarded the Contractor $3.8 million to the extent losses are not covered by insurance. All of the Contractor's other claims with respect to force majeure and geologic conditions were denied. If the Contractor were to prevail on the Contractor's claim that the delay liquidated damages clause is unenforceable, CE Casecnan would not be entitled to collect such delay damages for the period from March 31, 2001 through December 11, 2001. If the Contractor were to prevail in the Contractor's repudiation claim and prove quantum meruit damages in excess of amounts paid to the Contractor, CE Casecnan could be liable to make additional payments to the Contractor. CE Casecnan believes all of such allegations and claims are without merit and is vigorously contesting the Contractor's claims. CE Casecnan believes that an award will be issued by the ICC in 2004.

CE Casecnan Stockholder Litigation

Pursuant to the share ownership adjustment mechanism in the CE Casecnan stockholder agreement, which is based upon pro forma financial projections of the Casecnan project prepared following commencement of commercial operations, in February 2002, MEHC's indirect wholly owned subsidiary, CE Casecnan Ltd., advised the minority stockholder, LaPrairie Group Contractors (International) Ltd. ("LPG"), that MEHC's ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. In April 2002, CE Casecnan Ltd. and LPG entered into a status quo agreement pursuant to which CE Casecnan Ltd. agreed not to take any action to exercise control over or transfer LPG's shares in CE Casecnan. On July 8, 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco against, among others, CE Casecnan Ltd. and MEHC. In the complaint, LPG seeks compensatory and punitive damages for alleged breaches of the stockholder agreement and alleged breaches of fiduciary duties allegedly owed by CE Casecnan Ltd. and MEHC to LPG. The complaint also seeks injunctive relief against all defendants and a declaratory judgment that LPG is entitled to maintain a 15% interest in CE Casecnan. On January 21, 2004, CE Casecnan Ltd. and LPG entered into a second status quo agreement pursuant to which the parties agreed to set aside certain distributions related to the shares subject to the LPG dispute and not distribute such funds without at least 15 days prior notice to LPG. Accordingly, 15% of the dividend distribution declared on January 21, 2004 was set aside by CE Casecnan in an unsecured CE Casecnan account. The impact, if any, of this litigation on the Company cannot be determined at this time.

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20.    Segment Information:

The Company has identified seven reportable segments principally based on management structure: MidAmerican Energy, Kern River, Northern Natural Gas, CE Electric UK, CalEnergy Generation-Domestic, CalEnergy Generation-Foreign, and HomeServices. Information related to the Company's reportable operating segments is shown below (in thousands).

				Year Ended December 31,
				2003				2002				2001
Operating revenue:
MidAmerican Energy				$	2,600,239			$	2,240,879			$	2,388,650
Kern River					260,182				127,254				—
Northern Natural Gas					482,156				176,880				—
CE Electric UK					829,993				795,366				1,443,997
CalEnergy Generation – Domestic					45,750				38,546				37,299
CalEnergy Generation – Foreign					326,454				326,316				203,482
HomeServices					1,476,569				1,138,332				641,934
Segment operating revenue					6,021,343				4,843,573				4,715,362
Corporate/other					(73,119	)			(49,563	)			(18,581	)
Total operating revenue				$	5,948,224			$	4,794,010			$	4,696,781
Depreciation and amortization:
MidAmerican Energy				$	281,001			$	269,412			$	286,590
Kern River					36,771				17,165				—
Northern Natural Gas					52,716				18,151				—
CE Electric UK					125,000				116,792				133,865
CalEnergy Generation – Domestic					16,020				8,714				5,439
CalEnergy Generation – Foreign					87,928				88,036				66,315
HomeServices					17,560				22,072				17,201
Segment depreciation and amortization					616,996				540,342				509,410
Corporate/other					(7,107	)			(14,440	)			29,292
Total depreciation and amortization				$	609,889			$	525,902			$	538,702
Interest expense, net:
MidAmerican Energy				$	118,809			$	119,225			$	113,980
Kern River					61,979				33,036				—
Northern Natural Gas					55,833				22,987				—
CE Electric UK					171,767				183,472				112,308
CalEnergy Generation – Domestic					30,333				20,913				10,835
CalEnergy Generation – Foreign					59,603				68,338				30,875
HomeServices					3,864				4,256				3,884
Segment interest expense, net					502,188				452,227				271,882
Corporate/other					239,160				157,683				140,912
Total interest expense, net				$	741,348			$	609,910			$	412,794

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				Year Ended December 31,
				2003				2002				2001
Income before provisions for income taxes:
MidAmerican Energy				$	268,670			$	241,005			$	211,300
Kern River					133,720				60,700				—
Northern Natural Gas					127,307				42,882				—
CE Electric UK					288,720				266,755				173,816
CalEnergy Generation – Domestic					(25,510	)			(4,963	)			46,765
CalEnergy Generation – Foreign					179,546				149,915				94,542
HomeServices					113,537				69,979				42,945
Segment income before provision for income taxes					1,085,990				826,273				569,368
Corporate/other					(236,198	)			(183,175	)			(65,484	)
Total income before provision for income taxes				$	849,792			$	643,098			$	503,884
Provision for income taxes:
MidAmerican Energy				$	110,078			$	99,782			$	95,688
Kern River					51,319				23,014				—
Northern Natural Gas					50,599				16,947				—
CE Electric UK					91,539				25,245				163,253
CalEnergy Generation – Domestic					(18,183	)			(15,203	)			2,706
CalEnergy Generation – Foreign					76,493				37,577				29,712
HomeServices					43,587				28,207				15,953
Segment provision for income taxes					405,432				215,569				307,312
Corporate/other					(154,461	)			(115,981	)			(57,248	)
Total provision for income taxes				$	250,971			$	99,588			$	250,064
Capital expenditures:
MidAmerican Energy				$	378,530			$	358,194			$	252,615
Kern River					361,477				769,464				—
Northern Natural Gas					104,400				62,409				—
CE Electric UK					301,896				222,622				176,464
CalEnergy Generation – Domestic					17,845				61,920				52,940
CalEnergy Generation – Foreign					8,497				7,830				83,954
HomeServices					18,311				18,273				9,878
Segment capital expenditures					1,190,956				1,500,712				575,851
Corporate/other					71				7,373				901
Total capital expenditures				$	1,191,027			$	1,508,085			$	576,752

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				As of December 31,
				2003				2002				2001
Identifiable assets:
MidAmerican Energy				$	6,596,849			$	6,025,452			$	5,848,035
Kern River					2,200,201				1,797,850				—
Northern Natural Gas					2,167,621				2,162,367				—
CE Electric UK					5,038,880				4,714,459				4,340,147
CalEnergy Generation – Domestic					865,223				873,357				870,664
CalEnergy Generation – Foreign					949,237				974,852				950,035
HomeServices					567,736				488,324				322,552
Segment identifiable assets					18,385,747				17,036,661				12,331,433
Corporate/other					782,442				1,012,568				295,219
Total identifiable assets				$	19,168,189			$	18,049,229			$	12,626,652
Long-lived assets:
MidAmerican Energy				$	5,524,279			$	4,999,637			$	4,879,884
Kern River					2,010,113				1,682,934				—
Northern Natural Gas					1,809,623				1,818,469				—
CE Electric UK					4,489,306				3,936,598				3,650,385
CalEnergy Generation – Domestic					593,580				594,282				571,404
CalEnergy Generation – Foreign					621,674				724,908				805,050
HomeServices					418,999				384,899				262,175
Segment long-lived assets					15,467,574				14,141,727				10,168,898
Corporate/other					19,048				15,201				7,019
Total long-lived assets				$	15,486,622			$	14,156,928			$	10,175,917

The remaining differences from the segment amounts to the consolidated amounts described as "Corporate/Other" relate principally to the corporate functions including administrative costs, corporate cash and related interest income, corporate interest expenses, intersegment eliminations, and fair value adjustments relating to acquisitions.

The following table shows the change in the carrying amount of goodwill by reportable segment for the years ended December 31, 2003 and 2002 (in thousands):

				MidAmerican Energy				Kern River				Northern Natural Gas				CE Electric UK				Cal Energy Generation Domestic				Home- Services				Total
Balance, January 1, 2002				$	2,160,004			$	—			$	—			$	1,104,262			$	142,726			$	231,554			$	3,638,546
Goodwill from acquisitions during the year					—				32,547				414,721				56,626				—				108,914				612,808
Goodwill written off related to the sale of a business unit					—				—				—				(49,587	)			—				—				(49,587	)
Other goodwill adjustments (1)					(10,722	)			—				—				84,020				(16,286	)			(647	)			56,365
Balance, December 31, 2002					2,149,282				32,547				414,721				1,195,321				126,440				339,821				4,258,132
Goodwill from acquisitions during the year					—				—				—				—				—				26,648				26,648
Other goodwill adjustments (1)					(10,059	)			1,353				(35,573	)			66,262				(132	)			(988	)			20,863
Balance, December 31, 2003				$	2,139,223			$	33,900			$	379,148			$	1,261,583			$	126,308			$	365,481			$	4,305,643

(1)	Other goodwill adjustments include deferred tax, foreign currency translation, stock options and purchase price adjustments.

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Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.    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 of MEHC, 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 December 31, 2003. Based on that evaluation, the Company's management, including the Chief Executive Officer and Chief Financial Officer of MEHC, concluded that the Company's disclosure controls and procedures were effective. There have been no significant changes in the Company's internal controls or in other factors that could significantly affect internal controls.

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PART III

Item 10.    Directors and Executive Officers of the Registrant.

MEHC's management structure is organized functionally and the current executive officers and directors of MEHC and their positions are as follows:

Name				Position
David L. Sokol				Chairman of the Board, Chief Executive Officer and Director
Gregory E. Abel				President, Chief Operating Officer and Director
Patrick J. Goodman				Senior Vice President and Chief Financial Officer
Douglas L. Anderson				Senior Vice President, General Counsel and Corporate Secretary
Keith D. Hartje				Senior Vice President and Chief Administrative Officer
Warren E. Buffett				Director
Walter Scott Jr.				Director
Marc D. Hamburg				Director
W. David Scott				Director
Edgar D. Aronson				Director
John K. Boyer				Director
Stanley J. Bright				Director
Richard R. Jaros				Director

Officers are elected annually by the Board of Directors. There are no family relationships among the executive officers, nor any arrangements or understanding between any officer and any other person pursuant to which the officer was appointed.

Set forth below is certain information, as of January 1, 2004, with respect to each of the foregoing officers and directors:

DAVID L. SOKOL, 47, Chairman of the Board of Directors and Chief Executive Officer. Mr. Sokol has been CEO since April 19, 1993 and served as President of MEHC from April 19, 1993 until January 21, 1995. Mr. Sokol has been Chairman of the Board of Directors since May 1994 and a director since March 1991. Formerly, among other positions held in the independent power industry, Mr. Sokol served as President and Chief Executive Officer of Kiewit Energy Company, which at that time was a wholly owned subsidiary of Peter Kiewit & Sons', Inc., and Ogden Projects, Inc.

GREGORY E. ABEL, 41, President, Chief Operating Officer and Director. Mr. Abel joined MEHC in 1992 and initially served as Vice President and Controller. Mr. Abel is a Chartered Accountant and from 1984 to 1992 he was employed by Price Waterhouse. As a Manager in the San Francisco office of Price Waterhouse, he was responsible for clients in the energy industry.

PATRICK J. GOODMAN, 37, Senior Vice President and Chief Financial Officer. Mr. Goodman joined MEHC in 1995 and served in various accounting positions including Senior Vice President and Chief Accounting Officer. Prior to joining MEHC, Mr. Goodman was a financial manager for National Indemnity Company and a senior associate at Coopers & Lybrand.

DOUGLAS L. ANDERSON, 45, Senior Vice President and General Counsel. Mr. Anderson joined MEHC in February 1993 and has served in various legal positions including General Counsel of the Company's independent power affiliates. From 1990 to 1993, Mr. Anderson was a corporate attorney with Fraser, Stryker in Omaha, NE. Prior to that Mr. Anderson was a principal in the firm Anderson and Anderson.

KEITH D. HARTJE, 54, Senior Vice President and Chief Administrative Officer. Mr. Hartje has been with MidAmerican Energy and its predecessor companies since 1973. In that time, he has held a number of positions, including General Counsel and Corporate Secretary, District Vice President for southwest Iowa operations, and Vice President, Corporate Communications.

WARREN E. BUFFETT, 73, Director. Mr. Buffett has been a director of MEHC since March 2000. He is Chairman of the Board and Chief Executive Office of Berkshire Hathaway Inc. Mr. Buffett is a Director of the Coca-Cola Company, the Gillette Company and The Washington Post Company.

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WALTER SCOTT, JR., 72, Director. Mr. Scott has been a director of MEHC since June 1991. Mr. Scott was the Chairman and Chief Executive Officer of MEHC from January 8, 1992 until April 19, 1993. For more than the past five years, he has been Chairman of the Board of Directors of Level 3 Communications, Inc., a successor to certain businesses of Peter Kiewit & Sons', Inc. Mr. Scott is a director of Peter Kiewit & Sons', Inc., Berkshire Hathaway Inc., Burlington Resources, Inc., ConAgra, Inc., Valmont Industries, Inc., Kiewit Materials Co., Commonwealth Telephone Enterprises, Inc. and RCN Corporation. Mr. Scott is the father of W. David Scott.

MARC D. HAMBURG, 54, Director. Mr. Hamburg has been a director of MEHC since March 2000. He has served as Vice President – Chief Financial Officer of Berkshire Hathaway Inc. since October 1, 1992 and Treasurer since June 1, 1987, his date of employment with Berkshire Hathaway Inc.

W. DAVID SCOTT, 42, Director. Mr. Scott has been a director of MEHC since March 2000. Mr. Scott formed Magnum Resources, Inc., a commercial real estate investment and management company, in October 1994 and has served as its President and Chief Executive Officer since its inception. Before forming Magnum Resources, Mr. Scott worked for America First Companies, Cornerstone Banking Group and Peter Kiewit & Sons', Inc. Mr. Scott has been a director of America First Mortgage Investments, Inc., a mortgage REIT, since 1998. Mr. Scott is the son of Walter Scott, Jr.

EDGAR D. ARONSON, 69, Director. Mr. Aronson has been a director of MEHC since 1983. Mr. Aronson founded EDACO, Inc., a private venture capital company, in 1981, and has been President of EDACO, Inc. since that time. Prior to that, Mr. Aronson was Chairman of Dillon, Read International from 1979 to 1981 and a General Partner in charge of the International Department of Salomon Brothers Inc. from 1973 to 1979. Mr. Aronson served during 1962-1968 as Vice President consecutively in the International Departments of First National Bank of Chicago and Republic National Bank of New York. He founded the International Department of Salomon Brothers and Hutzler in 1968.

JOHN K. BOYER, 59, Director. Mr. Boyer has been a director of MEHC since March 2000. He is a partner with Fraser, Stryker, Meusey, Olson, Boyer & Bloch, P.C. where he has practiced from 1973 to present with emphasis on corporate, commercial, federal, state, and local taxation.

STANLEY J. BRIGHT, 63, Director. Mr. Bright was Chairman and Chief Executive Officer of MidAmerican Energy from July 1, 1995 until March 1999. Mr. Bright joined Iowa-Illinois Gas and Electric Company (a predecessor of MidAmerican Energy) as Vice President and Chief Financial Officer in 1986, became a director in 1987, President and Chief Operating Officer in 1990, and Chairman and Chief Executive Officer in 1991.

RICHARD R. JAROS, 51, Director. Mr. Jaros has been a director of MEHC since March 1991. Mr. Jaros served as President and Chief Operating Officer of MEHC from January 8, 1992 to April 19, 1993 and as Chairman of the Board from April 19, 1993 to May 1994. Until July 1997, Mr. Jaros was Executive Vice President and Chief Financial Officer of Peter Kiewit & Sons', Inc. and President of Kiewit Diversified Group, Inc., which is now Level 3 Communications, Inc. Mr. Jaros serves as director of Commonwealth Telephone Enterprises, Inc., RCN Corporation and Level 3 Communications, Inc.

Audit Committee Members and Financial Experts

The audit committee of the Board of Directors is comprised of Messrs. Marc D. Hamburg and Richard R. Jaros. The Board of Directors has determined that Messrs. Hamburg and Jaros qualify as "audit committee financial experts", as defined by Securities and Exchange Commission Rules, based on their education, experience and background. Mr. Jaros is independent as that term is used in Item 7(d) (3) (IV) of Schedule 14A under the Exchange Act.

Code of Ethics

MEHC has adopted a code of ethics that applies to its principal executive officer, its principal financial officer, its chief accounting officer and certain other covered officers. The code of ethics is filed as an exhibit to this annual report on Form 10-K.

Item 11.    Executive Compensation.

The following table sets forth the compensation of MEHC's Chief Executive Officer and its four other most highly compensated executive officers who were employed as of December 31, 2003, which

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MEHC refers to as its Named Executive Officers. Information is provided regarding its Named Executive Officers for the last three fiscal years during which they were its executive officers, if applicable.

Name and Principal Positions				Year Ended Dec. 31				Salary(1)				Bonus(1)				Other Annual Compensation				All Other Comp(2)
David L. Sokol					2003			$	800,000			$	2,750,000			$	—			$	7,960
Chairman and					2002				800,000				2,750,000				27,122,550				7,960
Chief Executive Officer					2001				750,000				2,400,000				—				33,033
Gregory E. Abel					2003				669,011				2,200,000				—				7,690
President and					2002				540,000				2,200,000				—				7,636
Chief Operating Officer					2001				520,000				1,150,000				—				23,657
Patrick J. Goodman					2003				273,570				285,000				—				7,392
Senior Vice President and					2002				248,000				365,000				209,560				7,353
Chief Financial Officer					2001				240,000				260,000				—				13,527
Douglas L. Anderson					2003				270,711				240,000				—				7,150
Senior Vice President and					2002				200,000				325,000				—				7,150
General Counsel					2001				154,427				200,000				—				6,630
Keith D. Hartje					2003				180,000				65,000				—				7,796
Senior Vice President and					2002				180,000				65,000				—				7,796
Chief Administrative Officer					2001				180,000				60,000				—				6,630

(1)	Includes amounts voluntarily deferred by the executive, if applicable.

(2)

Consists of 401(k) Plan contributions for 2003 for Messrs. Sokol, Abel, Goodman and Anderson of $7,150, and Mr. Hartje of $7,796. To offset its obligations under the Company's Executive Split Dollar Plan for executives whose retirement benefit cannot be fully funded through the Company's Base Retirement Plan for Salaried Employees, the Company has agreed to pay the premiums for policies of split dollar life insurance on the lives of such executives. No premiums were paid in 2003 for Mr. Sokol, Mr. Abel, or Mr. Goodman. Included are the insurance premiums in the following amounts paid by the Company with respect to the term life insurance portion of premiums paid in 2003 for Mr. Sokol of $810, for Mr. Abel of $540 and for Mr. Goodman of $242.

Pursuant to MEHC's Executive Incremental Profit Sharing Plan, Messrs. Sokol and Abel are each eligible to receive a one-time profit sharing award of $11.25 million, $18.75 million or $37.5 million based upon achieving specified adjusted diluted earnings per share targets for any calendar year from 2003 through 2007 and continued employment during such time.

Option Grants in Last Fiscal Year

MEHC did not grant any options during 2003.

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Aggregated Option Exercises In Last Fiscal Year And Fiscal Year End Option Values

The following table sets forth the option exercises and the number of securities underlying exercisable and unexercisable options held by each of its Named Executive Officers at December 31, 2003.

												Underlying Unexercised Options Held (#)								Value of Unexercised In-the-money Options ($) (1)
Name				Shares Acquired on Exercise (#)				Value Realized				Exercisable				Unexercisable				Exercisable				Unexercisable
David Sokol					—				—				1,399,277				—				N/A				N/A
Gregory E. Abel					—				—				649,052				—				N/A				N/A
Patrick J. Goodman					—				—				—				—				—				—
Douglas L. Anderson					—				—				—				—				—				—
Keith D. Hartje									—				—				—				—				—

(1)	On March 14, 2000, MEHC was acquired by a private investor group. As a privately held company, MEHC has no publicly traded equity securities and, consequently, its management does not believe there is a reliable method of computing the fair market value of the stock as of December 31, 2003.

Long-Term Incentive Plans – Awards in Last Fiscal Year

Name

Number of Shares, Units or Other Rights (#)

Performance or Other Period Until Maturation or Payout

Threshold ($)(1)

Target ($)(1)

Maximum ($)

Patrick J. Goodman

N/A

December 31, 2007

412,500

N/A

N/A

Douglas L. Anderson

N/A

December 31, 2007

390,000

N/A

N/A

Keith D. Hartje

N/A

December 31, 2007

163,913

N/A

N/A

(1)

The awards shown in the foregoing table are made pursuant to the Long-Term Incentive Partnership Plan ("LTIP"). The amounts shown are dollar amounts credited to an investment account for the benefit of the named executive officers and such amounts vest equally over five years (starting with year 2003) with any unvested balances forfeited upon termination of employment unless the participant retires at or above age 55 with at least 5 years of service in which case the participant will receive any unvested portion of the award. Vested balances (including any investment performance profits or losses thereon) are paid to the participant at the time of termination. Once an award is fully vested, the participant may elect to defer or receive payment of part or all of the award. Messrs. Sokol and Abel are not participants in the LTIP. Awards are credited or reduced with annual interest or loss based on a composite of funds or indices. Because the amounts to be paid out may increase or decrease depending on investment performance, the ultimate benefits are undeterminable and the payouts do not have a "target" or "maximum" amount.

Compensation of Directors

All directors, excluding Messrs. Sokol, Abel, Buffett and Walter Scott Jr., are paid an annual retainer fee of $20,000 and a fee of $500 per day for attendance at Board and Committee meetings. Directors who are employees are not entitled to receive such fees. All directors are reimbursed for their expenses incurred in attending Board meetings.

Retirement Plans

The Company maintains a Supplemental Retirement Plan for Designated Officers, which the Company refers to as the Supplemental Plan, to provide additional retirement benefits to designated participants, as determined by the Board of Directors. Messrs. Sokol, Abel, Goodman and Hartje are participants in the Supplemental Plan. The Supplemental Plan provides annual retirement benefits up to sixty-five percent of a participant's Total Cash Compensation in effect immediately prior to retirement, subject to a $1 million maximum retirement benefit. "Total Cash Compensation" means the highest

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amount payable to a participant as monthly base salary during the five years immediately prior to retirement multiplied by 12 plus the average of the participant's last three years awards under an annual incentive bonus program and special, additional or non-recurring bonus awards, if any, that are required to be included in Total Cash Compensation pursuant to a participant's employment agreement or approved for inclusion by the Board. Participants must be credited with five years service in order to be eligible to receive benefits under the Supplemental Plan. Each of the Company's Named Executive Officers has or will have five years of credited service with the Company as of their respective normal retirement age and will be eligible to receive benefits under the Supplemental Plan. A participant who elects early retirement is entitled to reduced benefits under the Supplemental Plan, however, in accordance with their respective employment agreements, Messrs. Sokol and Abel are eligible to receive the maximum retirement benefit at age 47. A survivor benefit is payable to a surviving spouse under the Supplemental Plan. Benefits from the Supplemental Plan will be paid out of general corporate funds; however, through a rabbi trust, the Company maintains life insurance on the participants in amounts expected to be sufficient to fund the after-tax cost of the projected benefits. Deferred compensation is considered part of the salary covered by the Supplemental Plan.

The supplemental retirement benefit will be reduced by the amount of the participant's regular retirement benefit under the MidAmerican Energy Cash Balance Retirement Plan, which the Company refers to as the MidAmerican Retirement Plan, that became effective January 1, 1997 and by benefits under the Iowa Resources Inc. and Subsidiaries Supplemental Retirement Income Plan ("IOR Supplemental Plan"), as applicable.

The MidAmerican Retirement Plan replaced retirement plans of predecessor companies that were structured as traditional, defined benefit plans. Under the MidAmerican Retirement Plan, each participant has an account, for record keeping purposes only, to which credits are allocated each payroll period based upon a percentage of the participant's salary paid in the current pay period. In addition, all balances in the accounts of participants earn a fixed rate of interest that is credited annually. The interest rate for a particular year is based on the constant maturity Treasury yield plus seven-tenths of one percentage point. At retirement or other termination of employment, an amount equal to the vested balance then credited to the account is payable to the participant in the form of a lump sum or a form of annuity for the entire benefit under the MidAmerican Retirement Plan.

Part A of the IOR Supplemental Plan provides retirement benefits up to sixty-five percent of a participant's highest annual salary during the five years prior to retirement reduced by the participant's MidAmerican Retirement Plan benefit. The percentage applied is based on years of accredited service. A participant who elects early retirement is entitled to reduced benefits under the plan. A survivor benefit is payable to a surviving spouse. Benefits are adjusted annually for inflation. Part B of the IOR Supplemental Plan provides that an additional one hundred-fifty percent of annual salary is to be paid out to participants at the rate of ten percent per year over fifteen years, except in the event of a participant's death, in which event the unpaid balance would be paid to the participant's beneficiary or estate. Deferred compensation is considered part of the salary covered by the IOR Supplemental Plan.

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The table below shows the estimated aggregate annual benefits payable under the Supplemental Plan and the MidAmerican Retirement Plan. The amounts exclude Social Security and are based on a straight life annuity and retirement at ages 55, 60 and 65. Federal law limits the amount of benefits payable to an individual through the tax qualified defined benefit and contribution plans, and benefits exceeding such limitation are payable under the Supplemental Plan.

				Estimated Annual Benefit
				Age at Retirement
Total Cash   Compensation at Retirement ($)				55				60				65
$400,000				$	220,000			$	240,000			$	260,000
500,000					275,000				300,000				325,000
600,000					330,000				360,000				390,000
700,000					385,000				420,000				455,000
800,000					440,000				480,000				520,000
900,000					495,000				540,000				585,000
1,000,000					550,000				600,000				650,000
1,250,000					687,500				750,000				812,500
1,500,000					825,000				900,000				975,000
1,750,000					962,500				1,000,000				1,000,000
2,000,000 and greater					1,000,000				1,000,000				1,000,000

Employment Agreements

Pursuant to his employment agreement Mr. Sokol serves as Chairman of MEHC's Board of Directors and Chief Executive Officer. The employment agreement provides that Mr. Sokol is to receive an annual base salary of not less than $750,000, senior executive employee benefits and annual bonus awards that shall not be less than $675,000. Subject to an annual renewal provision, such agreement is scheduled to expire on August 21, 2004.

The employment agreement provides that MEHC may terminate the employment of Mr. Sokol with cause, in which case MEHC is to pay to him any accrued but unpaid salary and a bonus of not less than the minimum annual bonus, or due to death, permanent disability or other than for cause, including a change in control, in which case Mr. Sokol is entitled to receive an amount equal to three times the sum of his annual salary then in effect and the greater of his minimum annual bonus or his average annual bonus for the two preceding years, as well as three years of accelerated option vesting plus continuation of his senior executive employee benefits (or the economic equivalent thereof) for three years. If Mr. Sokol resigns, MEHC is to pay to him any accrued but unpaid salary and a bonus of not less than the annual minimum bonus, unless he resigns for good reason in which case he will receive the same benefits as if he were terminated other than for cause.

In the event Mr. Sokol has relinquished his position as Chief Executive Officer and is subsequently terminated as Chairman of the Board due to death, disability or other than for cause, he is entitled to any accrued but unpaid salary plus an amount equal to the aggregate annual salary that would have been paid to him through the fifth anniversary of the date he commenced his employment solely as Chairman of the Board, the immediate vesting of all of his options and the continuation of his senior executive employee benefits (or the economic equivalent thereof) through this fifth anniversary. If Mr. Sokol relinquishes his position as Chief Executive Officer but offers to remain employed as the Chairman of the Board, he is to receive a special achievement bonus equal to two times the sum of his annual salary then in effect and the greater of his minimum annual bonus or his average annual bonus for the two preceding years, as well as two years of accelerated option vesting.

Under the terms of separate employment agreements with MEHC, each of Messrs. Abel and Goodman is entitled to receive two years base salary continuation, payments in respect of average bonuses for the prior two years and two years continued option vesting in the event MEHC terminates his employment other than for cause. If such persons were terminated without cause, Messrs. Sokol, Abel and Goodman would currently be entitled to be paid approximately $10,650,000, $5,750,000 and $1,200,000, respectively, without giving effect to any tax related provisions.

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Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The following table sets forth certain information regarding beneficial ownership of the shares of MEHC's common stock and certain information with respect to the beneficial ownership of each director, its Named Executive Officers and all directors and executive officers as a group as of January 31, 2004.

Name and Address of Beneficial Owner(1)				Number of Shares Beneficially Owned(2)				Percentage of Class(2)
Common Stock:
Walter Scott, Jr. (3)					5,000,000				55.06	%
David L. Sokol (4)					1,523,482				14.54	%
Berkshire Hathaway Inc. (5)					900,942				9.92	%
Gregory E. Abel (6)					704,992				7.25	%
W. David Scott (7)					624,350				6.88	%
Douglas L. Anderson					—				—
Edgar D. Aronson					—				—
Stanley J. Bright					—				—
John K. Boyer					—				—
Warren E. Buffett (8)					—				—
Patrick J. Goodman					—				—
Marc D. Hamburg (8)					—				—
Richard R. Jaros					—				—
Keith D. Hartje					—				—
All directors and executive officers as a group (14 persons)					8,753,766				77.40	%

(1)	Unless otherwise indicated, each address is c/o MEHC at 666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309.

(2)	Includes shares which the listed beneficial owner is deemed to have the right to acquire beneficial ownership under Rule 13d-3(d) under the Securities Exchange Act, including, among other things, shares which the listed beneficial owner has the right to acquire within 60 days.

(3)	Excludes 3 million shares held by family members and family controlled trusts and corporations ("Scott Family Interests") as to which Mr. Scott disclaims beneficial ownership. Such beneficial owner's address is 1000 Kiewit Plaza, Omaha, Nebraska 68131.

(4)	Includes options to purchase 1,399,277 shares of common stock that are exercisable within 60 days.

(5)	Such beneficial owner's address is 1440 Kiewit Plaza, Omaha, Nebraska 68131.

(6)	Includes options to purchase 649,052 shares of common stock which are exercisable within 60 days. Excludes 10,041 shares reserved for issuance pursuant to a deferred compensation plan.

(7)	Includes shares held by trusts for the benefit of or controlled by W. David Scott. Such beneficial owner's address is 11422 Miracle Hills Drive, Suite 400, Omaha, Nebraska 68154.

(8)	Excludes 900,942 shares of common stock held by Berkshire Hathaway Inc. of which beneficial ownership of such shares is disclaimed.

The terms of MEHC's Zero Coupon Convertible Preferred Stock held by Berkshire Hathaway entitle the holder thereof to elect two members of its Board of Directors. The Zero Coupon Convertible Preferred Stock does not vote as to the election of any other members of MEHC's Board of Directors. Mr. Sokol's employment agreement gives him the right during the term of his employment to serve as a member of the Board of Directors and to designate two additional directors.

Pursuant to a shareholders agreement, following March 14, 2003, Walter Scott, Jr. or any of the Scott Family Interests are able to require Berkshire Hathaway to purchase, for an agreed value or an appraised value, any or all of Walter Scott, Jr.'s and the Scott Family Interests' shares of MEHC's common stock,

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provided that Berkshire Hathaway is then a purchaser of a type which is able to consummate such a purchase without causing it or any of its affiliates or MEHC or any of its subsidiaries to become subject to regulation as a registered holding company or a subsidiary of a registered holding company under PUHCA. Berkshire Hathaway is not currently such a purchaser. The consummation of such a transaction could result in a change in control with respect to MEHC.

MEHC's Amended and Restated Articles of Incorporation provide that each share of the Zero Coupon Convertible Preferred Stock is convertible at the option of the holder thereof into one conversion unit, which is one share of its common stock subject to certain adjustments as described in its articles, upon the occurrence of a Conversion Event. A "Conversion Event" includes (1) any conversion of Zero Coupon Convertible Preferred Stock that would not cause the holder of the shares of common stock issued upon conversion (or any affiliate of such holder) or the Company to become subject to regulation as a registered holding company or as a subsidiary of a registered holding company under PUHCA either as a result of the repeal or amendment of PUHCA, the number of shares involved or the identity of the holder of such shares and (2) a Company Sale. A "Company Sale" includes MEHC's involuntary or voluntary liquidation, dissolution, recapitalization, winding-up or termination and mergers, consolidations or sale of all or substantially all of its assets. The conversion by Berkshire Hathaway of its shares of Zero Coupon Convertible Preferred Stock into MEHC's common stock could result in a change in control with respect to beneficial ownership of its voting securities as calculated pursuant to Rule 13d-3(d) under the Securities Exchange Act.

Item 13.    Certain Relationships and Related Transactions.

Under a subscription agreement with MEHC, Berkshire Hathaway has agreed to purchase, under certain circumstances, additional 11% trust issued mandatorily redeemable preferred securities in the event that certain outstanding trust preferred securities of MEHC which were outstanding prior to the closing of its acquisition by a private investor group on March 14, 2000 are tendered for conversion to cash by the current holders.

MEHC provided a guarantee in favor of a third party lender in connection with a $1,663,998.75 loan from such lender to its President, Gregory E. Abel, in March 2000. The loan matures on April 1, 2010. The proceeds of this loan were used by Mr. Abel to purchase 47,475 shares of MEHC's common stock. Such common stock (together with 8,465 additional shares of common stock owned by Mr. Abel) also secures the loan. The entire original principal amount of the loan and the guarantee remain presently outstanding.

In order to finance its acquisition of Northern Natural Gas, on August 16, 2002, MEHC sold to Berkshire Hathaway and three of its consolidated subsidiaries $950.0 million in aggregate principal amount of the 11% mandatorily redeemable trust issued preferred securities Series A, of its subsidiary trust, MidAmerican Capital Trust II, due August 31, 2012. The transaction was a private placement pursuant to Section 4(1) of the Securities Act and did not involve any underwriters, underwriting discounts or commissions. Scheduled principal payments began in August 2003. Messrs. Warren E. Buffett and Walter Scott, Jr. are members of the Board of Directors of Berkshire Hathaway. Messrs. Buffett and Marc D. Hamburg are executive officers of Berkshire Hathaway.

MEHC did not purchase any options or securities from its stockholders, directors or executive officers during the year ended December 31, 2003.

On January 6, 2004, MEHC purchased shares of common stock from Mr. Sokol for an aggregate price of $20.0 million.

Compensation Committee Interlocks and Insider Participation

The compensation committee of the Board of Directors is comprised of Messrs. Warren E. Buffett and Walter Scott, Jr.  Mr. Walter Scott, Jr. is a former officer of the Company. See "Certain Relationships and Related Transactions."

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Item 14.    Principal Accountant Fees and Services.

Aggregate fees billed to the Company as a consolidated entity for the fiscal years ending December 31, 2003 and 2002 by the Company's principal accounting firm, Deloitte & Touche LLP and their respective affiliates (collectively, "Deloitte"), are set forth below. The audit committee has considered whether the provision of the non-audit services described below is compatible with maintaining the principal accountant's independence.

				Year Ended December 31,
				2003				2002
				(in millions)
Audit Fees (1)				$	2.6			$	2.2
Audit-Related Fees (2)					0.3				0.4
Tax Fees (3)					0.9				1.3
All Other Fees (4)					—				—
Total aggregate fees billed				$	3.8			$	3.9

(1)

Includes the aggregate fees billed for each of the last two fiscal years for professional services rendered by Deloitte for the audit of the Company's financial statements and review of financial statements included in the Company's Form 10-K or services that are normally provided by Deloitte in connection with statutory and regulatory filings or engagements for those fiscal years.

(2)

Includes the aggregate fees billed for each of the last two fiscal years for assurance and related services by Deloitte that are reasonably related to the performance of the audit or review of the registrant's financial statements. Services included in this category include audits of benefit plans, due diligence for possible acquisitions and consultation pertaining to new and proposed accounting and regulatory rules.

(3)	Includes the aggregate fees billed for each of the last two fiscal years for professional services rendered by Deloitte for tax compliance, tax advice, and tax planning.

(4)	Includes the aggregate fees billed for each of the last two fiscal years for products and services provided by Deloitte, other than the services reported as "Audit Fees", "Audit-Related Fees", or "Tax Fees".

The audit committee reviewed the non-audit services rendered by Deloitte in and for fiscal 2003 as set forth in the above table and concluded that such services were compatible with maintaining the auditors' independence. Under the Sarbanes-Oxley Act of 2002, all audit and non-audit services performed by the Company's independent accountants must now be approved in advance by the audit committee to assure that such services do not impair the accountants' independence from the Company. Accordingly, the audit committee has adopted an Audit and Non-Audit Services Pre-Approval Policy (the "Policy") which sets forth the procedures and the conditions pursuant to which services to be performed by the independent accountants are to be pre-approved. Pursuant to the Policy, certain services described in detail in the Policy may be pre-approved on an annual basis together with pre-approved maximum fee levels for such services. The services eligible for annual pre-approval consist of services that would be included under the categories of Audit Fees, Audit-Related Fees and Tax Fees. If not pre-approved on an annual basis, proposed services must otherwise be separately approved prior to being performed by the independent auditors. In addition, any services that receive annual pre-approval but exceed the pre-approved maximum fee level also will require separate approval by the audit committee prior to being performed. The audit committee may delegate authority to pre-approve audit and non-audit services to any member of the audit committee, but may not delegate such authority to management.

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PART IV

Item 15.    Exhibits, Financial Statement Schedules and Reports on Form 8-K

(a)	Financial Statements and Schedules

(i)	Financial Statements

Financial Statements are included in Item 8 of this Form 10-K.

(ii)	Financial Statement Schedules

See Schedule I on page 111.
See Schedule II on page 114.
Schedules not listed above have been omitted because they are either not applicable, not required or the information required to be set forth therein is included in the consolidated financial statements or notes thereto.

(iii)	Exhibits

See Item 15 (c) below.

(b)	Reports on Form 8-K

MEHC filed the following Current Reports on Form 8-K during the fourth quarter of 2003:

•	MEHC filed a Current Report on Form 8-K on October 15, 2003.

•	MEHC filed a Current Report on Form 8-K on October 17, 2003.

•	MEHC filed an amended Current Report on Form 8-K on October 21, 2003.

(c)	Exhibits

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

(d)	Financial statements required by Regulation S-X, which are excluded from the Annual Report by Rule 14a-3(b).

Not applicable.

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MidAmerican Energy Holdings Company	Schedule I
Parent Company Only
Condensed Balance Sheets As of December 31, 2003 and 2002 (Amounts in thousands)

				2003				2002
ASSETS
Current assets — Cash and cash equivalents				$	328,750			$	320,629
Investments in and advances to subsidiaries and joint ventures					5,728,125				5,264,786
Equipment, net					15,388				15,984
Goodwill					1,370,241				1,381,009
Deferred charges and other assets					180,331				150,056
Total assets				$	7,622,835			$	7,132,464
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities: Accounts payable and other accrued liabilities				$	49,144			$	94,389
Current portion of long-term debt					—				215,000
Current portion of subordinated debt					100,000				—
Total current liabilities ..					149,144				309,389
Non-current liabilities					31,298				11,885
Notes payable — affiliate					86,045				94,795
Senior debt					2,777,878				2,323,387
Subordinated debt					1,772,146				—
Total liabilities					4,816,511				2,739,456
Deferred income					32,916				35,313
Minority interest					1,963				—
Company-obligated mandatorily redeemable preferred securities of subsidiary trusts					—				2,063,412
Stockholders' equity:
Zero coupon convertible preferred stock — authorized 50,000 shares, no par value; 41,263 shares outstanding at December 31, 2003 and 2002					—				—
Common stock — authorized 60,000 shares, no par value; 9,281 shares outstanding at December 31, 2003 and 2002					—				—
Additional paid in capital					1,957,277				1,956,509
Retained earnings					999,627				584,009
Accumulated other comprehensive loss, net					(185,459	)			(246,235	)
Total stockholders' equity					2,771,445				2,294,283
Total liabilities and stockholders' equity				$	7,622,835			$	7,132,464

The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.

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MidAmerican Energy Holdings Company	Schedule I
Parent Company Only (continued)
Condensed Statements of Operations For the three years ended December 31, 2003 (Amounts in thousands)

				2003				2002				2001
Revenue:
Equity in undistributed earnings of subsidiary companies and joint ventures				$	785,072			$	477,588			$	608,896
Dividends and distributions from subsidiary companies and joint ventures					318,665				351,847				87,625
Interest and other income					19,808				1,286				2,248
Total revenue					1,123,545				830,721				698,769
Costs and expenses:
General and administration					34,517				29,368				41,078
Depreciation and amortization					710				815				31,537
Interest, net of capitalized interest					251,578				173,240				148,680
Total costs and expenses ..					286,805				203,423				221,295
Income before provision for income taxes					836,740				627,298				477,474
Provision for income taxes					250,971				99,588				250,064
Income before minority interest					585,769				527,710				227,410
Minority interest and preferred dividends					170,151				147,667				80,137
Income before and cumulative effect of change in accounting principle					415,618				380,043				147,273
Cumulative effect of change in accounting principle, net of tax					—				—				(4,604	)
Net income available to common stockholders				$	415,618			$	380,043			$	142,669

The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.

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MidAmerican Energy Holdings Company	Schedule I
Parent Company Only (continued)
Condensed Statements of Cash Flows For the three years ended December 31, 2003 (Amounts in thousands)

				2003				2002				2001
Cash flows from operating activities				$	(260,271	)		$	(188,300	)		$	(272,906	)
Cash flows from investing activities:
Decrease (increase) in advances to and investments in subsidiaries and joint ventures					205,206				(1,692,742	)			204,118
Other, net					30,995				10,307				(5,297	)
Net cash flows from investing activities					236,201				(1,682,435	)			198,821
Cash flows from financing activities:
Proceeds from issuance of common and preferred stock					—				402,000				—
Proceeds from issuance of trust preferred securities					—				1,273,000				—
Repayment of subordinated debt					(198,958	)			—				—
Proceeds from issuances of senior debt					449,295				700,000				—
Repayments of senior debt					(215,000	)			—				(32	)
Net (repayment of) proceeds from corporate revolving credit facility					—				(153,500	)			68,500
Other					(3,146	)			(32,660	)			(82	)
Net cash flows from financing activities					32,191				2,188,840				68,386
Net change in cash and cash equivalents					8,121				318,105				(5,699	)
Cash and cash equivalents at beginning of year					320,629				2,524				8,223
Cash and cash equivalents at end of year				$	328,750			$	320,629			$	2,524
Supplemental disclosures:
Interest paid, net of interest capitalized				$	219,910			$	164,267			$	148,999
Income taxes paid				$	9,911			$	101,225			$	133,139

The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.

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Schedule II

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2002
(Amounts in thousands)

Column A Description				Column B Balance at Beginning of Year				Column C Additions												Column D Deductions				Column E Balance at End of Year
								Charged to Income				Other Accounts				Acquisition Reserves(2)
Reserves Deducted From Assets
To Which They Apply:
Reserve for uncollectible accounts receivable:
Year ended 2003				$	39,742			$	13,620			$	—			$	—			$	(27,358	)		$	26,004
Year ended 2002				$	7,319			$	27,782			$	—			$	10,142			$	(5,501	)		$	39,742
Year ended 2001				$	32,685			$	17,061			$	—			$	—			$	(42,427	)		$	7,319
Reserves Not Deducted From Assets (1):
Year ended 2003				$	10,981			$	10,527			$	—			$	—			$	(4,091	)		$	17,417
Year ended 2002				$	13,631			$	2,798			$	247			$	—			$	(5,695	)		$	10,981
Year ended 2001				$	25,063			$	5,046			$	—			$	—			$	(16,478	)		$	13,631

The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.

(1)	Reserves not deducted from assets include estimated liabilities for losses retained by MEHC for workers compensation, public liability and property damage claims

(2)	Acquisition reserves represent the reserves recorded at Kern River and Northern Natural Gas at the date of acquisition.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, in the City of Des Moines, State of Iowa, on this 9^th day of February 2004.

MIDAMERICAN ENERGY HOLDINGS COMPANY

/s/ David L. Sokol*

David L. Sokol Chairman of the Board and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature				Date
/s/ David L. Sokol* __________________________ David L. Sokol Chairman of the Board, Chief Executive Officer, and Director				February 9, 2004
/s/ Gregory E. Abel* __________________________ Gregory E. Abel President, Chief Operating Officer and Director				February 9, 2004
/s/ Patrick J. Goodman* __________________________ Patrick J. Goodman Senior Vice President and Chief Financial Officer				February 9, 2004
/s/ Edgar D. Aronson* __________________________ Edgar D. Aronson Director				February 9, 2004
/s/ Stanley J. Bright* __________________________ Stanley J. Bright Director				February 9, 2004
/s/ Walter Scott, Jr.* __________________________ Walter Scott, Jr. Director				February 9, 2004
/s/ Marc D. Hamburg* __________________________ Marc D. Hamburg Director				February 9, 2004
/s/ Warren E. Buffett* __________________________ Warren E. Buffett Director				February 9, 2004

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Signature				Date
/s/ John K. Boyer* __________________________ John K. Boyer Director				February 9, 2004
/s/ W. David Scott* __________________________ W. David Scott Director				February 9, 2004
/s/ Richard R. Jaros* __________________________ Richard R. Jaros Director				February 9, 2004
*By: /s/ Douglas L. Anderson ______________________				February 9, 2004
Douglas L. Anderson Attorney-in-Fact

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EXHIBIT INDEX

Exhibit No.
3.1				Amended and Restated Articles of Incorporation of MEHC effective March 6, 2002 (incorporated by reference to Exhibit 3.3 to MEHC's Annual Report on Form 10-K for the year ended December 31, 2001).
3.2				Bylaws of MEHC (incorporated by reference to Exhibit 3.2 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
4.1				Indenture, dated as of October 4, 2002, by and between MEHC and The Bank of New York, relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due 2012 (incorporated by reference to Exhibit 4.1 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
4.2				First Supplemental Indenture, dated as of October 4, 2002, by and between MEHC and The Bank of New York, relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due 2012 (incorporated by reference to Exhibit 4.2 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
4.3				Registration Rights Agreement, dated as of October 1, 2002, by and between MEHC and Credit Suisse First Boston (as Representative for the Initial Purchasers) (incorporated by reference to Exhibit 4.3 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
4.4				Indenture for the 6 1/4% Convertible Junior Subordinated Debentures due 2012, dated as of February 26, 1997, between MEHC, as issuer, and the Bank of New York, as Trustee (incorporated by reference to Exhibit 10.129 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1995).
4.5				Indenture, dated as of October 15, 1997, among MEHC and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to MEHC's Current Report on Form 8-K dated October 23, 1997).
4.6				Form of First Supplemental Indenture for the 7.63% Senior Notes in the principal amount of $350,000,000 due 2007, dated as of October 28, 1997, among MEHC and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.2 to MEHC's Current Report on Form 8-K dated October 23, 1997).
4.7				Form of Second Supplemental Indenture for the 6.96% Senior Notes in the principal amount of $215,000,000 due 2003, 7.23% Senior Notes in the principal amount of $260,000,000 due 2005, 7.52% Senior Notes in the principal amount of $450,000,000 due 2008, and 8.48% Senior Notes in the principal amount of $475,000,000 due 2028, dated as of September 22, 1998 between MEHC and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to MEHC's Current Report on Form 8-K dated September 17, 1998.)
4.8				Form of Third Supplemental Indenture for the 7.52% Senior Notes in the principal amount of $100,000,000 due 2008, dated as of November 13, 1998, between MEHC and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to MEHC's Current Report on Form 8-K dated November 10, 1998).
4.9				Indenture, dated as of March 14, 2000, among MEHC and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.9 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
4.10				Subscription Agreement, dated as of March 14, 2000, executed by Berkshire Hathaway Inc. (incorporated by reference to Exhibit 4.10 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).

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Exhibit No.
4.11				Indenture, dated as of March 12, 2002, between MEHC and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.11 to MEHC's Annual Report on Form 10-K for the year ended December 31, 2001).
4.12				Subscription Agreement, dated as of March 7, 2002, executed by Berkshire Hathaway Inc. (incorporated by reference to Exhibit 4.12 to MEHC's Annual Report on Form 10-K for the year ended December 31, 2001).
4.13				Subscription Agreement, dated as of March 12, 2002, executed by Berkshire Hathaway Inc. (incorporated by reference to Exhibit 4.13 to MEHC's Annual Report on Form 10-K for the year ended December 31, 2001).
4.14				Amended and Restated Declaration of Trust of MidAmerican Capital Trust III, dated as of August 16, 2002 (incorporated by reference to Exhibit 4.14 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
4.15				Amended and Restated Declaration of Trust of MidAmerican Capital Trust II, dated as of March 12, 2002 (incorporated by reference to Exhibit 4.15 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
4.16				Amended and Restated Declaration of Trust of MidAmerican Capital Trust I, dated as of March 14, 2000 (incorporated by reference to Exhibit 4.16 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
4.17				Indenture, dated as of August 16, 2002, between MEHC and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.17 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
4.18				Subscription Agreement, dated as of August 16, 2002, executed by Berkshire Hathaway Inc. (incorporated by reference to Exhibit 4.18 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
4.19				Shareholders Agreement, dated as of March 14, 2000 (incorporated by reference to Exhibit 4.19 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
10.1				Employment Agreement between MEHC and David L. Sokol, dated May 10, 1999 (incorporated by reference to Exhibit 10.1 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
10.2				Amendment No. 1 to the Amended and Restated Employment Agreement between MEHC and David L. Sokol, dated March 14, 2000 (incorporated by reference to Exhibit 10.2 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
10.3				Non-Qualified Stock Options Agreements of David L. Sokol, dated March 14, 2000 (incorporated by reference to Exhibit 10.3 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
10.4				Amended and Restated Employment Agreement between MEHC and Gregory E. Abel, dated May 10, 1999 (incorporated by reference to Exhibit 10.3 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
10.5				Non-Qualified Stock Options Agreements of Gregory E. Abel, dated March 14, 2000 (incorporated by reference to Exhibit 10.5 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
10.6				Employment Agreement between MEHC and Patrick J. Goodman, dated April 21, 1999 (incorporated by reference to Exhibit 10.5 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).

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Exhibit No.
10.7				MidAmerican Energy Holdings Company, Amended and Restated Long Term Incentive Partnership Plan dated as of January 1, 2003 (incorporated by reference to Exhibit 10.1 of MEHC's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003).
10.8				125 MW Power Plant-Upper Mahiao Agreement, dated September 6, 1993, between PNOC-Energy Development Corporation and Ormat, Inc. as amended by the First Amendment to 125 MW Power Plant Upper Mahiao Agreement, dated as of January 28, 1994, the Letter Agreement dated February 10, 1994, the Letter Agreement dated February 18, 1994 and the Fourth Amendment to 125 MW Power Plant-Upper Mahiao Agreement, dated as of March 7, 1994 (incorporated by reference to Exhibit 10.95 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.9				Credit Agreement, dated April 8, 1994, among CE Cebu Geothermal Power Company, Inc., the Banks thereto, Credit Suisse as Agent (incorporated by reference to Exhibit 10.96 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.10				Credit Agreement, dated as of April 8, 1994, between CE Cebu Geothermal Power Company, Inc., Export-Import Bank of the United States (incorporated by reference to Exhibit 10.97 to MEHC'sAnnual Report on Form 10-K for the year ended December 31, 1993).
10.11				Pledge Agreement, dated as of April 8, 1994, among CE Philippines Ltd, Ormat-Cebu Ltd., Credit Suisse as Collateral Agent and CE Cebu Geothermal Power Company, Inc. (incorporated by reference to Exhibit 10.98 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.12				Overseas Private Investment Corporation Contract of Insurance, dated April 8, 1994, between the Overseas Private Investment Corporation and the Company through its subsidiaries CE International Ltd., CE Philippines Ltd., and Ormat-Cebu Ltd. (incorporated by reference to Exhibit 10.99 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.13				180 MW Power Plant-Mahanagdong Agreement, dated September 18, 1993, between PNOC-Energy Development Corporation and CE Philippines Ltd. and the Company, as amended by the First Amendment to Mahanagdong Agreement, dated June 22, 1994, the Letter Agreement dated July 12, 1994, the Letter Agreement dated July 29, 1994, and the Fourth Amendment to Mahanagdong Agreement, dated March 3, 1995 (incorporated by reference to Exhibit 10.1 00 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.14				Credit Agreement, dated as of June 30, 1994, among CE Luzon Geothermal Power Company, Inc., American Pacific Finance Company, the Lenders party thereto, and Bank of America National Trust and Savings Association as Administrative Agent (incorporated by reference to Exhibit 10.101 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.15				Credit Agreement, dated as of June 30, 1994, between CE Luzon Geothermal Power Company, Inc. and Export-Import Bank of the United States (incorporated by reference to Exhibit 10.102 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.16				Finance Agreement, dated as of June 30, 1994, between CE Luzon Geothermal Power Company, Inc. and Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.103 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).

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Exhibit No.
10.17				Pledge Agreement, dated as of June 30, 1994, among CE Mahanagdong Ltd., Kiewit Energy International (Bermuda) Ltd., Bank of America National Trust and Savings Association as Collateral Agent and CE Luzon Geothermal Power Company, Inc. (incorporated by reference to Exhibit 10.104 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.18				Overseas Private Investment Corporation Contract of Insurance, dated July 29, 1994, between Overseas Private Investment Corporation and the Company, CE International Ltd., CE Mahanagdong Ltd. and American Pacific Finance Company and Amendment No. 1, dated August 3, 1994 (incorporated by reference to Exhibit 10.105 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.19				231 MW Power Plant-Malitbog Agreement, dated September 10, 1993, between PNOC-Energy Development Corporation and Magma Power Company and the First and Second Amendments thereto, dated December 8, 1993 and March 10, 1994, respectively (incorporated by reference to Exhibit 10.106 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.20				Credit Agreement, dated as of November 10, 1994, among Visayas Power Capital Corporation, the Banks parties thereto and Credit Suisse, as Bank Agent (incorporated by reference to Exhibit 10.107 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.21				Finance Agreement, dated as of November 10, 1994, between Visayas Geothermal Power Company and Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.108 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.22				Pledge and Security Agreement, dated as of November 10, 1994, among Broad Street Contract Services, Inc., Magma Power Company, Magma Netherlands B.V. and Credit Suisse, as Bank Agent (incorporated by reference to Exhibit 10.109 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1993).
10.23				Overseas Private Investment Corporation Contract of Insurance, dated December 21, 1994,between Overseas Private Investment Corporation and Magma Netherlands, B.V. (incorporated by reference to Exhibit 10.110 to MEHC's Annual Report on Form10-K for the year ended December 31, 1993).
10.24				Agreement as to Certain Common Representations, Warranties, Covenants and Other Terms, dated November 10, 1994, between Visayas Geothermal Power Company, Visayas Power Capital Corporation, Credit Suisse, as Bank Agent, Overseas Private Investment Corporation and the Banks named therein (incorporated by reference to Exhibit 10.111 to MEHC's 1994 Annual Report on Form 10-K for the year ended December 31, 1993).
10.25				Trust Indenture, dated as of November 27, 1995, between the CE Casecnan Water and Energy Company, Inc. and Chemical Trust Company of California (incorporated by reference to Exhibit 4.1 to CE Casecnan Water and Energy Company, Inc.'s Registration Statement on Form S-4 dated January 25, 1996).
10.26				Amended and Restated Casecnan Project Agreement, dated June 26, 1995, between the National Irrigation Administration and CE Casecnan Water and Energy Company Inc. (incorporated by reference to Exhibit 10.1 to CE Casecnan Water and Energy Company, Inc.'s Registration Statement on Form S-4 dated January 25, 1996).

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Exhibit No.
10.27				Term Loan and Revolving Facility Agreement, dated as of October 28, 1996, among CE Electric UK Holdings, CE Electric UK plc and Credit Suisse (incorporated by reference to Exhibit 10.130 to MEHC's Annual Report on Form 10-K for the year ended December 31, 1995).
10.28				Indenture and First Supplemental Indenture, dated March 11, 1999, between MidAmerican Funding LLC and IBJ Whitehall Bank & Trust Company and the First Supplement thereto relating to the $700 million Senior Notes and Bonds (incorporated by reference to MEHC's Annual Report on Form 10-K for the year ended December 31, 1998).
10.29				General Mortgage Indenture and Deed of Trust, dated as of January 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-1 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654).
10.30				First Supplemental Indenture, dated as of January 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-2 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654).
10.31				Second Supplemental Indenture, dated as of January 15, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-3 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654).
10.32				Third Supplemental Indenture, dated as of May 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4.4 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-10654).
10.33				Fourth Supplemental Indenture, dated as of October 1, 1994, between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.5 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654).
10.34				Fifth Supplemental Indenture, dated as of November 1, 1994, between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.6 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654).
10.35				Sixth Supplemental Indenture, dated as of July 1, 1995, between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.15 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 1995, Commission File No. 1-11505).
10.36				Indenture of Mortgage and Deed of Trust, dated as of March 1, 1947 (incorporated by reference to Exhibit 7B filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 2-6922).
10.37				Sixth Supplemental Indenture, dated as of July 1, 1967 (incorporated by reference to Exhibit 2.08 filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 2-28806).
10.38				Twentieth Supplemental Indenture, dated as of May 1, 1982 (incorporated by reference to Exhibit 4.B.23 to the Iowa-Illinois Gas and Electric Company Quarterly Report on Form 10-Q for the period ended June 30, 1982, Commission File No. 1-3573).

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Exhibit No.
10.39				Resignation and Appointment of successor Individual Trustee (incorporated by reference to Exhibit 4.B.30 filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 33-39211).
10.40				Twenty-Eighth Supplemental Indenture, dated as of May 15, 1992 (incorporated by reference to Exhibit 4.31.B to the Iowa-Illinois Gas and Electric Company Current Report on Form 8-K dated May 21, 1992, Commission File No. 1-3573).
10.41				Supplemental Agreement between CE Casecnan Water and Energy Company, Inc. and the Philippines National Irrigation Administration dated as of September 29, 2003.
10.42				Thirtieth Supplemental Indenture, dated as of October 1, 1993 (incorporated by reference to Exhibit 4.34.A to the Iowa-Illinois Gas and Electric Company Current Report on Form 8-K, dated October 7, 1993, Commission File No. 1-3573).
10.43				Thirty-First Supplemental Indenture, dated as of July 1, 1995, between Iowa-Illinois Gas and Electric Company and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.16 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended dated December 31, 1995, Commission File No. 1-11505).
10.44				Sixth Amendment to 180 MW Power Plant-Mahanagdong Agreement, dated August 31, 2003, between PNOC-Energy Development Corporation and CE Luzon Geothermal Power Company, Inc.
10.45				Third Amendment to 231 MW Power Plant-Malitbog Agreement, dated August 31, 2003, between PNOC-Energy Development Corporation and Visayas Geothermal Power Company, Inc.
10.46				Seventh Amendment to 125 MW Power Plant-Upper Mahiao Agreement, dated August 31, 2003, between PNOC-Energy Development Corporation and CE Cebu Geothermal Power Company, Inc.
10.47				Fiscal Agency Agreement, dated as of October 15, 2002, between Northern Natural Gas Company and J.P. Morgan Trust Company, National Association, Fiscal Agent, relating to the $300,000,000 in principal amount of the 5.375% Senior Notes due 2012.
10.48				Trust Indenture, dated as of August 13, 2001, among Kern River Funding Corporation, Kern River Gas Transmission Company and the JP Morgan Chase Bank, as Trustee, relating to the $510,000,000 in principal amount of the 6.676% Senior Notes due 2016.
10.49				Third Supplemental Indenture, dated as of May 1, 2003, among Kern River Funding Corporation, Kern River Gas Transmission Company and JPMorgan Chase Bank, as Trustee, relating to the $836,000,000 in principal amount of the 4.893% Senior Notes due 2018.
10.50				CalEnergy Company, Inc. Voluntary Deferred Compensation Plan, effective December 1, 1997, First Amendment, dated as of August 17, 1999, and Second Amendment effective March 2000 (incorporated by reference to Exhibit 10.50 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
10.51				MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan (incorporated by reference to Exhibit 10.51 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
10.52				MidAmerican Energy Company First Amended and Restated Supplemental Retirement Plan for Designated Officers dated as of May 10, 1999 (incorporated by reference to Exhibit 10.52 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).

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Exhibit No.
10.53				MidAmerican Energy Company Restated Executive Deferred Compensation Plan (incorporated by reference to Exhibit 10.6 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
10.54				MidAmerican Energy Holdings Company Restated Deferred Compensation Plan-Board of Directors (incorporated by reference to Exhibit 10 to MEHC's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999).
10.55				MidAmerican Energy Company Combined Midwest Resources/Iowa Resources Restated Deferred Compensation Plan-Board of Directors (incorporated by reference to Exhibit 10.63 to MEHC's Annual Report on Form 10-K/A for the year ended December 31, 1999).
10.56				Midwest Resources Inc. Supplemental Retirement Plan (formerly the Midwest Energy Company Supplemental Retirement Plan (incorporated by reference to Exhibit 10.10 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-10654).
10.57				Amendment No. 1 to the Midwest Resources Inc. Supplemental Retirement Plan (incorporated by reference to Exhibit 10.24 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654).
10.58				Iowa-Illinois Gas and Electric Company Supplemental Retirement Plan for Designated Officers, as amended as of July 28, 1994 (incorporated by reference to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-3573).
10.59				Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for Designated Officers, as amended as of July 1, 1993 (incorporated by reference to Exhibit 10.K.2 to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-3573).
10.60				Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for Key Employees, dated as of April 26, 1991 (incorporated by reference to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1991, Commission File No. 1-3573).
10.61				Iowa-Illinois Gas and Electric Company Board of Directors' Compensation Deferral Plan (incorporated by reference to Exhibit 10.K.4 to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-3573).
10.62				Iowa Utilities Board Settlement Agreement among MidAmerican Energy Company, Office of Consumer Advocate, Iowa Energy Consumers, Aluminum Company of America, Deere & Company, Cargill Inc., U.S. Gypsum Company, Interstate Power Company and IES Utilities, Inc. (incorporated by reference to Exhibit 10.16 to the MidAmerican Funding, LLC and MidAmerican Energy Company respective Annual Reports on the combined Form 10-K for the year ended December 31, 2000, Commission File Nos. 333-90553 and 1-11505, respectively).
10.63				Share Sale Agreement, dated as of August 6, 2001, among NPower Yorkshire Limited, Innogy Holdings plc, CE Electric UK plc and Northern Electric plc (incorporated by reference to Exhibit 10.63 of MEHC's Registration Statement No. 333-101699 dated December 6, 2002).
10.64				Purchase Agreement, dated as of March 7, 2002, among The Williams Companies, Inc., Williams Gas Pipeline Company, LLC, Williams Western Pipeline Company LLC, Kern River Acquisition, LLC and MEHC, KR Holding, LLC, KR Acquisition 1, LLC and KR Acquisition 2, LLC (incorporated by reference to Exhibit 99.2 to MEHC's Current Report on Form 8-K dated March 28, 2002).

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Exhibit No.
10.65				MidAmerican Energy Holdings Company Executive Incremental Profit Sharing Plan (incorporated by reference to Exhibit 10.2 of MEHC's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003.)
10.67				Purchase and Sale Agreement, dated as of July 28, 2002, between Dynegy Inc., NNGC Holding Company, Inc. and MEHC (incorporated by reference to Exhibit 99.2 to MEHC's Current Report on Form 8-K dated July 30, 2002).
14.1				MidAmerican Energy Holdings Company Code of Ethics for Chief Executive Officer, Chief Financial Officer and Other Covered Officers.
21.1				Subsidiaries of the Registrant.
24.1				Power of Attorney.
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.

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