(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Douglas L. Anderson
General Counsel
MidAmerican Energy Holdings Company
1111 South 103^rd Street
Omaha, Nebraska 68124
(402) 231-1642

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copy to:
Peter J. Hanlon, Esq.
Willkie Farr & Gallagher LLP
787 Seventh Avenue
New York, New York 10019
(212) 728-8000

Approximate date of commencement of proposed sale to the public: As soon as practicable following the effective date of this Registration Statement.

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box.

If this Form is filed to register additional securities for an offering pursuant to Rule 462(6) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.

The registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Up to $650,000,000 in aggregate principal amount of registered 5.75%
Senior Notes due April 1, 2018 for
all outstanding Unregistered 5.75% Senior Notes due April 1, 2018

See ‘‘Risk Factors’’ beginning on page 10 for a discussion of matters you should consider before you participate in the exchange offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

In this prospectus, references to ‘‘we,’’ ‘‘our’’ and ‘‘us’’ are to MidAmerican Energy Holdings Company (or MEHC) and, except as the context otherwise requires, its consolidated subsidiaries and, as applicable, its equity investments.

In this prospectus, references to ‘‘initial notes’’ are to the privately placed $650,000,000 aggregate principal amount of 5.75% Senior Notes due 2018, references to ‘‘exchange notes’’ are to the new 5.75% Senior Notes due 2018, which will be registered under the Securities Act of 1933, as amended, or the Securities Act, and references to ‘‘notes’’ are to, collectively, the initial notes and the exchange notes.

In this prospectus, references to ‘‘U.S. dollars,’’ ‘‘dollars,’’ ‘‘$’’ and ‘‘cents’’ are to the currency of the U.S. and references to ‘‘£’’ and ‘‘sterling’’ are to the currency of Great Britain. References to kW mean kilowatts, MW means megawatts, GW means gigawatts, kWh means kilowatt hours, MWh means megawatt hours, GWh means gigawatt hours, kV means kilovolts, MMcf means million cubic feet, Bcf means billion cubic feet, Dth means decatherms or one million British thermal units and Dthd means decatherms per day.

No dealer, salesperson or other individual has been authorized to give any information or to make any representations not contained in this prospectus in connection with the exchange offer. If given or made, such information or representations must not be relied upon as having been authorized by us. Neither the delivery of this prospectus nor any sale made hereunder shall, under any circumstances, create any implications that there has not been any change in the facts set forth in this prospectus or in our affairs since the date hereof.

acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an ‘‘underwriter’’ within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of the exchange notes received in exchange for initial notes where such initial notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 120 days after the expiration of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any such resales. See ‘‘Plan of Distribution.’’

NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A LICENSE HAS BEEN FILED UNDER CHAPTER 421-B OF THE NEW HAMPSHIRE REVISED STATUTES WITH THE STATE OF NEW HAMPSHIRE NOR THE FACT THAT A SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENSED IN THE STATE OF NEW HAMPSHIRE CONSTITUTES A FINDING BY THE SECRETARY OF STATE OF THE STATE OF NEW HAMPSHIRE THAT ANY DOCUMENT FILED UNDER CHAPTER 421-B IS TRUE, COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THE FACT THAT AN EXEMPTION OR EXCEPTION IS AVAILABLE FOR A SECURITY OR A TRANSACTION MEANS THAT THE SECRETARY OF STATE HAS PASSED IN ANY WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GIVEN APPROVAL TO, ANY PERSON, SECURITY OR TRANSACTION. IT IS UNLAWFUL TO MAKE, OR CAUSE TO BE MADE, TO ANY PROSPECTIVE PURCHASER, CUSTOMER, OR CLIENT ANY REPRESENTATION INCONSISTENT WITH THE PROVISIONS OF THIS PARAGRAPH.

This section contains a general summary of certain of the information contained in this prospectus. It does not include all of the information that may be important to you. You should read this entire prospectus, including the ‘‘Risk Factors’’ section and the financial statements and notes to those statements, before making an investment decision.

We are a holding company which owns subsidiaries that are principally engaged in energy businesses. We are a consolidated subsidiary of Berkshire Hathaway Inc. (or Berkshire Hathaway). The balance of our common stock is owned by a private investor group comprised of Mr. Walter Scott, Jr. (along with family members and related entities), who is a member of our Board of Directors, Mr. David L. Sokol, our Chairman, and Mr. Gregory E. Abel, our President and Chief Executive Officer. As of March 31, 2008, Berkshire Hathaway, Mr. Scott (along with family members and related entities), Mr. Sokol and Mr. Abel owned 88.2%, 11.0%, —% and 0.8%, respectively, of our voting common stock and held diluted ownership interests of 87.4%, 10.9%, 0.7% and 1.0% respectively.

On March 1, 2006, we and Berkshire Hathaway entered into an Equity Commitment Agreement (or the Berkshire Equity Commitment) pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of our common equity upon any requests authorized from time to time by our Board of Directors. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due MEHC’s debt obligations and (b) funding the general corporate purposes and capital requirements of our regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request in minimum increments of at least $250 million pursuant to one or more drawings authorized by our Board of Directors. The funding of each drawing will be made by means of a cash equity contribution to us in exchange for additional shares of our common stock. The Berkshire Equity Commitment will expire on February 28, 2011.

Our operations are organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding, LLC (or MidAmerican Funding) (which primarily includes MidAmerican Energy Company (or MidAmerican Energy)), Northern Natural Gas Company (or Northern Natural Gas), Kern River Gas Transmission Company (or Kern River), CE Electric UK Funding Company (or CE Electric UK) (which primarily consists of Northern Electric Distribution Limited (or Northern Electric) and Yorkshire Electricity Distribution plc (or Yorkshire Electricity)), CalEnergy Generation-Foreign (owning a majority interest in the Casecnan project in the Philippines), CalEnergy Generation-Domestic (owning interests in independent power projects in the U.S.), and HomeServices of America, Inc. (or collectively with its subsidiaries, HomeServices). Refer to Note 12 of our Notes to unaudited interim Consolidated Financial Statements and Note 23 of our Notes to audited Consolidated Financial Statements included in the ‘‘Financial Statements’’ section of this prospectus for additional segment information regarding our platforms. Through these platforms, we own and operate an electric utility company in the Western U.S., a combined electric and natural gas utility company in the Midwestern U.S., two interstate natural gas pipeline companies in the U.S., two electricity distribution companies in Great Britain, a diversified portfolio of independent power projects and the second-largest residential real estate brokerage firm in the U.S.

generation facilities in operation and under construction, including approximately 16,000 net owned MW in facilities that are part of the regulated asset base of our electric utility businesses and approximately 1,000 net owned MW in non-utility power generation facilities. The majority of our non-utility power generation facilities sell substantially all of their power under long-term contracts.

Our principal executive offices are located at 666 Grand Avenue, Suite 500, Des Moines, Iowa 50309-2580, and our telephone number is (515) 242-4300.

On March 28, 2008, we privately placed $650,000,000 aggregate principal amount of 5.75% Senior Notes due 2018, which we refer to as the initial notes, in a transaction exempt from registration under the Securities Act. In connection with the private placement, we entered into a registration rights agreement, dated as of March 28, 2008, with the initial purchasers of the initial notes. In the registration rights agreement, we agreed to offer our new 5.75% Senior Notes due 2018, which will be registered under the Securities Act, and which we refer to as the exchange notes, in exchange for the initial notes. The exchange offer described in this prospectus is intended to satisfy our obligations under the registration rights agreement. We also agreed to deliver this prospectus to the holders of the initial notes. In this prospectus, we refer to the initial notes and the exchange notes collectively as the notes. You should read the discussion under the headings ‘‘Summary — Terms of the Notes’’ and ‘‘Description of the Notes’’ for information regarding the notes.

This investment involves risks. Before you invest in the notes, you should carefully consider the matters set forth under the heading ‘‘Risk Factors’’ on the next page and all other information in this prospectus.

An investment in the notes is subject to numerous risks, including, but not limited to, those set forth below. In addition to the information contained elsewhere in this prospectus, you should carefully consider the following risk factors when evaluating an investment in the notes. The risks and uncertainties described below are not the only ones facing us. Additional risks and uncertainties not presently known or that are currently deemed immaterial may also materially impair our business operations and our ability to service the notes.

We are a holding company and depend on distributions from subsidiaries, including joint ventures, to meet our obligations.

We are a holding company with no material assets other than the stock of our subsidiaries and joint ventures, collectively referred to as our subsidiaries. Accordingly, cash flows and the ability to meet our obligations, including payment of principal, interest and any premium payments on the notes, are largely dependent upon the earnings of our subsidiaries and the payment of such earnings to us in the form of dividends, loans, advances or other distributions. Our subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay amounts due pursuant to the notes or to make funds available to us, whether by dividends, loans or other payments, for payment of the notes, and they do not guarantee the payment of the notes. Distributions from subsidiaries may also be limited by:

We are substantially leveraged, the terms of the notes do not restrict the incurrence of additional indebtedness by us or our subsidiaries, and the notes will be structurally subordinated to the indebtedness of our subsidiaries, each of which could adversely affect our financial results and our ability to service the notes.

A significant portion of our capital structure is debt and we expect to incur additional indebtedness in the future to fund acquisitions, capital investments or the development and construction of new or expanded facilities. As of March 31, 2008, we had the following outstanding obligations:

Our consolidated subsidiaries also have significant amounts of outstanding indebtedness, which totaled $13.19 billion as of March 31, 2008. These amounts exclude (i) trade debt or preferred stock obligations, (ii) letters of credit in respect of subsidiary indebtedness, and (iii) our share of the outstanding indebtedness of our own or our subsidiaries’ equity investments.

Given our substantial leverage, we may not generate sufficient cash to service our debt, including the notes. Our leverage could also limit our ability to finance future acquisitions, develop and construct additional projects, or operate successfully under adverse economic conditions. It could also impair our credit quality or the credit quality of our subsidiaries, making it more difficult to finance

operations or issue future indebtedness on favorable terms, and could result in a downgrade in debt ratings, including those of the notes, by credit rating agencies.

The terms of the notes and our other debt do not limit our ability or the ability of our subsidiaries to incur additional debt or issue preferred stock. Accordingly, we or our subsidiaries could enter into acquisitions, new financings, refinancings, recapitalizations or other highly leveraged transactions that could significantly increase our or our subsidiaries’ total amount of outstanding debt. The interest payments needed to service this increased level of indebtedness could adversely affect our financial results and our ability to service the notes. Further, if an event of default accelerates a repayment obligation and such acceleration results in an event of default under some or all of our other indebtedness, or the indenture for the notes, we may not have sufficient funds to repay all of the accelerated indebtedness and the notes simultaneously.

Because we are a holding company, the claims of our senior and subordinated debt holders are structurally subordinated with respect to the assets and earnings of our subsidiaries. Therefore, your rights and the rights of our other creditors to participate in the assets of any subsidiary in the event of a liquidation or reorganization are subject to the prior claims of the subsidiary’s creditors and preferred shareholders. In addition, a significant amount of the stock or assets of our operating subsidiaries is directly or indirectly pledged to secure their financings and, therefore, may be unavailable as potential sources of repayment of the notes.

A downgrade in our credit ratings or the credit ratings of our subsidiaries could negatively affect our or our subsidiaries’ access to capital, increase the cost of borrowing or raise energy transaction credit support requirements.

Our senior unsecured long-term debt is rated investment grade, and the notes are expected to be rated investment grade, by various rating agencies. We cannot assure that our senior unsecured long-term debt will continue to be rated investment grade in the future. Although none of our outstanding debt has rating-downgrade triggers that would accelerate a repayment obligation, a credit rating downgrade would increase our borrowing costs and commitment fees on the revolving credit agreements, perhaps significantly. In addition, we would likely be required to pay a higher interest rate in future financings, and the potential pool of investors and funding sources would likely decrease. Further, access to the commercial paper market, the principal source of short-term borrowings, could be significantly limited resulting in higher interest costs.

Similarly, any downgrade or other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could cause us to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing our and our subsidiaries’ liquidity and borrowing capacity.

Most of our large customers, suppliers and counterparties require sufficient creditworthiness in order to enter into transactions, particularly in the wholesale energy markets. If our credit ratings or the credit ratings of our subsidiaries were to decline, especially below investment grade, operating costs would likely increase because counterparties may require a letter of credit, collateral in the form of cash-related instruments or some other security as a condition to further transactions with us or our subsidiaries.

Our majority shareholder, Berkshire Hathaway, could exercise control over us in a manner that would benefit Berkshire Hathaway to the detriment of our creditors.

Berkshire Hathaway is our majority owner and has control over all decisions requiring shareholder approval, including the election of our directors. In circumstances involving a conflict of interest between Berkshire Hathaway and our creditors, Berkshire Hathaway could exercise its control in a manner that would benefit Berkshire Hathaway to the detriment of our creditors.

Much of our growth has been achieved through acquisitions, and additional acquisitions may not be successful.

Our growth has been achieved largely through acquisitions. Future acquisitions may range from buying individual assets to the purchase of entire businesses. We will continue to investigate and pursue opportunities for future acquisitions that we believe may increase shareholder value and expand or complement existing businesses. We may participate in bidding or other negotiations at any time for such acquisition opportunities which may or may not be successful. Any transaction that does take place may involve consideration in the form of cash or debt or equity securities.

Completion of any acquisition entails numerous risks, including, among others, the:

An acquisition could cause an interruption of, or loss of momentum in, the activities of one or more of our businesses. The diversion of management’s attention and any delays or difficulties encountered in connection with the approval and integration of the acquired operations could adversely affect our combined businesses and financial results and could impair our ability to realize the anticipated benefits of the acquisition.

We cannot assure you that future acquisitions, if any, or any related integration efforts will be successful, or that our ability to repay our notes will not be adversely affected by any future acquisitions.

Our regulated businesses are subject to extensive regulations and legislation that affect their operations and costs and may adversely affect our ability to service the notes. These regulations and laws are complex, dynamic and subject to change.

Our businesses are subject to numerous regulations and laws enforced by regulatory agencies. In the U.S., these regulatory agencies include, among others, the Federal Energy Regulatory Commission, or the FERC, the Environmental Protection Agency, or the EPA, the Nuclear Regulatory Commission, or the NRC, and the U.S. Department of Transportation, or the DOT. In addition, our domestic utility subsidiaries are subject to state utility regulation in each state in which they operate. In the United Kingdom, these regulatory agencies include, among others, the Gas and Electricity Markets Authority, or GEMA, which discharges certain of its powers through its staff within the Office of Gas and Electricity Markets, or Ofgem.

Regulations affect almost every aspect of our business and limit our ability to independently make and implement management decisions regarding, among other items, business combinations, constructing, acquiring or disposing of operating assets, setting rates charged to customers, establishing capital structures and issuing debt or equity securities, engaging in transactions between our domestic utilities and other subsidiaries and affiliates, and paying dividends. Regulations are subject to ongoing policy initiatives and we cannot predict the future course of changes in laws, regulations and orders, or the ultimate effect that regulatory changes may have on us. However, such changes could adversely affect our financial results and our ability to service the notes. For example, such changes could result in, but are not limited to, increased retail competition within our subsidiaries’ service territories, new environmental requirements, including the implementation of renewable portfolio standards and greenhouse gas emissions reduction goals, the acquisition by a municipality or other quasi-governmental body of our subsidiaries’ distribution facilities (by negotiation, legislation or condemnation or by a vote in favor of a Public Utility District under Oregon law), or a negative impact on our subsidiaries’ current transportation and cost recovery arrangements, including income tax recovery.

Federal and state energy regulation changes are emerging as one of the more challenging aspects of managing utility operations. New and expanded regulations imposed by policy makers, court systems and industry restructuring have imposed changes on the industry. The following are examples of current or recent changes to our regulatory environment that may impact us:

Recovery of costs by our subsidiaries is subject to regulatory review and approval, and the inability to recover costs may adversely affect their financial results and our ability to service the notes.

Two of our regulated subsidiaries, PacifiCorp and MidAmerican Energy, establish rates for their regulated retail service through state regulatory proceedings. These proceedings typically involve multiple parties, including government bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns, but who generally have the common objective of limiting rate increases. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings.

Each state sets retail rates based in part upon the state utility commission’s acceptance of an allocated share of total utility costs. When states adopt different methods to calculate interjurisdictional cost allocations, some costs may not be incorporated into rates of any state. Ratemaking is also generally done on the basis of estimates of normalized costs, so if a given year’s realized costs are higher than normalized costs, rates will not be sufficient to cover those costs. Each state utility commission generally sets rates based on a test year established in accordance with that commission’s policies. Certain states use a future test year or allow for escalation of historical costs while other states use a historical test year. Use of a historical test year may cause regulatory lag which results in our utilities incurring costs, including significant new investments, for which recovery through rates is delayed. State commissions also decide the allowed rate of return we will be permitted to earn on our equity investment. They also decide the allowed levels of expense and investment that they deem is just and reasonable in providing service. The state commissions may disallow recovery in rates for any costs that do not meet such standard.

In Iowa, MidAmerican Energy has agreed not to seek a general increase in electric base rates to become effective prior to January 1, 2014 unless its Iowa jurisdictional electric return on equity for any year falls below 10%. MidAmerican Energy expects to continue to make significant capital expenditures to maintain and improve the reliability of its generation, transmission and distribution facilities to reduce emissions and to support new business and customer growth. As a result, MidAmerican Energy’s financial results may be adversely affected if it is not able to deliver electricity in a cost-efficient manner and is unable to offset inflation and the cost of infrastructure investments with costs savings or additional sales.

In certain states, PacifiCorp and MidAmerican Energy are not permitted to pass through energy cost increases in their electric rates without a general rate case. Any significant increase in fuel costs or purchased power costs for electricity generation could have a negative impact on PacifiCorp or MidAmerican Energy, despite efforts to minimize this impact through future general rate cases or the use of hedging instruments. Any of these consequences could adversely affect our financial results and our ability to service the notes.

While rate regulation is premised on providing a fair opportunity to obtain a reasonable rate of return on invested capital, the state regulatory commissions do not guarantee that we will be able to realize a reasonable rate of return.

The FERC establishes cost-based tariffs under which both PacifiCorp and MidAmerican Energy provide transmission services to wholesale markets and retail markets in states that allow retail

competition. The FERC also has responsibility for approving both cost- and market-based rates under which both these companies sell electricity at wholesale and has licensing authority over most of PacifiCorp’s hydroelectric generation facilities. The FERC may impose price limitations, bidding rules and other mechanisms to address some of the volatility of these markets or may (pursuant to pending or future proceedings) revoke or restrict the ability of our public utility subsidiaries to sell electricity at market-based rates, which could adversely affect our financial results and our ability to service the notes. The FERC may also impose substantial civil penalties for any non-compliance with the Federal Power Act and the FERC’s rules and orders.

The FERC also has jurisdiction over the construction and operation of pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the modification or abandonment of such facilities and rates, charges and terms and conditions of service for the transportation of natural gas in interstate commerce. The FERC was granted expanded market transparency authority under § 23 of the Natural Gas Act, or the NGA, a section added to the NGA by the Energy Policy Act of 2005. The FERC has adopted additional reporting requirements for natural gas pipelines and buyers and sellers of natural gas which include revisions to the FERC Form No. 2 and a new annual report of aggregate volumes of gas sales and purchases at wholesale. The FERC has also initiated an inquiry into the methodology for rate recovery by natural gas pipelines of fuel and lost and unaccounted-for gas costs.

Rates established for our U.S. interstate natural gas transmission and storage operations at Northern Natural Gas and Kern River are subject to the FERC’s regulatory authority. The rates the FERC authorizes these companies to charge their customers may not be sufficient to cover the costs incurred to provide services in any given period. These pipelines, from time to time, have in effect rate settlements approved by the FERC which prevent them or third parties from modifying rates, except for allowed adjustments, for certain periods. These settlements do not preclude the FERC from initiating a separate proceeding under the Natural Gas Act to modify the rates. It is not possible to determine at this time whether any such actions would be instituted or what the outcome would be, but such proceedings could result in rate adjustments.

Northern Electric and Yorkshire Electricity, as holders of electricity distribution licenses, are subject to regulation by GEMA. Most of the revenue of the electricity distribution license holders is controlled by a distribution price control formula set out in the electricity distribution license. The price control formula does not constrain profits from year to year, but is a control on revenue that operates independently of most of the electricity distribution license holder’s costs. It has been the practice of Ofgem to review and reset the formula at five-year intervals, although the formula has been, and may be, reviewed at other times at the discretion of Ofgem. The current five-year cost control period became effective on April 1, 2005. A resetting of the formula requires the consent of the electricity distribution license holder; however, license modifications may be unilaterally imposed by Ofgem without such consent following review by the British competition commission. GEMA is able to impose financial penalties on electricity distribution companies who contravene any of their electricity distribution license duties or certain of their duties under British law, or fail to achieve satisfactory performance of individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the electricity distribution license holder’s revenue. During the term of the price control, additional costs have a direct impact on the financial results of Northern Electric and Yorkshire Electricity and could adversely affect our ability to service the notes.

Through subsidiaries and joint ventures, we are actively pursuing, developing and constructing new or expanded facilities, the completion and expected cost of which is subject to significant risk, and our subsidiaries and joint ventures have significant funding needs related to their planned capital expenditures.

Through subsidiaries and joint ventures, we are continuing to develop and construct new or expanded facilities. We expect that these subsidiaries and joint ventures will incur substantial annual

capital expenditures over the next several years. Expenditures could include, among others, amounts for new coal-fired, natural gas, nuclear and wind powered electric generating facilities, electric transmission or distribution projects, environmental control and compliance systems, gas storage facilities, new or expanded pipeline systems, as well as the continued maintenance of the installed asset base.

Development and construction of major facilities are subject to substantial risks, including fluctuations in the price and availability of commodities, manufactured goods, equipment, labor and other items over a multi-year construction period. These risks may result in higher than expected costs to complete an asset and place it into service. Such costs may not be recoverable in the regulated rates or market prices our subsidiaries are able to charge their customers. It is also possible that additional generation needs may be obtained through power purchase agreements, which could increase long-term purchase obligations and force our subsidiaries and joint ventures to rely on the operating performance of a third party. The inability to successfully and timely complete a project, avoid unexpected costs or to recover any such costs could adversely affect our financial results and our ability to service the notes.

Furthermore, our subsidiaries and joint ventures depend upon both internal and external sources of liquidity to provide working capital and to fund capital requirements. If we do not provide needed funding to our subsidiaries and joint ventures and the subsidiaries and joint ventures are unable to obtain funding from external sources, they may need to postpone or cancel planned capital expenditures. Failure to construct these projects could limit opportunities for revenue growth, increase operating costs and adversely affect the reliability of electric service to our customers. For example, if PacifiCorp is not able to expand its existing generating facilities it may be required to enter into bilateral long-term electricity procurement contracts or procure electricity at more volatile and potentially higher prices in the spot markets to support growing retail loads.

Our subsidiaries are subject to numerous environmental, health, safety and other laws, regulations and other requirements that could adversely affect our financial results and our ability to service the notes.

Our subsidiaries are subject to numerous environmental, health, safety, and other laws, regulations and other requirements affecting many aspects of their present and future operations, including, among others:

These and related laws, regulations and orders generally require our subsidiaries to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals.

Compliance with environmental, health, safety, and other laws, regulations and other requirements can require significant capital and operating expenditures, including expenditures for

new equipment, inspection, cleanup costs, damages arising out of contaminated properties, and fines, penalties and injunctive measures affecting operating assets for failure to comply with environmental regulations. Compliance activities pursuant to regulations could be prohibitively expensive. As a result, some facilities may be required to shut down or alter their operations. Further, our subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals for their operating assets or development projects. Delays in or active opposition by third parties to obtaining any required environmental or regulatory permits, failure to comply with the terms and conditions of the permits or increased regulatory or environmental requirements may increase costs or prevent or delay our subsidiaries from operating their facilities, developing new facilities, expanding existing facilities or favorably locating new facilities. If our subsidiaries fail to comply with all applicable environmental requirements, they may be subject to penalties and fines or other sanctions. The costs of complying with current or new environmental, health, safety, and other laws, regulations and other requirements could adversely affect our financial results and our ability to service the notes. Not being able to operate existing facilities or develop new electric generating facilities to meet customer energy needs could require our subsidiaries to increase their purchases of power from the wholesale markets which could increase market and price risks and adversely affect our financial results and our ability to service the notes. Proposals for voluntary initiatives and mandatory controls are being discussed both in the United States and worldwide to reduce so-called ‘‘greenhouse gases’’ such as carbon dioxide, a by-product of burning fossil fuels, methane (the primary component of natural gas) and methane leaks from pipelines. These actions could result in materially increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any greenhouse gas emissions program. These actions could also increase the demand for natural gas causing increased natural gas prices, thereby adversely affecting our operations and our ability to service the notes.

Further, the regulatory rate structure or long-term customer contracts may not necessarily allow our regulated subsidiaries to recover all costs incurred to comply with new environmental requirements. The inability to fully recover such costs in a timely manner could adversely affect our financial results and our ability to service the notes.

Environmental, health, safety and other laws, regulations and other requirements also impose obligations to remediate contaminated properties or to pay for the cost of such remediation, often by parties that did not actually cause the contamination. Our subsidiaries are generally responsible for on-site liabilities, and in some cases off-site liabilities, associated with the environmental condition of their assets, including power generation facilities, and electric and natural gas transmission and distribution assets which our subsidiaries have acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with acquisitions, we or our subsidiaries may obtain or require indemnification against some environmental liabilities. If our subsidiaries incur a material liability, or the other party to a transaction fails to meet its indemnification obligations, our subsidiaries could suffer material losses. Our subsidiaries have established reserves to recognize their estimated obligations for known remediation liabilities, but such estimates may change materially over time. PacifiCorp is required to fund its portion of the costs of mine reclamation at its coal mining operations, which include principally site restoration. Also, MidAmerican Energy is required to fund its portion of the costs of decommissioning the Quad Cities Generating Station Units 1 and 2, or Quad Cities Station, a nuclear power plant, when it is retired from service, which may include site remediation or decontamination. In addition, future events, such as changes in existing laws or policies or their enforcement, or the discovery of currently unknown contamination, may give rise to additional remediation liabilities that may be material.

Our subsidiaries are exposed to credit risk of counterparties with whom they do business and failure of their significant customers to perform under or to renew their contracts, or failure to obtain new customers for expanded capacity, could adversely affect our financial results and our ability to service the notes.

Certain of our subsidiaries are dependent upon a relatively small number of customers for a significant portion of their revenues. For example:

Adverse economic conditions or other events affecting counterparties with whom our subsidiaries conduct business could impair the ability of these counterparties to pay for services or fulfill their contractual obligations, or cause them to delay or reduce such payments to our subsidiaries. Our subsidiaries depend on these counterparties to remit payments on a timely basis. Any delay or default in payment or limitation on the subsidiaries to negotiate alternative arrangements could adversely affect our financial results and our ability to service the notes.

If our subsidiaries are unable to renew, remarket or find replacements for their long-term agreements, our sales volume and revenue would be exposed to reduction and increased volatility. For example, without the benefit of long-term transportation, transmission or power purchase agreements, we cannot assure that our pipeline subsidiaries will be able to transport gas at efficient capacity levels, our regulated subsidiaries will be able to operate profitably, or our unregulated power generators will be able to sell the power generated by the non-utility generating facilities. Failure to secure these long-term agreements could adversely affect our financial results and our ability to service the notes.

The replacement of any existing long-term customer agreements depends on market conditions and other factors that are beyond our subsidiaries’ control.

Inflation and changes in commodity prices and fuel transportation costs may adversely affect our financial results and our ability to service the notes.

Inflation affects our businesses through increased operating costs and increased capital costs for plant and equipment. As a result of existing rate agreements and competitive price pressures, our subsidiaries may not be able to pass the costs of inflation on to their customers. If our subsidiaries are unable to manage cost increases or pass them on to their customers, our financial results and our ability to service the notes could be adversely affected.

We are also exposed to changes in prices and availability of coal and natural gas and the transportation of coal and natural gas because a substantial portion of our generation capacity utilizes these fossil fuels. Each of our electric utilities currently has contracts of varying durations for the supply and transportation of coal for much of their existing generation capacity, although PacifiCorp obtains some of its coal supply from mines owned or leased by it. When these contracts expire or if they are not honored, we may not be able to purchase or transport coal on terms as favorable as the current contracts. We have similar exposures regarding the market price of natural gas. Changes in the cost of coal or natural gas supply and transportation and changes in the relationship between such costs and the market price of power will affect our financial results. Since the sales price we receive for power may not change at the same rate as our coal or natural gas supply and transportation costs, we may be unable to pass on the changes in costs to our customers. In addition, the overall prices we

charge our retail customers in some jurisdictions are capped and our fuel recovery mechanisms in other states are frozen for various periods of time or have been eliminated.

A significant decrease in demand for natural gas or electricity in the markets served by our subsidiaries’ pipeline and gas distribution systems would significantly decrease our operating revenues and thereby adversely affect our business, financial results and ability to service the notes.

A sustained decrease in demand for natural gas or electricity in the markets served by our subsidiaries would significantly reduce our operating revenue and adversely affect our financial results and our ability to service the notes. Factors that could lead to a decrease in market demand include, among others:

Our public utility subsidiaries’ financial results may be adversely affected if they are unable to obtain adequate, reliable and affordable access to transmission service.

Our public utility subsidiaries depend on transmission facilities owned and operated by other utilities to transport electricity and natural gas to both wholesale and retail markets, as well as natural gas purchased to supply some of our subsidiaries’ electric generation facilities. If adequate transmission is unavailable, our subsidiaries may be unable to purchase and sell and deliver products. Such unavailability could also hinder our subsidiaries from providing adequate or economical electricity or natural gas to their wholesale and retail electric and gas customers and could adversely affect their financial results and our ability to service the notes.

The different regional power markets have varying and dynamic regulatory structures, which could affect our businesses’ growth and performance. In addition, the independent system operators who oversee the transmission systems in regional power markets have imposed in the past, and may impose in the future, price limitations and other mechanisms to counter volatility in the power markets. These types of price limitations and other mechanisms may adversely impact the financial results of our utilities and our ability to service the notes.

Our subsidiaries are subject to market risk, counterparty performance risk and other risks associated with wholesale energy markets.

In general, wholesale market risk is the risk of adverse fluctuations in the market price of wholesale electricity and fuel, including natural gas and coal, which is compounded by volumetric changes affecting the availability of or demand for electricity and fuel. PacifiCorp and MidAmerican Energy purchase electricity and fuel in the open market or pursuant to short-term or variable-priced contracts as part of their normal operating businesses. If market prices rise, especially in a time when larger than expected volumes must be purchased at market or short-term prices, PacifiCorp or MidAmerican Energy may incur significantly greater expense than anticipated. Likewise, if electricity market prices decline in a period when PacifiCorp or MidAmerican Energy is a net seller of electricity in the wholesale market, PacifiCorp or MidAmerican Energy will earn less revenue.

Wholesale electricity prices in PacifiCorp’s service areas are influenced primarily by factors throughout the Western United States relating to supply and demand. Those factors include the

adequacy of generating capacity, scheduled and unscheduled outages of generating facilities, hydroelectric generation levels, prices and availability of fuel sources for generation, disruptions or constraints to transmission facilities, weather conditions, economic growth and changes in technology. Volumetric changes are caused by unanticipated changes in generation availability and/or changes in customer loads due to the weather, electricity prices, the economy, regulations or customer behavior. Although PacifiCorp plans for resources to meet its current and expected retail and wholesale load obligations, PacifiCorp is a net buyer of electricity during peak periods and therefore, its energy costs may be adversely impacted by market risk. In addition, PacifiCorp may not be able to timely recover all, if any, of those increased costs unless the state regulators authorize such recovery.

MidAmerican Energy’s total accredited net generating capability exceeds its historical peak load. As a result, in comparison to PacifiCorp, which relies to a significant extent on purchased power to satisfy its peak load, MidAmerican Energy has less exposure to wholesale electricity market price fluctuations. The actual amount of generation capacity available at any time, however, may be less than the accredited capacity due to regulatory restrictions, transmission constraints, contractual commitments to third parties, fuel restrictions and generating units being temporarily out of service for inspection, maintenance, refueling, modifications or other reasons. In such circumstances, MidAmerican Energy may need to purchase energy in the wholesale markets and it may not recover in rates all of the additional costs that may be associated with such purchases. Most of MidAmerican Energy’s electric wholesale sales and purchases take place under market-based pricing allowed by the FERC and are therefore subject to market volatility, including price fluctuations.

PacifiCorp and MidAmerican Energy are also exposed to risks related to performance of contractual obligations by wholesale suppliers and customers. Each utility relies on suppliers to deliver commodities, primarily natural gas, coal and electricity, in accordance with short- and long-term contracts. Failure or delay by suppliers to provide these commodities pursuant to existing contracts could disrupt the delivery of electricity and require the utilities to incur additional expenses to meet customer needs. In addition, when these contracts terminate, the utilities may be unable to purchase the commodities on terms equivalent to the terms of current contracts.

PacifiCorp and MidAmerican Energy rely on wholesale customers to take delivery of the energy they have committed to purchase and to pay for the energy on a timely basis. Failure of customers to take delivery may require these subsidiaries to find other customers to take the energy at lower prices than the original customers committed to pay. At certain times of the year, prices paid by PacifiCorp and MidAmerican Energy for energy needed to satisfy their customers’ energy needs may exceed the amounts they receive through rates from these customers. If the strategy used to minimize these risk exposures is ineffective, significant losses could result, and our ability to service the notes could be adversely affected.

Our operating results may fluctuate on a seasonal and quarterly basis and may be adversely affected by weather.

The sale of electric power and natural gas are generally seasonal businesses. In most parts of the United States and other markets in which our subsidiaries operate, demand for electricity peaks during the hot summer months when cooling needs are higher. Market prices for electric supply also generally peak at that time. In other areas, demand for electricity peaks during the winter. In addition, demand for gas and other fuels generally peaks during the winter when heating needs are higher. This is especially true in Northern Natural Gas’ market area and MidAmerican Energy’s retail gas business. Further, extreme weather conditions such as heat waves or winter storms could cause these seasonal fluctuations to be more pronounced. Periods of low rainfall or snowpack may also impact electric generation at PacifiCorp’s hydroelectric projects.

As a result, the overall financial results of our subsidiaries may fluctuate substantially on a seasonal and quarterly basis. We have historically sold less power, and consequently earned less income, when weather conditions are mild. Unusually mild weather in the future may adversely affect our financial results and our ability to service the notes through lower revenues or margins. Conversely, unusually extreme weather conditions could increase our costs to provide power and could adversely affect our financial results and our ability to service the notes. Furthermore, during or

following periods of low rainfall or snowpack, PacifiCorp may obtain substantially less electricity from hydroelectric projects and must purchase greater amounts of electricity from the wholesale market or from other sources at market prices. The extent of fluctuation in financial results may change depending on a number of factors related to our subsidiaries’ regulatory environment and contractual agreements, including their ability to recover power costs, the existence of revenue sharing provisions and terms of the power sale contracts.

Our subsidiaries are subject to operating uncertainties that could adversely affect our financial results and our ability to service the notes.

The operation of complex electric and gas utility (including generation, transmission and distribution) systems, pipelines or power generating facilities that are spread over large geographic areas involves many operating uncertainties and events beyond our control. These potential events include the breakdown or failure of power generation equipment, compressors, pipelines, transmission and distribution lines or other equipment or processes, unscheduled plant outages, work stoppages, shortage of qualified labor, transmission and distribution system constraints or outages, fuel shortages or interruptions, unavailability of critical equipment, materials and supplies, low water flows, performance below expected levels of output, capacity or efficiency, operator error and catastrophic events such as severe storms, fires, earthquakes, explosions or mining accidents. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Any of these risks or other operational risks could significantly reduce or eliminate our subsidiaries’ revenues or significantly increase their expenses, thereby reducing the availability of distributions to us. For example, if our subsidiaries cannot operate their electric or natural gas facilities at full capacity due to damage caused by a catastrophic event, their revenues could decrease due to decreased sales and their expenses could increase due to the need to obtain energy from more expensive sources. Further, we self-insure many risks, and current and future insurance coverage may not be sufficient to replace lost revenues or cover repair and replacement costs. Any reduction of revenues for such reason, or any other reduction of our subsidiaries’ revenues or increase in their expenses resulting from the risks described above could adversely affect our financial results and our ability to service the notes.

Potential terrorist activities or military or other actions could adversely affect our financial results and our ability to service the notes.

The continued threat of terrorism since September 11, 2001 and the impact of military and other actions by the United States and its allies may lead to increased political, economic and financial market instability and subject our subsidiaries’ operations to increased risk of acts of terrorism. The United States government has issued warnings that energy assets, specifically pipeline, nuclear generation and other electric utility infrastructure are potential targets for terrorist organizations. Political, economic or financial market instability or damage to the operating assets of our subsidiaries, customers or suppliers may result in business interruptions, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption and unstable markets, particularly with respect to natural gas and electric energy, increased security, repair or other costs that may materially adversely affect us and our subsidiaries in ways that cannot be predicted at this time. Any of these risks could materially affect our financial results and decrease the amount of funds we have available to make payments on the notes. Furthermore, instability in the financial markets as a result of terrorism or war could also materially adversely affect our ability and the ability of our subsidiaries to raise capital.

The insurance industry changed in response to these events. As a result, insurance covering risks we and our subsidiaries typically insure against may decrease in scope and availability, and we may elect to self-insure against many such risks. In addition, the available insurance may have higher deductibles, higher premiums and more restrictive policy terms.

MidAmerican Energy is subject to the unique risks associated with nuclear generation.

The ownership and operation of nuclear power plants, such as MidAmerican Energy’s 25% ownership interest in the Quad Cities Station, involves certain risks. These risks include, among other items, mechanical or structural problems, inadequacy or lapses in maintenance protocols, the

impairment of reactor operation and safety systems due to human error, the costs of storage, handling and disposal of nuclear materials, limitations on the amounts and types of insurance coverage commercially available, and uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives. The prolonged unavailability of the Quad Cities Station could materially adversely affect MidAmerican Energy’s financial results and our ability to service the notes, particularly when the cost to produce power at the plant is significantly less than market wholesale power prices. The following are among the more significant of these risks:

We own investments and projects located in foreign countries that are exposed to increased economic, regulatory and political risks.

We own and may acquire significant energy-related investments and projects outside of the United States. The economic, regulatory and political conditions in some of the countries where we have operations or are pursuing investment opportunities may present increased risks related to, among others, inflation, currency exchange rate fluctuations, currency repatriation restrictions, nationalization, renegotiation, privatization, availability of financing on suitable terms, customer creditworthiness, construction delays, business interruption, political instability, civil unrest, guerilla activity, terrorism, expropriation, trade sanctions, contract nullification and changes in law, regulations or tax policy. We may not be capable of either fully insuring against or effectively hedging these risks.

Our business operations and investments outside the United States increase our risk related to fluctuations in currency rates, primarily the British pound and the Philippine peso. Our principal reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from our foreign operations changes with the fluctuations of the currency in which they transact. We may selectively reduce some foreign currency risk by, among other things, requiring contracted amounts be settled in United States dollars, indexing contracts to the United States dollar or hedging through foreign currency derivatives. These efforts, however, may not be effective and could negatively affect our financial results and our ability to service the notes. We attempt, in many circumstances, to structure foreign transactions to provide for payments to be made in, or indexed to, United States dollars or a currency freely convertible into United States dollars. We may not be able to obtain sufficient dollars or other hard currency or available dollars may not be allocated to pay such obligations, which could adversely affect our financial results and our ability to service the notes.

Cyclical fluctuations in the residential real estate brokerage and mortgage businesses could adversely affect HomeServices.

The residential real estate brokerage and mortgage industries tend to experience cycles of greater and lesser activity and profitability and are typically affected by changes in economic conditions, including the current downturn in the U.S. housing market, which are beyond HomeServices’ control. Any of the following are examples of items that could have a material adverse effect on HomeServices’ businesses by causing a general decline in the number of home sales, sale prices or the number of home financings which, in turn, would adversely affect its financial results and our ability to service the notes:

We and our subsidiaries are involved in numerous legal proceedings, the outcomes of which are uncertain and could adversely affect our financial results and our ability to service the notes.

We and our subsidiaries are parties to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters. It is possible that the final resolution of some of the matters in which we and our subsidiaries are involved could result in additional payments in excess of established reserves over an extended period of time and in amounts that could have a material adverse effect on our financial results. Similarly, it is also possible that the terms of resolution could require that we or our subsidiaries change business practices and procedures, which could also have a material adverse effect on our financial results and our ability to service the notes. Further, litigation could result in the imposition of financial penalties or injunctions which could limit our ability to take certain desired actions or the denial of needed permits, licenses or regulatory authority to conduct our business, including the siting or permitting of facilities. Any of these outcomes could adversely affect our financial results and our ability to service the notes.

Potential changes in accounting standards might cause us to revise our financial results and disclosure in the future, which may change the way analysts measure our business or financial performance.

Accounting irregularities discovered in the past few years in various industries have caused regulators and legislators to take a renewed look at accounting practices, financial disclosures, companies’ relationships with their independent auditors and retirement plan practices. Because it is still unclear what laws or regulations will ultimately develop, we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically. In addition, the Financial Accounting Standards Board, or FASB, the FERC or the U.S. Securities and Exchange Commission, or the SEC, could enact new or revised accounting standards or FERC orders that might impact how we are required to record revenues, expenses, assets and liabilities.

Your ability to transfer the notes is limited by the absence of a market for the notes, and a trading market for the notes may not develop.

There is no existing public trading market for the notes and a market for the notes might not develop and you may not be able to sell the notes or obtain a suitable price. If such a market were to develop, the notes could trade at prices that may be higher or lower than their initial offering price

depending on many factors, including prevailing interest rates, our operating results and the market for similar securities. We do not intend to apply for listing of the notes on a securities exchange or an automated dealer quotation system. As a result, it may be difficult for you to find a buyer for the notes at the time you want to sell them and, even if you find a buyer, you might not get the price you want.

You may not be able to sell your initial notes if you do not exchange them for registered exchange notes in the exchange offer.

If you do not exchange your initial notes for registered exchange notes in the exchange offer, your initial notes will continue to be subject to the restrictions on transfer as stated in the legends on the initial notes. In general, you may not offer, sell or otherwise transfer the initial notes in the United States unless they are:

We do not currently anticipate that we will register any untendered initial notes under the Securities Act. Except for limited instances involving the initial purchasers or holders of notes who are not eligible to participate in the exchange offer or who do not receive freely transferable exchange notes in the exchange offer, we will not be under any obligation to register the initial notes under the Securities Act under the registration rights agreement or otherwise. Also, if the exchange offer is completed on the terms and within the time period contemplated by this prospectus, no additional interest will be payable on your initial notes.

Your ability to sell your initial notes may be significantly more limited and the price at which you may be able to sell your initial notes may be significantly lower if you do not exchange them for registered exchange notes in the exchange offer.

To the extent that initial notes are exchanged for registered exchange notes in the exchange offer, the trading market for the initial notes that remain outstanding may be significantly more limited. As a result, the liquidity of the initial notes not tendered for exchange could be adversely affected. The extent of the market for initial notes will depend upon a number of factors, including the number of holders of initial notes remaining outstanding and the interest of securities firms in maintaining a market in the initial notes. An issue of securities with a lesser outstanding market value available for trading, which is called the ‘‘float,’’ may command a lower price than would be comparable to an issue of securities with a greater float. As a result, the market price for initial notes that are not exchanged in the exchange offer may be affected adversely to the extent that initial notes exchanged in the exchange offer reduce the float. The reduced float also may make the trading price of the initial notes that are not exchanged more volatile.

There are state securities law restrictions on the resale of the exchange notes.

In order to comply with the securities laws of certain jurisdictions, the exchange notes may not be offered or resold by any holder unless they have been registered or qualified for sale in such jurisdictions or an exemption from registration or qualification is available and the requirements of such exemption have been satisfied. We do not currently intend to register or qualify the resale of the exchange notes in any such jurisdictions. However, an exemption is generally available for sales to registered broker-dealers and certain institutional buyers. Other exemptions under applicable state securities laws may also be available.

We will not accept your initial notes for exchange if you fail to follow the exchange offer procedures and, as a result, your initial notes will continue to be subject to existing transfer restrictions and you may not be able to sell your initial notes.

We will issue exchange notes in exchange for initial notes tendered and accepted for exchange pursuant to the exchange offer only after compliance by you with all of the conditions of the exchange

offer described elsewhere in this prospectus under the caption, ‘‘The Exchange Offer — How to Tender,’’ including timely (i) receipt by the exchange agent of (a) a properly completed and duly executed letter of transmittal, together with any required signature guarantees and any other required documents and (b) the certificate(s) representing the initial notes being tendered; (ii) compliance with the procedures for book-entry transfers described elsewhere in this prospectus; or (iii) compliance with the guaranteed delivery procedures set forth elsewhere in this prospectus. We are under no duty to give notification of defects or irregularities with respect to the tenders of initial notes for exchange. If there are defects or irregularities with respect to your tender of initial notes, we will not accept your initial notes for exchange. See ‘‘The Exchange Offer.’’

This prospectus contains statements that do not directly or exclusively relate to historical facts. These statements are ‘‘forward-looking statements’’ within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as ‘‘may,’’ ‘‘could,’’ ‘‘project,’’ ‘‘believe,’’ ‘‘anticipate,’’ ‘‘expect,’’ ‘‘estimate,’’ ‘‘continue,’’ ‘‘intend,’’ ‘‘potential,’’ ‘‘plan,’’ ‘‘forecast’’ and similar terms. These statements are based upon our current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside our control and could cause actual results to differ materially from those expressed or implied by our forward-looking statements. These factors include, among others:

Further details of the potential risks and uncertainties affecting us are described in the ‘‘Risk Factors’’ section of this prospectus. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors should not be construed as exclusive.

We will not receive any proceeds from the issuance of the exchange notes in the exchange offer. The exchange notes will evidence the same debt as the initial notes tendered in exchange for exchange notes. Accordingly, the issuance of the exchange notes will not result in any change in our indebtedness.

On March 28, 2008, we privately placed the initial notes in a transaction exempt from registration under the Securities Act. Accordingly, the initial notes may not be reoffered, resold or otherwise transferred in the U.S. unless so registered or unless an exemption from the Securities Act registration requirements is available. Pursuant to a registration rights agreement with the initial purchasers of the initial notes, we agreed, for the benefit of holders of the initial notes, to:

We will be entitled to consummate the exchange offer on the expiration date (as defined below) provided that we have accepted all initial notes previously validly tendered in accordance with the terms set forth in this prospectus and the applicable letter of transmittal.

In addition, under certain circumstances described below, we may be required to file a shelf registration statement to cover resales of the notes.

If we do not comply with certain of our obligations under the registration rights agreement, we must pay additional interest on the initial notes in addition to the interest that is otherwise due on the notes. The purpose of the exchange offer is to fulfill our obligations with respect to the registration rights agreement.

If you are a broker-dealer that receives exchange notes for its own account in exchange for initial notes, where you acquired such initial notes as a result of market-making activities or other trading activities, you must acknowledge that you will deliver a prospectus in connection with any resale of such exchange notes. See ‘‘Plan of Distribution.’’

Upon the terms and subject to the conditions contained in this prospectus and in the letters of transmittal that accompany this prospectus, we are offering to exchange $1,000 in principal amount of exchange notes for each $1,000 in principal amount of initial notes. The terms of the exchange notes are identical in all material respects to the terms of the initial notes except that the exchange notes will generally be freely transferable. The exchange notes will evidence the same debt as the initial notes and will be entitled to the benefits of the indenture. Any initial notes that remain outstanding after the consummation of the exchange offer, together with all exchange notes issued in connection with the exchange offer, will be treated as a single class of securities under the indenture. See ‘‘Description of the Notes.’’

The exchange offer is not conditioned on any minimum aggregate principal amount of initial notes being tendered for exchange.

Based on existing interpretations of the Securities Act by the staff of the SEC set forth in several no-action letters to third parties, and subject to the immediately following sentence, we believe that you may offer for resale, resell and otherwise transfer the exchange notes without further compliance with the registration and prospectus delivery provisions of the Securities Act. However, if you are an

‘‘affiliate’’ (within the meaning of the Securities Act) of ours or you intend to participate in the exchange offer for the purpose of distributing the exchange notes or you are a broker-dealer (within the meaning of the Securities Act) that acquired notes in a transaction other than as part of its market-making or other trading activities and who has arranged or has an understanding with any person to participate in the distribution of the exchange notes, you:

Subject to exceptions for certain holders, to participate in the exchange offer you will be required to represent to us at the time of the consummation of the exchange offer, among other things, that: (1) you are not an affiliate of ours; (2) any exchange notes to be received by you will be acquired in the ordinary course of your business; and (3) at the time of commencement of the exchange offer, you have no arrangement or understanding with any person to participate in a distribution (within the meaning of the Securities Act) of the notes. In addition, in connection with any resales of exchange notes, any broker-dealer who acquired exchange notes for its own account as a result of market-making activities or other trading activities must deliver a prospectus meeting the requirements of the Securities Act. The SEC has taken the position that such a broker-dealer may fulfill its prospectus delivery requirements with respect to the exchange notes (other than a resale of an unsold allotment from the initial sale of the initial notes) with this prospectus. Under the registration rights agreement, we are required to allow a broker-dealer and other persons with similar prospectus delivery requirements, if any, to use this prospectus in connection with the resale of such exchange notes for a period of time not less than 120 days following the consummation of the exchange offer. If you are a broker-dealer that receives exchange notes for its own account in exchange for initial notes, where you acquired such initial notes as a result of market-making activities or other trading activities, you must acknowledge that you will deliver a prospectus in connection with any resale of such exchange notes. See ‘‘Plan of Distribution.’’

You will not be required by us to pay brokerage commissions or fees or, subject to the instructions in the applicable letter of transmittal, transfer taxes relating to your exchange of initial notes for exchange notes in the exchange offer.

The foregoing obligations are subject to our right to postpone or suspend the filing or effectiveness of any shelf registration statement (or exchange offer registration statement) if such action is required by law or taken by us in good faith and for valid business reasons in accordance with the terms of the registration rights agreement.

You will not be entitled, except if you were an initial purchaser of the initial notes, to have your notes registered under any shelf registration statement (if one is filed), unless you agree in writing to be bound by the applicable provisions of the registration rights agreement. In order to sell your notes under the shelf registration statement, you generally must be named as a selling security holder in the related prospectus and must deliver a prospectus to purchasers. Consequently, you will be subject to the civil liability provisions under the Securities Act in connection with those sales and indemnification obligations under the registration rights agreements.

Additional interest will accrue on the initial notes subject to such registration default, for so long as they constitute Transfer Restricted Securities, at a rate of 0.50% per annum from and including the date on which any such registration default occurs to but excluding the date on which all such registration defaults have ceased to be continuing. In no event will such additional interest be payable for periods after March 28, 2010. In each case, such additional interest is payable in addition to any other interest payable from time to time with respect to the initial notes and the exchange notes. The exchange notes will not contain any additional provisions regarding the payment of additional interest.

The exchange offer expires on the expiration date. The expiration date is 5:00 p.m., New York City time, on , 2008, unless we in our sole discretion extend the period during which the exchange offer is open, in which event the expiration date is the latest time and date on which the exchange offer, as so extended by us, expires. We reserve the right to extend the exchange offer at any time and from time to time by giving written notice to The Bank of New York Trust Company, N.A., as the exchange agent, before 9:00 a.m., New York City time, on the first business day following the previously scheduled expiration date and by timely public announcement communicated in accordance with applicable law or regulation. During any extension of the exchange offer, all initial notes previously tendered pursuant to the exchange offer and not validly withdrawn will remain subject to the exchange offer.

The exchange date will occur promptly after the expiration date. We expressly reserve the right to (i) terminate the exchange offer and not accept for exchange any initial notes for any reason, including if any of the events set forth below under ‘‘— Conditions to the Exchange Offer’’ shall have occurred and shall not have been waived by us and (ii) amend the terms of the exchange offer in any manner, whether before or after any tender of the initial notes. If any such termination or amendment occurs, we will notify the exchange agent in writing and will either issue a press release or give written notice to the holders of the initial notes as promptly as practicable. Unless we terminate the exchange offer prior to 5:00 p.m., New York City time, on the expiration date, we will exchange the initial notes for the exchange notes on the exchange date.

If we waive any material condition to the exchange offer, or amend the exchange offer in any other material respect, and if at the time that notice of such waiver or amendment is first published, sent or given to holders of initial notes in the manner specified above, the exchange offer is scheduled to expire at any time earlier than the expiration of a period ending on the fifth business day from, and including, the date that such notice is first so published, sent or given, then the exchange offer will be extended until the expiration of such period of five business days.

This prospectus and the related letters of transmittal and other relevant materials will be mailed by us to record holders of initial notes and will be furnished to brokers, banks and similar persons whose names, or the names of whose nominees, appear on the lists of holders for subsequent transmittal to beneficial owners of initial notes.

The tender to us of initial notes by you pursuant to one of the procedures set forth below will constitute an agreement between you and us in accordance with the terms and subject to the conditions set forth herein and in the applicable letter of transmittal.

General Procedures. To validly tender the initial notes pursuant to the exchange offer, either:

The term ‘‘agent’s message’’ means a message, transmitted by DTC and received by the exchange agent and forming part of a Book-Entry Confirmation, which states that DTC has received an express acknowledgment from a participant tendering initial notes that are the subject of the Book-Entry Confirmation that the participant has received and agrees to be bound by the terms of the letter of transmittal, and that we may enforce that agreement against the participant.

If tendered initial notes are registered in the name of the signer of the letter of transmittal and the exchange notes to be issued in exchange therefor are to be issued (and any untendered initial notes are to be reissued) in the name of the registered holder, the signature of such signer need not be guaranteed. In any other case, the tendered initial notes must be endorsed or accompanied by written instruments of transfer in form satisfactory to us and duly executed by the registered holder and the signature on the endorsement or instrument of transfer must be guaranteed by a firm, which we refer to as an Eligible Institution, that is a member of a recognized signature guarantee medallion program within the meaning of Rule 17Ad-15 under the Exchange Act of 1934. If the exchange notes and/or initial notes not exchanged are to be delivered to an address other than that of the registered holder appearing on the note register for the initial notes, the signature on the letter of transmittal must be guaranteed by an Eligible Institution.

Any beneficial owner whose initial notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and who wishes to tender initial notes should contact such holder promptly and instruct such holder to tender initial notes on such beneficial owner’s behalf. If such beneficial owner wishes to tender such initial notes himself, such beneficial owner must, prior to completing and executing the letter of transmittal and delivering such initial notes, either make appropriate arrangements to register ownership of the initial notes in such beneficial owner’s name or follow the procedures described in the immediately preceding paragraph. The transfer of record ownership may take considerable time.

Book-Entry Transfer. The exchange agent will make a request to establish an account with respect to the initial notes at DTC for purposes of the exchange offer within two business days after the date of this prospectus. Any financial institution that is a participant in DTC’s systems may utilize DTC’s ATOP procedures to tender initial notes and may make book-entry delivery of initial notes by causing DTC to transfer such initial notes into the exchange agent’s account at DTC in accordance with DTC’s ATOP procedures for transfer. However, although delivery of initial notes may be effected through book-entry transfer at DTC, the letter of transmittal, with any required signature guarantees and any other required documents, must, in any case, be transmitted to and received by the exchange agent at its address or facsimile number set forth on the back cover of this prospectus on or prior to the expiration date, unless the holder either (1) complies with the guaranteed delivery procedures described below or (2) sends an agent’s message through ATOP.

If delivery is made through ATOP, the exchange for the initial notes so tendered will be made only after a Book-Entry Confirmation and an agent’s message and any other documents required by the letter of transmittal have been received by the exchange agent, in each case on or prior to the expiration date.

The method of delivery of initial notes and all other documents is at your election and risk. If sent by mail, we recommend that you use registered mail, return receipt requested, obtain proper insurance, and complete the mailing sufficiently in advance of the expiration date to permit delivery to the exchange agent on or before the expiration date. Delivery of documents to DTC does not constitute delivery to the exchange agent.

Guaranteed Delivery Procedures. If a holder desires to accept the exchange offer and time will not permit a letter of transmittal or initial notes to reach the exchange agent on or before the expiration date, or the procedures for book-entry transfer set forth above cannot be completed on a timely basis, a tender may nevertheless be effected, provided that all of the following guaranteed delivery procedures are complied with:

Unless all of the guaranteed delivery procedures set forth in the preceding paragraph are complied with, we may, at our option, reject the tender. Copies of a Notice of Guaranteed Delivery which may be used by Eligible Institutions for the purposes described in this paragraph are being delivered with this prospectus and the related letter of transmittal. A tender will be deemed to have been received as of the date when the tendering holder’s properly completed and duly signed letter of transmittal accompanied by the initial notes (or agent’s message accompanied by a Book-Entry Confirmation in the case of a book-entry transfer) is received by the exchange agent. Issuances of exchange notes in exchange for initial notes tendered pursuant to a notice of guaranteed delivery by an Eligible Institution or an electronic message transmitted through ATOP with respect to guaranteed delivery for book-entry transfers will be made only against deposit of the letter of transmittal (and any other required documents) and the tendered initial notes or, in the case of a book-entry transfer, against deposit of an agent’s message through ATOP (and any other required documents) and a timely Book-Entry Confirmation.

All questions as to the validity, form, eligibility (including time of receipt) and acceptance for exchange of any tender of initial notes will be determined by us and our determination will be final and binding. We reserve the absolute right to reject any or all tenders not in proper form or the acceptances for exchange of which may, in the opinion of our counsel, be unlawful. We also reserve the absolute right to waive any of the conditions of the exchange offer or any defect or irregularities in tenders of any particular holder whether or not similar defects or irregularities are waived in the case of other holders. None of us, the exchange agent or any other person will be under any duty to give notification of any defects or irregularities in tenders or shall incur any liability for failure to give any such notification. Our interpretation of the terms and conditions of the exchange offer (including the letters of transmittal and the instructions thereto) will be final and binding.

The letters of transmittal contain, among other things, the following terms and conditions, which are part of the exchange offer.

The party tendering initial notes for exchange, whom we refer to as the Transferor, exchanges, assigns and transfers the initial notes to us and irrevocably constitutes and appoints the exchange agent as the Transferor’s agent and attorney-in-fact to cause the initial notes to be assigned, transferred and exchanged. The Transferor represents and warrants that it has full power and authority to tender, exchange, assign and transfer the initial notes and to acquire exchange notes issuable upon the exchange of such tendered initial notes, and that, when the same are accepted for exchange, we will acquire good and unencumbered title to the tendered initial notes, free and clear of all liens, restrictions, charges and encumbrances and not subject to any adverse claim. The Transferor also warrants that it will, upon request, execute and deliver any additional documents deemed by us to be necessary or desirable to complete the exchange, assignment and transfer of tendered initial notes. The Transferor further agrees that acceptance of any tendered initial notes by us and the issuance of exchange notes in exchange therefor shall constitute performance in full by us of our obligations under the registration rights agreement and that we shall have no further obligations or liabilities thereunder (except in certain limited circumstances). All authority conferred by the Transferor will survive the death or incapacity of the Transferor and every obligation of the Transferor shall be binding upon the heirs, legal representatives, successors, assigns, executors and administrators of such Transferor.

Initial notes tendered pursuant to the exchange offer may be withdrawn at any time prior to the expiration date. For a withdrawal to be effective, a written or facsimile transmission notice of withdrawal must be timely received by the exchange agent at its address set forth on the back cover of this prospectus. Any such notice of withdrawal must specify the person named in the letter of transmittal as having tendered initial notes to be withdrawn, the certificate numbers of initial notes to be withdrawn, the principal amount of initial notes to be withdrawn (which must be an authorized denomination), a statement that such holder is withdrawing his election to have such initial notes exchanged, and the name of the registered holder of such initial notes, and must be signed by the holder in the same manner as the original signature on the letter of transmittal (including any required signature guarantees) or be accompanied by documents of transfer sufficient to have the trustee register the transfer of such initial notes into the name of the person withdrawing the tender. The exchange agent will return the properly withdrawn initial notes promptly following receipt of notice of withdrawal. If initial notes have been tendered pursuant to the procedures for book-entry transfer set forth above, any notice of withdrawal must specify the name and number of the account at DTC to be credited with the withdrawn initial notes or otherwise comply with DTC’s procedures, and in such case the initial notes will be credited to such account by the exchange agent promptly after withdrawal. All questions as to the validity of notices of withdrawals, including time of receipt, will be determined by us, and our determination will be final and binding on all parties.

Upon the terms and subject to the conditions of the exchange offer, the acceptance for exchange of initial notes validly tendered and not withdrawn and the issuance of the exchange notes will be made on the exchange date. For the purposes of the exchange offer, we shall be deemed to have accepted for exchange validly tendered initial notes when, as and if we have given written notice thereof to the exchange agent.

In all cases, delivery of exchange notes in exchange for initial notes tendered and accepted pursuant to this exchange offer will be made only after timely receipt by the exchange agent of:

The exchange agent will act as agent for the tendering holders of initial notes for the purposes of receiving exchange notes from us and causing the initial notes to be assigned, transferred and exchanged. Upon the terms and subject to the conditions of the exchange offer, delivery of exchange notes to be issued in exchange for accepted initial notes will be made by the exchange agent promptly after acceptance of the tendered initial notes. Initial notes not accepted for exchange by us will be returned without expense to the tendering holders (or in the case of initial notes tendered by book-entry transfer into the exchange agent’s account at DTC pursuant to the procedures described above, such non-exchanged initial notes will be credited to an account maintained with DTC) promptly following the expiration date or, if we terminate the exchange offer prior to the expiration date, promptly after the exchange offer is so terminated.

We are not required to accept for exchange, or to issue exchange notes in exchange for, any outstanding initial notes. We may terminate or extend the exchange offer by oral or written notice to the exchange agent and by timely public announcement communicated in accordance with applicable law or regulation for any reason, if any of the following shall have occurred:

The foregoing conditions are for our sole benefit and may be asserted by us with respect to all or any portion of the exchange offer regardless of the circumstances (including any action or inaction by us) giving rise to such condition or may be waived by us in whole or in part at any time or from time to time in our sole discretion. The failure by us at any time to exercise any of the foregoing rights will not be deemed a waiver of any such right, and each right will be deemed an ongoing right which may be asserted at any time or from time to time. In addition, we have reserved the right, notwithstanding the satisfaction of each of the foregoing conditions, to terminate or amend the exchange offer.

Any determination by us concerning the fulfillment or non-fulfillment of any conditions will be final and binding upon all parties.

The Bank of New York Trust Company, N.A. has been appointed as the exchange agent for the exchange offer. Letters of transmittal must be addressed to the exchange agent at its address set forth on the back cover page of this prospectus. Delivery to an address other than as set forth herein, or transmissions of instructions via a facsimile or telex number other than the ones set forth herein, will not constitute a valid delivery. The Bank of New York Trust Company, N.A. is the trustee under the indenture. The Bank of New York Trust Company, N.A. (or one of its affiliates) currently serves, and may in the future serve, as trustee under indentures evidencing other indebtedness of us and our affiliates. The Bank of New York Trust Company, N.A. (or one of its affiliates) is also, and may in the future be, a lender under credit facilities for us and our affiliates.

We have not retained any dealer-manager or similar agent in connection with the exchange offer and will not make any payments to brokers, dealers or others for soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and will reimburse it for reasonable out-of-pocket expenses in connection therewith. We will also pay brokerage houses and other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding tenders for their customers. The expenses to be incurred in connection with the exchange offer, including the fees and expenses of the exchange agent and printing, accounting and legal fees, will be paid by us and are estimated at approximately $250,000.

No dealer, salesperson or other individual has been authorized to give any information or to make any representations not contained in this prospectus in connection with the exchange offer. If given or made, such information or representations must not be relied upon as having been authorized by us. Neither the delivery of this prospectus nor any exchange made hereunder shall, under any circumstances, create any implication that there has been no change in our affairs since the respective dates as of which information is given herein.

The exchange offer is not being made to (nor will tenders be accepted from or on behalf of) holders of initial notes in any jurisdiction in which the making of the exchange offer or the acceptance thereof would not be in compliance with the laws of such jurisdiction. However, we may, at our discretion, take such action as we may deem necessary to make the exchange offer in any such jurisdiction and extend the exchange offer to holders of initial notes in such jurisdiction. In any jurisdiction the securities laws or blue sky laws of which require the exchange offer to be made by a licensed broker or dealer, the exchange offer is being made on behalf of us by one or more registered brokers or dealers which are licensed under the laws of such jurisdiction.

The exchange of initial notes for exchange notes will not be a taxable exchange for U.S. federal income tax purposes, and holders will not recognize any taxable gain or loss or any interest income as a result of such exchange. See ‘‘Certain U.S. Federal Income Tax Considerations.’’

Participation in the exchange offer is voluntary and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decisions on what action to take.

As a result of the making of, and upon acceptance for exchange of all validly tendered initial notes pursuant to the terms of this exchange offer, we will have fulfilled a covenant contained in the terms of the initial notes and the registration rights agreement. Holders of the initial notes who do not tender their initial notes in the exchange offer will continue to hold such initial notes and will be entitled to all the rights, and limitations applicable thereto, under the indenture, except for any such rights under the registration rights agreement which by their terms terminate or cease to have further effect as a result of the making of this exchange offer. See ‘‘Description of the Notes.’’ All untendered initial notes will continue to be subject to the restriction, on transfer set forth in the indenture. To the extent that initial notes are tendered and accepted in the exchange offer, the trading market, if any, for the initial notes could be adversely affected. See ‘‘Risk Factors — Your ability to sell your initial notes may be significantly more limited and the price at which you may be able to sell your initial notes may be significantly lower if you do not exchange them for registered exchange notes in the exchange offer.’’

We may in the future seek to acquire untendered initial notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plan to acquire any initial notes which are not tendered in the exchange offer.

The following table sets forth our consolidated capitalization as of March 31, 2008 (in millions). The table should be read in conjunction with our selected consolidated historical financial and operating data and our historical Consolidated Financial Statements and notes thereto included elsewhere in this prospectus.


Consolidated indebtedness:
Short-term debt	$	22
Current portion of long-term debt		1,861
Current portion of MEHC subordinated debt — Berkshire Hathaway		234
MEHC senior debt		5,120
MEHC subordinated debt — Berkshire Hathaway		587
MEHC subordinated debt — other		305
Subsidiary and project debt		12,333
Total consolidated indebtedness		20,462
Minority interest		132
Preferred securities of subsidiaries		128
Shareholders’ equity:
Common stock — 115 shares authorized, no par value; 75 shares issued and outstanding		—
Additional paid-in capital		5,454
Retained earnings		4,124
Accumulated other comprehensive income, net		99
Total shareholders’ equity		9,677
Total capitalization	$	30,399

The following table sets forth our selected consolidated historical financial and operating data, which should be read in conjunction with our historical Consolidated Financial Statements and notes thereto included elsewhere in this prospectus. The selected consolidated historical financial and operating data as of March 31, 2008, and for the three-month periods ended March 31, 2008 and 2007, have been derived from our historical unaudited interim Consolidated Financial Statements and notes thereto included elsewhere in this prospectus. In the opinion of management, these historical unaudited interim Consolidated Financial Statements include all adjustments necessary for a fair presentation. The selected consolidated historical financial and operating data as of December 31, 2007 and 2006, and for each of the three years in the period ended December 31, 2007, have been derived from our historical audited Consolidated Financial Statements and notes thereto included elsewhere in this prospectus. The selected consolidated historical financial and operating data as of December 31, 2005, 2004 and 2003, and for the years ended December 31, 2004 and 2003, have been derived from our historical audited Consolidated Financial Statements and notes thereto not included in this prospectus.


	Three-Month Periods Ended March 31,						Years Ended December 31,
	2008			2007			2007			2006⁽¹⁾			2005			2004				2003
	(in millions)
Consolidated Statement of Operations Data:
Operating revenue		$	3,356		$	3,224		$	12,376		$	10,301		$	7,116		$	6,553			$	5,966
Depreciation and amortization			278			286			1,150			1,007			608			638				603
Total costs and expenses			2,584			2,485			9,688			8,181			5,587			5,028				4,516
Operating income			772			739			2,688			2,120			1,529			1,525				1,450
Interest expense, net of capitalized interest⁽²⁾			317			302			1,266			1,112			874			883				731
Income from continuing operations			342			313			1,189			916			558			538				443
Income (loss) from discontinued operations, net of tax⁽³⁾			—			—			—			—			5			(368	)			(27	)
Net income available to common and preferred shareholders			342			313			1,189			916			563			170				416


	As of March 31, 2008			As of December 31,
	As of March 31, 2008			2007			2006⁽¹⁾			2005			2004			2003
	(in millions)
Consolidated Balance Sheet Data:
Property, plant and equipment, net		$	26,555		$	26,221		$	24,039		$	11,915		$	11,607		$	11,181
Total assets			40,417			39,216			36,447			20,371			19,904			19,145
Short-term debt			22			130			552			70			9			48
Long-term debt, including current maturities:
MEHC senior debt			6,120			5,471			4,479			2,766			3,032			2,778
MEHC subordinated debt — Berkshire Hathaway			821			821			1,055			1,289			1,478			1,578
MEHC subordinated debt — other			305			304			302			299			297			294
Subsidiary and project debt			13,194			13,097			11,614			7,150			7,191			7,176
Preferred securities of subsidiaries			128			128			128			88			90			92
Total shareholders’ equity			9,677			9,326			8,011			3,385			2,971			2,771

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS

The following is management’s discussion and analysis of certain significant factors that have affected our financial condition and results of operations during the periods included herein. Explanations include management’s best estimate of the impact of weather, customer growth and other factors. This discussion should be read in conjunction with our historical unaudited interim Consolidated Financial Statements and the related notes thereto and our historical audited Consolidated Financial Statements and the related notes thereto included in the ‘‘Financial Statements’’ section of this prospectus. Our actual results in the future could differ significantly from the historical results.

Our operations are organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding, which primarily includes MidAmerican Energy, Northern Natural Gas, Kern River, CE Electric UK, which primarily includes Northern Electric and Yorkshire Electricity, CalEnergy Generation-Foreign, CalEnergy Generation-Domestic and HomeServices. Through these platforms, we own and operate an electric utility company in the Western United States, a combined electric and natural gas utility company in the Midwestern United States, two interstate natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of independent power projects and the second largest residential real estate brokerage firm in the United States.

Net income for the first quarter of 2008 was $342 million, an increase of $29 million, or 9%, from the comparable period in 2007. The increase was due primarily to favorable operating income at most regulated businesses, due primarily to improved margins, as well as benefits from a lower effective tax rate and lower minority interest expense. These benefits were partially offset by the transfer of two geothermal projects to the Philippine government in July 2007, lower earnings at HomeServices due to the continuing weak U.S. housing market and higher interest expense on MEHC senior debt.

The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to our significant accounting policies. The differences between the segment amounts and the consolidated amounts, described as ‘‘Corporate/other,’’ relate principally to corporate functions, including administrative costs and intersegment eliminations.

A comparison of operating revenue and operating income for our reportable segments are summarized as follows (in millions):

Operating revenue increased $68 million for the first quarter of 2008. Retail revenue increased $57 million due primarily to higher prices approved by regulators, higher average customer usage primarily due to weather and an increase in the average number of customers. Wholesale and other revenue increased $34 million due primarily to higher average prices offset by lower volumes and higher transmission revenue. Changes in the fair value of energy sales contracts accounted for as derivatives resulted in a $23 million decrease in operating revenue.

Operating income increased $11 million for the first quarter of 2008 due primarily to the aforementioned higher revenue, partially offset by an increase in fuel costs of $76 million. Fuel costs increased due primarily to higher natural gas consumed at PacifiCorp’s natural gas-fired generation facilities due to the addition of the 548-MW Lake Side plant in September 2007, higher coal consumed and higher average unit natural gas and coal costs. Fuel cost increases were partially offset by lower operating expenses, lower depreciation and amortization and a $14 million favorable impact from changes in the fair value of energy purchase contracts accounted for as derivatives.

MidAmerican Funding’s operating revenue and operating income are summarized as follows (in millions):

Regulated electric revenue increased $3 million for the first quarter of 2008 due to increases in retail revenue of $9 million, partially offset by lower wholesale revenue of $6 million. Retail revenue increased due primarily to an increase in the average number of retail customers and favorable weather conditions in 2008. Wholesale revenue decreased due to lower market prices, partially offset by higher sales volumes. Regulated natural gas revenue increased $72 million for the first quarter of 2008 due primarily to higher retail sales volumes resulting from colder temperatures and a higher average per-unit cost of gas sold. Nonregulated and other revenue increased $61 million for the first quarter of 2008 due to increases in electric retail customers, sales volumes and prices resulting from market conditions and higher gas revenue due primarily to higher volumes and prices.

Regulated electric operating income increased $21 million for the first quarter of 2008 as a result of higher gross margins totaling $23 million. Regulated electric gross margins increased due primarily to increased generation principally resulting from the addition of Walter Scott, Jr. Energy Center Unit No. 4, or WSEC Unit 4, and additional wind generation. Regulated natural gas operating income increased $4 million for the first quarter of 2008 due primarily to higher volumes sold. Nonregulated and other operating income increased $5 million for the first quarter of 2008 due primarily to higher gross margins on electric retail operating revenue increases.

Operating revenue decreased $2 million for the first quarter of 2008 due primarily to lower sales of gas for operational purposes of $15 million due primarily to lower sales volumes, partially offset by higher transportation and storage revenues of $13 million due primarily to higher volumes resulting from favorable market conditions. Operating income decreased $1 million for the first quarter of 2008.

Operating revenue increased $24 million for the first quarter of 2008 due to a reduction in customer refund liabilities related to Kern River’s current rate proceeding, partially offset by lower market oriented revenues as a result of less favorable market conditions in 2008.

Operating income increased $15 million for the first quarter of 2008 due primarily to the aforementioned increase in operating revenue, partially offset by a $6 million sales and use tax refund received in 2007 and higher depreciation expense in 2008.

Operating revenue increased $37 million for the first quarter of 2008 due primarily to higher distribution revenue of $32 million at Northern Electric and Yorkshire Electricity due primarily to tariff increases and higher contracting revenue.

Operating income increased $21 million for the first quarter of 2008 due primarily to higher revenues described above, partially offset by higher costs and expenses of $17 million. Costs and expenses were higher for the first quarter of 2008 due primarily to a reduction in expenses in 2007 due to a $17 million realized gain on the sale of certain CalEnergy Gas (Holdings) Limited, or CE Gas, assets.

Operating revenue decreased $37 million for the first quarter of 2008 as the Malitbog and Mahanagdong projects were transferred on July 25, 2007 to the Philippine government, which reduced operating revenue by $42 million. This decrease was partially offset by higher operating revenue of $5 million at the Casecnan project primarily due to higher variable energy fees as a result of increased generation from higher water flows.

Operating income decreased $23 million for the first quarter of 2008 due primarily to the aforementioned transfer of the Malitbog and Mahanagdong projects which resulted in lower operating income of $26 million.

Operating revenue decreased $94 million for the first quarter of 2008 due to a significant decline in transaction volumes reflecting the continuing weak U.S. housing market.

Operating income decreased $17 million for the first quarter of 2008 due primarily to the aforementioned decline in transaction volumes, partially offset by lower commissions and operating expenses.

Interest expense increased $12 million for the first quarter of 2008 due primarily to debt issuances at domestic energy businesses and at MEHC, partially offset by debt retirements and scheduled principal repayments.

Capitalized interest and other income, which includes equity allowance for funds used during construction, or AFUDC, decreased $3 million and $8 million, respectively, for the first quarter of 2008 due primarily to lower work in progress.

Income tax expense decreased $13 million to $147 million for the first quarter of 2008. The effective tax rates were 30% and 33% for the first quarter of 2008 and 2007, respectively. The decreases in income tax expense and the effective tax rate were primarily due to increased production tax credits at PacifiCorp and MidAmerican Funding associated with increased wind generation production and lower foreign taxes primarily due to a favorable foreign tax ruling.

Minority interest and preferred dividends of subsidiaries decreased $9 million to $4 million for the first quarter of 2008. The decrease was due primarily to additional expense in 2007 related to the minority ownership of the Casecnan project.

Net income for 2007 was $1.19 billion, an increase of $273 million, or 30%, compared to 2006. PacifiCorp, which was acquired on March 21, 2006, contributed an additional $235 million of net income in 2007 compared to 2006. Also contributing to the increase in net income were favorable operating results at our other domestic energy businesses, largely as a result of improved margins from favorable market conditions and additional generation assets being placed in service, a $58 million deferred income tax benefit recognized as a result of the reduction in the United Kingdom corporate income tax rate from 30% to 28% and the favorable impact from the foreign currency exchange rate. Net income decreased due to lower earnings at our foreign energy businesses, which included the planned turnover to the Philippine government of the Upper Mahiao project in June 2006 and the Malitbog and Mahanagdong projects in July 2007, lower earnings at HomeServices due to the general slowdown in the United States housing market, $73 million of after tax gains on sales of available-for-sale securities in 2006 and higher interest expense as a result of debt issuances at MEHC and our domestic energy businesses.

Net income for 2006 was $916 million, an increase of $353 million, or 63%, compared to 2005. Net income related to PacifiCorp, which was acquired on March 21, 2006, was $215 million during 2006. Also contributing to the increase in net income were favorable comparative results at most of our energy businesses and $73 million of after tax gains on sales of available-for-sale securities. These improvements were partially offset by lower earnings at HomeServices and higher interest expense on MEHC senior debt.

A comparison of operating revenue and operating income for our reportable segments for the years ended December 31 follows (in millions):

On March 21, 2006, we acquired 100% of the common stock of PacifiCorp. Our operating revenue for 2007 and 2006 consisted of retail revenue of $3.25 billion and $2.33 billion, respectively, and wholesale and other revenues of $1.01 billion and $610 million, respectively. PacifiCorp’s operating income was favorably impacted by higher retail revenues as a result of higher prices approved by regulators as well as continued growth in the number of customers and usage, higher net margins on wholesale activities due to higher average prices on sales and lower purchased electricity volumes and lower employee expense. These improvements were partially offset by higher fuel costs due to increased volumes of natural gas consumed in PacifiCorp’s generation plants and higher prices for coal, natural gas and purchased electricity.

MidAmerican Funding’s operating revenue and operating income for the years ended December 31 are summarized as follows (in millions):

Regulated electric revenue increased $155 million for 2007 compared to 2006 due to increases in wholesale revenue of $103 million and retail revenue of $52 million. Wholesale revenue increased due primarily to higher sales volumes, as a result of new generating assets placed in service during 2007 and improved market opportunities, and prices. Retail revenue increased due primarily to growth in retail demand, an increase in the average number of retail customers and favorable weather conditions in 2007. Regulated natural gas revenue increased $62 million for 2007 compared to 2006 due primarily to higher retail sales volumes and an increase in the average per-unit cost of gas sold, partially offset by lower wholesale sales volumes. Nonregulated and other revenue increased $597 million for 2007 compared to 2006 due primarily to increases in electric retail sales volumes and prices driven by improved market opportunities, partially offset by decreases in gas sales volumes and prices.

Regulated electric revenue increased $266 million for 2006 compared to 2005 due to increases in wholesale revenue of $219 million and retail revenue of $47 million. Wholesale revenue increased due primarily to higher average electric energy prices and volumes as a result of additional generation placed in service and greater market opportunities. Retail revenue increased due primarily to an increase in retail demand and usage, partially offset by lower revenue due to mild summer temperatures in 2006. Regulated natural gas revenue decreased $211 million for 2006 compared to 2005 due primarily to a decrease in the average per-unit cost of gas sold and lower volumes. Nonregulated and other revenue increased $232 million for 2006 compared to 2005 due primarily to a change in management strategy related to certain end-use natural gas contracts that required the related revenues and cost of sales to be recorded prospectively on a gross, rather than net, basis, partially offset by a decrease in natural gas sales volumes and lower electric and natural gas prices. In 2005, cost of sales totaling $289 million were netted in nonregulated operating revenue for such end-use gas contracts.

Regulated electric operating income increased $26 million for 2007 compared to 2006 as a result of higher gross margins of $86 million from both retail and wholesale sales and lower depreciation and amortization of $7 million, partially offset by higher operating expenses of $67 million. Depreciation and amortization was lower in 2007 due primarily to a $25 million decrease in regulatory expense related to a revenue sharing arrangement in Iowa as a result of lower Iowa electric equity returns, partially offset by higher depreciation as a result of new generation assets placed in service in 2007. Operating expenses were higher due primarily to maintenance costs incurred for restoration of facilities damaged by storms, new generation assets placed in service during 2007 and the timing of maintenance for natural gas-fueled generating facilities. Operating income for regulated natural gas and nonregulated and other increased $17 million and $50 million, respectively, due primarily to higher gross margins on the aforementioned operating revenue increases.

Regulated electric operating income increased $38 million for 2006 compared to 2005 as a result of higher gross margins of $71 million due to the aforementioned higher sales volumes and prices, partially offset by $28 million of higher operating expenses and $6 million of higher depreciation and amortization expense. The increase in operating expenses was due primarily to higher generating plant operating and maintenance expenses including additional expense for wind generation.

Operating revenue increased $30 million for 2007 compared to 2006 due to higher transportation and storage revenues of $47 million on higher rates and volumes from favorable market conditions, partially offset by a lower volume of gas and condensate liquids sales of $17 million, which are both utilized in the operation and balancing of the pipeline system. Operating revenue increased $65 million for 2006 compared to 2005 due primarily to higher transportation and storage revenues due to higher rates and volumes from favorable market conditions.

Operating income increased $39 million for 2007 compared to 2006 due primarily to the aforementioned increase in transportation and storage revenues, partially offset by a $6 million asset impairment charge. Operating income increased $60 million for 2006 compared to 2005 due to the aforementioned increase in transportation and storage revenues. Several non-routine events also impacted operating income in 2005, including a $29 million asset impairment charge of a non-contiguous portion of the pipeline system, a gain of $20 million from the sale of an idled section of pipeline in Oklahoma and Texas and the adjustments from two FERC-approved settlements that increased operating income by $16 million.

Operating revenue increased $79 million for 2007 compared to 2006. Kern River earned higher market oriented revenue of $50 million as a result of more favorable market conditions in 2007. Additionally, Kern River received a FERC order in 2006 that resulted in a $34 million reduction to operating revenue for rate case estimated refunds. Operating revenue increased $1 million for 2006 compared to 2005 as higher market oriented revenue of $34 million due to favorable market conditions was offset by the aforementioned adjustment to Kern River’s provision for estimated refunds.

Operating income increased $60 million for 2007 compared to 2006 due primarily to the aforementioned increase in market oriented revenue. The $34 million decrease in revenue related to the FERC order received in 2006 was largely offset by a corresponding $28 million adjustment that also lowered depreciation and amortization expense. Also contributing to the increase in operating income for 2007 compared to 2006 was $8 million of lower depreciation and amortization expense due mainly to changes in the expected depreciation rates in connection with the current rate proceeding and a $6 million sales and use tax refund received in 2007. Operating income increased $13 million for 2006 compared to 2005 due primarily to lower depreciation and amortization due primarily to changes in the expected rates in connection with the current rate proceeding.

Operating revenue increased $151 million for 2007 compared to 2006 due primarily to a $79 million favorable impact from the exchange rate, higher distribution revenue of $33 million at Northern Electric and Yorkshire Electricity, due primarily to tariff increases, and higher revenue of $32 million at CE Gas, primarily from higher gas production. Operating revenue increased $44 million for 2006 compared to 2005 due primarily to higher contracting revenue of $21 million, higher distribution revenues at Northern Electric and Yorkshire Electricity of $14 million due to higher units distributed and the favorable impact of the exchange rate of $12 million.

Operating income increased $39 million for 2007 compared to 2006 due primarily to higher gross margins on distribution and gas production revenues totaling $60 million and the favorable impact from the exchange rate of $43 million, partially offset by higher costs and expenses of $62 million. Costs and expenses were higher for 2007 due primarily to higher depreciation and amortization expense of $37 million primarily associated with distribution assets, higher distribution costs of $18 million due mainly to higher maintenance and restoration costs, and the write-off of an unsuccessful exploration well at CE Gas, partially offset by a realized gain on the sale of certain CE Gas assets in 2007. Operating income increased $32 million for 2006 compared to 2005 due primarily to the higher distribution revenues and the favorable impact of the exchange rate.

Operating revenue decreased $116 million for 2007 compared to 2006 as the Malitbog and Mahanagdong projects were transferred on July 25, 2007, and the Upper Mahiao project was transferred on June 25, 2006, to the Philippine government, which reduced operating revenue by $92 million. Additionally, operating revenue at the Casecnan project was lower by $24 million as a result of lower water flows and related energy production. Operating revenue increased $24 million for 2006 compared to 2005. Higher revenue at the Casecnan project of $42 million as a result of above normal water flows throughout 2006 was partially offset by lower operating revenue of $18 million due primarily to the aforementioned transfer of the Upper Mahiao project.

Operating income decreased $88 million for 2007 compared to 2006. Lower revenue was partially offset by lower depreciation and amortization expense of $30 million as the projects were transferred. Operating income increased $45 million for 2006 compared to 2005 due primarily to the higher revenue as well as lower operating expenses of $15 million due primarily to the aforementioned transfer of the Upper Mahiao project.

Operating revenue decreased $202 million for 2007 compared to 2006 and $166 million for 2006 compared to 2005 due to the general slowdown in the U.S. housing market and the resulting lower number of brokerage transactions.

Operating income decreased $22 million for 2007 compared to 2006 due mainly to the aforementioned decrease in brokerage transactions, partially offset by lower commissions, operating expenses and depreciation and amortization expense. Operating income decreased $70 million for 2006 compared to 2005 due mainly to the aforementioned decrease in brokerage transactions and higher acquisition related amortization, partially offset by lower operating expenses due primarily to lower salaries and employee benefits expenses.

Interest expense for the years ended December 31 is summarized as follows (in millions):

Interest expense increased $168 million for 2007 compared to 2006 and $261 million for 2006 compared to 2005 due to the acquisition of PacifiCorp, debt issuances at our domestic energy businesses and at MEHC, and the higher exchange rate. Interest expense was higher by $90 million in 2007 and $224 million in 2006 as a result of the acquisition of PacifiCorp. The increase in interest expense for 2007 and 2006 was partially offset by debt retirements and scheduled principal repayments.

Other income, net for the years ended December 31 is summarized as follows (in millions):

Capitalized interest increased $14 million for 2007 compared to 2006 and $23 million for 2006 compared to 2005 due primarily to the acquisition of PacifiCorp and increased levels of capital project expenditures at MidAmerican Energy.

Interest and dividend income increased $32 million for 2007 compared to 2006 due primarily to more favorable cash positions at MEHC and certain subsidiaries as a result of 2007 debt issuances as well as $9 million resulting from the acquisition of PacifiCorp. Interest and dividend income increased $15 million for 2006 compared to 2005 due primarily to the acquisition of PacifiCorp.

Other income decreased $117 million for 2007 compared to 2006 and increased $164 million for 2006 compared to 2005. Other income for 2006 included Kern River’s $89 million of gains from the sale of Mirant stock and $47 million of gains at MidAmerican Funding from the sales of other non-strategic investments. Partially offsetting the decrease for 2007 compared to 2006 was higher equity AFUDC of $28 million due to increased levels of capital project expenditures. Additionally, other income was higher by $27 million for 2006 compared to 2005 as a result of the acquisition of PacifiCorp.

Other expense decreased $10 million for 2006 compared to 2005 due primarily to 2005 losses for other-than-temporary impairments of MidAmerican Funding’s investments in commercial passenger aircraft leased to major domestic airlines.

Income tax expense increased $49 million, or 12%, for 2007 compared to 2006. The effective tax rates were 28% and 31% for 2007 and 2006, respectively. The increase in income tax expense is due primarily to higher pretax earnings, partially offset by the recognition of $58 million of deferred income tax benefits due to a reduction in the United Kingdom corporate income tax rate from 30% to 28%. Adjusting for the effect of the change in the United Kingdom corporate income tax rate, the 2007 effective tax rate was 31%.

Income tax expense increased $162 million, or 66%, for 2006 compared to 2005. The effective tax rates were 31% and 32% for 2006 and 2005, respectively. The increase in income tax expense was due to higher pretax earnings.

Minority interest and preferred dividends of subsidiaries increased $12 million to $27 million for 2006 compared to 2005 due mainly to higher earnings at CE Casecnan Water and Energy, Inc., or CE Casecnan, and preferred dividends at PacifiCorp.

Equity income decreased $7 million to $36 million for 2007 compared to 2006 due primarily to the sale and write-off of an investment in a mortgage joint venture at HomeServices. Equity income decreased $10 million to $43 million for 2006 compared to 2005 due primarily to lower earnings at CE Generation, LLC, or CE Generation, as a result of higher depreciation and maintenance expenses and lower equity income at HomeServices due to lower refinancing activity at its residential mortgage loan joint ventures.

We have available a variety of sources of liquidity and capital resources, both internal and external, including the Berkshire Equity Commitment. These resources provide funds required for current operations, construction expenditures, debt retirement and other capital requirements. We may from time to time seek to acquire our outstanding securities through cash purchases in the open market, privately negotiated transactions or otherwise. Such repurchases, if any, may be temporary, and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Each of our direct and indirect subsidiaries is organized as a legal entity separate and apart from us and our other subsidiaries. Pursuant to separate financing agreements, the assets of each subsidiary may be pledged or encumbered to support or otherwise provide the security for its own project or subsidiary debt. It should not be assumed that any asset of any subsidiary of ours will be available to satisfy the obligations of us or any of our other subsidiaries’ obligations. However, unrestricted cash or other assets which are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to us or affiliates thereof.

Our cash and cash equivalents were $2.19 billion as of March 31, 2008, compared to $1.18 billion and $343 million as of December 31, 2007 and 2006, respectively. We recorded separately in other current assets, restricted cash and investments as of March 31, 2008, December 31, 2007 and December 31, 2006 of $84 million, $73 million and $132 million, respectively. The restricted cash and investments balance is mainly composed of current amounts deposited in restricted accounts relating to (i) our debt service reserve requirements relating to certain projects, (ii) trust funds related to mine reclamation costs, (iii) customer deposits held in escrow, (iv) custody deposits, and (v) unpaid dividends declared obligations. The debt service funds are restricted by their respective project debt agreements to be used only for the related project. Additionally, we have restricted cash and investments recorded in deferred charges, investments and other assets of $400 million, $425 million and $399 million as of March 31, 2008, December 31, 2007 and December 31, 2006, respectively, that

principally relate to trust funds held for mine reclamation and nuclear decommissioning costs. As of March 31, 2008, we had $556 million of availability under our $600 million revolving credit facility with letters of credit issued under the credit agreement totaling $44 million and no borrowings outstanding.

Cash flows generated from operations for the three-month periods ended March 31, 2008 and 2007 were $777 million and $819 million, respectively. The decrease was due primarily to the timing of payments and cash collections and the transfer of the Malitbog and Mahanagdong projects, partially offset by higher margins in 2008. Additionally, we expect to pay refunds when the Kern River rate case is finalized as discussed in Note 4 of our Notes to unaudited interim Consolidated Financial Statements included in the ‘‘Financial Statements’’ section of this prospectus.

Cash flows generated from operations for the years ended December 31, 2007 and 2006 were $2.34 billion and $1.92 billion, respectively. The increase was mainly due to the acquisition of PacifiCorp on March 21, 2006, which contributed $399 million to the increase in operating cash flows. Higher cash flows from operations at MidAmerican Energy, Kern River and CE Electric UK were largely offset by lower cash flows from operations at CalEnergy Generation-Foreign, as a result of the transfer of the Malitbog and Mahanagdong projects to the Philippine government in 2007, and HomeServices.

Cash flows used in investing activities for the three-month periods ended March 31, 2008 and 2007 were $312 million and $834 million, respectively. In February 2008, we received proceeds from the maturity of a guaranteed investment contract of $393 million. Also, capital expenditures decreased $109 million in part due to WSEC Unit 4 beginning commercial operations in June 2007.

Cash flows used in investing activities for the years ended December 31, 2007 and 2006 were $3.25 billion and $7.32 billion, respectively. In 2007, a certain wholly owned subsidiary of CE Electric UK received proceeds of $201 million from the maturity of a guaranteed investment contract. Capital expenditures, construction and other development costs increased $1.09 billion for 2007 compared to 2006. Additionally, net purchases and sales of available-for-sale securities resulted in higher cash outflows for 2007 of $157 million due primarily to Kern River’s receipt of $89 million in proceeds from the sale of Mirant stock in 2006 and MidAmerican Funding’s receipt of $28 million in proceeds from the sale of common shares held in an electronic energy and metals trading exchange in 2006. In 2006, we acquired PacifiCorp for $4.93 billion, net of cash acquired.

On March 21, 2006, a wholly owned subsidiary ours acquired 100% of the common stock of PacifiCorp from a wholly owned subsidiary of ScottishPower for a cash purchase price of $5.11 billion, which was funded through the issuance of common stock. We also incurred $10 million of direct transaction costs associated with the acquisition, which consisted principally of investment banker commissions and outside legal and accounting fees and expenses, resulting in a total purchase price of $5.12 billion. The results of PacifiCorp’s operations are included in our results beginning March 21, 2006.

In the first quarter of 2006, the state commissions in all six states where PacifiCorp has retail customers approved the sale of PacifiCorp to us. The approvals were conditioned on a number of regulatory commitments, including expected financial benefits in the form of reduced corporate overhead and financing costs, certain mid- to long-term capital and other expenditures of significant amounts and a commitment not to seek utility rate increases attributable solely to the change in ownership. The capital and other expenditures proposed by us and PacifiCorp include:

As of December 31, 2007, PacifiCorp had incurred $205 million in capital expenditures related to its commitment to invest in emissions reduction technology for its existing coal plants, and $112 million of capital expenditures and $16 million of operating expenses related to its commitment to invest in its transmission and distribution system. PacifiCorp met the requirements of its commitment to bring 100 MW of cost-effective wind resources into service by March 21, 2007 with the completion of the 101-MW Leaning Juniper wind plant, which was placed in service in September 2006. Additionally, PacifiCorp met its commitment to add 400 MW of cost-effective renewable resources to its generation portfolio by December 31, 2007.

Capital expenditures include both those relating to operating projects and to construction and other development costs. Capital expenditures by reportable segment for the three-month periods ended March 31 and for the years ended December 31 are summarized as follows (in millions):

Capital expenditures relating to operating projects, mainly for distribution, transmission, generation, mining and other infrastructure needed to serve existing and growing demand, totaled $395 million for the three-month period ended March 31, 2008. Capital expenditures relating to construction and other development costs totaled $315 million for the three-month period ended March 31, 2008 and consisted primarily of the following:

Capital expenditures relating to operating projects, mainly for distribution, transmission, generation, mining and other infrastructure needed to serve existing and growing demand, totaled $1.69 billion in 2007. Capital expenditures relating to construction and other development costs totaled $1.82 billion in 2007 and consisted primarily of the following:

We have significant future capital requirements. Forecasted capital expenditures for fiscal 2008, which exclude non-cash equity AFUDC, are approximately $4.3 billion and consist of $2.0 billion for operating projects mainly for distribution, transmission, generation, mining and other infrastructure needed to serve existing and growing demand, and $2.3 billion for construction and other development projects.

Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews. Estimates may change significantly at any time as a result of, among other factors, changes in rules and regulations, including environmental and nuclear, changes in income tax laws, general business conditions, load projections, the cost and efficiency of construction labor, equipment, and materials, and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. We expect to meet our capital expenditure requirements with cash flows from operations and the issuance of debt. To the extent funds are not available to support capital expenditures, projects may be delayed and operating income may be reduced.

Projected 2008 construction and other development expenditures include the following:

In April 2008, PacifiCorp entered into a purchase agreement to acquire 100% of the equity interests of an entity owning a 520-MW natural gas-fired facility located in Chehalis, Washington. This anticipated acquisition is not included in the above forecasted capital expenditures for fiscal 2008. The acquisition is subject to regulatory approval of the transaction by the FERC, the Department of Justice/Federal Trade Commission pursuant to the Hart-Scott-Rodino Act, the Federal Communications Commission, the Utah Public Service Commission, or the UPSC, and the Washington Energy Facilities Siting Council. In April 2008, PacifiCorp filed requests with the UPSC and the Oregon Public Utility Commission, or the OPUC, seeking a waiver of state-mandated request for proposal procurement processes to purchase a generating facility. Also in April 2008, PacifiCorp filed with the FERC its application under Section 203 of the Federal Power Act.

We are subject to federal, state, local and foreign laws and regulations with regard to air and water quality, renewable portfolio standards, hazardous and solid waste disposal and other environmental matters. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to us. In particular, future mandates, including those associated with addressing the issue of global climate change, may impact the operation of our domestic generating facilities and may require both PacifiCorp and MidAmerican Energy to reduce emissions at their facilities through the installation of additional emission control equipment or to purchase additional emission allowances or offsets in the future. We are not aware of any proven commercially available technology that eliminates or captures and stores carbon dioxide emissions from coal-fired and other gas fired facilities and we are uncertain when, or if, such technology will be commercially available.

Expenditures for compliance-related items such as pollution-control technologies, replacement generation, mine reclamation, nuclear decommissioning, hydroelectric relicensing, hydroelectric decommissioning and associated operating costs are generally incorporated into our regulated retail rates. An inability to recover these costs from our customers, either through regulated rates, long-term arrangements or market prices could adversely affect our future financial results.

Refer to Environmental Regulation included in the ‘‘Regulation’’ section of this prospectus for a detailed discussion of the topic.

Cash flows generated from financing activities for the first three months of 2008 were $543 million. Sources of cash totaled $1.05 billion and consisted mainly of proceeds from the issuance of MEHC senior debt totaling $649 million and subsidiary and project debt totaling $397 million. Uses of cash totaled $506 million and consisted mainly of $399 million for repayments of subsidiary and project debt and $107 million of net repayments of subsidiary short-term debt.

Cash flows generated from financing activities for the first three months of 2007 were $621 million. Sources of cash totaled $751 million and consisted of proceeds from the issuance of subsidiary and project debt. Uses of cash totaled $130 million and consisted primarily of $84 million of net repayments of subsidiary short-term debt and $38 million of repayments of subsidiary and project debt.

Cash flows from financing activities were $1.75 billion for the year ended December 31, 2007. Sources of cash totaled $3.58 billion and consisted primarily of $2 billion of proceeds from the issuance of subsidiary and project debt and $1.54 billion of proceeds from the issuance of MEHC senior debt. Uses of cash totaled $1.83 billion and consisted primarily of $784 million for repayments of MEHC senior and subordinated debt, $599 million for repayments of subsidiary and project debt, $269 million for net repayments of subsidiary short-term debt and $152 million for net repayments of our revolving credit facility.

Cash flows from financing activities were $5.38 billion for the year ended December 31, 2006. Sources of cash totaled $7.90 billion and consisted primarily of $5.13 billion of proceeds from the issuance of common stock, $1.70 billion of proceeds from the issuance of MEHC senior debt and $718 million of proceeds from the issuance of subsidiary and project debt. Uses of cash totaled $2.52 billion and consisted primarily of $1.75 billion of repurchases of common stock, $516 million for repayments of subsidiary and project debt and $234 million for repayments of MEHC subordinated debt.

In 2007, 370,000 common stock options were exercised having a weighted average exercise price of $26.99 per share and in 2006, 775,000 common stock options were exercised having a weighted average exercise price of $28.65 per share.

On March 1, 2006, we and Berkshire Hathaway entered into the Berkshire Equity Commitment pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of our common equity upon any requests authorized from time to time by our Board of Directors. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due MEHC’s debt obligations and (b) funding the general corporate purposes and capital requirements of our regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request. The Berkshire Equity Commitment will expire on February 28, 2011, was not used for the PacifiCorp acquisition and will not be used for future acquisitions.

On March 21, 2006, Berkshire Hathaway and certain other of our existing shareholders and related companies invested $5.11 billion, in the aggregate, in 35,237,931 shares of our common stock in order to provide equity funding for the PacifiCorp acquisition. The per-share value assigned to the shares of common stock issued, which were effected pursuant to a private placement and were exempt from the registration requirements of the Securities Act of 1933, as amended, was based on an assumed fair market value as agreed to by our shareholders.

In March 2006, we repurchased 12,068,412 shares of common stock for an aggregate purchase price of $1.75 billion.

In addition to the debt issuances discussed herein, our subsidiaries made scheduled repayments on subsidiary and project debt totaling approximately $399 million during the three-month period ended March 31, 2008.

In addition to the debt issuances discussed herein, we and our subsidiaries made scheduled repayments on MEHC senior and subordinated debt and subsidiary and project debt totaling approximately $1.38 billion during the year ended December 31, 2007.

In addition to the debt issuances discussed herein, we and our subsidiaries made scheduled repayments on MEHC subordinated debt and subsidiary and project debt totaling approximately $750 million during the year ended December 31, 2006.

As of March 31, 2008, our senior unsecured debt credit ratings were as follows: Moody’s Investor Service, ‘‘Baa1/stable;’’ Standard and Poor’s, ‘‘BBB+/stable;’’ and Fitch Ratings, ‘‘BBB+/stable.’’

Debt and preferred securities of ours and certain of our subsidiaries are 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 issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time. Other than the agreements discussed below, we and our subsidiaries do 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 their risk management activities, PacifiCorp and MidAmerican Energy must meet credit quality standards as required by counterparties. In accordance with industry practice, master agreements that govern PacifiCorp’s and MidAmerican Energy’s energy supply and marketing activities either specifically require each company 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 PacifiCorp’s or MidAmerican Energy’s creditworthiness. If one or more of PacifiCorp’s or MidAmerican Energy’s credit ratings decline below investment grade, PacifiCorp or MidAmerican Energy may be required to post cash collateral, letters of credit or other similar credit support to facilitate ongoing wholesale energy supply and marketing activities. As of March 31, 2008, PacifiCorp’s and MidAmerican Energy’s credit ratings from the three recognized credit rating agencies were investment grade; however if the ratings fell one rating below investment grade, the PacifiCorp and MidAmerican Energy estimated potential collateral requirements would total approximately $332 million and $194 million, respectively. Additional collateral requirements would be necessary if ratings fell further than one rating below investment grade. The potential collateral requirements could fluctuate considerably due to seasonality, market price volatility, and a loss of key generating facilities or other related factors.

We have contractual obligations and commercial commitments that may affect our financial condition. Contractual obligations to make future payments arise from MEHC and subsidiary long-term debt and notes payable, operating leases, purchase obligations and power and fuel purchase contracts. Other obligations and commitments arise from unused lines of credit and letters of credit. Material obligations and commitments as of December 31, 2007 are as follows (in millions):


	Payments Due By Periods
	Total			2008			2009– 2010			2011– 2012			2013 and After
Contractual Cash Obligations:
MEHC senior debt		$	5,475		$	1,000		$	—		$	500		$	3,975
MEHC subordinated debt			1,196			234			423			269			270
Subsidiary and project debt			13,000			966			561			1,994			9,479
Interest payments on long-term debt⁽¹⁾			19,379			1,233			2,154			1,939			14,053
Short-term debt			130			130			—			—			—
Coal, electricity and natural gas contract commitments⁽¹⁾			8,523			1,637			2,289			1,055			3,542
Purchase obligations⁽¹⁾			602			440			85			26			51
Owned hydroelectric commitments⁽¹⁾			812			39			109			126			538
Operating leases⁽¹⁾			549			100			147			94			208
Minimum pension funding requirements			490			112			92			92			194
Total contractual cash obligations		$	50,156		$	5,891		$	5,860		$	6,095		$	32,310


	Commitment Expiration per Period
	Total			2008			2009– 2010			2011– 2012			2013 and After
Other Commercial Commitments:
Unused revolving credit facilities and lines of credit –
MEHC revolving credit facility		$	554		$	—		$	—		$	554		$	—
Subsidiary revolving credit facilities and lines of credit			2,073			—			279			1,794			—
Total unused revolving credit facilities and lines of credit		$	2,627		$	—		$	279		$	2,348		$	—
MEHC letters of credit outstanding		$	47		$	23		$	24		$	—		$	—
Pollution control revenue bond standby letters of credit		$	297		$	—		$	—		$	297		$	—
Pollution control revenue bond standby bond purchase agreements		$	221		$	124		$	—		$	97		$	—
Other standby letters of credit		$	90		$	20		$	6		$	64		$	—

We have other types of commitments that relate primarily to construction and other development costs (Liquidity and Capital Resources included within this ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ section of this prospectus), debt guarantees (Note 11), asset retirement obligations (Note 12) and uncertain tax positions (Note 15) which have not been included in the above tables because the amount and timing of the cash payments are not certain. Refer, where applicable, to the respective referenced note in our Notes to audited Consolidated Financial Statements included in the ‘‘Financial Statements’’ section of this prospectus for additional information.

As of March 31, 2008, there were no material changes in the contractual obligations and commercial commitments from the information provided above for the year ended December 31, 2007, other than the 2008 debt issuances previously discussed.

We have certain investments that are accounted for under the equity method in accordance with accounting principles generally accepted in the United States of America, or GAAP. Accordingly, an amount is recorded on our Consolidated Balance Sheets as an equity investment and is increased or decreased for our pro-rata share of earnings or losses, respectively, less any dividend distribution from such investments.

As of March 31, 2008, our investments that are accounted for under the equity method had short- and long-term debt, unused revolving credit facilities and letters of credit outstanding of $659 million, $205 million and $78 million, respectively. As of March 31, 2008, our pro-rata share of such short- and long-term debt, unused revolving credit facilities and outstanding letters of credit was $328 million, $103 million and $39 million, respectively. The entire amount of our pro-rata share of the outstanding short- and long-term debt and unused revolving credit facilities is non-recourse to us. $32 million of our pro-rata share of the outstanding letters of credit is recourse to us. We have included in the Obligations and Commitments table our pro-rata share of outstanding letters of credit with recourse to us as of December 31, 2007. Although we are generally not required to support debt service obligations of our equity investees, default with respect to this non-recourse short- and long-term debt could result in a loss of invested equity.

For a discussion of new accounting pronouncements affecting us, refer to Note 2 of our Notes to unaudited interim Consolidated Financial Statements included in the ‘‘Financial Statements’’ section of this prospectus.

Certain accounting policies require management to make estimates and judgments concerning transactions that will be settled in the future. Amounts recognized in the Consolidated Financial Statements from such estimates are necessarily based on numerous assumptions involving varying and potentially significant degrees of judgment and uncertainty. Accordingly, the amounts currently reflected in the Consolidated Financial Statements will likely increase or decrease in the future as additional information becomes available. The following critical accounting policies are impacted significantly by judgments, assumptions and estimates used in the preparation of the Consolidated Financial Statements. Our critical accounting policies have not changed materially since December 31, 2007.

PacifiCorp, MidAmerican Energy, Northern Natural Gas and Kern River, or the Domestic Regulated Businesses, prepare their financial statements in accordance with the provisions of Statement of Financial Accounting Standards, or SFAS, No. 71, ‘‘Accounting for the Effects of Certain Types of Regulation,’’ or SFAS No. 71, which differs in certain respects from the application of GAAP by non-regulated businesses. In general, SFAS No. 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated entity is required to defer the recognition of costs or income if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, the Domestic Regulated Businesses have deferred certain costs and income that will be recognized in earnings over various future periods.

Management continually evaluates the applicability of SFAS No. 71 and assesses whether our regulatory assets are probable of future recovery by considering factors such as a change in the regulator’s approach to setting rates from cost-based rate making to another form of regulation, other regulatory actions or the impact of competition which could limit our ability to recover our costs. Based upon this continual assessment, management believes the application of SFAS No. 71 continues to be appropriate and our existing regulatory assets are probable of recovery. The assessment reflects the current political and regulatory climate at both the state and federal levels and is subject to change in the future. If it becomes no longer probable that these costs will be recovered, the regulatory assets and regulatory liabilities would be written off and recognized in operating income. Total regulatory assets were $1.50 billion and total regulatory liabilities were $1.63 billion as of December 31, 2007. Refer to Note 6 of our Notes to audited Consolidated Financial Statements included in the ‘‘Financial Statements’’ section of this prospectus for additional information regarding our regulatory assets and liabilities.

We are exposed to variations in the market prices of electricity and natural gas, foreign currency and interest rates and we use derivative instruments, including forward purchases and sales, futures, swaps and options to manage these inherent market price risks.

Derivative instruments are recorded in the Consolidated Balance Sheets at fair value as either assets or liabilities unless they are designated and qualifying for the normal purchases and normal sales exemption afforded by GAAP. The fair values of derivative instruments are determined using forward price curves. Forward price curves represent our estimates of the prices at which a buyer or

seller could contract today for delivery or settlement at future dates. We base our forward price curves upon market price quotations when available and use internally developed, modeled prices when market quotations are unavailable. The fair value of these instruments is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. The assumptions used in these models are critical, since any changes in assumptions could have a significant impact on the fair value of the contracts.

Almost all of our contracts are probable of recovery in rates, and therefore recorded as a net regulatory asset or liability, or are accounted for as cash flow hedges and therefore changes in fair value are recorded as accumulated other comprehensive income (loss). Accordingly, amounts are generally not recognized in earnings until the contracts are settled. As of December 31, 2007, we had $276 million recorded as net regulatory assets and $91 million recorded as accumulated other comprehensive income (loss), before tax, related to these contracts in the Consolidated Balance Sheets. If it becomes no longer probable that a contract will be recovered in rates, the regulatory asset will be written-off and recognized in earnings. For contracts designated in hedge relationships, or hedge contracts, we discontinue hedge accounting prospectively when we have determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued, future changes in the value of the derivative are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in accumulated other comprehensive income will remain there until the hedged item is realized, unless it is probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in accumulated other comprehensive income are immediately recognized in earnings.

We evaluate long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable or the assets meet the criteria of held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated discounted present value of the expected future cash flows from using the asset. For regulated assets, any impairment charge is offset by the establishment of a regulatory asset to the extent recovery in rates is probable. Substantially all of property, plant and equipment was used in regulated businesses as of December 31, 2007. For all other assets, any resulting impairment loss is reflected in the Consolidated Statements of Operations.

The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what we would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from, but are not limited to, significant changes in the regulatory environment, the business climate, management’s plans, legal factors, market price of the asset, the use of the asset or the physical condition of the asset. An impairment analysis of generating facilities or pipelines requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the facilities. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect our results of operations.

Our Consolidated Balance Sheet as of December 31, 2007 includes goodwill of acquired businesses of $5.34 billion. Goodwill is allocated to each reporting unit and is tested for impairment using a variety of methods, principally discounted projected future net cash flows, at least annually and impairments, if any, are charged to earnings. We completed our annual review as of October 31. A significant amount of judgment is required in performing goodwill impairment tests. Key assumptions used in the testing include, but are not limited to, the use of estimated future cash flows,

earnings before interest, taxes, depreciation and amortization multiples and an appropriate discount rate. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating cash flows, we incorporate current market information as well as historical factors.

We sponsor defined benefit pension and other postretirement benefit plans that cover the majority of our employees. We recognize the funded status of our defined benefit pension and postretirement plans in the Consolidated Balance Sheet. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2007, we recognized an asset totaling $162 million for the over-funded status and a liability totaling $442 million for the under-funded status for our defined benefit pension and other postretirement benefit plans.

The expense and benefit obligations relating to these pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected returns on plan assets and health care cost trend rates. These actuarial assumptions are reviewed annually and modified as appropriate. We believe that the assumptions utilized in recording obligations under the plans are reasonable based on prior experience and market conditions. Refer to Note 19 of our Notes to audited Consolidated Financial Statements included in the ‘‘Financial Statements’’ section of this prospectus for disclosures about our pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic cost for these plans as of and for the period ended December 31, 2007.

In establishing our assumption as to the expected return on assets, we review the expected asset allocation and develop return assumptions for each asset class based on historical performance and forward-looking views of the financial markets. Pension and other postretirement benefit expenses increase as the expected rate of return on retirement plan and other postretirement benefit plan assets decreases. We regularly review our actual asset allocations and periodically rebalance our investments to our targeted allocations when considered appropriate.

We choose a discount rate based upon high quality fixed-income investment yields in effect as of the measurement date that corresponds to the expected benefit period. The pension and other postretirement benefit liabilities, as well as expenses, increase as the discount rate is reduced.

We choose a health care cost trend rate which reflects the near and long-term expectations of increases in medical costs. The health care cost trend rate gradually declines to 5% in 2010 through 2016 at which point the rate is assumed to remain constant. Refer to Note 19 of our Notes to audited Consolidated Financial Statements included in the ‘‘Financial Statements’’ section of this prospectus for health care cost trend rate sensitivity disclosures.

The actuarial assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to the amount of pension and postretirement benefit expense recorded and the funded status. If changes were to occur for the following assumptions, the approximate effect on the financial statements would be as follows (in millions):

A variety of factors, including our plan funding practices, affect the funded status of the plans. The Pension Protection Act of 2006 imposed generally more stringent funding requirements for defined benefit pension plans, particularly for those significantly under-funded, and allowed for greater tax deductible contributions to such plans than previous rules permitted under the Employee Retirement Income Security Act. As a result of the Pension Protection Act of 2006, we do not anticipate any significant changes to the amount of funding previously anticipated through 2008; however, depending on a variety of factors which impact the funded status of the plans, including asset returns, discount rates and plan changes, we may be required to accelerate contributions to our domestic pension plans for periods after 2008 and there may be more volatility in annual contributions than historically experienced, which could have a material impact on our financial results.

In determining our tax liabilities, management is required to interpret complex tax laws and regulations. In preparing tax returns, we are subject to continuous examinations by federal, state, local and foreign tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The U.S. Internal Revenue Service has closed examination of our income tax returns through 2003. In the U.K., each legal entity is subject to examination by HM Revenue and Customs, or HMRC, the U.K. equivalent of the U.S. Internal Revenue Service. HMRC has closed examination of income tax returns for the separate entities from 2000 to 2005. Most significantly, Northern Electric’s and Yorkshire Electricity’s examinations are closed through 2001. In addition, open tax years related to a number of state and other foreign jurisdictions remain subject to examination. Although the ultimate resolution of our federal, state and foreign tax examinations is uncertain, we believe we have made adequate provisions for these tax positions and the aggregate amount of any additional tax liabilities that may result from these examinations, if any, is not expected to have a material adverse affect on our financial results.

Both PacifiCorp and MidAmerican Energy are required to pass income tax benefits related to certain accelerated tax depreciation and other property-related basis differences on to their customers in most state jurisdictions. These amounts were recognized as a net regulatory asset totaling $606 million as of December 31, 2007, and will be included in rates when the temporary differences reverse. Management believes the existing regulatory assets are probable of recovery. If it becomes no longer probable that these costs will be recovered, the assets would be written-off and recognized in earnings.

We have not provided U.S. deferred income taxes on our currency translation adjustment or the cumulative earnings of international subsidiaries that have been determined by management to be reinvested indefinitely. The cumulative earnings related to ongoing operations were approximately $1.5 billion as of December 31, 2007. Because of the availability of U.S. foreign tax credits, it is not

practicable to determine the U.S. federal income tax liability that would be payable if such earnings were not reinvested indefinitely. Deferred taxes are provided for earnings of international subsidiaries when we plan to remit those earnings. We periodically evaluate our cash requirements in the U.S. and abroad and evaluate our short-term and long-term operational and fiscal objectives in determining whether the earnings of our foreign subsidiaries are indefinitely invested outside the U.S. or will be remitted to the U.S. within the foreseeable future.

Unbilled revenues were $480 million as of December 31, 2007. Historically, any differences between the actual and estimated amounts have been immaterial. Revenue from energy business customers is recognized as electricity or gas is delivered or services are provided. The determination of sales to individual customers is based on the reading of meters, fixed reservation charges based on contractual quantities and rates or, in the case of the U.K. distribution businesses, when information is received from the national settlement system. The monthly unbilled revenue is determined by the estimation of unbilled energy provided during the period. Factors that can impact the estimate of unbilled energy provided include, but are not limited to, seasonal weather patterns, historical trends, volumes, line losses, economic impacts and composition of customer class. Estimates are generally reversed in the following month and actual revenue is recorded based on subsequent meter readings.

Our Consolidated Balance Sheets include assets and liabilities whose fair values are subject to market risks. Our significant market risks are primarily associated with commodity prices, foreign currency exchange rates and interest rates. The following sections address the significant market risks associated with our business activities. We also have established guidelines for credit risk management. Refer to Note 6 of our Notes to unaudited interim Consolidated Financial Statements and Notes 2 and 14 of our Notes to audited Consolidated Financial Statements included in the ‘‘Financial Statements’’ section of this prospectus for additional information regarding our accounting for derivative contracts. Our exposure to market risk has not changed materially since December 31, 2007.

We are subject to significant commodity risk, particularly through our ownership of PacifiCorp and MidAmerican Energy. Exposures include variations in the price of wholesale electricity that is purchased and sold, fuel costs to generate electricity, and natural gas supply for regulated retail gas customers. Electricity and natural gas prices are subject to wide price swings as demand responds to, among many other items, changing weather, limited storage, transmission and transportation constraints, and lack of alternative supplies from other areas. To mitigate a portion of the risk, our subsidiaries use derivative instruments, including forwards, futures, options, swaps and other over-the-counter agreements, to effectively secure future supply or sell future production at fixed prices. The settled cost of these contracts is generally recovered from customers in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives, that are probable of recovery in rates, are recorded as regulatory assets or liabilities. Financial results may be negatively impacted if the costs of wholesale electricity, fuel or natural gas are higher than what is permitted to be recovered in rates.

MidAmerican Energy also uses futures, options and swap agreements to economically hedge gas and electric commodity prices for physical delivery to non-regulated customers. We do not engage in a material amount of proprietary trading activities.

The table that follows summarizes our commodity risk on energy derivative contracts as of December 31, 2007 and shows the effects of a hypothetical 10% increase and a 10% decrease in forward market prices by the expected volumes for these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (dollars in millions):

Our business operations and investments outside the U.S. increase our risk related to fluctuations in foreign currency rates primarily in relation to the British pound. Our principal reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from our foreign operations changes with the fluctuations of the currency in which they transact.

CE Electric UK’s functional currency is the British pound. At December 31, 2007, a 10% devaluation in the British pound to the U.S. dollar would result in our Consolidated Balance Sheet being negatively impacted by a $212 million cumulative translation adjustment in accumulated other comprehensive income. A 10% devaluation in the average currency exchange rate would have resulted in lower reported earnings for CE Electric UK of $30 million in 2007.

As of December 31, 2007, we had fixed-rate long-term debt totaling $18.96 billion with a total fair value of $19.80 billion. Because of their fixed interest rates, these instruments do not expose us to the risk of earnings loss due to changes in market interest rates. However, the fair value of these instruments would decrease by approximately $917 million if interest rates were to increase by 10% from their levels as of December 31, 2007. Comparatively, as of December 31, 2006, we had fixed-rate long-term debt totaling $16.72 billion with a total fair value of $17.57 billion. The fair value of these instruments would have decreased by approximately $733 million if interest rates had increased by 10% from their levels as of December 31, 2006. In general, such a decrease in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of these instruments prior to their maturity.

As of December 31, 2007 and 2006, we had floating-rate obligations totaling $729 million and $727 million, respectively, which exposed us to the risk of increased interest expense in the event of increases in short-term interest rates. This market risk is not hedged; however, if floating interest rates were to increase by 10% from December 31 levels, it would not have a material effect on our consolidated annual interest expense in either year.

PacifiCorp and MidAmerican Energy extend unsecured credit to other utilities, energy marketers, financial institutions and certain commercial and industrial end-users in conjunction with wholesale energy marketing activities. Credit risk relates to the risk of loss that might occur as a result of non-performance by counterparties of their contractual obligations to make or take delivery of electricity, natural gas or other commodities and to make financial settlements of these obligations. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances involving other market participants that have a direct or indirect relationship with such counterparty.

PacifiCorp and MidAmerican Energy analyze the financial condition of each significant counterparty before entering into any transactions, establish limits on the amount of unsecured credit to be extended to each counterparty and evaluate the appropriateness of unsecured credit limits on a daily basis. To mitigate exposure to the financial risks of wholesale counterparties, PacifiCorp and MidAmerican Energy enter into netting and collateral arrangements that include margining and cross-product netting agreements and obtaining third-party guarantees, letters of credit and cash deposits. Counterparties may be assessed interest fees for delayed receipts. If required, PacifiCorp and MidAmerican Energy exercise rights under these arrangements, including calling on the counterparty’s credit support arrangement.

At December 31, 2007, 71% of PacifiCorp’s and 91% of MidAmerican Energy’s credit exposure, net of collateral, from wholesale operations was with counterparties having externally rated ‘‘investment grade’’ credit ratings, while an additional 9% of PacifiCorp’s and 8% of MidAmerican Energy’s credit exposure, net of collateral, from wholesale operations was with counterparties having financial characteristics deemed equivalent to ‘‘investment grade’’ by PacifiCorp and MidAmerican Energy based on internal review.

Northern Natural Gas’ primary customers include regulated local distribution companies in the upper Midwest. Kern River’s primary customers are major oil and gas companies or affiliates of such companies, electric generating companies, energy marketing and trading companies and natural gas distribution utilities which provide services in Utah, Nevada and California. As a general policy, collateral is not required for receivables from creditworthy customers. Customers’ financial condition and creditworthiness are regularly evaluated, and historical losses have been minimal. In order to

provide protection against credit risk, and as permitted by the separate terms of each of Northern Natural Gas’ and Kern River’s tariffs, the companies have required customers that lack creditworthiness, as defined by the tariffs, to provide cash deposits, letters of credit or other security until their creditworthiness improves.

Northern Electric and Yorkshire Electricity charge fees for the use of their electrical infrastructure levied on supply companies. The supply companies, which purchase electricity from generators and traders and sell the electricity to end-use customers, use Northern Electric’s and Yorkshire Electricity’s distribution networks pursuant to the multilateral ‘‘Distribution Connection and Use of System Agreement.’’ Northern Electric’s and Yorkshire Electricity’s customers are concentrated in a small number of electricity supply businesses with RWE Npower PLC accounting for approximately 40% of distribution revenues in 2007. Ofgem has determined a framework which sets credit limits for each supply business based on its credit rating or payment history and requires them to provide credit cover if their value at risk (measured as being equivalent to 45 days usage) exceeds the credit limit. Acceptable credit typically is provided in the form of a parent company guarantee, letter of credit or an escrow account. Ofgem has indicated that, provided Northern Electric and Yorkshire Electricity have implemented credit control, billing and collection in line with best practice guidelines and can demonstrate compliance with the guidelines or are able to satisfactorily explain departure from the guidelines, any bad debt losses arising from supplier default will be recovered through an increase in future allowed income. Losses incurred to date have not been material.

The Philippine National Irrigation Administration’s, or NIA, obligations under the Casecnan project agreement is CE Casecnan’s sole source of operating revenue. Because of the dependence on a single customer, any material failure of the customer to fulfill its obligations under the project agreement and any material failure of the ROP to fulfill its obligation under the performance undertaking would significantly impair the ability to meet existing and future obligations, including obligations pertaining to the outstanding project debt. Total operating revenue for the Casecnan project was $125 million for the year ended December 31, 2007. The Casecnan project agreement expires in December 2021.

We are a holding company which owns subsidiaries that are principally engaged in energy businesses. We are a consolidated subsidiary of Berkshire Hathaway. The balance of our common stock is owned by a private investor group comprised of Mr. Walter Scott, Jr. (along with family members and related entities), who is a member of our Board of Directors, Mr. David L. Sokol, our Chairman, and Mr. Gregory E. Abel, our President and Chief Executive Officer. As of March 31, 2008, Berkshire Hathaway, Mr. Scott (along with family members and related entities), Mr. Sokol and Mr. Abel owned 88.2%, 11.0%, —% and 0.8%, respectively, of our voting common stock and held diluted ownership interests of 87.4%, 10.9%, 0.7% and 1.0%, respectively.

On March 1, 2006, we and Berkshire Hathaway entered into the Berkshire Equity Commitment pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of our common equity upon any requests authorized from time to time by our Board of Directors. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due MEHC’s debt obligations and (b) funding the general corporate purposes and capital requirements of our regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request in minimum increments of at least $250 million pursuant to one or more drawings authorized by our Board of Directors. The funding of each drawing will be made by means of a cash equity contribution to us in exchange for additional shares of our common stock. The Berkshire Equity Commitment will expire on February 28, 2011.

Our operations are organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding (which primarily includes MidAmerican Energy), Northern Natural Gas, Kern River, CE Electric UK (which primarily consists of Northern Electric and Yorkshire Electricity), CalEnergy Generation-Foreign (which owns a majority interest in the Casecnan project in the Philippines), CalEnergy Generation-Domestic (which owns interests in independent power projects in the U.S.), and HomeServices. Refer to Note 12 of our Notes to unaudited interim Consolidated Financial Statements and Note 23 of our Notes to audited Consolidated Financial Statements included in the ‘‘Financial Statements’’ section of this prospectus for additional segment information regarding our platforms. Through these platforms, we own and operate an electric utility company in the Western U.S., a combined electric and natural gas utility company in the Midwestern U.S., two interstate natural gas pipeline companies in the U.S., two electricity distribution companies in Great Britain, a diversified portfolio of independent power projects and the second-largest residential real estate brokerage firm in the U.S.

Our energy subsidiaries generate, transmit, store, distribute and supply energy. Approximately 91% of our operating income in 2007 was generated from rate-regulated businesses. As of March 31, 2008, our electric and natural gas utility subsidiaries served approximately 6.2 million electricity customers and end users and approximately 0.7 million natural gas customers. Our natural gas pipeline subsidiaries operate interstate natural gas transmission systems that transported approximately 8% of the total natural gas consumed in the United States in 2007. These pipeline subsidiaries have approximately 17,000 miles of pipeline in operation and a design capacity of 6.9 bcf of natural gas per day. As of March 31, 2008, we had interests in approximately 17,000 net owned MW of power generation facilities in operation and under construction, including approximately 16,000 net owned MW in facilities that are part of the regulated asset base of our electric utility businesses and approximately 1,000 net owned MW in non-utility power generation facilities. The majority of our non-utility power generation facilities have long-term contracts for the sale of energy and/or capacity from the facilities.

Our principal executive offices are located at 666 Grand Avenue, Suite 500, Des Moines, Iowa 50309-2580 and our telephone number is (515) 242-4300. We initially incorporated in 1971 under the laws of the state of Delaware and reincorporated in 1999 in Iowa, at which time we changed our name from CalEnergy Company, Inc. to MidAmerican Energy Holdings Company.

On March 21, 2006, a wholly owned subsidiary of ours acquired 100% of the common stock of PacifiCorp, a public utility company, from a wholly owned subsidiary of Scottish Power plc, or ScottishPower, for a cash purchase price of $5.12 billion, which includes direct transaction costs. The results of PacifiCorp’s operations are included in our results beginning March 21, 2006. In connection with the 2006 acquisition of PacifiCorp, PacifiCorp and we agreed to certain regulatory commitments as discussed in the ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ section in this prospectus.

PacifiCorp serves approximately 1.7 million regulated retail electric customers in its service territories in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. The combined service territory’s diverse regional economy ranges from rural, agricultural and mining areas to urban, manufacturing and government service centers. No single segment of the economy dominates the service territory, which helps mitigate PacifiCorp’s exposure to economic fluctuations. In the eastern portion of the service territory, mainly consisting of Utah, Wyoming and southeast Idaho, the principal industries are manufacturing, health services, recreation, agriculture and mining or extraction of natural resources. In the western portion of the service territory, mainly consisting of Oregon, southeastern Washington and northern California, the principal industries are agriculture and manufacturing, with forest products, food processing, technology and primary metals being the largest industrial sectors. In addition to retail sales, PacifiCorp sells electric energy to other utilities, municipalities and marketers. These sales are referred to as wholesale sales.

PacifiCorp’s regulated electric operations are conducted under franchise agreements, certificates, permits and licenses obtained from state and local authorities. The average term of these franchise agreements is approximately 30 years, although their terms range from five years to indefinite.

On May 10, 2006, the PacifiCorp Board of Directors elected to change PacifiCorp’s fiscal year-end from March 31 to December 31. Therefore, in the following pages, the nine-month period ended December 31, 2006 information covers the transition period beginning April 1, 2006 and ending December 31, 2006.

The percentages of electricity sold (measured in MWh) to retail and wholesale customers, by class of customer, and the average number of retail customers (in millions) were as follows:

The percentages of retail electric operating revenue, by jurisdiction, were as follows:

Customer demand is typically highest in the summer across PacifiCorp’s service territory when air-conditioning and irrigation systems are heavily used. Customer demand also peaks in the winter months in the western portion of PacifiCorp’s service territory primarily due to heating requirements and in the eastern portion due to other electricity demands.

For residential customers, within a given year, weather conditions are the dominant cause of usage variations from normal seasonal patterns. Strong Utah residential growth over the last several years and increasing installations of central air conditioning systems have contributed to increased summer peak load growth. During the year ended December 31, 2007, PacifiCorp’s peak load was 9,775 MW in the summer and 8,650 MW in the winter. During the year ended December 31, 2007, PacifiCorp’s average load was 7,185 MW for the summer and 7,028 MW for the winter.

The estimated percentages of PacifiCorp’s total energy requirements supplied by its generation facilities and through long- and short-term contracts or spot market purchases were as follows:

The percentage of PacifiCorp’s energy requirements generated by its facilities will vary from year to year and is determined by factors such as planned and unplanned outages, the availability and price of coal and natural gas, precipitation and snowpack levels, other weather-related impacts, environmental considerations and the market price of electricity. PacifiCorp manages certain risks relating to its natural gas supply requirements and its wholesale transactions by entering into various financial derivative instruments, including forward purchases and sales, swaps and options. Refer to the ‘‘Quantitative and Qualitative Disclosure About Market Risk’’ section in this prospectus for a discussion of commodity price risk and derivative instruments.

Mines owned or leased by PacifiCorp supplied 31% of PacifiCorp’s total coal requirements during the year ended December 31, 2007 and the nine-month period ended December 31, 2006, compared to 32% during the year ended March 31, 2006. The remaining coal requirements are acquired through long- and short-term third party contracts. PacifiCorp’s mines are located adjacent to many of its

coal-fired generating facilities, which significantly reduces overall transportation costs included in fuel expense. In an effort to lower costs and obtain better quality coal, the Jim Bridger mine developed an underground mine to access 57 million tons of PacifiCorp’s coal reserves. Sustained operations at the underground mine commenced in March 2007 and production continues at its surface operations. The life of the underground mine is expected to be approximately 15 years.

Recoverable coal reserves as of March 31, 2008, based on PacifiCorp’s most recent engineering studies, were as follows (in millions):

Coal reserve estimates are subject to adjustment as a result of the development of additional engineering and geological data, new mining technology and changes in regulation and economic factors affecting the utilization of such reserves. PacifiCorp believes that the coal reserves available to the Craig, Huntington, Hunter and Jim Bridger plants, together with coal available under both long- and short-term contracts with external suppliers to supply its remaining plants, will be substantially sufficient to provide these plants with fuel for their currently expected useful lives. To meet applicable standards, PacifiCorp blends coal mined from its owned mines with contracted coal, and utilizes electricity plant technologies for controlling sulfur dioxide and other emissions.

Recoverability by surface mining methods typically ranges from 90% to 95%. Recoverability by underground mining techniques ranges from 50% to 70%. Most of PacifiCorp’s coal reserves are held pursuant to leases from the federal government through the Bureau of Land Management and from certain states and private parties. The leases generally have multi-year terms that may be renewed or extended only with the consent of the lessor and require payment of rents and royalties.

PacifiCorp uses natural gas as fuel for its combined− and simple-cycle natural gas-fired plants. Oil and natural gas are also used for igniter fuel and to fuel generation for transmission support and standby purposes. These sources are presently in adequate supply and available to meet PacifiCorp’s needs.

PacifiCorp operates the majority of its hydroelectric generating portfolio under long-term licenses from the FERC with terms of 30 to 50 years. Several of PacifiCorp’s long-term operating licenses have expired and they are operating under temporary annual licenses issued by the FERC until new long-term operating licenses are issued. The amount of electricity PacifiCorp is able to generate from its hydroelectric plants depends on a number of factors, including snowpack in the mountains upstream of its hydroelectric plants, reservoir storage, precipitation in its watersheds, plant availability and restrictions imposed by oversight bodies due to competing water management objectives. When these factors are favorable, PacifiCorp can generate more electricity using its hydroelectric plants. When these factors are unfavorable, PacifiCorp must increase its reliance on more expensive thermal plants and purchased electricity.

PacifiCorp is pursuing renewable resources as a viable, economic and environmentally prudent means of generating electricity. The benefits of energy from renewable resources include low to no emissions and typically little or no fossil fuel requirements. The intermittent nature of some renewable resources, such as wind, is complemented by PacifiCorp’s other generating resources, which are important to integrating intermittent wind resources into the electric system.

In addition to its portfolio of generating plants, PacifiCorp purchases electricity in the wholesale markets to meet its retail load and long-term wholesale obligations, for system balancing requirements and to enhance the efficient use of its generating capacity over the long-term. PacifiCorp enters into wholesale purchase and sale transactions to balance its electricity supply when generation and retail loads are higher or lower than expected. Generation can vary with the levels of outages, hydroelectric and wind conditions, operational factors and transmission constraints. Retail load can vary with the weather, distribution system outages, consumer trends and the level of economic activity. In addition, PacifiCorp purchases electricity in the wholesale markets when it is more economical than generating it at its own plants. PacifiCorp may also sell into the wholesale market excess electricity arising from imbalances between generation and retail load obligations, subject to pricing and transmission constraints. Many of PacifiCorp’s purchased electricity contracts have fixed-price components, which provide some protection against price volatility.

PacifiCorp’s wholesale transactions are integral to its retail business, providing for a balanced and economically hedged position and enhancing the efficient use of its generating capacity over the long term. Historically, PacifiCorp has been able to purchase electricity from utilities in the Western United States for its own requirements. Delivery of these purchases is conducted through PacifiCorp and third-party transmission systems, which connect with market hubs in the Pacific Northwest to provide access to normally low-cost hydroelectric generation, and in the Southwestern United States to provide access to normally higher-cost fossil-fuel generation. The transmission system is available for common use consistent with open-access regulatory requirements.

The following table sets out certain information concerning PacifiCorp’s power generating facilities as of March 31, 2008:


	Location	Energy Source	Installed	Facility Net Capacity (MW)⁽¹⁾		Net MW Owned⁽¹⁾
COAL:
Jim Bridger	Rock Springs, WY	Coal	1974-1979		2,120		1,414
Huntington	Huntington, UT	Coal	1974-1977		895		895
Dave Johnston	Glenrock, WY	Coal	1959-1972		762		762
Naughton	Kemmerer, WY	Coal	1963-1971		700		700
Hunter No. 1	Castle Dale, UT	Coal	1978		430		403
Hunter No. 2	Castle Dale, UT	Coal	1980		430		259
Hunter No. 3	Castle Dale, UT	Coal	1983		460		460
Cholla No. 4	Joseph City, AZ	Coal	1981		380		380
Wyodak	Gillette, WY	Coal	1978		335		268
Carbon	Castle Gate, UT	Coal	1954-1957		172		172
Craig Nos. 1 and 2	Craig, CO	Coal	1979-1980		856		165
Colstrip Nos. 3 and 4	Colstrip, MT	Coal	1984-1986		1,480		148
Hayden No. 1	Hayden, CO	Coal	1965-1976		184		45
Hayden No. 2	Hayden, CO	Coal	1965-1976		262		33
					9,466		6,104
NATURAL GAS:
Lake Side	Vineyard, UT	Natural gas/Steam	2007		548		548
Currant Creek	Mona, UT	Natural gas/Steam	2005-2006		540		540
Hermiston	Hermiston, OR	Natural gas/Steam	1996		474		237
Gadsby Steam	Salt Lake City, UT	Natural gas	1951-1952		235		235
Gadsby Peakers	Salt Lake City, UT	Natural gas	2002		120		120
Little Mountain	Ogden, UT	Natural gas	1972		14		14
					1,931		1,694
HYDROELECTRIC:
Swift No. 1	Cougar, WA	Lewis River	1958		264		264
Merwin	Ariel, WA	Lewis River	1931-1958		151		151
Yale	Amboy, WA	Lewis River	1953		163		163
Five North Umpqua Plants	Toketee Falls, OR	N. Umpqua River	1950-1956		141		141
John C. Boyle	Keno, OR	Klamath River	1958		83		83
Copco Nos. 1 and 2	Hornbrook, CA	Klamath River	1918-1925		62		62
Clearwater Nos. 1 and 2	Toketee Falls, OR	Clearwater River	1953		49		49
Grace	Grace, ID	Bear River	1908-1923		33		33
Prospect No. 2	Prospect OR	Rogue River	1928		36		36
Cutler	Collingston, UT	Bear River	1927		29		29
Oneida	Preston, ID	Bear River	1915-1920		28		28
Iron Gate	Hornbrook, CA	Klamath River	1962		19		19
Soda	Soda Springs, ID	Bear River	1924		14		14
28 minor hydroelectric plants	Various	Various	1895-1990		86		86
					1,158		1,158
WIND:
Foote Creek	Arlington, WY	Wind	1997		41		33
Leaning Juniper 1	Arlington, OR	Wind	2006		101		101
Marengo	Dayton, WA	Wind	2007		140		140
					282		274
OTHER:
Camas Co-Gen	Camas, WA	Black liquor	1996		22		22
Blundell	Milford, UT	Geothermal	1984,2007		34		34
					56		56
Total Available Generating Capacity					12,893		9,286
PROJECTS UNDER CONSTRUCTION/DEVELOPMENT⁽²⁾:
Various wind projects	Various	Wind	2008-2009		618		618
					13,511		9,904

In April 2008, PacifiCorp entered into a purchase agreement to acquire 100% of the equity interests of an entity owning a 520-MW natural gas-fired facility located in Chehalis, Washington. The acquisition is subject to regulatory approval by the FERC, the Department of Justice/Federal Trade Commission pursuant to the Hart-Scott-Rodino Act, the Federal Communications Commission, the UPSC and the Washington Energy Facilities Siting Council. In April 2008, PacifiCorp filed requests with the UPSC and the OPUC seeking a waiver of state-mandated request for proposal procurement processes to purchase a generating facility. Also in April 2008, PacifiCorp filed with the FERC its application under Section 203 of the Federal Power Act.

PacifiCorp has provided a comprehensive set of demand-side management programs to its customers since the 1970s. The programs are designed to reduce growth in peak load and energy consumption. Current programs offer customers services such as energy engineering and audits, as well as rebates for high efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors and process equipment and systems; new construction; and load management (curtailment) programs for large commercial and industrial customers and residential customers whose central air conditioners are controlled during summer peak load periods. Subject to random prudence reviews, state regulations allow for contemporaneous recovery of costs incurred for demand-side management programs and services through the energy efficiency service charges to all retail electric customers. In 2007, $53 million was expended on the demand-side management programs in PacifiCorp’s six-state service area, resulting in an estimated 300,000 MWh of first year energy savings and 170 MW of peak load management.

PacifiCorp operates one balancing authority area in the western portion of its service territory, and one balancing authority area in the eastern portion of its service territory. A balancing authority area is a geographic area with electric systems that control generation to maintain schedules with other balancing authority areas and ensure reliable operations. In operating the balancing authority areas, PacifiCorp is responsible for continuously balancing electric supply and demand by dispatching generating resources and interchange transactions so that generation internal to the balancing authority area, plus net imported power, matches customer loads. PacifiCorp also schedules deliveries over its transmission system in accordance with FERC requirements.

PacifiCorp’s transmission system is part of the Western Interconnection, the regional grid in the West. The Western Interconnection includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico that make up the Western Electric Coordinating Council, or the WECC. PacifiCorp’s transmission system, together with contractual rights on other transmission systems, enables PacifiCorp to integrate and access generation resources to meet its customer load requirements.

PacifiCorp’s wholesale transmission services are regulated by the FERC under cost-based regulation subject to PacifiCorp’s OATT. In accordance with the OATT, PacifiCorp offers several transmission services to wholesale customers:

These services are offered on a non-discriminatory basis, which means that all potential customers are provided an equal opportunity to access the transmission system. PacifiCorp’s transmission business is managed and operated independently from the generating and marketing business in accordance with the FERC Standards of Conduct. Transmission costs are not separated from, but rather are ‘‘bundled’’ with, generation and distribution costs in retail rates approved by state regulatory commissions.

The electric transmission system of PacifiCorp as of March 31, 2008 included approximately 15,700 miles of transmission lines. As of March 31, 2008, PacifiCorp owned approximately 900 substations.

In May 2007, PacifiCorp announced plans to build in excess of 1,200 miles of new high-voltage transmission lines primarily in Wyoming, Utah, Idaho, Oregon and the desert Southwest. The estimated $4.1 billion investment plan includes projects that will address customers’ increasing electric energy use, improve system reliability and deliver wind and other renewable generation resources to more customers throughout PacifiCorp’s six-state service area and the Western United States. These transmission lines are expected to be placed into service beginning in 2010 and continuing through 2014. PacifiCorp is also collaborating with other utilities to address transmission needs, including new development and system reliability.

MidAmerican Energy, an indirect wholly owned subsidiary of ours, is a public utility company headquartered in Iowa, which serves approximately 0.7 million regulated retail electric customers and approximately 0.7 million regulated retail and transportation natural gas customers. MidAmerican Energy is principally engaged in the business of generating, transmitting, distributing and selling electricity and in distributing, selling and transporting natural gas. MidAmerican Energy distributes electricity at retail in Council Bluffs, Des Moines, Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities (Davenport and Bettendorf, Iowa and Rock Island, Moline and East Moline, Illinois); and a number of adjacent communities and areas. It also distributes natural gas at retail in Cedar Rapids, Des Moines, Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities; Sioux Falls, South Dakota; and a number of adjacent communities and areas. Additionally, MidAmerican Energy transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. In addition to retail sales and natural gas transportation, MidAmerican Energy sells electric energy and natural gas to other utilities, municipalities and marketers. These sales are referred to as wholesale sales.

MidAmerican Energy’s regulated electric and gas operations are conducted under numerous franchise agreements, certificates, permits and licenses obtained from state and local authorities. The franchise agreements, with various expiration dates, are typically for 25-year terms.

MidAmerican Energy has a diverse customer base consisting of residential, agricultural, and a variety of commercial and industrial customer groups. Some of the larger industrial groups served by MidAmerican Energy include the processing and sales of food products; the manufacturing, processing and fabrication of primary metals; farm and other non-electrical machinery; real estate; and cement and gypsum products.

MidAmerican Energy also conducts a number of nonregulated business activities in addition to its traditional regulated electric and natural gas services, including nonregulated electric and natural gas sales and gas income-sharing arrangements. MidAmerican Energy’s nonregulated retail electric marketing services provide electric supply services to retail customers predominantly in Illinois, but also in Michigan and Maryland. During 2007, MidAmerican Energy’s nonregulated retail electric marketing services expanded significantly in Illinois as a result of that market becoming fully open to competition. Effective January 1, 2007, the major electric distribution companies in Illinois increased their purchases of energy on the open market due to the expiration of contracts associated with electric industry restructuring in Illinois. MidAmerican Energy’s nonregulated gas marketing services operate in Iowa, Illinois, Michigan, South Dakota and Nebraska. MidAmerican Energy purchases gas from producers and third party marketers and sells it directly to commercial and industrial end-users. In addition, MidAmerican Energy manages gas supplies for a number of smaller commercial end-users, which includes the sale of gas to these customers to meet their supply requirements.

MidAmerican Energy’s operating revenues were derived from the following business activities during the years ended December 31:

The percentages of electricity sold (measured in MWh) to retail and wholesale customers, by class of customer, and the average number of retail customers (in millions) as of and for the years ended December 31 were as follows:

The percentages of electricity sold (measured in MWh), by jurisdiction, for the years ended December 31 were as follows:

There are seasonal variations in MidAmerican Energy’s electric business that are principally related to the use of electricity for air conditioning. In general, 35-40% of MidAmerican Energy’s regulated electric revenues are reported in the months of June, July, August and September.

The annual hourly peak demand on MidAmerican Energy’s electric system usually occurs as a result of air conditioning use during the cooling season. On August 13, 2007, retail customer usage of electricity caused a new record hourly peak demand of 4,240 MW on MidAmerican Energy’s electric system, an increase of 104 MW from the previous record set in 2006.

The estimated percentages of MidAmerican Energy’s total energy requirements supplied by its generation plants and through long- and short-term contracts or spot market purchases for the years ended December 31 were as follows:

The share of MidAmerican Energy’s energy requirements generated by its plants will vary from year to year and is determined by factors such as planned and unplanned outages, the availability and price of fuels, weather, environmental considerations and the market price of electricity.

MidAmerican Energy is exposed to fluctuations in energy costs relating to retail sales in Iowa and, effective January 1, 2007, in Illinois as it does not have fuel adjustment clauses in those jurisdictions. In Illinois, base rates were adjusted to include recoveries at average 2004/2005 energy cost levels beginning January 1, 2007, and rate case approval is required for any base rate changes. MidAmerican Energy may not petition for reinstatement of the Illinois fuel adjustment clause until November 2011.

All of the coal-fired generating stations operated by MidAmerican Energy are fueled by low-sulfur, western coal from the Powder River Basin in northeast Wyoming and southeast Montana. MidAmerican Energy’s coal supply portfolio includes multiple suppliers and mines under short-term and multi-year agreements of varying terms and quantities. MidAmerican Energy’s coal supply portfolio has a substantial majority of its expected 2008 requirements under fixed-price contracts. MidAmerican Energy regularly monitors the western coal market looking for opportunities to enhance its coal supply portfolio.

MidAmerican Energy has a long-term coal transportation agreement with Union Pacific Railroad Company, or Union Pacific. Under this agreement, Union Pacific delivers coal directly to MidAmerican Energy’s George Neal and Walter Scott, Jr. Energy Centers and to an interchange point with the Iowa, Chicago & Eastern Railroad Corporation for short-haul delivery to the Louisa and Riverside Energy Centers. MidAmerican Energy has the ability to use BNSF Railway Company for delivery of a small amount of coal to the Walter Scott, Jr., Louisa and Riverside Energy Centers should the need arise.

MidAmerican Energy is a 25% joint owner of Quad Cities Station, a nuclear power plant. Exelon Generation Company, LLC, or Exelon Generation, the 75% joint owner and the operator of Quad Cities Station, is a subsidiary of Exelon Corporation. Approximately one-third of the nuclear fuel assemblies in each reactor core at the Quad Cities Station is replaced every 24 months. MidAmerican Energy has been advised by Exelon Generation that the following requirements for the Quad Cities Station can be met under existing supplies or commitments: uranium requirements through 2010 and partial requirements through 2015; uranium conversion requirements through 2010 and partial requirements through 2011; enrichment requirements through 2010 and partial requirements through 2017; and fuel fabrication requirements through 2015. MidAmerican Energy has been advised by Exelon Generation that it does not anticipate that it will have difficulty in contracting for uranium, uranium conversion, enrichment or fabrication of nuclear fuel needed to operate Quad Cities Station during this time.

MidAmerican Energy uses natural gas and oil as fuel for intermediate and peak demand electric generation, igniter fuel, transmission support and standby purposes. These sources are presently in

adequate supply and available to meet MidAmerican Energy’s needs. MidAmerican Energy manages a portion of its natural gas supply requirements by entering into various financial derivative instruments, including forward purchases and sales, futures, swaps and options. Refer to the ‘‘Quantitative and Qualitative Disclosure About Market Risk’’ section in this prospectus for a discussion of commodity price risk and derivative instruments.

MidAmerican Energy is pursuing renewable resources as a viable, economic and environmentally prudent means of generating electricity. The benefits of energy from renewable resources include low to no emissions and typically little or no fossil fuel requirements. The intermittent nature of some renewable resources, such as wind, is complemented by MidAmerican Energy’s other generating resources, which are important to integrating intermittent wind resources into the electric system.

The following table sets out certain information concerning MidAmerican Energy’s power generating facilities as of March 31, 2008:


	Location	Energy Source	Installed	Facility Net Capacity (MW)⁽¹⁾		Net MW Owned⁽¹⁾
COAL:
George Neal Unit No. 1	Sergeant Bluff, IA	Coal	1964		135		135
George Neal Unit No. 2	Sergeant Bluff, IA	Coal	1972		289		289
George Neal Unit No. 3	Sergeant Bluff, IA	Coal	1975		515		371
George Neal Unit No. 4	Salix, IA	Coal	1979		644		261
Louisa	Muscatine, IA	Coal	1983		700		616
Ottumwa	Ottumwa, IA	Coal	1981		672		349
Riverside Unit No. 3	Bettendorf, IA	Coal	1925		5		5
Riverside Unit No. 5	Bettendorf, IA	Coal	1961		130		130
Walter Scott, Jr. Unit No. 1	Council Bluffs, IA	Coal	1954		45		45
Walter Scott, Jr. Unit No. 2	Council Bluffs, IA	Coal	1958		88		88
Walter Scott, Jr. Unit No. 3	Council Bluffs, IA	Coal	1978		690		546
Walter Scott, Jr. Unit No. 4	Council Bluffs, IA	Coal	2007		790		471
					4,703		3,306
NATURAL GAS:
Greater Des Moines	Pleasant Hill, IA	Natural gas	2003-2004		497		497
Coralville	Coralville, IA	Natural gas	1970		64		64
Electrifarm	Waterloo, IA	Natural gas/Oil	1975-1978		199		199
Moline	Moline, IL	Natural gas	1970		64		64
Parr	Charles City, IA	Natural gas	1969		32		32
Pleasant Hill	Pleasant Hill, IA	Natural gas/Oil	1990-1994		161		161
River Hills	Des Moines, IA	Natural gas	1966-1967		117		117
Sycamore	Johnston, IA	Natural gas/Oil	1974		149		149
28 portable power modules	Various	Oil	2000		56		56
					1,339		1,339
NUCLEAR:
Quad Cities Unit No. 1	Cordova, IL	Uranium	1972		872		218
Quad Cities Unit No. 2	Cordova, IL	Uranium	1972		868		217
					1,740		435
WIND:
Century	Blairsburg, IA	Wind	2005-2008		200		200
Intrepid	Schaller, IA	Wind	2004-2005		176		176
Pomeroy	Pomeroy, IA	Wind	2007-2008		198		198
Victory	Westside, IA	Wind	2006		99		99
Charles City	Charles City, IA	Wind	2008		69		69
					742		742
OTHER:
Moline Unit Nos. 1-4	Moline, IL	Mississippi River	1941		3		3
Total Available Generating Capacity					8,527		5,825
PROJECTS UNDER CONSTRUCTION/DEVELOPMENT⁽²⁾:
Various wind projects	Various	Wind	2008		489		489
					9,016		6,314

On July 27, 2007, the Iowa Utilities Board, or IUB, approved a settlement agreement between MidAmerican Energy and the Iowa Office of Consumer Advocate, or OCA, in conjunction with MidAmerican Energy’s ratemaking principles application for up to 540 MW (nameplate ratings) of additional wind-powered generation capacity in Iowa to be placed in service on or before December 31, 2013. All new wind-powered generation capacity up to the 540 MW will be subject to the 2007 settlement agreement, including 78 MW (nameplate ratings) placed in service in the fourth quarter of 2007 and 81 MW (nameplate ratings) placed in service in the first quarter of 2008. As of March 31, 2008, MidAmerican Energy had 489 MW (nameplate ratings) of wind-powered generation capacity in Iowa under development or construction that it expects will be placed in service by December 31, 2008, including 108 MW (nameplate ratings) not covered by the 2007 settlement agreement. The 108 MW expansion is the subject of a settlement agreement between MidAmerican Energy and the OCA, which must be approved by the IUB prior to becoming effective. Generally speaking, accredited capacity ratings for wind-powered generation facilities are considerably less than the nameplate ratings due to the varying nature of wind. MidAmerican Energy continues to pursue additional cost effective wind-powered generation capacity. Refer to Note 6 of our Notes to audited Consolidated Financial Statements included in the ‘‘Financial Statements’’ section of this prospectus for a discussion of the settlement agreement.

MidAmerican Energy has provided a comprehensive set of demand-side management programs to its Iowa electric and gas customers since 1990. The programs are designed to reduce growth in peak load and energy consumption. Current Iowa programs offer customers incentives for energy audits and weatherization; rebates or below market financing for high efficiency equipment such as lighting, heating and cooling equipment, insulation, motors and process equipment and systems; new construction; and load management (curtailment) programs for large commercial and industrial customers and residential customers whose central air conditioners are controlled during summer peak load periods. Subject to random prudence reviews, Iowa regulation allows for contemporaneous recovery of costs incurred for the demand-side management plan through an energy charge to all retail electric and gas customers. In 2007, $51 million was expended on the demand-side management programs in Iowa resulting in an estimated 268 MW and 5,464 Dth/day of electric and gas peak demand reduction, respectively. MidAmerican Energy plans to offer similar or comparable programs to Illinois customers in 2008.

MidAmerican Energy is interconnected with utilities in Iowa and neighboring states. MidAmerican Energy is also a party to an electric generation reserve sharing pool and regional transmission group administered by MAPP. MAPP is a voluntary association of electric utilities doing business in Minnesota, Nebraska, North Dakota and the Canadian provinces of Saskatchewan and Manitoba and portions of Iowa, Montana, South Dakota and Wisconsin. Its membership also includes power marketers, regulatory agencies and independent power producers. MAPP performs functions including administration of its short-term regional OATT, coordination of regional planning and operations, and operation of the generation reserve sharing pool.

MidAmerican Energy can transact with a substantial number of parties through its participation in MAPP and through its direct interconnections to the Midwest Independent Transmission System Operator, Inc., Southwest Power Pool, Inc. and PJM Interconnection, L.L.C. regional transmission organizations, or RTOs, and several other major transmission-owning utilities in the region. Under

normal operating conditions, MidAmerican Energy’s transmission system has adequate capacity to deliver energy to MidAmerican Energy’s distribution system and to export and import energy with other interconnected systems. The electric transmission system of MidAmerican Energy as of March 31, 2008 included approximately 2,200 miles of transmission lines. MidAmerican Energy’s electric distribution system included approximately 400 substations as of March 31, 2008.

MidAmerican Energy is engaged in the procurement, transportation, storage and distribution of natural gas for customers in the Midwest. MidAmerican Energy purchases natural gas from various suppliers, transports it from the production areas to MidAmerican Energy’s service territory under contracts with interstate pipelines, stores it in various storage facilities to manage fluctuations in system demand and seasonal pricing, and delivers it to customers through MidAmerican Energy’s distribution system. MidAmerican Energy sells natural gas and transportation services to end-use customers and natural gas to other utilities, municipalities and marketers. MidAmerican Energy also transports through its distribution system natural gas purchased independently by a number of end-use customers. During 2007, 46% of the total natural gas delivered through MidAmerican Energy’s system for end use customers was under natural gas transportation service.

The percentages of regulated natural gas Dth, excluding transportation throughput, by class of customer, for the years ended December 31 were as follows:

The percentages of regulated natural gas Dth, excluding transportation throughput, by jurisdiction, for the years ended December 31 were as follows:

MidAmerican Energy is allowed to recover its cost of natural gas from all of its regulated natural gas customers through purchased gas adjustment clauses. Accordingly, as long as MidAmerican Energy is prudent in its procurement practices, MidAmerican Energy’s regulated natural gas customers retain the risk associated with the market price of natural gas. MidAmerican Energy uses several strategies designed to reduce the market price risk for its natural gas customers, including the use of storage gas and peak-shaving facilities, sharing arrangements to share savings and costs with customers and short-term and long-term financial and physical gas purchase agreements.

MidAmerican Energy purchases natural gas supplies from producers and third-party marketers. To enhance system reliability, a geographically diverse supply portfolio with varying terms and contract conditions is utilized for the natural gas supplies. MidAmerican Energy has rights to firm pipeline capacity to transport natural gas to its service territory through direct interconnects to the pipeline systems of several interstate natural gas pipeline systems, including Northern Natural Gas (an affiliate company).

There are seasonal variations in MidAmerican Energy’s natural gas business that are principally due to the use of natural gas for heating. Typically, 45-55% of MidAmerican Energy’s regulated natural gas revenue is reported in the months of January, February, March and December.

MidAmerican Energy utilizes leased gas storage to meet peak day requirements and to manage the daily changes in demand due to changes in weather. The storage gas is typically replaced during off-peak months when the demand for natural gas is historically lower than during the heating season. In addition, MidAmerican Energy also utilizes three liquefied natural gas, or LNG, plants and two propane-air plants to meet peak day demands in the winter. The storage and peak shaving facilities reduce MidAmerican Energy’s dependence on natural gas purchases during the volatile winter heating season. MidAmerican Energy can deliver approximately 50% of its design day sales requirements from its storage and peak shaving supply sources.

On February 2, 1996, MidAmerican Energy had its highest peak-day delivery of 1,143,026 Dth. This peak-day delivery consisted of 88% traditional sales service and 12% transportation service of customer-owned gas. MidAmerican Energy’s 2007/2008 winter heating season peak-day delivery of 1,019,111 Dth was reached on January 29, 2008. This peak-day delivery included 73% traditional sales service and 27% transportation service.

Natural gas property consists primarily of natural gas mains and services pipelines, meters, and related distribution equipment, including feeder lines to communities served from natural gas pipelines owned by others. The gas distribution facilities of MidAmerican Energy as of March 31, 2008 included approximately 21,800 miles of gas mains and service pipelines. In addition, natural gas property includes three liquefied natural gas plants and two propane-air plants.

Northern Natural Gas, an indirect wholly owned subsidiary of ours, owns one of the largest interstate natural gas pipeline systems in the United States, which reaches from southern Texas to Michigan’s Upper Peninsula. Northern Natural Gas primarily transports and stores natural gas for utilities, municipalities, other pipeline companies, gas marketers, industrial and commercial users and other end users. Northern Natural Gas owns and operates approximately 15,700 miles of natural gas pipelines, consisting of approximately 6,700 miles of mainline transmission pipelines and approximately 9,000 miles of branch and lateral pipelines, with a Market Area design capacity of 5.1 Bcf per day, transporting approximately 4.9% of the total natural gas consumed in the U.S. in 2007. Based on a review of relevant industry data, the Northern Natural Gas system is believed to be the largest single pipeline in the U.S. as measured by pipeline miles and the seventh-largest as measured by throughput. Northern Natural Gas’ transportation and storage revenue accounted for 93% of its total operating revenue in 2007. Except for quantities of natural gas owned and managed for operational and system balancing purposes, Northern Natural Gas does not own the natural gas that is transported through its system. The sales of natural gas for operational and system balancing purposes account for the balance of its 2007 revenue. Northern Natural Gas’ transportation and storage operations are subject to a regulated tariff that is on file with the FERC. The tariff rates are designed to allow it to recover its costs and generate a regulated return on equity.

Northern Natural Gas’ pipeline system, which is interconnected with many interstate and intrastate pipelines in the national grid system, consists of two distinct but operationally integrated markets. Its traditional end-use and distribution market area is at the northern part of the system,

including points in Michigan, Illinois, Iowa, Minnesota, Nebraska, Wisconsin and South Dakota, which Northern Natural Gas refers to as the Market Area. Its natural gas supply and delivery service area is at the southern part of the system, including Kansas, Oklahoma, Texas and New Mexico, which Northern Natural Gas refers to as the Field Area.

Northern Natural Gas’ pipeline system provides its customers access to natural gas from key production areas, including the Hugoton, Permian, Anadarko and Rocky Mountain basins in its Field Area and, through interconnections with other pipelines, the Rocky Mountain and Canadian basins in its Market Area. In each of these areas, Northern Natural Gas has numerous interconnecting receipt and delivery points.

Northern Natural Gas transports natural gas primarily to end-user and local distribution markets in the Market Area. In 2007, 66% of Northern Natural Gas’ transportation and storage revenue was generated from Market Area customer transportation contracts. Its Market Area customers consist primarily of utilities and end-use customers. Northern Natural Gas directly serves 76 utilities, with eight large utilities, including MidAmerican Energy, accounting for over 54% of its transportation and storage revenue in 2007. In turn, these large utilities serve numerous residential, commercial and industrial customers. In 2007, 85% of Northern Natural Gas’ transportation and storage revenue for the Field and Market Areas was generated from reservation charges under firm transportation and storage contracts and 67% of that revenue was from utilities.

A majority of Northern Natural Gas’ capacity in the Market Area is committed to customers under firm transportation contracts. As of March 31, 2008, 92% of Northern Natural Gas’ customers’ entitlement in the Market Area is contracted beyond 2009, and 46% is contracted beyond 2015.

Northern Natural Gas’ Northern Lights expansion project is expected to add approximately 650,100 Dth per day capacity to its Market Area. This load is concentrated primarily in the Twin Cities area of Minnesota and is expected to serve incremental load due to residential growth, gas-fired power plants and ethanol facilities. The majority of service for the first phase began in November 2007 with entitlement consisting of approximately 422,900 Dth per day. Service for the second phase is expected to begin by November 2008 with entitlement consisting of approximately 91,200 Dth per day. Service for the next phase is expected to begin by November 2009 with entitlement consisting of approximately 136,000 Dth per day. All of the Northern Lights entitlement, except for 24,600 Dth per day in 2007 and 13,000 Dth per day in 2008, is associated with new service. All phases of Northern Lights are entirely supported by executed precedent agreements and contracts, the majority of which (91% by volume) have terms ranging from five to twenty years. In total, the Northern Lights expansion project is expected to require over $336 million in capital expenditures of which $173 million has been incurred through March 31, 2008.

In the Field Area, customers holding contracted firm transportation capacity, or entitlement, consist primarily of marketers, power generators and producers. The majority of Northern Natural Gas’ Field Area firm transportation was previously conducted under long-term firm transportation contracts, the majority of which expired on October 31, 2007, with such volumes supplemented by volumes transported on a short-term firm and interruptible basis. The majority of this entitlement was recontracted as of November 1, 2007, principally by marketers and producers, although the contracts are generally for less than one year. Northern Natural Gas expects short-term recontracting to continue in the foreseeable future, since Market Area customers presently need to purchase gas from the production basins connected to its Field Area in order to meet their growing demand requirements. Market Area demand cannot presently be met without the purchase of supplies from the Field Area. Supplies from the Field Area are generally less expensive than the supply alternatives available from other sources that interconnect with our system in the Market Area. In 2007, 21% of Northern Natural Gas’ transportation and storage revenue was generated from Field Area customer transportation contracts.

Northern Natural Gas’ storage services are provided through the operation of one underground natural gas storage field in Iowa, two underground natural gas storage facilities in Kansas and one LNG storage peaking unit each in Garner, Iowa and Wrenshall, Minnesota. The three underground natural gas storage facilities and two LNG storage peaking units have a total firm service cycle

capacity of approximately 65 Bcf and over 1.9 Bcf per day of FERC-certificated peak delivery capability. These storage facilities provide Northern Natural Gas with operational flexibility for the daily balancing of its system and provide services to customers to meet their winter peaking and year-round load swing requirements. In 2007, 13% of Northern Natural Gas’ transportation and storage revenue was generated from storage services.

In June 2006, Northern Natural Gas added 6 Bcf of firm storage cycle capacity through investments and modifications made at its Cunningham, Kansas and Redfield, Iowa storage facilities. This capacity was sold to one LDC for a term of 21 years at maximum tariff rates. Pursuant to binding requests for firm storage cycle capacity submitted by customers in an open season, Northern Natural Gas has been pursuing the development of additional storage capacity at the facility it owns at Redfield, Iowa. Northern Natural Gas has been granted authority by the FERC to charge market-based rates for this project. In March 2008, Northern Natural Gas received FERC authorization to increase the cycle capacity of the storage field by 8 Bcf. Contracts with 15 customers have been secured effective June 1, 2008 at an average cycle rate of $1.32/Dth and terms of 20 years. The project is expected to cost approximately $55 million.

Northern Natural Gas’ system experiences significant seasonal swings in demand, with the highest demand typically occurring during the months of November through March. These high winter demand requirements create significant price volatility that provides Northern Natural Gas with opportunities to deliver additional value-added services, such as firm and interruptible storage services, as well as no-notice services. Because of its location and multiple interconnections with interstate and intrastate pipelines, Northern Natural Gas is able to access natural gas from both traditional production areas, such as the Hugoton, Permian and Anadarko Basins, and growing supply areas, such as the Rocky Mountains, through Trailblazer Pipeline Company, Kinder Morgan Interstate Gas Transmission, Cheyenne Plains Pipeline, Colorado Interstate Gas Pipeline Company, or Colorado Interstate, and, beginning in 2008, Rockies Express Pipeline, as well as from Canadian production areas through Northern Border Pipeline Company, or Northern Border, Great Lakes Gas Transmission Limited Partnership, or Great Lakes, and Viking Gas Transmission Company, or Viking. This supply diversity provides significant flexibility to Northern Natural Gas’ system and customers. As a result of Northern Natural Gas’ geographic location in the middle of the United States and its many interconnections with other pipelines, Northern Natural Gas augments its steady end-user and local distribution companies, or LDCs, revenue by capitalizing on opportunities for shippers to reach additional markets, such as Chicago, Illinois, other parts of the Midwest, and Texas, through interconnections.

Kern River, an indirect wholly owned subsidiary of ours, owns an interstate natural gas transportation pipeline system consisting of approximately 1,700 miles of pipeline, with an approximate design capacity of 1,755,575 Dth per day, extending from supply areas in the Rocky Mountains to consuming markets in Utah, Nevada and California. On May 1, 2003, Kern River placed into service approximately 700-miles for an expansion project, or the 2003 Expansion Project, which increased the design capacity of Kern River’s pipeline system by 885,575 Dth per day to its current capacity. Except for quantities of natural gas owned for system operations, Kern River does not own the natural gas that is transported through its system. Kern River’s transportation operations are subject to a regulated tariff that is on file with the FERC. The tariff rates are designed to allow it an opportunity to recover its costs and generate a regulated return on equity.

Kern River’s pipeline consists of two sections: the mainline section and the common facilities. Kern River owns the entire mainline section, which extends from the pipeline’s point of origination near Opal, Wyoming through the Central Rocky Mountains area into Daggett, California. The mainline section consists of approximately 700 miles of the original 36-inch diameter pipeline, approximately 600 miles of 36-inch diameter loop pipeline related to the 2003 Expansion Project and approximately 100 miles of various laterals that connect to the mainline.

The common facilities consist of approximately 200-miles of the original pipeline that extends from the point of interconnection with the mainline in Daggett to Bakersfield, California and an

additional approximately 100 miles related to the 2003 Expansion Project. The common facilities are jointly owned by Kern River (approximately 77% as of March 31, 2008) and Mojave Pipeline Company, or Mojave, a wholly owned subsidiary of El Paso Corporation, (approximately 23% as of March 31, 2008), as tenants-in-common. Kern River’s ownership percentage in the common facilities will increase or decrease pursuant to the capital contributions made by the respective joint owners. Kern River has exclusive rights to approximately 1,570,500 Dth per day of the common facilities’ capacity, and Mojave has exclusive rights to 400,000 Dth per day of capacity. Operation and maintenance of the common facilities are the responsibility of Mojave Pipeline Operating Company, an affiliate of Mojave.

Kern River has year-round long-term firm natural gas transportation service agreements for 1,755,575 Dth per day of capacity. Pursuant to these agreements, the pipeline receives natural gas on behalf of shippers at designated receipt points, transports the natural gas on a firm basis up to each shipper’s maximum daily quantity and delivers thermally equivalent quantities of natural gas at designated delivery points. Each shipper pays Kern River the aggregate amount specified in its long-term firm natural gas transportation service agreement and Kern River’s tariff, with such amount consisting primarily of a fixed monthly reservation fee based on each shipper’s maximum daily quantity and a commodity charge based on the actual amount of natural gas transported.

These year-round long-term firm natural gas transportation service agreements expire between September 30, 2011 and April 30, 2018, and have a weighted-average remaining contract term of almost eight years. Shippers on the pipeline include major oil and gas companies or affiliates of such companies, electric generating companies, energy marketing and trading companies, financial institutions and natural gas distribution utilities which provide services in Utah, Nevada and California. As of March 31, 2008, over 92% of the firm capacity has primary delivery points in California, with the flexibility to access secondary delivery points in Nevada and Utah.

Pipelines compete on the basis of cost (including both transportation costs and the relative costs of the natural gas they transport), flexibility, reliability of service and overall customer service. Industrial end-users often have the ability to choose from alternative fuel sources, such as fuel oil and coal, in addition to natural gas. Natural gas competes with other forms of energy, including electricity, coal and fuel oil, primarily on the basis of price. Legislation and governmental regulations, the weather, the futures market, production costs and other factors beyond the control of Northern Natural Gas and Kern River influence the price of natural gas.

Historically, Northern Natural Gas has been able to provide competitively priced services because of its access to a variety of relatively low cost supply basins, its cost control measures and its relatively high load factor throughput, which lowers the per unit cost of transportation. To date, Northern Natural Gas has avoided any significant pipeline system bypasses or turn-back of firm entitlement. In recent years, Northern Natural Gas has retained and signed long-term contracts with customers such as CenterPoint Energy Minnesota Gas, or CenterPoint, Xcel Energy Inc., or Xcel Energy, and Metropolitan Utilities District, which in some cases, because of competition, resulted in lower reservation charges relative to the contracts being replaced. The weighted average remaining contract term for Northern Natural Gas’ Market Area transportation contracts is approximately seven years as of March 31, 2008.

Northern Natural Gas’ major competitors in the Market Area include ANR Pipeline Company, Northern Border Pipeline Company and Natural Gas Pipeline Company of America. Other competitors of Northern Natural Gas include Great Lakes and Viking. In the Field Area, Northern Natural Gas competes with a large number of interstate and intrastate pipeline companies where the vast majority of Northern Natural Gas’ capacity is used for transportation services provided on a short-term firm basis. Northern Natural Gas’ tariff rates are competitive with the market alternative and provide value to the shippers holding the firm capacity.

Although it needs to compete aggressively to retain and build load, Northern Natural Gas believes that current and anticipated changes in its competitive environment have created

opportunities to serve its existing customers more efficiently and to meet certain growing supply needs. While peak day delivery growth of utilities is driven by population growth and alternative fuel replacement, new baseload or off-peak demand growth is being driven primarily by power and ethanol plant expansion. This baseload or off-peak demand growth is important to Northern Natural Gas as this demand provides revenue year round and allows Northern Natural Gas to utilize facilities on a year-round basis. The additional Market Area load growth also supports the continued sale of Northern Natural Gas’ storage services and Field Area transportation services. Northern Natural Gas has been successful in competing for a significant amount of the increased demand related to the construction of new power and ethanol plants as discussed above related to its Northern Lights expansion project.

Kern River competes with various interstate pipelines and its shippers in order to market any unutilized or unsubscribed capacity serving the southern California, Las Vegas, Nevada and Salt Lake City, Utah market areas. Kern River provides its customers with supply diversity through pipeline interconnections with Northwest Pipeline, Colorado Interstate, Overland Trail Pipeline, Questar Pipeline Company and Questar Overthrust Pipeline Company. These interconnections, in addition to the direct interconnections to natural gas processing facilities, allow Kern River to access natural gas reserves in Colorado, northwestern New Mexico, Wyoming, Utah and the Western Canadian Sedimentary Basin.

Kern River is the only interstate pipeline that presently delivers natural gas directly from a gas supply basin to end users in the California market. This enables direct connect customers to avoid paying a ‘‘rate stack’’ (i.e., additional transportation costs attributable to the movement from one or more interstate pipeline systems to an intrastate system within California). Kern River believes that its historic levelized rate structure and access to upstream pipelines/storage facilities and to economic Rocky Mountain gas reserves increases its competitiveness and attractiveness to end-users. Kern River believes it has an advantage relative to other competing interstate pipelines because its relatively new pipeline can be economically expanded and will require significantly less capital expenditures to comply with the Pipeline Safety Improvement Act of 2002, or PSIA, than other systems. Kern River’s favorable market position is tied to the availability and relatively favorable price of gas reserves in the Rocky Mountain area, an area that in recent years has attracted considerable expansion of pipeline capacity serving markets other than California and Nevada. In addition, Kern River’s 2003 Expansion Project has several long-term transportation service agreements with electric generation companies, whose long-term competition and financial prospects are now improving as demand for electric generation in Kern River’s market territory increases and older, less efficient power plants in the region are retired.

In 2007, Northern Natural Gas had two customers who each accounted for greater than 10% of its revenue and its eight largest customers accounted for 54% of its systemwide transportation and storage revenue. Northern Natural Gas has agreements to retain the vast majority of its two largest customers’ volumes through at least 2017. Kern River had three customers who each accounted for greater than 10% of its revenue. The loss of any of these significant customers, if not replaced, could have a material adverse effect on Northern Natural Gas’ and Kern River’s respective businesses.

CE Electric UK, an indirect wholly owned subsidiary of ours, is a holding company which owns, primarily, two companies that distribute electricity in Great Britain, Northern Electric and Yorkshire Electricity. Northern Electric and Yorkshire Electricity operate in the north-east of England from North Northumberland through Durham, Tyne and Wear, Tees Valley and Yorkshire to North Lincolnshire, an area covering approximately 10,000 square miles, and serve approximately 3.8 million end users.

The principal function of Northern Electric and Yorkshire Electricity is to build and maintain the electricity distribution network to serve the end user. The service territory geographically features a

diverse economy with no dominant sector. The mix of rural, agricultural, urban and industrial areas covers a broad customer base ranging from domestic usage through farming and retail to major industry including automotives, chemicals, mining, steelmaking and offshore marine construction. The industry within the area is concentrated around the principal centers of Newcastle, Middlesbrough and Leeds.

The price controlled revenues of the regulated distribution companies are agreed with the regulator, Ofgem, based around 5-year price control periods, with the current price control period commencing April 1, 2005.

In addition to building and maintaining the electricity distribution network, CE Electric UK also owns an engineering contracting business and a hydrocarbon exploration and development business.

Northern Electric’s and Yorkshire Electricity’s operations consist primarily of the distribution of electricity in Great Britain. Northern Electric and Yorkshire Electricity receive electricity from the national grid transmission system and distribute it to their customers’ premises using their networks of transformers, switchgear and distribution lines and cables. Substantially all of the end users in Northern Electric’s and Yorkshire Electricity’s distribution service areas are connected to the Northern Electric and Yorkshire Electricity networks and electricity can only be delivered through their distribution systems, thus providing Northern Electric and Yorkshire Electricity with distribution volume that is relatively stable from year to year. Northern Electric and Yorkshire Electricity each charge fees for the use of their distribution systems to the suppliers of electricity. The suppliers, which purchase electricity from generators and sell the electricity to end-user customers, use Northern Electric’s and Yorkshire Electricity’s distribution networks pursuant to an industry standard ‘‘Distribution Connection and Use of System Agreement,’’ which Northern Electric and Yorkshire Electricity separately entered into with the various suppliers of electricity in their respective distribution service areas. One such supplier, RWE Npower PLC and certain of its affiliates, represented approximately 40% of the total combined distribution revenues of Northern Electric and Yorkshire Electricity in 2007. The fees that may be charged by Northern Electric and Yorkshire Electricity for use of their distribution systems are controlled by a formula prescribed by the United Kingdom’s electricity regulatory body that limits increases (and may require decreases) based upon the rate of inflation, other factors and other regulatory action.

Electricity distributed (in GWh) to end users and the total number of end users (in millions) as of and for the years ended December 31 were as follows:

As of March 31, 2008, Northern Electric’s and Yorkshire Electricity’s electricity distribution network on a combined basis included approximately 29,000 kilometers of overhead lines, approximately 63,000 kilometers of underground cables and approximately 700 major substations.

Integrated Utility Services Limited, CE Electric UK’s indirect wholly-owned subsidiary, is an engineering contracting company providing electrical infrastructure contracting services to third parties.

CE Gas, CE Electric UK’s indirect wholly owned subsidiary, is a hydrocarbon exploration and development company that is focused on developing integrated upstream gas projects in Australia, the United Kingdom and Poland. Its upstream gas business consists of full or partial ownership in exploration, construction and production projects, which, if successful, result in the sale of gas and other hydrocarbon products to third parties.

The CalEnergy Generation-Foreign platform consists of our indirect ownership of the Casecnan project, which is a combined irrigation and hydroelectric power generation project located in the central part of the island of Luzon in the Philippines.

The following table sets out certain information concerning the Casecnan project as of March 31, 2008:

NIA’s payment obligation under the project agreement is substantially denominated in U.S. dollars and is the Casecnan project’s sole source of operating revenue. Because of the dependence on a single customer, any material failure of the customer to fulfill its obligation under the project agreement and any material failure of the ROP to fulfill its obligation under the performance undertaking would significantly impair the ability to meet existing and future obligations of the relevant project company, including obligations pertaining to the outstanding project debt.

CE Casecnan owns and operates the Casecnan project under the terms of the Project Agreement. CE Casecnan will own and operate the project for a 20-year cooperation period which commenced on December 11, 2001, the start of the Casecnan project’s commercial operations, after which ownership and operation of the project will be transferred to NIA at no cost on an ‘‘as-is’’ basis. The Casecnan project is dependent upon sufficient rainfall to generate electricity and deliver water. Rainfall varies within the year and from year to year, which is outside the control of CE Casecnan, and will impact the amounts of electricity generated and water delivered by the Casecnan project. Rainfall has historically been highest from June through December and lowest from January through May. The contractual terms for water delivery fees and variable energy fees can produce variability in revenue between reporting periods.

On June 25, 2006 the Upper Mahiao project’s and on July 25, 2007 the Malitbog and Mahanagdong projects’ separate 10-year cooperation periods ended and the projects, representing a total of 485 MW of net owned contract capacity, were transferred to PNOC-Energy Development Corporation, or PNOC-EDC, by us at no cost on an ‘‘as-is’’ basis.

The subsidiaries comprising our CalEnergy Generation-Domestic platform own interests in 15 non-utility power projects in the U.S. The following table sets out certain information concerning CalEnergy Generation-Domestic’s non-utility power projects in operation as of March 31, 2008:

HomeServices is the second largest full-service residential real estate brokerage firm in the United States. In addition to providing traditional residential real estate brokerage services, HomeServices offers other integrated real estate services, including mortgage originations, primarily through joint ventures, title and closing services, property and casualty insurance, home warranties and other home-related services. HomeServices’ real estate brokerage business is subject to seasonal fluctuations because more home sale transactions tend to close during the second and third quarters of the year. As a result, HomeServices’ operating results and profitability are typically higher in the second and third quarters relative to the remainder of the year. HomeServices currently operates more than 370 broker offices in 19 states with over 18,000 agents under the following 20 brand names: Carol Jones REALTORS, CBSHOME Real Estate, Champion Realty, Edina Realty Home Services, EWM REALTORS, Harry Norman Realtors, HOME Real Estate, Huff Realty, Iowa Realty, Jenny Pruitt and Associates REALTORS, Long Realty Company, Prudential California Realty, Prudential Carolinas Realty, Prudential First Realty, RealtySouth, Rector-Hayden REALTORS, Reece & Nichols, Roberts Brothers, Inc., Semonin REALTORS and Woods Bros. Realty. HomeServices generally occupies the number one or number two market share position in each of its major markets based on aggregate closed transaction sides. HomeServices’ major markets consist of the following

metropolitan areas: Minneapolis and St. Paul, Minnesota; Los Angeles and San Diego, California; Kansas City, Kansas; Kansas City and Springfield, Missouri; Des Moines and Cedar Rapids, Iowa; Atlanta, Georgia; Omaha and Lincoln, Nebraska; Birmingham, Auburn and Mobile, Alabama; Tucson, Arizona; Winston-Salem, Raleigh-Durham and Charlotte, North Carolina; Louisville and Lexington, Kentucky; Annapolis, Maryland; Cincinnati, Ohio; and Miami, Florida. The U.S. residential real estate brokerage business is highly competitive and consists of numerous local brokers and agents in each market seeking to represent sellers and buyers in residential real estate transactions.

In December 2007, approval was received from the Public Utility Commission of Texas, or PUCT, to establish Electric Transmission Texas, LLC, or ETT, as a joint venture company to fund, own and operate electric transmission assets in the Electric Reliability Council of Texas, or ERCOT, market. The PUCT order also approved initial rates based on a 9.96% return on equity and a debt to equity capital structure of 60:40. In December 2007, AEP Texas Central Company contributed $70 million of transmission assets to ETT. Through a series of transactions, a subsidiary of American Electric Power Company, Inc., or AEP, then sold, at net book value, a 50% equity ownership interest in ETT to a wholly-owned subsidiary of ours. ETT intends to invest in additional transmission projects in ERCOT over the next several years. New projects are evaluated on a case-by-case basis and are subject to joint approval by us and AEP. Two immediate sources of new projects include (a) the assignment of AEP Texas Central Company and AEP Texas North Company projects, and (b) potential projects within the ERCOT Competitive Renewable Energy Zones, or CREZ.

In February 2007, ETT filed a proposal with the PUCT that addresses the CREZ initiative of the Texas Legislature, which outlines opportunities for additional significant investment in transmission assets in Texas. The PUCT issued an interim order in August 2007 that determined the wind zones and directed ERCOT to perform studies by April 2008. ERCOT has determined the transmission upgrades necessary to accommodate between 12,000 and 24,800 MW of wind development from CREZ across the Texas panhandle and central West Texas. The PUCT will likely issue an order in July 2008 addressing the final amount of wind capacity and the transmission plan locations. In a separate docket, the PUCT will select the transmission provider(s) to build the transmission. A decision in that proceeding is anticipated by the end of 2008.

In September 2007, subsidiaries of AEP and ours formed Electric Transmission America, LLC, or ETA, to pursue transmission opportunities outside of ERCOT. We also hold a 50% equity ownership in ETA. In May 2008, ETA and Westar Energy, Inc., or Westar, formed Prairie Wind Transmission, LLC, a joint venture company, to build and own new electric transmission assets in Kansas. ETA and Westar filed an application in May 2008 seeking authority from the Kansas Corporation Commission to construct, own and operate transmission in Kansas. ETA and Westar also will seek rate approval from the FERC in the coming months.

As of March 31, 2008, we employed approximately 17,100 people, of which approximately 7,700 are covered by union contracts. The majority of the union employees are employed by PacifiCorp and MidAmerican Energy and are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Boilermakers and the United Mine Workers of America. These collective bargaining agreements have expiration dates ranging through January 2013. HomeServices’ residential real estate agents are independent contractors and not employees.

Our subsidiaries are subject to comprehensive governmental regulation which significantly influences their operating environment, prices charged to customers, capital structure, costs and their ability to recover costs.

Our domestic regulated public utility subsidiaries, PacifiCorp and MidAmerican Energy, are subject to comprehensive regulation by state utility commissions, federal agencies, and other state and local regulatory agencies. The more significant aspects of this regulatory framework are described below.

Historically, state utility commissions have established service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its costs of providing services and to earn a reasonable return on its investment. A utility’s cost-of-service generally reflects its allowed operating expenses, including operation and maintenance expense, depreciation expense and taxes. Some portion of margins earned on wholesale sales for electricity and capacity and gas transmission service has historically been included as a component of retail cost of service upon which retail rates are based. State utility commissions may adjust rates pursuant to a review of (i) a utility’s revenues and expenses during a defined test period and (ii) such utility’s level of investment. State utility commissions typically have the authority to review and change service rates on their own initiative. Some states may initiate reviews at the request of a utility customer, a governmental agency or a representative of a group of customers. The utility and such parties, however, may agree with one another not to request a review of or changes to rates for a specified period of time.

The electric rates of PacifiCorp and MidAmerican Energy are generally based on the cost of providing traditional bundled service, including generation, transmission and distribution services. Historically, the state regulatory framework in the service areas of PacifiCorp’s and MidAmerican Energy’s systems reflected specified power and fuel costs as part of bundled rates or incorporated power or fuel adjustment clauses in the utility’s rates and tariffs. Power and fuel adjustment clauses permit periodic adjustments to cost recovery from customers and therefore provide protection against exposure to cost changes.

Except for Oregon, Washington and Illinois, PacifiCorp and MidAmerican Energy have an exclusive right to serve electricity customers within their service territories and, in turn, have the obligation to provide electric service to those customers. Under Oregon law, certain commercial and industrial customers have the right to choose alternative electric suppliers. The impact of these programs on our financial results has not been material. In Washington, the state statute does not provide for exclusive service territory allocation. PacifiCorp’s service territory in Washington is surrounded by other public utilities with whom PacifiCorp has from time to time entered into service area agreements under the jurisdiction of the Washington Utilities and Transportation Commission, or the WUTC. In Illinois, all customers are free to choose their electricity supplier and MidAmerican Energy has an obligation to serve customers at regulated rates that leave MidAmerican Energy’s system, but later choose to return. To date, there has been no significant loss of customers in Illinois.

PacifiCorp is currently pursuing a regulatory program in all states, with the objective of keeping rates closely aligned to ongoing costs. The following table illustrates the current rate case status in each state jurisdiction in which PacifiCorp operates:


State Regulator	Base Rate⁽¹⁾	Power Costs⁽¹⁾
UPSC	December 2006 stipulation resulted in an annual increase of $115 million, or 10% overall, with $85 million effective in December 2006 and the remaining $30 million effective in June 2007. In December 2007, PacifiCorp filed a general rate case requesting an increase of $161 million, or 11% overall. In February 2008, the UPSC issued an order determining that the proper test period should end December 2008. In March 2008, PacifiCorp filed supplemental testimony reducing the requested rate increase to $100 million. The change in the test period accounts for $40 million of the reduction and reflects an additional $21 million of reductions associated with recent UPSC orders on depreciation rate changes and two deferred accounting requests that were pending when the original case was filed. Hearings on the revenue requirement portion of the case are scheduled for June 2008 with the rate-design phase scheduled for October 2008. PacifiCorp expects that initial rates, if approved, will become effective no later than August 2008. Additionally, on April 7, 2008, PacifiCorp filed a non-obligating notice of intent to file a general rate case with the UPSC on or soon after June 6, 2008.	No separate power cost recovery mechanism.
OPUC	September 2006 settlement agreement resulted in an annual increase for non-power costs of $33 million effective in January 2007⁽²⁾.	Uses an annual transition adjustment mechanism, resulting in a $10 million increase in January 2007. In December 2007, the OPUC issued an order approving an increase of $22 million effective January 1, 2008 related to forecasted power costs. In December 2007, the OPUC approved a renewable adjustment clause, or RAC, mechanism with an effective date of January 1, 2008 to recover revenue requirements of new renewable resources between rate cases. Under the RAC mechanism, PacifiCorp will submit a filing on April 1 of each year, with rates to become effective January 1 of the following year to recover the revenue requirement of new renewable resources and associated transmission that are not reflected in general rates. In April 2008, PacifiCorp filed its first annual RAC to recover the revenue requirement related to new renewable resources and associated transmission that are eligible under the Oregon Renewable Energy Act and are not reflected in general rates. PacifiCorp requested an annual increase of $39 million on an Oregon-allocated basis, or an average price increase of 4%. The OPUC is expected to issue a decision by November 2008, with rates effective January 1, 2009. In April 2008, as part of its annual transition adjustment mechanism, PacifiCorp filed its forecasted net power costs for 2009. PacifiCorp proposed a net power cost increase of $41 million on an Oregon-allocated basis, or an average price increase of 4%. The forecasted net power costs will be updated in July 2008 and early November 2008 for changes to the forward price curve, new contracts and updates for wholesale revenues, purchases, fuel and transmission expenses. A final update for changes in the forward price curve will be filed in November 2008. The OPUC is expected to issue a decision by November 2008, with rates effective January 1, 2009.


State Regulator	Base Rate⁽¹⁾	Power Costs⁽¹⁾
WPSC	In June 2007, PacifiCorp filed for a rate increase of $36 million, or 8% overall, to be effective May 1, 2008. In January 2008, PacifiCorp reached a settlement with all parties to this case for an annual increase of $23 million, or 5% overall. The final stipulation was approved on April 30, 2008 by the WPSC.	The January 2008 rate case settlement allows for a one time forecast period for the existing power cost mechanism. The power cost adjustment mechanism terminates in April 2011. PacifiCorp’s marginal cost pricing tariff proposal will not be implemented, but will be the subject of a collaborative process to seek a new pricing proposal. Also as part of the settlement, PacifiCorp agreed to withdraw from this filing its request for a renewable resource recovery mechanism. The stipulation was approved by the WPSC in April 2008. In February 2008, PacifiCorp filed its annual deferred net power cost adjustment application with the WPSC for $31 million of costs incurred during the period December 1, 2006 through November 30, 2007. In March 2008, the WPSC approved PacifiCorp’s request on an interim basis effective April 1, 2008, resulting in an annual rate increase of $31 million, or an average price increase of 8%. The interim surcharge will continue until the matter is either settled through negotiation with the parties or is litigated in a contested hearing. In either case, the WPSC must approve the final surcharge and tariff.
WUTC	In June 2007, the WUTC approved a rate increase of $14 million, or 6% overall, effective June 27, 2007 and accepted PacifiCorp’s proposed western balancing authority area cost allocation methodology for a five-year pilot period. In February 2008, PacifiCorp filed a general rate case with the WUTC for an annual increase of $35 million, or 15% overall, with an effective date no later than January 2009.	No separate power cost recovery mechanism.
IPUC	In December 2007, the IPUC approved a settlement of PacifiCorp’s general rate case, resulting in a $12 million, or 6% overall, base rate increase effective January 2008. The settlement also provides for rate increases effective January 1, 2009 and 2010 for PacifiCorp’s two special contract industrial customers and no additional rate changes for those two special contract customers effective prior to January 1, 2011. Additional rate increases for the remaining customer classes may be requested if needed to maintain cost of service coverage.	No separate power cost recovery mechanism.
CPUC	The CPUC approved a $1 million, or 1% overall, increase effective January 1, 2008 to reflect changes to the post test-year adjustment mechanism, which allows for annual rate adjustments for changes in operating costs and plant additions outside of the context of a traditional rate case.	In December 2007, the CPUC approved a $5 million, or 7% overall, increase effective January 1, 2008 to reflect the new level of net power costs.

The IUB has approved over the past several years a series of electric settlement agreements between MidAmerican Energy, the OCA and other interveners under which, MidAmerican Energy has agreed not to seek a general increase in electric base rates to become effective prior to January 1, 2014, unless its Iowa jurisdictional electric return on equity for any year covered by the applicable agreement falls below 10%, computed as prescribed in each respective agreement. Prior to filing for a general increase in electric rates, MidAmerican Energy is required to conduct 30 days of good faith

negotiations with the signatories to the settlement agreements to attempt to avoid a general increase in rates. As a party to the settlement agreements, the OCA has agreed not to request or support any decrease in MidAmerican Energy’s Iowa electric base rates to become effective prior to January 1, 2014. The settlement agreements specifically allow the IUB to approve or order electric rate design or cost of service rate changes that could result in changes to rates for specific customers as long as such changes do not result in an overall increase in revenues for MidAmerican Energy. Additionally, the settlement agreements also each provide that revenues associated with Iowa retail electric returns on equity within specified ranges will be shared with customers. Refer to Note 6 of our Notes to audited Consolidated Financial Statements included in the ‘‘Financial Statements’’ section of this prospectus for additional discussion regarding these settlements.

On July 27, 2007, the IUB approved a settlement agreement between MidAmerican Energy and the OCA in conjunction with MidAmerican Energy’s ratemaking principles application for up to 540 MW (nameplate ratings) of additional wind-powered generation capacity in Iowa to be placed in service on or before December 31, 2013. All new wind-powered generation capacity up to the 540 MW will be subject to the 2007 settlement agreement, including 78 MW (nameplate ratings) placed in service in the fourth quarter of 2007 and 81 MW (nameplate ratings) placed in service in the first quarter of 2008. As of March 31, 2008, MidAmerican Energy had 489 MW (nameplate ratings) of wind-powered generation capacity in Iowa under development or construction that it expects will be placed in service by December 31, 2008, including 108 MW (nameplate ratings) not covered by the 2007 settlement agreement. The 108 MW expansion is the subject of a settlement agreement between MidAmerican Energy and the OCA, which must be approved by the IUB prior to becoming effective. Generally speaking, accredited capacity ratings for wind-powered generation facilities are considerably less than the nameplate ratings due to the varying nature of wind. MidAmerican Energy continues to pursue additional cost effective wind-powered generation capacity. Refer to Note 6 of our Notes to audited Consolidated Financial Statements included in the ‘‘Financial Statements’’ section of this prospectus for additional discussion regarding these settlements.

MidAmerican Energy does not have an electric fuel and purchased power adjustment clause in Iowa. A monthly purchased gas cost adjustment clause combined with an Incentive Gas Supply Procurement Plan provides protection from market changes in gas costs while offering financial incentives for MidAmerican Energy to minimize the cost of its gas supply portfolio.

In December 1997, Illinois enacted a law to restructure Illinois’ electric utility industry. The law changed how and what electric services are regulated by the Illinois Commerce Commission, or ICC, and transitioned portions of the traditional electric services to a competitive environment. Electric base rates in Illinois were generally frozen until January 1, 2007, and are now subject to cost-based ratemaking.

Effective January 2007, MidAmerican Energy and the ICC have eliminated the monthly adjustment clause for recovery of fuel for electric generation and purchased power costs in Illinois. Base rates have been adjusted effective January 1, 2007 to include recoveries at average 2004/2005 cost levels. The elimination of the fuel adjustment clause exposes MidAmerican Energy to monthly market price changes for fuel and purchased power costs in Illinois, with rate case approval required for any base rate changes. With the elimination of the fuel adjustment clause, MidAmerican Energy may not petition for its reinstatement until November 2011. A monthly adjustment clause remains in effect for MidAmerican Energy’s purchased gas costs.

The FERC is an independent agency with broad authority to implement provisions of the Federal Power Act and the Energy Policy Act. MidAmerican Energy is also subject to regulation by the NRC pursuant to the Atomic Energy Act of 1954, as amended, or Atomic Energy Act, with respect to the operation of the Quad Cities Station.

Under the Federal Power Act, the FERC regulates rates for interstate sales of electricity at wholesale, transmission of electric power, accounting, securities issuances and other matters, including construction and operation of hydroelectric projects. Margins earned on wholesale sales for electricity and capacity and transmission service have historically been included as a component of retail cost of service upon which retail rates are based.

The FERC regulates PacifiCorp’s and MidAmerican Energy’s rates charged to wholesale customers for electricity, capacity and transmission services. Most of PacifiCorp’s and MidAmerican Energy’s electric wholesale sales and purchases take place under market-based rate pricing allowed by the FERC and are therefore subject to market volatility. A December 2006 decision of the Ninth Circuit changed the interpretation of the relevant standard that the FERC should apply when reviewing wholesale contracts for electricity or capacity from a stringent ‘‘public policy’’ standard to a broader ‘‘just and reasonable’’ standard making contracts more vulnerable to challenge. The decision raises some concerns regarding the finality of contract prices, particularly from the sellers’ side of the transactions. The U.S. Supreme Court is reviewing the case on appeal and the outcome of its ruling cannot be predicted at this time. All sellers subject to the FERC’s jurisdiction, including PacifiCorp and MidAmerican Energy, are currently subject to increased risk as a result of this decision.

The FERC conducts a triennial review of PacifiCorp’s and MidAmerican Energy’s market-based rate pricing authority. Each utility must demonstrate the lack of generation market power in order to charge market-based rates for sales of wholesale electricity and capacity in their respective balancing authority areas. Under the FERC’s market-based rules, PacifiCorp and MidAmerican Energy must file a notice of change in status when 100 MW of incremental generation becomes operational. Following separate filings by PacifiCorp of a change in status notice relating to new generation, the FERC in February and November 2007, confirmed that PacifiCorp does not have market power and may continue to charge market-based rates. In accordance with the filing schedule established by the FERC in Order No. 697, PacifiCorp’s next triennial review will occur in 2010. MidAmerican Energy’s most recent review, which began in October 2004, is complete pending the FERC’s acceptance of a refund report filed in May 2008 describing an immaterial amount of refunds for certain sales made within MidAmerican Energy’s balancing authority area for delivery outside the balancing authority area. The refunds were made as directed by the FERC in an order issued in April 2008. In the order, the FERC confirmed that MidAmerican Energy is authorized to sell at market-based rates outside of its balancing authority area and directed that MidAmerican Energy submit its next required triennial review in accordance with the schedule established in Order No. 697. In Order No. 697-A, the FERC confirmed that MidAmerican Energy’s next triennial filings will occur in June and December 2008.

The FERC regulates PacifiCorp’s and MidAmerican Energy’s wholesale transmission services. The regulation requires each to provide open access transmission service at cost-based rates. The FERC also regulates unbundled transmission service to retail customers. These services are offered on a non-discriminatory basis, meaning that all potential customers are provided an equal opportunity to access the transmission system. Our transmission businesses are managed and operated independently from our generating and wholesale marketing businesses in accordance with the FERC Standards of Conduct.

In January 2007, the FERC approved a settlement with PacifiCorp regarding PacifiCorp’s use of its transmission system while conducting wholesale power transactions with third parties. PacifiCorp discovered possible violations of its FERC-approved tariff during an internal review of its compliance with certain FERC regulations shortly before our acquisition of PacifiCorp. Upon completion of the acquisition, PacifiCorp self-reported the potential violations to the FERC. The potential violations primarily related to the way PacifiCorp used its own transmission system to transmit energy using ‘‘network service’’ instead of ‘‘point-to-point’’ service as the FERC believes is required by PacifiCorp’s

tariff. This use of transmission service neither enriched PacifiCorp’s shareholders nor harmed its retail customers. As part of the settlement, PacifiCorp voluntarily refunded $1 million to other transmission customers in April 2006 and paid a $10 million fine to the U.S. Treasury in January 2007.

On February 16, 2007, the FERC adopted a final rule in Order No. 890 designed to strengthen the pro-forma OATT by providing greater specificity and increasing transparency. The most significant revisions to the pro forma OATT relate to the development of more consistent methodologies for calculating available transfer capability, changes to the transmission planning process, changes to the pricing of certain generator and energy imbalances to encourage efficient scheduling behavior and to exempt intermittent generators, and changes regarding long-term point-to-point transmission service, including the addition of conditional firm long-term point-to-point transmission service, and generation redispatch. As transmission providers with an OATT on file with the FERC, PacifiCorp and MidAmerican Energy are required to comply with the requirements of the new rule. The first compliance filing, which amends the OATT, was filed on July 13, 2007. Certain details related to the precise methodology that will be used to calculate available transfer capability were filed with the FERC on September 11, 2007. A number of parties to the proceeding, including PacifiCorp and MidAmerican Energy, have requested rehearing or clarification of various portions of the final rule. In December 2007, the FERC issued Order No. 890-A generally affirming the provisions of the final rule as adopted in Order No. 890 with certain limited clarifications. Although PacifiCorp has requested a limited clarification of Order No. 890-A, the final rule as revised is not anticipated to have a significant impact on PacifiCorp’s or MidAmerican Energy’s financial results, but it will likely have a significant impact on their transmission operations, planning and wholesale marketing functions.

In March 2007, the FERC issued Order No. 693, Mandatory Reliability Standards for the Bulk-Power System, which imposes penalties of up to $1 million per day per violation for failure to comply with new electric reliability standards. The FERC approved 83 reliability standards developed by the North American Electric Reliability Corporation, or the NERC. Responsibility for compliance and enforcement of these standards has been given to the WECC for PacifiCorp and the Midwest Reliability Organization for MidAmerican Energy. The 83 standards comprise over 600 requirements and sub-requirements with which PacifiCorp and MidAmerican Energy must comply. On June 18, 2007, the standards became mandatory and enforceable under federal law. PacifiCorp and MidAmerican Energy expect that the existing standards will change as a result of modifications, guidance and clarification following industry implementation and ongoing audits and enforcement. On January 18, 2008, the FERC approved eight additional cyber security and critical infrastructure protection standards proposed by the NERC. The additional standards became effective on April 7, 2008. We cannot predict the effect that these standards will have on our consolidated financial results, however, they will likely have a significant impact on PacifiCorp’s and MidAmerican Energy’s transmission operations and resource planning functions. Also during 2007, the WECC audited PacifiCorp’s compliance with several of the reliability standards approved by the FERC. PacifiCorp is analyzing the preliminary results of the audit and, at this time, cannot predict the impact of potential penalties, if any, on its consolidated financial results.

Neither PacifiCorp nor MidAmerican Energy is part of a RTO, but MidAmerican Energy has hired an independent transmission system coordinator to administer various MidAmerican Energy OATT functions for transmission service and is evaluating participating in a RTO market. PacifiCorp, along with other private utilities and public power organizations throughout the Pacific Northwest and Western United States, is a member of the Northern Tier Transmission Group, which initially will conduct reliability and economic planning coordination for its members.

maintenance expense, and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. Refer to Note 8 of our Notes to unaudited interim Consolidated Financial Statements included in the ‘‘Financial Statements’’ section of this prospectus for additional information regarding hydroelectric relicensing.

The Northwest Power Act, through the Residential Exchange Program, provides access to the benefits of low-cost federal hydroelectricity to the residential and small-farm customers of the region’s investor-owned utilities. The program is administered by the Bonneville Power Administration, or the BPA, in accordance with federal law. Pursuant to agreements between the BPA and PacifiCorp, benefits from the BPA are passed through to PacifiCorp’s Oregon, Washington and Idaho residential and small-farm customers in the form of electricity bill credits. Several publicly owned utilities, cooperatives and the BPA’s direct-service industry customers filed lawsuits against the BPA with the United States Court of Appeals for the Ninth Circuit, or the Ninth Circuit, seeking review of certain aspects of the BPA’s Residential Exchange Program, as well as challenging the level of benefits previously paid to investor-owned utility customers under the agreements. In May 2007, the Ninth Circuit issued two decisions that resulted in the BPA suspending payments to the Pacific Northwest’s six utilities, including PacifiCorp. This resulted in increases to PacifiCorp’s residential and small-farm customers’ electric bills in Oregon, Washington and Idaho. In February 2008, the BPA initiated a rate proceeding under section 7(i) of the Northwest Power Act to reconsider the level of benefits for the years 2002 through 2006 consistent with the Ninth Circuit’s decisions to re-establish the level of benefits for years 2007 and 2008 and to set the level of benefits for years 2009 and beyond. Also in February 2008, the BPA offered PacifiCorp and other investor-owned utilities an interim agreement intended to resume customer benefits pending the outcome of the rate proceeding. In March 2008, the OPUC ordered PacifiCorp to not execute the interim agreement offered by the BPA because the benefits offered were subject to true-up and acceptance of the benefits before the conclusion of the rate proceeding was not in the best interest of customers. Also in March 2008, PacifiCorp and other parties submitted opening testimony in the BPA Section 7(i) rate proceeding. Because the benefit payments from the BPA are passed through to PacifiCorp’s customers, the outcome of this matter is not expected to have a significant effect on our consolidated financial results.

On August 8, 2005, the Energy Policy Act was signed into law and has significantly impacted the energy industry. In particular, the law expanded the FERC’s regulatory authority in areas such as electric system reliability, electric transmission expansion and pricing, regulation of utility holding companies, and enforcement authority to issue civil penalties of up to $1 million per day. While the FERC has now issued rules and decisions on multiple aspects of the Energy Policy Act, the full impact of those decisions remains uncertain.

The Energy Policy Act also repealed the Public Utility Holding Company Act of 1935, or PUHCA 1935, and enacted the Public Utility Holding Company Act of 2005, or PUHCA 2005, effective February 8, 2006. PUHCA 2005 eliminated the substantive requirements and restrictions previously applicable to holding companies under PUHCA 1935. Its repeal enabled Berkshire Hathaway to convert its shares of our no par, zero-coupon non-voting convertible preferred stock into an equal number of shares of our voting common stock. As a consequence, we became a consolidated subsidiary of Berkshire Hathaway. PUHCA 2005 also increased the FERC’s authority over utility mergers, provides the FERC with access to books and records and requires holding companies to comply with its record retention requirements.

The Energy Policy Act also gives the FERC ‘‘backstop’’ transmission siting authority and directs the FERC to oversee the establishment of mandatory transmission reliability standards as discussed above. The Energy Policy Act also extended the federal production tax credit for new renewable electricity generation projects through December 31, 2007, with subsequent legislation extending the credit to December 31, 2008. Partly as a result of that portion of the law, PacifiCorp and MidAmerican Energy began development efforts to add additional wind-powered generation facilities.

MidAmerican Energy is subject to the jurisdiction of the NRC with respect to its license and 25% ownership interest in the Quad Cities Station. Exelon Generation is the operator of Quad Cities Station and is under contract with MidAmerican Energy to secure and keep in effect all necessary NRC licenses and authorizations.

The NRC regulates the granting of permits and licenses for the construction and operation of nuclear generating stations and regularly inspects such stations for compliance with applicable laws, regulations and license terms. Current licenses for the Quad Cities Station provide for operation until December 14, 2032. The NRC review and regulatory process covers, among other things, operations, maintenance, and environmental and radiological aspects of such stations. The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of such licenses.

Federal regulations provide that any nuclear operating facility may be required to cease operation if the NRC determines there are deficiencies in state, local or utility emergency preparedness plans relating to such facility, and the deficiencies are not corrected. Exelon Generation has advised MidAmerican Energy that an emergency preparedness plan for Quad Cities Station has been approved by the NRC. Exelon Generation has also advised MidAmerican Energy that state and local plans relating to Quad Cities Station have been approved by the Federal Emergency Management Agency.

MidAmerican Energy maintains financial protection against catastrophic loss associated with its interest in the Quad Cities Station through a combination of insurance purchased by Exelon Generation (the operator and joint owner of the Quad Cities Station), insurance purchased directly by MidAmerican Energy, and the mandatory industry-wide loss funding mechanism afforded under the Price-Anderson Amendments Act of 1988, which was amended and extended by the Energy Policy Act of 2005. The general types of coverage are: nuclear liability, property coverage and nuclear worker liability.

Mining operations are regulated by the federal Mine Safety and Health Administration, or MSHA, which administers federal mine safety and health laws, regulations and state regulatory agencies. The Mine Improvement and New Emergency Response Act of 2006, or MINER Act, enacted in June 2006, amended previous mine safety and health laws to improve mine safety and health and accident preparedness. The MINER Act, portions of which are not yet fully implemented, requires operators of underground coal mines to develop a written emergency response plan specific to each mine they operate. These plans must be updated and re-certified by MSHA every six months. It also requires every mine to have at least two rescue teams located within one hour, and it limits the legal liability of rescue team members and the companies that employ them. The MINER Act also increases civil and criminal penalties for violations of federal mine safety standards and gives MSHA the ability to institute a civil action for relief, including a temporary or permanent injunction, restraining order or other appropriate order against a mine operator who fails to pay the penalties or fines.

The natural gas pipeline and storage operations of our U.S. interstate pipeline subsidiaries are regulated by the FERC, which administers, most significantly, the Natural Gas Act and the Natural Gas Policy Act of 1978. Under this authority, the FERC regulates, among other items, (i) rates, charges, terms and conditions of service, and (ii) the construction and operation of U.S. pipelines, storage and related facilities, including the extension, expansion or abandonment of such facilities.

Northern Natural Gas continues to use a modified straight fixed variable rate design methodology, whereby substantially all fixed costs, including a return on invested capital and income taxes, are collected through reservation charges, which are paid by firm transportation and storage customers

regardless of volumes shipped. Commodity charges, which are paid only with respect to volumes actually shipped, are designed to recover the remaining, primarily variable, cost. Kern River’s rates have historically been set using a ‘‘levelized cost-of-service’’ methodology so that the rate is constant over the contract period; however, rate design is the subject of Kern River’s current rate case before the FERC and may be subject to change as a result of the rate case outcome. This levelized cost of service has been achieved by using a FERC-approved depreciation schedule in which depreciation increases as interest expense decreases.

FERC regulations also restrict each pipeline’s marketing affiliates’ access to U.S. interstate pipeline natural gas transmission customer data and place certain conditions on services provided by the U.S interstate pipelines to their marketing affiliates.

Additional proposals and proceedings that might affect the interstate natural gas pipeline industry are considered from time to time by the U.S. Congress, the FERC, state regulatory bodies and the courts. We cannot predict when or if any new proposals might be implemented or, if so, how Northern Natural Gas and Kern River might be affected.

U.S. interstate natural gas pipelines are also subject to regulations by a federal agency within the DOT, pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended, or NGPSA, which establishes safety requirements in the design, construction, operation and maintenance of interstate natural gas transportation facilities, and the PSIA, which implemented additional safety and pipeline integrity regulations for high consequence areas.

The NGPSA requires any entity that owns or operates pipeline facilities to comply with applicable safety standards, to establish and maintain inspection and maintenance plans and to comply with such plans. Our pipeline operations conduct internal audits of their major facilities at least every four years, with more frequent reviews of those it deems of higher risk. The DOT also routinely audits these pipeline facilities. Compliance issues that arise during these audits or during the normal course of business are addressed on a timely basis.

The PSIA, as amended by the Pipeline Safety Act of 2002 and the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, established mandatory inspections for all natural gas pipelines in high-consequence areas. These regulations require pipeline operators to implement integrity management programs, including more frequent inspections, and other safety protection in areas where the consequences of potential pipeline accidents pose the greatest risk to life and property. We believe our pipeline operations comply in all material respects to this regulation. The regulation also requires Northern Natural Gas and Kern River to complete certain modifications to their pipeline systems by December 17, 2012. Each pipeline is scheduled to have this work completed by December 2011.

In addition to FERC and DOT regulation, certain operations are subject to oversight by state regulatory commissions.

Northern Electric and Yorkshire Electricity, as holders of electricity distribution licenses, are subject to regulation by GEMA. GEMA discharges certain of its powers through its staff within Ofgem. Each of fourteen distribution license holders, or DLH, distributes electricity from the national grid system to end use customers within their respective distribution service areas.

Given the absence of an effective competitive market in the distribution of electricity, the amount of revenue that can be collected from customers by a DLH is controlled by a distribution price control formula. This encourages companies to look for efficiency gains in order to improve profits. The distribution price control formula also adjusts the revenue received by DLHs to reflect an increase or decrease in distribution of units and number of end users. Currently, price controls are established every five years, although the formula has been, and may be, reviewed at the regulator’s discretion. The procedure and methodology adopted at a price control review are at the reasonable discretion of Ofgem. Historically, Ofgem’s judgment of the future allowed revenue of licensees has been based upon, among other things:

The current electricity distribution price control was agreed in December 2004, became effective April 2005 and is expected to continue through March 2010. Prices during this 5-year period will be allowed to increase by no more than the rate of inflation (based upon the retail price index). Ofgem also indicated that during the current price control period, the retention of any actual reductions in operating costs from the assumptions used in setting the new price control might depend on the successful implementation of revised cost reporting guidelines prescribed by Ofgem and to be applied by all DLHs.

A number of incentive schemes also operate within the current price control period to encourage DLHs to provide an appropriate quality of service with specified payments to be made for failures to meet prescribed standards of service. The aggregate of these payments is uncapped, but may be excused in certain prescribed circumstances that are generally beyond the control of the DLH. There are also incentive schemes pursuant to which allowed revenue may increase by up to 3.3% or decrease by up to 3.5% in any year.

Ofgem also monitors DLH compliance with license conditions and enforces the remedies resulting from any breach of condition. License conditions include the prices and terms of service, financial strength of the DLH, the provision of information to Ofgem and the public, as well as maintaining transparency, non-discrimination and avoidance of cross-subsidy in the provision of such services. Ofgem also monitors and enforces certain duties of a DLH set out in the Electricity Act of 1989 including the duty to develop and maintain an efficient, coordinated and economical system of electricity distribution. Under the Utilities Act 2000, the regulators are able to impose financial penalties on DLHs who contravene any of their license duties or certain of their duties under the Electricity Act 1989, as amended, or who are failing to achieve a satisfactory performance in relation to the individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the licensee’s revenue.

The Philippine Congress has passed the Electric Power Industry Reform Act of 2001, or EPIRA, which is aimed at restructuring the Philippine power industry, privatizing the NPC and introducing a competitive electricity market, among other initiatives. The implementation of EPIRA may impact our future operations in the Philippines and the Philippine power industry as a whole, the effect of which is not yet known as changes resulting from EPIRA are ongoing.

Both the Cordova and Power Resources Projects are Exempt Wholesale Generators, or EWG, under the Energy Policy Act while the remaining domestic projects are currently certified as Qualifying Facilities, or QF, under the Public Utility Regulatory Policies Act of 1978. Both EWGs and

QFs are generally exempt from compliance with extensive federal and state regulations that control the financial structure of an electric generating plant and the prices and terms at which electricity may be sold by the facilities.

EWGs are permitted to sell capacity and electricity only in the wholesale markets, not to end users. Additionally, utilities are required to purchase electricity produced by QFs at a price that does not exceed the purchasing utility’s ‘‘avoided cost’’ and to sell back-up power to the QFs on a non-discriminatory basis. Avoided cost is defined generally as the price at which the utility could purchase or produce the same amount of power from sources other than the QF on a long-term basis. The Energy Policy Act eliminated the purchase requirement for utilities with respect to new contracts under certain conditions. New QF contracts are also subject to FERC rate filing requirements, unlike QF contracts entered into prior to the Energy Policy Act. FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates other than the utilities’ avoided cost.

HomeServices is regulated by the U.S. Department of Housing and Urban Development, or HUD, most significantly under the Real Estate Settlement Procedures Act, or RESPA, and by state agencies where it operates. RESPA primarily governs the real estate settlement process by mandating all parties fully inform borrowers about all closing costs, lender servicing and escrow account practices, and business relationships between closing service providers and other parties to the transaction. In March 2008, HUD issued a proposed rule to revise the RESPA regulation by updating procedures and forms, enhancing notice and communication requirements and further clarifying the scope of business relationships among closing service providers. We are presently unable to quantify the likely impact of a final rule, if adopted.

We and our subsidiaries are subject to federal, state, local, and foreign laws and regulations with regard to air and water quality, renewable portfolio standards, hazardous and solid waste disposal and other environmental matters and are subject to zoning and other regulation by local authorities. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance including fines, injunctive relief and other sanctions. We believe we are in material compliance with all laws and regulations. The most significant environmental laws and regulations affecting us include:

Refer to Liquidity and Capital Resources included in the ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ section of this prospectus for additional information regarding planned capital expenditures related to environmental regulation.

The Clean Air Act provides a framework for protecting and improving the nation’s air quality, and controlling mobile and stationary sources of air emissions. The major Clean Air Act programs, which most directly affect our electric generating facilities, are briefly described below. Many of these programs are implemented and administered by the states, which can impose additional, more stringent requirements.

The EPA implements national ambient air quality standards for ozone and fine particulate matter, as well as for other criteria pollutants that set the minimum level of air quality for the United States. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area are required to make emissions reductions. A new, more stringent standard for fine particulate matter became effective on December 18, 2006, but is under legal challenge in the United States Court of Appeals for the District of Columbia Circuit. Air quality modeling and preliminary air quality monitoring data indicate that portions of the states in which PacifiCorp and MidAmerican Energy have major emission sources may not meet the new standards. Until attainment designations under the new fine particulate standard are made, the impact of these new standards on PacifiCorp and MidAmerican Energy will not be known. The counties in Washington, Idaho, Montana, Wyoming, Colorado, Utah and Arizona, where PacifiCorp’s major emission sources are located are in attainment of the current ambient air quality standards. The Iowa Department of Natural Resources recently notified emission sources, including MidAmerican Energy’s Riverside and Louisa facilities, in Scott and Muscatine Counties in Iowa that the two counties have not attained the fine particulate matter standard that was adopted in December 2006. MidAmerican Energy’s remaining major emission sources are located in attainment areas. The Iowa Department of Natural Resources has made a preliminary determination that MidAmerican Energy’s sources are not included within the proposed nonattainment boundary; however, the full effect of the nonattainment area’s impact on MidAmerican Energy’s sources has not yet been fully determined.

In July 2007, the EPA proposed revisions to the primary and secondary national ambient air quality standards for ozone, including lowering the current level of the 8-hour standard from 0.08 parts per million to a range of 0.070 and 0.075 parts per million. The EPA also solicited public comments through October 9, 2007 on alternative levels between 0.060 parts per million and the current 8-hour standard. On March 12, 2008 the EPA issued final rules to strengthen the national ambient air quality standard for ground level ozone, lowering the standard to 0.075 parts per million from 0.08 parts per million. States will then have until March 2009 to characterize their attainment status, with the EPA’s determinations regarding non-attainment made by March 2010 and state implementation plans due in 2013. Until the EPA makes its final determination on the revised standards and attainment designations are made, the impact of any new standards on PacifiCorp and MidAmerican Energy will not be known.

In March 2005, the EPA released the final Clean Air Mercury Rule, or CAMR, a two-phase program that utilizes a market-based cap and trade mechanism to reduce mercury emissions from coal-burning power plants from the 1999 nationwide level of 48 tons to 15 tons. The CAMR required initial reductions of mercury emission in 2010 and an overall reduction in mercury emissions from coal-burning power plants of 70% by 2018. The individual states in which PacifiCorp and MidAmerican Energy operate facilities regulated under the CAMR submitted state implementation plans reflecting their regulations relating to state mercury control programs. On February 8, 2008, a three-judge panel of the United States Court of Appeals for the District of Columbia Circuit held that the EPA improperly removed electricity generating units from Section 112 of the Clean Air Act and, thus, that the CAMR was improperly promulgated under Section 111 of the Clean Air Act. The court vacated the CAMR’s new source performance standards and remanded the matter to the EPA for reconsideration. On March 24, 2008, the EPA filed for rehearing of the decision of the three-judge panel by the full court. Until the court or the EPA take further action, it is not known the extent to which future mercury rules may impact PacifiCorp’s and MidAmerican Energy’s current plans to reduce mercury emissions at their coal-fired facilities.

In March 2005, the EPA released the final CAIR, calling for reductions of SO₂ and NO_x emissions in the Eastern United States through, at each state’s option, a market-based cap and trade system, emission reductions, or both. The state of Iowa has adopted rules implementing the market-based cap and trade system. While the state of Iowa has been determined to be in attainment of the existing ozone and fine particulate standards, Iowa has been found to significantly contribute to nonattainment of the fine particulate standard in Cook County, Illinois; Lake County, Indiana; Madison County, Illinois; St. Clair County, Illinois; and Marion County, Indiana. The EPA has also concluded that emissions from Iowa significantly contribute to ozone nonattainment in Kenosha and Sheboygan counties in Wisconsin and Macomb County, Michigan. Under the CAIR, the first phase of NO_xemissions reductions are effective January 1, 2009, and the first phase of SO₂ emissions reductions are effective January 1, 2010. For both NO_x and SO₂, the second-phase reductions are effective January 1, 2015. The CAIR requires overall reductions by 2015 of SO₂ and NO_x in Iowa of 68% and 67%, respectively, from 2003 levels. PacifiCorp’s generation facilities are not subject to the CAIR.

The CAIR could, in whole or in part, be superseded or made more stringent by current or future regulatory and legislative proposals at the federal or state levels that would result in significant reductions of SO₂, NO_X and mercury, as well as carbon dioxide and other gases that may affect global climate change. In addition to any federal rules or legislation that could be enacted, the CAIR could be changed or overturned as a result of litigation. The sufficiency of the standards established by the CAIR has been legally challenged in the United States Circuit Court of Appeals for the District of Columbia.

The EPA has initiated a regional haze program intended to improve visibility at specific federally protected areas. Some of PacifiCorp’s and MidAmerican Energy’s plants meet the threshold

applicability criteria under the Clean Air Visibility Rules. In accordance with the federal requirements, states were required to submit state implementation plans by December 2007 to demonstrate reasonable progress toward achieving natural visibility conditions in certain Class I areas by requiring emission controls, known as best available retrofit technology, on sources with emissions that are anticipated to cause or contribute to impairment of visibility. Iowa submitted its state implementation plan to the EPA by December 2007 and suggested that the emission reductions already made by MidAmerican Energy and additional reductions that will be made under the CAIR place the state in the position that no further reductions should be required. Wyoming has not yet submitted its state implementation plan and is continuing to review the results of analyses relating to planned emission reductions at PacifiCorp’s Wyoming generating plants. Utah has not yet submitted its state implementation plan, but expects to do so in the near term. PacifiCorp believes that its planned emission reduction projects will satisfy the regional haze requirements in Utah and Wyoming; however, it is possible that some additional controls may be required once the respective state implementation plans have been submitted.

Under existing New Source Review, or NSR, provisions of the Clean Air Act, any facility that emits regulated pollutants 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 to an existing stationary source of such pollutants that increases certain levels of emissions, unless the changes are exempt under the regulations (including routine maintenance, repair and replacement of equipment). In general, projects subject to NSR regulations are subject to pre-construction review and permitting under the Prevention of Significant Deterioration, or 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 and other sanctions and remedies including requiring installation of enhanced pollution controls and funding supplemental environmental projects.

As part of an industry-wide investigation to assess compliance with the NSR and PSD provisions, the EPA has requested from numerous utilities information and supporting documentation regarding their capital projects for various generating plants. Between 2001 and 2003, PacifiCorp and MidAmerican Energy responded to requests for information relating to their capital projects at their generating plants. PacifiCorp has been engaged in periodic discussions with the EPA over several years regarding this matter. There are currently no outstanding data requests at MidAmerican Energy pending from the EPA. An NSR enforcement case against another utility has been decided by the Supreme Court, holding that an increase in the annual emissions of a facility, when combined with a modification (i.e., a physical or operational change), may trigger NSR permitting. PacifiCorp and MidAmerican Energy cannot predict the outcome of the EPA’s review of the data they have submitted at this time.

In 2002 and 2003, the EPA proposed various changes to its NSR rules that clarify what constitutes routine repair, maintenance and replacement for purposes of triggering NSR requirements. These changes have been subject to legal challenge and in March 2006, a panel of the United States Court of Appeals for the District of Columbia Circuit invalidated portions of the EPA’s new NSR rules, holding that they conflicted with the wording of the statute. However, the EPA has asked the Supreme Court to review portions of the case. Until such time as the legal challenges are resolved and the revised rules are effective, PacifiCorp and MidAmerican Energy will continue to manage projects at their generating plants in accordance with the rules in effect prior to 2002, except for pollution-control projects, which are now subject to permitting under the PSD program. In 2005, the EPA proposed a rule that would change or clarify how emission increases are to be calculated for purposes of determining the applicability of the NSR permitting program for existing power plants. The EPA also proposed additional changes to the NSR rules in September 2006 that are intended to simplify the

permitting process and allow facilities to undertake activities that improve their safety, reliability and efficiency without triggering NSR requirements. In April 2007, the EPA issued a supplemental notice of proposed rulemaking to the October 2005 proposed rulemaking to determine emissions increases for electric generating units, proposing to use both hourly and annual emissions tests to determine whether utilities trigger the NSR permitting program when an existing power plant makes a physical or operational change. The supplemental proposal was issued three weeks after the U.S. Supreme Court issued a unanimous opinion in Environmental Defense v. Duke Energy that the EPA was correct in applying an annual emissions test to determine NSR compliance.

Refer to Note 18 of our Notes to audited Consolidated Financial Statements included in the ‘‘Financial Statements’’ section of this prospectus for additional information regarding commitments and litigation related to air quality standards.

The renewable portfolio standards, or RPS, described below could significantly impact our financial results. Resources that meet the qualifying electricity requirements under the RPS vary from state-to-state. Each state’s RPS requires some form of compliance reporting and we can be subject to penalties in the event of non-compliance.

In November 2006, Washington voters approved a ballot initiative establishing a RPS requirement for qualifying electric utilities, including PacifiCorp. The requirements are 3% of retail sales by January 1, 2012 through 2015, 9% of retail sales by January 1, 2016 through 2019 and 15% of retail sales by January 1, 2020. The WUTC has adopted final rules to implement the initiative. We expect to be able to recover our costs of complying with the RPS, either through rate cases or an adjustment mechanism.

In June 2007, the Oregon Renewable Energy Act, or the OREA, was adopted, providing a comprehensive renewable energy policy for Oregon. Subject to certain exemptions and cost limitations established in the OREA, PacifiCorp and other qualifying electric utilities must meet minimum qualifying electricity requirements for electricity sold to retail customers of at least 5% in 2011 through 2014, 15% in 2015 through 2019, 20% in 2020 through 2024, and 25% in 2025 and subsequent years. As required by the OREA, the OPUC has approved an automatic adjustment clause to allow an electric utility, including PacifiCorp, to recover prudently incurred costs of its investments in renewable energy facilities and associated transmission costs. The OPUC and the Oregon Department of Energy have undertaken additional rulemaking proceedings to further implement the initiative. We expect to be able to recover our costs of complying with the RPS through the automatic adjustment mechanism.

California law requires electric utilities to increase their procurement of renewable resources by at least 1% of their annual retail electricity sales per year so that 20% of their annual electricity sales are procured from renewable resources by no later than December 31, 2010. However, PacifiCorp and other small multi-jurisdictional utilities, or SMJU, are currently awaiting further guidance from the CPUC on the treatment of SMJUs in the California RPS program. PacifiCorp has filed comments requesting SMJU rules for flexible compliance with annual targets. PacifiCorp expects rules governing the treatment of SMJUs and any specific flexible compliance mechanisms to be released by CPUC staff for public review in early 2008. Absent further direction from the CPUC on treatment of SMJUs, we cannot predict the impact of the California RPS on our financial results.

In March 2008, Utah’s governor signed Utah Senate Bill 202, ‘‘Energy Resource and Carbon Emission Reduction Initiative;’’ legislation supported by PacifiCorp. Among other things, this provides that, beginning in the year 2025, 20% of adjusted retail electric sales of all Utah utilities be supplied by renewable energy, if it is cost effective. Retail electric sales will be adjusted by deducting the amount of generation from sources that produce zero or reduced carbon emissions, and for sales avoided as a result of energy efficiency and demand-side management programs. Qualifying renewable energy sources can be located anywhere in the Western Electricity Coordinating Council areas, and renewable energy credits can be used. The costs of complying with the law will be a system cost and are expected to be recovered in retail rates in all states served, either through rate cases or adjustment mechanisms.

As a result of increased attention to global climate change in the United States, numerous bills have been introduced in the current session of the United States Congress that would reduce greenhouse gas emissions in the United States. Congressional leadership has made climate change legislation a priority, and many congressional observers expect to see the passage of climate change legislation within the next several years. The Lieberman-Warner Climate Security Act of 2007 (S. 2191), was passed by the United States Senate Environment and Public Works Committee on December 5, 2007. The bill would impose an economy-wide cap on greenhouse gas emissions to reduce emissions 70% from 2005 levels by 2050. Included within the bill’s definition of a covered facility is any facility that uses more than 5,000 tons of coal in a calendar year, which includes all of PacifiCorp’s and MidAmerican Energy’s coal-fired generating plants. In addition, nongovernmental organizations have become more active in initiating citizen suits under existing environmental and other laws. In April 2007, a United States Supreme Court decision concluded that the EPA has the authority under the Clean Air Act to regulate emissions of greenhouse gases from motor vehicles. Furthermore, pending cases that address the potential public nuisance from greenhouse gas emissions from electricity generators and the EPA’s failure to regulate greenhouse gas emissions from new and existing coal-fired plants are expected to become active. While debate continues at the national level over the direction of domestic climate policy, several states have developed state-specific laws or regional legislative initiatives to reduce greenhouse gas emissions, including:

PacifiCorp and MidAmerican Energy continue to add renewable electricity capacity to their generation portfolios. In addition, PacifiCorp and MidAmerican Energy have engaged in several voluntary programs designed to either reduce or avoid greenhouse gas emissions, including the EPA’s sulfur hexafluoride reduction program, refrigerator recycling programs, and the EPA landfill methane outreach program. PacifiCorp is a member of the California Climate Action Registry and The Climate Registry, under which it reports and certifies its greenhouse gas emissions. MidAmerican Energy and Northern Natural Gas are also founding members of The Climate Registry and will report their greenhouse gas emissions.

The impact of any pending judicial proceedings and any pending or enacted federal and state climate change legislation and regulation cannot be determined at this time; however, adoption of stringent limits on greenhouse gas emissions could significantly adversely impact our current and future fossil-fueled facilities, and, therefore, our financial results.

The Clean Water Act establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the ‘‘best technology available for minimizing adverse environmental impact’’ to aquatic organisms. In July 2004, the EPA established significant new national technology-based performance standards for existing electric generating facilities that take in more than 50 million gallons of water a day. These rules are aimed at minimizing the adverse environmental impacts of cooling water intake structures by reducing the number of aquatic organisms lost as a result of water withdrawals. In response to a legal challenge to the rule, in January 2007, the Second Circuit Court of Appeals remanded almost all aspects of the rule to the EPA, leaving companies with cooling water intake structures uncertain regarding compliance with these requirements. Petitions for certiorari were granted by the U.S. Supreme Court regarding the Second Circuit’s decision to remand the rule to the EPA. The Supreme Court will consider whether §316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining ‘‘best technology available for minimizing adverse environmental impact’’ at cooling water intake structures. Compliance and the potential costs of compliance, therefore, cannot be ascertained until such time as the Supreme Court’s decision is rendered or further action is taken by the EPA. Currently, PacifiCorp’s Dave Johnston Plant and all of MidAmerican Energy’s coal-fired generating facilities, except Louisa, Ottumwa and Walter Scott, Jr. Unit 4, which have water cooling towers, exceed the 50 million gallons of water per day in-take threshold. In the event that PacifiCorp’s or MidAmerican Energy’s existing intake structures require modification or alternative technology is required by new rules, expenditures to comply with these requirements could be significant.

Our energy properties consist of the physical assets necessary and appropriate to generate, transmit, store, distribute and supply energy and consist mainly of electric generation, transmission and distribution facilities and gas distribution plants, natural gas pipelines, storage facilities, compressor stations and meter stations, along with the related rights-of-way. It is the opinion of management that the principal depreciable properties owned by us are in good operating condition and are well maintained. Pursuant to separate financing agreements, substantially all or most of the properties of each of our subsidiaries (except CE Electric UK, all of MidAmerican Energy’s gas and non-Iowa electric utility properties and Northern Natural Gas) are pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. For additional information regarding our energy properties, refer to the ‘‘Business’’ section of this prospectus and Notes 3 and 12 of our Notes to unaudited interim Consolidated Financial Statements and Notes 4 and 23 of our Notes to audited Consolidated Financial Statements included in the ‘‘Financial Statements’’ section of this prospectus.

The right to construct and operate our electric transmission and distribution facilities and pipelines across certain property was obtained in most circumstances through negotiations and, where necessary, through the exercise of the power of eminent domain. PacifiCorp, MidAmerican Energy, Northern Natural Gas and Kern River in the United States and Northern Electric and Yorkshire Electricity in the United Kingdom continue to have the power of eminent domain in each of the jurisdictions in which they operate their respective facilities, but the United States utilities do not have the power of eminent domain with respect to Native American tribal lands. Although the main Kern River pipeline crosses the Moapa Indian Reservation, all facilities in the Moapa Indian Reservation are located within a utility corridor that is reserved to the United States Department of Interior, Bureau of Land Management, with whom Kern River has a right of way grant.

With respect to real property, each of the electric transmission and distribution facilities and pipelines fall into two basic categories: (1) parcels that are owned in fee, such as certain of the generation stations, electric substations, compressor stations, measurement stations and office sites; and (2) parcels where the interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction, operation and maintenance of the electric transmission and distribution facilities and pipelines. We believe that each of our subsidiaries and joint ventures have satisfactory title to or have the right to use all of the real property making up their respective facilities in all material respects.

In addition to the proceedings described below, we are currently party to various items of litigation or arbitration in the normal course of business, none of which are reasonably expected by us to have a material adverse effect on our consolidated financial results.

In December 2007, PacifiCorp was served with a complaint filed in the United States District Court for the Northern District of California by the Klamath Riverkeeper (a local environmental group), individual Karuk and Yurok Tribe members and a resort owner. The complaint alleged that reservoirs behind the hydroelectric dams that PacifiCorp operates on the Klamath River provide an environment for the growth of a blue-green algae known as microcystis aeruginosa, which can generate a toxin called microcystin. The complaint alleged that such algae is a ‘‘solid waste’’ under the federal Resource Conservation and Recovery Act, that PacifiCorp ‘‘generates’’ and ‘‘stores’’ such algae in its reservoirs, that PacifiCorp ‘‘disposes’’ of such algae when it passes through the dams, and that such ‘‘generation,’’ ‘‘storage’’ and ‘‘disposal’’ causes or threatens to cause an imminent and substantial endangerment to health and the environment. PacifiCorp believed the claims to be without merit and filed a motion to dismiss in December 2007. In March 2008, the court dismissed the complaint following plaintiffs’ failure to agree to the court’s conditions for combining this case with the May 2007 case described below.

In May 2007, PacifiCorp was served with a complaint filed in the United States District Court for the Northern District of California by individual Karuk and Yurok Tribe members, a commercial fisherman, a resort owner and the Klamath Riverkeeper. The complaint similarly alleges that microcystis aeruginosa causes the plaintiffs physical, property and economic harm. Plaintiffs allege seven causes of action based on nuisance, trespass, negligence, and unlawful business practices, all under California law. Elevated concentrations of microcystis aeruginosa (blue-green algae), which can generate a toxin called microcystin, have been identified in Klamath River hydroelectric project reservoirs, and now farther downstream on the Klamath River. The algae occur naturally across Oregon, California, and throughout the world. Elevated concentrations tend to appear in areas of slack water that is relatively warm. It has been identified for years on Klamath Lake. Plaintiffs seek unspecified damages and injunctive relief; however, in an order filed by the court in August 2007, the court dismissed plaintiffs’ claims for injunctive relief based on federal preemption under the Federal Power Act. In March 2008, one of the Yurok Tribe members voluntarily dismissed his claims in the case, and in April 2008, the court entered a stipulation and order dismissing plaintiff Klamath Riverkeeper’s claims, with prejudice. The remaining plaintiffs and PacifiCorp are currently engaged in discovery. PacifiCorp denies the allegations and is vigorously defending the case.

In May 2004, PacifiCorp was served with a complaint filed in the United States District Court for the District of Oregon by the Klamath Tribes of Oregon, individual Klamath Tribal members and the Klamath Claims Committee. The complaint generally alleges that PacifiCorp and its predecessors affected the Klamath Tribes’ federal treaty rights to fish for salmon in the headwaters of the Klamath River in southern Oregon by building dams that blocked the passage of salmon upstream to the headwaters beginning in 1911. In September 2004, the Klamath Tribes filed their first amended complaint adding claims of damage to their treaty rights to fish for sucker and steelhead in the headwaters of the Klamath River. The complaint seeks in excess of $1.0 billion in compensatory and punitive damages. In July 2005, the District Court dismissed the case and in September 2005 denied the Klamath Tribes’ request to reconsider the dismissal. In October 2005, the Klamath Tribes appealed the District Court’s decision to the United States Court of Appeals for the Ninth Circuit, or the Ninth Circuit, and briefing was completed in March 2006. In February 2008, a three-judge panel of the Ninth Circuit affirmed the District Court’s 2005 decisions dismissing the case. The plaintiffs may seek rehearing before a larger panel on the Ninth Circuit or appeal to the U.S. Supreme Court. PacifiCorp believes the outcome of this proceeding will not have a material impact on its consolidated financial results.

In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in the federal district court in Cheyenne, Wyoming, alleging violations of the Wyoming state opacity standards at PacifiCorp’s Jim Bridger plant in Wyoming. Under Wyoming state requirements, which are part of the Jim Bridger plant’s Title V permit and are enforceable by private citizens under the federal Clean Air Act, a potential source of pollutants such as a coal-fired generating facility must meet minimum standards for opacity, which is a measurement of light that is obscured in the flue of a generating facility. The complaint alleges thousands of violations of six-minute compliance periods and seeks an injunction ordering the Jim Bridger plant’s compliance with opacity limits, civil penalties of $32,500 per day per violation, and the plaintiffs’ costs of litigation. The court granted a motion to bifurcate the trial into separate liability and remedy phases. In March 2008, the court indefinitely postponed the date for the liability-phase trial. It is not known when the court will reschedule the liability-phase trial. The remedy-phase trial has not yet been scheduled. The court also has before it a number of motions on which it has not yet ruled. PacifiCorp believes it has a number of defenses to the claims. PacifiCorp intends to vigorously oppose the lawsuit but cannot predict its outcome at this time. PacifiCorp has already committed to invest at least $812 million in pollution control equipment at its generating facilities, including the Jim Bridger plant. This commitment is expected to significantly reduce system-wide emissions, including emissions at the Jim Bridger plant.

On December 28, 2004, an apparent gas explosion and fire resulted in three fatalities, one serious injury and property damage at a commercial building in Ramsey, Minnesota. According to the Minnesota Office of Pipeline Safety, an improper installation of a pipeline connection may have been a cause of the explosion and fire. A predecessor company to MidAmerican Energy provided gas service in Ramsey, Minnesota, at the time of the original installation in 1980. In 1993, a predecessor of CenterPoint Energy, Inc., or CenterPoint, acquired all of the Minnesota gas properties owned by the MidAmerican Energy predecessor company. All of the wrongful death, personal injury and property damage claims arising from this incident have been settled by CenterPoint.

Two lawsuits naming MidAmerican Energy as a third party defendant filed by CenterPoint in the U.S. District Court, District of Minnesota, related to this incident have also been settled. CenterPoint sought reimbursement of all sums associated with its replacement of all service lines in the MidAmerican Energy predecessor company’s properties located in Minnesota at a cost of approximately $39 million according to publicly available reports. MidAmerican Energy made immaterial payments to CenterPoint and its insurer, and the court dismissed the complaints in March 2008.

In 1998, the United States Department of Justice informed the then current owners of Northern Natural Gas and Kern River 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 Northern Natural Gas and Kern River. 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 October 21, 1999, the Panel on Multi-District Litigation transferred the claims to the United States District Court for the District of Wyoming for pre-trial purposes. Motions to dismiss based on various jurisdictional grounds were filed on June 4, 2004. On May 17, 2005, Northern Natural Gas and Kern River each received a Special Master’s Report and Recommendations which recommended that the action be dismissed for lack of subject matter jurisdiction. On October 20, 2006, the United States District Court for the District of Wyoming affirmed the Special Master’s Report and Recommendations and dismissed Grynberg’s complaint as to all defendants. On November 16, 2006, Grynberg filed 74 separate notices of appeal. In accordance with case management orders issued by the Court of Appeals for the Tenth Circuit, initial appellate briefs were filed by the parties in the second half of 2007 with additional briefs to be filed during the first half of 2008. Oral argument is scheduled for the week of September 22, 2008. In connection with

the purchase of Kern River from The Williams Companies, Inc., or Williams, in 2002, Williams agreed to indemnify us against any liability for this claim; however, no assurance can be given as to the ability of Williams to perform on this indemnity should it become necessary. No such indemnification was obtained in connection with the purchase of Northern Natural Gas in 2002. We believe that the Grynberg cases filed against Northern Natural Gas and Kern River 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 and believe that the ultimate outcome of the Grynberg cases will not have a material impact on their financial results.

On June 8, 2001, Northern Natural Gas, Kern River and other pipeline companies, were named as defendants in a nationwide class action in the 26th Judicial District, District Court, Stevens County Kansas, Civil Department. 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. With court approval, the plaintiffs filed a fourth amended petition alleging a class of gas royalty owners in Kansas, Colorado and Wyoming on July 28, 2003. Kern River was not a named defendant in the amended petition and has been dismissed from the action. Northern Natural Gas filed an answer to the fourth amended petition on August 22, 2003. After fully briefing the class certification issue, on November 9, 2006, the plaintiffs filed a request for a new briefing schedule on class certification in light of a new Kansas Supreme Court case on class actions which remanded the case because the trial court failed to engage in properly rigorous analysis of class certification and choice of law issues. On July 31, 2007, both the plaintiffs and Northern Natural Gas, as one of the coordinated defendants, filed their proposed findings of fact and conclusions of law regarding class certification. Northern Natural Gas believes that this claim is without merit and intends to defend these actions vigorously and believes that the ultimate outcome will not have a material impact on its financial results.

Similar to the June 8, 2001 matter referenced above, the plaintiffs in that matter filed a new companion action on May 12, 2003 against Northern Natural Gas and other parties, but excluding Kern River, in a Kansas state district court for damages for mismeasurement of British thermal unit content, resulting in lower royalties. After fully briefing the class certification issue, on November 9, 2006, the plaintiffs filed a request for a new briefing schedule on class certification in light of a new Kansas Supreme Court case on class actions which remanded the case because the trial court failed to engage in properly rigorous analysis of class certification and choice of law issues. On July 31, 2007, both the plaintiffs and Northern Natural Gas, as one of the coordinated defendants, filed their proposed findings of fact and conclusions of law regarding class certification. Northern Natural Gas believes that this claim is without merit and intends to defend these actions vigorously and believes that the ultimate outcome will not have a material impact on its financial results.

Pursuant to the share ownership adjustment mechanism in the CE Casecnan shareholder agreement, which is based upon proforma financial projections of the Casecnan Project prepared following commencement of commercial operations, in February 2002, our indirect wholly owned subsidiary, CE Casecnan Ltd., advised the minority shareholder of CE Casecnan, LaPrairie Group Contractors (International) Ltd., or LPG, that our indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. On July 8, 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco against CE Casecnan Ltd. and us. LPG’s complaint, as amended, seeks compensatory and punitive damages arising out of CE Casecnan Ltd.’s and our alleged improper calculation of the proforma financial projections and alleged improper settlement of the NIA arbitration.

and a written decision was issued on February 4, 2008 specifying the method for determining LPG’s buy-up price. A hearing was held on May 9, 2008 regarding the inclusion of certain tax considerations in the calculation of the buy-up price. The court has taken the matter under advisement and has not issued a decision. LPG waived its request for a jury trial for the breach of fiduciary duty claim and the parties have entered into a stipulation which provides for a trial of such claim by the court based on the existing record of the case. The trial was held on April 23, 2008. The court took the matter under advisement and requested further briefs from the parties on the burden of proof to be applied. We intend to vigorously defend and pursue the remaining claims.

In February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc., or San Lorenzo, an original shareholder substantially all of whose shares in CE Casecnan were purchased by us in 1998, threatened to initiate legal action against us in the Philippines in connection with certain aspects of its option to repurchase such shares. We believe that San Lorenzo has no valid basis for any claim and, if named as a defendant in any action that may be commenced by San Lorenzo, we will vigorously defend such action. On July 1, 2005, we and CE Casecnan Ltd. commenced an action against San Lorenzo in the District Court of Douglas County, Nebraska, seeking a declaratory judgment as to our and CE Casecnan Ltd.’s rights vis-à-vis San Lorenzo in respect of such shares. San Lorenzo filed a motion to dismiss on September 19, 2005. Subsequently, San Lorenzo purported to exercise its option to repurchase such shares. On January 30, 2006, San Lorenzo filed a counterclaim against us and CE Casecnan Ltd. seeking declaratory relief that it has effectively exercised its option to purchase 15% of the shares of CE Cascenan, that it is the rightful owner of such shares and that it is due all dividends paid on such shares. On March 9, 2006, the court granted San Lorenzo’s motion to dismiss, but has since permitted us and CE Casecnan Ltd. to file an amended complaint incorporating the purported exercise of the option. The complaint has been amended and the action is proceeding. Currently, the action is in the discovery phase and a one-week trial has been set to begin on November 3, 2008. The impact, if any, of San Lorenzo’s purported exercise of its option and the Nebraska litigation on us cannot be determined at this time. We intend to vigorously defend the counterclaims.

The Board of Directors appoints executive officers annually. There are no family relationships among the executive officers, nor, except as set forth in employment agreements, any arrangements or understandings between any executive officer and any other person pursuant to which the executive officer was appointed. Set forth below is certain information, as of March 31, 2008, with respect to our current directors and executive officers:

DAVID L. SOKOL, 51, Chairman of the Board of Directors and Chief Executive Officer. Mr. Sokol has been the Chief Executive Officer since 1993, the Chairman of the Board of Directors since 1994 and a director since 1991. On March 11, 2008, we announced that Mr. Sokol would relinquish the position of Chief Executive Officer effective April 16, 2008, but would continue to serve as our Chairman of the Board of Directors. Mr. Sokol joined us in 1991.

GREGORY E. ABEL, 45, President and Director. Mr. Abel has been the President and Chief Operating Officer since 1998 and a director since 2000. On March 11, 2008, we announced that Mr. Abel was named our President and Chief Executive Officer effective April 16, 2008, succeeding Mr. Sokol. Mr. Abel joined us in 1992. Mr. Abel is also a director of PacifiCorp.

PATRICK J. GOODMAN, 41, Senior Vice President and Chief Financial Officer since 1999. Mr. Goodman joined us in 1995. Mr. Goodman is also a director of PacifiCorp.

DOUGLAS L. ANDERSON, 50, Senior Vice President, General Counsel and Corporate Secretary since 2001. Mr. Anderson joined us in 1993. Mr. Anderson is also a director of PacifiCorp.

MAUREEN E. SAMMON, 44, Senior Vice President and Chief Administrative Officer since 2007. Ms. Sammon has been employed by MidAmerican Energy and its predecessor companies since 1986 and has held several positions, including Manager of Benefits and Vice President, Human Resources and Insurance.

WARREN E. BUFFETT, 77, Director. Mr. Buffett has been a director of ours since 2000 and has been Chairman of the Board of Directors and Chief Executive Officer of Berkshire Hathaway for more than five years. Mr. Buffett is also a director of The Washington Post Company.

WALTER SCOTT, JR., 76, Director. Mr. Scott has been a director of ours since 1991 and has been Chairman of the Board of Directors of Level 3 Communications, Inc., a successor to certain businesses of Peter Kiewit & Sons’, Inc., for more than five years. Mr. Scott is also a director of Peter Kiewit & Sons’, Inc., Berkshire Hathaway and Valmont Industries, Inc.

MARC D. HAMBURG, 58, Director. Mr. Hamburg has been a director of ours since 2000 and has been Vice President-Chief Financial Officer and Treasurer of Berkshire Hathaway for more than five years.

The audit committee of the Board of Directors is comprised of Mr. Marc D. Hamburg. The Board of Directors has determined that Mr. Hamburg qualifies as an ‘‘audit committee financial expert,’’ as defined by SEC rules, based on his education, experience and background. Based on the standards of the New York Stock Exchange Inc., on which the common stock of our majority owner, Berkshire Hathaway, is listed, our Board of Directors has determined that Mr. Hamburg is not independent because of his employment by Berkshire Hathaway.

We have adopted a code of ethics that applies to our principal executive officer, our principal financial and accounting officer, or persons acting in such capacities, and certain other covered officers. The code of ethics is filed as an exhibit to our Annual Report on Form 10-K for the year ended December 31, 2007.

We believe that the compensation paid to each of our Chairman and Chief Executive Officer, or CEO, our Chief Financial Officer, or CFO, and our three other most highly compensated executive officers, to whom we refer collectively as our Named Executive Officers, or NEOs, should be closely aligned with our overall performance, and each NEO’s contribution to that performance, on both a short- and long-term basis, and that such compensation should be sufficient to attract and retain highly qualified leaders who can create significant value for our organization. Our compensation programs are designed to provide our NEOs with meaningful incentives for superior corporate and individual performance. Performance is evaluated on a subjective basis within the context of both financial and non-financial objectives that we believe contribute to our long-term success, among which are financial strength, customer service, operational excellence, employee commitment and safety, environmental respect and regulatory integrity.

Our Compensation Committee is comprised of Messrs. Warren E. Buffett and Walter Scott, Jr. The Compensation Committee is responsible for the establishment and oversight of our compensation policy. Approval of compensation decisions for our NEOs is made by the Compensation Committee, unless specifically delegated. Although the Compensation Committee reviews each NEO’s complete compensation package at least annually, it has delegated to the CEO and President and Chief Operating Officer, or President, authority to approve off-cycle pay changes, performance awards and participation in other employee benefit plans and programs.

Our criteria for assessing executive performance and determining compensation in any year is inherently subjective and is not based upon specific formulas or weighting of factors. Given the uniqueness of each NEO’s duties, we do not specifically use other companies as benchmarks when establishing our NEOs’ initial compensation. Subsequently, the Compensation Committee reviews peer company data when making annual base salary and incentive recommendations for the CEO and the President. The peer companies for 2007 were American Electric Power Company, Inc., Consolidated Edison, Inc., Dominion Resources, Inc., Duke Energy Corporation, Edison International, Energy Future Holdings Corp. (formerly TXU Corp.), Entergy Corporation, Exelon Corporation, FirstEnergy Corp., FPL Group, Inc., PG&E Corporation, Progress Energy, Inc., Public Service Enterprise Group Incorporated, Sempra Energy, The Southern Company and Xcel Energy Inc.

We determine base salaries for all our NEOs by reviewing our overall performance and each NEO’s performance, the value each NEO brings to us and general labor market conditions. While base salary provides a base level of compensation intended to be competitive with the external market, the annual base salary adjustment for each NEO is determined on a subjective basis after consideration of these factors and is not based on target percentiles or other formal criteria. The CEO makes recommendations regarding the President’s base salary, the CEO and President together make recommendations regarding the other NEOs’ base salaries, and the Compensation Committee must approve all annual merit increases, which take effect on January 1 of each year. The Compensation Committee alone sets our CEO’s base salary. Base salaries for all NEOs increased on average by 2.5% effective January 1, 2007. An increase or decrease in base pay may also result from a promotion or other significant change in a NEO’s responsibilities during the year. Ms. Sammon received a base pay increase in May 2007 when she was appointed our Chief Administrative Officer. There were no other base salary changes for our NEOs during the year after the January 1, 2007 merit increase.

The objective of short-term incentive compensation is to reward the achievement of significant annual corporate goals while also providing NEOs with competitive total cash compensation.

Under our Performance Incentive Plan, or PIP, all NEOs are eligible to earn an annual discretionary cash incentive award, which is determined on a subjective basis and is not based on a specific formula or cap. Awards paid to a NEO under the PIP are based on a variety of measures linked to our overall performance and each NEO’s contribution to that performance. An individual NEO’s performance is measured against defined objectives that commonly include financial measures (e.g., net income and cash flow) and non-financial measures (e.g., customer service, operational excellence, employee commitment and safety, environmental respect and regulatory integrity), as well as the NEO’s response to issues and opportunities that arise during the year. The CEO and President recommend annual incentive awards for the other NEOs to the Compensation Committee prior to the last committee meeting of each year, traditionally held in the fourth quarter. The CEO recommends the annual incentive award for the President, and the Compensation Committee determines the CEO’s award. If approved by the Compensation Committee, awards are paid prior to year-end.

In addition to the annual awards under the PIP, we may grant cash performance awards periodically during the year to one or more NEOs to reward the accomplishment of significant non-recurring tasks or projects. These awards are discretionary and approved by the President, as delegated by the CEO and the Compensation Committee. In 2007, awards were granted to Mr. Anderson and Ms. Sammon in recognition of support provided relative to certain non-routine projects. Although both Messrs. Sokol and Abel are eligible for performance awards, neither has been granted an award in the past five years.

The objective of long-term incentive compensation is to retain NEOs, reward their exceptional performance and motivate them to create long-term, sustainable value. Our current long-term incentive compensation program is cash-based. We have not issued stock options or other forms of equity-based awards since March 2000. All stock options held by Messrs. Sokol and Abel are fully vested.

The MidAmerican Energy Holdings Company Long-Term Incentive Partnership Plan, or LTIP, is designed to retain key employees and to align our interests and the interests of the participating employees. Messrs. Goodman and Anderson and Ms. Sammon, as well as 76 other employees, participate in this plan, while our CEO and President do not. Our LTIP provides for annual awards based upon significant accomplishments by the individual participants and the achievement of the financial and non-financial objectives previously described. The goals are developed with the objective of being attainable with a sustained, focused and concerted effort and are determined and communicated in January of each plan year. Participation is discretionary and is determined by the CEO and President who recommend awards to the Compensation Committee annually in the fourth quarter. Except for limited situations of extraordinary performance, awards are capped at 1.5 times base salary. The value is finalized in the first quarter of the following year. These cash-based awards are subject to mandatory deferral and equal annual vesting over a five-year period starting in the performance year. Participants allocate the value of their deferral accounts among various investment alternatives, which are determined by a vote of all participants. Gains or losses may be incurred based on the investment performance. Participating NEOs may elect to defer all or a part of the award or receive payment in cash after the five-year mandatory deferral and vesting period. Vested balances (including any investment profits or losses thereon) of terminating participants are paid at the time of termination.

The MidAmerican Energy Company Supplemental Retirement Plan for Designated Officers, or SERP, provides additional retirement benefits to participants. We include the SERP as part of the participating NEO’s overall compensation in order to provide a comprehensive, competitive package and as a key retention tool. Messrs. Sokol, Abel and Goodman participate, and the plan is currently closed to any new participants. The SERP provides annual retirement benefits of up to 65% of a participant’s total cash compensation in effect immediately prior to retirement, subject to an annual $1 million maximum retirement benefit. Total cash compensation means (i) the highest amount payable to a participant as monthly base salary during the five years immediately prior to retirement multiplied by 12, plus (ii) the average of the participant’s annual awards under an annual incentive bonus program during the three years immediately prior to the year of retirement and (iii) 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 of Directors. All participating NEOs have met the five-year service requirement under the plan. Mr. Goodman’s SERP benefit will be reduced by the amount of his regular retirement benefit under the MidAmerican Energy Company Retirement Plan and ratably for retirement between ages 55 and 65.

The MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan, or DCP, provides a means for all NEOs to make voluntary deferrals of up to 50% of base salary and 100% of short-term incentive compensation awards. The deferrals and any investment returns grow on a tax-deferred basis. Amounts deferred under the DCP receive a rate of return based on the returns of any combination of eight investment options offered under the DCP and selected by the participant, and the plan allows participants to choose from three forms of distribution. While the plan allows us to make discretionary contributions, we have not made contributions to date. We include the DCP as part of the participating NEO’s overall compensation in order to provide a comprehensive, competitive package.

This benefit provides NEOs with financial planning and tax preparation services. The value of the benefit is included in the NEO’s taxable income. It is offered both as a competitive benefit itself and also to help ensure our NEOs best utilize the other forms of compensation we provide to them.

We provide universal life insurance to Messrs. Sokol, Abel and Goodman, having a death benefit of two times annual base salary during employment, reducing to one times annual base salary in retirement. The value of the benefit is included in the NEO’s taxable income. We include the executive life insurance as part of the participating NEO’s overall compensation in order to provide a comprehensive, competitive package.

Compensation paid under our executive compensation plans has been reported as an expense in our historical Consolidated Financial Statements. We are entitled to a statutory exemption from the deductibility limitations of executive compensation under Section 162(m) of the Internal Revenue Code as we are a non-publicly held affiliate of a consolidated taxpayer, Berkshire Hathaway.

Certain NEOs are entitled to post-termination payments in the event their employment is terminated under certain circumstances. We believe these post-termination payments are an important component of the competitive compensation package we offer to these NEOs.

The Compensation Committee, consisting of Messrs. Buffett and Scott, has reviewed and discussed the Compensation Discussion and Analysis with management and, based on this review and discussion, has recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

The following table sets forth information regarding compensation earned by each of our NEOs during the years indicated:


Name and Principal Position	Year		Base Salary ($)			Bonus⁽¹⁾ ($)			Non-Equity Incentive Plan Compensation⁽²⁾ ($)			Change in Pension Value and Nonqualified Deferred Compensation Earnings⁽³⁾ ($)			All Other Compensation⁽⁴⁾ ($)			Total⁽⁵⁾ ($)
David L. Sokol, Chairman and		2007		$	850,000		$	4,000,000		$	—		$	—		$	213,038		$	5,063,038
Chief Executive Officer⁽⁶⁾		2006			850,000			2,500,000			26,250,000			344,000			281,735			30,225,735
Gregory E. Abel, President⁽⁶⁾		2007			775,000			4,000,000			—			—			370,624			5,145,624
		2006			760,000			2,200,000			26,250,000			234,000			265,386			29,709,386
Patrick J. Goodman, Senior Vice		2007			320,000			889,306			—			51,000			47,868			1,308,174
President and Chief Financial		2006			307,500			1,025,453			—			89,000			51,248			1,473,201
Officer
Douglas L. Anderson, Senior Vice		2007			291,500			788,705			—			20,000			29,372			1,129,577
President and General Counsel		2006			283,000			802,560			—			28,000			45,101			1,158,661
Maureen E. Sammon, Senior Vice		2007			196,659			452,903			—			17,000			20,291			686,853
President and Chief		2006			185,000			434,035			—			29,000			20,207			668,242
Administrative Officer

The following table sets forth information regarding outstanding equity awards held by each of our NEOs at December 31, 2007:

The following table sets forth information regarding stock options exercised by Mr. Abel during the year ended December 31, 2007:

The following table sets forth certain information regarding the defined benefit pension plan accounts held by each of our NEOs at December 31, 2007:

The SERP provides additional retirement benefits to participants. The SERP provides annual retirement benefits up to 65% of a participant’s total cash compensation in effect immediately prior to retirement, subject to an annual $1 million maximum retirement benefit. Total cash compensation means (i) the highest amount payable to a participant as monthly base salary during the five years immediately prior to retirement multiplied by 12, plus (ii) the average of the participant’s awards under an annual incentive bonus program during the three years immediately prior to the year of retirement and (iii) 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 of Directors. Mr. Goodman’s SERP benefit will be reduced by the amount of his regular retirement benefit under the MidAmerican Energy Company Retirement Plan and ratably for retirement between ages 55 and 65. A survivor benefit is payable to a surviving spouse under the SERP. Benefits from the SERP will be paid out of general corporate funds; however, through a Rabbi trust, we maintain life insurance on the participants in amounts expected to be sufficient to fund the after-tax cost of the projected benefits. Deferred compensation is considered part of the salary covered by the SERP.

Under the MidAmerican Energy Company Retirement Plan, each NEO has an account, for record-keeping purposes only, to which credits are allocated annually based upon a percentage of the NEO’s base salary and incentive paid in the plan year. In addition, all balances in the accounts of NEOs earn a fixed rate of interest that is credited annually. The interest rate for a particular year is based on the one-year constant maturity Treasury yield plus seven-tenths of one percentage point. Each NEO is vested in the MidAmerican Energy Company Retirement Plan. At retirement, or other termination of employment, an amount equal to the vested balance then credited to the account is payable to the NEO in the form of a lump sum or an annuity.

The following table sets forth certain information regarding the nonqualified deferred compensation plan accounts held by each of our NEOs at December 31, 2007:

Eligibility for our DCP is restricted to select management and highly compensated employees. The plan provides tax benefits to eligible participants by allowing them to defer compensation on a pretax basis, thus reducing their current taxable income. Deferrals and any investment returns grow

on a tax-deferred basis, thus participants pay no income tax until they receive distributions. The DCP permits participants to make a voluntary deferral of up to 50% of base salary and 100% of short-term incentive compensation awards. All deferrals are net of social security taxes due on that bonus or award. Amounts deferred under the DCP receive a rate of return based on the returns of any combination of eight investment options offered by the plan and selected by the participant. Gains or losses are calculated monthly, and returns are posted to accounts based on participants’ fund allocation elections. Participants can change their fund allocations as of the end of any calendar month.

The DCP allows participants to maintain three accounts based upon when they want to receive payments: retirement distribution, in-service distribution and education distribution. Both the retirement and in-service accounts can be distributed as lump sums or in up to 10 annual installments. The education account is distributed in four annual installments. If a participant leaves employment prior to retirement (age 55) all amounts in the participant’s account will be paid out in a lump sum as soon as administratively practicable. Participants are 100% vested in their deferrals and any investment gains or losses recorded in their accounts.

Participants in our LTIP also have the option of deferring all or a part of those awards after the five-year mandatory deferral and vesting period. The provisions governing the deferral of LTIP awards are similar to those described for the DCP above.

We have entered into employment agreements with Messrs. Sokol, Abel and Goodman that provide for payments following termination of employment under various circumstances, which do not include change-in-control provisions.

Mr. Sokol’s employment will terminate upon his resignation, permanent disability, death, termination by us with or without cause, or our failure to provide Mr. Sokol with the compensation or to maintain the job responsibilities set forth in his employment agreement. A termination of employment of either Messrs. Abel or Goodman will occur upon his resignation (with or without good reason), permanent disability, death, or termination by us with or without cause. The employment agreements for Messrs. Sokol and Abel also include provisions specific to the calculation of their respective SERP benefits.

Neither Mr. Anderson nor Ms. Sammon has an employment agreement. Where a NEO does not have an employment agreement, or in the event that the agreements for Messrs. Sokol, Abel and Goodman do not address an issue, payments upon termination are determined by the applicable plan documents and our general employment policies and practices as discussed below.

Mr. Sokol’s employment agreement provides that we may terminate his employment with cause, in which case we must pay him any accrued but unpaid base salary and a bonus of not less than the minimum annual bonus as defined in his employment agreement. If termination is due to death, permanent disability or other than for cause, Mr. Sokol is entitled to receive an amount equal to three times the sum of his annual base salary then in effect and the greater of his minimum annual bonus or his average annual bonus for the two preceding years, plus continuation of his senior executive employee benefits (or the economic equivalent thereof) for three years. If Mr. Sokol resigns, we must pay him any accrued but unpaid base 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.

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 base salary then in effect and the greater of his minimum annual bonus or his average annual bonus for the two preceding years. This total payment as of December 31, 2007 is estimated at $8,200,000 (and is not included in the termination scenarios table below). He will also receive an

annual salary of $750,000 and will be eligible for an annual bonus. Effective April 16, 2008, Mr. Sokol relinquished his position as Chief Executive Officer and a payment approximating the estimated amount was made.

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 (i) any accrued but unpaid base salary plus an amount equal to the aggregate annual base 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 and (ii) the continuation of his senior executive employee benefits (or the economic equivalent thereof) through such fifth anniversary.

Payments made in accordance with the employment agreement are contingent on Mr. Sokol complying with the confidentiality and post-employment restrictions described therein. The term of the agreement expires on August 21, 2009, but is extended automatically for additional one year terms thereafter subject to Mr. Sokol’s election to decline renewal at least 120 days prior to the then current expiration date or termination.

The following table sets forth the estimated enhancements to payments pursuant to the termination scenarios described above. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) account balances and those portions of life insurance benefits and cash balance pension amounts that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 2007, and are payable as lump sums unless otherwise noted.

Mr. Abel’s employment agreement entitles him to receive two years base salary continuation and payments in respect of average bonuses for the prior two years in the event we terminate his employment other than for cause. The payments are to be paid as a lump sum with no discount for present valuation.

In addition, if Mr. Abel’s employment is terminated due to death, permanent disability or other than for cause, he is entitled to continuation of his senior executive employee benefits (or the economic equivalent thereof) for two years. If Mr. Abel resigns, we must pay him any accrued but unpaid base salary, unless he resigns for good reason, in which case he will receive the same benefits as if he were terminated other than for cause.

Payments made in accordance with the employment agreement are contingent on Mr. Abel complying with the confidentiality and post-employment restrictions described therein. The term of the agreement effectively expires on August 6, 2012, and is extended automatically for additional one year terms thereafter subject to Mr. Abel’s election to decline renewal at least 365 days prior to the August 6 that is four years prior to the current expiration date (or by August 6, 2008 for the agreement not to extend to August 6, 2013).

The following table sets forth the estimated enhancements to payments pursuant to the termination scenarios indicated. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) and nonqualified deferred compensation account balances and those portions of life insurance benefits and cash balance pension amounts that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 2007, and are payable as lump sums unless otherwise noted.

Mr. Goodman’s employment agreement entitles him to receive two years base salary continuation and payments in respect of average bonuses for the prior two years in the event we terminate his employment other than for cause. The payments are to be paid as a lump sum with no discount for present valuation.

In addition, if Mr. Goodman’s employment is terminated due to death, permanent disability or other than for cause, he is entitled to continuation of his senior executive employee benefits (or the economic equivalent thereof) for one year. If Mr. Goodman resigns, we must pay him any accrued but unpaid base salary, unless he resigns for good reason, in which case he will receive the same benefits as if he were terminated other than for cause.

Payments made in accordance with the employment agreement are contingent on Mr. Goodman complying with the confidentiality and post-employment restrictions described therein. The term of the agreement expires on April 21, 2009, but is extended automatically for additional one year terms thereafter subject to Mr. Goodman’s election to decline renewal at least 365 days prior to the then current expiration date or termination.

The following table sets forth the estimated enhancements to payments pursuant to the termination scenarios indicated. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) and nonqualified deferred compensation account balances and those portions of long-term incentive payments, life insurance benefits and cash balance pension amounts that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 2007, and are payable as lump sums unless otherwise noted.

The following table sets forth the estimated enhancements to payments pursuant to the termination scenarios indicated. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) and nonqualified deferred compensation account balances and those portions of long-term incentive payments and cash balance pension amounts that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 2007, and are payable as lump sums unless otherwise noted.

Our directors are not paid any fees for serving as directors. All directors are reimbursed for their expenses incurred in attending Board of Directors meetings.

Mr. Buffett is the Chairman of the Board of Directors and Chief Executive Officer of Berkshire Hathaway, our majority owner. Mr. Scott is a former officer of ours. Based on the standards of the New York Stock Exchange, Inc. on which the common stock of our majority owner, Berkshire Hathaway, is listed, our Board of Directors has determined that Messrs. Buffett and Scott are not independent because of their ownership of our common stock. None of our executive officers serves

as a member of the compensation committee of any company that has an executive officer serving as a member of our Board of Directors. None of our executive officers serves as a member of the board of directors of any company that has an executive officer serving as a member of our Compensation Committee.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

We are a consolidated subsidiary of Berkshire Hathaway. The remainder of our common stock is owned by a private investor group comprised of Messrs. Scott, Sokol and Abel. The following table sets forth certain information regarding beneficial ownership of our shares of common stock held by each of our directors, executive officers and all of our directors and executive officers as a group as of March 31, 2008:

The following table sets forth certain information regarding beneficial ownership of Class A and Class B shares of Berkshire Hathaway’s common stock held by each of our directors, executive officers and all of our directors and executive officers as a group as of March 31, 2008:


Name and Address of Beneficial Owner⁽¹⁾	Number of Shares Beneficially Owned⁽²⁾		Percentage Of Class⁽²⁾
Walter Scott, Jr.⁽³⁾⁽⁴⁾
Class A		100	*
Class B		—		—
David L. Sokol⁽⁴⁾
Class A		1,162	*
Class B		103	*
Gregory E. Abel⁽⁴⁾
Class A		—		—
Class B		6	*
Douglas L. Anderson
Class A		3	*
Class B		—		—
Warren E. Buffett⁽⁵⁾
Class A		350,000		32.38	%
Class B		2,564,355		18.26	%
Patrick J. Goodman
Class A		2	*
Class B		3	*
Marc D. Hamburg
Class A		—		—
Class B		—		—
Maureen E. Sammon
Class A		—		—
Class B		21	*
All directors and executive officers as a group (8 persons)
Class A		351,267	32.50%
Class B		2,564,488	18.26%

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 nominate two additional directors.

Pursuant to a shareholders agreement, as amended on December 7, 2005, Mr. Scott or any of the Scott Family Interests and Messrs. Sokol and Abel are able to require Berkshire Hathaway to exchange any or all of their respective shares of our common stock for shares of Berkshire Hathaway common stock. The number of shares of Berkshire Hathaway stock to be exchanged is based on the fair market value of our common stock divided by the closing price of the Berkshire Hathaway stock on the day prior to the date of exchange.

The Berkshire Hathaway Inc. Code of Business Conduct and Ethics and the MEHC Code of Business Conduct, or the Codes, which apply to all of our directors, officers and employees and those of our subsidiaries, generally govern the review, approval or ratification of any related-person transaction. A related-person transaction is one in which we or any of our subsidiaries participate and in which one or more of our directors, executive officers, holders of more than five percent of our voting securities or any of such persons’ immediate family members have a direct or indirect material interest.

Under the Codes, all of our directors and executive officers (including those of our subsidiaries) must disclose to our legal department any material transaction or relationship that reasonably could be expected to give rise to a conflict with our interests. No action may be taken with respect to such transaction or relationship until approved by the legal department. For our chief executive officer and chief financial officer, prior approval for any such transaction or relationship must be given by Berkshire Hathaway’s audit committee. In addition, prior legal department approval must be obtained before a director or executive officer can accept employment, offices or board positions in other for-profit businesses, or engage in his or her own business that raises a potential conflict or appearance of conflict with our interests. Transactions with Berkshire Hathaway require the approval of our Board of Directors.

Under a subscription agreement with us, which expired in March 2007, Berkshire Hathaway had agreed to purchase, under certain circumstances, additional shares of 11% trust issued mandatorily redeemable preferred securities to be issued by our wholly owned subsidiary trust in the event that certain of our other outstanding trust preferred securities, which were outstanding prior to the closing of our acquisition by a private investor group on March 14, 2000, were tendered for conversion to cash by the current holders.

At March 31, 2008 and December 31, 2007, Berkshire Hathaway and its affiliates held 11% mandatorily redeemable preferred securities due from certain of our wholly owned subsidiary trusts with liquidation preferences of $821 million. Interest expense on these securities totaled $23 million for the three-month period ended March 31, 2008. Principal repayments and interest expense on these securities totaled $234 million and $108 million, respectively, during 2007.

On November 12, 2007, we issued 370,000 shares of our common stock, no par value, to Mr. Abel upon the exercise by Mr. Abel of 370,000 of his outstanding common stock options. The common stock options were exercisable at a weighted-average price of $26.99 per share and the aggregate exercise price paid by Mr. Abel was $10 million. This issuance was pursuant to a private placement and was exempt from the registration requirements of the Securities Act of 1933, as amended.

Based on the standards of the New York Stock Exchange, Inc., on which the common stock of our majority owner, Berkshire Hathaway, is listed, our Board of Directors has determined that none of our directors are considered independent because of their employment by Berkshire Hathaway or us or their ownership of our common stock.

The initial notes were, and the exchange notes will be, issued pursuant to a supplemental indenture to the indenture, dated as of October 4, 2002, as amended to date, between us and The Bank of New York, as trustee. The term ‘‘indenture’’ when used in this prospectus will refer to the indenture as amended by all supplemental indentures executed and delivered on or prior to the date on which the notes are issued and sold. The terms of the notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended.

On October 4, 2002, we issued $200,000,000 of our 4.625% Senior Notes due 2007 (hereafter referred to as the series A notes) and $500,000,000 of our 5.875% Senior Notes due 2012 (hereafter referred to as the series B notes); on May 16, 2003, we issued $450,000,000 of our 3.50% Senior Notes due 2008 (hereafter referred to as the series C notes); on February 12, 2004, we issued $250,000,000 of our 5.00% Senior Notes due 2014 (hereafter referred to as the series D notes); on March 24, 2006, we issued $1,700,000,000 of our 6.125% Senior Bonds due 2036 (hereafter referred to as the series E bonds); on May 11, 2007, we issued $550,000,000 of our 5.95% Senior Bonds due 2037 (hereafter referred to as the series F bonds); and on August 28, 2007, we issued $1,000,000,000 of our 6.50% Senior Bonds due 2037 (hereafter referred to as the series G bonds), in each case pursuant to the indenture. The series A notes and the series C notes have been repaid in full. Unless otherwise indicated, references hereafter to the securities in this prospectus include the series B notes, the series D notes, the series E bonds, the series F bonds, the series G bonds and the notes (and any other series of notes, bonds or other securities hereafter issued under a supplemental indenture or otherwise pursuant to the indenture), except that any references to ‘‘securities’’ in this prospectus, to the extent related to a determination of whether a ‘‘Change of Control’’ has occurred (and the related definitions), refer only to the notes and the series E bonds, the series F bonds and the series G bonds. The principal difference between the Change of Control provisions for the notes and the series E, F and G bonds and the comparable provisions for all other series of securities issued under the indenture relates to the definition of the applicable ‘‘Rating Decline.’’

The following description is a summary of the material provisions of the indenture and the related registration rights agreement. It does not restate those agreements in their entirety. We urge you to read the indenture and the registration rights agreement because they, and not this description, define your rights as a holder of the notes. The definitions of certain capitalized terms used in the following summary are set forth below under ‘‘— Definitions.’’

The indenture does not limit the aggregate principal amount of the debt securities that may be issued thereunder and provides that debt securities may be issued from time to time in one or more series.

The initial notes were initially offered in the aggregate principal amount of $650,000,000. We may, without the consent of the holders, increase such principal amount in the future on the same terms and conditions (except for the issue date and issue price) and with the same CUSIP number(s) as the notes.

The initial notes were, and the exchange notes will be, issued in one series, will bear interest at the rate of 5.75% per annum and will mature on April 1, 2018. Interest on the notes is payable semi-annually in arrears on each April 1 and October 1, commencing October 1, 2008, to the holders thereof at the close of business on the preceding March 15 and September 15, respectively. Interest on the notes will be computed on the basis of a 360-day year of twelve 30-day months.

The initial notes were, and the exchange notes will be, issued without coupons and in fully registered form only in denominations of $2,000 and any integral multiple of $1,000 in excess thereof.

MEHC files certain reports and other information with the SEC in accordance with the requirements of Sections 13 and 15(d) under the Exchange Act. See ‘‘Where You Can Find More Information.’’ In addition, at any time that Sections 13 and 15(d) cease to apply to MEHC, we will covenant, and have covenanted in the indenture to file comparable reports and information with the

trustee and the SEC, and mail such reports and information to holders of securities at their registered addresses, for so long as any securities remain outstanding.

If (i) the registration statement of which this prospectus is a part is not declared effective by the SEC within 270 days after the closing date of the offering of the initial notes, (ii) a shelf registration statement with respect to the resale of the notes which is required under the registration rights agreement is not declared effective by the SEC before the later of 150 days after the date our obligation to file such shelf registration statement arises or 270 days after the closing date for the initial notes or (iii) any of the foregoing registration statements (or the prospectuses related thereto) after being declared effective by the SEC cease to be so effective or usable (subject to certain exceptions) in connection with certain resales of the initial notes or exchange notes for the periods specified and in accordance with the registration rights agreement, the interest rate on the notes that are then subject to such cessation or other registration default and qualify as Transfer Restricted Securities will increase by 0.5% from and including the date on which any such event occurs until such event ceases to be continuing. The exchange offer, registration rights and additional interest provisions are more fully described under ‘‘The Exchange Offer.’’

Any initial notes that remain outstanding after the consummation of the exchange offer, together with all exchange notes issued in connection with the exchange offer, will be treated as a single class of securities under the indenture.

The notes will be redeemable in whole or in part, at our option at any time, at a redemption price equal to the greater of:

plus, for (1) or (2) above, whichever is applicable, accrued interest on such notes to the date of redemption.

Notice of redemption shall be given not less than 30 days nor more than 60 days prior to the date of redemption. If fewer than all of the notes are to be redeemed, the selection of the notes for redemption will be made by the trustee pro rata among all outstanding notes.

Unless we default in payment of the Redemption Price (as defined below), from and after the date of redemption the notes or portions of notes called for redemption will cease to bear interest, and the holders of those notes will have no right in respect of those notes except the right to receive the applicable Redemption Price.

Under the procedures described above, the price payable upon the optional redemption at any time of a note (or the Redemption Price) is determined by calculating the present value (or the Present Value) at such time of each remaining payment of principal of or interest on such note and then totaling those Present Values. If the sum of those Present Values is equal to or less than 100% of the principal amount of such note, the Redemption Price of such note will be 100% of its principal amount (redemption at par). If the sum of those Present Values is greater than 100% of the principal amount of such note, the Redemption Price of such note will be such greater amount (redemption at a premium). In no event may a note be redeemed optionally at less than 100% of its principal amount.

The Present Value at any time of a payment of principal of or interest on a note is calculated by applying to such payment the discount rate (or the Discount Rate) applicable to such payment. The

Discount Rate applicable at any time to payment of principal of or interest on a note equals the equivalent yield to maturity at such time of a fixed rate United States treasury security having a maturity comparable to the maturity of such payment plus 35 basis points, such yield being calculated on the basis of the interest rate borne by such United States treasury security and the price at such time of such security. The United States treasury security employed in the calculation of a Discount Rate (or a Relevant Security) as well as the price and equivalent yield to maturity of such Relevant Security will be selected or determined by an Independent Investment Banker.

Whether the sum of the Present Values of the remaining payments of principal of and interest on a note to be redeemed optionally will or will not exceed 100% of its principal amount and, accordingly, whether such note will be redeemed at par or at a premium will depend on the Discount Rate used to calculate such Present Values. Such Discount Rate, in turn, will depend upon the equivalent yield to maturity of a Relevant Security, which yield will itself depend on the interest rate borne by, and the price of, the Relevant Security. While the interest rate borne by the Relevant Security is fixed, the price of the Relevant Security tends to vary with interest rate levels prevailing from time to time. In general, if at a particular time the prevailing level of interest rates for a newly issued United States treasury security having a maturity comparable to that of a Relevant Security is higher than the level of interest rates for newly issued United States treasury securities having a maturity comparable to such Relevant Security prevailing at the time the Relevant Security was issued, the price of the Relevant Security will be lower than its issue price. Conversely, if at a particular time the prevailing level of interest rates for a newly issued United States treasury security having a maturity comparable to that of a Relevant Security is lower than the level of interest rates prevailing for newly issued United States treasury securities having a maturity comparable to the Relevant Security at the time the Relevant Security was issued, the price of the Relevant Security will be higher than its issue price.

Because the equivalent yield to maturity on a Relevant Security depends on the interest rate it bears and its price, an increase or a decrease in the level of interest rates for newly issued United States treasury securities with a maturity comparable to that of a Relevant Security above or below the levels of interest rates for newly issued United States treasury securities having a maturity comparable to the Relevant Security prevailing at the time of issue of the Relevant Security will generally result in an increase or a decrease, respectively, in the Discount Rate used to determine the Present Value of a payment of principal of or interest on a note. An increase or a decrease in the Discount Rate, and therefore an increase or a decrease in the levels of interest rates for newly issued United States treasury securities having a maturity comparable to the Relevant Security, will result in a decrease or an increase, respectively, of the Present Value of a payment of principal of or interest on a note. In other words, the Redemption Price varies inversely with the levels of interest rates for newly issued United States treasury securities having a maturity comparable to the Comparable Treasury Issue. As noted above, however, if the sum of the Present Values of the remaining payments of principal of and interest on a note proposed to be redeemed is less than its principal amount, such note may only be redeemed at par.

The notes are general, unsecured senior obligations of MEHC and will rank pari passu in right of payment with all other existing and future senior unsecured obligations of MEHC (including the series B notes, series D notes, series E bonds, series F bonds and series G bonds) and senior in right of payment to all existing and future subordinated obligations of MEHC. The notes will be effectively subordinated to all existing and future secured obligations of MEHC and to all existing and future obligations of MEHC’s Subsidiaries. At March 31, 2008, MEHC’s outstanding senior indebtedness was approximately $6.12 billion and MEHC’s outstanding subordinated indebtedness, which consists of MEHC’s trust preferred securities, was approximately $1.126 billion. These amounts exclude MEHC’s

guarantees and letters of credit in respect of Subsidiary and equity investment indebtedness aggregating approximately $82 million as of March 31, 2008. MEHC’s Subsidiaries also have significant amounts of indebtedness. At March 31, 2008, MEHC’s consolidated Subsidiaries had outstanding indebtedness totaling approximately $13.19 billion. This amount does not include (i) any trade debt or preferred stock obligations of MEHC’s Subsidiaries, (ii) MEHC’s Subsidiaries’ letters of credit in respect of their indebtedness or (iii) MEHC’s share of the outstanding indebtedness of its and its Subsidiaries’ equity investments.

Except as set forth under ‘‘— Defeasance and Discharge — Covenant Defeasance’’ below, for so long as any securities remain outstanding, we will comply with the terms of the covenants set forth below.

MEHC will not be permitted to pledge, mortgage, hypothecate or permit to exist any pledge, mortgage or other Lien upon any property or assets at any time directly owned by MEHC to secure any indebtedness for money borrowed which is incurred, issued, assumed or guaranteed by MEHC (or Indebtedness for Borrowed Money), without making effective provisions whereby the outstanding securities will be equally and ratably secured with any and all such Indebtedness for Borrowed Money and with any other Indebtedness for Borrowed Money similarly entitled to be equally and ratably secured; provided, however, that this restriction will not apply to or prevent the creation or existence of:

In the event that MEHC proposes to pledge, mortgage or hypothecate or permit to exist any pledge, mortgage or other Lien upon any property or assets at any time directly owned by it to secure any Indebtedness for Borrowed Money, other than as permitted by clauses (1) through (4) of the previous paragraph, MEHC will give prior written notice thereof to the trustee and MEHC will, prior to or simultaneously with such pledge, mortgage or hypothecation, effectively secure all the securities equally and ratably with such Indebtedness for Borrowed Money.

The foregoing covenant will not restrict the ability of our Subsidiaries and affiliates to pledge, mortgage, hypothecate or permit to exist any mortgage, pledge or Lien upon their property or assets, in connection with project financings or otherwise.

So long as any securities are outstanding, MEHC is not permitted to consolidate with or merge with or into any other person, or convey, transfer or lease its consolidated properties and assets substantially as an entirety to any person, or permit any person to merge into or consolidate with MEHC, unless (1) MEHC is the surviving or continuing corporation or the surviving or continuing corporation or purchaser or lessee is a corporation incorporated under the laws of the United States of America, one of the states thereof or the District of Columbia or Canada and assumes MEHC’s obligations under the securities and under the indenture and (2) immediately before and after such transaction, no event of default under the indenture shall have occurred and be continuing.

Except for a sale of the consolidated properties and assets of MEHC substantially as an entirety as provided above, and other than properties or assets required to be sold to conform with laws or governmental regulations, MEHC is not permitted, directly or indirectly, to sell or otherwise dispose of any of its consolidated properties or assets (other than short-term, readily marketable investments purchased for cash management purposes with funds not representing the proceeds of other asset sales) if on a pro forma basis, the aggregate net book value of all such sales during the most recent 12-month period would exceed 10% of Consolidated Net Tangible Assets computed as of the end of the most recent quarter preceding such sale; provided, however, that (1) any such sales shall be disregarded for purposes of this 10% limitation if the net proceeds are invested in properties or assets in similar or related lines of business of MEHC and its Subsidiaries, including, without limitation, any of the lines of business in which MEHC or any of its Subsidiaries is engaged on the date of such sale or disposition, and (2) MEHC may sell or otherwise dispose of consolidated properties and assets in excess of such 10% limitation if the net proceeds from such sales or dispositions, which are not reinvested as provided above, are retained by MEHC as cash or Cash Equivalents or used to retire its Indebtedness for Borrowed Money (other than Indebtedness for Borrowed Money which is subordinated to the securities) and that of its Subsidiaries.

The covenant described immediately above includes a phrase relating to a conveyance, transfer or lease of our consolidated properties and assets ‘‘substantially as an entirety.’’ Although there is a limited body of case law interpreting the phrase ‘‘substantially as an entirety,’’ there is no precise established definition of the phrase under applicable law. Accordingly, the nature and extent of the restriction on our ability to convey, transfer or lease our consolidated properties or assets substantially as an entirety, and the protections provided to the holders of securities by such restriction, may be uncertain.

Upon the occurrence of a Change of Control, each holder of the securities will have the right to require that we repurchase all or any part of such holder’s securities at a purchase price in cash equal to 101% of the principal thereof on the date of purchase plus accrued interest, if any, to the date of purchase.

The Change of Control provisions may not be waived by the trustee or by our board of directors, and any modification thereof must be approved by each holder. Nevertheless, the Change of Control provisions will not necessarily afford protection to holders, including protection against an adverse effect on the value of the securities of any series, including the notes, in the event that we or our Subsidiaries incur additional Debt, whether through recapitalizations or otherwise.

Within 30 days following a Change of Control, we will mail a notice to each holder of the securities with a copy to the trustee, stating the following:

On the Purchase Date, we will (1) accept for payment all securities or portions thereof tendered pursuant to the Change of Control Offer, (2) deposit with the trustee money sufficient to pay the purchase price of all securities or portions thereof so tendered for purchase and (3) deliver or cause to be delivered to the trustee the securities properly tendered together with an officer’s certificate identifying the securities or portions thereof tendered to us for purchase. The trustee will promptly mail, to the holders of the securities properly tendered and purchased, payment in an amount equal to the purchase price, and promptly authenticate and mail to each holder a new security having a principal amount equal to any portion of such holder’s securities that were surrendered but not tendered and purchased. We will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Purchase Date.

If we are prohibited by applicable law from making the Change of Control Offer or purchasing securities of any series, including the notes, thereunder, we need not make a Change of Control Offer pursuant to this covenant for so long as such prohibition is in effect.

We will comply with all applicable tender offer rules, including, without limitation, Rule 14e-1 under the Exchange Act, in connection with a Change of Control Offer.

An event of default with respect to the securities of any series, including the notes, will be defined in the indenture as being any one of the following events:

The indenture provides that the trustee may withhold notice to the holders of any default (except in payment of principal of, premium, if any, or interest on any series of securities and any payment required in connection with a Change of Control) if the trustee considers it in the interest of holders to do so.

The indenture provides that if an event of default with respect to the securities of any series at the time outstanding, including the notes (other than an event of bankruptcy, insolvency or reorganization of MEHC or a Significant Subsidiary) has occurred and is continuing, either the trustee or (i) in the case of any event of default described in clause (1) or (2) above, the holders of at least 33% in aggregate principal amount of the securities of that series then outstanding, or (ii) in the case of any other event of default, the holders of at least a majority in aggregate principal amount of the securities of that series then outstanding, may declare the principal of and any accrued interest on all securities of that series to be due and payable immediately, but upon certain conditions such declaration may be annulled and past defaults (except, unless theretofore cured, a default in payment of principal of, premium, if any, or interest on the securities of that series or any payment required in connection with a Change of Control) may be waived by the holders of a majority in principal amount of the securities of that series then outstanding. If an event of default due to the bankruptcy, insolvency or reorganization of MEHC or a Significant Subsidiary occurs, the indenture provides that the entire principal amount of and any interest accrued on all securities will become immediately due and payable without any action by the trustee, the holders of securities or any other person.

The holders of a majority in principal amount of the securities of any series then outstanding, including the notes, will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the trustee under the indenture with respect to the securities of such series, subject to certain limitations specified in the indenture, provided that the holders of securities of such series must have offered to the trustee reasonable indemnity against expenses and liabilities.

The indenture requires the annual filing by MEHC with the trustee of a written statement as to its knowledge of the existence of any default in the performance and observance of any of the covenants contained in the indenture.

The indenture contains provisions permitting us and the trustee, with the consent of the holders of not less than a majority in principal amount of the outstanding securities of each series affected by the modification, including the notes, to modify the indenture or the rights of the holders of such series, except that no such modification may (1) extend the stated maturity of the principal of or any

installment of interest on the securities, reduce the principal amount thereof or the interest rate thereon, reduce any premium payable on redemption or purchase thereof, impair the right of any holder to institute suit for the enforcement of any such payment on or after the stated maturity thereof or make any change in the covenants regarding a Change of Control or the related definitions without the consent of the holder of each outstanding security so affected, or (2) reduce the percentage of any series of securities, the consent of the holders of which is required for any such modification, without the consent of the holders of all series of securities then outstanding.

The indenture provides that we will be deemed to have paid and will be discharged from any and all obligations in respect of the notes or any other series of securities issued thereunder on the 123rd day after the deposit referred to below has been made (or immediately if an opinion of counsel is delivered to the effect described in clause (B)(3)(y) below), and the provisions of the indenture will cease to be applicable with respect to the securities of such series (except for, among other matters, certain obligations to register the transfer or exchange of the securities of such series, to replace stolen, lost or mutilated securities of such series, to maintain paying agents and to hold monies for payment in trust) if, among other things:

The indenture further provides that the provisions of the covenants described herein under ‘‘— Covenants — Restrictions on Liens,’’ ‘‘— Consolidation, Merger, Conveyance, Sale or Lease’’ and ‘‘— Purchase of Securities Upon a Change of Control,’’ clauses (3) and (4) under ‘‘Events of Default’’ with respect to such covenants, clause (2) under ‘‘Events of Default’’ with respect to offers to purchase upon a Change of Control as described above and clauses (5) and (6) under ‘‘Events of Default’’ will cease to be applicable to us and our Subsidiaries upon the satisfaction of the provisions described in clauses (A), (B), (C) and (D) of the preceding paragraph; provided, however, that with respect to such covenant defeasance, the opinion of counsel described in clause (B)(1)(x) above need not be based upon any ruling of the IRS or change in applicable federal income tax law or related Treasury regulations.

If we exercise our option to omit compliance with certain covenants and provisions of the indenture with respect to the securities of any series, including the notes, as described in the immediately preceding paragraph and any series of securities is declared due and payable because of the occurrence of an event of default that remains applicable, the amount of money and/or U.S. Government Obligations on deposit with the trustee will be sufficient to pay amounts due on such securities at the time of their stated maturity or scheduled redemption, but may not be sufficient to pay amounts due on such securities at the time of acceleration resulting from such event of default. MEHC will remain liable for such payments.

The indenture and the securities will be governed by, and construed in accordance with, the law of the State of New York, including Section 5-1401 of the New York General Obligations Law, but otherwise without regard to conflict of laws rules.

The Bank of New York Trust Company, N.A. is the trustee under the indenture. The Bank of New York Trust Company, N.A. (or one of its affiliates) currently serves, and may in the future serve, as trustee under indentures evidencing other indebtedness of MEHC and its affiliates. The Bank of New York Trust Company, N.A. (or one of its affiliates) is also, and may in the future be, a lender under credit facilities for MEHC and its affiliates.

Set forth below is a summary of certain of the defined terms used in the covenants and other provisions of the indenture. Reference is made to the indenture for the full definitions of all such terms as well as any other capitalized terms used herein for which no definition is provided.

‘‘Attributable Value’’ means, as to a Capitalized Lease Obligation under which any person is at the time liable and at any date as of which the amount thereof is to be determined, the capitalized amount thereof that would appear on the face of a balance sheet of such person in accordance with GAAP.

‘‘Berkshire Hathaway’’ means Berkshire Hathaway Inc. and any Subsidiary of Berkshire Hathaway Inc.

‘‘Capital Stock’’ means, with respect to any person, any and all shares, interests, participations or other equivalents (however designated, whether voting or non-voting) in, or interests (however designated) in, the equity of such person that is outstanding or issued on or after the date of the indenture, including, without limitation, all common stock and preferred stock and partnership and joint venture interests in such person.

‘‘Capitalized Lease’’ means, as applied to any person, any lease of any property of which the discounted present value of the rental obligations of such person as lessee, in conformity with GAAP, is required to be capitalized on the balance sheet of such person, and ‘‘Capitalized Lease Obligation’’ means the rental obligations, as aforesaid, under any such lease.

‘‘Change of Control’’ means the occurrence of one or more of the following events:

provided that with respect to the foregoing subparagraphs (1) and (2), a Change of Control will not be deemed to have occurred unless and until a Rating Decline has occurred as well.

‘‘Comparable Treasury Issue’’ means the United States Treasury security selected by an Independent Investment Banker as having a maturity comparable to the remaining term of securities of any series to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of such securities.

‘‘Comparable Treasury Price’’ means, with respect to any Redemption Date, (1) the average of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) on the third business day preceding such Redemption Date, as set forth in the daily statistical release (or any successor release) published by the Federal Reserve Bank of New York and designated ‘‘Composite 3:30 p.m. Quotations for U.S. Government Securities’’ or (2) if such release (or any successor release) is not published or does not contain such prices on such business day, the Reference Treasury Dealer Quotation for such Redemption Date.

‘‘Consolidated Net Tangible Assets’’ means, as of the date of any determination thereof, the total amount of all of the assets of MEHC determined on a consolidated basis in accordance with GAAP as of such date less the sum of (a) the consolidated current liabilities of MEHC determined in accordance with GAAP and (b) assets properly classified as Intangible Assets.

‘‘Currency Protection Agreement’’ means, with respect to any person, any foreign exchange contract, currency swap agreement or other similar agreement or arrangement intended to protect such person against fluctuations in currency values to or under which such person is a party or a beneficiary on the date of the indenture or becomes a party or a beneficiary thereafter.

‘‘Debt’’ means, with respect to any person, at any date of determination (without duplication):

For purposes of determining any particular amount of Debt that is or would be outstanding, Guarantees of, or obligations with respect to letters of credit or similar instruments supporting (to the extent the foregoing constitutes Debt), Debt otherwise included in the determination of such particular amount will not be included. For purposes of determining compliance with the indenture, in the event that an item of Debt meets the criteria of more than one of the types of Debt described in the above clauses, we, in our sole discretion, will classify such item of Debt and only be required to include the amount and type of such Debt in one of such clauses.

‘‘Guarantee’’ means any obligation, contingent or otherwise, of any person directly or indirectly guaranteeing any Debt of any other person and, without limiting the generality of the foregoing, any Debt obligation, direct or indirect, contingent or otherwise, of such person (1) to purchase or pay (or advance or supply funds for the purchase or payment of) such Debt of such other person (whether arising by virtue of partnership arrangements (other than solely by reason of being a general partner of a partnership), or by agreement to keep-well, to purchase assets, goods, securities or services or to take-or-pay, or to maintain financial statement conditions or otherwise) or (2) entered into for purposes of assuring in any other manner the obligee of such Debt of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part), provided that the term ‘‘Guarantee’’ will not include endorsements for collection or deposit in the ordinary course of business or the grant of a lien in connection with any Non-Recourse Debt. The term ‘‘Guarantee’’ used as a verb has a corresponding meaning.

‘‘Independent Investment Banker’’ means an independent investment banking institution of international standing appointed by us.

‘‘Intangible Assets’’ means, as of the date of determination thereof, all assets of MEHC properly classified as intangible assets determined on a consolidated basis in accordance with GAAP.

‘‘Interest Rate Protection Agreement’’ means, with respect to any person, any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement intended to protect such person against fluctuations in interest rates to or under which such person or any of its Subsidiaries is a party or a beneficiary on the date of the indenture or becomes a party or a beneficiary thereafter.

‘‘Joint Venture’’ means a joint venture, partnership or other similar arrangement, whether in corporate, partnership or other legal form.

‘‘Lien’’ means, with respect to any Property, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such Property, but will not include any partnership, joint venture, shareholder, voting trust or similar governance agreement with respect to Capital Stock in a Subsidiary or Joint Venture. For purposes of the indenture, MEHC will be deemed to own subject to a Lien any Property that it has acquired or holds subject to the interest of a vendor or lessor under any conditional sale agreement, capital lease or other title retention agreement relating to such Property.

‘‘Non-Recourse’’ means any Debt or other obligation (or that portion of such Debt or other obligation) that is without recourse to MEHC or any property or assets directly owned by MEHC (other than a pledge of the equity interests in any of its Subsidiaries, to the extent recourse to MEHC under such pledge is limited to such equity interests).

‘‘Property’’ of any person means all types of real, personal, tangible or mixed property owned by such person whether or not included in the most recent consolidated balance sheet of such person under GAAP.

‘‘Rating Agencies’’ means (1) S&P and (2) Moody’s or (3) if S&P or Moody’s or both do not make a rating of the securities publicly available, a nationally recognized securities rating agency or agencies, as the case may be, selected by us, which will be substituted for S&P or Moody’s or both, as the case may be.

‘‘Rating Decline’’ means the occurrence of the following on, or within 90 days after, the earlier of (1) the occurrence of a Change of Control and (2) the earlier of (x) the date of public notice of the occurrence of a Change of Control or (y) the date of the public notice of our intention to effect a Change of Control (or the Rating Date), which period will be extended so long as the rating of the notes is under publicly announced consideration for possible downgrading by any of the Rating Agencies: the rating of such securities by both such Rating Agencies is reduced below BBB+, in the case of S&P, and Baa1, in the case of Moody’s.

‘‘Redeemable Stock’’ means any class or series of Capital Stock of any person that by its terms or otherwise is (1) required to be redeemed prior to the stated maturity of any series of the securities, (2) redeemable at the option of the holder of such class or series of Capital Stock at any time prior to the stated maturity of any series of the securities or (3) convertible into or exchangeable for Capital Stock referred to in clause (1) or (2) above or Debt having a scheduled maturity prior to the stated maturity of any series of the securities, provided that any Capital Stock that would not constitute Redeemable Stock but for provisions thereof giving holders thereof the right to require MEHC to purchase or redeem such Capital Stock upon the occurrence of a ‘‘change of control’’ occurring prior to the stated maturity of any series of the securities will not constitute Redeemable Stock if the ‘‘change of control’’ provisions applicable to such Capital Stock are no more favorable to the holders of such Capital Stock than the provisions contained in the covenants described under ‘‘Purchase of Securities Upon a Change of Control’’ above.

‘‘Redemption Date’’ means any date on which we redeem all or any portion of the securities in accordance with the terms of the indenture.

‘‘Reference Treasury Dealer’’ means a primary U.S. government securities dealer in New York City appointed by us.

‘‘Reference Treasury Dealer Quotation’’ means, with respect to the Reference Treasury Dealer and any Redemption Date, the average, as determined by us, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount and quoted in writing to us by such Reference Treasury Dealer at 5:00 p.m. on the third business day preceding such Redemption Date).

‘‘Significant Subsidiary’’ means a ‘‘significant subsidiary’’ as defined in Rule 1-02(w) of Regulation S-X under the Securities Act and the Exchange Act, substituting 20 percent for 10 percent each place it appears therein. Unless the context otherwise clearly requires, any reference to a ‘‘Significant Subsidiary’’ is a reference to a Significant Subsidiary of MEHC.

‘‘Subsidiary’’ means, with respect to any person, including, without limitation, us and our Subsidiaries, any corporation or other entity of which such person owns, directly or indirectly, a majority of the Capital Stock or other ownership interests and has ordinary voting power to elect a majority of the board of directors or other persons performing similar functions.

‘‘Trade Payables’’ means, with respect to any person, any accounts payable or any other indebtedness or monetary obligation to trade creditors incurred, created, assumed or Guaranteed by such person or any of its Subsidiaries or Joint Ventures arising in the ordinary course of business.

‘‘Treasury Yield’’ means, with respect to any Redemption Date, the rate per annum equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such Redemption Date.

‘‘U.S. Government Obligations’’ means any security that is (1) a direct obligation of the U.S. for the payment of which its full faith and credit is pledged or (2) an obligation of a person controlled or supervised by and acting as an agency or instrumentality of the U.S., the payment of which is unconditionally guaranteed as a full faith and credit obligation by the U.S., that, in the case of clause (1) or (2) is not callable or redeemable at the option of the issuer thereof, and will also include any depository receipt issued by a bank or trust company as custodian with respect to any such U.S. Government Obligations or a specific payment of interest on or principal of any such

U.S. Government Obligation held by such custodian for the account of the holder of a depository receipt, provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depository receipt from any amount received by the custodian in respect of the U.S. Government Obligation or the specific payment of interest on or principal of the U.S. Government Obligation evidenced by such depository receipt.

‘‘Voting Stock’’ means, with respect to any person, Capital Stock of any class or kind ordinarily having the power to vote for the election of directors (or persons fulfilling similar responsibilities) of such person.

The initial notes were and the exchange notes will be, issued under a book-entry system in the form of one or more global notes (or, each, a Global Note). Each Global Note with respect to the initial notes was, and each Global Note with respect to the exchange notes will be, deposited with, or on behalf of, a depositary, which will be The Depository Trust Company, New York, New York (or the Depositary). The Global Notes with respect to the initial notes were, and the Global Notes with respect to the exchange notes will be, registered in the name of the Depositary or its nominee.

The initial notes were not issued in certificated form and, except under the limited circumstances described below, owners of beneficial interests in the Global Notes are not entitled to physical delivery of the notes in certificated form. The Global Notes may not be transferred except as a whole by the Depositary to a nominee of the Depositary or by a nominee of the Depositary to the Depositary or another nominee of the Depositary or by the Depositary or any nominee to a successor of the Depositary or a nominee of such successor.

The Depositary is a limited-purpose trust company organized under the New York Banking Law, a ‘‘banking organization’’ within the meaning of the New York Banking Law, a member of the Federal Reserve System, a ‘‘clearing corporation’’ within the meaning of the New York Uniform Commercial Code, and a ‘‘clearing agency’’ registered pursuant to the provisions of Section 17A of the Exchange Act. The Depositary holds securities that its participants (or Direct Participants) deposit with the Depositary. The Depositary also facilitates the post-trade settlement among Direct Participants of securities transactions, such as transfers and pledges, in deposited securities through electronic computerized book-entry changes in Direct Participants’ accounts, thereby eliminating the need for physical movement of securities certificates. Direct Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations, including Euroclear Bank S.A./N.V. as operator of the Euroclear System (or Euroclear) and Clearstream Banking, société anonyme (or Clearstream). The Depositary is a wholly owned subsidiary of The Depository Trust & Clearing Corporation (or DTCC). DTCC, in turn, is owned by a number of Direct Participants and Members of the National Securities Clearing Corporation, Government Securities Clearing Corporation, MBS Clearing Corporation and Emerging Markets Clearing Corporation, also subsidiaries of DTCC, as well as by the New York Stock Exchange, Inc., the American Stock Exchange LLC and the Financial Industry Regulatory Authority, Inc. Access to the Depositary system is also available to others such as securities brokers and dealers, banks and trust companies that clear through or maintain a custodial relationship with a Direct Participant, either directly or indirectly (or Indirect Participants). The rules applicable to the Depositary and its Direct and Indirect Participants are on file with the SEC.

Purchases of the securities under the Depositary system must be made by or through Direct Participants, which will receive a credit for the securities on the Depositary’s records. The ownership interest of each actual purchaser of each security (or Beneficial Owner) is in turn to be recorded on the Direct and Indirect Participants’ records. Beneficial Owners will not receive written confirmation from the Depositary of their purchase, but Beneficial Owners are expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the Direct or Indirect Participant through which the Beneficial Owner entered into the transaction. Transfers of ownership interests in the securities are to be accomplished by entries made on the books of Direct and Indirect Participants acting on behalf of Beneficial Owners. Beneficial

Owners will not receive certificates representing their ownership interests in securities, except in the event that use of the book-entry system for the securities is discontinued.

To facilitate subsequent transfers, all notes deposited by Direct Participants with the Depositary are registered in the name of the Depositary’s partnership nominee, Cede & Co., or such other name as may be requested by an authorized representative of the Depositary. The deposit of notes with the Depositary and their registration in the name of Cede & Co. or such other nominee effect no change in beneficial ownership. The Depositary has no knowledge of the actual Beneficial Owners of the notes; the Depositary’s records reflect only the identity of the Direct Participants to whose accounts such notes are credited, which may or may not be the Beneficial Owners. The Direct and Indirect Participants will remain responsible for keeping account of their holdings on behalf of their customers.

Conveyance of notices and other communications by the Depositary to Direct Participants, by Direct Participants to Indirect Participants, and by Direct Participants and Indirect Participants to Beneficial Owners are governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time.

Neither the Depositary nor Cede & Co. (nor any other nominee of the Depositary) will consent or vote with respect to the notes unless authorized by a Direct Participant in accordance with the Depositary’s procedures. Under its usual procedures, the Depositary mails an Omnibus Proxy to us as soon as possible after the record date. The Omnibus Proxy assigns Cede & Co.’s consenting or voting rights to those Direct Participants to whose accounts the securities are credited on the record date (identified in a listing attached to the Omnibus Proxy).

Principal (and premium, if any) and interest payments on the notes and any redemption payments are made to Cede & Co. (or such other nominee as may be requested by an authorized representative of the Depositary). The Depositary’s practice is to credit Direct Participants’ accounts upon the Depositary’s receipt of funds and corresponding detail information from us or the trustee on the payable date in accordance with their respective holdings shown on the Depositary’s records. Payments by Participants to Beneficial Owners will be governed by standing instructions and customary practices, as is the case with securities held for the accounts of customers in bearer form or registered in ‘‘street name,’’ and will be the responsibility of such Participant and not of the Depositary, the trustee or us, subject to any statutory or regulatory requirements as may be in effect from time to time. Payment of principal (and premium, if any), interest and any redemption proceeds to Cede & Co. (or such other nominee as may be requested by an authorized representative of the Depositary) is the responsibility of MEHC, disbursements of such payments to Direct Participants shall be the responsibility of the Depositary, and disbursement of such payments to the Beneficial Owners shall be the responsibility of Direct and Indirect Participants.

The Depositary may discontinue providing its services as securities depositary with respect to the notes at any time by giving reasonable notice to us or the trustee. Under such circumstances, in the event that a successor securities depositary is not obtained, certificated notes are required to be printed and delivered. We may decide to discontinue use of the system of book-entry transfers through the Depositary (or a successor securities depositary). In that event, certificated notes will be printed and delivered.

The information in this section concerning the Depositary and the Depositary’s book-entry system has been obtained from sources that we believe to be reliable but has not been independently verified by us, the initial purchasers or the trustee.

Prior to the expiration of the ‘‘40-day distribution compliance period’’ (within the meaning of Rule 903 of Regulation S), beneficial interests in any Global Note for notes sold outside the U.S. in reliance on Regulation S under the Securities Act may only be held through Euroclear or Clearstream, unless delivery is made pursuant to an exemption from registration under the Securities Act in accordance with the certification requirements of the indenture.

A Global Note may not be transferred except as a whole by the Depositary to a nominee or successor of the Depositary or by a nominee of the Depositary to another nominee of the Depositary. A Global Note representing notes is exchangeable, in whole but not in part, for notes in definitive

form of like tenor and terms if (1) the Depositary notifies us that it is unwilling or unable to continue as depositary for such Global Note or if at any time the Depositary is no longer eligible to be or in good standing as a ‘‘clearing agency’’ registered under the Exchange Act, and in either case, a successor depositary is not appointed by us within 120 days of receipt by us of such notice or of our becoming aware of such ineligibility, (2) while such Global Note is subject to the transfer restrictions described under ‘‘Transfer Restrictions,’’ the book-entry interests in such Global Note cease to be eligible for Depositary services because such notes are neither (a) rated in one of the top four categories by a nationally recognized statistical rating organization nor (b) included within a Self-Regulatory Organization system approved by the SEC for the reporting of quotation and trade information of securities eligible for transfer pursuant to Rule 144A under the Securities Act, or (3) we in our sole discretion at any time determine not to have such notes represented by a Global Note and notify the trustee thereof. A Global Note exchangeable pursuant to the preceding sentence shall be exchangeable for notes registered in such names and in such authorized denominations as the Depositary shall direct.

The exchange of initial notes for exchange notes pursuant to the exchange offer will not constitute a taxable event for U.S. federal income tax purposes. The exchange notes received by a holder of initial notes should be treated as a continuation of such holder’s investment in the initial notes; thus there should be no material U.S. federal income tax consequences to holders exchanging initial notes for exchange notes. As a result:

Based on existing interpretations of the Securities Act by the staff of the SEC set forth in several no-action letters to third parties, and subject to the immediately following sentence, we believe that the exchange notes that will be issued pursuant to the exchange offer may be offered for resale, resold and otherwise transferred by the holders thereof without further compliance with the registration and prospectus delivery provisions of the Securities Act. However, any purchaser of notes who is an ‘‘affiliate’’ (within the meaning of the Securities Act) of ours or who intends to participate in the exchange offer for the purpose of distributing the exchange notes or a broker-dealer (within the meaning of the Securities Act) that acquired initial notes in a transaction other than as part of its market-making or other trading activities and who has arranged or has an understanding with any person to participate in the distribution of the exchange notes: (1) will not be able to rely on the interpretations by the staff of the SEC set forth in the above-mentioned no-action letters; (2) will not be able to tender its initial notes in the exchange offer; and (3) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the notes unless such sale or transfer is made pursuant to an exemption from such requirements.

Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for initial notes where such initial notes were acquired as a result of market-marketing activities or other trading activities. We have agreed that, for a period of 120 days after the expiration date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale.

We will not receive any proceeds from any such sale of exchange notes by broker-dealers. Exchange notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the exchange notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or at negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker/dealer and/or the purchasers of any such exchange notes. Any broker-dealer that resells exchange notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such exchange notes may be deemed to be an ‘‘underwriter’’ within the meaning of the Securities Act and any profit on any such resale of exchange notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an ‘‘underwriter’’ within the meaning of the Securities Act.

For a period of 120 days after the expiration date we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer (including the expenses of one counsel for the holders of the notes other than commissions or concessions of any brokers or dealers and will indemnify the holders of the notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

Certain legal matters with respect to the exchange notes will be passed upon for us by Willkie Farr & Gallagher LLP, New York, New York.

The Consolidated Financial Statements of MidAmerican Energy Holdings Company and its subsidiaries, as of December 31, 2007 and 2006, and for each of the three years in the period ended December 31, 2007, included in this Prospectus and the related financial statement schedules included elsewhere in the Registration Statement, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein and elsewhere in the Registration Statement which report expresses an unqualified opinion on the financial statements and financial statement schedules and includes an explanatory paragraph referring to the adoption of Statement of Financial Accounting Standards No. 158, ‘‘Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R),’’ as of December 31, 2006. Such financial statements and financial statement schedules have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

With respect to the unaudited interim financial information of MidAmerican Energy Holdings Company and its subsidiaries, for the periods ended March 31, 2008 and 2007, included in this Prospectus, Deloitte & Touche LLP, an independent registered public accounting firm, have applied limited procedures in accordance with the standards of the Public Company Accounting Oversight Board (United States) for a review of such information. However, as stated in their report included in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, appearing herein and elsewhere in the Registration Statement, they did not audit and they do not express an opinion on that interim financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. Deloitte & Touche LLP are not subject to the liability provisions of Section 11 of the Securities Act for their report on the unaudited interim financial information because this report is not a ‘‘report’’ or a ‘‘part’’ of the Registration Statement prepared or certified by an accountant within the meaning of Sections 7 and 11 of the Securities Act.

MEHC files reports and information statements and other information with the SEC. Such reports, proxy and information statements and other information filed by us with the SEC can be inspected and copied at the Public Reference Section of the SEC at 100 F Street, NE, Room 1580, Washington, D.C. 20549, and at the regional offices of the SEC located at Woolworth Building, 233 Broadway, New York, New York 10279 and 500 West Madison Street, Suite 1400, Chicago, Illinois 60661. Copies of such material can be obtained from the Public Reference Section of the SEC at 100 F Street, NE, Room 1580, and Washington, D.C. 20549 at prescribed rates. The SEC maintains a Web site that contains reports, proxy and information statements and other materials that are filed through the SEC’s Electronic Data Gathering, Analysis, and Retrieval (or EDGAR) system. This Web site can be accessed at http://www.sec.gov.

MEHC makes available free of charge through its internet website at http://www.midamerican.com its annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after it electronically files with, or furnishes them to, the SEC. Any information available on or through its website is not part of this prospectus and its web address is included as an inactive textual reference only.

All documents and other reports filed by us with the SEC subsequent to the date of this prospectus and prior to the completion of the exchange offer pursuant to Section 13 or 15(d) of the Exchange Act shall be deemed to be incorporated by reference into this prospectus and to be a part hereof from the date of filing such documents and reports.

Any statement contained in a document incorporated by reference herein shall be deemed to be modified or superseded for purposes of this prospectus to the extent that a statement contained in any other subsequently filed document which is also incorporated herein by reference, modifies or supersedes such statement. Any such statement so modified or superseded shall not be deemed to constitute part of this prospectus except as so modified or superseded.

We hereby undertake to provide without charge to each person to whom a copy of this prospectus has been delivered, on the written or oral request of any such person, a copy of any or all of the documents referred to above which may be incorporated into this prospectus by reference, other than exhibits to such documents. Requests for such copies should be directed to Vice President and Treasurer, MidAmerican Energy Holdings Company, 666 Grand Avenue, Suite 500, Des Moines, Iowa 50309-2580, telephone number (515) 242-4300.

To the Board of Directors and Shareholders
MidAmerican Energy Holdings Company
Des Moines, Iowa

We have reviewed the accompanying consolidated balance sheet of MidAmerican Energy Holdings Company and subsidiaries (the ‘‘Company’’) as of March 31, 2008, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the three-month periods ended March 31, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of MidAmerican Energy Holdings Company and subsidiaries as of December 31, 2007, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the year then ended; and in our report dated February 27, 2008, we expressed an unqualified opinion on those consolidated financial statements, which included an explanatory paragraph related to the adoption of Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R), as of December 31, 2006. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2007, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)


	As of
	March 31, 2008			December 31, 2007
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	1,005		$	1,063
Accrued interest			342			341
Accrued property and other taxes			253			230
Derivative contracts			252			266
Other current liabilities			919			816
Short-term debt			22			130
Current portion of long-term debt			1,861			1,966
Current portion of MEHC subordinated debt			234			234
Total current liabilities			4,888			5,046
Other long-term accrued liabilities			1,314			1,372
Regulatory liabilities			1,627			1,629
Derivative contracts			598			499
MEHC senior debt			5,120			4,471
MEHC subordinated debt			892			891
Subsidiary and project debt			12,333			12,131
Deferred income taxes			3,708			3,595
Total liabilities			30,480			29,634
Minority interest			132			128
Preferred securities of subsidiaries			128			128
Commitments and contingencies (Note 8)
Shareholders’ equity:
Common stock – 115 shares authorized, no par value, 75 shares issued and outstanding			—			—
Additional paid-in capital			5,454			5,454
Retained earnings			4,124			3,782
Accumulated other comprehensive income, net			99			90
Total shareholders’ equity			9,677			9,326
Total liabilities and shareholders’ equity		$	40,417		$	39,216

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)


	Three-Month Periods Ended March 31,
	2008				2007
Operating revenue		$	3,356			$	3,224
Costs and expenses:
Cost of sales			1,619				1,517
Operating expense			687				682
Depreciation and amortization			278				286
Total costs and expenses			2,584				2,485
Operating income			772				739
Other income (expense):
Interest expense			(328	)			(316	)
Capitalized interest			11				14
Interest and dividend income			18				19
Other income			18				26
Other expense			(1	)			(1	)
Total other income (expense)			(282	)			(258	)
Income before income tax expense, minority interest and preferred dividends of subsidiaries and equity income			490				481
Income tax expense			147				160
Minority interest and preferred dividends of subsidiaries			4				13
Equity income			(3	)			(5	)
Net income		$	342			$	313

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (Unaudited)
FOR THE THREE-MONTH PERIODS ENDED MARCH 31, 2008 AND 2007
(Amounts in millions)


													Accumulated Other Comprehensive Income (Loss), Net
	Outstanding Common Shares					Additional Paid-in Capital
			Common Stock						Retained Earnings
			Common Stock						Retained Earnings								Total
Balance, January 1, 2007		74		$	—		$	5,420		$	2,598			$	(7	)		$	8,011
Adoption of FASB Interpretation No. 48		—			—			—			(5	)			—				(5	)
Net income		—			—			—			313				—				313
Other comprehensive income		—			—			—			—				31				31
Other equity transactions		—			—			2			—				—				2
Balance, March 31, 2007		74		$	—		$	5,422		$	2,906			$	24			$	8,352
Balance, January 1, 2008		75		$	—		$	5,454		$	3,782			$	90			$	9,326
Net income		—			—			—			342				—				342
Other comprehensive income		—			—			—			—				9				9
Balance, March 31, 2008		75		$	—		$	5,454		$	4,124			$	99			$	9,677

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)


	Three-Month Periods Ended March 31,
	2008				2007
Cash flows from operating activities:
Net income		$	342			$	313
Adjustments to reconcile net income to cash flows from operations:
Gain on other items, net			(2	)			(19	)
Depreciation and amortization			278				286
Amortization of regulatory assets and liabilities			(11	)			10
Provision for deferred income taxes			118				29
Other			(47	)			14
Changes in other items:
Accounts receivable and other current assets			37				22
Accounts payable and other accrued liabilities			62				164
Net cash flows from operating activities			777				819
Cash flows from investing activities:
Capital expenditures			(710	)			(819	)
Purchases of available-for-sale securities			(61	)			(381	)
Proceeds from sale of available-for-sale securities			62				292
Proceeds from maturity of guaranteed investment contract			393				—
Proceeds from sale of assets			6				31
(Increase) decrease in restricted cash			(8	)			31
Other			6				12
Net cash flows from investing activities			(312	)			(834	)
Cash flows from financing activities:
Proceeds from MEHC senior debt			649				—
Proceeds from subsidiary and project debt			397				751
Repayments of subsidiary and project debt			(399	)			(38	)
Net repayments of MEHC revolving credit facility			—				(7	)
Net repayments of subsidiary short-term debt			(107	)			(84	)
Other			3				(1	)
Net cash flows from financing activities			543				621
Effect of exchange rate changes			1				1
Net change in cash and cash equivalents			1,009				607
Cash and cash equivalents at beginning of period			1,178				343
Cash and cash equivalents at end of period		$	2,187			$	950

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

MidAmerican Energy Holdings Company (‘‘MEHC’’) is a holding company which owns subsidiaries that are principally engaged in energy businesses. MEHC and its subsidiaries are referred to as the ‘‘Company.’’ MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. (‘‘Berkshire Hathaway’’). The Company is organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding, LLC (‘‘MidAmerican Funding’’) (which primarily includes MidAmerican Energy Company (‘‘MidAmerican Energy’’)), Northern Natural Gas Company (‘‘Northern Natural Gas’’), Kern River Gas Transmission Company (‘‘Kern River’’), CE Electric UK Funding Company (‘‘CE Electric UK’’) (which primarily includes Northern Electric Distribution Limited (‘‘Northern Electric’’) and Yorkshire Electricity Distribution plc (‘‘Yorkshire Electricity’’)), CalEnergy Generation-Foreign (owning a majority interest in the Casecnan project), CalEnergy Generation-Domestic (owning interests in independent power projects in the United States) and HomeServices of America, Inc. (collectively with its subsidiaries, ‘‘HomeServices’’). Through these platforms, the Company owns and operates an electric utility company in the Western United States, a combined electric and natural gas utility company in the Midwestern United States, two interstate natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of independent power projects and the second largest residential real estate brokerage firm in the United States.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (‘‘GAAP’’) for interim financial information and the U.S. Securities and Exchange Commission’s rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the financial statements as of March 31, 2008, and for the three-month periods ended March 31, 2008 and 2007. Certain amounts in the prior period Consolidated Financial Statements have been reclassified to conform to the current period presentation. Such reclassifications did not impact previously reported operating income, net income or retained earnings. The results of operations for the three-month periods ended March 31, 2008 are not necessarily indicative of the results to be expected for the full year.

The unaudited Consolidated Financial Statements include the accounts of MEHC and its subsidiaries in which it holds a controlling financial interest. The Consolidated Statements of Operations include the revenues and expenses of an acquired entity from the date of acquisition. Intercompany accounts and transactions have been eliminated.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, describes the most significant accounting estimates and policies used in the preparation of the Consolidated Financial Statements. There have been no significant changes in the Company’s assumptions regarding significant accounting policies during the first three months of 2008.

In March 2008, the Financial Accounting Standards Board (‘‘FASB’’) issued Statement of Financial Accounting Standards (‘‘SFAS’’) No. 161, ‘‘Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133’’ (‘‘SFAS No. 161’’). SFAS No. 161 is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand how and why an entity uses derivative instruments and their effects on an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Company is currently evaluating the impact of adopting SFAS No. 161 on its disclosures included within the notes to its Consolidated Financial Statements.

In December 2007, the FASB issued SFAS No. 141(R), ‘‘Business Combinations’’ (‘‘SFAS No. 141(R)’’). SFAS No. 141(R) applies to all transactions or other events in which an entity obtains control of one or more businesses. SFAS No. 141(R) establishes how the acquirer of a business should recognize, measure and disclose in its financial statements the identifiable assets and goodwill acquired, the liabilities assumed and any noncontrolling interest in the acquired business. SFAS No. 141(R) is applied prospectively for all business combinations with an acquisition date on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, with early application prohibited. SFAS No. 141(R) will not have an impact on the Company’s historical Consolidated Financial Statements and will be applied to business combinations completed, if any, on or after January 1, 2009.

In December 2007, the FASB issued SFAS No. 160, ‘‘Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51’’ (‘‘SFAS No. 160’’). SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 requires entities to report noncontrolling interests as a separate component of shareholders’ equity in the consolidated financial statements. The amount of earnings attributable to the parent and to the noncontrolling interests should be clearly identified and presented on the face of the consolidated statements of operations. Additionally, SFAS No. 160 requires any changes in a parent’s ownership interest of its subsidiary, while retaining its control, to be accounted for as equity transactions. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008 and interim periods within those fiscal years. The Company is currently evaluating the impact of adopting SFAS No. 160 on its consolidated financial position and results of operations.

In February 2007, the FASB issued SFAS No. 159, ‘‘The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FASB Statement No. 115’’ (‘‘SFAS No. 159’’). SFAS No. 159 permits entities to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS No. 159, an entity may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option may only be made at initial recognition of the asset or liability or upon a remeasurement event that gives rise to new-basis accounting. The decision about whether to elect the fair value option is applied on an instrument-by-instrument basis, is irrevocable and is applied only to an entire instrument and not only to specified risks, cash flows or portions of that instrument. SFAS No. 159 does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value nor does it eliminate disclosure requirements included in other accounting standards. The Company adopted SFAS No. 159 effective January 1, 2008, and did not elect the fair value option for any existing eligible items.

principal or most advantageous market. The standard clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In February 2008, the FASB issued Staff Position No. 157-2, ‘‘Effective Date of FASB Statement No. 157’’ (‘‘FSP FAS 157-2’’), which delays the effective date of SFAS No. 157 for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the consolidated financial statements on a recurring basis, until fiscal years beginning after November 15, 2008. These non-financial items include assets and liabilities such as non-financial assets and liabilities assumed in a business combination, reporting units measured at fair value in a goodwill impairment test and asset retirement obligations initially measured at fair value. The Company adopted the provisions of SFAS No. 157 for assets and liabilities recognized at fair value on a recurring basis effective January 1, 2008. The partial adoption of SFAS No. 157 did not have a material impact on the Company’s Consolidated Financial Statements. Refer to Note 10 for additional discussion.

In September 2006, the FASB issued SFAS No. 158, ‘‘Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R)’’ (‘‘SFAS No. 158’’). SFAS No. 158 requires that an employer measure plan assets and obligations as of the end of the employer’s fiscal year, eliminating the option in SFAS No. 87 and SFAS No. 106 to measure up to three months prior to the financial statement date. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end is not required until fiscal years ending after December 15, 2008. As of March 31, 2008, PacifiCorp had not yet adopted the measurement date provisions of the statement. Upon adoption of the measurement date provisions, PacifiCorp will be required to record a transitional adjustment to retained earnings or to a regulatory asset depending on whether the amount is considered probable of being recovered in rates.

Substantially all of the construction in progress as of March 31, 2008 and December 31, 2007 relates to the construction of regulated assets.

The following are updates to regulatory matters based upon material changes that occurred subsequent to December 31, 2007.

Kern River’s 2004 general rate case hearing concluded in August 2005. On March 2, 2006, Kern River received an initial decision on the case from the administrative law judge. On October 19, 2006, the Federal Energy Regulatory Commission (‘‘FERC’’) issued an order that modified certain aspects of the administrative law judge’s initial decision, including changing the allowed return on equity from 9.34% to 11.2% and granting Kern River an income tax allowance. The order also affirmed the rejection of certain issues included in Kern River’s filed position, including the load and inflation factors. Kern River and other parties filed their requests for rehearing of the initial order on November 20, 2006. On April 17, 2008, the FERC issued an order denying rehearing on the issues raised by Kern River and other parties to the proceeding except Kern River’s request to include gas pipeline master limited partnerships in the proxy group for determining the allowed rate of return on equity. The grant of rehearing on this issue is consistent with the FERC’s April 17, 2008 adoption of a policy statement that addresses the inclusion of master limited partnerships in the proxy group used to determine a pipeline’s allowed return on equity. The FERC reopened the record for a paper hearing for additional consideration of this issue and established a procedural schedule requiring all parties to have their submissions completed by August 1, 2008. Rate refunds will be due within 30 days after a final order on Kern River’s rate case is issued. Kern River was permitted to bill the requested rate increase prior to final approval by the FERC, subject to refund, beginning effective November 1, 2004. Since that time, Kern River has recorded a liability for rates subject to refunds.

In October 2007, PacifiCorp filed its first tax report under Oregon Senate Bill 408 (‘‘SB 408’’), which was enacted in September 2005. SB 408 requires that PacifiCorp and other large regulated, investor-owned utilities that provide electric or natural gas service to Oregon customers file an annual tax report with the Oregon Public Utility Commission (the ‘‘OPUC’’). PacifiCorp’s filing indicated that in 2006, PacifiCorp paid $33 million more in federal, state and local taxes than was collected in rates from its retail customers. PacifiCorp proposed to recover $27 million of the surcharge over a one-year period starting June 1, 2008 and to defer any excess into a balancing account for future disposition. During the review process, PacifiCorp updated its filing to address the OPUC staff recommendations, which increased the initial request by $2 million for a total of $35 million. In April 2008, the OPUC approved PacifiCorp’s revised request, with $27 million to be recovered over a one-year period beginning June 1, 2008, and the remainder to be deferred until a later period, with interest to accrue at PacifiCorp’s authorized rate of return. The OPUC’s decision is subject to a 60-day appeal period. PacifiCorp expects to file its 2007 tax report under SB 408 during the fourth quarter of 2008. PacifiCorp has not recorded any amounts related to either the 2006 tax report or the expected filing for 2007.

On March 28, 2008, MEHC issued $650 million of 5.75% senior notes due April 1, 2018. The net proceeds will be used for general corporate purposes. Pending application for such use, the net proceeds will be temporarily invested in short-term securities, money market funds, bank deposits or cash equivalents.

On March 25, 2008, MidAmerican Energy issued $350 million of 5.3% senior notes due March 15, 2018. The proceeds are being used by MidAmerican Energy to pay construction costs, including costs for its wind-powered generation projects in Iowa, repay short-term indebtedness and for general corporate purposes.

The Company is exposed to the impact of market fluctuations in commodity prices, principally natural gas and electricity, particularly through its ownership of PacifiCorp and MidAmerican Energy. Interest rate risk exists on variable rate debt, commercial paper and future debt issuances. The Company is also exposed to foreign currency risk from its business operations and investments in Great Britain. The Company employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including forward contracts, futures, options, swaps and other over-the-counter agreements. The risk management process established by each business platform is designed to identify, assess, monitor, report, manage, and mitigate each of the various types of risk involved in its business. The Company does not engage in a material amount of proprietary trading activities.

The following table summarizes the various derivative mark-to-market positions included in the Consolidated Balance Sheet as of March 31, 2008 (in millions):

The following table summarizes the various derivative mark-to-market positions included in the Consolidated Balance Sheet as of December 31, 2007 (in millions):

As of March 31, 2008 and December 31, 2007, Berkshire Hathaway and its affiliates held 11% mandatory redeemable preferred securities due from certain wholly owned subsidiary trusts of MEHC of $821 million. Interest expense on these securities totaled $23 million and $29 million for the three-month periods ended March 31, 2008 and 2007, respectively. Accrued interest totaled $17 million as of March 31, 2008 and December 31, 2007.

For the three-month periods ended March 31, 2008 and 2007, the Company received cash payments for income taxes from Berkshire Hathaway totaling $25 million and $13 million, respectively.

The Company is subject to federal, state, local and foreign laws and regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters that have the potential to impact the Company’s current and future operations. The Company believes it is in material compliance with current environmental requirements.

The Company is fully or partly responsible for environmental remediation at various contaminated sites, including sites that are or were part of the Company’s operations and sites owned by third parties. The Company accrues environmental remediation expenses when the expenses are believed to be probable and can be reasonably estimated. The quantification of environmental exposures is based on many factors, including changing laws and regulations, advancements in environmental technologies, the quality of available site-specific information, site investigation results, expected remediation or settlement timelines, the Company’s proportionate responsibility, contractual indemnities and coverage provided by insurance policies. The liability recorded as of March 31, 2008 and December 31, 2007 was $39 million and $38 million, respectively, and is included in other current liabilities and other long-term accrued liabilities on the Consolidated Balance Sheets. Environmental remediation liabilities that separately result from the normal operation of long-lived assets and that are associated with the retirement of those assets are separately accounted for as asset retirement obligations.

PacifiCorp’s hydroelectric portfolio consists of 47 plants with an aggregate facility net owned capacity of 1,158 megawatts (‘‘MW’’). The FERC regulates 98% of the net capacity of this portfolio through 16 individual licenses. As of March 31, 2008, several of PacifiCorp’s hydroelectric plants were in some stage of relicensing with the FERC. Hydroelectric relicensing and the related environmental compliance requirements and litigation are subject to uncertainties. PacifiCorp expects that future costs relating to these matters will be significant and will consist primarily of additional relicensing costs, operations and maintenance expense, and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. PacifiCorp had incurred $91 million and $89 million in costs as of March 31, 2008 and December 31, 2007, respectively, for ongoing hydroelectric relicensing projects, which are included in construction in progress and reflected in property, plant and equipment, net in the Consolidated Balance Sheets.

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 169-MW (nameplate rating) Klamath hydroelectric project in anticipation of the March 2006 expiration of the existing license. PacifiCorp is currently operating under an annual license issued by the FERC and expects to continue to operate under annual licenses until the new operating license is issued. As part of the relicensing process, the United States Departments of Interior and Commerce filed proposed licensing terms and conditions with the FERC in March 2006, which proposed that PacifiCorp construct upstream and downstream fish passage facilities at the Klamath hydroelectric project’s four mainstem dams. In April 2006, PacifiCorp filed alternatives to the federal agencies’ proposal and requested an administrative hearing to challenge some of the federal agencies’ factual assumptions supporting their proposal for the construction of the fish passage facilities. A hearing was held in August 2006 before an administrative law judge. The administrative law judge issued a ruling in September 2006 generally supporting the federal agencies’ factual assumptions. In January 2007, the United States Departments of Interior and Commerce filed modified terms and conditions consistent with March 2006 filings and rejected the alternatives proposed by PacifiCorp. PacifiCorp is prepared to meet and implement the federal agencies’ terms and conditions as part of the project’s relicensing. However, PacifiCorp expects to continue in settlement discussions with various parties in the Klamath Basin area who have intervened with the FERC licensing proceeding to try to achieve a mutually acceptable outcome for the project.

Also, as part of the relicensing process, the FERC is required to perform an environmental review. In September 2006, the FERC issued its draft environmental impact statement on the Klamath hydroelectric project license. PacifiCorp filed comments on the draft statement by the close of the public comment period on December 1, 2006. Subsequently, in November 2007, the FERC issued its final environmental impact statement. The United States Fish and Wildlife Service and the National Marine Fisheries Service issued final biological opinions in December 2007 analyzing the hydroelectric project’s impact on endangered species under a new FERC license consistent with the FERC staff’s recommended alternative and modified terms and conditions issued by the Departments of Interior and Commerce. The United States Fish and Wildlife Service asserts the hydroelectric project is currently not covered by previously issued biological opinions, and that consultation under the Endangered Species Act is required by the issuance of annual license renewals. PacifiCorp disputes these assertions and believes that consultation on annual FERC licenses is not required. PacifiCorp will need to obtain water quality certifications from Oregon and California prior to the FERC issuing a final license. PacifiCorp currently has applications pending before each state.

In the relicensing of the Klamath hydroelectric project, PacifiCorp had incurred $50 million and $48 million in costs as of March 31, 2008 and December 31, 2007, respectively, which are included in construction in progress and reflected in property, plant and equipment, net in the Consolidated Balance Sheets. While the costs of implementing new license provisions cannot be determined until such time as a new license is issued, such costs could be material.

The Company is party in a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material effect on its consolidated financial results. The Company is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines and penalties in substantial amounts and are described below.

In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in the federal district court in Cheyenne, Wyoming, alleging violations of the Wyoming state opacity standards at PacifiCorp’s Jim Bridger plant in Wyoming. Under Wyoming state requirements, which are part of the Jim Bridger plant’s Title V permit and are enforceable by private citizens under the federal Clean Air Act, a potential source of pollutants such as a coal-fired generating facility must meet minimum standards for opacity, which is a measurement of light that is obscured in the flue of a generating facility. The complaint alleges thousands of violations of six-minute compliance periods and seeks an injunction ordering the Jim Bridger plant’s compliance with opacity limits, civil penalties of $32,500 per day per violation and the plaintiffs’ costs of litigation. The court granted a motion to bifurcate the trial into separate liability and remedy phases. In March 2008, the court indefinitely postponed the date for the liability-phase trial. It is not known when the court will reschedule the liability-phase trial. The remedy-phase trial has not yet been scheduled. The court also has before it a number of motions on which it has not yet ruled. PacifiCorp believes it has a number of defenses to the claims. PacifiCorp intends to vigorously oppose the lawsuit but cannot predict its outcome at this time. PacifiCorp has already committed to invest at least $812 million in pollution control equipment at its generating facilities, including the Jim Bridger plant. This commitment is expected to significantly reduce system-wide emissions, including emissions at the Jim Bridger plant.

Contractors (International) Ltd. (‘‘LPG’’), that MEHC’s indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. On July 8, 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco against CE Casecnan Ltd. and MEHC. LPG’s complaint, as amended, seeks compensatory and punitive damages arising out of CE Casecnan Ltd.’s and MEHC’s alleged improper calculation of the proforma financial projections and alleged improper settlement of the NIA arbitration.

On February 21, 2007, the appellate court issued a decision, and as a result of the decision, CE Casecnan Ltd. determined that LPG would retain ownership of 10% of the shares of CE Casecnan, with the remaining 5% ownership being transferred to CE Casecnan Ltd. subject to certain buy-up rights under the shareholder agreement. At a hearing on October 10, 2007, the court determined that LPG was ready, willing and able to exercise its buy-up rights in 2007. Additional hearings were held on October 23 and 24, 2007, regarding the issue of the buy-up price calculation and a written decision was issued on February 4, 2008 specifying the method for determining LPG’s buy-up price. The court has scheduled a hearing for May 9, 2008 regarding the inclusion of certain tax considerations in the calculation of the buy-up price. LPG waived its request for a jury trial for the breach of fiduciary duty claim and the parties have entered into a stipulation which provides for a trial of such claim by the court based on the existing record of the case. The trial was held on April 23, 2008. The court took the matter under advisement and requested further briefs from the parties on the burden of proof to be applied. The Company intends to vigorously defend and pursue the remaining claims.

In February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. (‘‘San Lorenzo’’), an original shareholder substantially all of whose shares in CE Casecnan were purchased by MEHC in 1998, threatened to initiate legal action against the Company in the Philippines in connection with certain aspects of its option to repurchase such shares. The Company believes that San Lorenzo has no valid basis for any claim and, if named as a defendant in any action that may be commenced by San Lorenzo, the Company will vigorously defend such action. On July 1, 2005, MEHC and CE Casecnan Ltd. commenced an action against San Lorenzo in the District Court of Douglas County, Nebraska, seeking a declaratory judgment as to MEHC’s and CE Casecnan Ltd.’s rights vis-à-vis San Lorenzo in respect of such shares. San Lorenzo filed a motion to dismiss on September 19, 2005. Subsequently, San Lorenzo purported to exercise its option to repurchase such shares. On January 30, 2006, San Lorenzo filed a counterclaim against MEHC and CE Casecnan Ltd. seeking declaratory relief that it has effectively exercised its option to purchase 15% of the shares of CE Cascenan, that it is the rightful owner of such shares and that it is due all dividends paid on such shares. On March 9, 2006, the court granted San Lorenzo’s motion to dismiss, but has since permitted MEHC and CE Casecnan Ltd. to file an amended complaint incorporating the purported exercise of the option. The complaint has been amended and the action is proceeding. Currently, the action is in the discovery phase and a one-week trial has been set to begin on November 3, 2008. The impact, if any, of San Lorenzo’s purported exercise of its option and the Nebraska litigation on the Company cannot be determined at this time. The Company intends to vigorously defend the counterclaims.

Combined net periodic benefit cost for the pension, including supplemental executive retirement plans, and other postretirement benefit plans included the following components for the three-month periods ended March 31 (in millions):

Employer contributions to the pension and other postretirement plans are expected to be $77 million and $41 million, respectively, in 2008. As of March 31, 2008, $36 million and $10 million of contributions had been made to the pension and other postretirement plans, respectively.

Net periodic benefit cost for the UK pension plan included the following components for the three-month periods ended March 31 (in millions):

Employer contributions to the UK pension plan are expected to be £48 million for 2008. As of March 31, 2008, £14 million, or $28 million, of contributions had been made to the UK pension plan.

The Company has various financial instruments that are measured at fair value in the Consolidated Financial Statements, including marketable debt and equity securities and commodity derivatives. The Company’s financial assets and liabilities are measured using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

The following table presents the Company’s assets and liabilities recognized in the Consolidated Balance Sheet and measured at fair value on a recurring basis as of March 31, 2008 (in millions):

The Company’s investments in debt and equity securities are classified as available-for-sale and stated at fair value. When available, the quoted market price or net asset value of an identical security in the principal market is used to record the fair value. In the absence of a quoted market price in a readily observable market, the fair value is determined using pricing models based on observable market inputs and quoted market prices of securities with similar characteristics. The fair value of the Company’s investments in auction rate securities, where there is no current liquid market, is determined using broker quotes or pricing models based on unobservable inputs.

The Company uses various commodity derivative instruments, including forward contracts, futures, options, swaps and other over-the counter agreements. The fair value of commodity derivatives is determined using unadjusted quoted prices for identical instruments on the applicable exchange in which the Company transacts. When quoted prices for identical instruments are not available, the Company uses forward price curves derived from market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first six years, and therefore the Company’s forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first six years or the instrument is not actively traded. Given that limited market data exists for these instruments, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on significant unobservable inputs.

The following table reconciles the beginning and ending balance of the Company’s assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three-month period ended March 31, 2008 (in millions):

(11) Comprehensive Income and Components of Accumulated Other Comprehensive Income, Net

Accumulated other comprehensive income, net is included in the Consolidated Balance Sheets in the common shareholders’ equity section, and consists of the following components, net of tax, as follows (in millions):

MEHC’s reportable segments were determined based on how the Company’s strategic units are managed. The Company’s foreign reportable segments include CE Electric UK, whose business is principally in Great Britain, and CalEnergy Generation-Foreign, whose business is in the Philippines. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company’s reportable segments is shown below (in millions):


	Three-Month Periods Ended March 31,
	2008				2007
Operating revenue:
PacifiCorp		$	1,095			$	1,027
MidAmerican Funding			1,373				1,237
Northern Natural Gas			232				234
Kern River			110				86
CE Electric UK			285				248
CalEnergy Generation-Foreign			29				66
CalEnergy Generation-Domestic			7				8
HomeServices			241				335
Corporate/other⁽¹⁾			(16	)			(17	)
Total operating revenue		$	3,356			$	3,224
Depreciation and amortization:
PacifiCorp		$	117			$	121
MidAmerican Funding			72				70
Northern Natural Gas			15				14
Kern River			21				19
CE Electric UK			44				42
CalEnergy Generation-Foreign			5				17
CalEnergy Generation-Domestic			2				2
HomeServices			5				5
Corporate/other⁽¹⁾			(3	)			(4	)
Total depreciation and amortization		$	278			$	286
Operating income:
PacifiCorp		$	231			$	220
MidAmerican Funding			175				145
Northern Natural Gas			148				149
Kern River			76				61
CE Electric UK			167				146
CalEnergy Generation-Foreign			21				44
CalEnergy Generation-Domestic			3				4
HomeServices			(22	)			(5	)
Corporate/other⁽¹⁾			(27	)			(25	)
Total operating income			772				739
Interest expense			(328	)			(316	)
Capitalized interest			11				14
Interest and dividend income			18				19
Other income			18				26
Other expense			(1	)			(1	)
Total income before income tax expense, minority interest and preferred dividends of subsidiaries and equity income		$	490			$	481

Goodwill is allocated to each reportable segment included in total assets above. Goodwill as of December 31, 2007 and the changes for the three-month period ended March 31, 2008 by reportable segment are as follows (in millions):

To the Board of Directors and Shareholders
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, 2007 and 2006, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedules listed in the Index at Item 21. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 158, ‘‘Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R),’’ as of December 31, 2006.

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions)

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Amounts in millions)


	As of December 31,
	2007			2006
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	1,063		$	1,049
Accrued interest			341			306
Accrued property and other taxes			230			231
Derivative contracts			266			271
Other current liabilities			816			713
Short-term debt			130			552
Current portion of long-term debt			1,966			1,103
Current portion of MEHC subordinated debt			234			234
Total current liabilities			5,046			4,459
Other long-term accrued liabilities			1,372			1,716
Regulatory liabilities			1,629			1,839
Derivative contracts			499			618
MEHC senior debt			4,471			3,929
MEHC subordinated debt			891			1,123
Subsidiary and project debt			12,131			11,061
Deferred income taxes			3,595			3,449
Total liabilities			29,634			28,194
Minority interest			128			114
Preferred securities of subsidiaries			128			128
Commitments and contingencies (Note 18)
Shareholders’ equity:
Common stock – 115 shares authorized, no par value, 75 shares and 74 shares issued and outstanding as of December 31, 2007 and 2006, respectively			—			—
Additional paid-in capital			5,454			5,420
Retained earnings			3,782			2,598
Accumulated other comprehensive income (loss), net			90			(7	)
Total shareholders’ equity			9,326			8,011
Total liabilities and shareholders’ equity		$	39,216		$	36,447

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)


	Years Ended December 31,
	2007				2006				2005
Operating revenue		$	12,376			$	10,301			$	7,116
Costs and expenses:
Cost of sales			5,680				4,587				3,293
Operating expense			2,858				2,587				1,686
Depreciation and amortization			1,150				1,007				608
Total costs and expenses			9,688				8,181				5,587
Operating income			2,688				2,120				1,529
Other income (expense):
Interest expense			(1,320	)			(1,152	)			(891	)
Capitalized interest			54				40				17
Interest and dividend income			105				73				58
Other income			122				239				75
Other expense			(10	)			(13	)			(23	)
Total other income (expense)			(1,049	)			(813	)			(764	)
Income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income			1,639				1,307				765
Income tax expense			(456	)			(407	)			(245	)
Minority interest and preferred dividends of subsidiaries			(30	)			(27	)			(15	)
Equity income			36				43				53
Income from continuing operations			1,189				916				558
Income from discontinued operations, net of tax			—				—				5
Net income		$	1,189			$	916			$	563

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
FOR THE THREE YEARS ENDED DECEMBER 31, 2007
(Amounts in millions)


	Common Shares			Common Stock			Additional Paid-in Capital				Retained Earnings				Accumulated Other Comprehensive Income (Loss), net				Total
Balance, January 1, 2005		9			$	—		$	1,951			$	1,157			$	(137	)		$	2,971
Net income		—				—			—				563				—				563
Other comprehensive income:
Foreign currency translation adjustment		—				—			—				—				(186	)			(186	)
Fair value adjustment on cash flow hedges, net of tax of $(10)		—				—			—				—				(20	)			(20	)
Minimum pension liability adjustment, net of tax of $18		—				—			—				—				44				44
Unrealized gains on marketable securities, net of tax of $1		—				—			—				—				1				1
Total comprehensive income																					402
Exercise of common stock options		—				—			6				—				—				6
Tax benefit from exercise of common stock options		—				—			6				—				—				6
Balance, December 31, 2005		9				—			1,963				1,720				(298	)			3,385
Net income		—				—			—				916				—				916
Other comprehensive income:
Foreign currency translation adjustment		—				—			—				—				263				263
Fair value adjustment on cash flow hedges, net of tax of $32		—				—			—				—				54				54
Minimum pension liability adjustment, net of tax of $146		—				—			—				—				338				338
Unrealized gains on marketable securities, net of tax of $2		—				—			—				—				3				3
Total comprehensive income																					1,574
Adjustment to initially apply FASB Statement No. 158, net of tax of $(160)		—				—			—				—				(367	)			(367	)
Preferred stock conversion to common stock		41				—			—				—				—				—
Exercise of common stock options		1				—			22				—				—				22
Tax benefit from exercise of common stock options		—				—			34				—				—				34
Common stock issuances		35				—			5,110				—				—				5,110
Common stock purchases		(12	)			—			(1,712	)			(38	)			—				(1,750	)
Other equity transactions		—				—			3				—				—				3
Balance, December 31, 2006		74				—			5,420				2,598				(7	)			8,011
Adoption of FASB Interpretation No. 48		—				—			—				(5	)			—				(5	)
Net income		—				—			—				1,189				—				1,189
Other comprehensive income:
Foreign currency translation adjustment		—				—			—				—				30				30
Fair value adjustment on cash flow hedges, net of tax of $17		—				—			—				—				28				28
Unrecognized amounts on retirement benefits, net of tax of $32		—				—			—				—				38				38
Unrealized gains on marketable securities, net of tax of $1		—				—			—				—				1				1
Total comprehensive income																					1,286
Exercise of common stock options		1				—			10				—				—				10
Tax benefit from exercise of common stock options		—				—			21				—				—				21
Other equity transactions		—				—			3				—				—				3
Balance, December 31, 2007		75			$	—		$	5,454			$	3,782			$	90			$	9,326

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)


	Years Ended December 31,
	2007				2006				2005
Cash flows from operating activities:
Income from continuing operations		$	1,189			$	916			$	558
Adjustments to reconcile income from continuing
operations to cash flows from continuing operations:
Gain on other items, net			(12	)			(145	)			(6	)
Depreciation and amortization			1,150				1,007				608
Amortization of regulatory assets and liabilities			(16	)			26				39
Provision for deferred income taxes			129				260				130
Other			(102	)			1				(41	)
Changes in other items, net of effects from acquisitions:
Accounts receivable and other current assets			(255	)			(39	)			(136	)
Accounts payable and other accrued liabilities			252				(103	)			159
Net cash flows from operating activities			2,335				1,923				1,311
Cash flows from investing activities:
Capital expenditures relating to operating projects			(1,693	)			(1,684	)			(796	)
Construction and other development costs			(1,819	)			(739	)			(400	)
PacifiCorp acquisition, net of cash acquired			—				(4,932	)			(5	)
Other acquisitions, net of cash acquired			—				(74	)			(5	)
Purchases of available-for-sale securities			(1,641	)			(1,504	)			(2,842	)
Proceeds from sale of available-for-sale securities			1,586				1,606				2,913
Maturity (Purchase) of guaranteed investment contracts			201				—				(557	)
Proceeds from sale of assets			65				30				103
Decrease (increase) in restricted cash			75				(32	)			27
Other			(24	)			8				4
Net cash flows from continuing operations			(3,250	)			(7,321	)			(1,558	)
Net cash flows from discontinued operations			—				—				7
Net cash flows from investing activities			(3,250	)			(7,321	)			(1,551	)
Cash flows from financing activities:
Proceeds from the issuances of common stock			10				5,132				6
Purchases of common stock			—				(1,750	)			—
Proceeds from MEHC senior debt			1,539				1,699				—
Proceeds from subsidiary and project debt			2,000				718				1,051
Repayments of MEHC senior and subordinated debt			(784	)			(234	)			(449	)
Repayments of subsidiary and project debt			(599	)			(516	)			(875	)
Net (repayments of) proceeds from MEHC revolving credit facility			(152	)			101				51
Net (repayments of) proceeds from subsidiary short-term debt			(269	)			196				10
Net proceeds from settlement of treasury rate lock agreements			32				53				—
Other			(30	)			(22	)			(13	)
Net cash flows from financing activities			1,747				5,377				(219	)
Effect of exchange rate changes			3				6				(20	)
Net change in cash and cash equivalents			835				(15	)			(479	)
Cash and cash equivalents at beginning of period			343				358				837
Cash and cash equivalents at end of period		$	1,178			$	343			$	358

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

MidAmerican Energy Holdings Company (‘‘MEHC’’) is a holding company which owns subsidiaries that are principally engaged in energy businesses. MEHC and its subsidiaries are referred to as the ‘‘Company.’’ MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. (‘‘Berkshire Hathaway’’). The Company is organized and managed as eight distinct platforms: PacifiCorp (which was acquired on March 21, 2006), MidAmerican Funding, LLC (‘‘MidAmerican Funding’’) (which primarily includes MidAmerican Energy Company (‘‘MidAmerican Energy’’)), Northern Natural Gas Company (‘‘Northern Natural Gas’’), Kern River Gas Transmission Company (‘‘Kern River’’), CE Electric UK Funding Company (‘‘CE Electric UK’’) (which primarily includes Northern Electric Distribution Limited (‘‘Northern Electric’’) and Yorkshire Electricity Distribution plc (‘‘Yorkshire Electricity’’)), CalEnergy Generation-Foreign (owning a majority interest in the Casecnan project), CalEnergy Generation-Domestic (owning interests in independent power projects in the United States), and HomeServices of America, Inc. (collectively with its subsidiaries, ‘‘HomeServices’’). Through these platforms, the Company owns and operates an electric utility company in the Western United States, a combined electric and natural gas utility company in the Midwestern United States, two interstate natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of independent power projects and the second largest residential real estate brokerage firm in the United States.

The Consolidated Financial Statements include the accounts of MEHC and its subsidiaries in which it holds a controlling financial interest. The Consolidated Statements of Operations include the revenues and expenses of an acquired entity from the date of acquisition.

The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America (‘‘GAAP’’) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. These estimates include, but are not limited to, unbilled receivables, valuation of energy contracts, the effects of regulation, long-lived asset recovery, goodwill impairment, the accounting for contingencies, including environmental, regulatory and income tax matters, and certain assumptions made in accounting for pension and other postretirement benefits. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.

Cash equivalents consist of funds invested in commercial paper, money market securities and in other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where the availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in other current assets and deferred charges, investments and other assets in the Consolidated Balance Sheets.

The Company’s management determines the appropriate classifications of investments in debt and equity securities at the acquisition date and re-evaluates the classifications at each balance sheet date. The Company’s investments in debt and equity securities are primarily classified as available-for-sale.

Available-for-sale securities are stated at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in accumulated other comprehensive income (‘‘AOCI’’), net of tax. Realized and unrealized gains and losses on certain trust funds related to the decommissioning of nuclear generation assets and the final reclamation of leased coal mining property are recorded as regulatory assets or liabilities since the Company expects to recover costs for these activities through rates.

The Company utilizes the equity method of accounting with respect to investments where it exercises significant influence, but not control, over the operating and financial policies of the investee. The equity method of accounting is normally applied where the Company has a voting interest of at least 20% and no greater than 50%. In applying the equity method, investments are recorded at cost and subsequently increased or decreased by the Company’s proportionate share of the net earnings or losses of the investee. The Company also records its proportionate share of other comprehensive income items of the investee as a component of its comprehensive income. Dividends or other equity distributions are recorded as a reduction of the investment. Equity investments are required to be tested for impairment when it is determined that an other-than-temporary loss in value below the carrying amount has occurred.

PacifiCorp, MidAmerican Energy, Northern Natural Gas and Kern River (the ‘‘Domestic Regulated Businesses’’) prepare their financial statements in accordance with the provisions of Statement of Financial Accounting Standards (‘‘SFAS’’) No. 71, ‘‘Accounting for the Effects of Certain Types of Regulation,’’ (‘‘SFAS No. 71’’) which differs in certain respects from the application of GAAP by non-regulated businesses. In general, SFAS No. 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated entity is required to defer the recognition of costs or income if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, the Domestic Regulated Businesses have deferred certain costs and income that will be recognized in earnings over various future periods.

Management continually evaluates the applicability of SFAS No. 71 and assesses whether its regulatory assets are probable of future recovery by considering factors such as a change in the regulator’s approach to setting rates from cost-based rate making to another form of regulation, other regulatory actions or the impact of competition which could limit the Company’s ability to recover its costs. Based upon this continual assessment, management believes the application of SFAS No. 71 continues to be appropriate and its existing regulatory assets are probable of recovery. The assessment reflects the current political and regulatory climate at both the state and federal levels and is subject to change in the future. If it becomes no longer probable that these costs will be recovered, the regulatory assets and regulatory liabilities would be written off and recognized in operating income.

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 ability of customers to pay the amounts owed to the Company and the outcome of pending disputes and arbitrations. As of December 31, 2007 and 2006, the allowance for doubtful accounts totaled $22 million and $30 million, respectively.

The Company employs a number of different derivative instruments in connection with its electric and natural gas, foreign currency exchange rate and interest rate risk management activities, including forward purchases and sales, futures, swaps and options. Derivative instruments are recorded in the Consolidated Balance Sheets at fair value as either assets or liabilities unless they are designated and qualify for the normal purchases and normal sales exemption afforded by GAAP. Contracts that qualify as normal purchases or normal sales are not marked to market. Derivative contracts for

commodities used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases and normal sales pursuant to the exemption. Recognition of these contracts in operating revenue or cost of sales in the Consolidated Statements of Operations occurs when the contracts settle.

For contracts designated in hedge relationships (‘‘hedge contracts’’), the Company maintains formal documentation of the hedge. In addition, at inception and on a quarterly basis, the Company formally assesses whether the hedge contracts are highly effective in offsetting changes in cash flows or fair values of the hedged items. The Company documents hedging activity by transaction type and risk management strategy.

Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective, are included in the Consolidated Statements of Shareholders’ Equity as AOCI, net of tax, until the hedged item is recognized in earnings. The Company discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, future changes in the value of the derivative are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in AOCI will remain in AOCI until the hedged item is realized, unless it is probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in current earnings.

Certain derivative electric and gas contracts utilized by the regulated operations of PacifiCorp and MidAmerican Energy are recoverable through rates. Accordingly, unrealized changes in fair value of these contracts are deferred as net regulatory assets or liabilities pursuant to SFAS No. 71.

When available, quoted market prices or prices obtained through external sources are used to measure a contract’s fair value. For contracts without available quoted market prices, fair value is determined based on internally developed modeled prices. The fair value of these instruments is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of the contracts.

Inventories consist mainly of materials and supplies, coal stocks, gas in storage and fuel oil, which are valued at the lower of cost or market. The cost of materials and supplies, coal stocks and fuel oil is determined primarily using average cost. The cost of gas in storage is determined using the last-in-first-out (‘‘LIFO’’) method. With respect to inventories carried at LIFO cost, the cost determined under the first-in-first-out method would be $73 million and $77 million higher as of December 31, 2007 and 2006, respectively.

Property, plant and equipment is recorded at historical cost. The Company capitalizes all construction related material, direct labor costs and contract services, as well as indirect construction costs, which include capitalized interest and equity allowance for funds used during construction (‘‘AFUDC’’). The cost of major additions and betterments are capitalized, while costs for replacements, maintenance, and repairs that do not improve or extend the lives of the respective assets are charged to operating expense. Depreciation and amortization are generally computed by applying the composite and straight-line method based on estimated economic lives or regulatorily mandated recovery periods. Periodic depreciation studies are performed to determine the appropriate group lives, net salvage and group depreciate rates. The Company believes the useful lives assigned to the depreciable assets, which range from 3 to 85 years, are reasonable.

Generally when the Company retires or sells its domestic regulated property, plant and equipment, it charges the original cost to accumulated depreciation. Any net cost of removal is

charged against the cost of removal regulatory liability that was established through depreciation rates. Net salvage is recorded in the related accumulated depreciation and amortization accounts and the residual gain or loss is deferred and subsequently amortized through future depreciation expense. Any gain or loss on disposals of all other assets is recorded in income or expense.

The Domestic Regulated Businesses record AFUDC, which represents the estimated debt and equity costs of capital funds necessary to finance the construction of domestic regulated facilities. AFUDC is capitalized as a component of property, plant and equipment cost, with offsetting credits to the Consolidated Statements of Operations. After construction is completed, the Company is permitted to earn a return on these costs by their inclusion in rate base, as well as recover these costs through depreciation expense over the useful life of the related assets.

The Company recognizes legal asset retirement obligations (‘‘ARO’’), mainly related to the decommissioning of nuclear generation assets and the final reclamation of leased coal mining property. The fair value of a liability for a legal ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the liability is adjusted for any material revisions to the expected value of the retirement obligation (with corresponding adjustments to property, plant and equipment) and for accretion of the liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability. Estimated removal costs that PacifiCorp and MidAmerican Energy recover through approved depreciation rates, but that do not meet the requirements of a legal ARO, are accumulated in asset retirement removal costs within regulatory liabilities in the Consolidated Balance Sheets.

The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable, or the assets meet the criteria of held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated discounted present value of the expected future cash flows from using the asset. For regulated assets, any impairment charge is offset by the establishment of a regulatory asset to the extent recovery in rates is probable. For all other assets, any resulting impairment loss is reflected in the Consolidated Statements of Operations.

Goodwill represents the difference between purchase cost and the fair value of net assets acquired in business acquisitions. Goodwill is allocated to each reporting unit and is tested for impairment using a variety of methods, principally discounted projected future net cash flows, at least annually and impairments, if any, are charged to earnings. The Company completed its annual review as of October 31. Key assumptions used in the testing include, but are not limited to, the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, the Company incorporates current market information as well as historical factors. During 2007, 2006 and 2005, the Company did not record any goodwill impairments.

The Company records goodwill adjustments for (i) changes in the estimates or the settlement of tax bases of acquired assets, liabilities and carryforwards and items relating to acquired entities’ prior income tax returns, (ii) the tax benefit associated with the excess of tax-deductible goodwill over the reported amount of goodwill, and (iii) changes to the purchase price allocation prior to the end of the allocation period, which is generally one year from the acquisition date.

Revenue from electric customers is recognized as electricity is delivered and includes amounts for services rendered. Revenue from the sale, distribution and transportation of natural gas is recognized when either the service is provided or the product is delivered. Revenue recognized includes unbilled as well as billed amounts.

Rates charged by the domestic regulated energy businesses are subject to federal and state regulation. When preliminary rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a provision for estimated refunds is accrued. Electric distribution revenues in the U.K. are limited to amounts allowed under their regulatory formula while under-recoveries are not recognized in revenue. Over- or under-recoveries of amounts allowed under the regulatory formula are either refunded to customers or recovered through adjustments in future rates.

Electricity and water is delivered in the Philippines pursuant to provisions of the respective project agreements which are accounted for as arrangements that contain both a lease and a service contract. The leases are classified as operating due to significant uncertainty regarding the collection of future amounts mainly due to the existence of political, economic and other uncertainties in the Philippines. The majority of the revenue under these arrangements is fixed.

The Company records sales, franchise and excise taxes, which are collected directly from customers and remitted directly to the taxing authorities, on a net basis in the Consolidated Statements of Operations.

Commission revenue from real estate brokerage transactions and related amounts due to agents are recognized when a real estate transaction is closed. Title fee revenue from real estate transactions and related amounts due to the title insurer are recognized at closing.

Premiums, discounts and financing costs incurred during the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.

The accounts of foreign-based subsidiaries are measured in most instances using the local currency as the functional currency. Revenue and expenses of these businesses are translated into U.S. dollars at the average exchange rate for the period. Assets and liabilities are translated at the exchange rate as of the end of the reporting period. Gains or losses from translating the financial statements of foreign-based operations are included in shareholders’ equity as a component of AOCI. Gains or losses arising from other transactions denominated in a foreign currency are included in the Consolidated Statements of Operations.

Berkshire Hathaway commenced including the Company in its U.S. federal income tax return in 2006 as a result of converting its convertible preferred stock of MEHC into shares of MEHC common stock on February 9, 2006. The Company’s provision for income taxes has been computed on a stand-alone basis. Prior to the conversion, the Company filed a consolidated U.S. federal income tax return.

Deferred tax assets and liabilities are based on differences between the financial statements and tax bases of assets and liabilities using the estimated tax rates in effect for the year in which the

differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of other comprehensive income are charged or credited directly to other comprehensive income. Changes in deferred income tax assets and liabilities that are associated with income tax benefits related to certain property-related basis differences and other various differences that PacifiCorp and MidAmerican Energy are required to pass on to their customers in most state jurisdictions are charged or credited directly to a regulatory asset or regulatory liability. These amounts were recognized as a net regulatory asset totaling $606 million and $581 million as of December 31, 2007 and December 31, 2006, respectively, and will be included in rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Valuation allowances have been established for certain deferred tax assets where management has judged that realization is not likely.

Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory jurisdictions.

The Company has not provided U.S. federal deferred income taxes on its currency translation adjustment or the cumulative earnings of international subsidiaries that have been determined by management to be reinvested indefinitely. The cumulative earnings related to ongoing operations were approximately $1.5 billion as of December 31, 2007. Because of the availability of U.S. foreign tax credits, it is not practicable to determine the U.S. federal income tax liability that would be payable if such earnings were not reinvested indefinitely. Deferred taxes are provided for earnings of international subsidiaries when the Company plans to remit those earnings.

In determining the Company’s tax liabilities, management is required to interpret complex tax laws and regulations. In preparing tax returns, the Company is subject to continuous examinations by federal, state, local and foreign tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The U.S. Internal Revenue Service has closed examination of the Company’s income tax returns through 2003. In the U.K., each legal entity is subject to examination by HM Revenue and Customs (‘‘HMRC’’), the U.K. equivalent of the U.S. Internal Revenue Service. HMRC has closed examination of income tax returns for the separate entities from 2000 to 2005. Most significantly, Northern Electric’s and Yorkshire Electricity’s examinations are closed through 2001. In addition, open tax years related to a number of state and other foreign jurisdictions remain subject to examination. Although the ultimate resolution of the Company’s federal, state and foreign tax examinations is uncertain, the Company believes it has made adequate provisions for these tax positions and the aggregate amount of any additional tax liabilities that may result from these examinations, if any, will not have a material adverse affect on the Company’s financial results. The Company’s unrecognized tax benefits are primarily included in other long-term accrued liabilities in the Consolidated Balance Sheets. The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense in the Consolidated Statements of Operations.

In July 2006, the Financial Accounting Standards Board (‘‘FASB’’) issued FASB Interpretation No. 48, ‘‘Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109’’ (‘‘FIN 48’’). The Company adopted the provisions of FIN 48 effective January 1, 2007. Under FIN 48, tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50% likely to be realized upon ultimate settlement. Unrecognized tax benefits are tax benefits claimed in the Company’s tax returns that do not meet these recognition and measurement standards. Refer to Note 15 for additional discussion.

In December 2007, the FASB issued Statement of Financial Accounting Standards (‘‘SFAS’’) No. 141(R), ‘‘Business Combinations’’ (‘‘SFAS No. 141(R)’’). SFAS No. 141(R) applies to all transactions or other events in which an entity obtains control of one or more businesses. SFAS No. 141(R) establishes how the acquirer of a business should recognize, measure and disclose in its

financial statements the identifiable assets and goodwill acquired, the liabilities assumed and any noncontrolling interest in the acquired business. SFAS No. 141(R) is applied prospectively for all business combinations with an acquisition date on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, with early application prohibited. SFAS No. 141(R) will not have an impact on the Company’s historical Consolidated Financial Statements and will be applied to business combinations completed, if any, on or after January 1, 2009.

In February 2007, the FASB issued SFAS No. 159, ‘‘The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FASB Statement No. 115’’ (‘‘SFAS No. 159’’). SFAS No. 159 permits entities to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS No. 159, an entity may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option should only be made at initial recognition of the asset or liability or upon a remeasurement event that gives rise to new-basis accounting. The decision about whether to elect the fair value option is applied on an instrument-by-instrument basis, is irrevocable and is applied only to an entire instrument and not only to specified risks, cash flows or portions of that instrument. SFAS No. 159 does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value nor does it eliminate disclosure requirements included in other accounting standards. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Company does not anticipate electing the fair value option for any existing eligible items. However, the Company will continue to evaluate items on a case-by-case basis for consideration of the fair value option.

In September 2006, the FASB issued SFAS No. 157, ‘‘Fair Value Measurements’’ (‘‘SFAS No. 157’’). SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 does not impose fair value measurements on items not already accounted for at fair value; rather it applies, with certain exceptions, to other accounting pronouncements that either require or permit fair value measurements. Under SFAS No. 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal or most advantageous market. The standard clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating the impact of adopting SFAS No. 157 on its consolidated financial position and results of operations.

In September 2006, the FASB issued SFAS No. 158, ‘‘Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R)’’ (‘‘SFAS No. 158’’). The Company adopted the recognition and related disclosure provisions of SFAS No. 158 as of December 31, 2006. SFAS No. 158 also requires that an employer measure plan assets and obligations as of the end of the employer’s fiscal year, eliminating the option in SFAS No. 87 and SFAS No. 106 to measure up to three months prior to the financial statement date. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end is not required until fiscal years ending after December 15, 2008. As of December 31, 2007, PacifiCorp had not yet adopted the measurement date provisions of the statement. Upon adoption of the measurement date provisions, PacifiCorp will be required to record a

transitional adjustment to retained earnings or to a regulatory asset depending on whether the amount is considered probable of being recovered in rates.

In May 2005, MEHC reached a definitive agreement with Scottish Power plc (‘‘ScottishPower’’) and its subsidiary, PacifiCorp Holdings, Inc., to acquire 100% of the common stock of ScottishPower’s wholly-owned indirect subsidiary, PacifiCorp. On March 21, 2006, a wholly owned subsidiary of MEHC acquired 100% of the common stock of PacifiCorp from a wholly owned subsidiary of ScottishPower for a cash purchase price of $5.11 billion, which was funded through the issuance of common stock (see Note 17). MEHC also incurred $10 million of direct transaction costs associated with the acquisition, which consisted principally of investment banker commissions and outside legal and accounting fees, resulting in a total purchase price of $5.12 billion. As a result of the acquisition, MEHC controls substantially all of PacifiCorp’s voting securities, which include both common and preferred stock. The results of PacifiCorp’s operations are included in the Company’s results beginning March 21, 2006 (the ‘‘acquisition date’’).

The total purchase price was allocated to PacifiCorp’s net tangible and identified intangible assets acquired and liabilities assumed based on their estimated fair values at the acquisition date. PacifiCorp’s operations are regulated and are accounted for pursuant to SFAS No. 71. PacifiCorp has demonstrated a past history of recovering its costs incurred through its rate making process. Certain adjustments, which were not significant, related to derivative contracts, severance costs and income taxes were made to the purchase price allocation. The following table summarizes the adjusted fair values of the assets acquired and liabilities assumed as of the acquisition date (in millions):

Certain transition activities, pursuant to established plans, were undertaken as PacifiCorp was integrated into the Company. Costs, relating primarily to employee termination activities, have been incurred associated with such transition activities, which were completed as of March 31, 2007. The finalization of certain integration plans resulted in adjustments to the purchase price allocation for the acquired assets and assumed liabilities of PacifiCorp. Qualifying severance costs accrued during the three-month period ended March 31, 2007, and the period from the acquisition date to December 31, 2006, totaled $7 million and $41 million, respectively. Accrued severance costs were $34 million and $31 million as of March 31, 2007 and December 31, 2006, respectively.

The following pro forma condensed consolidated results of operations assume that the acquisition of PacifiCorp was completed as of January 1, 2005, and provides information for the years ended December 31 (in millions):

The pro forma financial information represents the historical operating results of the combined company with adjustments for purchase accounting and is not necessarily indicative of the results of operations that would have been achieved if the acquisition had taken place at the beginning of each period presented.

Property, plant and equipment, net consist of the following as of December 31 (in millions):

Substantially all of the construction in progress as of December 31, 2007 and 2006 relates to the construction of regulated assets.

Northern Natural Gas entered into a purchase and sale agreement for the West Hugoton non-strategic section of its interstate pipeline system in the fourth quarter of 2005. As a result of entering into the purchase and sale agreement, Northern Natural Gas recognized a non-cash impairment charge of $29 million ($18 million after-tax) to write down the carrying value of the asset to its fair value. The fair value was determined based on the agreed sale price. The impairment charge is recorded in operating expense in the accompanying Consolidated Statements of Operations for the year ended December 31, 2005.

Under joint plant ownership agreements with other utilities, both PacifiCorp and MidAmerican Energy, as tenants in common, have undivided interests in jointly owned generation and transmission facilities. The Company accounts for its proportional share of each facility, and each joint owner has provided financing for its share of each generating plant or transmission line. Operating costs of each

facility are assigned to joint owners based on ownership percentage or energy purchased, depending on the nature of the cost. Operating expenses in the Consolidated Statements of Operations include the Company’s share of the expenses of these facilities.

The amounts shown in the table below represent the Company’s share in each jointly owned facility as of December 31, 2007 (dollars in millions):


	Company Share			Plant in Service			Accumulated Depreciation/ Amortization			Construction Work-in- Progress
PacifiCorp:
Jim Bridger Nos. 1-4		67	%		$	965		$	482		$	13
Wyodak		80				329			168			1
Hunter No. 1		94				304			146			1
Colstrip Nos. 3 and 4		10				243			118			1
Hunter No. 2		60				192			87			1
Hermiston⁽¹⁾		50				170			37			2
Craig Nos. 1 and 2		19				167			77			1
Hayden No. 1		25				44			20			1
Foote Creek		79				37			13			—
Hayden No. 2		13				27			14			—
Other transmission and distribution plants	Various					80			20			2
Total PacifiCorp						2,558			1,182			23
MidAmerican Energy:
Walter Scott, Jr. Unit No. 4		60	%			634			10			—
Louisa Unit No. 1		88				750			352			1
Walter Scott, Jr. Unit No. 3		79				345			227			86
Quad Cities Unit Nos. 1 and 2		25				320			149			9
Ottumwa Unit No. 1		52				264			147			3
George Neal Unit No. 4		41				169			123			—
George Neal Unit No. 3		72				142			105			2
Transmission facilities	Various					169			46			—
Total MidAmerican Energy						2,793			1,159			101
Total					$	5,351		$	2,341		$	124

Regulatory assets represent costs that are expected to be recovered in future rates. The Company’s regulatory assets reflected in the Consolidated Balance Sheets consist of the following as of December 31 (in millions):

The Company had regulatory assets not earning a return or earning less than the stipulated return as of December 31, 2007 and 2006 of $1.3 billion and $1.7 billion, respectively.

Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. The Company’s regulatory liabilities reflected in the Consolidated Balance Sheets consist of the following as of December 31 (in millions):

The Iowa Utilities Board (‘‘IUB’’) has approved a series of settlement agreements between MidAmerican Energy, the Iowa Office of Consumer Advocate (‘‘OCA’’) and other intervenors, under

which MidAmerican Energy has agreed not to seek a general increase in electric base rates to become effective prior to January 1, 2014, unless its Iowa jurisdictional electric return on equity for any year covered by the applicable agreement falls below 10%, computed as prescribed in each respective agreement. Prior to filing for a general increase in electric rates, MidAmerican Energy is required to conduct 30 days of good faith negotiations with the signatories to the settlement agreements to attempt to avoid a general increase in such rates. As a party to the settlement agreements, the OCA has agreed not to request or support any decrease in MidAmerican Energy’s Iowa electric base rates to become effective prior to January 1, 2014. The settlement agreements specifically allow the IUB to approve or order electric rate design or cost of service rate changes that could result in changes to rates for specific customers as long as such changes do not result in an overall increase in revenues for MidAmerican Energy.

The settlement agreements also each provide that revenues associated with Iowa retail electric returns on equity within specified ranges will be shared with customers and that the portion assigned to customers will be recorded as a regulatory liability. The following table summarizes the ranges of Iowa electric returns on equity subject to revenue sharing under each settlement agreement, the percent of revenues within those ranges to be assigned to customers, and the method by which the liability to customers will be settled.

Date Approved
by the IUB

Years
Covered

Range of
Iowa Electric
Return on
Equity Subject
to Sharing

Customers’
Share of
Revenues
Within Range

Method to be Used to
Settle Liability to
Customers

December 21, 2001

2001-2005

12%-14%
Above 14%

50%
83.33%

Credits against the cost of new generation plant in Iowa

October 17, 2003

2006-2010

11.75%-13%
13%-14%
Above 14%

40%
50%
83.3%

Credits against the cost of new generation plant in Iowa

January 31, 2005

2011

Same as 2006-2010

Credits to customer bills in 2012

April 18, 2006

2012

Same as 2006-2010

Credits to customer bills in 2013

July 27, 2007

2013

Same as 2006-2010⁽¹⁾

Credits against the cost of wind-powered generation projects covered by this agreement

The regulatory liabilities created by the settlement agreements have been and are currently recorded as a regulatory charge in depreciation and amortization expense when the liability is accrued. As a result of the credits applied to generating plant balances when the related plant is placed in service, depreciation expense is reduced over the life of the plant. On June 1, 2007, WSEC Unit 4 was placed in service. Accordingly, the January 1, 2007 balance of the revenue sharing liability of $264 million, plus the related interest accrued in 2007, was applied against the cost of WSEC Unit 4 in utility generation, distribution and transmission system.

Kern River’s 2004 general rate case hearing concluded in August 2005. On March 2, 2006, Kern River received an initial decision on the case from the administrative law judge. On October 19, 2006,

the Federal Energy Regulatory Commission (‘‘FERC’’) issued an order that modified certain aspects of the administrative law judge’s initial decision, including changing the allowed return on equity from 9.34% to 11.2% and granting Kern River an income tax allowance. The order also affirmed the rejection of certain issues included in Kern River’s filed position, including the load factors to be used in calculating rates for the vintage system. The FERC determined that a 100% load factor should be used in the rate calculation rather than the 95% load factor requested by Kern River. The FERC also rejected a 3% inflation factor for certain operating expenses and a shorter useful life for certain plant. Kern River and other parties filed their requests for rehearing of the initial order on November 20, 2006. Kern River submitted its compliance filing, which sets forth compliance rates in accordance with the initial order, on December 18, 2006. A final order on the request for rehearing and compliance filing is not expected until after the FERC finalizes its proposed policy statement that addresses the inclusion of master limited partnerships in the proxy group used to determine a pipeline’s allowed return on equity. Rate refunds will be due within 30 days after a final order on Kern River’s rate case is issued. Kern River was permitted to bill the requested rate increase prior to final approval by the FERC, subject to refund, beginning effective November 1, 2004. Since that time, Kern River has recorded a provision for estimated refunds. As a result of the October 19, 2006 order, additional customer billings and the accrual of interest, the liability for rates subject to refund increased $78 million during 2006 to $107 million as of December 31, 2006. As of December 31, 2007, the liability for rates subject to refund was $191 million.

In October 2007, PacifiCorp filed its first tax report under Oregon Senate Bill 408 (‘‘SB 408’’), which was enacted in September 2005. SB 408 requires that PacifiCorp and other large regulated, investor-owned utilities that provide electric or natural gas service to Oregon customers file an annual tax report with the Oregon Public Utility Commission (‘‘OPUC’’). PacifiCorp’s filing indicates that in 2006, PacifiCorp paid $33 million more in federal, state and local taxes than was collected in rates from its retail customers. PacifiCorp proposes to amortize $27 million of the surcharge over a one year period, which would result in an average price increase of 3%. If the OPUC issues an order providing for recovery in excess of $27 million and allows the deferral of the excess, the portion not yet recovered will be tracked in a balancing account accruing interest at PacifiCorp’s weighted cost of capital. The deferred amount, if any, would be addressed in a subsequent SB 408 filing. The 2006 tax report is currently being challenged during the 180-day procedural schedule that follows the date of the filing, with rates potentially effective June 2008. PacifiCorp expects to file its 2007 tax report under SB 408 during the fourth quarter of 2008. PacifiCorp has not recorded any amounts related to either the 2006 tax report or the 2007 expected filing.

Noncurrent investments are included in deferred charges, investments and other assets in the Consolidated Balance Sheets as management does not intend to use them in current operations. Gross unrealized and realized gains and losses of investments are not material as of December 31, 2007 and 2006 and for the three years in the period ended December 31, 2007, respectively.

In May 2005, certain indirect wholly owned subsidiaries of CE Electric UK purchased £300 million of fixed rate guaranteed investment contracts (£100 million at 4.75% and £200 million at 4.73%) with a portion of the proceeds of the issuance of £350 million of 5.125% bonds due in 2035. These guaranteed investment contracts matured in December 2007 (£100 million) and February 2008 (£200 million) and the proceeds were used to repay certain long-term debt of subsidiaries of CE Electric UK. The guaranteed investment contracts were reported at cost.

MidAmerican Energy has established trusts for the investment of funds for decommissioning the Quad Cities Nuclear Station Units 1 and 2. These investments in debt and equity securities are classified as available-for-sale and are reported at fair value. Funds are invested in the trust in accordance with applicable federal investment guidelines and are restricted for use as reimbursement for costs of decommissioning the Quad Cities Station. As of December 31, 2007, 54% of the fair value of the trusts’ funds was invested in domestic common equity securities, 22% in domestic corporate debt securities and the remainder in investment grade municipal and U.S. Treasury bonds. As of December 31, 2006, 56% of the fair value of the trusts’ funds was invested in domestic common equity securities, 13% in domestic corporate debt securities and the remainder in investment grade municipal and U.S. Treasury bonds.

PacifiCorp has established a trust for the investment of funds for final reclamation of a leased coal mining property. These investments in debt and equity securities are classified as available-for-sale and are reported at fair value. Amounts funded are based on estimated future reclamation costs and estimated future coal deliveries. As of December 31, 2007 and 2006, 52% and 56%, respectively, of the fair value of the trust’s funds was invested in equity securities with the remainder invested in debt securities.

The Company has invested in AAA-rated interest bearing auction rate securities with remaining maturities of 9 to 29 years. These auction rate securities normally provide liquidity via an auction process that resets the applicable interest rate at predetermined calendar intervals, usually every 28 days or less. Interest on these securities has been paid on the scheduled auction dates. During the third and fourth quarters of 2007, auctions for the $73 million of the Company’s investments in auction rate securities failed. The failures resulted in the interest rate on these investments resetting at higher levels. Although there is no current liquid market for the auction rate securities, the Company believes the underlying creditworthiness of the repayment sources for these securities’ principal and interest has not materially deteriorated. Therefore, the fair value of these investments approximates the carrying amount as of December 31, 2007.

MEHC has a $600 million unsecured credit facility expiring in July 2012. The credit facility has a variable interest rate based on the London Interbank Offered Rate (‘‘LIBOR’’) plus 0.195%, which varies based on MEHC’s credit ratings for its senior unsecured long-term debt securities, or a base rate, at MEHC’s option. The credit facility supports letters of credit for the benefit of certain subsidiaries and affiliates. As of December 31, 2007, MEHC had no borrowings outstanding under its credit facility and had letters of credit issued under the credit agreement totaling $46 million. As of

December 31, 2006, the outstanding balance of the credit facility totaled $152 million, at an interest rate of 5.57%, and letters of credit issued under the credit agreement totaled $60 million. The related credit agreement requires that MEHC’s ratio of consolidated debt to total capitalization, including current maturities, not exceed 0.70 to 1.0 as of the last day of any quarter.

At December 31, 2007, PacifiCorp had $1.5 billion available under its unsecured revolving credit facilities. During 2007, PacifiCorp entered into an unsecured revolving credit facility with total bank commitments of $700 million available through October 23, 2012. Under PacifiCorp’s previously existing unsecured revolving credit facility, $800 million is available through July 6, 2011 and $760 million is available from July 7, 2011 through July 6, 2012. Each credit facility includes a variable interest rate borrowing option based on LIBOR plus 0.195% that varies based on PacifiCorp’s credit ratings for its senior unsecured long-term debt securities and supports PacifiCorp’s commercial paper program. As of December 31, 2007, PacifiCorp had no borrowings outstanding under either credit facility. As of December 31, 2006, PacifiCorp had $397 million of commercial paper arrangements outstanding at an average interest rate of 5.3% and no borrowings outstanding under its revolving credit agreement. Each revolving credit agreement requires that PacifiCorp’s ratio of consolidated debt to total capitalization, including current maturities, at no time exceed 0.65 to 1.0.

MidAmerican Energy has a $500 million unsecured revolving credit facility expiring in July 2012. The credit facility has a variable interest rate based on the LIBOR plus 0.115% that varies based on MidAmerican Energy’s credit ratings for its senior unsecured long-term debt securities and supports MidAmerican Energy’s $380 million commercial paper program and its variable rate pollution control revenue obligations. MidAmerican Energy had $86 million of commercial paper arrangements outstanding as of December 31, 2007, at an average rate of 4.46%, and no borrowings outstanding under its revolving credit agreement as of December 31, 2007 and 2006. The related credit agreement requires that MidAmerican Energy’s ratio of consolidated debt to total capitalization, including current maturities, not exceed 0.65 to 1.0 as of the last day of any quarter.

CE Electric UK has a £100 million unsecured revolving credit facility expiring in April 2010. The facility carries a variable interest rate based on sterling LIBOR plus 0.25% to 0.40% that varies based on its credit ratings. As of December 31, 2007, the outstanding balance of the credit facility totaled $44 million, at an interest rate of 5.961%, and there were no borrowings outstanding under the facility as of December 31, 2006. The related credit agreement requires that CE Electric UK’s ratio of consolidated senior net debt to regulated asset value, including current maturities, not exceed 0.8 to 1.0 at CE Electric UK and 0.65 to 1.0 at Northern Electric and Yorkshire Electricity as of June 30 and December 31. Additionally, CE Electric UK’s interest coverage ratio can not exceed 2.5 to 1.0.

CE Electric UK also has a £15 million unsecured, uncommitted line of credit, which was not drawn on as of December 31, 2007 and 2006. The interest rate of this uncommitted line of credit as of December 31, 2007 is variable based on sterling LIBOR plus 0.40%.

HomeServices has a $125 million unsecured senior revolving credit facility expiring in December 2010. The facility carries a variable interest rate based on the prime lending rate or LIBOR, at HomeServices’ option, plus 0.5% to 1.125%, that varies based on HomeServices’ total debt ratio. The spread was 0.5% as of December 31, 2007 and 2006. As of December 31, 2007 and 2006 there were no borrowings outstanding under the facility. The related credit agreement requires that HomeServices’ ratio of consolidated total debt to earnings before interest, taxes, depreciation and amortization (‘‘EBITDA’’) not exceed 3.0 to 1.0 at the end of any fiscal quarter and its ratio of EBITDA to interest can not be less than 2.5 to 1.0 at the end of any fiscal quarter.

MEHC senior debt represents unsecured senior obligations of MEHC and consists of the following, including fair value adjustments and unamortized premiums and discounts, as of December 31 (in millions):

MEHC subordinated debt consists of the following, including fair value adjustments, as of December 31 (in millions):

The Capital Trusts were formed for the purpose of issuing trust preferred securities to holders and investing the proceeds received in subordinated debt issued by MEHC. The terms of the MEHC subordinated debt are substantially identical to those of the trust preferred securities. The MEHC subordinated debt associated with the CalEnergy Trusts is callable at the option of MEHC at any time at par value plus accrued interest. The MEHC subordinated debt associated with the MidAmerican Capital Trusts is not callable by MEHC except upon the limited occurrence of specified events. Distributions on the MEHC subordinated debt are payable either quarterly or semi-annually, depending on the issue, in arrears, and can be deferred at the option of MEHC for up to five years. During the deferral period, interest continues to accrue on the CalEnergy Capital Trusts at their stated rates, while interest accrues on the MidAmerican Capital Trusts at 13% per annum. The CalEnergy Capital Trust preferred securities are convertible any time into cash at the option of the holder for an aggregate amount of $284 million.

The MidAmerican Capital Trusts preferred securities are held by Berkshire Hathaway and its affiliates, which are prohibited from transferring the securities absent an event of default to non-affiliated persons. Interest expense to Berkshire Hathaway for the years ended December 31, 2007, 2006 and 2005 was $108 million, $134 million and $157 million, respectively. Interest expense on the CalEnergy Capital Trusts for the years ended December 31, 2007, 2006 and 2005 was $28 million, $27 million and $27 million, respectively.

The MEHC subordinated debt is subordinated to all senior indebtedness of MEHC and is subject to certain covenants, events of default and optional and mandatory redemption provisions, all described in the indenture. Upon involuntary liquidation, the holder is entitled to par value plus any

distributions in arrears. MEHC has agreed to pay to the holders of the trust preferred 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 preferred securities.

MEHC’s direct and indirect subsidiaries are organized as legal entities separate and apart from MEHC and its other subsidiaries. Pursuant to separate financing agreements, substantially all or most of the properties of each of the Company’s subsidiaries (except CE Electric UK, all of MidAmerican Energy’s gas and non-Iowa electric utility properties and Northern Natural Gas) are pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. It should not be assumed that the assets of any subsidiary will be available to satisfy MEHC’s obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets which are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MEHC or affiliates thereof. The long-term debt of subsidiaries and projects may include provisions that allow MEHC’s subsidiaries to redeem it in whole or in part at any time. These provisions generally include make-whole premiums.

Distributions at these separate legal entities are limited by various covenants including, among others, leverage ratios, interest coverage ratios and debt service coverage ratios. As of December 31, 2007, all subsidiaries were in compliance with their covenants. However, Cordova Energy’s 537 MW gas-fired power plant in the Quad Cities, Illinois area is currently prohibited from making distributions by the terms of its indenture due to its failure to meet its debt service coverage ratio requirement.

Long-term debt of subsidiaries and projects consists of the following, including fair value adjustments and unamortized premiums and discounts, as of December 31 (in millions):

The components of PacifiCorp’s long-term debt consist of the following, including unamortized premiums and discounts, as of December 31 (dollars in millions):


	Par Value			2007			2006
First mortgage bonds:
4.3% to 9.2%, due through 2012		$	1,169		$	1,169		$	1,294
5.0% to 8.8%, due 2013 to 2017			442			441			441
8.1% to 8.5%, due 2018 to 2022			175			175			175
6.7% to 8.2%, due 2023 to 2026			249			249			249
7.7% due 2031			300			299			299
5.3% to 6.3%, due 2034 to 2037			2,050			2,047			847
Pollution-control revenue obligations:
Variable rate series (2007-3.5% to 3.8%, 2006-3.9% to 4.0%):
Due 2013, secured by first mortgage bonds⁽¹⁾			41			41			41
Due 2014 to 2025⁽¹⁾			325			325			325
Due 2024, secured by first mortgage bonds⁽¹⁾			176			176			176
3.4% to 5.7%, due 2014 to 2025, secured by first mortgage bonds			184			183			183
6.2%, due 2030			13			13			13
Mandatorily Redeemable Preferred Stock, due 2007			—			—			38
Capital lease obligations — 10.4% to 14.8%, due through 2036			49			49			50
		$	5,173		$	5,167		$	4,131

As of December 31, 2007, PacifiCorp had $518 million of standby letters of credit and standby bond purchase agreements available to provide credit enhancement and liquidity support for variable-rate pollution-control revenue bond obligations.

The components of MidAmerican Funding’s senior notes and bonds consist of the following, including fair value adjustments, as of December 31 (dollars in millions):

MidAmerican Funding’s subsidiaries must make payments on their own indebtedness before making distributions to MidAmerican Funding. The distributions are also subject to utility regulatory restrictions agreed to by MidAmerican Energy in March 1999, whereby it committed to the IUB to use commercially reasonable efforts to maintain an investment grade rating on its long-term debt and to maintain a common equity to total capitalization ratio above 42%, except under circumstances beyond its control. MidAmerican Energy’s common equity to total capitalization ratio is not allowed to decline below 39% for any reason. If the ratio declines below the defined threshold, MidAmerican Energy must seek the approval of a reasonable utility capital structure from the IUB. MidAmerican Energy’s ability to issue debt could also be restricted. As of December 31, 2007, MidAmerican Energy’s common equity to total capitalization ratio, computed on a basis consistent with the commitment, exceeded the minimum threshold.

The components of MidAmerican Energy’s mortgage bonds, pollution control revenue obligations and notes consist of the following, including unamortized premiums and discounts, as of December 31 (dollars in millions):


	Par Value			2007			2006
Pollution control revenue obligations:
6.10% Series, due 2007		$	—		$	—		$	1
5.95% Series, due 2023, secured by general mortgage bonds			29			29			29
Variable rate series (2007-3.51%, 2006-3.97%):
Due 2016 and 2017			38			38			38
Due 2023, secured by general mortgage bonds			28			28			28
Due 2023			7			7			7
Due 2024			35			35			35
Due 2025			13			13			13
Notes:
5.65% Series, due 2012			400			400			—
5.125% Series, due 2013			275			275			274
4.65% Series, due 2014			350			350			350
5.95% Series, due 2017			250			249			—
6.75% Series, due 2031			400			396			396
5.75% Series, due 2035			300			300			300
5.80% Series, due 2036			350			349			349
Other			2			2			1
Total MidAmerican Energy		$	2,477		$	2,471		$	1,821

The components of Northern Natural Gas’ senior notes consist of the following, including unamortized premiums and discounts, as of December 31 (dollars in millions):

The components of Kern River’s term notes are due in monthly installments and consist of the following as of December 31 (dollars in millions):

Kern River provides a debt service reserve letter of credit in amounts equal to the next six months of principal and interest payments due on the loans which were equal to $64 million as of December 31, 2007 and 2006.

The components of CE Electric UK and its subsidiaries’ long-term debt consist of the following, including fair value adjustments and unamortized premiums and discounts, as of December 31 (dollars in millions):

CE Casecnan Water and Energy Company, Inc. (‘‘CE Casecnan’’) has 11.95% Senior Secured Series B Bonds, due in 2010 with a par value of $69 million. The outstanding balance of these bonds, including fair value adjustments, as of December 31, 2007 and 2006 was $68 million and $105 million, respectively.

Cordova Funding Corporation’s (‘‘Cordova Funding’’) senior secured bonds are due in semi-annual installments and consist of the following, including fair value adjustments, as of December 31 (dollars in millions):

MEHC has issued a limited guarantee of 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 million.

The components of HomeServices’ long-term debt consist of the following, including fair value adjustments, as of December 31 (dollars in millions):

The annual repayments of MEHC and subsidiary and project debt for the years beginning January 1, 2008 and thereafter, excluding fair value adjustments and unamortized premiums and discounts, are as follows (in millions):

The Company estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons including plan revisions, inflation and changes in the amount and timing of expected work. The change in the balance of the total ARO liability, which is included in other long-term accrued liabilities in the Consolidated Balance Sheets, is summarized as follows (in millions):

PacifiCorp’s coal mining operations are subject to the Surface Mining Control and Reclamation Act of 1977 and similar state statutes that establish operational, reclamation and closure standards that must be met during and upon completion of mining activities. These statutes mandate that mine property be restored consistent with specific standards and the approved reclamation plan. PacifiCorp is incurring expenditures for both ongoing and final reclamation. The fair value of PacifiCorp’s estimated mine reclamation costs, principally the Jim Bridger mine, was $115 million and $141 million as of December 31, 2007 and 2006, respectively, and is the asset retirement obligation for these mines. PacifiCorp has established trusts for the investment of funds for the Jim Bridger mine. The fair value of the assets held in trusts was $117 million and $110 million as of December 31, 2007 and 2006, respectively, and is reflected in other current assets and deferred charges, investments and other assets in the Consolidated Balance Sheets.

The Nuclear Regulatory Commission (‘‘NRC’’) regulates the decommissioning of nuclear power plants, which includes the planning and funding for the decommissioning. In accordance with these regulations, MidAmerican Energy submits a biennial report to the NRC providing reasonable assurance that funds will be available to pay for its share of the Quad Cities Station decommissioning.

The decommissioning costs are included in base rates in MidAmerican Energy’s Iowa tariffs. The fair value of MidAmerican Energy’s share of estimated Quad Cities Station decommissioning costs was $150 million and $142 million as of December 31, 2007 and 2006, respectively, and is the asset retirement obligation for the Quad Cities Station. MidAmerican Energy has established trusts for the investment of decommissioning funds. The fair value of the assets held in the trusts was $276 million and $259 million as of December 31, 2007 and 2006, respectively, and is reflected in deferred charges, investments and other assets in the Consolidated Balance Sheets.

In addition to the ARO liabilities, the Company has accrued for the cost of removing other electric and gas assets through its depreciation rates, in accordance with accepted regulatory practices. These accruals are reflected as regulatory liabilities and total $1.20 billion and $1.16 billion as of December 31, 2007 and 2006, respectively.

The total outstanding preferred stock of PacifiCorp, which does not have mandatory redemption requirements, was $41 million as of December 31, 2007 and 2006. Generally, this preferred stock is redeemable at stipulated prices plus accrued dividends, subject to certain restrictions. In the event of voluntary liquidation, all preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends. Upon involuntary liquidation, all preferred stock is entitled to stated value plus accrued dividends. Dividends on all preferred stock are cumulative. Holders also have the right to elect members to the PacifiCorp board of directors in the event dividends payable are in default in an amount equal to four full quarterly payments.

The total outstanding cumulative preferred securities of MidAmerican Energy are not subject to mandatory redemption requirements and may be redeemed at the option of MidAmerican Energy at prices which, in the aggregate, total $31 million. The aggregate total the holders of all preferred securities outstanding as of December 31, 2007 and 2006, are entitled to upon involuntary bankruptcy is $30 million plus accrued dividends.

The total outstanding 8.061% cumulative preferred securities of a subsidiary of CE Electric UK, which are redeemable in the event of the revocation of the subsidiary’s electricity distribution license by the Secretary of State, was $56 million as of December 31, 2007 and 2006.

The Company is exposed to the impact of market fluctuations in commodity prices, principally natural gas and electricity, particularly through its ownership of PacifiCorp and MidAmerican Energy. Interest rate risk exists on variable rate debt, commercial paper and future debt issuances. The Company is also exposed to foreign currency risk primarily due to its business operations and investments in Great Britain. The Company employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including forward contracts, futures, options, swaps and other over-the-counter agreements. The risk management process established by each business platform is designed to identify, assess, monitor, report, manage, and mitigate each of the various types of risk involved in its business. The Company does not engage in a material amount of proprietary trading activities.

The following table summarizes the various derivative mark-to-market positions included in the Consolidated Balance Sheet as of December 31, 2007 (in millions):

The following table summarizes the various derivative mark-to-market positions included in the Consolidated Balance Sheet as of December 31, 2006 (in millions):

The Company is subject to significant commodity risk particularly through its ownership of PacifiCorp and MidAmerican Energy. Exposures include variations in the price of wholesale electricity that is purchased and sold, fuel costs to generate electricity, and natural gas supply for regulated retail gas customers. Electricity and natural gas prices are subject to wide price swings as demand responds to, among many other items, changing weather, limited storage, transmission and transportation constraints, and lack of alternative supplies from other areas. To mitigate a portion of the risk, the Company uses derivative instruments, including forwards, futures, options, swap and other over-the-counter agreements, to effectively secure future supply or sell future production at fixed prices. The settled cost of these contracts is generally recovered from customers in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives, that are probable of recovery in rates, are recorded as regulatory net assets or liabilities.

MidAmerican Energy also uses futures, options and swap agreements to economically hedge gas commodity prices for physical delivery to nonregulated customers. MidAmerican Energy also enters into forward physical supply contracts and swap agreements to economically hedge electricity commodity prices for physical delivery to nonregulated customers. Nonregulated retail physical electricity contracts are considered normal purchases or sales and gains and losses on such contracts are recognized when settled. All other nonregulated gas and electric contracts are recorded at fair value.

Other MEHC subsidiaries use derivative instruments such as swaps, future, forwards and options principally as cash flow hedges for spring operational sales, natural gas storage and other transactions. During 2006, CE Gas recognized $14 million of unrealized losses on derivative contracts that became ineffective due to its inability to effectively forecast the associated hedged transactions.

Realized gains and losses on all hedges and hedge ineffectiveness are recognized in income as operating revenue, cost of sales or operating expenses depending upon the nature of the item being hedged. Net unrealized gains and losses on hedges utilized for regulatory purposes are generally recorded as regulatory assets and liabilities. As of December 31, 2007, the Company had cash flow hedges with expiration dates through October 2013. For the year ended December 31, 2007, hedge ineffectiveness was insignificant. As of December 31, 2007, $4 million of pre-tax net unrealized gains are forecasted to be reclassified from AOCI into earnings over the next twelve months as contracts settle.

MEHC selectively reduces its foreign currency risk by hedging through foreign currency derivatives. CE Electric UK has entered into certain currency rate swap agreements with large multi-national financial institutions for its U.S. dollar denominated senior notes and Yankee bonds. As of December 31, 2006, the swap agreements effectively converted the U.S. dollar fixed interest rate to a fixed rate in sterling for $237 million of 6.995% senior notes and $281 million of 6.496% Yankee bonds outstanding. The swap agreement for $237 million of senior notes expired with the maturity of the senior notes on December 30, 2007, and the swap agreement for $281 million of Yankee bonds expired with the maturity of the Yankee bonds on February 25, 2008. The estimated fair value of these swap agreements as of December 31, 2007 and 2006 was a liability of $106 million and $149 million, respectively, 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.

The Company may enter into contractual agreements to hedge exposure to interest rate risk. In September 2006, MEHC entered into a treasury rate lock agreement in the notional amount of $1.55 billion to protect against an increase in interest rates on future long-term debt issuances. As of December 31, 2006, the fair value of the treasury rate lock agreement was $12 million. The financings occurred on May 11, 2007 and August 28, 2007, and MEHC received a total of $32 million, which is being amortized as a reduction to interest expense over the term of the related financings. In May 2005, MEHC entered into a treasury rate lock agreement in the notional amount of $1.6 billion to protect against an increase in interest rates on future long-term debt issuances. The financing occurred on March 24, 2006 and MEHC received $53 million, which is being amortized as a reduction to interest expense over the term of the related financing.

Income tax expense on continuing operations consists of the following for the years ended December 31 (in millions):

A reconciliation of the federal statutory tax rate to the effective tax rate on continuing operations applicable to income before income tax expense for the years ended December 31 follows:

In 2007, the Company recognized $58 million of deferred income tax benefits upon the enactment of the reduction in the United Kingdom corporate income tax rate from 30% to 28% to be effective April 1, 2008.

The net deferred tax liability consists of the following as of December 31 (in millions):


	2007				2006
Deferred tax assets:
Regulatory liabilities		$	473			$	452
Employee benefits			161				362
Accruals not currently deductible for tax purposes			154				141
Net operating loss (‘‘NOL’’) and credit carryforwards			130				201
Revenue subject to refund			72				41
Uncertain tax positions			32				—
Nuclear reserve and decommissioning			24				23
Revenue sharing accruals			8				110
Other			223				172
Total deferred tax assets			1,277				1,502
Valuation allowance			(12	)			(20	)
Total deferred tax assets, net			1,265				1,482
Deferred tax liabilities:
Property, plant and equipment, net			(3,654	)			(3,562	)
Regulatory assets			(984	)			(1,095	)
Other			(60	)			(122	)
Total deferred tax liabilities			(4,698	)			(4,779	)
Net deferred tax liability		$	(3,433	)		$	(3,297	)
Reflected as:
Deferred income taxes-current asset		$	162			$	152
Deferred income taxes-non-current liability			(3,595	)			(3,449	)
		$	(3,433	)		$	(3,297	)

As of December 31, 2007, the Company has available unused NOL and credit carryforwards that may be applied against future taxable income and that expire at various intervals between 2008 and 2027.

The Company adopted FIN 48 effective January 1, 2007 and had $117 million of net unrecognized tax benefits. Of this amount, the Company recognized a net increase in the liability for unrecognized tax benefits of $22 million as a cumulative effect of adopting FIN 48, which was offset by reductions in beginning retained earnings of $5 million, deferred income tax liabilities of $31 million and goodwill of $15 million and an increase in regulatory assets of $1 million in the Consolidated Balance Sheet. The remaining $95 million had been previously accrued under SFAS No. 5, ‘‘Accounting for Contingencies,’’ or SFAS No. 109, ‘‘Accounting for Income Taxes.’’

As of December 31, 2007, net unrecognized tax benefits totaled $127 million which included $104 million of tax positions that, if recognized, would have an impact on the effective tax rate. The remaining unrecognized tax benefits relate to positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility and tax positions related to acquired companies. Recognition of these tax benefits, other than applicable interest and penalties, would not affect the Company’s effective tax rate.

Other income, as shown on the Consolidated Statements of Operations, for the years ending December 31 consists of the following (in millions):

Mirant was one of the shippers that entered into a 15-year, 2003 Expansion Project, firm gas transportation contract with Kern River (the ‘‘Mirant Agreement’’) and provided a letter of credit equivalent to 12 months of reservation charges as security for its obligations thereunder. In July 2003, Mirant filed for Chapter 11 bankruptcy protection. Kern River claimed $210 million in damages due to the rejection of the Mirant Agreement. The bankruptcy court ultimately determined that Kern River was entitled to a general unsecured claim of $74 million in addition to $15 million of cash collateral. In January 2006, Mirant emerged from bankruptcy. In February 2006, Kern River received an initial distribution of such shares in payment of the majority of its allowed claim. Kern River sold all of the shares of new Mirant stock received from its allowed claim amount plus interest in the first quarter of 2006 and recognized a gain from those sales of $89 million.

As of December 31, 2005, Berkshire Hathaway owned 41,263,395 shares of MEHC’s no par zero-coupon convertible preferred stock. Each share of preferred stock was 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. The convertible preferred stock was convertible into common stock only upon the occurrence of specified events, including modification or elimination of the Public Utility Holding Company Act of 1935 (‘‘PUHCA 1935’’) so that holding company registration would not be triggered by conversion. On February 9, 2006, following the effective date of the repeal of the Public Utility Holding Company Act of 1935, Berkshire Hathaway converted its 41,263,395 shares of MEHC’s no par zero-coupon convertible preferred stock into an equal number of shares of MEHC’s common stock.

On March 14, 2000, and as amended on December 7, 2005, MEHC’s shareholders entered into a Shareholder Agreement that provides specific rights to certain shareholders. One of these rights allows certain shareholders the ability to put their common shares back to MEHC at the then current fair value dependent on certain circumstances controlled by MEHC.

On March 1, 2006, MEHC and Berkshire Hathaway entered into an Equity Commitment Agreement (the ‘‘Berkshire Equity Commitment’’) pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of common equity of MEHC upon any requests authorized from time to time by the Board of Directors of MEHC. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due MEHC’s debt obligations and (b) funding the general corporate purposes and capital requirements of the Company’s regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request. The Berkshire Equity Commitment will expire on February 28, 2011.

On March 2, 2006, MEHC amended its Articles of Incorporation to (i) increase the amount of its common stock authorized for issuance to 115,000,000 shares and (ii) no longer provide for the authorization to issue any preferred stock of MEHC.

In March 2006, MEHC repurchased 12,068,412 shares of common stock for an aggregate purchase price of $1.75 billion.

On March 21, 2006, Berkshire Hathaway and certain other of MEHC’s existing shareholders and related companies invested $5.11 billion, in the aggregate, in 35,237,931 shares of MEHC’s common stock in order to provide equity funding for the PacifiCorp acquisition (see Note 3). The per-share value assigned to the shares of common stock issued, which were effected pursuant to a private placement and were exempt from the registration requirements of the Securities Act of 1933, as amended, was based on an assumed fair market value as agreed to by MEHC’s shareholders.

There were no common stock options granted, forfeited or that expired during each of the three years in the period ended December 31, 2007. There were 370,000 common stock options exercised during the year ended December 31, 2007 having a weighted-average exercise price of $26.99 per share. There were 703,329 common stock options outstanding and exercisable with an exercise price of $35.05 per share and a remaining contractual life of 2.25 years as of December 31, 2007.

There were 775,000 common stock options exercised during the year ended December 31, 2006 having a weighted-average exercise price of $28.65 per share. There were 1,073,329 common stock options outstanding and exercisable with a weighted-average exercise price of $32.27 per share as of December 31, 2006. As of December 31, 2006, 370,000 of the outstanding and exercisable common stock options had exercise prices ranging from $24.22 to $34.69 per share, a weighted-average exercise price of $26.99 per share and a remaining contractual life of 1.25 years. The remaining 703,329 outstanding and exercisable common stock options had an exercise price of $35.05 per share and a remaining contractual life of 3.25 years.

There were 200,000 common stock options exercised during the year ended December 31, 2005 having an exercise price of $29.01 per share. There were 1,848,329 common stock options outstanding and exercisable with a weighted-average exercise price of $30.75 per share as of December 31, 2005. 1,145,000 of the outstanding and exercisable common stock options had exercise prices ranging from $15.94 to $34.69 per share, a weighted-average exercise price of $28.11 per share and a remaining contractual life of 2.25 years. The remaining 703,329 outstanding and exercisable common stock options had an exercise price of $35.05 per share and a remaining contractual life of 4.25 years. There were 2,048,329 common stock options outstanding and exercisable with a weighted-average exercise price of $30.58 per share as of December 31, 2004.

The Company is subject to federal, state, local and foreign laws and regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters and believes it is in material compliance with current environmental requirements.

Litigation was filed in the federal district court for the southern district of New York seeking to require reductions of carbon dioxide emissions from generating facilities of five large electric utilities. The court dismissed the suit, ruling that critical issues affecting the United States, like greenhouse gas emissions reductions, are not the domain of the courts and should be resolved by the executive branch of the federal government and the U.S. Congress. This ruling has been appealed to the Second Circuit Court of Appeals. The outcome of climate change litigation and federal and state climate change initiatives cannot be determined at this time; however, adoption of stringent limits on greenhouse gas emissions could significantly impact the Company’s fossil-fueled facilities and, therefore, its financial results.

The Environmental Protection Agency’s regulation of certain pollutants under the Clean Air Act, and its failure to regulate other pollutants, is being challenged by various lawsuits brought by both individual state attorney generals and environmental groups. To the extent that these actions may be successful in imposing additional and/or more stringent regulation of emissions on fossil-fueled facilities in general and PacifiCorp’s and MidAmerican Energy’s facilities in particular, such actions could significantly impact the Company’s fossil-fueled facilities and, therefore, its financial results.

The Company is fully or partly responsible for environmental remediation that results from other than normal operations at various contaminated sites, including sites that are or were part of the Company’s operations and sites owned by third parties. The Company accrues environmental remediation expenses when the expense is believed to be probable and can be reasonably estimated. The quantification of environmental exposures is based on many factors, including changing laws and regulations, advancements in environmental technologies, the quality of available site-specific information, site investigation results, expected remediation or settlement timelines, the Company’s proportionate responsibility, contractual indemnities and coverage provided by insurance policies. The liability recorded as of December 31, 2007 and 2006 was $38 million and $50 million, respectively, and is included in other liabilities and other long-term accrued liabilities on the Consolidated Balance Sheets. Environmental remediation liabilities that result from the normal operation of a long-lived asset and that are associated with the retirement of those assets is accounted for as an asset retirement obligation.

PacifiCorp’s hydroelectric portfolio consists of 47 plants with an aggregate facility net owned capacity of 1,158 MW. The FERC regulates 98% of the net capacity of this portfolio through 16 individual licenses. Several of PacifiCorp’s hydroelectric plants are in some stage of relicensing with the FERC. Hydroelectric relicensing and the related environmental compliance requirements and litigation are subject to uncertainties. PacifiCorp expects that future costs relating to these matters may be significant and will consist primarily of additional relicensing costs, operations and maintenance expense, and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. PacifiCorp had incurred $89 million and $79 million in costs as of December 31, 2007 and 2006, respectively, for ongoing hydroelectric relicensing, which are included in construction in progress and reflected in property, plant and equipment, net in the Consolidated Balance Sheet.

In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 169 MW (nameplate rating) Klamath hydroelectric project in anticipation of the March 2006 expiration of the existing license. PacifiCorp is currently operating under an annual license issued by the FERC and expects to continue to operate under annual licenses until the new operating license is issued. As part of the relicensing process, the United States Departments of Interior and Commerce filed proposed licensing terms and conditions with the FERC in March 2006, which proposed that PacifiCorp construct upstream and downstream fish passage facilities at the Klamath hydroelectric project’s four mainstem dams. In April 2006, PacifiCorp filed alternatives to the federal agencies’ proposal and requested an administrative hearing to challenge some of the federal agencies’ factual assumptions supporting their proposal for the construction of the fish passage facilities. A hearing was held in August 2006 before an administrative law judge. The administrative law judge issued a ruling in September 2006 generally supporting the federal agencies’ factual assumptions. In January 2007, the United States Departments of Interior and Commerce filed modified terms and conditions consistent with March 2006 filings and rejected the alternatives proposed by PacifiCorp. PacifiCorp is prepared to meet and implement the federal agencies’ terms and conditions as part of the project’s relicensing. However, PacifiCorp expects to continue in settlement discussions with various parties in the Klamath Basin area who have intervened with the FERC licensing proceeding to try to achieve a mutually acceptable outcome for the project.

Also, as part of the relicensing process, the FERC is required to perform an environmental review. In September 2006, the FERC issued its draft environmental impact statement on the Klamath hydroelectric project license. PacifiCorp filed comments on the draft statement by the close of the public comment period on December 1, 2006. Subsequently, in November 2007, the FERC issued its final environmental impact statement. The United States Fish and Wildlife Service and the National Marine Fisheries Service issued final biological opinions in December 2007 analyzing the hydroelectric project’s impact on endangered species under the proposed new FERC license. The United States Fish and Wildlife Service asserts the hydroelectric project is currently not covered by previously issued biological opinions, and that consultation under the Endangered Species Act is required by the issuance of annual license renewals. PacifiCorp disputes these assertions, and believes federal case law is clear that consultation on annual FERC licenses is not required. PacifiCorp will need to obtain water quality certifications from Oregon and California prior to the FERC issuing a final license. PacifiCorp currently has applications pending before each state.

In the relicensing of the Klamath hydroelectric project, PacifiCorp had incurred $48 million and $42 million in costs as of December 31, 2007 and 2006, respectively, which are included in construction in progress and reflected in property, plant and equipment, net in the Consolidated Balance Sheets. While the costs of implementing new license provisions cannot be determined until such time as a new license is issued, such costs could be material.

In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a compliant against PacifiCorp in the federal district court in Cheyenne, Wyoming, alleging violations of the Wyoming state opacity standards at PacifiCorp’s Jim Bridger plant in Wyoming. Under Wyoming state requirements, which are part of the Jim Bridger plant’s Title V permit and are enforceable by private citizens under the federal Clean Air Act, a potential source of pollutants such as a coal-fired generating facility must meet minimum standards for opacity, which is a measurement of light that is obscured in the flue of a generating facility. The complaint alleges thousands of violations of asserted six-minute compliance periods and seeks an injunction ordering the Jim Bridger plant’s compliance with opacity limits, civil penalties of $32,500 per day per violation, and the plaintiffs’ costs of litigation. The court granted a motion to bifurcate the trial into separate liability and remedy phases. A five-day trial on the liability phase is scheduled to begin on April 2008. The remedy-phase trail has not yet been set. PacifiCorp believes it has a number of defenses to the claims. PacifiCorp intends to vigorously oppose the lawsuit but cannot predict its outcome at this time. PacifiCorp has already committed to invest at least $812 million in pollution control equipment at its generating facilities, including the Jim Bridger plant. This commitment is expected to significantly reduce system-wide emissions, including emissions at the Jim Bridger plant.

Pursuant to the share ownership adjustment mechanism in the CE Casecnan shareholder agreement, which is based upon proforma 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 shareholder of CE Casecnan, LaPrairie Group Contractors (International) Ltd. (‘‘LPG’’), that MEHC’s indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. On July 8, 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco

against CE Casecnan Ltd. and MEHC. LPG’s complaint, as amended, seeks compensatory and punitive damages arising out of CE Casecnan Ltd.’s and MEHC’s alleged improper calculation of the proforma financial projections and alleged improper settlement of the NIA arbitration.

On February 21, 2007, the appellate court issued a decision, and as a result of the decision, CE Casecnan Ltd. determined that LPG would retain ownership of 10% of the shares of CE Casecnan, with the remaining 5% ownership being transferred to CE Casecnan Ltd. subject to certain buy-up rights under the shareholder agreement. At a hearing on October 10, 2007, the court determined that LPG was ready, willing and able to exercise its buy-up rights in 2007. Additional hearings were held on October 23 and 24, 2007, regarding the issue of the buy-up price calculation and a written decision was issued on February 4, 2008 specifying the method for determining LPG’s buy-up price. A final judgment has not been issued on the buy-up right and price and when issued will be subject to appeal. LPG waived its request for a jury trial for the breach of fiduciary duty claim and the parties have entered into a stipulation which provides for a trial of such claim by the court based on the existing record of the case. The trial date has been set for March 12, 2008. The Company intends to vigorously defend and pursue the remaining claims.

The Company has the following unconditional purchase obligations as of December 31, 2007 (in millions) which are not reflected in the Consolidated Balance Sheet:

PacifiCorp and MidAmerican Energy have fuel supply and related transportation contracts for their coal-fired and gas generating stations. PacifiCorp and MidAmerican Energy expect to

supplement these contracts with additional contracts and spot market purchases to fulfill their future fossil fuel needs. PacifiCorp and MidAmerican Energy acquire a portion of their electricity through long-term purchases and/or exchange agreements. Included in the purchased electricity payments are any power purchase agreements that meet the definition of an operating lease.

The Company has purchase obligations for an ongoing construction program to meet increased electricity usage, customer growth and system reliability objectives. Additionally, the Company has various other purchase obligations that are non-cancelable or cancelable only under certain conditions related to equipment maintenance and various other service and maintenance agreements.

As part of the hydroelectric relicensing process, PacifiCorp entered into settlement agreements with various interested parties that resulted in commitments for environmental mitigation and enhancement measures over the life of the licenses.

The Company has non-cancelable operating leases primarily for computer equipment, office space, certain operating facilities, land and rail cars. These leases generally require the Company to pay for insurance, taxes and maintenance applicable to the leased property. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. The Company also has non-cancelable easements for land on which its wind-farm turbines are located, as well as non-cancelable maintenance contracts for the turbines. Rent expense on non-cancelable operating leases totaled $122 million for 2007, $117 million for 2006 and $79 million for 2005.

The Company has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on the Company’s consolidated financial results. The Company is generally required to obtain state regulatory commission approval prior to guaranteeing debt or obligations of other parties. The following represent the material indemnification obligations of the Company as of December 31, 2007.

PacifiCorp has made certain commitments related to the decommissioning or reclamation of certain jointly owned facilities and mine sites. The decommissioning commitments require PacifiCorp to pay a proportionate share of the decommissioning costs based upon percentage of ownership. The mine reclamation commitments require PacifiCorp to pay the mining entity a proportionate share of the mine’s reclamation costs based on the amount of coal purchased by PacifiCorp. In the event of default by any of the other joint participants, PacifiCorp potentially may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party’s liability. PacifiCorp has recorded its estimated share of the decommissioning and reclamation commitments.

PacifiCorp sponsors defined benefit pension plans that cover the majority of its employees. PacifiCorp’s pension plans include a noncontributory defined benefit pension plan, a supplemental executive retirement plan (‘‘SERP’’) and certain multi-employer and joint trust union plans to which PacifiCorp contributes on behalf of certain bargaining units. MidAmerican Energy sponsors defined

benefit pension plans that cover substantially all employees of MEHC and its domestic energy subsidiaries other than PacifiCorp. MidAmerican Energy’s pension plans included a noncontributory defined benefit pension plan and a SERP. PacifiCorp and MidAmerican Energy also provide certain postretirement health care and life insurance benefits through various plans for eligible retirees.

Changes to the Company’s domestic defined benefit and other postretirement plans include the following:

Plan assets and benefit obligations for PacifiCorp-sponsored plans were measured as of September 30, 2007 and MidAmerican Energy-sponsored plans were measured as of December 31, 2007. 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.

Combined net periodic benefit cost for the pension, including SERP, and other postretirement benefits plans included the following components for the years ended December 31 (in millions):

The following table is a reconciliation of the combined fair value of plan assets as of December 31 (in millions):

The SERPs have no plan assets; however the Company has Rabbi trusts that hold corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERPs. The cash surrender value of all of the policies included in the Rabbi trusts, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was $159 million and $148 million as of December 31, 2007 and 2006, respectively. These assets are not included in the plan assets in the above table, but are reflected in the Consolidated Balance Sheet. The portion of the pension projected benefit obligation, included in the table below, related to the SERPs was $155 million and $161 million as of December 31, 2007 and 2006, respectively.

The following table is a reconciliation of the combined benefit obligations as of December 31 (in millions):

PacifiCorp’s noncontributory defined benefit pension plan’s accumulated benefit obligation exceeded the fair value of the plan’s assets by $46 million and $228 million as of December 31, 2007 and 2006, respectively. Additionally, the accumulated benefit obligations related to the SERPs totaled $152 million and $156 million as of December 31, 2007 and 2006, respectively.

The combined funded status of the plans and the amounts recognized in the Consolidated Balance Sheets as of December 31 are as follows (in millions):


	Pension								Other Postretirement
	2007				2006				2007				2006
Plan assets at fair value, end of year		$	1,638			$	1,548			$	603			$	532
Less – Benefit obligations, end of year			1,813				2,038				793				824
Funded status			(175	)			(490	)			(190	)			(292	)
Contributions after the measurement date but before year-end			—				—				12				27
Amounts recognized in the Consolidated Balance Sheets		$	(175	)		$	(490	)		$	(178	)		$	(265	)
Amounts recognized in the Consolidated Balance Sheets:
Deferred charges, investments and other assets		$	77			$	66			$	—			$	—
Other current liabilities			(11	)			(11	)			—				(1	)
Other long-term accrued liabilities			(241	)			(545	)			(178	)			(264	)
Amounts recognized		$	(175	)		$	(490	)		$	(178	)		$	(265	)
Amounts not yet recognized as components of net periodic benefit cost:
Net loss		$	108			$	292			$	70			$	144
Prior service cost (credit)			(109	)			18				13				16
Net transition obligation			3				5				63				76
Total		$	2			$	315			$	146			$	236

A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the year ended December 31, 2007 is as follows (in millions):

The net loss, prior service cost and net transition obligation that will be amortized in 2008 into net periodic benefit cost are estimated to be as follows (in millions):

Assumptions used to determine benefit obligations as of December 31 and net benefit cost for the years ended December 31 were as follows:


	Pension						Other Postretirement
	2007		2006		2005		2007		2006		2005
	%		%		%		%		%		%
Benefit obligations as of the measurement date:
PacifiCorp-sponsored plans –
Discount rate		6.30		5.85		—		6.45		6.00		—
Rate of compensation increase		4.00		4.00		—		N/A		N/A		N/A
MidAmerican Energy-sponsored plans –
Discount rate		6.00		5.75		5.75		6.00		5.75		5.75
Rate of compensation increase		4.50		4.50		5.00		N/A		N/A		N/A
Net benefit cost for the years ended December 31:
PacifiCorp-sponsored plans –
Discount rate		5.76		5.75		—		6.00		5.75		—
Expected return on plan assets		8.00		8.50		—		8.00		8.50		—
Rate of compensation increase		4.00		4.00		—		N/A		N/A		N/A
MidAmerican Energy-sponsored plans –
Discount rate		5.75		5.75		5.75		5.75		5.75		5.75
Expected return on plan assets		7.50		7.00		7.00		7.50		7.00		7.00
Rate of compensation increase		4.50		5.00		5.00		N/A		N/A		N/A


	2007			2006
Assumed health care cost trend rates as of the measurement date:
PacifiCorp-sponsored plans –
Health care cost trend rate assumed for next year – under 65		9.00	%		10.00	%
Health care cost trend rate assumed for next year – over 65		7.00	%		8.00	%
Rate that the cost trend rate gradually declines to		5.00	%		5.00	%
Year that the rate reaches the rate it is assumed to remain at – under 65		2012			2012
Year that the rate reaches the rate it is assumed to remain at – over 65		2010			2010
MidAmerican Energy-sponsored plans –
Health care cost trend rate assumed for next year		9.00	%		8.00	%
Rate that the cost trend rate gradually declines to		5.00	%		5.00	%
Year that the rate reaches the rate it is assumed to remain at		2016			2010

A one-percentage-point change in assumed health care cost trend rates would have the following effects (in millions):

Employer contributions to the pension and other postretirement plans are expected to be $77 million and $41 million, respectively, for 2008. The Company’s policy is to contribute the minimum required amount to its pension plans and the net periodic cost to its other postretirement plans. The Pension Protection Act of 2006 changes funding rules beginning in 2008 and may have the effect of making minimum pension funding requirements more volatile than they have been historically. Accordingly, the Company continually evaluates its funding strategies.

The Company’s expected benefit payments to participants from its pension and other postretirement plans for 2008 through 2012 and for the five years thereafter are summarized below (in millions):

The Company’s investment policy for its pension and other postretirement plans is to balance risk and return through a diversified portfolio of equity securities, fixed income securities and other alternative investments. Asset allocation for the pension and other postretirement plans are as indicated in the tables below. Maturities for fixed income securities are managed to targets consistent with prudent risk tolerances. Sufficient liquidity is maintained to meet near-term benefit payment obligations. The plans retain outside investment advisors to manage plan investments within the parameters outlined by each plan’s Pension and Employee Benefits Plans Administrative Committee. The weighted-average return on assets assumption is based on historical performance for the types of assets in which the plans invest.

PacifiCorp’s other postretirement plan assets are composed of three different trust accounts. The 401(h) account is invested in the same manner as the assets of the pension plan. Each of the two Voluntary Employees’ Beneficiaries Association (‘‘VEBA’’) Trusts has its own investment allocation strategies. PacifiCorp’s asset allocation as of December 31 was as follows:

New target ranges for MidAmerican Energy’s other postretirement benefit plan assets were approved by MidAmerican Energy’s Administrative Committee in December 2007. No rebalancing took place before December 31, 2007.

The Company sponsors defined contribution pension plans (401(k) plans) and an employee savings plan covering substantially all 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 Company contributions were $36 million, $34 million and $17 million for 2007, 2006 and 2005, respectively.

Certain wholly-owned subsidiaries of CE Electric UK participate in the Northern Electric group of the United Kingdom industry-wide Electricity Supply Pension Scheme (the ‘‘UK Plan’’), which provides pension and other related defined benefits, based on final pensionable pay, to the majority of the employees of CE Electric UK.

Plan assets and obligations for the UK Plan are measured as of December 31, 2007. 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. The components of the net periodic benefit cost for the UK Plan for the years ended December 31 was as follows (in millions):

The following table is a reconciliation of the fair value of plan assets as of December 31 (in millions):

The following table is a reconciliation of the benefit obligation as of December 31 (in millions):

The funded status of the plan and the amounts recognized in the Consolidated Balance Sheets as of December 31 is as follows (in millions):

A reconciliation of the amounts not yet recognized as components of net periodic benefit cost, which are included in accumulated other comprehensive income (loss) in the Consolidated Balance Sheets, for the year ended December 31, 2007 is as follows (in millions):

The net loss and prior service cost that will be amortized from accumulated other comprehensive income (loss) in 2008 into net periodic benefit cost is estimated to be $19 million and $2 million, respectively.

Assumptions used to determine benefit obligations as of December 31 and net periodic benefit cost for the years ended December 31 are as follows:

The expected benefit payments to participants in the UK Plan for 2008 through 2012 and for the five years thereafter are summarized below (in millions):

Employer contributions to the UK Plan, including £23 million for the funding deficiency, are currently expected to be £48 million for 2008.

CE Electric UK’s investment policy for its pension plan is to balance risk and return through a diversified portfolio of equity securities, fixed income securities and real estate. Maturities for fixed income securities are managed such that sufficient liquidity exists to meet near-term benefit payment obligations. The plan retains outside investment advisors to manage plan investments within the parameters set by the trustees of the UK Plan in consultation with CE Electric UK. The return on assets assumption is based on a weighted average of the expected historical performance for the types of assets in which the plans invest.

CE Electric UK’s pension plan asset allocation as of December 31 was as follows:

The carrying amounts of cash and cash equivalents, short-term investments, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity or frequent remarketing of these instruments. Derivative instruments are recorded at their fair values, which are based upon published market indexes as adjusted for other market factors such as location pricing differences or internally developed models. Substantially all investments are carried at their fair values, which are based on quoted market prices.

The fair value of the Company’s long-term debt has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with

comparable maturities with similar credit risks. The carrying amount of variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying amount and estimated fair value of the Company’s long-term debt, including the current portion, as of December 31 (in millions):

The summary of supplemental cash flow information for the years ending December 31 follows (in millions):

Accumulated other comprehensive income (loss), net is included in the Consolidated Balance Sheets in the common shareholders’ equity section, and consists of the following components, net of tax, as of December 31 (in millions):


	Year Ended December 31,
	2007				2006				2005
Operating revenue:
PacifiCorp		$	4,258			$	2,939			$	—
MidAmerican Energy			4,267				3,453				3,166
Northern Natural Gas			664				634				569
Kern River			404				325				324
CE Electric UK			1,079				928				884
CalEnergy Generation-Foreign			220				336				312
CalEnergy Generation-Domestic			32				32				34
HomeServices			1,500				1,702				1,868
Corporate/other⁽¹⁾			(48	)			(48	)			(41	)
Total operating revenue		$	12,376			$	10,301			$	7,116
Depreciation and amortization:
PacifiCorp		$	496			$	368			$	—
MidAmerican Energy			269				275				269
Northern Natural Gas			58				57				30
Kern River			80				56				62
CE Electric UK			187				138				136
CalEnergy Generation-Foreign			50				80				90
CalEnergy Generation-Domestic			8				8				9
HomeServices			20				32				18
Corporate/other⁽¹⁾			(18	)			(7	)			(6	)
Total depreciation and amortization		$	1,150			$	1,007			$	608
Operating income:
PacifiCorp		$	917			$	528			$	—
MidAmerican Energy			514				421				381
Northern Natural Gas			308				269				209
Kern River			277				217				204
CE Electric UK			555				516				484
CalEnergy Generation-Foreign			142				230				185
CalEnergy Generation-Domestic			12				14				15
HomeServices			33				55				125
Corporate/other⁽¹⁾			(70	)			(130	)			(74	)
Total operating income			2,688				2,120				1,529
Interest expense			(1,320	)			(1,152	)			(891	)
Capitalized interest			54				40				17
Interest and dividend income			105				73				58
Other income			122				239				75
Other expense			(10	)			(13	)			(23	)
Total income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income		$	1,639			$	1,307			$	765


	Year Ended December 31,
	2007				2006				2005
Interest expense:
PacifiCorp		$	314			$	224			$	—
MidAmerican Energy			179				155				138
Northern Natural Gas			58				50				53
Kern River			75				74				73
CE Electric UK			241				215				218
CalEnergy Generation-Foreign			13				20				31
CalEnergy Generation-Domestic			17				18				18
HomeServices			2				2				2
Corporate/other⁽¹⁾			285				233				173
MEHC subordinated debt			136				161				185
Total interest expense		$	1,320			$	1,152			$	891
Income tax expense:
PacifiCorp		$	240			$	139			$	—
MidAmerican Energy			111				94				91
Northern Natural Gas			106				85				71
Kern River			78				87				50
CE Electric UK			47				100				93
CalEnergy Generation-Foreign			56				68				56
CalEnergy Generation-Domestic			—				1				(1	)
HomeServices			15				30				56
Corporate/other⁽¹⁾			(197	)			(197	)			(171	)
Total income tax expense		$	456			$	407			$	245
Capital expenditures:
PacifiCorp		$	1,518			$	1,114			$	—
MidAmerican Energy			1,300				758				701
Northern Natural Gas			225				122				125
Kern River			15				3				7
CE Electric UK			422				404				342
CalEnergy Generation-Foreign			1				2				1
CalEnergy Generation-Domestic			—				—				1
HomeServices			26				18				19
Corporate/other⁽¹⁾			5				2				—
Total capital expenditures		$	3,512			$	2,423			$	1,196

The following table shows the change in the carrying amount of goodwill by reportable segment for the years ended December 31, 2007 and 2006 (in millions):


									Northern Natural Gas							CE Electric UK				CalEnergy Generation Domestic
					MidAmerican Energy								Kern River											Home- Services
	PacifiCorp				MidAmerican Energy								Kern River											Home- Services				Total
Balance, January 1, 2006		$	—			$	2,118			$	327			$	34		$	1,207			$	72			$	398			$	4,156
Acquisitions			1,118				—				—				—			—				—				34				1,152
Reclassification of intangible assets⁽¹⁾			—				—				—				—			—				—				(45	)			(45	)
Foreign currency translation adjustment			—				—				—				—			126				—				—				126
Other goodwill adjustments⁽²⁾			—				(10	)			(26	)			—			(5	)			(1	)			(2	)			(44	)
Balance, December 31, 2006			1,118				2,108				301				34			1,328				71				385				5,345
Acquisitions⁽³⁾			22				—				—				—			—				—				9				31
Adoption of FIN 48			(10	)			(4	)			—				—			(1	)			—				—				(15	)
Foreign currency translation adjustment			—				—				—				—			14				—				—				14
Other goodwill adjustments⁽²⁾			(5	)			4				(26	)			—			(6	)			—				(3	)			(36	)
Balance, December 31, 2007		$	1,125			$	2,108			$	275			$	34		$	1,335			$	71			$	391			$	5,339

All tendered initial notes, executed letters of transmittal, and other related documents should be directed to the exchange agent. Requests for assistance and for additional copies of this prospectus, the letter of transmittal and other related documents should be directed to the exchange agent.

Bank of New York Mellon Corporation
Corporate Trust Operations
Reorganization Unit
101 Barclay Street
Floor 7 East
New York, NY 10286
Attn: Mr. Randolph Holder

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to the Registrant’s directors and officers pursuant to the following provisions or otherwise, the Registrant has been advised that, although the validity and scope of the governing statute have not been tested in court, in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In addition, indemnification may be limited by state securities laws.

Sections 490.850-490.859 of the Iowa Business Corporation Act permit corporations organized thereunder to indemnify directors, officers, employees and agents against liability under certain circumstances. The Restated Articles of Incorporation, as amended, and the Restated Bylaws, as amended, of MidAmerican Energy Holdings Company provide for indemnification of directors, officers and employees to the full extent provided by the Iowa Business Corporation Act.

As permitted by Section 490.202 of the Iowa Business Corporation Act and Article VI of the Articles of Incorporation, no director shall be personally liable to MidAmerican Energy Holdings Company or its shareholders for money damages for any action taken, or any failure to take any action, as a director, except liability for any of the following: (1) the amount of a financial benefit received by a director to which the director is not entitled; (2) an intentional infliction of harm on the corporation or the shareholders; (3) a violation of Section 490.833 of the Iowa Business Corporation Act (relating to certain unlawful distributions to shareholders); (4) an intentional violation of criminal law; or (5) any other violation of Section 490.831 of the Iowa Business Corporation Act (Standards of Liability for Directors).

The Registrant’s Amended and Restated Articles of Incorporation and Bylaws provides that if the proceeding for which indemnification is sought is by or in the right of the Registrant, indemnification may be made only for reasonable expenses and may not be made in any proceeding in which the person is adjudged liable to the Registrant. Further, any such person may not be indemnified in any proceeding that charges improper personal benefit to the person in which the person is adjudged to be liable.

The Registrant’s Amended and Restated Articles of Incorporation and Bylaws allow the Registrant to maintain liability insurance to protect itself and any director, officer, employee, or agent against any expense, liability or loss whether or not the Registrant would have the power to indemnify such person against such incurred expense, liability, or loss. Pursuant to Section 490.857 of the Iowa Business Corporation Act, the Articles of Incorporation and the Bylaws, the Registrant maintains directors’ and officers’ liability insurance coverage.

The Registrant may also enter into indemnification agreements with certain directors and officers to further assure such persons’ indemnification as permitted by Iowa law.

The rights to indemnification conferred on any person by the Registrant’s Amended and Restated Articles of Incorporation and Bylaws are not exclusive of any right which any person may have or acquire under any statute, provision of the Registrant’s Amended and Restated Articles of Incorporation, Bylaws, agreement, or vote of shareholders or disinterested directors.

The exhibits listed on the accompanying Exhibit Index (immediately following Schedule II) are filed as part of this prospectus.

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.

(a) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i) To include any prospectus required by Section 10(a)(3) of the Securities Act;

(ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the SEC pursuant to Rule 424(b) under the Securities Act if, in the aggregate, the changes in volume and price represent no more than a 20% change in the maximum aggregate offering price set forth in the ‘‘Calculation of Registration Fee’’ table in the effective registration statement; and

(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

(b) That, for the purpose of determining any liability under the Securities Act, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(c) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

The undersigned registrant hereby undertakes that, for the purposes of determining any liability under the Securities Act, each filing of the registrant’s annual report pursuant to Section 13(a) or 15(d) of the Exchange Act (and, where applicable, each filing of an employee benefit plan’s annual report pursuant to Section 15(d) of the Exchange Act) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant, pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by any such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether or not such indemnification is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Notwithstanding the foregoing, no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement in any such document immediately prior to such date of first use.

The undersigned registrant hereby undertakes to respond to requests for information, if any, that is incorporated by reference into the prospectus pursuant to Item 4, 10(b), 11 or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

The undersigned registrant hereby undertakes to supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Des Moines, State of Iowa, on this 4th day of June, 2008.

The undersigned officers and directors of MidAmerican Energy Holdings Company hereby severally constitute and appoint Douglas L. Anderson and Paul J. Leighton, and each of them, attorneys-in-fact for the undersigned, in any and all capacities, with the power of substitution, to sign any amendments to this registration statement (including post-effective amendments) and any subsequent registration statement for the same offering which may be filed under Rule 462(b) under the Securities Act of 1933, as amended, and to file the same with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully and to all interests and purposes as he might or could do in person, hereby ratifying and confirming all that each said attorney-in-fact, or his substitute or substitutes, may do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed below by the following persons, in the capacities and on the dates indicated.

MidAmerican Energy Holdings Company
Parent Company Only
Condensed Balance Sheets
As of December 31, 2007 and 2006
(Amounts in millions)


	2007			2006
ASSETS
Current assets:
Cash and cash equivalents		$	765		$	3
Derivative contracts			—			12
Other current assets			4			5
Total current assets			769			20
Investments in and advances to subsidiaries and joint ventures			13,995			12,788
Equipment, net			34			33
Goodwill			1,278			1,276
Deferred charges, investments and other assets			135			145
Total assets		$	16,211		$	14,262
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable and other current liabilities		$	167		$	151
Short-term debt			—			152
Current portion of senior debt			1,000			550
Current portion of subordinated debt			234			234
Total current liabilities			1,401			1,087
Other long-term accrued liabilities			121			104
Senior debt			4,471			3,929
Subordinated debt			891			1,123
Total liabilities			6,884			6,243
Minority interest			1			8
Shareholders’ equity:
Common stock-115 shares authorized, no par value, 75 shares and 74 shares issued and outstanding as of December 31, 2007 and 2006, respectively			—			—
Additional paid in capital			5,454			5,420
Retained earnings			3,782			2,598
Accumulated other comprehensive income (loss), net			90			(7	)
Total shareholders’ equity			9,326			8,011
Total liabilities and shareholders’ equity		$	16,211		$	14,262

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

MidAmerican Energy Holdings Company
Parent Company Only (continued)
Condensed Statements of Operations
For the three years ended December 31, 2007
(Amounts in millions)

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

MidAmerican Energy Holdings Company
Parent Company Only (continued)
Condensed Statements of Cash Flows
For the three years ended December 31, 2007
(Amounts in millions)


	2007				2006				2005
Cash flows from operating activities		$	(204	)		$	(250	)		$	(154	)
Cash flows from investing activities:
(Increase) decrease in advances to and investments in subsidiaries and joint ventures			317				(4,708	)			204
Purchases of available-for-sale securities			(407	)			(148	)			(1,667	)
Proceeds from sale of available-for-sale securities			399				140				1,750
Other, net			19				—				18
Net cash flows from investing activities			328				(4,716	)			305
Cash flows from financing activities:
Proceeds from the issuances of common stock			10				5,132				—
Purchases of common stock			—				(1,750	)			—
Proceeds from senior debt			1,539				1,699				—
Repayments of subordinated debt			(234	)			(234	)			(189	)
Repayments of senior debt			(550	)			—				(260	)
Net (repayments of) proceeds from revolving credit facility			(152	)			101				51
Net repayment of affiliate notes			—				(22	)			(23	)
Other, net			25				41				6
Net cash flows from financing activities			638				4,967				(415	)
Net change in cash and cash equivalents			762				1				(264	)
Cash and cash equivalents at beginning of year			3				2				266
Cash and cash equivalents at end of year		$	765			$	3			$	2

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

MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2007
(Amounts in millions)

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


Exhibit No.			Description
	3	.1	Second Amended and Restated Articles of Incorporation of MidAmerican Energy Holdings Company effective March 2, 2006 (incorporated by reference to Exhibit 3.1 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2005).
	3	.2	Amended and Restated Bylaws of MidAmerican Energy Holdings Company (incorporated by reference to Exhibit 3.2 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2005).
	4	.1	Indenture, dated as of October 4, 2002, by and between MidAmerican Energy Holdings Company and The Bank of New York, Trustee, relating to the 5.875% Senior Notes due 2012 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
	4	.2	First Supplemental Indenture, dated as of October 4, 2002, by and between MidAmerican Energy Holdings Company and The Bank of New York, Trustee, relating to the 5.875% Senior Notes due 2012 (incorporated by reference to Exhibit 4.2 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
	4	.3	Second Supplemental Indenture, dated as of May 16, 2003, by and between MidAmerican Energy Holdings Company and The Bank of New York, Trustee, relating to the 3.50% Senior Notes due 2008 (incorporated by reference to Exhibit 4.3 to the MidAmerican Energy Holdings Company’s Registration Statement No. 333-105690 dated May 23, 2003).
	4	.4	Third Supplemental Indenture, dated as of February 12, 2004, by and between MidAmerican Energy Holdings Company and The Bank of New York, Trustee, relating to the 5.00% Senior Notes due 2014 (incorporated by reference to Exhibit 4.4 to the MidAmerican Energy Holdings Company Registration Statement No. 333-113022 dated February 23, 2004).
	4	.5	Fourth Supplemental Indenture, dated as of March 24, 2006, by and between MidAmerican Energy Holdings Company and The Bank of New York Trust Company, N.A., Trustee, relating to the 6.125% Senior Bonds due 2036 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated March 28, 2006).
	4	.6	Fifth Supplemental Indenture, dated as of May 11, 2007, by and between MidAmerican Energy Holdings Company and The Bank of New York Trust Company, N.A., Trustee, relating to the 5.95% Senior Bonds due 2037 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated May 11, 2007).
	4	.7	Sixth Supplemental Indenture, dated as of August 28, 2007, by and between MidAmerican Energy Holdings Company and The Bank of New York Trust Company, N.A., Trustee, relating to the 6.50% Senior Bonds due 2037 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated August 28, 2007).


Exhibit No.			Description
	4	.8	Seventh Supplemental Indenture, dated as of March 28, 2008, by and between MidAmerican Energy Holdings Company and The Bank of New York Trust Company, N.A., as Trustee, relating to the 5.75% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated March 28, 2008).
	4	.9	Registration Rights Agreement, dated March 28, 2008, by and among MidAmerican Energy Holdings Company and Lehman Brothers Inc., Barclays Capital Inc., Greenwich Capital Markets, Inc. and Wachovia Capital Markets, LLC as Representatives of the several Initial Purchasers.
	4	.10	Indenture dated as of February 26, 1997, by and between MidAmerican Energy Holdings Company and the Bank of New York, Trustee relating to the 6¼% Convertible Junior Subordinated Debentures due 2012 (incorporated by reference to Exhibit 10.129 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 1995).
	4	.11	Indenture, dated as of October 15, 1997, by and between MidAmerican Energy Holdings Company and IBJ Schroder Bank & Trust Company, Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated October 23, 1997).
	4	.12	Form of Second Supplemental Indenture, dated as of September 22, 1998 by and between MidAmerican Energy Holdings Company and IBJ Schroder Bank & Trust Company, Trustee, relating to the 7.52% Senior Notes in the principal amount of $450,000,000 due 2008, and the 8.48% Senior Notes in the principal amount of $475,000,000 due 2028 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated September 17, 1998).
	4	.13	Form of Third Supplemental Indenture, dated as of November 13, 1998, by and between MidAmerican Energy Holdings Company and IBJ Schroder Bank & Trust Company, Trustee, relating to the 7.52% Senior Notes in the principal amount of $100,000,000 due 2008 (incorporated by reference to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated November 10, 1998).
	4	.14	Indenture, dated as of March 14, 2000, by and between MidAmerican Energy Holdings Company and the Bank of New York, Trustee (incorporated by reference to Exhibit 4.9 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K/A for the year ended December 31, 1999).
	4	.15	Indenture, dated as of March 12, 2002, by and between MidAmerican Energy Holdings Company and the Bank of New York, Trustee (incorporated by reference to Exhibit 4.11 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2001).
	4	.16	Amended and Restated Declaration of Trust of MidAmerican Capital Trust III, dated as of August 16, 2002 (incorporated by reference to Exhibit 4.14 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
	4	.17	Amended and Restated Declaration of Trust of MidAmerican Capital Trust II, dated as of March 12, 2002 (incorporated by reference to Exhibit 4.15 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).


Exhibit No.			Description
	4	.18	Amended and Restated Declaration of Trust of MidAmerican Capital Trust I, dated as of March 14, 2000 (incorporated by reference to Exhibit 4.16 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
	4	.19	Indenture, dated as of August 16, 2002, by and between MidAmerican Energy Holdings Company and the Bank of New York, Trustee (incorporated by reference to Exhibit 4.17 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
	4	.20	Amended and Restated Credit Agreement, dated as of July 6, 2006, by and among MidAmerican Energy Holdings Company, as Borrower, The Banks and Other Financial Institutions Parties Hereto, as Banks, JPMorgan Chase Bank, N.A., as L/C Issuer, Union Bank of California, N.A., as Administrative Agent, The Royal Bank of Scotland PLC, as Syndication Agent, and ABN Amro Bank N.V., JPMorgan Chase Bank, N.A. and BNP Paribas as Co-Documentation Agents (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2006).
	4	.21	Trust Indenture, dated as of November 27, 1995, by and between CE Casecnan Water and Energy Company, Inc. and Chemical Trust Company of California, Trustee (incorporated by reference to Exhibit 4.1 to the CE Casecnan Water and Energy Company, Inc. Registration Statement on Form S-4 dated January 25, 1996).
	4	.22	Indenture and First Supplemental Indenture, dated March 11, 1999, by and between MidAmerican Funding, LLC and IBJ Whitehall Bank & Trust Company, Trustee, relating to the $700 million Senior Notes and Bonds (incorporated by reference to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 1998).
	4	.23	Second Supplemental Indenture, dated as of March 1, 2001, by and between MidAmerican Funding, LLC and The Bank of New York, Trustee (incorporated by reference to Exhibit 4.4 to the MidAmerican Funding, LLC Registration Statement on Form S-3, Registration No. 333-56624).
	4	.24	General Mortgage Indenture and Deed of Trust, dated as of January 1, 1993, by and 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).
	4	.25	First Supplemental Indenture, dated as of January 1, 1993, by and 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).
	4	.26	Second Supplemental Indenture, dated as of January 15, 1993, by and 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).


Exhibit No.			Description
	4	.27	Third Supplemental Indenture, dated as of May 1, 1993, by and 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).
	4	.28	Fourth Supplemental Indenture, dated as of October 1, 1994, by and 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).
	4	.29	Fifth Supplemental Indenture, dated as of November 1, 1994, by and 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).
	4	.30	Sixth Supplemental Indenture, dated as of July 1, 1995, by and 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).
	4	.31	Indenture dated as of December 1, 1996, by and between MidAmerican Energy Company and the First National Bank of Chicago, Trustee (incorporated by reference to Exhibit 4(1) to the MidAmerican Energy Company Registration Statement on Form S-3, Registration No. 333-15387).
	4	.32	First Supplemental Indenture, dated as of February 8, 2002, by and between MidAmerican Energy Company and The Bank of New York, Trustee (incorporated by reference to Exhibit 4.3 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 333-15387).
	4	.33	Second Supplemental Indenture, dated as of January 14, 2003, by and between MidAmerican Energy Company and The Bank of New York, Trustee (incorporated by reference to Exhibit 4.2 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 333-15387).
	4	.34	Third Supplemental Indenture, dated as of October 1, 2004, by and between MidAmerican Energy Company and The Bank of New York, Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 333-15387).
	4	.35	Fourth Supplemental Indenture, dated November 1, 2005, by and between MidAmerican Energy Company and the Bank of New York Trust Company, NA, Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2005).
	4	.36	Fiscal Agency Agreement, dated as of October 15, 2002, by and 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 (incorporated by reference to Exhibit 10.47 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2003).


Exhibit No.			Description
	4	.37	Trust Indenture, dated as of August 13, 2001, among Kern River Funding Corporation, Kern River Gas Transmission Company and JP Morgan Chase Bank, Trustee, relating to the $510,000,000 in principal amount of the 6.676% Senior Notes due 2016 (incorporated by reference to Exhibit 10.48 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2003).
	4	.38	Third Supplemental Indenture, dated as of May 1, 2003, among Kern River Funding Corporation, Kern River Gas Transmission Company and JPMorgan Chase Bank, Trustee, relating to the $836,000,000 in principal amount of the 4.893% Senior Notes due 2018 (incorporated by reference to Exhibit 10.49 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2003).
	4	.39	Trust Deed, dated December 15, 1997 among CE Electric UK Funding Company, AMBAC Insurance UK Limited and The Law Debenture Trust Corporation, p.l.c., Trustee (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated March 30, 2004).
	4	.40	Insurance and Indemnity Agreement, dated December 15, 1997 by and between CE Electric UK Funding Company and AMBAC Insurance UK Limited (incorporated by reference to Exhibit 99.2 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated March 30, 2004).
	4	.41	Supplemental Agreement to Insurance and Indemnity Agreement, dated September 19, 2001, by and between CE Electric UK Funding Company and AMBAC Insurance UK Limited (incorporated by reference to Exhibit 99.3 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated March 30, 2004).
	4	.42	Fiscal Agency Agreement, dated as of September 4, 1998, by and between Northern Natural Gas Company and Chase Bank of Texas, National Association, Fiscal Agent, relating to the $150,000,000 in principal amount of the 6.75% Senior Notes due 2008 (incorporated by reference to Exhibit 10.69 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
	4	.43	Fiscal Agency Agreement, dated as of May 24, 1999, by and between Northern Natural Gas Company and Chase Bank of Texas, National Association, Fiscal Agent, relating to the $250,000,000 in principal amount of the 7.00% Senior Notes due 2011 (incorporated by reference to Exhibit 10.70 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
	4	.44	Trust Indenture, dated as of September 10, 1999, by and between Cordova Funding Corporation and Chase Manhattan Bank and Trust Company, National Association, Trustee, relating to the $225,000,000 in principal amount of the 8.75% Senior Secured Bonds due 2019 (incorporated by reference to Exhibit 10.71 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
	4	.45	Trust Deed, dated as of February 4, 1998 among Yorkshire Power Finance Limited, Yorkshire Power Group Limited and Bankers Trustee Company Limited, Trustee, relating to the £200,000,000 in principal amount of the 7.25% Guaranteed Bonds due 2028 (incorporated by reference to Exhibit 10.74 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).


Exhibit No.			Description
	4	.46	First Supplemental Trust Deed, dated as of October 1, 2001, among Yorkshire Power Finance Limited, Yorkshire Power Group Limited and Bankers Trustee Company Limited, Trustee, relating to the £200,000,000 in principal amount of the 7.25% Guaranteed Bonds due 2028 (incorporated by reference to Exhibit 10.75 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
	4	.47	Third Supplemental Trust Deed, dated as of October 1, 2001, among Yorkshire Electricity Distribution plc, Yorkshire Electricity Group plc and Bankers Trustee Company Limited, Trustee, relating to the £200,000,000 in principal amount of the 9.25% Bonds due 2020 (incorporated by reference to Exhibit 10.76 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
	4	.48	Indenture, dated as of February 1, 2000, among Yorkshire Power Finance 2 Limited, Yorkshire Power Group Limited and The Bank of New York, Trustee (incorporated by reference to Exhibit 10.78 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
	4	.49	First Supplemental Trust Deed, dated as of September 27, 2001, among Northern Electric Finance plc, Northern Electric plc, Northern Electric Distribution Limited and The Law Debenture Trust Corporation p.l.c., Trustee, relating to the £100,000,000 in principal amount of the 8.875% Guaranteed Bonds due 2020 (incorporated by reference to Exhibit 10.81 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
	4	.50	Trust Deed, dated as of January 17, 1995, by and between Yorkshire Electricity Group plc and Bankers Trustee Company Limited, Trustee, relating to the £200,000,000 in principal amount of the 9 1/4% Bonds due 2020 (incorporated by reference to Exhibit 10.83 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
	4	.51	Master Trust Deed, dated as of October 16, 1995, by and between Northern Electric Finance plc, Northern Electric plc and The Law Debenture Trust Corporation p.l.c., Trustee, relating to the £100,000,000 in principal amount of the 8.875% Guaranteed Bonds due 2020 (incorporated by reference to Exhibit 10.70 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2004).
	4	.52	Fiscal Agency Agreement, dated April 14, 2005, by and between Northern Natural Gas Company and J.P. Morgan Trust Company, National Association, Fiscal Agent, relating to the $100,000,000 in principal amount of the 5.125% Senior Notes due 2015 (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated April 18, 2005).
	4	.53	£100,000,000 Facility Agreement, dated April 4, 2005 among CE Electric UK Funding Company, the subsidiaries of CE Electric UK Funding Company listed in Part 1 of Schedule 1, Lloyds TSB Bank plc and The Royal Bank of Scotland plc (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated April 20, 2005).


Exhibit No.			Description
	4	.54	Trust Deed dated May 5, 2005 among Northern Electric Finance plc, Northern Electric Distribution Limited, Ambac Assurance UK Limited and HSBC Trustee (C.I.) Limited (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
	4	.55	Reimbursement and Indemnity Agreement dated May 5, 2005 among Northern Electric Finance plc, Northern Electric Distribution Limited and Ambac Assurance UK Limited (incorporated by reference to Exhibit 99.2 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
	4	.56	Trust Deed, dated May 5, 2005 among Yorkshire Electricity Distribution plc, Ambac Assurance UK Limited and HSBC Trustee (C.I.) Limited (incorporated by reference to Exhibit 99.3 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
	4	.57	Reimbursement and Indemnity Agreement, dated May 5, 2005 between Yorkshire Electricity Distribution plc and Ambac Assurance UK Limited (incorporated by reference to Exhibit 99.4 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
	4	.58	Supplemental Trust Deed, dated May 5, 2005 among CE Electric UK Funding Company, Ambac Assurance UK Limited and The Law Debenture Trust Corporation plc (incorporated by reference to Exhibit 99.5 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
	4	.59	Second Supplemental Agreement to Insurance and Indemnity Agreement, dated May 5, 2005 by and between CE Electric UK Funding Company and Ambac Assurance UK Limited (incorporated by reference to Exhibit 99.6 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
	4	.60	Amended and Restated Credit Agreement, dated as of July 6, 2006, among MidAmerican Energy Company, the Lending Institutions Party Hereto, as Banks, Union Bank of California, N.A., as Syndication Agent, JPMorgan Chase Bank, N.A., as Administrative Agent, and The Royal Bank of Scotland plc, ABN AMRO Bank N.V. and BNP Paribas as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2006).
	4	.61	Shareholders Agreement, dated as of March 14, 2000 (incorporated by reference to Exhibit 4.19 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
	4	.62	Amendment No. 1 to Shareholders Agreement, dated December 7, 2005 (incorporated by reference to Exhibit 4.17 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2005).
	4	.63	Equity Commitment Agreement, dated as of March 1, 2006, by and between Berkshire Hathaway Inc. and MidAmerican Energy Holdings Company (incorporated by reference to Exhibit 10.72 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2005).


Exhibit No.			Description
	4	.64	Fiscal Agency Agreement, dated February 12, 2007, by and between Northern Natural Gas Company and Bank of New York Trust Company, N.A., Fiscal Agent, relating to the $150,000,000 in principal amount of the 5.80% Senior Bonds due 2037 (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated February 12, 2007).
	4	.65	Indenture, dated as of October 1, 2006, by and between MidAmerican Energy Company and the Bank of New York Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended September 30, 2006).
	4	.66	First Supplemental Indenture, dated as of October 6, 2006, by and between MidAmerican Energy Company and the Bank of New York Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.2 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended September 30, 2006).
	4	.67	Second Supplemental Indenture, dated June 29, 2007, by and between MidAmerican Energy Company and The Bank of New York Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Current Report on Form 8-K dated June 29, 2007).
	4	.68	Third Supplemental Indenture between MidAmerican Energy Company and The Bank of New York Trust Company, N.A. dated March 25, 2008 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Current Report on Form 8-K dated March 25, 2008).
	4	.69	Mortgage and Deed of Trust dated as of January 9, 1989, between PacifiCorp and JP Morgan Chase Bank (formerly known as The Chase Manhattan Bank), Trustee, incorporated by reference to Exhibit 4-E to PacifiCorp’s Form 8-B, File No. 1-5152, as supplemented and modified by 21 Supplemental Indentures, each incorporated by reference, as follows:


Exhibit Number	PacifiCorp File Type	File Date	File Number
(4)(b)	SE	November 2, 1989	33-31861
(4)(a)	8-K	January 9, 1990	1-5152
(4)(a)	8-K	September 11, 1991	1-5152
4(a)	8-K	January 7, 1992	1-5152
4(a)	10-Q	Quarter ended March 31, 1992	1-5152
4(a)	10-Q	Quarter ended September 30, 1992	1-5152
4(a)	8-K	April 1, 1993	1-5152
4(a)	10-Q	Quarter ended September 30, 1993	1-5152
(4)b	10-Q	Quarter ended June 30, 1994	1-5152
(4)b	10-K	Year ended December 31, 1994	1-5152
(4)b	10-K	Year ended December 31, 1995	1-5152
(4)b	10-K	Year ended December 31, 1996	1-5152
(4)b	10-K	Year ended December 31, 1998	1-5152
99(a)	8-K	November 21, 2001	1-5152
4.1	10-Q	Quarter ended June 30, 2003	1-5152
99	8-K	September 8, 2003	1-5152
4	8-K	August 24, 2004	1-5152
4	8-K	June 13, 2005	1-5152
4.2	8-K	August 14, 2006	1-5152
4	8-K	March 14, 2007	1-5152
4.1	8-K	October 3, 2007	1-5152


Exhibit No.			Description
	4	.70	$700,000,000 Credit Agreement dated as of October 23, 2007 among PacifiCorp, The Banks Party thereto, The Royal Bank of Scotland plc, as Syndication Agent, and Union Bank of California, N.A., as Administrative Agent (incorporated by reference to Exhibit 99 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended September 30, 2007).
	5	.1	Opinion of Willkie Farr & Gallagher LLP.*
	8	.1	Opinion of Willkie Farr & Gallagher LLP with respect to certain tax matters.*
	10	.1	Amended and Restated Employment Agreement, dated February 25, 2008, by and between MidAmerican Energy Holdings Company and David L. Sokol (incorporated by reference to Exhibit 10.1 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2007).
	10	.2	Non-Qualified Stock Option Agreements of David L. Sokol, dated March 14, 2000 (incorporated by reference to Exhibit 10.3 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002) and the related 2000 Stock Option Plan attached as Exhibit A thereto (incorporated by reference to Exhibit 10.3 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-143286 dated May 25, 2007).
	10	.3	Amended and Restated Employment Agreement, dated February 25, 2008, by and between MidAmerican Energy Holdings Company and Gregory E. Abel (incorporated by reference to Exhibit 10.3 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2007).
	10	.4	Non-Qualified Stock Option Agreements of Gregory E. Abel, dated March 14, 2000 (incorporated by reference to Exhibit 10.5 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002) and the related 2000 Stock Option Plan attached as Exhibit A thereto (incorporated by reference to Exhibit 10.5 of MidAmerican Energy Holdings Company’s Registration Statement No. 333-143286 dated May 25, 2007).
	10	.5	Amended and Restated Employment Agreement, dated February 25, 2008, by and between MidAmerican Energy Holdings Company and Patrick J. Goodman (incorporated by reference to Exhibit 10.5 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2007).
	10	.6	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 the CE Casecnan Water and Energy Company, Inc. Registration Statement on Form S-4 dated January 25, 1996).
	10	.7	Supplemental Agreement, dated as of September 29, 2003, by and between CE Casecnan Water and Energy Company, Inc. and the Philippines National Irrigation Administration (incorporated by reference to Exhibit 98.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated October 15, 2003).
	10	.8	CalEnergy Company, Inc. Voluntary Deferred Compensation Plan, effective December 1, 1997, First Amendment, dated as of August 17, 1999, and Second Amendment effective March 14, 2000 (incorporated by reference to Exhibit 10.50 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).


Exhibit No.			Description
	10	.9	MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan restated effective as of January 1, 2007 (incorporated by reference to Exhibit 10.9 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2007).
	10	.10	MidAmerican Energy Company First Amended and Restated Supplemental Retirement Plan for Designated Officers dated as of May 10, 1999 amended on February 25, 2008 to be effective as of January 1, 2005 (incorporated by reference to Exhibit 10.10 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2007).
	10	.11	MidAmerican Energy Holdings Company Long-Term Incentive Partnership Plan as Amended and Restated January 1, 2007 (incorporated by reference to Exhibit 10.11 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2007).
	10	.12	Summary of Key Terms of Compensation Arrangements with MidAmerican Energy Holdings Company Named Executive Officers and Directors (incorporated by reference to Exhibit 10.12 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2007).
	12	.1	Computation of Ratios of Earnings to Fixed Charges.
	14	.1	MidAmerican Energy Holdings Company Code of Ethics for Chief Executive Officer, Chief Financial Officer and Other Covered Officers (incorporated by reference to Exhibit 14.1 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2003).
	15	.1	Awareness Letter of Deloitte & Touche LLP.
	21	.1	Subsidiaries of the Registrant (incorporated by reference to Exhibit 21.1 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2007).
	23	.1	Consent of Willkie Farr & Gallagher LLP (included in their opinions filed as Exhibits 5.1 and 8.1).*
	23	.2	Consent of Deloitte & Touche LLP.
	24	.1	Power of Attorney (included on signature page hereto).
	25	.1	Statement on Form T-1 of Eligibility of Trustee relating to the 5.75% Senior Notes due 2018.
	99	.1	Form of Letter of Transmittal relating to the 5.75% Senior Notes due 2018.
	99	.2	Form of Notice of Guaranteed Delivery relating to the 5.75% Senior Notes due 2018.
	99	.3	Form of Letter to Clients relating to the 5.75% Senior Notes due 2018.
	99	.4	Form of Letter to Nominees relating to the 5.75% Senior Notes due 2018.


Iowa	4900	94-2213782
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)



Title of Each Class of Securities to be Registered	Amount to be Registered			Proposed Maximum Offering Price⁽¹⁾			Proposed Maximum Aggregate Offering Price⁽¹⁾			Amount of Registration Fee
5.75% Senior Notes due April 1, 2018		$	650,000,000		100	%		$	650,000,000		$	25,545


	Domestic Plans
								Other Postretirement Benefit Plans							United Kingdom Pension Plan
	Pension Plans							Other Postretirement Benefit Plans							United Kingdom Pension Plan
	+0.5%				−0.5%			+0.5%				−0.5%			+0.5%				−0.5%
Effect on December 31, 2007, Benefit Obligations:
Discount rate		$	(97	)		$	107		$	(45	)		$	50		$	(149	)		$	167
Effect on 2007 Periodic Cost:
Discount rate		$	(9	)		$	10		$	(4	)		$	4		$	(8	)		$	8
Expected return on assets			(7	)			7			(3	)			3			(8	)			8


	Fair Value – Asset (Liability)				Hypothetical Price Change	Estimated Fair Value after Hypothetical Change in Price
As of December 31, 2007		$	(263	)	10% increase		$	(208	)
					10% decrease			(318	)


Net Income			Award
Less than or equal to net income target goal			None
Exceeds net income target goal by 0.01% – 3.25%			15% of excess
Exceeds net income target goal by 3.251% – 6.50%			15% of the first 3.25% excess; 25% of excess over 3.25%
Exceeds net income target goal by more than 6.50%			15% of the first 3.25% excess; 25% of the next 3.25% excess; 35% of excess over 6.50%


	•	We are offering to exchange new registered 5.75% senior notes due April 1, 2018 for all of our outstanding unregistered 5.75% senior notes due April 1, 2018.


	•	The exchange offer expires at 5:00 p.m., New York City time, on, 2008, unless extended.


	•	The exchange offer is subject to customary conditions that may be waived by us.


	•	All initial notes outstanding that are validly tendered and not validly withdrawn prior to the expiration of the exchange offer will be exchanged for the exchange notes.


	•	Tenders of initial notes may be withdrawn at any time before 5:00 p.m., New York City time, on the expiration date of the exchange offer.


	•	The terms of the exchange notes to be issued are substantially identical to the terms of the initial notes, except that the exchange notes will not have transfer restrictions, and you will not have registration rights.


	•	There is no established trading market for the exchange notes, and we do not intend to apply for listing of the exchange notes on any securities exchange or market quotation system.


	Page
Summary		1
Risk Factors		10
Disclosure Regarding Forward-Looking Statements		26
Use of Proceeds		28
The Exchange Offer		29
Capitalization		39
Selected Historical Financial and Operating Data		40
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		42
QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK		65
BUSINESS		68
REGULATION		90
PROPERTIES		107
LEGAL PROCEEDINGS		108
MANAGEMENT		112
DESCRIPTION OF THE NOTES		129
CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS		145
PLAN OF DISTRIBUTION		146
LEGAL MATTERS		147
EXPERTS		147
WHERE YOU CAN FIND MORE INFORMATION		147
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE		148
FINANCIAL STATEMENTS		F-1


The Exchange Offer		This is an offer to exchange $1,000 in principal amount of the exchange notes for each $1,000 in principal amount of the initial notes. The exchange notes are substantially identical to the initial notes, except that the exchange notes will generally be freely transferable. We believe that you can transfer the exchange notes without complying with the registration and prospectus delivery provisions of the Securities Act if you:


		•	acquire the exchange notes in the ordinary course of your business;


		•	are not and do not intend to become engaged in a distribution of the exchange notes;


		•	are not an ‘‘affiliate’’ (within the meaning of the Securities Act) of ours;


		•	are not a broker-dealer (within the meaning of the Securities Act) that acquired the initial notes from us or our affiliates; and


		If any of these conditions are not satisfied and you transfer any exchange notes without delivering a proper prospectus or without qualifying for a registration exemption, you may incur liability under the Securities Act. See ‘‘The Exchange Offer — Terms of the Exchange.’’


Registration Rights Agreement		We have agreed to file an exchange offer registration statement or, under certain circumstances, a shelf registration statement pursuant to a registration rights agreement with respect to the notes. If we fail to comply with certain of our obligations under the registration rights agreement, we will pay additional interest in cash on all or a portion of the notes, as applicable, for the periods specified in the registration rights agreement. See ‘‘The Exchange Offer.’’


Minimum Condition		The exchange offer is not conditioned on any minimum aggregate principal amount of initial notes being tendered for exchange.


Expiration Date		The exchange offer will expire at 5:00 p.m., New York City time, on , 2008, unless we extend it.


Exchange Date		The initial notes will be accepted for exchange at the time when all conditions of the exchange offer are satisfied or waived. The exchange notes will be delivered promptly after we accept the initial notes.


Conditions to the Exchange		Our obligation to complete the exchange offer is subject to certain conditions. See ‘‘The Exchange Offer — Conditions to the Exchange Offer.’’ We reserve the right to terminate or amend the exchange offer at any time prior to its expiration on the expiration date.


Withdrawal Rights		You may withdraw the tender of your initial notes at any time before the expiration of the exchange offer on the expiration date. Any initial notes not accepted for any reason will be returned to you without expense as promptly as practicable after the expiration or termination of the exchange offer.


Procedures for Tendering Initial Notes		See ‘‘The Exchange Offer — How to Tender.’’


U.S. Federal Income Tax Consequences		The exchange of the initial notes for the exchange notes will not be a taxable exchange for U.S. federal income tax purposes, and holders will not recognize any taxable gain or loss as a result of such exchange.


Effect on Holders of Initial Notes		If the exchange offer is completed on the terms and within the period contemplated by this prospectus, holders of the initial notes will have no further registration or other rights under the registration rights agreement, except under limited circumstances. See ‘‘The Exchange Offer — Other.’’


		Holders of initial notes who do not tender their initial notes will continue to hold those initial notes. All untendered, and tendered but unaccepted, initial notes will continue to be subject to the transfer restrictions provided for in the initial notes and the indenture under which the initial notes have been issued. To the extent that the initial notes are tendered and accepted in the exchange offer, the trading market, if any, for the initial notes could be adversely affected. See ‘‘Risk Factors — Other Risks Associated with the Notes.’’ You may not be able to sell your initial notes if you do not exchange them for registered exchange notes in the exchange offer. Your


		ability to sell your initial notes may be significantly more limited and the price at which you may be able to sell your initial notes may be significantly lower if you do not exchange them for registered exchange notes in the exchange offer. See ‘‘The Exchange Offer — Other.’’


Exchange Agent		The Bank of New York Trust Company, N.A., is serving as the exchange agent in connection with the exchange offer.


General		$650,000,000 aggregate principal amount of 5.75% Senior Notes due 2018. The initial notes were, and the exchange notes will be, issued under a seventh supplement to the indenture, dated as of October 4, 2002, as amended to date, between us and The Bank of New York, as trustee. On October 4, 2002, we issued $200,000,000 of our 4.625% Senior Notes due 2007 (which we refer to as the series A notes) and $500,000,000 of our 5.875% Senior Notes due 2012 (which we refer to as the series B notes); on May 16, 2003, we issued $450,000,000 of our 3.50% Senior Notes due 2008 (which we refer to as the series C notes); on February 12, 2004, we issued $250,000,000 of our 5.00% Senior Notes due 2014 (which we refer to as the series D notes); on March 24, 2006, we issued $1,700,000,000 of our 6.125% Senior Bonds due 2036 (which we refer to as the series E bonds); on May 11, 2007, we issued $550,000,000 of our 5.95% Senior Bonds due 2037 (which we refer to as the series F bonds) and on August 28, 2007, we issued $1,000,000,000 of our 6.50% Senior Bonds due 2037 (which we refer to as the series G bonds), in each case pursuant to the indenture. The series A notes and the series C notes have been repaid in full. Unless otherwise indicated, references to the securities in this prospectus include the series B notes, the series D notes, the series E bonds, the series F bonds, the series G bonds and the notes (and any other series of notes, bonds or other securities hereafter issued under a supplemental indenture or otherwise pursuant to the indenture).


Interest Payment Dates		April 1 and October 1, commencing October 1, 2008.


Optional Redemption		We may redeem the notes, at our option, in whole or in part, at any time, at a redemption price equal to the greater of:


		(1)	100% of the principal amount of the notes to be redeemed; or