**UNITED
      STATES**


**SECURITIES
      AND EXCHANGE COMMISSION**


Washington,
      D.C. 20549





**FORM
      10-K**





**[X]
      Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act
      of
      1934**





For
      the
      fiscal year ended December 31, 2005





or





**[
      ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange
      Act of 1934**





For
      the
      transition period from ______ to _______





Commission
      File No .
      001-14881





**MIDAMERICAN
      ENERGY HOLDINGS COMPANY**


(Exact
      name of registrant as specified in its charter)





Iowa
            
            94-2213782(State
                or other jurisdiction of
            
            (I.R.S.
                Employerincorporation
                or organization)
            
            Identification
                No.)666
                Grand Avenue, Des Moines, Iowa
            
            50309(Address
                of principal executive offices)
            
            (Zip
                Code)(515)
                242-4300(Registrant’s
                telephone number, including area
                code)





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


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





Indicate
      by check mark if the registrant is a well-known seasoned issuer, as defined
      in
      Rule 405 of the Securities Act.


Yes  ̈ No T





Indicate
      by check mark if the registrant is not required to file reports pursuant to
      Section 13 or Section 15(d) of the Act.


Yes T No o





Indicate
      by check mark whether the registrant: (1) has filed all reports required to
      be
      filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
      the
      preceding 12 months (or for such shorter period that the registrant was required
      to file such reports), and (2) has been subject to such filing requirements
      for
      the past 90 days. Yes  ̈ No T





Indicate
      by check mark if disclosure of delinquent filers pursuant to Item 405 of
      Regulation S-K is not contained herein, and will not be contained, to the best
      of the registrant’s knowledge, in definitive proxy or information statements
      incorporated by reference in Part III of this Form 10-K or any amendment to
      this
      Form 10-K. T





Indicate
      by check mark whether the registrant is a large accelerated filer, an
      accelerated filer, or a non-accelerated filer. See the definition of
“accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange
      Act. (Check one):





Large
      accelerated filer  ̈   Accelerated
      filer  ̈   Non-accelerated
      filer T





Indicate
      by check mark whether the registrant is a shell company (as defined in rule
      12b-2 of the Exchange Act).


Yes  ̈ No T





All
      of
      the shares of common equity of MidAmerican Energy Holdings Company are privately
      held by a limited group of investors. As of March 1, 2006, 50,544,482 shares
      of
      common stock were outstanding.











**TABLE
      OF CONTENTS**











**PART
      I**





Item
                1.
            Business
            4Item
                1A.
            Risk
                Factors
            29Item
                1B.
            Unresolved
                Staff Comments
            36Item
                2.
            Properties
            37Item
                3.
            Legal
                Proceedings
            39Item
                4.
            Submission
                of Matters to a Vote of Security
                Holders
            39**PART
                II**Item
                5.
            Market
                for Registrant’s Common Equity, Related Stockholder
                Matters and Issuer Purchases of Equity Securities
            40Item
                6.
            Selected
                Financial Data
            40Item
                7.
            Management’s
                Discussion and Analysis of Financial
                Condition and Results of Operations
            41Item
                7A.
            Quantitative
                and Qualitative Disclosures About Market
                Risk
            61Item
                8.
            Financial
                Statements and Supplementary
                Data
            65Item
                9.
            Changes
                in and Disagreements with Accountants on
                Accounting and Financial Disclosure
            113Item
                9A.
            Controls
                and Procedures
            113Item
                9B.
            Other
                Information
            113**PART
                III**Item
                10.
            Directors
                and Executive Officers of the
                Registrant
            114Item
                11.
            Executive
                Compensation
            115Item
                12.
            Security
                Ownership of Certain Beneficial Owners and
                Management and Related Stockholder Matters
            119Item
                13.
            Certain
                Relationships and Related
                Transactions
            120Item
                14.
            Principal
                Accountant Fees and
                Services
            120**PART
                IV**Item
                15.
            Exhibits
                and Financial Statement
                Schedules
            122Signatures
            
            127Exhibit
                Index
            
            128














2





**Disclosure
      Regarding Forward-Looking Statements**





This
      report 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,” “will,” “could,” “project,” “believe,” “anticipate,”
“expect,” “estimate,” “continue,” “potential,” “plan,” “forecast,” and similar
      terms. These statements are based upon the Company’s current intentions,
      assumptions, expectations and beliefs and are subject to risks, uncertainties
      and other important factors. Many of these factors are outside the Company’s
      control and could cause actual results to differ materially from those expressed
      or implied by the Company’s forward-looking statements. These factors include,
      among others:





·
            general
                economic, political and business conditions in the jurisdictions
                in which
                the Company’s facilities are
                located;


·
            the
                financial condition and creditworthiness of the Company’s significant
                customers and suppliers;


·
            governmental,
                statutory, legislative, regulatory or administrative initiatives,
                including those relating to the recently enacted Energy Policy Act
                of 2005
                (“Energy Policy Act”), or ratemaking actions affecting the Company or the
                electric or gas utility, pipeline or power generation
                industries;


·
            the
                outcome of general rate cases and other proceedings conducted before
                regulatory authorities;


·
            weather
                effects on sales and revenue;


·
            changes
                in expected customer growth or usage of electricity or
                gas;


·
            economic
                or industry trends that could impact electricity or gas
                usage;


·
            increased
                competition in the power generation, electric and gas utility or
                pipeline
                industries;


·
            fuel,
                fuel transportation and power costs and
                availability;


·
            continued
                availability of accessible gas
                reserves;


·
            changes
                in business strategy, development plans or customer or vendor
                relationships;


·
            availability,
                terms and deployment of capital;


·
            availability
                of qualified personnel;


·
            unscheduled
                outages or repairs;


·
            risks
                relating to nuclear generation;


·
            financial
                or regulatory accounting principles or policies imposed by the Public
                Company Accounting Oversight Board, the Financial Accounting Standards
                Board (“FASB”), the U.S. Securities and Exchange Commission (“SEC”), the
                Federal Energy Regulatory Commission (“FERC”), state public utility
                commissions and similar entities with regulatory
                oversight;


·
            changes
                in, and compliance with, environmental laws, regulations, decisions
                and
                policies that could increase operating and capital improvement costs
                or
                affect plant output and/or delay plant
                construction;


·
            the
                Company’s ability to consummate the acquisition of PacifiCorp and,
                following the consummation of such acquisition, to successfully integrate
                PacifiCorp’s operations into the Company’s
                business;


·
            other
                risks or unforeseen events, including wars, the effects of terrorism,
                embargoes and other catastrophic events;
                and


·
            other
                business or investment considerations that may be disclosed from
                time to
                time in SEC filings or in other publicly disseminated written
                documents.





Further
      details of the potential risks and uncertainties affecting the Company are
      described in MidAmerican Energy Holdings Company’s filings with the SEC,
      including Item 1A. Risk Factors and other discussions contained in this Form
      10-K. MidAmerican Energy Holdings Company undertakes 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.


3


**PART
      I**





Item
      1.Business.





**General**





MidAmerican
      Energy Holdings Company (“MEHC”) and its subsidiaries (together with MEHC, the
“Company”) are organized and managed as seven distinct platforms: MidAmerican
      Funding, LLC (“MidAmerican Funding”) (which primarily includes MidAmerican
      Energy Company (“MidAmerican Energy”)), Kern River Gas Transmission Company
      (“Kern River”), Northern Natural Gas Company (“Northern Natural Gas”), 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 (the subsidiaries owning the Upper Mahiao, Malitbog and
      Mahanagdong projects (collectively, the “Leyte Projects”) and the Casecnan
      Project), CalEnergy Generation-Domestic (the subsidiaries owning interests
      in
      independent power projects in the United States), and HomeServices of America,
      Inc. (collectively with its subsidiaries, “HomeServices”). Refer to Note 22 of
      Notes to Consolidated Financial Statements included in Item 8. Financial
      Statements and Supplementary Data of this Form 10-K for additional segment
      information regarding the Company’s platforms. Through these platforms, the
      Company owns and operates a combined electric and natural gas utility company
      in
      the United States, two natural gas pipeline companies in the United States,
      two
      electricity distribution companies in Great Britain, a diversified portfolio
      of
      domestic and international independent power projects and the second largest
      residential real estate brokerage firm in the United States.





MEHC’s
      energy subsidiaries generate, transmit, store, distribute and supply energy.
      MEHC’s electric and natural gas utility subsidiaries currently serve
      approximately 4.4 million electricity customers and approximately 688,000
      natural gas customers. MEHC's natural gas pipeline subsidiaries operate
      interstate natural gas transmission systems that have approximately 18,100
      miles
      of pipeline in operation, a peak delivery capacity of 6.6 billion cubic
      feet of natural gas per day and transported approximately 7.8% of the total
      natural gas consumed in the United States in 2005. The Company has interests
      in
      6,740 net owned megawatts of power generation facilities in operation and under
      construction, including 5,166 net owned megawatts in facilities that are part
      of
      the regulated asset base of its electric utility business and 1,574 net owned
      megawatts in non-utility power generation facilities. Substantially all of
      the
      non-utility power generation facilities have long-term contracts for the sale
      of
      energy and/or capacity from the facilities.





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





On
      March 14, 2000, MEHC and an investor group including Berkshire Hathaway
      Inc. (“Berkshire Hathaway”), Walter Scott, Jr., a director of MEHC, David L.
      Sokol, Chairman and Chief Executive Officer of MEHC, and Gregory E. Abel,
      President and Chief Operating Officer of MEHC, executed a definitive agreement
      and plan of merger whereby the investor group acquired all of the outstanding
      common stock of MEHC (the “Teton Transaction”). As of December 31, 2005
      Walter Scott, Jr. (including family members and related entities), Berkshire
      Hathaway, David L. Sokol and Gregory E. Abel owned 86.2%, 9.7%,
      3.5% and 0.6%, respectively, of MEHC’s voting common stock and held diluted
      ownership interests of 15.3%, 80.5%, 2.9% and 1.3%, respectively.





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





4


In
      this
      annual report, references to “U.S. dollars,” “dollars,” “$” or “cents” are to
      the currency of the United States, references to “pounds sterling,” “£,”
“sterling,” “pence” or “p” are to the currency of Great Britain and references
      to “pesos” are to the currency of the Philippines. References to kW means
      kilowatts, MW means megawatts, GW means gigawatts, kWh means kilowatt hours,
      MWh
      means megawatt hours, GWh means gigawatt hours, kV means kilovolts, MMcf means
      million cubic feet, Bcf means billion cubic feet, Tcf means trillion cubic
      feet
      and Dth means decatherms or one million British thermal units.





**Recent
      Developments Regarding the Pending PacifiCorp Acquisition**





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, a regulated electric utility providing service to approximately
      1.6 million customers in California, Idaho, Oregon, Utah, Washington and
      Wyoming. MEHC will purchase all of the outstanding shares of the PacifiCorp
      common stock for approximately $5.1 billion in cash. The long-term debt and
      preferred stock of PacifiCorp, which aggregated $4.3 billion at
      December 31, 2005, will remain outstanding. As of March 1, 2006, all
      state and federal approvals required for the acquisition were
      obtained, subject to  completion of a "most favored states"
      process in Wyoming, Washington, Utah, Idaho and Oregon that
      allows  each such state to  make applicable to that state
      any acquisition commitments or conditions accepted in other
      PacifiCorp states. Subject to the most favored states process and other
      customary closing conditions, the transaction is expected to close in March
      2006. MEHC expects to fund the acquisition of PacifiCorp with the proceeds
      from
      an investment by Berkshire Hathaway and other existing shareholders of
      approximately $3.4 billion in MEHC common stock and the issuance by MEHC of
      $1.7 billion of either additional common stock to Berkshire Hathaway or
      long-term senior notes to third parties.





**Recent
      Developments Regarding Berkshire Hathaway**





On
      February 9, 2006, following the effective date of the repeal of the Public
      Utility Holding Company Act of 1935 (“PUHCA 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. As a consequence,
      Berkshire Hathaway owns 83.4% (80.5% on a diluted basis) of the outstanding
      common stock of MEHC, will consolidate the Company in its financial statements
      as a majority-owned subsidiary, and will include the Company in its consolidated
      federal U.S. income tax return.





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, and will not be used for the PacifiCorp acquisition
      or for other future acquisitions.





**MidAmerican
      Energy**





MidAmerican
      Energy, an indirect wholly-owned subsidiary of MEHC, is a public utility company
      headquartered in Iowa and is principally engaged in the business of generating,
      transmitting, distributing and selling electric energy and in distributing,
      selling and transporting natural gas. MidAmerican Energy distributes electricity
      at 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. As of December 31, 2005, MidAmerican Energy had
      approximately 706,000 regulated retail electric customers and 688,000 regulated
      retail and transportation natural gas customers.





In
      addition to retail sales and natural gas transportation, MidAmerican Energy
      sells electric energy and natural gas to other utilities, marketers and
      municipalities. These sales are referred to as wholesale sales.


5


MidAmerican
      Energy’s regulated electric and gas operations are conducted under 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. Among the primary
      industries served by MidAmerican Energy are those that are concerned with food
      products, the manufacturing, processing and fabrication of primary metals,
      real
      estate, farm and other non-electrical machinery, and cement and gypsum
      products.





MidAmerican
      Energy also conducts a number of nonregulated business activities, which include
      a variety of activities outside of the traditional regulated electric and
      natural gas services.





MidAmerican
      Energy derived its operating revenues from the following business
      activities.





Year
                Ended December 31,2005
            
            2004
            
            2003Regulated
                electric
            
            
            47.9
            %
            
            52.7
            %
            
            53.9
            %Regulated
                gas
            
            
            41.8
            
            
            37.5
            
            
            36.5Nonregulated
            
            
            10.3
            
            
            9.8
            
            
            9.6100.0
            %
            
            100.0
            %
            
            100.0
            %





*Electric
      Operations*





The
      percentage of regulated electric revenue by customer class follows:





Year
                Ended December 31,2005
            
            2004
            
            2003Residential
            
            
            21.3
            %
            
            19.6
            %
            
            19.4
            %Small
                general service(1)
            
            
            15.0
            
            
            14.5
            
            
            14.0Large
                general service(2)
            
            
            27.9
            
            
            26.7
            
            
            25.4Wholesale(3)
            
            
            30.5
            
            
            34.2
            
            
            36.4Other
            
            
            5.3
            
            
            5.0
            
            
            4.8100.0
            %
            
            100.0
            %
            
            100.0
            %





(1)
            Small
                general service generally includes commercial and industrial customers
                with a demand of 200 kilowatts or less.(2)
            Large
                general service generally includes commercial and industrial customers
                with a demand of more than 200 kilowatts.(3)
            Wholesale
                generally includes other utilities, marketers and municipalities
                to whom
                electric energy is sold at wholesale for resale to ultimate
                customers.





The
      percentage of regulated electric revenue by jurisdiction follows:





Year
                Ended December 31,2005
            
            2004
            
            2003Iowa
            
            
            89.0
            %
            
            88.7
            %
            
            88.8
            %Illinois
            
            
            10.1
            
            
            10.3
            
            
            10.4South
                Dakota
            
            
            0.9
            
            
            1.0
            
            
            0.8100.0
            %
            
            100.0
            %
            
            100.0
            %





6


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 July 20,
      2005, retail customer usage of electricity caused a new record hourly peak
      demand of 4,040 MW on MidAmerican Energy’s electric system, an increase of 105
      MW from the previous record of 3,935 MW set in August 2003.





MidAmerican
      Energy is exposed to fluctuations in energy costs relating to retail sales
      in
      Iowa as it does not have an energy adjustment clause. Under its Illinois and
      South Dakota electric tariffs, MidAmerican Energy is allowed to recover
      fluctuations in the cost of all fuels and purchased energy used for retail
      electric generation through a fuel cost adjustment clause.





The
      following table sets out certain information concerning MidAmerican Energy’s
      power generation facilities based upon summer 2005 accreditation and expected
      accredited generating capacity of projects recently completed or under
      construction:





**Facility
                Net****Capacity**
            
            **Net
                MW**
            
            **Energy**
            
            
            
            **Year****Operating
                Project****(1)**
            
            **(MW)****(2)**
            
            **Owned****(2)**
            
            **Source**
            
            **Location**
            
            **In-Service**Steam
                Electric Generating Facilities:Council
                Bluffs Energy Center Units 1 and 2
            
            133
            
            133
            
            Coal
            
            Iowa
            
            1954,
                1958Council
                Bluffs Energy Center Unit 3
            
            690
            
            546
            
            Coal
            
            Iowa
            
            1978Louisa
                Generation Station
            
            700
            
            616
            
            Coal
            
            Iowa
            
            1983Neal
                Generation Station Units 1 and 2
            
            435
            
            435
            
            Coal
            
            Iowa
            
            1964,
                1972Neal
                Generation Station Unit 3
            
            515
            
            371
            
            Coal
            
            Iowa
            
            1975Neal
                Generation Station Unit 4
            
            644
            
            261
            
            Coal
            
            Iowa
            
            1979Ottumwa
                Generation Station
            
            673
            
            350
            
            Coal
            
            Iowa
            
            1981Riverside
                Generation Station
            
            135
            
            135
            
            Coal
            
            Iowa
            
            1925,
                1961Total
                steam electric generating facilities
            
            3,925
            
            2,847Other
                Facilities:Combustion
                Turbines
            
            792
            
            792
            
            Gas/Oil
            
            Iowa
            
            Various(3)Combined
                Cycle - Greater Des Moines Energy Center
            
            491
            
            491
            
            Gas
            
            Iowa
            
            2003-2004Quad
                Cities Generating Station
            
            1,748
            
            437
            
            Nuclear
            
            Illinois
            
            1972Portable
                Power Modules
            
            56
            
            56
            
            Oil
            
            Iowa
            
            2000Wind
                - Intrepid(4)
            
            33
            
            33
            
            Wind
            
            Iowa
            
            2005Moline
                Water Power
            
            3
            
            3
            
            Water
            
            Illinois
            
            1970Total
                other facilities
            
            3,123
            
            1,812Total
                accredited generating capacity
            
            7,048
            
            4,659Projects
                Recently Completed or Under Construction:Council
                Bluffs Energy Center Unit 4
            
            790
            
            479
            
            Coal
            
            Iowa
            
            2007Wind
                - Century(4)
            
            28
            
            28
            
            Wind
            
            Iowa
            
            2005Total
                projects recently completed or under construction
            
            818
            
            5077,866
            
            5,166





7


**______________**





(1)
            MidAmerican
                Energy operates all such power generation facilities other than Quad
                Cities Generating Station and Ottumwa Generation
                Station.




(2)
            Represents accredited net generating capacity from
              the
              summer of 2005 and the expected accredited generating capacity of projects
              recently completed or under construction. Actual MW may vary depending
              on
              operating conditions and plant design for operating projects. Net MW
              Owned
              indicates ownership of accredited capacity for the summer of 2005 as
              approved by the Mid-Continent Area Power Pool
              (“MAPP”).




(3)
            A
                total of 629 MW were placed in-service between 1966 and 1978 while
                the
                three turbines totaling 120 MW at the Pleasant Hill facility were
                placed
                in-service between 1990 and 1994.




(4)
            MidAmerican
                Energy owns 360.5 MW (nameplate rating) of wind power facilities.
                The 61
                MW of accredited capacity ratings for these wind power facilities
                included
                in the table above are considerably less than the nameplate ratings
                due to
                the varying nature of wind.  MidAmerican
      Energy’s total accredited net generating capability in the summer of 2005 was
      5,098 MW. Accredited net generating capability represents the amount of
      generation available to meet the requirements on MidAmerican Energy’s system and
      consists of MidAmerican Energy-owned generation of 4,659 MW and the net amount
      of capacity purchases and sales of 439 MW. Accredited capacity may vary from
      the
      nameplate capacity ratings. Additionally, the actual amount of generation
      capacity available at any time may be less than the accredited capacity due
      to
      regulatory restrictions, transmission constraints, fuel restrictions and
      generating units being temporarily out of service for inspection, maintenance,
      refueling, modifications or other reasons.





In
      2005,
      MidAmerican Energy completed construction of its 360.5 MW (nameplate rating)
      wind power project that consists of facilities located at two sites in north
      central Iowa. As of December 31, 2004, wind turbines totaling 160.5 MW at
      the Intrepid site were completed and in service, and in the third quarter of
      2005, wind turbines totaling 150 MW at the Century site were placed in service.
      The remaining 50 MW of wind turbines were completed in December 2005, of which
      35 MW are located at the Century site and 15 MW are at the Intrepid site.
      Generally speaking, accredited capacity ratings for wind power facilities are
      considerably less than the nameplate ratings due to the varying nature of wind.
      The current total projected accredited capacity for these wind power facilities
      is approximately 61 MW. MidAmerican Energy owns and operates these facilities.
      On December 16, 2005, MidAmerican Energy made a filing with the Iowa
      Utilities Board (“IUB”) for approval to add up to 545 MW (nameplate rating) of
      additional wind generation capacity in Iowa.





MidAmerican
      Energy is currently constructing Council Bluffs Energy Center Unit No. 4 (“CBEC
      Unit 4”), a 790 MW (based on expected accreditation) super-critical-temperature,
      low sulfur coal-fired generating plant. MidAmerican Energy will operate the
      plant and hold an undivided ownership interest as a tenant in common with the
      other owners of the plant. MidAmerican Energy’s current ownership interest is
      60.67%, equating to 479 MW of output. Municipal, cooperative and public power
      utilities will own the remainder, which is a typical ownership arrangement
      for
      large base-load plants in Iowa. The facility will provide service to regulated
      retail electricity customers. Wholesale sales may also be made from the project
      to the extent the power is not immediately needed for regulated retail service.
      MidAmerican Energy has obtained regulatory approval to include the Iowa portion
      of the actual cost of the generation project in its Iowa rate base as long
      as
      the actual cost does not exceed the agreed cap that MidAmerican Energy has
      deemed to be reasonable. If the cap is exceeded, MidAmerican Energy has the
      right to demonstrate the prudence of the expenditures above the cap, subject
      to
      regulatory review. MidAmerican Energy expects to invest approximately
      $737 million in CBEC Unit 4, including transmission facilities and
      excluding allowance for funds used during construction. Through
      December 31, 2005, MidAmerican Energy has invested $502.0 million in
      the project, including $121.3 million for MidAmerican Energy’s share of
      deferred payments allowed by the construction contract.





MidAmerican
      Energy is interconnected with Iowa utilities and utilities in neighboring
      states. MidAmerican Energy is also party to an electric generation reserve
      sharing pool and regional transmission group administered by the MAPP. The
      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.
      The MAPP performs functions including administration of its short-term regional
      Open Access Transmission Tariff (“OATT”), coordination of regional planning and
      operations, and operation of the generation reserve sharing pool.





8


Each
      MAPP
      generation reserve participant is required to maintain for emergency purposes
      a
      net generating capability reserve of at least 15% above its system peak demand
      on a 12-month rolling basis. MidAmerican Energy’s reserve margin at peak demand
      for 2005 was approximately 26%. MidAmerican Energy believes it has adequate
      electric capacity reserve through 2009, including capacity provided by the
      generating projects discussed above. However, significantly higher-than-normal
      temperatures during the cooling season could cause MidAmerican Energy’s reserve
      to fall below the 15% minimum. If MidAmerican Energy fails to maintain the
      required minimum reserve, significant penalties could be contractually imposed
      by the MAPP.





MidAmerican
      Energy’s transmission system connects its generating facilities with
      distribution substations and interconnects with 14 other transmission providers
      in Iowa and five adjacent states. 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 at December 31, 2005, included 911 miles of 345-kV lines and 1,128
      miles of 161-kV lines. MidAmerican Energy’s electric distribution system
      included approximately 227,000 transformers and 400 substations at
      December 31, 2005.





*Natural
      Gas Operations*





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 area
      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 distributes it to customers through
      MidAmerican Energy's distribution system.





MidAmerican
      Energy sells natural gas and transportation services to end-use, or retail,
      customers and natural gas to other utilities, marketers and municipalities.
      MidAmerican Energy also transports through its distribution system natural
      gas
      purchased independently by a number of end-use customers. During 2005, 46%
      of
      total natural gas delivered through MidAmerican Energy's system for end-use
      customers was under natural gas transportation service.





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





The
      percentage of regulated natural gas revenue, excluding transportation
      throughput, by customer class follows:





Year
                Ended December 31,2005
            
            2004
            
            2003Residential
            
            
            37.5
            %
            
            40.0
            %
            
            44.1
            %Small
                general service(1)
            
            
            18.2
            
            
            19.6
            
            
            21.0Large
                general service(1)
            
            
            4.1
            
            
            2.2
            
            
            1.9Wholesale(2)
            
            
            40.2
            
            
            38.0
            
            
            32.7Other
            
            
            -
            
            
            0.2
            
            
            0.3100.0
            %
            
            100.0
            %
            
            100.0
            %





(1)
            Small
                and large general service customers are classified primarily based
                on the
                nature of their business and gas usage. Small general service customers
                are business customers whose gas usage is principally for heating.
                Large
                general service customers are business customers whose principal
                gas usage
                is for their manufacturing processes.(2)
            Wholesale
                generally includes other utilities, marketers and municipalities
                to whom
                natural gas is sold at wholesale for eventual resale to ultimate
                end-use
                customers.





9


The
      percentage of regulated natural gas revenue, excluding transportation
      throughput, by jurisdiction follows:





Year
                Ended December 31,2005
            
            2004
            
            2003Iowa
            
            
            77.4
            %
            
            77.7
            %
            
            77.9
            %South
                Dakota
            
            
            11.7
            
            
            11.5
            
            
            11.3Illinois
            
            
            10.0
            
            
            9.9
            
            
            10.0Nebraska
            
            
            0.9
            
            
            0.9
            
            
            0.8100.0
            %
            
            100.0
            %
            
            100.0
            %





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 attempts to optimize the value of its regulated assets by
      engaging in wholesale sales transactions. IUB and South Dakota Public Utilities
      Commission (“SDPUC”) rulings have allowed MidAmerican Energy to retain 50% of
      the respective jurisdictional margins earned on wholesale sales of natural
      gas,
      with the remaining 50% being returned to customers through the purchased gas
      adjustment clauses discussed below.





MidAmerican
      Energy has rights to firm pipeline capacity to transport natural gas to its
      service territory through direct interconnects to the pipeline systems of
      Northern Natural Gas (an affiliate company), Natural Gas Pipeline Company of
      America (“NGPL”), Northern Border Pipeline Company (“Northern Border”) and ANR
      Pipeline Company (“ANR”). At times, the capacity available through MidAmerican
      Energy’s firm capacity portfolio may exceed the demand on MidAmerican Energy’s
      distribution system. Firm capacity in excess of MidAmerican Energy’s system
      needs can be resold to other companies to achieve optimum use of the available
      capacity. Past IUB and SDPUC rulings have allowed MidAmerican Energy to retain
      30% of the respective jurisdictional margins earned on the resold capacity,
      with
      the remaining 70% being returned to customers through the purchased gas
      adjustment clauses.





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 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 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
      withdrawn during periods of peak demand and 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 (“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.





In
      1995,
      the IUB gave initial approval of MidAmerican Energy’s Incentive Gas Supply
      Procurement Program. In November 2004, the IUB extended the program through
      October 31, 2006. Under the program, as amended, MidAmerican Energy is
      required to file with the IUB every six months a comparison of its natural
      gas
      procurement costs to a reference price. If MidAmerican Energy’s cost of natural
      gas for the period is less or greater than an established tolerance band around
      the reference price, then MidAmerican Energy shares a portion of the savings
      or
      costs with customers. A similar program is currently in effect in South Dakota
      through October 31, 2010. Since the implementation of the program,
      MidAmerican Energy has successfully achieved and shared savings with its natural
      gas customers.





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. As of March 1, 2006,
      MidAmerican Energy’s 2005/2006 winter heating season peak-day delivery of
      1,004,109 Dth was reached on February 17, 2006. This peak-day delivery
      included 74% traditional sales service and 26% transportation
      service.


10


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 at December 31, 2005,
      included approximately 21,900 miles of gas mains and services
      pipelines.





**Interstate
      Pipeline Companies**





*Kern
      River*





Kern
      River, an indirect wholly-owned subsidiary of MEHC, owns an interstate natural
      gas transportation pipeline system comprising 1,679 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 a 717-mile
      expansion project (“2003 Expansion Project”), which increased the design
      capacity of Kern River’s pipeline system by 885,575 Dth per day to its current
      1,755,575 Dth per day. 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 Federal
      Energy Regulatory Commission (“FERC”) regulated tariff that is designed to allow
      it an opportunity to recover its costs together with 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 the
      original 682 miles of 36-inch diameter pipeline, 628 miles of 36-inch diameter
      loop pipeline related to the 2003 Expansion Project and 68 miles of various
      laterals that connect to the mainline.





The
      common facilities consist of a 219-mile section of original pipeline that
      extends from the point of interconnection with the mainline in Daggett to
      Bakersfield, California and an additional 82 miles related to the 2003 Expansion
      Project. The common facilities are jointly owned by Kern River (approximately
      76.8% as of December 31, 2005) and Mojave Pipeline Company (“Mojave”), a
      wholly-owned subsidiary of El Paso Corporation (“El Paso”), (approximately 23.2%
      as of December 31, 2005) 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.





As
      of
      December 31, 2005, Kern River had 1,661,575 Dth per day of capacity under
      long-term firm natural gas transportation service agreements pursuant to which
      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.





With
      respect to Kern River’s mainline facilities in existence prior to the 2003
      Expansion Project, at December 31, 2005, Kern River had 28 long-term firm
      natural gas transportation service agreements with 16 shippers, for a total
      of
      848,949 Dth per day of capacity. These long-term firm natural gas transportation
      service agreements expire between September 30, 2011 and April 30,
      2018. Several of these shippers are major oil and gas companies or affiliates
      of
      such companies. These shippers also include electric generating companies,
      energy marketing and trading companies, and a natural gas distribution utility
      which provides services in Nevada and California.





With
      respect to Kern River’s 2003 Expansion Project, at December 31, 2005, Kern River
      had 19 long-term firm natural gas transportation service agreements with 16
      shippers, for a total of 812,626 Dth per day of capacity from the pipeline’s
      point of origination near Opal, Wyoming to delivery points primarily in
      California. Approximately 83% of the 2003 Expansion Project’s capacity is
      contracted for 15 years, with 14 of the long-term firm natural gas
      transportation service agreements expiring on April 30, 2018. The remaining
      17% of capacity is contracted for 10 years, with five long-term firm natural
      gas
      transportation service agreements expiring on April 30, 2013. Over 95% of
      the 2003 Expansion Project’s capacity has primary delivery points in California,
      with the flexibility to access secondary delivery points in Nevada and Utah.
      Kern River has an additional 94,000 Dth per day of available firm capacity
      associated with the 2003 Expansion Project that was recently sold to a number
      of
      shippers at a discounted daily demand rate for the period of April 2006 through
      September 2008 on a short-term basis. Kern River will continue to market this
      capacity or use it for any future expansion needs for any period beyond
      September 2008.





11


Calpine
      Corp., including Calpine Energy Services, L.P. (“Calpine”), filed for Chapter 11
      bankruptcy protection on December 20, 2005. Calpine holds two 50,000 Dth
      per day incremental 2003 Expansion Project firm transportation contracts that
      have termination dates of April 30, 2018. Pursuant to Kern River's credit
      requirements, Calpine provided approximately $19 million as cash security for
      the transportation contracts, which is expected to be applied against Calpine's
      pre-petition invoices. Post-petition, to date, Calpine has continued to nominate
      on its transportation contracts and pay its post-petition invoices; however,
      Calpine has indicated that it has not yet determined whether it will assume
      or
      reject the transportation contracts.





*Northern
      Natural Gas*





Northern
      Natural Gas, an indirect wholly-owned subsidiary of MEHC, owns one of the
      largest interstate natural gas pipeline systems in the United States. It reaches
      from Texas to Michigan’s Upper Peninsula and is engaged in the transmission and
      storage of natural gas for utilities, municipalities, other pipeline companies,
      gas marketers, industrial and commercial users and other end users. Northern
      Natural Gas operates approximately 16,400 miles of natural gas pipelines,
      consisting of approximately 7,000 miles of mainline transmission pipelines
      and
      approximately 9,400 miles of lateral pipelines, with a design capacity of 4.6
      Bcf per day. Based on a review of relevant industry data, the Northern Natural
      Gas system is believed to be the largest single pipeline in the United States
      as
      measured by pipeline miles and the ninth largest as measured by throughput.
      Northern Natural Gas’ revenue is derived from the interstate transportation and
      storage of natural gas for third parties. Except for quantities of natural
      gas
      owned for system operations, Northern Natural Gas does not own the natural
      gas
      that is transported through its system. Northern Natural Gas’ transportation and
      storage operations are subject to a FERC regulated tariff that is designed
      to
      allow it an opportunity to recover its costs together with a regulated return
      on
      equity.





Northern
      Natural Gas’ system consists of two distinct but operationally integrated
      markets. Its traditional end-use and distribution market area is at the northern
      end of the system, including delivery points in Michigan, Illinois, Iowa,
      Minnesota, Nebraska, Wisconsin and South Dakota, which Northern Natural Gas
      refers to as the Market Area, and the natural gas supply and service area is
      at
      the southern end of the system, including Kansas, Oklahoma, Texas and New
      Mexico, which Northern Natural Gas refers to as the Field Area. Northern Natural
      Gas’ Field Area is interconnected with many interstate and intrastate pipelines
      in the national grid system. A majority of Northern Natural Gas’ capacity in
      both the Market Area and the Field Area is dedicated to Market Area customers
      under long-term firm transportation contracts. Approximately 54% of Northern
      Natural Gas’ current firm transportation capacity in the Market Area is
      contracted beyond 2008 and approximately 38% of such capacity is contracted
      beyond 2015.





Northern
      Natural Gas’ pipeline system transports natural gas primarily to end-user and
      local distribution markets in the Market Area. Customers consist of local
      distribution companies (“LDCs”), municipalities, other pipeline companies, gas
      marketers and end-users. While eight large LDCs account for the majority of
      Market Area volumes, Northern Natural Gas also serves numerous small communities
      through these large LDCs as well as municipalities or smaller LDCs and directly
      serves several large end-users. In 2005, over 85% of Northern Natural Gas’
transportation and storage revenue was from capacity charges under firm
      transportation and storage contracts and approximately 80% of that revenue
      was
      from LDCs. In 2005, approximately 71% of Northern Natural Gas’ transportation
      and storage revenue was generated from Market Area customer
      contracts.





The
      Field
      Area of Northern Natural Gas’ system provides access to natural gas supply from
      key production areas including the Hugoton, Permian and Anadarko Basins. In
      each
      of these areas, Northern Natural Gas has numerous interconnecting receipt and
      delivery points, with volumes received in the Field Area consisting of both
      directly connected supply and volumes from interconnections with other pipeline
      systems. In addition, Northern Natural Gas has the ability to aggregate
      processable natural gas for deliveries to various gas processing
      facilities.





In
      the
      Field Area, customers holding transportation capacity consist of LDCs,
      marketers, producers, and end-users. The majority of Northern Natural Gas’ Field
      Area firm transportation is provided to Northern Natural Gas’ Market Area firm
      customers under long-term firm transportation contracts with such volumes
      supplemented by volumes transported on an interruptible basis or pursuant to
      short-term firm contracts. In 2005, approximately 19% of Northern Natural Gas’
transportation and storage revenue was generated from Field Area customer
      transportation contracts.


12


Northern
      Natural Gas’ storage services are provided through the operation of one
      underground storage field in Iowa, two underground storage facilities in Kansas
      and one LNG storage peaking unit each in Iowa and Minnesota. The three
      underground natural gas storage facilities and Northern Natural Gas’ two LNG
      storage peaking units have a total firm service storage capacity of
      approximately 59 Bcf and over 1.3 Bcf per day of peak day deliverability. These
      storage facilities provide Northern Natural Gas with operational flexibility
      for
      the daily balancing of its system and providing services to customers for
      meeting their year-round load requirements. In 2005, approximately 10% of
      Northern Natural Gas’ transportation and storage revenue was generated from
      storage services.





Northern
      Natural Gas’ system experiences significant seasonal swings in demand, with the
      highest demand occurring during the months of November through March. This
      seasonality provides Northern Natural Gas opportunities to deliver high
      value-added services, such as firm and interruptible storage services, as well
      as no notice services, particularly during the lower demand months. Because
      of
      its location and multiple interconnections with other 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,
      as well as growing supply areas such as the Rocky Mountains, through Trailblazer
      Pipeline Company, Kinder Morgan Interstate Gas Transmission, Cheyenne Plains
      Gas
      Pipeline Company and Colorado Interstate Gas Pipeline Company (“Colorado
      Interstate”), and from Canadian production areas through Northern Border, Great
      Lakes Gas Transmission Limited Partnership (“Great Lakes”) and Viking Gas
      Transmission Company (“Viking”). 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 LDC
      revenue by taking advantage of opportunities to provide intermediate
      transportation through pipeline interconnections for customers in other markets,
      including Chicago, Illinois and other parts of the Midwest and
      Texas.





*Kern
      River and Northern Natural Gas Competition*





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, location and overall customer service. Industrial end-users often
      have
      the ability to choose from alternative fuel sources in addition to natural
      gas,
      such as fuel oil and coal. 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 Kern River and Northern
      Natural Gas influence the price of natural gas.





Kern
      River competes with various interstate pipelines and its shippers in order
      to
      market any unutilized or unsubscribed capacity in 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,
      Overthrust Pipeline and Questar Pipeline. These interconnections, in addition
      to
      the direct interconnections to natural gas supply and 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 into the intrastate 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 is advantaged relative to other competing interstate pipelines
      because its relatively new pipeline can be economically expanded and will
      require significantly less capital expenditure to comply with the Pipeline
      Safety Improvement Act of 2002 (“PSIA”) than other systems. Kern River’s
      levelized rate structures has been challenged in its 2004 general rate case.
      Certain parties have advocated converting the system to a traditional, declining
      rate base rate structure. Kern River’s favorable market position is tied to the
      availability and favorable price of gas reserves in the Rocky Mountain area,
      an
      area that in recent years has attracted considerable interest for increased
      pipeline capacity serving markets other than California and Nevada. In addition,
      Kern River’s 2003 Expansion Project relies substantially on long-term
      transportation service agreements with several electric generation companies,
      who face significant competitive and financial pressures due to, among other
      things, the financial stress of energy markets and apparent over-building of
      electric generation capacity in California and other markets. This condition
      is
      expected to ease over time as demand for electric generation in Kern River’s
      market territory increases and older, less efficient power plants in the region
      are retired.





13


Northern
      Natural Gas has been able to provide cost competitive service because of its
      access to a variety of relatively low cost gas supply basins, its cost-control
      measures and its competitive load factor, which lowers the cost per unit of
      transportation. Although Northern Natural Gas has periodically experienced
      bypasses of the pipeline system affecting a small percentage of its market,
      to
      date Northern Natural Gas has been able to more than offset any load lost to
      bypass in the Northern Natural Gas Market Area through expansion
      projects.





Major
      competitors in the Northern Natural Gas Market Area include; ANR, Northern
      Border and NGPL. Other competitors include Great Lakes and Viking. In the Field
      Area, Northern Natural Gas competes with a large number of other competitors.
      Particularly in the Field Area, a significant amount of Northern Natural Gas’
capacity is used on an interruptible or short-term firm basis. In summer months,
      Northern Natural Gas’ Market Area customers often release significant amounts of
      their unused firm capacity to other shippers, which released capacity competes
      with Northern Natural Gas’ short-term firm or interruptible
      services.





Although
      Northern Natural Gas will need to aggressively compete to retain and build
      load,
      Northern Natural Gas believes that current and anticipated changes in its
      competitive environment have created opportunities to serve existing customers
      more efficiently and to meet certain growing supply needs. While LDCs’ peak day
      growth is driven by population growth and alternative fuel replacement, new
      off-peak demand growth is being driven primarily by power and ethanol plant
      expansions. Off-peak demand growth is important to Northern Natural Gas as
      this
      demand can generally be satisfied with little or no requirement for the
      construction of new facilities. Northern Natural Gas has been successful in
      competing for a significant amount of the increased demand related to electric
      generation and ethanol plants. Over the last five years, Northern Natural Gas
      has contracted approximately 319 MMcf per day of firm volume on its system
      from
      such new facilities, of which approximately 255 MMcf per day is currently in
      service and approximately 64 MMcf per day is scheduled to begin service in
      2006.
      The recent passage of the Energy Policy Act has continued to encourage ethanol
      development and has had a positive effect of increasing demand on Northern
      Natural Gas’ system.





Kern
      River has one customer who accounts for greater than 10% of its revenue.
      Northern Natural Gas has two customers who each account for greater than 10%
      of
      its revenue. Northern Natural Gas has agreements to retain the vast majority
      of
      both of these customers’ volumes through at least 2017. The loss of any one or
      more of these customers, if not replaced, could have a material adverse effect
      on Kern River’s and Northern Natural Gas’ respective businesses.





*Development
      Project*





MEHC
      and
      a subsidiary, Alaska Gas Transmission Company, LLC (“Alaska Gas”), were two of
      several other parties, including existing producers of oil from Alaska’s North
      Slope, involved in a competitive selection process to develop and construct
      a
      proposed 745-mile natural gas pipeline that would extend from the North Slope
      area near Prudhoe Bay, Alaska south to the Alaska-Yukon border near Beaver
      Creek, Alaska. Due to unfavorable developments, MEHC and Alaska Gas ceased
      discussions with the state of Alaska in 2005.





**CE
      Electric UK**





CE
      Electric UK, an indirect wholly-owned subsidiary of MEHC, owns, primarily,
      two
      companies that distribute electricity in Great Britain, Northern Electric and
      Yorkshire Electricity. Northern Electric and Yorkshire Electricity, together,
      constitute the third largest distributor of electricity in Great Britain,
      serving more than 3.7 million customers in an area of approximately 10,000
      square miles.





*Electricity
      Distribution*





Northern
      Electric and Yorkshire Electricity receive electricity from the national grid
      transmission system and distribute it to their customers’ premises using their
      network of transformers, switchgear and cables. Substantially all of the end
      users in Northern Electric’s and Yorkshire Electricity’s distribution services
      areas are connected to the Northern Electric and Yorkshire Electricity networks
      and electricity can only be delivered to such end users through their
      distribution system, thus providing Northern Electric and Yorkshire Electricity
      with distribution volume that is relatively stable from year to year. Northern
      Electric and Yorkshire Electricity charge fees for the use of the distribution
      system 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 Use of System Agreement”, which Northern
      Electric and Yorkshire Electricity separately entered into with the various
      suppliers of electricity in their respective distribution services areas. One
      such supplier, RWE Npower PLC (“Npower”) and certain of its affiliates,
      represented approximately 44% of the total distribution revenues of Northern
      Electric and Yorkshire Electricity in 2005.





14


At
      December 31, 2005, Northern Electric’s and Yorkshire Electricity’s
      electricity distribution network (excluding service connections to consumers)
      on
      a combined basis included approximately 33,000 kilometers of overhead lines
      and
      approximately 65,000 kilometers of underground cables. In addition to the
      circuits referred to above, at December 31, 2005, Northern Electric’s and
      Yorkshire Electricity’s distribution facilities also included approximately
      60,000 transformers and approximately 700 primary substations. Substantially
      all
      substations are owned, with the balance being leased from third parties and
      mostly having remaining terms of at least 10 years.





*Utility
      Services*





Integrated
      Utility Services Limited, CE Electric UK's indirect wholly-owned subsidiary,
      is
      an engineering contracting company whose main business is providing electrical
      connection services for Northern Electric and Yorkshire Electricity and
      providing electrical infrastructure contracting services to third
      parties.





*Gas
      Exploration and Production*





CalEnergy
      Gas (Holdings) Limited (“CE Gas”), CE Electric UK’s indirect wholly-owned
      subsidiary, is a gas exploration and production company that is focused on
      developing integrated upstream gas projects in Australia, the United Kingdom
      and
      Poland. Its upstream gas business consists of exploration, development and
      production projects, resulting in the sale of gas to third parties.





In
      Australia, CE Gas has construction and development projects in the Bass, Otway
      and Perth Basins. The Yolla construction project in the Bass Basin is a gas
      and
      gas liquids project in which CE Gas holds a 15% interest. The project, operated
      by Origin Energy Limited of Australia, is nearing completion and includes an
      approximately 145 kilometer sub-sea pipeline across the Bass Strait off southern
      Victoria. The Bass Project is expected to be fully operational in 2006. The
      gas
      from the project will be sold to Origin Energy Limited’s retail affiliate, the
      liquefied petroleum gas will be sold to Elgas Limited, the largest marketer
      of
      liquefied petroleum gas in Australia, and the condensate will be sold to The
      Shell Company of Australia Limited. The Otway project, in which CE Gas holds
      a
      5% interest, is operated by Woodside Exploration Limited of Australia. This
      project received construction approval during 2004. Construction has now
      commenced with first production expected around mid-2006.





In
      the
      United Kingdom, CE Gas continues to retain its 5% interest in the Victor Field,
      which is a gas field, located in the Southern North Sea. CE Gas is also
      developing certain new exploration in the North Sea.





**CalEnergy
      Generation-Foreign**





The
      CalEnergy Generation-Foreign platform consists of MEHC’s indirect ownership of
      the Leyte Projects, which are geothermal power plants located on the island
      of
      Leyte in the Philippines, and a combined irrigation and hydroelectric power
      generation project located in the central part of the island of Luzon in the
      Philippines (the “Casecnan Project”). Each plant possesses an operating margin
      that allows for production in excess of the amount listed below. Utilization
      of
      this operating margin is based upon a variety of factors and can be expected
      to
      vary between calendar quarters under normal operating conditions.





15


The
      following table sets out certain information concerning CalEnergy
      Generation-Foreign’s non-utility power projects in operation as of
      December 31, 2005:





**Facility**Net
            
            
            
            
            
            
            
            **Power****Capacity**
            
            **Net
                MW**
            
            **Energy**
            
            **Contract**
            
            **Purchaser/****Project****(1)**
            
            **(MW)****(2)**
            
            **Owned****(2)**
            
            **Source**
            
            **Expiration**
            
            **Guarantor****(3)**Upper
                Mahiao
            
            119
            
            119
            
            Geo
            
            June
                2006
            
            PNOC-EDC/ROPMahanagdong
            
            154
            
            150
            
            Geo
            
            July
                2007
            
            PNOC-EDC/ROPMalitbog
            
            216
            
            216
            
            Geo
            
            July
                2007
            
            PNOC-EDC/ROPCasecnan(4)
            
            150
            
            150
            
            Water
            
            December
                2021
            
            NIA/ROPTotal
            
            639
            
            635





(1)
            All
                projects are located in the Philippines and carry political risk
                insurance.(2)
            Actual
                MW may vary depending on operating, geothermal reservoir and water
                flow
                conditions, as well as plant design. Facility Net Capacity (MW) represents
                the contract capacity for the facility. Net MW Owned indicates current
                legal ownership, but, in some cases, does not reflect the current
                allocation of distributions.(3)
            Philippine
                National Oil Company-Energy Development Corporation (“PNOC-EDC”), Republic
                of the Philippines (“ROP”), and National Irrigation Administration
                (“NIA”). NIA also pays CE Casecnan Water and Energy Company, Inc. (“CE
                Casecnan”), an indirect subsidiary of MEHC, for the delivery of water and
                electricity by CE Casecnan. Separate sovereign performance
                undertakings of the ROP support PNOC-EDC’s obligations for the Leyte
                Projects. The ROP has also provided a performance undertaking under
                which
                NIA’s obligations under the Casecnan Project agreement, as supplemented
                by
                the Supplemental Agreement, are guaranteed by the full faith and
                credit of
                the ROP.(4)
            Net
                MW Owned of approximately 150 MW is subject to repurchase rights
                of up to
                15% of the project by an initial minority shareholder and a dispute
                with
                the other initial minority shareholder regarding an additional 15%
                of the
                project. Refer to Item 3. Legal Proceedings of this Form 10-K for
                additional information.





PNOC-EDC’s
      and NIA’s obligations under the project agreements are substantially denominated
      in U.S. dollars and are the Leyte Projects’ and 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 obligations under the project
      agreements 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.





The
      Upper
      Mahiao project is a 119 net MW geothermal power project owned and operated
      by CE
      Cebu Geothermal Power Company, Inc. (“CE Cebu”), a Philippine corporation that
      is 100% indirectly owned by MEHC. On June 25, 2006, the end of the 10-year
      cooperation period, the Upper Mahiao facility will be transferred to PNOC-EDC
      at
      no cost on an “as-is” basis.





The
      Upper
      Mahiao project takes geothermal steam and fluid, provided by PNOC-EDC at no
      cost, and converts its thermal energy into electrical energy which is sold
      to
      PNOC-EDC, which in turn sells the power to the National Power Corporation
      (“NPC”), the government-owned and controlled corporation that is the primary
      supplier of electricity in the Philippines, for distribution on the island
      of
      Cebu. PNOC-EDC pays CE Cebu a fee based on the plant capacity. Pursuant to
      an
      amendment to the Upper Mahiao energy conversion agreement dated August 31,
      2003, CE Cebu and PNOC-EDC agreed that the plant capacity for purposes of the
      fee would equal the contractually specified level of 118.5 MW. PNOC-EDC also
      pays CE Cebu a fee based on the electricity actually delivered to PNOC-EDC
      (approximately 2% of total contract revenue). Payments under the Upper Mahiao
      agreement are denominated in U.S. dollars, or computed in U.S. dollars and
      paid
      in pesos at the then-current exchange rate, except for the energy
      fee.





16


The
      Mahanagdong project is a 154 net MW geothermal power project owned and operated
      by CE Luzon Geothermal Power Company, Inc. (“CE Luzon”), a Philippine
      corporation of which MEHC indirectly owns 100% of the common stock. Another
      industrial company owns an approximate 3% preferred equity interest in the
      Mahanagdong project. The Mahanagdong project sells 100% of its capacity to
      PNOC-EDC, which in turn sells the power to the NPC for distribution on the
      island of Luzon.





The
      terms
      of the Mahanagdong energy conversion agreement are substantially similar to
      those of the Upper Mahiao agreement. On July 25, 2007, the end of the
      10-year cooperation period, the Mahanagdong facility will be transferred to
      PNOC-EDC at no cost on an “as-is” basis. PNOC-EDC pays CE Luzon a fee based on
      the plant capacity. Pursuant to an amendment to the Mahanagdong energy
      conversion agreement dated August 31, 2003, CE Luzon and PNOC-EDC agreed
      that the plant capacity would equal the contractually specified level, which
      declines from approximately 154 MW in 2005 to approximately 153 MW in the last
      year of the cooperation period. The capacity fees are approximately 99% of
      total
      revenue at the contractually agreed capacity levels and the energy fees are
      approximately 1% of such total revenue.





The
      Malitbog project is a 216 net MW geothermal project owned and operated by
      Visayas Geothermal Power Company (“VGPC”), a Philippine general partnership that
      is indirectly wholly owned by MEHC. VGPC sells 100% of its capacity on
      substantially the same basis as described above for the Upper Mahiao project
      to
      PNOC-EDC, which sells the power to the NPC for distribution on the islands
      of
      Cebu and Luzon.





The
      Malitbog energy conversion agreement 10-year cooperation period expires on
      July 25, 2007, at which time the facility will be transferred to PNOC-EDC
      at no cost on an “as-is” basis. Capacity payments under the agreement equal 100%
      of total revenue. Pursuant to an amendment to the Malitbog energy conversion
      agreement dated August 31, 2003, VGPC and PNOC-EDC agreed that the plant
      capacity would equal the contractually specified level of 216 MW. A substantial
      majority of the capacity payments are required to be made by PNOC-EDC in U.S.
      dollars. The portion of capacity payments payable to PNOC-EDC in pesos is
      expected to vary over the term of the Malitbog project energy conversion
      agreement from 10% of VGPC’s revenue in the early years of the cooperation
      period to 23% of VGPC’s revenue at the end of the cooperation period. Payments
      made in pesos are generally made to a peso-denominated account and are used
      to
      pay peso-denominated expenses with respect to the Malitbog project.





The
      Casecnan Project is a combined irrigation and hydroelectric power generation
      project. The Casecnan Project consists generally of diversion structures in
      the
      Casecnan and Taan rivers that capture and divert excess water in the Casecnan
      watershed by means of concrete, in-stream diversion weirs and transfer that
      water through a transbasin tunnel of approximately 23 kilometers. During the
      water transfer, the elevation differences between the two watersheds allows
      electrical energy to be generated at an approximately 150 MW rated capacity
      power plant, which is located in an underground powerhouse cavern at the end
      of
      the transbasin water tunnel. A tailrace discharge tunnel then delivers water
      to
      the existing underutilized water storage reservoir at Pantabangan, providing
      additional water for irrigation and increasing the potential electrical
      generation at two existing downstream hydroelectric facilities of NPC. Once
      in
      the reservoir at Pantabangan, the water is under the control of
      NIA.





CE
      Casecnan owns and operates the Casecnan Project under the terms of the Project
      Agreement between CE Casecnan and NIA, which was modified by a Supplemental
      Agreement between CE Casecnan and NIA effective on October 15, 2003 (the
“Supplemental 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 dependant 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 may have a material
      impact on 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 (described below) can produce significant
      variability in revenue between reporting periods.





Under
      the
      Supplemental Agreement, CE Casecnan is paid a fee for the delivery of water
      and
      a fee for the generation of electricity. With respect to water deliveries,
      the
      water delivery fee is payable in a fixed monthly payment based upon an average
      annual water delivery of 801.9 million cubic meters, pro-rated to
      approximately 66.8 million cubic meters per month, multiplied by the
      applicable per cubic meter rate through December 25, 2008. For each
      contract year starting from December 25, 2003, and ending on
      December 25, 2008, a water delivery credit (deferred revenue) is computed
      equal to 801.9 million cubic meters minus the greater of actual water
      deliveries or 700.0 million cubic meters - the minimum threshold. The water
      delivery credit at the end of the contract year is available to be earned in
      the
      succeeding contract years ending December 25, 2008. The cumulative water
      delivery credit at December 25, 2008, if any, shall be amortized from
      December 25, 2008 through December 25, 2013. Accordingly, in
      recognizing revenue, the water delivery fees are recorded each month pro-rated
      to approximately 58.3 million cubic meters per month until the minimum
      threshold has been reached for the contract year. Subsequent water delivery
      fees
      within the contract year are based on actual water delivered.





17


With
      respect to electricity, CE Casecnan is paid a guaranteed energy delivery fee
      each month equal to the product obtained by multiplying 19 GWh times $0.1596
      per
      kWh. The guaranteed energy delivery fee is payable regardless of the amount
      of
      energy actually generated and delivered by CE Casecnan in any month. NIA also
      pays CE Casecnan an excess energy delivery fee, which is a variable amount
      based
      on actual electrical energy, if any, delivered in each month in excess of
      19 GWh multiplied by (i) $0.1509 per kWh through the end of 2008 and (ii)
      commencing in 2009, $0.1132 (escalating at 1% per annum thereafter) per kWh,
      provided that any deliveries of energy in excess of 490 GWh but less than 550
      GWh per year are paid for at a rate of 1.3 pesos per kWh and deliveries in
      excess of 550 GWh per year are at no cost to NIA. Within each contract year,
      no
      variable energy fees are payable until energy in excess of the cumulative 19
      GWh
      per month for the contract year to date has been delivered. If the Casecnan
      Project is not dispatched up to 150 MW whenever water is available, NIA will
      pay
      for energy that could have been generated but was not as a result of such
      dispatch constraint.





In
      connection with the signing of the Supplemental Agreement, CE Casecnan received
      written confirmation from the Private Sector Assets and Liabilities Management
      Corporation that the issues with respect to the Casecnan Project that had been
      raised by the interagency review of independent power producers in the
      Philippines or that may have existed with respect to the project under certain
      provisions of the Electric Power Industry Reform Act of 2001 (“EPIRA”), which
      authorized the ROP to seek to renegotiate certain contracts such as the Project
      Agreement, have been satisfactorily addressed by the Supplemental
      Agreement.





**CalEnergy
      Generation-Domestic**





The
      subsidiaries comprising the Company's CalEnergy Generation-Domestic platform
      own
      interests in 15 operating non-utility power projects in the United States.
      The
      following table sets out certain information concerning CalEnergy
      Generation-Domestic’s non-utility power projects in operation as of
      December 31, 2005:





**Facility**
            
            
            
            
            
            
            
            **Power****Net**
            
            **Net**
            
            
            
            
            
            **Purchase****Capacity**
            
            **MW**
            
            **Energy**
            
            
            
            **Agreement**
            
            **Power****Operating
                Project**
            
            **(MW)****(1)**
            
            **Owned****(1)**
            
            **Source**
            
            **Location**
            
            **Expiration**
            
            **Purchaser****(2)**Cordova
            
            537
            
            537
            
            Gas
            
            Illinois
            
            2019
            
            ConstellationRoosevelt
                Hot Springs
            
            23
            
            17
            
            Geo
            
            Utah
            
            2020
            
            PacifiCorpCE
                Generation:(3)Geothermal
                -Salton
                Sea I
            
            10
            
            5
            
            Geo
            
            California
            
            2017
            
            EdisonSalton
                Sea II
            
            20
            
            10
            
            Geo
            
            California
            
            2020
            
            EdisonSalton
                Sea III
            
            50
            
            25
            
            Geo
            
            California
            
            2019
            
            EdisonSalton
                Sea IV
            
            40
            
            20
            
            Geo
            
            California
            
            2026
            
            EdisonSalton
                Sea V
            
            49
            
            25
            
            Geo
            
            California
            
            Varies
            
            VariousVulcan
            
            34
            
            17
            
            Geo
            
            California
            
            2016
            
            EdisonElmore
            
            38
            
            19
            
            Geo
            
            California
            
            2018
            
            EdisonLeathers
            
            38
            
            19
            
            Geo
            
            California
            
            2019
            
            EdisonDel
                Ranch
            
            38
            
            19
            
            Geo
            
            California
            
            2019
            
            EdisonCE
                Turbo
            
            10
            
            5
            
            Geo
            
            California
            
            2029
            
            APS327
            
            164Natural-Gas
                Fired -Saranac
            
            240
            
            90
            
            Gas
            
            New
                York
            
            2009
            
            NYSE&GPower
                Resources
            
            212
            
            106
            
            Gas
            
            Texas
            
            N/A
            
            Market
                salesYuma
            
            50
            
            25
            
            Gas
            
            Arizona
            
            2024
            
            SDG&E502
            
            221829
            
            385Total(4)
            
            1,389
            
            939





18




(1)
            Represents
                nominal net generating capability (accredited for Cordova and contract
                capacity for most others). Actual MW may vary depending on operating
                and
                reservoir conditions and plant design. Net MW Owned indicates current
                legal ownership, but, in some cases, does not reflect the current
                allocation of partnership distributions.(2)
            Constellation
                Energy Commodities Group (“Constellation”); Southern California Edison
                Company (“Edison”); Arizona Public Service (“APS”) New York State Electric
                & Gas Corporation (“NYSE&G”); and San Diego Gas & Electric
                Company (“SDG&E”).(3)
            MEHC
                has a 50% ownership interest in CE Generation, LLC (“CE Generation”) whose
                affiliates currently operate ten geothermal plants in the Imperial
                Valley
                of California (the “Imperial Valley Projects”) and three natural gas-fired
                power generation facilities.(4)
            The
                totals do not include MEHC’s 50% ownership of the Wailuku hydroelectric
                project (facility net capacity of 10 MW), which was obtained on
                February 17, 2006.





Cordova
      Energy owns a 537 MW gas-fired power plant in the Quad Cities, Illinois area
      (the “Cordova Project”). CalEnergy Generation Operating Company, an indirect
      wholly owned subsidiary of MEHC, operates the Cordova Project which commenced
      commercial operations in June 2001. On July 6, 1999, Cordova Energy entered
      into a power purchase agreement with a unit of El Paso, under which El Paso
      was obligated to purchase all of the capacity and energy generated from the
      project until December 31, 2019. Effective January 1, 2006, El Paso
      assigned all of its rights and obligations under the power purchase agreement
      to
      Constellation. In connection with the assignment, Constellation Energy Group,
      Inc., the ultimate parent of Constellation, issued a limited guarantee of
      Constellation’s obligations under the power purchase agreement. The contract
      year under the power purchase agreement extends from May 15th in a year to
      May 14th in the subsequent year. For each contract year, Cordova Energy has
      an option to recall 50% of the output of the Cordova Project.





Each
      of
      the Imperial Valley Projects, excluding the Salton Sea V and CE Turbo projects,
      sells electricity to Edison pursuant to a separate Standard Offer No. 4
      Agreement (“SO4 Agreement”) or a negotiated power purchase agreement. Each power
      purchase agreement is independent of the others, and the performance
      requirements specified within one such agreement apply only to the project
      subject to the agreement. The power purchase agreements provide for capacity
      payments, capacity bonus payments and energy payments. Edison makes fixed annual
      capacity payments and capacity bonus payments to the applicable projects to
      the
      extent that capacity factors exceed certain benchmarks. The price for capacity
      is fixed for the life of the SO4 Agreements and is significantly higher in
      the
      months of June through September.





Energy
      payments under the original SO4 Agreements were based on the cost that Edison
      avoids by purchasing energy from the project instead of obtaining the energy
      from other sources (“Avoided Cost of Energy”). In June and November 2001, the
      Imperial Valley Projects (except the Salton Sea IV project, which remained
      on
      Edison’s Avoided Cost of Energy) which receive Edison’s Avoided Cost of Energy
      entered into agreements that provide for amended energy payments under the
      SO4
      Agreements. The amendments provide for fixed energy payments per kWh in lieu
      of
      Edison’s Avoided Cost of Energy. The fixed energy payment was 3.25 cents per kWh
      from December 1, 2001 through April 30, 2002 and is 5.37 cents per kWh
      from May 1, 2002 through April 30, 2007. Beginning May 1, 2007,
      the energy payments revert back to Edison’s Avoided Cost of Energy. For the
      years ended December 31, 2005, 2004 and 2003, Edison’s average Avoided Cost
      of Energy was 7.7 cents per kWh, 5.9 cents per kWh and 5.4 cents per kWh,
      respectively. Estimates of Edison’s future Avoided Cost of Energy vary
      substantially from year to year primarily based on the future cost of natural
      gas and may be impacted by regulatory proceedings and other commodity
      factors.





The
      Saranac project is a 240 net MW natural gas-fired cogeneration facility located
      in Plattsburgh, New York owned by the Saranac Partnership, which is indirectly
      owned by subsidiaries of CE Generation, Osaka Gas Energy America Corporation
      and
      General Electric Capital Corporation. Osaka Gas Energy America Corporation
      acquired ArcLight Capital Holdings’ interest in the project on December 15,
      2005. The Saranac project has entered into a 15-year power purchase agreement
      with NYSE&G, 15-year steam purchase agreements with Georgia-Pacific
      Corporation and Pactiv Corporation and a 15-year natural gas supply contract
      with Coral Energy to supply 100% of the Saranac project’s fuel requirements.
      Each of the power purchase agreement, the steam purchase agreements and the
      natural gas supply contract contains rates that are fixed for the respective
      contract terms and expire in June 2009.





19


The
      Power
      Resources project is a 212 net MW natural gas-fired cogeneration project owned
      by Power Resources Ltd. (“Power Resources”), an indirect wholly-owned subsidiary
      of CE Generation. On August 5, 2003, Power Resources entered into a Tolling
      Agreement with ONEOK Energy, Marketing and Trading Company, L.P. The agreement
      commenced October 1, 2003 and expired on December 31, 2005.





Power
      Resources currently operates as a merchant power plant and is subject to
      electricity and gas markets to economically dispatch its output. Power Resources
      entered into a one-year Energy Management Service Agreement with Mpower Trade
      and Marketing (“Mpower”) effective January 1, 2006. Mpower is engaged to
      provide energy services required to manage the electrical
      generation, steam, and ancillary services capacity and related natural gas
      requirements of the plant. Mpower is due 10% of all net margins generated
      and Mpower’s credit is used in all transactions with no credit assurance
      required from Power Resources.





The
      Yuma
      project is a 50 net MW natural gas-fired cogeneration project in Yuma, Arizona
      owned by Yuma Cogeneration Associates (“YCA”), providing its electricity to
      SDG&E under an existing 30-year power purchase contract which commenced in
      May 1994 (the “Yuma Contract”). MEHC has guaranteed all of the obligations of
      YCA under the Yuma Contract or any other agreement with SDG&E relating to or
      arising out of the Yuma Contract. YCA also has executed steam sales contracts
      with Queen Carpet, Inc. to act as its thermal host.





*Development
      Project*





MEHC’s
      indirect wholly-owned subsidiary, CE Obsidian Energy LLC (“Obsidian”), has
      evaluated the development of a 185 net MW geothermal facility in the Imperial
      Valley of California. Substantially all of the output of the facility would
      be
      sold to the Imperial Irrigation District pursuant to a power purchase agreement.
      Due to current unfavorable project economics, MEHC and Obsidian are not actively
      developing this project.





**HomeServices**





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 and mortgage banking, primarily through joint
      ventures, title and closing services and other 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 in 18 states under the following
      brand
      names: Carol Jones REALTORS, CBSHOME Real Estate, Champion Realty, Edina Realty
      Home Services, Esslinger-Wooten-Maxwell REALTORS, First Realty/GMAC, HOME Real
      Estate, Iowa Realty, Jenny Pruitt and Associates REALTORS, Long Realty,
      Prudential California Realty, Prudential Carolinas 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, Iowa; Omaha and Lincoln, Nebraska; Birmingham, Auburn
      and
      Mobile, Alabama; Tucson, Arizona; Winston-Salem and Charlotte, North Carolina;
      Louisville and Lexington, Kentucky; Annapolis, Maryland; Atlanta, Georgia;
      and
      Miami, Florida.





In
      2005,
      HomeServices separately acquired three real estate companies for an aggregate
      purchase price of $5.1 million, net of cash acquired, plus working capital
      and certain other adjustments. For the year ended December 31, 2004, these
      real estate companies had combined revenue of $21.8 million on
      approximately 3,400 closed sides representing $0.8 billion of sales volume.
      In 2004, HomeServices separately acquired six real estate companies for an
      aggregate purchase price of $30.7 million, net of cash acquired, plus
      working capital and certain other adjustments. For the year ended
      December 31, 2003, these real estate companies had combined revenue of
      $95.7 million on approximately 15,000 closed sides representing
      $3.2 billion of sales volume. In 2003, HomeServices separately acquired
      four real estate companies for an aggregate purchase price of
      $36.7 million, net of cash acquired, plus working capital and certain other
      adjustments. For the year ended December 31, 2002, these real estate
      companies had combined revenue of $102.9 million on approximately 16,000
      closed sides representing $3.6 billion of sales volume.





20


**Regulatory
      Matters**





General
      Regulation





The
      Company’s businesses are subject to a number of federal, state, local and
      international regulations. In addition to the discussion contained herein,
      refer
      to Note 19 of Notes to Consolidated Financial Statements included in Item 8.
      Financial Statements and Supplementary Data of this Form 10-K for additional
      regulatory matter information regarding the Company’s businesses.





*MidAmerican
      Energy*





MidAmerican
      Energy is subject to comprehensive regulation by the FERC as well as utility
      regulatory agencies in Iowa, Illinois and South Dakota that significantly
      influences the operating environment and the recoverability of costs from
      utility customers. Except for Illinois, that regulatory environment has to
      date,
      in general, given MidAmerican Energy an exclusive right to serve electricity
      customers within its service territory and, in turn, the obligation to provide
      electric service to those customers. In Illinois, all customers are free to
      choose their electricity provider 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
      from MidAmerican Energy’s existing regulated Illinois rates.





In
      conjunction with the March 1999 approval by the IUB of the MidAmerican Energy
      acquisition and March 2000 affirmation as part of the Company’s acquisition by a
      private investor group, MidAmerican Energy committed to the IUB to use
      commercially reasonable efforts to maintain an investment grade rating on its
      long-term debt and to maintain its common equity level above 42% of total
      capitalization unless circumstances beyond its control result in the common
      equity level decreasing to below 39% of total capitalization. MidAmerican Energy
      must seek the approval of the IUB of a reasonable utility capital structure
      if
      MidAmerican Energy’s common equity level decreases below 42% of total
      capitalization, unless the decrease is beyond the control of MidAmerican Energy.
      MidAmerican Energy is also required to seek the approval of the IUB if
      MidAmerican Energy’s equity level decreases to below 39%, even if the decrease
      is due to circumstances beyond the control of MidAmerican Energy. If MidAmerican
      Energy’s common equity level were to drop below the required thresholds,
      MidAmerican Energy’s ability to issue debt and declare dividends could be
      restricted.





Under
      a
      series of settlement agreements between MidAmerican Energy, the Iowa Office
      of
      Consumer Advocate (“OCA”) and other interveners approved by the IUB, MidAmerican
      Energy has agreed not to seek a general increase in electric rates to become
      effective prior to January 1, 2012 unless its Iowa jurisdictional electric
      return on equity for any year falls below 10%. These settlement agreements
      further provide that earnings exceeding a return on equity of 12% through
      December 31, 2005 and 11.75% for January 1, 2006 through December 31, 2011,
      will be recorded as a regulatory liability and shared with ratepayers. 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 seek any decrease
      in MidAmerican Energy’s Iowa electric rates prior to January 1, 2012. 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 portions of revenues associated with Iowa retail electric returns
      on equity within specified ranges will be recorded as a regulatory
      liability.





Under
      Iowa law, there are two options for temporary collection of higher rates
      following the filing of a request for a rate increase. Collection can begin,
      subject to refund, either within 10 days of filing, without IUB review, or
      90
      days after filing, with approval by the IUB. If the 10-day option is selected,
      Iowa law provides that if the utility is required to make refunds, the refunds
      may be based on overpayments made by each customer class, group or rate zone
      of
      the difference between final rates and the rates that would have been collected
      if temporary rates had been based upon prior regulatory principles. If the
      90-day option is selected, Iowa law provides that the IUB shall prescribe the
      manner of refunding the difference between final rates and the rates based
      on
      prior ratemaking principles and a rate of return on common equity previously
      approved by the IUB. In either case, if the IUB has not issued a final order
      within ten months after the filing date, the temporary rates become final and
      any difference between the requested rate increase and the temporary rates
      may
      then be collected subject to refund until receipt of a final order. Exceptions
      to the ten-month limitation provide for extensions due to a utility's lack
      of
      due diligence in the rate proceeding, judicial appeals and situations involving
      new generating units being placed in service. MidAmerican Energy's cost of
      gas
      is collected in its Iowa gas rates through the Iowa Uniform Purchased Gas
      Adjustment Clause, which is updated monthly to reflect changes in actual
      costs.





21


South
      Dakota law authorizes the SDPUC to suspend new rates for up to six months during
      the pendency of rate proceedings; however, the rates are permitted to be
      implemented after six months subject to refund pending a final order in the
      proceeding.





Under
      Illinois law, new rates may become effective 45 days after filing with the
      ICC,
      or on such earlier date as the ICC may approve, subject to its authority to
      suspend the proposed new rates, subject to hearing, for a period not to exceed
      approximately eleven months after filing. Under Illinois electric tariffs,
      MidAmerican Energy's Fuel Cost Adjustment Clause reflects changes in the cost
      of
      all fuels used for retail electric generation, including certain fuel
      transportation costs, nuclear fuel disposition costs and the cost of energy
      purchased from other utilities. MidAmerican Energy's cost of gas is reflected
      in
      its Illinois gas rates through the Illinois Uniform Purchased Gas Adjustment
      Clause. Both of the adjustment clauses are updated on a monthly basis to reflect
      changes in actual costs.





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
      ICC and transitions portions of the traditional electric services to a
      competitive environment. In general for the transition period that extends
      through 2006, the law allows for certain limits on the ICC’s regulatory
      authority over a utility’s generation and also relaxes its regulatory authority
      over many corporate transactions, such as the transfer of generation assets
      to
      affiliates. Special authority and limitations of authority apply during the
      transition to a competitive marketplace. Also, the law permits utilities to
      eliminate their fuel adjustment clauses and incorporates provisions by which
      earnings in excess of allowed amounts are either partially refunded to customers
      or are used to accelerate a company's asset recovery. Electric rates in Illinois
      are frozen until January 1, 2007, subject to certain exceptions allowing
      for increases, at which time bundled rates are subject to cost-based
      ratemaking.





The
      FERC
      regulates MidAmerican Energy’s rates charged to wholesale customers for energy
      and transmission services. 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. The FERC conducts a triennial review
      of
      MidAmerican Energy’s market-based pricing authority. Margins earned on wholesale
      sales have historically been included as a component of retail cost of service
      upon which retail rates are based.





On
      July 22, 2005, MidAmerican Energy made a filing with the FERC requesting
      its approval to establish a transmission service coordinator (“TSC”). The TSC
      would be a third party administrator of various MidAmerican Energy OATT
      functions for transmission service. On December 16, 2005, the FERC issued
      an order conditionally accepting MidAmerican Energy’s request to establish a
      TSC. The order requires MidAmerican Energy to make modifications to the draft
      TSC agreement filed with the FERC as part of the request and to file a final
      executed TSC agreement with the FERC for its review prior to the agreement
      becoming effective. MidAmerican Energy has entered into a contract with a
      third-party vendor to administer MidAmerican Energy’s OATT. MidAmerican Energy
      does not believe that the incremental costs will have a material impact on
      its
      results of operations, financial position or cash flows. Subject to FERC
      approval, the TSC is scheduled to commence operations in the third quarter
      of
      2006. Under the contract, the vendor would provide its tariff administration
      and
      planning services into the fall of 2009.





On
      June 3, 2004, the FERC’s Division of Operational Investigations of the
      Office of Market Oversight and Investigations (“OMOI”) informed MidAmerican
      Energy that it was commencing an audit to determine whether and how MidAmerican
      Energy and its subsidiaries and affiliates are complying with (1) requirements
      of the standards of conduct and open access same-time information system of
      the
      FERC’s regulations, and (2) codes of conduct. In addition, OMOI sought to review
      MidAmerican Energy’s transmission practices. The FERC commenced several such
      audits of utilities in 2003 and 2004. On September 29, 2005, the FERC
      approved the audit findings and MidAmerican Energy agreed to take certain
      corrective actions. Accordingly, MidAmerican Energy will build $9.2 million
      in previously unscheduled transmission system upgrades. That capital expenditure
      will be excluded from MidAmerican Energy’s rate base for six years during which
      time MidAmerican Energy will not earn a return on the transmission upgrades.
      In
      addition, MidAmerican Energy has agreed to accelerate $14.7 million of
      scheduled transmission system upgrades. MidAmerican Energy has implemented
      a
      compliance plan to address certain aspects of the audit findings relating to
      transmission practices and the administration of the OATT.





22


On
      July 13, 2004, the FERC issued an order requiring MidAmerican Energy to
      conduct a study to determine whether MidAmerican Energy or its affiliates
      possess generation market power. MidAmerican Energy is being required to show
      the absence of generation market power in order to be allowed to continue to
      sell wholesale electric power at market-based rates. The FERC order is intended
      to have MidAmerican Energy conform to what has become the FERC’s general
      practice for utilities given authorization to make wholesale market-based sales.
      Under this general practice, utilities authorized to make market-based electric
      sales must submit a new market power study to the FERC every three years.
      MidAmerican Energy filed the required study on October 29, 2004. On
      June 1, 2005, the FERC issued an order setting for investigation the
      reasonableness of MidAmerican Energy’s market-based rates within its control
      area. The order also terminated the previously established November 1, 2004
      refund date and instead required that market-based sales made by MidAmerican
      Energy within its control area beginning August 7, 2005 be subject to
      refund until the matter is resolved. The FERC also required MidAmerican Energy
      to file additional information by July 1, 2005, and August 1, 2005. In
      its August 1, 2005 filing, MidAmerican Energy filed a proposed cost-based
      sales tariff applicable to sales made within its control area to replace its
      market-based sales tariff. The FERC is currently reviewing the proposed tariff.
      MidAmerican Energy does not expect the outcome of this issue to have a material
      effect on its results of operations, financial position or cash
      flows.





*Kern
      River and Northern Natural Gas*





Kern
      River and Northern Natural Gas are subject to regulation by various federal
      and
      state agencies. As owners of interstate natural gas pipelines, Northern Natural
      Gas’ and Kern River’s rates, services and operations are subject to regulation
      by the FERC. The FERC administers, among other things, the Natural Gas Act
      and
      the Natural Gas Policy Act of 1978. Additionally, interstate pipeline companies
      are subject to regulation by the United States Department of Transportation
      (“DOT”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”), which
      establishes safety requirements in the design, construction, operations and
      maintenance of interstate natural gas transmission facilities, and the PSIA,
      which implemented additional safety and pipeline integrity regulations for
      high
      consequence areas.





The
      FERC
      has jurisdiction over, among other things, 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. The FERC also has jurisdiction over the rates and charges
      and
      terms and conditions of service for the transportation of natural gas in
      interstate commerce.





Additional
      proposals and proceedings that might affect the interstate natural gas pipeline
      industry are considered from time to time by 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 Kern River and Northern Natural Gas might
      be
      affected.





The
      Company’s pipeline operations are subject to regulation by the DOT under the
      NGPSA relating to design, installation, testing, construction, operation and
      management of its pipeline systems. 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. The Company’s 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
      aging
      pipeline infrastructure in the United States has led to heightened regulatory
      and legislative scrutiny of pipeline safety and integrity practices. The NGPSA
      was amended by the Pipeline Safety Act of 1992 to require the DOT’s Office of
      Pipeline Safety to consider protection of the environment when developing
      minimum pipeline safety regulations. In addition, the amendments require that
      the DOT issue pipeline regulations concerning, among other issues, the
      circumstances under which emergency flow restriction devices should be required,
      training and qualification standards for personnel involved in maintenance
      and
      operation, and requirements for periodic integrity inspections, as well as
      periodic inspection of facilities in navigable waters that pose a hazard to
      navigation or public safety. In addition, the amendments narrowed the scope
      of
      the exemption for gas pipelines from the underground storage tank requirements
      under the Resource Conservation and Recovery Act. The Company believes its
      pipeline systems comply in all material respects with the NGPSA.





The
      PSIA
      requires major new programs in the areas of operator qualification, risk
      analysis and integrity management. The PSIA requires the periodic inspection
      or
      testing of pipelines in areas where the potential consequences of a gas pipeline
      accident may be significant or may do considerable harm to people and their
      property, which are referred to as High Consequence Areas. Pursuant to the
      PSIA,
      the DOT promulgated new regulations, effective February 14, 2004, that
      require interstate pipeline operators to (i) develop comprehensive integrity
      management programs, (ii) identify applicable threats to pipeline segments
      that
      could impact High Consequence Areas, (iii) assess these segments, and (iv)
      provide ongoing mitigation and monitoring. The Company believes its pipeline
      operations comply in all material respects with the PSIA.





23


*Energy
      Policy Act*





On
      August 8, 2005, the Energy Policy Act was signed into law. That law
      potentially impacts many segments of the energy industry. The law will result
      in
      expanding the FERC’s regulatory authority in areas such as mandatory electric
      system reliability standards, electric transmission expansion incentives and
      pricing, regulation of utility holding companies, and gives the FERC enforcement
      authority to issue substantial civil penalties. 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 repealed PUHCA 1935 and enacted the Public Utility Holding
      Company Act of 2005 (“PUHCA 2005”), effective February 8, 2006. PUHCA 1935
      extensively regulated and restricted the activities of registered public utility
      holding companies and their subsidiaries. PUHCA 2005 and the rules issued by
      the
      FERC to implement PUHCA 2005 require, among other things, public utility holding
      companies to permit access by the FERC to the books and records of the holding
      company and its affiliates transacting business with the public utility, unless
      such requirement is exempted or waived, and to comply with the FERC’s record
      retention requirements. The repeal of PUHCA 1935 enabled Berkshire Hathaway
      to
      convert all of its outstanding no par, zero-coupon convertible preferred stock
      into an equal number of shares of MEHC’s common stock thereby becoming the
      majority owner of MEHC.





The
      Energy Policy Act also substantially amended the Public Utility Regulatory
      Policies Act of 1978 (“PURPA”). PURPA and the regulations issued thereunder
      affected MEHC and certain of its subsidiaries’ operations by providing to
      qualifying facilities (“QF”) certain exemptions from federal and state laws and
      regulations, including organizational, rate and financial regulation. New
      Section 210(m) eliminates the requirement that public utilities purchase the
      capacity and energy of QFs if the FERC determines that the requisite competitive
      market criteria are satisfied. In January 2006, the FERC instituted a rulemaking
      process to implement this section of the Energy Policy Act. The Energy Policy
      Act removed the 50% limitation on electric utility and electric utility holding
      company ownership of QFs. The Energy Policy Act does not authorize the
      termination of any existing contract and the Company does not expect the
      amendments to PURPA to have an adverse effect on the Company.





*CE
      Electric UK*





Since
      1990, the electricity generation, transmission, supply and distribution
      industries in Great Britain have been privatized, and competition has been
      introduced in generation and supply, and, to a much more limited extent, in
      some
      aspects of distribution such as new connections and metering. Electricity is
      produced by generators, transmitted through the national grid transmission
      system and distributed to customers by the fourteen Distribution License Holders
      (“DLHs”) in their respective distribution services areas.





Under
      the
      Utilities Act 2000, the public electricity supply license created pursuant
      to
      the Electricity Act 1989 was replaced by two separate licenses - the electricity
      distribution license and the electricity supply license. When the relevant
      provision of the Utilities Act 2000 became effective on October 1, 2001,
      the public electricity supply licenses formerly held by Northern Electric plc
      (“NE”) and Yorkshire Electricity Group plc (“YE”) were split so that separate
      subsidiaries held licenses for electricity distribution and electricity supply.
      In order to comply with the Utilities Act 2000 and to facilitate this license
      splitting, NE and YE (and each of the other holders of the former public
      electricity supply licenses) each made a statutory transfer scheme that was
      approved by the Secretary of State for Trade and Industry. These schemes
      provided for the transfer of certain assets and liabilities to the licensed
      subsidiaries. This occurred on October 1, 2001, a date set by the Secretary
      of State for Trade and Industry. As a consequence of these schemes, the
      electricity distribution businesses of NE and YE were transferred to Northern
      Electric and Yorkshire Electricity, respectively. Northern Electric and
      Yorkshire Electricity are each a DLH. The residual elements of the electricity
      supply licenses were transferred to Innogy Holdings plc (“Innogy”), the
      predecessor of Npower, in connection with the sale of NE’s electricity and gas
      supply business to Innogy and the purchase by NE of YE’s electricity
      distribution business from Innogy on September 21, 2001.





Each
      of
      the DLHs is required to offer terms for connection to its distribution system
      and for use of its distribution system to any person. In providing the use
      of
      its distribution system, a DLH must not discriminate between users, nor may
      its
      charges differ except where justified by differences in cost.





24


Under
      the
      Utilities Act 2000, the Gas and Electricity Markets Authority (“GEMA”) is able
      to impose financial penalties on license holders who contravene (or have in
      the
      past contravened) any of their license duties or certain of their duties under
      the Electricity Act 1989, as amended, or who are failing (or have in the past
      failed) to achieve a satisfactory performance in relation to the individual
      standards of performance prescribed by GEMA. Any penalty imposed must be
      reasonable and may not exceed 10% of the licensee’s revenue.





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 British
      electricity regulatory body and was last reset on April 1, 2005. The
      distribution price control formula is generally reviewed and reset at five-year
      intervals. Through March 31, 2010, the change in revenue is expected to be
      mainly influenced by the rate of inflation in the United Kingdom, system losses,
      the number of customers connected to the network and customer service
      performance. The Office of Gas and Electricity Markets (“Ofgem”) completed the
      process of reviewing the existing price control formula for Northern Electric
      and Yorkshire Electricity in November 2004. As a result of the review, the
      allowed revenue of Northern Electric’s and Yorkshire Electricity’s distribution
      businesses were reduced by 4% and 9%, respectively, in real terms, effective
      April 1, 2005.





*CalEnergy
      Generation-Foreign*





The
      Philippine Congress has passed 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
      have an impact on the Company’s future operations in the Philippines and the
      Philippine power industry as a whole, the effect of which is not yet
      determinable or estimable.





In
      connection with the signing of the Supplemental Agreement, CE Casecnan received
      written confirmation from the Private Sector Assets and Liabilities Management
      Corporation that the issues with respect to the Casecnan Project that had been
      raised by the interagency review of independent power producers in the
      Philippines or that may have existed with respect to the project under certain
      provisions of EPIRA, which authorized the ROP to seek to renegotiate certain
      contracts such as the Project Agreement, have been satisfactorily addressed
      by
      the Supplemental Agreement.





*CalEnergy
      Generation-Domestic*





Each
      of
      the domestic power facilities in the CalEnergy Generation-Domestic platform,
      excluding Cordova Energy and Power Resources, meets the requirements promulgated
      under PURPA to be a QF. Prior to passage of the Energy Policy Act, QF status
      under PURPA provided two primary benefits. First, regulations under PURPA
      exempted QFs from PUHCA 1935, the FERC rate regulation under Sections 205 and
      206 of the Federal Power Act and the state laws concerning rates of electric
      utilities and financial and organization regulations of electric utilities.
      Second, the FERC’s regulations promulgated under PURPA required that (1)
      electric utilities purchase electricity generated by QFs, the construction
      of
      which commenced on or after November 9, 1978, at a price based on the
      purchasing utility’s Avoided Cost of Energy, (2) electric utilities sell
      back-up, interruptible, maintenance and supplemental power to QFs on a
      non-discriminatory basis, and (3) electric utilities interconnect with QFs
      in
      their service territories. Following the effective date of repeal of PUHCA
      1935,
      the exemption from PUHCA 1935 is no longer relevant, but QFs remain exempt
      from
      the accounting and reporting requirements of PUHCA 2005. QF sales that occur
      pursuant to existing contracts will continue to be exempt from FERC rate
      regulation under Sections 205 and 206 of the Federal Power Act. However, with
      respect to new contracts, QFs are no longer exempt from FERC’s regulation of
      rates under Sections 205 and 206 of the Federal Power Act, unless the relevant
      sales are made pursuant to a state regulatory authority’s implementation of
      PURPA,





In
      addition, in January 2006, the FERC issued a notice of proposed rulemaking
      to
      implement a provision of the Energy Policy Act, which eliminates the electric
      utilities’ mandatory purchase obligation under PURPA if the FERC determines that
      certain conditions regarding QF access to transmission facilities and
      competitive markets are satisfied. Although the proposed rule does not permit
      electric utilities to terminate existing agreements, such as those now in place
      with CalEnergy Generation-Domestic, if the final rule is adopted substantially
      as proposed, the effect on the Company when the existing agreements terminate
      could be adverse. QF owners are required to provide notice to the FERC of a
      “material change” in facts in an application for recertification or notice of
      self-recertification. Subsequent notices of self-recertification for the same
      QF
      need only refer to changes which have occurred with respect to the facility
      since the prior notice or the prior FERC certification.





25


In
      another rulemaking proceeding to implement part of the Energy Policy Act, the
      FERC stated that exempt wholesale generators (“EWG”) like Cordova Energy and
      Power Resources are not considered to be an electric utility company for the
      limited purpose of the FERC’s access to the books and records of holding company
      systems under PUHCA 2005. As such, a EWG is permitted to sell capacity and
      electricity in the wholesale markets, but not in the retail markets. If a EWG
      is
      subject to a “material change” in facts that might affect its continued
      eligibility for EWG status, within 60 days of such material change, the EWG
      must
      (1) file a written explanation of why the material change does not affect its
      EWG status, (2) file a new application for EWG status, or (3) notify the FERC
      that it no longer wishes to maintain EWG status.





*HomeServices*





HomeServices
      is subject to regulations promulgated by the U.S. Department of Housing and
      Urban Development (“HUD”) as well as regulatory agencies in the states within
      which it operates that significantly influence its operating environment. The
      House Committee on Financial Services, the Senate Committee on Banking, Housing
      and Urban Affairs and HUD each had indicated that reforming the Real Estate
      Settlement and Procedures Act (“RESPA”) regulation was a priority in 2005. On
      June 27, 2005, HUD announced their plan to hold six roundtables to discuss
      with the industry what provisions a new RESPA reform rule should contain. Those
      roundtables were held across the country in July and August 2005. HUD stated
      that it would publish its RESPA proposal in late 2005 and the Final Rule in
      2006. As of December 31, 2005, HUD did not publish a RESPA proposal and has
      not indicated when a Final Rule will be issued in 2006. It is believed that
      this
      delay has been caused, in part, by the damage caused by hurricanes Katrina
      and
      Wilma. It is unknown whether a proposed rule will be introduced or finalized
      in
      2006. Accordingly, the Company is presently unable to quantify the likely impact
      of any proposed rule, if issued.





Environmental
      Regulation





*Domestic*





The
      Company’s domestic operations are subject to a number of federal, state and
      local environmental and environmentally related laws and regulations affecting
      many aspects of its present and future operations in the United States. Such
      laws and regulations generally require the Company’s domestic operations to
      obtain and comply with a wide variety of licenses, permits and other approvals.
      The Company believes that its operating power facilities and natural gas
      pipeline operations are currently in material compliance with all applicable
      federal, state and local laws and regulations. However, no guarantee can be
      given that in the future the Company’s domestic operations will be in material
      compliance with all applicable environmental statutes and regulations or that
      all necessary permits will be obtained or approved. In addition, the
      construction of new power facilities and natural gas pipeline operations is
      a
      costly and time-consuming process requiring a multitude of complex environmental
      permits and approvals prior to the start of construction that may create the
      risk of expensive delays or material impairment of project value if projects
      cannot function as planned due to changing regulatory requirements or local
      opposition. The Company cannot provide assurance that existing regulations
      will
      not be revised or that new regulations will not be adopted or become applicable
      to it which could have an adverse impact on its capital or operating costs
      or
      its operations.





Under
      various federal, state and local environmental laws and regulations, a current
      or previous owner or operator of any facility may be required to investigate
      and
      remediate past releases or threatened releases of hazardous or toxic substances
      or petroleum products located at the facility, and may be held liable to a
      governmental entity or to third parties for property damage, personal injury
      and
      investigation and remediation costs incurred by a party in connection with
      certain releases or threatened releases. In certain cases liability for damages
      to natural resources may also be assessed. These laws, including the
      Comprehensive Environmental Response, Compensation and Liability Act of 1980,
      as
      amended by the Superfund Amendments and Reauthorization Act of 1986, impose
      liability without regard to whether the owner knew of or caused the release
      of
      the hazardous substances, and courts have interpreted liability under such
      laws
      to be strict and joint and several. The cost of investigation, remediation
      or
      removal of substances may be substantial. In connection with the Company’s
      ownership and operation of its power facilities and pipeline systems, the
      Company may become liable for such costs. Given the use of hazardous substances
      and/or petroleum products within its power facilities and pipeline systems,
      often within areas that have a long history of industrial use, it is possible
      that the Company will discover currently unknown contamination or that future
      spills or other causes of contamination will occur. As a result, even at those
      sites where the Company is not presently aware of any contamination that
      currently requires remediation, it is possible that the Company may become
      liable for additional remediation costs.





26


*Clean
      Air Standards*





MidAmerican
      Energy is subject to applicable provisions of the Clean Air Act and related
      air
      quality standards promulgated by the United States Environmental Protection
      Agency (“EPA”). The Clean Air Act provides the framework for regulation of
      certain air emissions and permitting and monitoring associated with those
      emissions. MidAmerican Energy believes it is in material compliance with current
      air quality requirements. In addition to the discussion contained herein, refer
      to Note 20 of Notes to Consolidated Financial Statements included in Item 8.
      Financial Statements and Supplementary Data of this Form 10-K for additional
      clean air standards information regarding MidAmerican Energy’s
      operations.





On
      February 16, 2005, the Kyoto Protocol became effective, requiring 35
      developed countries to reduce greenhouse gas emissions by approximately 5%
      between 2008 and 2012. While the United States did not ratify the protocol,
      the
      ratification and implementation of its requirements in other countries has
      resulted in increased attention to the climate change issue in the United
      States. In 2005, the Senate adopted a “sense of the Senate” resolution that puts
      the Senate on record that Congress should enact a comprehensive and effective
      national program of mandatory, market-based limits and incentives on emissions
      of greenhouse gases that slow, stop, and reverse the growth of such emissions
      at
      a rate and in a manner that will not significantly harm the United States
      economy; and will encourage comparable action by other nations that are major
      trading partners and key contributors to global emissions. It is anticipated
      that the resolution may be further addressed by Congress in 2006. While debate
      continues at the national level over the direction of domestic climate policy,
      several states are developing state-specific or regional legislative initiatives
      to reduce greenhouse gas emissions. In December 2005, the states of Connecticut,
      Delaware, Maine, New Hampshire, New Jersey, New York and Vermont signed a
      mandatory regional pact to reduce greenhouse gas emissions. 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 public nuisance suit,
      holding that such critical issues affecting the United States such as greenhouse
      gas emissions reductions are not the domain of the court and should be resolved
      by the Executive Branch 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 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 results of
      operations.





The
      EPA’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
      MidAmerican’s facilities in particular, such actions could significantly impact
      the Company’s fossil-fueled facilities and, therefore, its results of
      operations.





*Clean
      Water Standards*





Section
      316(b) of the Clean Water Act requires that cooling water intake structures
      reflect the best technology available for minimizing "adverse environmental
      impacts" to aquatic organisms. On February 16, 2004, EPA Administrator
      Michael Leavitt signed the final Phase II rule for existing electric generating
      facilities. The rule sets significant new national technology-based performance
      standards 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. MidAmerican Energy has completed a review of its
      historical Section 316(b) studies, as well as filed Proposals for Information
      Collection describing MidAmerican Energy’s plans for conducting biological field
      studies adjacent to its cooling water intake structures over the next two years.
      Although the impact of the MidAmerican Energy intake structures on aquatic
      organisms is unknown at this time, the previous Section 316(b) studies suggest
      that the impingement impact at the facility intake structures is minimal and
      that little if any intake structure expenditures will be necessary to meet
      the
      Section 316(b) impingement standard. Because of the high flow rate of the
      Missouri and Mississippi Rivers as compared to the withdrawal rates of the
      intake structures, the entrainment criteria of the Section 316(b) rule is not
      applicable to the MidAmerican Energy facilities. However, should the new
      impingement studies show that the intakes are impacting the fish species, the
      intake structures may need to be modified to meet best technology standards.
      This could include significant expenditures involved with limiting the amount
      of
      water withdrawn from the Missouri or Mississippi Rivers, and restrictions on
      the
      intake flow velocity.





*Nuclear
      Regulation*





MidAmerican
      Energy is subject to the jurisdiction of the NRC with respect to its license
      and
      25% ownership interest in Quad Cities Station Units 1 and 2. Exelon Generation
      Company, LLC (“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.





27


The
      NRC
      regulations control the granting of permits and licenses for the construction
      and operation of nuclear generating stations and subject such stations to
      continuing review and regulation. On October 29, 2004, the NRC granted
      renewed licenses for both Quad Cities Station Unit 1 and Unit 2 that provide
      for
      operation until December 14, 2032, which is in effect a 20-year extension
      of the licenses. 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.





The
      NRC
      also regulates the decommissioning of nuclear power plants including the
      planning and funding for the eventual decommissioning of the plants. In
      accordance with these regulations, MidAmerican Energy submits a report to the
      NRC every two years providing reasonable assurance that funds will be available
      to pay the costs of decommissioning its share of Quad Cities
      Station.





Under
      the
      Nuclear Waste Policy Act of 1982 (“NWPA”), the U.S. Department of Energy (“DOE”)
      is responsible for the selection and development of repositories for, and the
      permanent disposal of, spent nuclear fuel and high-level radioactive wastes.
      Exelon Generation, as required by the NWPA, signed a contract with the DOE
      under
      which the DOE was to receive spent nuclear fuel and high-level radioactive
      waste
      for disposal beginning not later than January 1998. The DOE did not begin
      receiving spent nuclear fuel on the scheduled date and remains unable to receive
      such fuel and waste. The earliest the DOE currently is expected to be able
      to
      receive such fuel and waste is 2010. The costs to be incurred by the DOE for
      disposal activities are being financed by fees charged to owners and generators
      of the waste. In 2004, Exelon Generation reached a settlement with the DOE
      concerning the DOE’s failure to begin accepting spent nuclear fuel in 1998. As a
      result, Quad Cities Station will be billing the DOE, and the DOE will be
      obligated to reimburse the station for all station costs incurred due to the
      DOE’s delay. Exelon Generation has completed construction of an interim spent
      fuel storage installation (“ISFSI”) at Quad Cities Station to store spent
      nuclear fuel in dry casks in order to free space in the storage pool. The first
      pad at the ISFSI is expected to facilitate storage of casks to support
      operations at Quad Cities Station until at least 2017. The first storage in
      dry
      cask commenced in November 2005. In the 2017 to 2022 timeframe, Exelon
      Generation plans to add a second pad to the ISFSI to accommodate storage of
      spent nuclear fuel through the end of operations at Quad Cities
      Station.





MidAmerican
      Energy has established trusts for the investment of funds collected for nuclear
      decommissioning associated with Quad Cities Station. Electric tariffs currently
      in effect include provisions for annualized collection of estimated
      decommissioning costs at Quad Cities Station. In Iowa, estimated Quad Cities
      Station decommissioning costs are reflected in base rates. MidAmerican Energy’s
      cost related to decommissioning funding in 2005 was
      $8.3 million.





*United
      Kingdom*





CE
      Electric UK’s businesses are subject to a number of United Kingdom regulations
      with respect to the protection of the environment. The principal legislation
      behind these regulations in relation to CE Electric UK activities is the Water
      Resources Act of 1991 and the Environmental Protection Act of 1990. The most
      relevant regulatory requirement is the Hazardous Waste (England and Wales)
      Regulations, which came into force in July 2005. These regulations widened
      the
      scope of hazardous waste and have reclassified many waste products as hazardous
      that were previously regarded as non-hazardous waste. The cost of compliance
      with these requirements has been immaterial and the Company expects the ongoing
      cost of compliance will not have a material impact on the Company.





*Philippines*





On
      June 23, 1999, the Philippine Congress enacted the Philippine Clean Air Act
      of 1999 (the “Philippine Clean Air Act”). The related implementing rules and
      regulations were adopted in November 2000. The law as written would require
      the
      Leyte Projects to comply with a maximum discharge of 200 grams of hydrogen
      sulfide per gross MWh of output by June 2004. On November 13, 2002, the
      Secretary of the Philippine Department of Environment and Natural Resources
      issued a Memorandum Circular (“MC”) designating geothermal areas as “special
      airsheds.” PNOC-EDC has advised the Leyte Projects that the MC exempts the
      Mahanagdong and Malitbog plants from the need to comply with the point-source
      emission standards of the Philippine Clean Air Act. CE Cebu and PNOC-EDC have
      constructed a gas dispersion facility for the Upper Mahiao project which is
      designed to ensure compliance with the emission standards of the Philippine
      Clean Air Act. The gas dispersion project was put into commercial operation
      in
      December 2003.





28


**Employees**





At
      December 31, 2005, the Company employed approximately 11,400 people, of
      which approximately 3,900 are covered by union contracts. MidAmerican Energy’s
      union contract with International Brotherhood of Electrical Workers locals
      109
      and 499 was set to expire on February 28, 2006, and covers approximately
      1,700 employee members. On February 10, 2006, the contract terms with
      locals 109 and 499 were extended through April 30, 2006, and the parties
      agreed to a 30-day notice of strike or lockout.





**Item
      1A.** **Risk
      Factors.**





Risks
      Associated with the Company’s Corporate and Financial Structure





*MEHC
      is a holding company that depends on distributions from its subsidiaries and
      joint ventures to meet its needs.*





MEHC
      is a
      holding company and derives substantially all of its income and cash flow from
      its subsidiaries and joint ventures. MEHC expects that future development and
      acquisition efforts will be similarly structured to involve operating
      subsidiaries and joint ventures. MEHC is dependent on the earnings and cash
      flows of, and dividends, loans, advances or other distributions from, its
      subsidiaries and joint ventures to generate the funds necessary to meet its
      obligations. All required payments on debt and preferred stock at subsidiary
      levels will be made before funds from subsidiaries are available to MEHC. The
      availability of distributions from such entities is also subject
      to:




Ÿ
              their
                  earnings and capital requirements;Ÿ
              the
                  satisfaction of various covenants and conditions contained in financing
                  documents by which they are bound or in their organizational documents;
                  andŸ
              in
                  the case of MEHC’s regulated utility subsidiaries, regulatory restrictions
                  which restrict their ability to distribute profits to
                  MEHC.


MEHC’s
        subsidiaries and joint ventures are separate and distinct legal entities
        and
        have no obligation, contingent or otherwise, to pay any of MEHC’s obligations or
        to make any funds available, whether by dividends, loans or other payments,
        for
        payment of MEHC’s obligations, and do not guarantee the payment of MEHC’s
        obligations.





*The
      Company is substantially leveraged, the terms of MEHC’s senior and subordinated
      debt do not restrict its ability or its subsidiaries’ ability to incur
      additional indebtedness that could have an adverse impact on the Company’s
      financial condition and MEHC’s senior and subordinated debt is structurally
      subordinated to the indebtedness of its subsidiaries.*





The
      Company’s substantial leverage level presents the risk that it might not
      generate sufficient cash to service its indebtedness or that the Company’s
      leveraged capital structure could limit its ability to finance future
      acquisitions, develop additional projects, compete effectively and operate
      successfully under adverse economic conditions. At December 31, 2005,
      MEHC’s outstanding senior indebtedness was approximately $2.8 billion and
      MEHC’s outstanding subordinated indebtedness was approximately
      $1.6 billion. These amounts exclude MEHC’s guarantees and letters of credit
      in respect of subsidiary and equity investment indebtedness aggregating
      approximately $90.9 million as of December 31, 2005. The Company
      expects to incur additional indebtedness in the future, including approximately
      $1.7 billion of MEHC long-term senior debt.





MEHC’s
      subsidiaries also have significant amounts of indebtedness. At December 31,
      2005, MEHC’s consolidated subsidiaries had outstanding indebtedness totaling
      approximately $7.2 billion. This amount does not include (i) any trade debt
      or preferred stock obligations of MEHC’s subsidiaries, (ii) its subsidiaries’
letters of credit in respect of their indebtedness, (iii) MEHC’s share of the
      outstanding indebtedness of its and its subsidiaries’ equity investments, or
      (iv) the outstanding indebtedness and preferred stock of PacifiCorp, which
      was
      approximately $4.3 billion at December 31, 2005.





29


The
      terms
      of MEHC’s senior and subordinated debt do not limit its ability or the ability
      of its subsidiaries or joint ventures to incur additional debt or issue
      additional preferred stock. Accordingly, MEHC or its subsidiaries or joint
      ventures could enter into acquisitions, refinancings, recapitalizations or
      other
      highly leveraged transactions that could significantly increase MEHC’s or their
      total amount of outstanding debt. The interest payments needed to service this
      increased level of indebtedness could have a material adverse effect on MEHC’s
      or its subsidiaries’ operating results. A highly leveraged capital structure
      could also impair MEHC’s or its subsidiaries’ overall credit quality, making it
      more difficult for the Company to finance its operations or issue future
      indebtedness on favorable terms, and could result in a downgrade in the ratings
      of the Company’s indebtedness by credit rating agencies. Further, if any of
      MEHC’s or its subsidiaries’ indebtedness is accelerated due to an event of
      default under such indebtedness and such acceleration results in an event of
      default under some or all of the Company’s other indebtedness, the Company may
      not have sufficient funds to repay all of the accelerated
      indebtedness.





Claims
      of
      creditors of MEHC’s subsidiaries and joint ventures have priority over the
      claims of MEHC’s senior and subordinated debt holders with respect to the assets
      and earnings of MEHC’s subsidiaries and joint ventures. In addition, the stock
      or assets of substantially all of MEHC’s operating subsidiaries and joint
      ventures is directly or indirectly pledged to secure their financings and,
      therefore, may be unavailable as potential sources of repayment of MEHC’s senior
      and subordinated debt.





*MEHC’s
      majority stockholder, Berkshire Hathaway, could exercise control over the
      Company in a manner that would benefit Berkshire Hathaway to the detriment
      of
      the Company’s creditors.*





MEHC
      became a majority owned subsidiary of Berkshire Hathaway on February 9,
      2006, and, therefore, Berkshire Hathaway has control over the decision of all
      matters submitted for shareholder approval, including the election of MEHC’s
      directors who oversee its management and affairs. In circumstances involving
      a
      conflict of interest between Berkshire Hathaway, on the one hand, and MEHC’s
      creditors, on the other, Berkshire Hathaway could exercise its control in a
      manner that would benefit Berkshire Hathaway to the detriment of MEHC’s
      creditors.





Risks
      Associated with the Company’s Business





*The
      Company’s growth has been achieved, in significant part, through strategic
      acquisitions, and additional acquisitions may not be
      successful.*





The
      Company’s growth has been achieved, in significant part, through strategic
      acquisitions. The Company intends to continue to pursue selected opportunities
      for acquisitions of assets and businesses, as well as business combinations,
      within the Company’s industries for the foreseeable future. The Company
      investigates opportunities that it believes may increase shareholder value
      and
      build on existing businesses. The Company has participated in the past, and
      the
      Company’s security holders may assume that at any time the Company may be
      participating, in bidding or other negotiations for such transactions. This
      participation may or may not result in a transaction for the Company. Any
      transaction that does take place may involve consideration in the form of cash,
      debt or equity securities.





Since
      1996, the Company has completed several significant acquisitions, including
      the
      acquisitions of Northern Electric, Yorkshire Electricity, MidAmerican Energy,
      Kern River and Northern Natural Gas. In May 2005, MEHC announced that it had
      reached a definitive agreement with ScottishPower to acquire its wholly-owned
      indirect subsidiary, PacifiCorp, a regulated electric utility for a cash
      purchase price of approximately $5.1 billion. Subject to the most favored
      states process with the regulatory authorities in certain states where
      PacifiCorp has operations and other customary closing conditions, MEHC expects
      this transaction to close in March 2006.





The
      successful integration of any businesses the Company may acquire in the future
      will entail numerous risks, including, among others, the risk of diverting
      management’s attention from day-to-day operations, the risk that the acquired
      businesses will require substantial capital and financial investments and the
      risk that the investments will fail to perform in accordance with expectations.
      Any substantial diversion of management attention and any substantial
      difficulties encountered in the transition and integration process could have
      a
      material adverse effect on the Company’s revenues, levels of expenses and
      operating results.





30


In
      addition, it has been publicly reported over the past several years that many
      of
      the participants in the United States energy industry, including the prior
      owners of Kern River and Northern Natural Gas and potentially including other
      industry participants from whom the Company may choose to purchase additional
      businesses in the future, have had or may have liquidity, creditworthiness
      and
      other financial difficulties. As a consequence, there can be no assurance that
      any such sellers will not enter into bankruptcy or insolvency proceedings or
      that they will otherwise be able, required or willing to perform on their
      indemnification obligations to the Company if it should elect to pursue any
      such
      claims the Company may have against any of them under our acquisition agreements
      in the future. If the Company’s due diligence efforts were or are unsuccessful
      in identifying and analyzing all material liabilities relating to acquired
      companies and if there were to be any material undisclosed liabilities, or
      if
      there were to be other unexpected consequences from any such bankruptcy or
      insolvency proceeding, such as a successful challenge as to whether the prices
      paid by the Company constituted reasonably equivalent value within the meaning
      of the relevant bankruptcy laws, then any such bankruptcy or insolvency, or
      failure by any of these sellers to perform their indemnification obligations
      to
      the Company, could have a material adverse effect on the Company’s business,
      financial condition, results of operations and the market prices and rates
      for
      the Company’s securities.





The
      Company cannot provide assurance that future acquisitions, if any, or any
      related integration efforts will be successful, or that the Company’s ability to
      repay its debt will not be adversely affected by any future
      acquisitions.





*The
      Company is actively pursuing, developing and constructing new or expanded
      facilities, the completion and expected cost of which is subject to significant
      risk.*





Through
      MEHC’s operating subsidiaries, the Company is continuing to develop, construct,
      own and operate new or expanded facilities, including new electric generating
      projects in Iowa. The Company also expects that its existing subsidiaries and
      PacifiCorp will make substantial annual capital expenditures relating to new
      or
      expanded facilities over the next five years. MEHC is under no contractual
      obligation to provide capital to any of its subsidiaries. If MEHC does not
      provide any required funding to any of its subsidiaries, such subsidiaries
      may
      be unable to fund required capital requirements and may need to postpone or
      cancel planned capital expenditures. Any such postponement or cancellation
      of
      planned capital expenditures could result in system reliability issues,
      environmental issues, penalties for outages or noncompliance with laws and
      the
      inability to earn a return on amounts expended.





In
      the
      future the Company expects to pursue the development, construction, ownership
      and operation of additional new or expanded energy projects (including, without
      limitation, generation, distribution, transmission, exploration/production,
      storage and supply projects and related activities, infrastructure and
      services), both domestically and internationally. The completion of any or
      all
      of these pending, proposed or future projects is subject to substantial risk
      and
      may expose the Company to significant costs. The Company cannot assure you
      that
      its development or construction efforts on any particular project or the
      Company’s efforts generally, will be successful. If the Company is unable to
      complete the development or construction of any such project, or if it decides
      to delay or cancel a project, the Company may not be able to recover its
      investment in that project.





Also,
      a
      proposed expansion or new project may cost more than planned to complete, and
      such excess costs, if related to a regulated asset and found to be imprudent,
      may not be recoverable in rates. The inability to successfully and timely
      complete a project or avoid unexpected costs may require the Company to perform
      under guarantees, and the inability to avoid unsuccessful projects or to recover
      any excess costs may materially affect the Company’s ability to service its
      obligations.





*MEHC’s
      subsidiaries are subject to certain operating uncertainties which may adversely
      affect the Company’s financial position, results of operation and ability to
      service MEHC’s senior and subordinated debt.*





The
      operation of complex electric and natural gas utility (including transmission
      and distribution) systems, pipelines or power generating facilities which are
      spread over a large geographic area involves many risks associated with
      operating uncertainties and events beyond the Company’s control. These risks
      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, transmission and distribution system
      constraints or outages, fuel shortages or interruptions, performance below
      expected levels of output, capacity or efficiency, operator error and
      catastrophic events such as severe storms, fires, earthquakes or explosions.
      A
      casualty occurrence might result in injury or loss of life, extensive property
      damage or environmental damage. The realization of any of these risks could
      significantly reduce or eliminate MEHC’s affiliates’ revenues or significantly
      increase MEHC’s affiliates’ expenses, thereby adversely affecting the ability to
      receive distributions from subsidiaries and joint ventures. For example, if
      MEHC’s affiliates cannot operate their electric or natural gas facilities at
      full capacity due to restrictions imposed by environmental regulations, their
      revenues could decrease due to decreased wholesale sales and their expenses
      could increase due to the need to obtain energy from higher cost sources. Any
      reduction of revenues for such reason, or any other reduction of MEHC’s
      affiliates’ revenues or increase in their expenses resulting from the risks
      described above, could decrease the Company’s net cash flow and provide the
      Company with fewer funds with which to service MEHC’s senior and subordinated
      debt.





31


Further,
      the Company cannot provide assurance that its current and future insurance
      coverage will be sufficient to replace lost revenue or cover repair and
      replacement costs, especially in light of the recent catastrophic events in
      the
      insurance markets that make it more difficult or costly to obtain certain types
      of insurance.





*Acts
      of sabotage and terrorism aimed at the Company’s facilities, the facilities of
      the Company’s fuel suppliers or customers, or at regional transmission
      facilities could adversely affect the Company’s business.*





Since
      the
      September 11, 2001 terrorist attacks, the United States government has
      issued warnings that energy assets, specifically our nation’s pipeline and
      electric utility infrastructure, may be the future targets of terrorist
      organizations. These developments have subjected the Company’s operations to
      increased risks. Damage to the assets of the Company’s fuel suppliers, the
      assets of the Company’s customers or the Company’s own assets or at regional
      transmission facilities inflicted by terrorist groups or saboteurs could result
      in a significant decrease in revenues and significant repair costs, force the
      Company to increase security measures, cause changes in the insurance markets
      and cause disruptions of fuel supplies, energy consumption and markets,
      particularly with respect to natural gas and electric energy. Any of these
      consequences of acts of terrorism could materially affect the Company’s results
      of operations and decrease the amount of funds the Company has available to
      make
      payments on MEHC’s senior and subordinated debt. Instability in the financial
      markets as a result of terrorism or war could also materially adversely affect
      the Company’s ability to raise capital.





*The
      Company is subject to energy regulation, legislation and political risks and
      changes in regulations and rates or legislative developments may adversely
      affect the Company’s business, financial condition, results of operations and
      ability to service MEHC’s senior and subordinated debt.*





The
      Company is subject to comprehensive governmental regulation, including
      regulation in the United States by various federal, state and local regulatory
      agencies, regulation in the United Kingdom and regulation in the Philippines,
      all of which significantly influences the Company’s operating environment, its
      rates, its capital structure, its costs and its ability to recover the Company’s
      costs from customers. These regulatory agencies include, among others, the
      FERC,
      the EPA, the Nuclear Regulatory Commission (“NRC”), the DOT, the IUB, the ICC,
      the SDPUC, other state utility boards, numerous local agencies, the GEMA, which
      in discharging certain of its powers acts through its staff within Ofgem, in
      the
      United Kingdom, and various other governmental agencies in the United States,
      the United Kingdom and the Philippines. Changes in regulations or the imposition
      of additional regulations by any of these entities or new legislation could
      have
      a material adverse impact on the Company’s results of operations. For example,
      such changes could result in increased retail competition in MidAmerican
      Energy’s service territory, the acquisition by a municipality (by negotiation or
      condemnation) of the Company’s distribution facilities or a negative impact on
      the Company’s current transportation and cost recovery
      arrangements.





The
      Company also conducts its business in conformance with a multitude of federal,
      state and foreign laws, which are subject to significant changes at any time.
      Changes in regulations or the imposition of additional regulations by any of
      these entities or new legislation could have a material adverse impact on the
      Company’s results of operations. For example, such changes could result in
      increased retail competition in MidAmerican Energy’s service territory,
      encouragement of investments in renewable or lower-emission generation, the
      acquisition by a municipality or other quasi-governmental body of MidAmerican
      Energy’s distribution facilities (by negotiation, legislation or condemnation)
      or a negative impact on MidAmerican Energy’s current transportation and cost
      recovery arrangements.





On
      August 8, 2005, the Energy Policy Act was signed into law. That law
      potentially impacts many segments of the energy industry. The law will result
      in
      the FERC issuing new regulations and regulatory decisions in areas such as
      electric system reliability, electric transmission expansion and pricing,
      regulation of utility holding companies, and enforcement authority. 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 PUHCA 1935, and enacted PUHCA 2005, effective February 8,
      2006. PUHCA 1935 extensively regulated and restricted the activities of
      registered public utility holding companies and their subsidiaries. PUHCA 2005
      and the rules issued by the FERC to implement PUHCA 2005 require, among other
      things, public utility holding companies to permit access by the FERC to the
      books and records of the holding company and its affiliates transacting business
      with the public utility, unless such requirement is exempted or waived, and
      to
      comply with the FERC’s record retention requirements.





In
      addition, as a result of past events affecting electric reliability, the Energy
      Policy Act requires federal agencies, working together with non-governmental
      organizations charged with electric reliability responsibilities, to adopt
      and
      implement measures designed to ensure the reliability of electric transmission
      and distribution systems. The implementation of such measures could result
      in
      the imposition of more comprehensive or stringent requirements on MEHC or its
      subsidiaries or other industry participants, which would result in increased
      compliance costs and could have a material adverse effect on the Company’s
      business, financial condition, results of operations and ability to service
      its
      obligations.





32


*The
      Company is subject to environmental, health, safety and other laws and
      regulations which may adversely impact the Company.*





Through
      MEHC’s subsidiaries and joint ventures, it is subject to a number of
      environmental, health, safety and other laws and regulations affecting many
      aspects of the Company’s present and future operations, both domestic and
      foreign, including air emissions, water quality, wastewater discharges, solid
      wastes, hazardous substances and safety matters. The Company may incur
      substantial costs and liabilities in connection with its operations as a result
      of these regulations. In particular, the cost of future compliance with federal,
      state and local clean air laws, such as those that require certain generators,
      including some of MEHC’s subsidiaries’ electric generating facilities, to limit
      nitrogen oxide emissions, sulfur dioxide, carbon dioxide, mercury emissions
      and
      other potential pollutants or emissions, may require the Company to make
      significant capital expenditures which may not be recoverable through future
      rates. In addition, these costs and liabilities may include those relating
      to
      claims for damages to property and persons resulting from the Company’s
      operations. The implementation of regulatory changes imposing more comprehensive
      or stringent requirements on the Company, to the extent such changes would
      result in increased compliance costs or additional operating restrictions,
      could
      have a material adverse effect on the Company’s business, financial condition,
      results of operations and ability to service its obligations.





In
      addition, regulatory compliance for existing facilities and the construction
      of
      new facilities is a costly and time-consuming process, and intricate and rapidly
      changing environmental regulations may require major expenditures for permitting
      and create the risk of expensive delays or material impairment of value if
      projects cannot function as planned due to changing regulatory requirements
      or
      local opposition.





PSIA
      and
      its implementing rules that became effective on February 14, 2004, require
      interstate pipeline operators to develop comprehensive integrity management
      programs, take measures to protect pipeline segments located in
‘‘high-consequence areas’’ and provide ongoing mitigation and monitoring. The
      Company believes its pipeline operations currently comply in all material
      respects with PSIA and related rules. However, in the future, the Company may
      incur unexpected capital costs and/or operating costs in order to maintain
      compliance. Moreover, regulatory agencies and the public continue to focus
      on
      pipeline safety issues which may result in additional inspection, monitoring,
      testing, reporting and other requirements being implemented in the future that
      could increase the Company’s operating costs and/or capital costs. The Company’s
      FERC-approved tariffs or competition from other energy sources may not allow
      the
      Company to recover these increased costs of compliance.





In
      addition to operational standards, environmental laws also impose obligations
      to
      clean up or remediate contaminated properties or to pay for the cost of such
      remediation, often upon parties that did not actually cause the contamination.
      Accordingly, the Company may become liable, either contractually or by operation
      of law, for remediation costs even if the contaminated property is not presently
      owned or operated by the Company, or if the contamination was caused by third
      parties during or prior to the Company’s ownership or operation of the property.
      Given the nature of the past industrial operations conducted by the Company
      and
      others at its properties, there can be no assurance that all potential instances
      of soil or groundwater contamination have been identified, even for those
      properties where an environmental site assessment or other investigation has
      been conducted. Although the Company has accrued reserves for its known
      remediation liabilities, 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 which may
      be
      material. Any failure to recover increased environmental, health or safety
      costs
      incurred by the Company may have a material adverse effect on the Company’s
      business, financial condition, results of operations and ability to service
      its
      obligations.





*One
      of MEHC’s indirect wholly owned subsidiaries, MidAmerican Energy, is subject to
      the unique risks associated with nuclear generation.*




Regulatory
        requirements applicable in the future to nuclear generating facilities could
        adversely affect the results of operations of MEHC and, in particular,
        MidAmerican Energy. The Company is subject to certain generic risks associated
        with utility nuclear generation, which include the following:
 
 Ÿ
              the
                  potential harmful effects on the environment and human health resulting
                  from the operation of nuclear facilities and the storage, handling
                  and
                  disposal of high-level and low-level radioactive
                  materials;Ÿ
              limitations
                  on the amounts and types of insurance commercially available in
                  respect of
                  losses that might arise in connection with nuclear operations;
                  andŸ
              uncertainties
                  with respect to the technological and financial aspects of decommissioning
                  nuclear plants at the end of their licensed
                  lives.


33


The
      NRC
      has broad authority under federal law to impose licensing and safety-related
      requirements for the operation of nuclear generating facilities. In the event
      of
      noncompliance, the NRC has the authority to impose fines or shut down a unit,
      or
      both, depending upon its assessment of the severity of the situation, until
      compliance is achieved. Revised safety requirements promulgated by the NRC
      have,
      in the past, necessitated substantial capital expenditures at nuclear plants,
      including the facility in which MidAmerican Energy has an ownership interest,
      and additional expenditures could be required in the future. In addition,
      although the Company has no reason to anticipate a serious nuclear incident
      at
      the facility in which MidAmerican Energy has an interest, if an incident did
      occur, it could have a material but presently undeterminable adverse effect
      on
      the Company’s financial position, results of operations and ability to service
      its obligations.





*Increased
      competition resulting from legislative, regulatory and restructuring efforts
      could have a significant financial impact on the Company and its utility
      subsidiaries and consequently decrease the Company’s revenue.*





The
      wholesale generation segment of the electric industry has been and will continue
      to be significantly impacted by competition. Competition in the wholesale market
      has resulted in a proliferation of power marketers and a substantial increase
      in
      market activity. Many of these marketers have experienced financial difficulties
      and the market continues to be volatile. Margins from wholesale electric
      transactions have a material impact on the Company’s results of operations.
      Accordingly, significant changes in the wholesale electric markets could have
      a
      material adverse effect on the Company’s financial position, results of
      operations and the ability to service its obligations.





As
      a
      result of FERC orders, including Order 636, the FERC’s policies favoring
      competition in natural gas markets, the expansion of existing pipelines and
      the
      construction of new pipelines, the interstate pipeline industry has experienced
      some failure to renew, or turn back, of firm capacity, as existing
      transportation service agreements expire and are terminated. LDCs and end-use
      customers have more choices in the new, more competitive environment and may
      be
      able to obtain service from more than one pipeline to fulfill their natural
      gas
      delivery requirements. If a pipeline experiences capacity turn back and is
      unable to remarket the capacity, the pipeline or its remaining customers may
      have to bear the costs associated with the capacity that is turned back. Any
      new
      pipelines that are constructed could compete with the Company’s pipeline
      subsidiaries for customers’ service needs. Increased competition could reduce
      the volumes of gas transported by the Company’s pipeline subsidiaries or, in
      cases where they do not have long-term fixed rate contracts, could force the
      Company’s pipeline subsidiaries to lower their rates to meet competition. This
      could adversely affect the Company’s pipeline subsidiaries’ financial
      results.





*A
      significant decrease in demand for natural gas in the markets served by the
      Company’s subsidiaries’ pipeline and distribution systems would significantly
      decrease the Company’s revenue and thereby adversely affect the Company’s
      business, financial condition, results of operations and ability to service
      its
      obligations.*





A
      sustained decrease in demand for natural gas in the markets served by the
      Company’s subsidiaries’ pipeline and distribution systems would significantly
      reduce the Company’s revenues and adversely affect the Company’s ability to
      service its obligations. Factors that could lead to a decrease in market demand
      include:




Ÿ
              a
                  recession or other adverse economic condition that results in a
                  lower
                  level of economic activity or reduced spending by consumers on
                  natural
                  gas;Ÿ
              an
                  increase in the market price of natural gas or a decrease in the
                  price of
                  other competing forms of energy, including electricity, coal and
                  fuel
                  oil;Ÿ
              higher
                  fuel taxes or other governmental or regulatory actions that increase,
                  directly or indirectly, the cost of natural gas or that limit the
                  use of
                  natural gas;Ÿ
              a
                  shift by consumers to more fuel-efficient or alternative fuel machinery
                  or
                  an improvement in fuel economy, whether as a result of technological
                  advances by manufacturers, pending legislation proposing to mandate
                  higher
                  fuel economy, or otherwise; andŸ
              a
                  shift by the Company’s pipeline and distribution customers to the use of
                  alternate fuels, such as fuel oil, due to price differentials or
                  other
                  incentives.


34


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





MEHC’s
      subsidiary, HomeServices, has experienced strong revenue growth and increases
      in
      net income in each of the years ended December 31, 2005, 2004 and 2003. 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 which are beyond HomeServices’
control. Any of the following 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 revenues and profitability:





·
            rising
                interest rates or unemployment
                rates;


·
            periods
                of economic slowdown or recession in the markets
                served;


·
            decreasing
                home
                affordability; and


·
            declining
                demand for residential real estate as an
                investment.





*Failure
      of the Company’s significant power purchasers, pipeline customers and British
      retail suppliers to pay amounts due under their contracts or other commitments
      could reduce the Company’s revenues materially.*





MEHC’s
      subsidiaries’ non-utility generating facilities and both of the Company’s
      pipeline subsidiaries are dependent upon a relatively small number of customers
      for a significant portion of their revenues. In addition, the Company’s utility
      distribution businesses in Great Britain are dependent upon a relatively small
      number of retail suppliers, including one retail supplier who represents
      approximately 44% of the total revenues of our utility distribution businesses
      in Great Britain. As a result, the Company’s profitability and ability to make
      payments under its obligations generally will depend in part upon the continued
      financial performance and creditworthiness of these customers. Accordingly,
      failure of one or more of the Company’s most significant customers to pay for
      contracted electric generating capacity, pipeline capacity reservation charges
      or distribution system use charges, as applicable, for reasons related to
      financial distress or otherwise, could reduce the Company’s revenues materially
      if the Company is not able to make adequate alternate arrangements on a timely
      basis, such as adequate replacement contracts. The replacement of any of the
      Company’s existing long-term contracts or British retail suppliers, should it
      become necessary, will depend on a number of factors beyond the Company’s
      control, including:





·
            the
                availability of economically deliverable natural gas for transport
                through
                the Company’s pipeline system, including in particular continued
                availability of adequate supplies from the Rocky Mountains, Hugoton,
                Permian, Anadarko and Western Canadian supply basins currently accessible
                to the Company’s pipeline
                subsidiaries;


·
            existing
                competition to deliver natural gas to the upper Midwest and southern
                California;


·
            new
                pipelines or expansions potentially serving the same markets as the
                Company’s pipelines;


·
            the
                growth in demand for natural gas in the upper Midwest, southern
                California, Nevada and Utah;


·
            whether
                transportation of natural gas pursuant to long-term contracts continues
                to
                be market practice;


·
            the
                actions of regulators, including the electricity regulator in Great
                Britain;


·
            the
                availability and financial condition of replacement British retail
                suppliers; and


·
            whether
                the Company’s business strategy, including its expansion strategy,
                continues to be successful.





Any
      failure to replace a significant portion of these contracts on adequate terms
      or
      to make other adequate alternate arrangements, should it become necessary,
      may
      have a material adverse effect on the Company’s business, financial condition,
      results of operations and ability to service its obligations.





*The
      Company’s utility and non-utility energy businesses are subject to power and
      fuel price fluctuations, other weather risks, commodity price risks and credit
      risks that could adversely affect the Company’s results of
      operations.*





The
      Company is exposed to commodity price risks, energy transmission price risks
      and
      credit risks in MEHC’s subsidiaries’ generation, retail distribution and
      pipeline operations. Specifically, such possible risks include commodity price
      changes, market supply shortages, interest rate changes and counterparty
      defaults, all of which could have an adverse effect on the Company’s financial
      condition, results of operations and ability to service its obligations. In
      addition, the sale of electric power and natural gas is generally a seasonal
      business, which seasonality results in competitive price fluctuations. The
      Company’s revenues are negatively impacted by low commodity prices resulting
      from low demand for electricity. Demand for electricity often peaks during
      the
      hottest summer months and coldest winter months and declines during the other
      months. As a result of these variations in demand and resulting price
      fluctuations, the Company’s overall operating results in the future may
      fluctuate substantially on a seasonal basis. The Company has historically earned
      less income when weather conditions are milder. The Company expects that
      unusually mild weather in the future could decrease its revenues and provide
      the
      Company with fewer funds available to service its obligations.





35


Also,
      in
      Iowa, MidAmerican Energy does not have an ability to pass through fuel price
      increases in its rates (an energy adjustment clause), so any significant
      increase in fuel costs or purchased power costs for electricity generation
      could
      have a negative impact on MidAmerican Energy, despite the Company’s efforts to
      minimize this negative impact through the use of hedging instruments. The impact
      of these risks could result in MidAmerican Energy’s inability to fulfill
      contractual obligations, significantly higher energy or fuel costs relative
      to
      corresponding sales contracts or increased interest expense. Any of these
      consequences could decrease the Company’s net cash flow and impair its ability
      to make payments on its obligations.





*The
      Company has significant operations outside the United States which may be
      subject to increased risk because of the economic or political conditions of
      the
      country in which they operate.*





The
      Company has a number of operations outside of the United States. The
      acquisition, ownership and operation of businesses outside the United States
      entails significant political and financial risks (including, without
      limitation, uncertainties associated with privatization efforts, inflation,
      currency exchange rate fluctuations, currency repatriation restrictions, changes
      in law or regulation, changes in government policy, political instability,
      civil
      unrest and expropriation) and other risk/structuring issues that have the
      potential to cause material impairment of the value of the business being
      operated, which the Company may not be capable of fully insuring against. The
      risk of doing business outside of the United States could be greater than in
      the
      United States because of specific economic or political conditions of each
      country. The uncertainty of the legal environment in certain foreign countries
      in which the Company operates or may acquire projects or businesses could make
      it more difficult for the Company to enforce its rights under agreements
      relating to such projects or businesses. The Company’s international projects
      may be subject to the risk of being delayed, suspended or terminated by the
      applicable foreign governments or may be subject to the risk of contract
      abrogation, expropriations or other uncertainties resulting from changes in
      government policy or personnel or changes in general political or economic
      conditions affecting the country or otherwise. In addition, the laws and
      regulations of certain countries may limit the Company’s ability to hold a
      majority interest in some of the projects or businesses that it may acquire.
      Furthermore, the central bank of any such country may have the authority in
      certain circumstances to suspend, restrict or otherwise impose conditions on
      foreign exchange transactions or to restrict distributions to foreign investors.
      Although the Company may structure certain project revenue and other agreements
      to provide for payments to be made in, or indexed to, U.S. dollars or a currency
      freely convertible into U.S. dollars, there can be no assurance that the Company
      will be able to obtain sufficient U.S. dollars or other hard currency or that
      available U.S. dollars will be allocated to pay such obligations.





*The
      Company faces exchange rate risk.*





Payments
      from some of the Company’s foreign investments, including without limitation CE
      Electric UK, are made in a foreign currency and any dividends or distributions
      of earnings in respect of such investments may be significantly affected by
      fluctuations in the exchange rate between the U.S. dollar and the sterling
      or
      other applicable foreign currency, which could adversely affect the Company’s
      financial condition and results of operations. Although the Company may enter
      into certain transactions to hedge risks associated with exchange rate
      fluctuations, there can be no assurance that such transactions will be
      successful in reducing such risks.




**Item 1B. Unresolved
      Staff Comments.**





Not
      applicable.




**Item
      2.     Properties.**





The
      Company’s utility properties consist of physical assets necessary and
      appropriate to render electric and gas service in its service territories.
      Electric property consists primarily of generation, transmission and
      distribution facilities and related rights-of-way. Gas property consists
      primarily of distribution plants, natural gas pipelines, related rights-of-way,
      compressor stations and meter stations. It is the opinion of management that
      the
      principal depreciable properties owned by the Company are in good operating
      condition and well maintained. Pursuant to separate financing agreements,
      substantially all or most of the properties of each subsidiary (except CE
      Electric UK and Northern Natural Gas) are pledged or encumbered to support
      or
      otherwise provide the security for their own project or subsidiary debt. Refer
      to Item 1. Business and Note 4 and Note 22 of Notes to Consolidated Financial
      Statements included in Item 8. Financial Statements and Supplementary Data
      of
      this Form 10-K for additional information about the Company’s
      properties.


36


The
      right
      to construct and operate the pipelines across certain property was obtained
      through negotiations and through the exercise of the power of eminent domain,
      where necessary. Kern River and Northern Natural Gas continue to have the power
      of eminent domain in each of the states in which they operate their respective
      pipelines, but they 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 are located within a utility corridor
      that is reserved to the United States Department of Interior, Bureau of Land
      Management.





With
      respect to real property, each of the pipelines falls into two basic categories:
      (1) parcels that are owned in fee, such as certain of the compressor stations,
      measurement stations and district 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 pipelines. MEHC believes that
      Kern River and Northern Natural Gas each have satisfactory title to all of
      the
      real property making up their respective pipelines in all material
      respects.





**Item
      3.** **Legal
      Proceedings.**





In
      addition to the proceedings described below, the Company is currently party
      to
      various items of litigation or arbitration in the normal course of business,
      none of which are reasonably expected by the Company to have a material adverse
      effect on its financial position, results of operations or cash flows. See
      Item
      1. Business and Item 8. Financial Statements and Supplementary Data of this
      Form
      10-K for details relative to environmental matters affecting the
      Company.





**Pipeline
      Litigation**





In
      1998,
      the United States Department of Justice informed the then current owners of
      Kern
      River and Northern Natural Gas that Jack Grynberg, an individual, had filed
      claims in the United States District Court for the District of Colorado under
      the False Claims Act against such entities and certain of their subsidiaries
      including Kern River and Northern Natural Gas. Mr. Grynberg has also filed
      claims against numerous other energy companies and alleges that the defendants
      violated the False Claims Act in connection with the measurement and purchase
      of
      hydrocarbons. The relief sought is an unspecified amount of royalties allegedly
      not paid to the federal government, treble damages, civil penalties, attorneys’
fees and costs. On April 9, 1999, the United States Department of Justice
      announced that it declined to intervene in any of the Grynberg qui tam cases,
      including the actions filed against Kern River and Northern Natural Gas in
      the
      United States District Court for the District of Colorado. On October 21,
      1999, the Panel on Multi-District Litigation transferred the Grynberg qui tam
      cases, including the ones filed against Kern River and Northern Natural Gas,
      to
      the United States District Court for the District of Wyoming for pre-trial
      purposes. On October 9, 2002, the United States District Court for the
      District of Wyoming dismissed Grynberg’s royalty valuation claims. On
      November 19, 2002, the United States District Court for the District of
      Wyoming denied Grynberg’s motion for clarification and dismissed his royalty
      valuation claims. Grynberg appealed this dismissal to the United States Court
      of
      Appeals for the Tenth Circuit and on May 13, 2003, the Tenth Circuit Court
      dismissed his appeal. On May 17, 2005, Kern River and Northern Natural Gas
      each received a Special Master’s Report and Recommendations in which the Special
      Master recommended that the action against Kern River and Northern Natural
      Gas
      be dismissed for lack of subject matter jurisdiction. Grynberg and the
      coordinated defendants each filed motions relating to the Special Master’s
      Report and Recommendations on June 27, 2005. Oral arguments on the parties’
motions were held on December 9, 2005, and the parties are awaiting a
      ruling from the court regarding this report. In connection with the purchase
      of
      Kern River from The Williams Companies, Inc. (“Williams”) in March 2002,
      Williams agreed to indemnify MEHC against any liability for this claim; however,
      no assurance can be given as to the ability of Williams to perform on this
      indemnity should it become necessary. No such indemnification was obtained
      in
      connection with the purchase of Northern Natural Gas in August 2002. The Company
      believes that the Grynberg cases filed against Kern River and Northern Natural
      Gas are without merit and that Williams, on behalf of Kern River pursuant to
      its
      indemnification, and Northern Natural Gas, intend to defend these actions
      vigorously.





On
      June 8, 2001, a number of interstate pipeline companies, including Kern
      River and Northern Natural Gas, were named as defendants in a nationwide class
      action lawsuit which had been pending in the 26th Judicial District, District
      Court, Stevens County Kansas, Civil Department against other defendants,
      generally pipeline and gathering companies, since May 20, 1999. The
      plaintiffs allege that the defendants have engaged in mismeasurement techniques
      that distort the heating content of natural gas, resulting in an alleged
      underpayment of royalties to the class of producer plaintiffs. On May 12,
      2003, the plaintiffs filed a motion for leave to file a fourth amended petition
      alleging a class of gas royalty owners in Kansas, Colorado and Wyoming. The
      court granted the motion for leave to amend on July 28, 2003. Kern River
      was not a named defendant in the amended complaint and has been dismissed from
      the action. Northern Natural Gas filed an answer to the fourth amended petition
      on August 22, 2003. On January 4, 2005, the plaintiffs filed their
      class certification motion and brief in support of that motion. Northern Natural
      Gas filed its joint brief and expert affidavits in opposition to class
      certification on February 22, 2005. The plaintiffs filed their reply brief
      in support of class certification on March 18, 2005. Northern Natural Gas
      believes that this claim is without merit.





37


Similar
      to the June 8, 2001 matter referenced above, the plaintiffs in that matter
      have filed a new companion action against a number of parties, including
      Northern Natural Gas but excluding Kern River, in a Kansas state district court
      for damages for mismeasurement of British thermal unit content, resulting in
      lower royalties. The action was filed on May 12, 2003. On January 4,
      2005, the plaintiffs filed their class certification motion and brief in support
      of that motion. Northern Natural Gas filed its joint brief and expert affidavits
      in opposition to class certification on February 22, 2005. The plaintiffs
      filed their reply brief in support of class certification on March 18,
      2005. Northern Natural Gas believes that this claim is without
      merit.





**MidAmerican
      Energy**





*Natural
      Gas Commodity Litigation*





MidAmerican
      Energy is one of dozens of companies named as defendants in a January 20,
      2004 consolidated class action lawsuit filed in the United States District
      Court
      for the Southern District of New York. The suit alleges that the defendants
      have
      engaged in unlawful manipulation of the prices of natural gas futures and
      options contracts traded on the New York Mercantile Exchange (“NYMEX”) during
      the period January 1, 2000 to December 31, 2002. MidAmerican Energy is
      mentioned as a company that has engaged in wash trades on Enron Online (an
      electronic trading platform) that had the effect of distorting prices for gas
      trades on the NYMEX. The plaintiffs to the class action do not specify the
      amount of alleged damages. On September 9, 2005, MidAmerican Energy and
      counsel for the plaintiffs executed a stipulation and agreement of settlement,
      which, upon final approval by the court following notice to all class members,
      MidAmerican Energy will be dismissed from the lawsuit. The settlement was filed
      with the court on February 2, 2006 and approved by the court on a
      preliminary basis on February 8, 2006. If finally accepted by the court,
      the settlement will not have a material impact upon MidAmerican Energy.
      Additionally, the court issued an order on September 29, 2005, granting the
      plaintiffs’ motion for class certification.





*Other*





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 allegedly
      provided gas service in Ramsey, Minnesota at the time of the original
      installation of the pipeline in 1980. In 1993, a predecessor of CenterPoint
      Resources Corp. (“CenterPoint”) acquired all of the Minnesota gas properties
      owned by the MidAmerican Energy predecessor company.





As
      a
      result of the explosion and fire, MidAmerican Energy and CenterPoint have
      received settlement demands which total $15.5 million. MidAmerican Energy’s
      exposure, if any, to these demands are covered under its liability insurance
      coverage to which a $2.0 million retention applies. In addition, counsel
      for CenterPoint stated that a replacement program has been initiated for the
      purpose of locating and replacing all mechanical couplings in the former North
      Central Public Service Company properties located in Minnesota. Counsel for
      CenterPoint has represented that it is anticipated that the value of the
      replacement claim may be in the range of $35-$45 million.





On
      February 8, 2006, MidAmerican Energy was served with a Third Party
      Complaint filed in U.S. District Court, District of Minnesota by CenterPoint.
      The Third Party Complaint seeks contribution and indemnity on a wrongful death
      claim filed by the estate of one of the decedents and all sums associated with
      CenterPoint’s replacement program. An additional compliant filed by the estate
      of one of the decedents seeks damages from MEHC and other defendants, including
      CenterPoint, on a wrongful death claim arising from this incident. MEHC and
      MidAmerican Energy intend to vigorously defend their position in these claims
      and believe their ultimate outcome will not have a material impact on their
      results of operations, financial position or cash flows.





38


**Philippines**





Pursuant
      to the share ownership adjustment mechanism in the CE Casecnan stockholder
      agreement, which is based upon pro forma financial projections of the Casecnan
      Project prepared following commencement of commercial operations, in February
      2002, MEHC’s indirect wholly-owned subsidiary, CE Casecnan Ltd., advised the
      minority stockholder 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., KEIL Casecnan Ltd. (“KE”), a former stockholder, 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. On January 21, 2004, CE Casecnan
      Ltd., LPG and CE Casecnan entered into a status quo agreement pursuant to which
      the parties agreed to set aside certain distributions related to the shares
      subject to the LPG dispute and CE Casecnan agreed not to take any further
      actions with respect to such distributions without at least 15 days prior notice
      to LPG. Accordingly, 15% of the CE Casecnan dividend distributions declared
      in
      2004 and 2005, totaling $17.6 million, was set aside in a separate bank
      account in the name of CE Casecnan and is shown as restricted cash and
      short-term investments and other current liabilities in the accompanying
      consolidated balance sheets included in Item 8. Financial Statements and
      Supplementary Data of this Form 10-K.





On
      August 4, 2005, the court issued a decision, ruling in favor of LPG on five
      of the eight disputed issues in the first phase of the litigation. On
      September 12, 2005, LPG filed a motion seeking the release of the funds
      which have been set aside pursuant to the status quo agreement referred to
      above. MEHC and CE Casecnan Ltd. filed an opposition to the motion on October
      3,
      2005, and at the hearing on October 26, 2005, the court denied LPG’s
      motion. On January 3, 2006, the court entered a judgment in favor of LPG
      against CE Casecnan Ltd. and KE. According to the judgment LPG would retain
      its
      ownership of 15% of the shares of CE Casecnan and distributions of the amounts
      deposited into escrow plus interest at 9% per annum. On February 28, 2006,
      CE Casecnan Ltd. and KE filed an appeal of this judgment and the August 4,
      2005 decision. The appeal is expected to be resolved sometime in 2007. The
      impact, if any, of this litigation on the Company cannot be determined at this
      time.





In
      February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. (“San
      Lorenzo”), an original shareholder substantially all of whose shares in CE
      Casecnan were purchased by MEHC in 1998, threatened to initiate legal action
      against the Company in the Philippines in connection with certain aspects of
      its
      option to repurchase such shares. 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.
      The motion was heard on October 21, 2005, and the court took the matter
      under advisement. 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
      Casecnan, that it is the rightful owner of such shares, and that it is due
      all
      dividends paid on such shares. 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.





**Mirant
      Americas Energy Marketing (“Mirant”) Claim**





Mirant
      was one of the shippers that entered into a 15-year, 2003 Expansion Project,
      firm gas transportation contract (90,000 Dth per day) 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 and Kern River subsequently
      drew on the letter of credit and held the proceeds thereof, $14.8 million,
      as cash collateral. Kern River claimed $210.2 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 $74.4 million
      in addition to the $14.8 million cash collateral. In January 2006, Mirant
      emerged from bankruptcy and on February 6, 2006, a stipulated judgment was
      entered that allowed Kern River to receive a pro rata amount of shares of new
      Mirant stock determined by Kern River’s allowed claim amount plus interest in
      relation to the unsecured creditor class of over $6 billion. On
      February 10, 2006, Kern River received an initial distribution of such
      shares in payment of the majority of its allowed claim.




**Item
        4.** **Submission
        of Matters to a Vote of Security
        Holders.**
 
 Not
        applicable.


39


**PART
      II**





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





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





**Item
      6.** **Selected
      Financial Data.**





The
      following table sets forth selected financial data, which should be read in
      conjunction with Item 7. Management’s Discussion and Analysis of Financial
      Condition and Results of Operations and with the Company’s consolidated
      financial statements and the related notes to those statements included in
      Item
      8. Financial Statements and Supplementary Data appearing elsewhere in this
      Form
      10-K. The selected financial data has been derived from the Company’s historical
      consolidated financial statements.





**Year
                Ended December 31,****2005**
            
            **2004**
            
            **2003**
            
            **2002****(1)**
            
            **2001****Statement
                of Operations Data:**Operating
                revenue
            
            $
            7,115.5
            
            $
            6,553.4
            
            $
            5,965.6
            
            $
            4,795.2
            
            $
            4,696.8Income
                from continuing operations
            
            
            557.5
            
            
            537.8
            
            
            442.7
            
            
            397.4
            
            
            148.4Income
                (loss) from discontinued operations, net of tax(2)
            
            
            5.1
            
            
            (367.6
            )
            
            (27.1
            )
            
            (17.4
            )
            
            (5.7
            )Net
                income
            
            $
            562.6
            
            $
            170.2
            
            $
            415.6
            
            $
            380.0
            
            $
            142.7**As
                of****December 31,****2005**
            
            
            **2004**
            
            
            **2003**
            
            
            **2002****(1)**
            
            
            **2001****Balance
                Sheet Data:**Total
                assets
            
            $
            20,193.0
            
            $
            19,903.6
            
            $
            19,145.0
            
            $
            18,434.9
            
            $
            12,994.6Parent
                company senior debt(3)
            
            
            2,776.2
            
            
            2,772.0
            
            
            2,777.9
            
            
            2,323.4
            
            
            1,834.5Parent
                company subordinated debt(3)
            
            
            1,354.1
            
            
            1,585.8
            
            
            1,772.1
            
            
            -
            
            
            -Company-obligated
                mandatory redeemable preferred securities of subsidiary
                trusts
            
            
            -
            
            
            -
            
            
            -
            
            
            2,063.4
            
            
            788.2Subsidiary
                and project debt(3)
            
            
            6,836.6
            
            
            6,304.9
            
            
            6,674.6
            
            
            7,077.1
            
            
            4,754.8Subsidiary-obligated
                mandatorily redeemable preferred securities of subsidiary
                trusts
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            100.0Preferred
                securities of subsidiaries
            
            
            88.4
            
            
            89.5
            
            
            92.1
            
            
            93.3
            
            
            121.2Total
                stockholders’ equity
            
            $
            3,385.3
            
            $
            2,971.2
            
            $
            2,771.4
            
            $
            2,294.3
            
            $
            1,708.2





(1)
            Reflects
                the acquisitions of Kern River on March 27, 2002 and Northern Natural
                Gas on August 16, 2002.(2)
            Reflects
                MEHC’s decision to cease operations of the Zinc Recovery Project effective
                September 10, 2004, which resulted in a non-cash, after-tax
                impairment charge of $340.3 million being recorded to write-off the
                Zinc Recovery Project, rights to quantities of extractable minerals,
                and
                allocated goodwill (collectively, the “Mineral Assets”). The charge and
                related activity of the Mineral Assets, including the reclassification
                of
                such activity for the years ended December 31, 2003, 2002 and 2001,
                are classified separately as discontinued operations.(3)
            Excludes
                current portion.


40


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





The
      following discussion and analysis should be read in combination with the
      selected financial data and the consolidated financial statements included
      in
      Item 6. Selected Financial Data and Item 8. Financial Statements and
      Supplementary Data of this Form 10-K.





**Executive
      Summary**





MEHC,
      through its subsidiaries, owns and operates a combined electric and natural
      gas
      utility company in the United States, two natural gas interstate pipeline
      companies in the United States, two electricity distribution companies in Great
      Britain, a diversified portfolio of domestic and international independent
      power
      projects and the second largest residential real estate brokerage firm in the
      United States. These businesses are organized and managed as seven distinct
      platforms: MidAmerican Energy, Kern River, Northern Natural Gas, CE Electric
      UK
      (which includes Northern Electric and Yorkshire Electricity), CalEnergy
      Generation-Foreign, CalEnergy Generation-Domestic, and
      HomeServices.





MEHC’s
      energy subsidiaries generate, transmit, store, distribute and supply energy.
      MEHC’s electric and natural gas utility subsidiaries currently serve
      approximately 4.4 million electricity customers and approximately 688,000
      natural gas customers. MEHC's natural gas pipeline subsidiaries operate
      interstate natural gas transmission systems that have approximately 18,100
      miles
      of pipeline in operation, a peak delivery capacity of 6.6 Bcf of natural gas
      per
      day and transported approximately 7.8% of the total natural gas consumed in
      the
      United States in 2005. The Company has interests in 6,740 net owned MW of power
      generation facilities in operation and under construction, including 5,166
      net
      owned MW in facilities that are part of the regulated asset base of its electric
      utility business and 1,574 net owned MW in non-utility power generation
      facilities. Substantially all of the non-utility power generation facilities
      have long-term contracts for the sale of energy and/or capacity from the
      facilities.





The
      following significant events occurred during the years ended December 31,
      2005, 2004 and 2003, respectively, as discussed in more detail herein and in
      Item 1. Business of this Form 10-K, that highlight some of the factors which
      affected, or may affect in the future, the Company’s financial condition,
      results of operations and liquidity:





·
            In
                May 2005, MEHC reached a definitive agreement with ScottishPower and
                its subsidiary, PacifiCorp Holdings, Inc., to acquire 100% of the
                common
                stock of ScottishPower’s wholly-owned indirect subsidiary, PacifiCorp, a
                regulated electric utility, for approximately $5.1 billion in cash.
                Subject to the most favored states process and other customary closing
                conditions, the transaction is expected to close in March 2006. MEHC
                expects to fund the acquisition of PacifiCorp with the proceeds from
                an
                investment by Berkshire Hathaway and other existing shareholders
                of
                approximately $3.4 billion in MEHC common stock and the issuance by
                MEHC of $1.7 billion of either additional common stock to Berkshire
                Hathaway or long-term senior notes to third parties. According to
                PacifiCorp’s most recent Form 10-Q filed with the SEC, PacifiCorp had
                total assets of $12.8 billion as of December 31, 2005, and had
                $2.7 billion of operating revenue and $213.6 million of net
                income, respectively, for the nine months ended December 31,
                2005.





·
            On
                February 9, 2006, following the effective date of the repeal of PUHCA
                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. As a consequence, Berkshire Hathaway owns 83.4%
                (80.5% on a diluted basis) of the outstanding common stock of MEHC,
                will
                consolidate the Company in its financial statements as a majority-owned
                subsidiary, and will include the Company in its consolidated federal
                U.S.
                income tax return.




·
            On
                March 1, 2006, MEHC and Berkshire Hathaway entered into 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, and will not be used for the PacifiCorp
                acquisition or for other future
                acquisitions.


41




·
            MidAmerican
                Energy has continued its construction of electric generation facilities
                in
                Iowa by placing in-service 900.5 MW (nameplate rating) of capacity
                during
                2005, 2004 and 2003. Projects completed include the 540 MW (nameplate
                rating) combined-cycle Greater Des Moines Energy Center in 2003 and
                2004
                and 360.5 MW (nameplate rating) of wind turbines in 2005 and 2004.
                Additionally, MidAmerican Energy is currently constructing CBEC
                Unit 4, a 790 MW (expected accreditation) super-critical-temperature,
                low sulfur coal-fired generating plant of which MidAmerican Energy’s share
                is 479 MW, and has made a filing with the IUB for approval to add
                up to
                545 MW (nameplate rating) of additional wind generation
                capacity.





·
            Kern
                River completed construction of its 2003 Expansion Project in May
                2003 at
                a total cost of $1.2 billion.





·
            Indirect
                wholly-owned subsidiaries of MEHC own the rights to commercial quantities
                of extractable minerals from elements in solution in the geothermal
                brine
                and fluids utilized at the Imperial Valley Projects and a zinc recovery
                plant constructed near the Imperial Valley Projects designed to recover
                zinc from the geothermal brine through an ion exchange, solvent
                extraction, electrowinning and casting process (the “Zinc Recovery
                Project”). On September 10, 2004, management made the decision to
                cease operations of the Zinc Recovery Project. Implementation of
                the
                decommissioning plan began in September 2004 and as of December 31,
                2005, the dismantling, decommissioning, and sale of remaining assets
                of
                the Zinc Recovery Project was
                completed.





·
            MidAmerican
                Energy issued $300.0 million of 5.75%, 30-year, medium-term notes on
                November 1, 2005, and $350.0 million of 4.65%, 10-year,
                medium-term notes on October 1, 2004. The proceeds from each offering
                are being used to support construction of its electric generation
                projects
                and for general corporate purposes.





·
            On
                May 5, 2005, certain subsidiaries of CE Electric UK collectively
                issued £350.0 million of 5.125% senior bonds due 2035. The proceeds
                from the offerings are being invested and used for general corporate
                purposes. Proceeds from the maturing investments will be used to
                repay
                certain long-term debt of subsidiaries of CE Electric UK in 2007
                and 2008.





·
            In
                February 2004, MEHC issued $250.0 million of 5.00% senior notes due
                February 15, 2014. The proceeds were used to satisfy a demand made by
                an affiliate on MEHC’s guarantee of certain debt related to the Zinc
                Recovery Project and for general corporate
                purposes.





·
            Northern
                Natural Gas reached agreement with its customers in June 2005 on
                a FERC
                approved rate settlement covering its consolidated rate case related
                to
                filings for rate increases made with the FERC in May 2003 and January
                2004.





·
            Ofgem
                completed the process of reviewing the existing price control formula
                for
                Northern Electric and Yorkshire Electricity in November 2004. As
                a result
                of the review, the allowed revenue of Northern Electric’s and Yorkshire
                Electricity’s distribution businesses were reduced by 4% and 9%,
                respectively, in real terms, effective April 1,
                2005.





·
            Kern
                River filed for a rate increase with the FERC in April 2004, with
                the new
                rates being effectuated on November 1, 2004, subject to refund. The
                general rate case hearing concluded in August 2005 and Kern River
                is
                awaiting an initial decision on the case. The final resolution of
                the rate
                case is dependent on receiving a final, non-appealable decision on
                the
                case from the FERC, or approval of a settlement of the case by the
                FERC,
                and is not expected at the earliest until late 2006 or early
                2007.





·
            CE
                Casecnan reached an arbitration settlement with the NIA effective
                during
                the fourth quarter of 2003. In exchange for the receipt of approximately
                $18 million of cash and a $97.0 million ROP Note, CE Casecnan
                agreed to modify certain provisions of its project agreement, the
                most
                significant being the elimination of the tax compensation portion
                of the
                water delivery fee and modification of the threshold volume of water
                used
                to calculate the guaranteed water delivery
                fee.





42


**Results
      of Operations**





Summary





Operating
      results for the years ended December 31, 2005, 2004 and 2003 are summarized
      in the following table (in millions):





**Year
                Ended December 31,****2005**
            
            **2004**
            
            **2003**Operating
                revenue
            
            $
            7,115.5
            
            $
            6,553.4
            
            $
            5,965.6Operating
                income
            
            $
            1,528.7
            
            $
            1,525.4
            
            $
            1,449.8Interest
                expense
            
            
            (891.0
            )
            
            (903.2
            )
            
            (761.0
            )Other
                income, net
            
            
            127.2
            
            
            177.0
            
            
            169.2Income
                tax expense
            
            
            (244.7
            )
            
            (265.0
            )
            
            (270.3
            )Minority
                interest and preferred dividends of subsidiaries
            
            
            (16.0
            )
            
            (13.3
            )
            
            (183.2
            )Equity
                income
            
            
            53.3
            
            
            16.9
            
            
            38.2Income
                from continuing operations
            
            
            557.5
            
            
            537.8
            
            
            442.7Income
                (loss) from discontinued operations, net of tax
            
            
            5.1
            
            
            (367.6
            )
            
            (27.1
            )Net
                income available to common and preferred stockholders
            
            $
            562.6
            
            $
            170.2
            
            $
            415.6





In
      2005,
      MEHC’s income from continuing operations was $557.5 million versus
      $537.8 million in 2004. In 2005, MEHC benefited from favorable comparative
      results at most of its domestic businesses and from gains on sales of certain
      non-strategic assets and investments. These improvements were partially offset
      by lower earnings from CE Electric UK, primarily associated with the
      distribution businesses. In the fourth quarter of 2004, MEHC realized an
      after-tax gain of $43.7 million from the realization of certain
      Enron-related bankruptcy claims. Ignoring the effect of this one-time event,
      MEHC’s income from continuing operations was $494.1 million, which, when
      compared to 2003 results, reflects improved results at most of MEHC’s major
      operating platforms.





During
      the third quarter of 2004, the Company recorded an after-tax charge, which
      is
      reflected in discontinued operations, of $340.3 million to write down
      certain assets of the Zinc Recovery Project.





Segment
      Results





The
      reportable segment financial information includes all necessary adjustments
      and
      eliminations needed to conform to the Company’s 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, intersegment eliminations and fair value
      adjustments relating to acquisitions. Additionally, the activity of the
      Company’s Mineral Assets, which was previously reported in the CalEnergy
      Generation-Domestic reportable segment, is presented as discontinued operations
      within the consolidated financial statements included in Item 8. Financial
      Statements and Supplementary Data of this Form 10-K.





43


A
      comparison of operating revenue and operating income for the Company’s
      reportable segments for the years ended December 31, 2005, 2004, and 2003
      follows (in millions):





**Year
                Ended December 31,****2005**
            
            **2004**
            
            **2003****Operating
                revenue:**MidAmerican
                Energy
            
            $
            3,166.1
            
            $
            2,701.7
            
            $
            2,600.2Kern
                River
            
            
            323.6
            
            
            316.1
            
            
            260.2Northern
                Natural Gas
            
            
            569.1
            
            
            544.8
            
            
            486.9CE Electric UK
            
            
            884.1
            
            
            936.4
            
            
            830.0CalEnergy
                Generation-Foreign
            
            
            312.3
            
            
            307.4
            
            
            326.4CalEnergy
                Generation-Domestic
            
            
            33.8
            
            
            39.0
            
            
            45.2HomeServices
            
            
            1,868.5
            
            
            1,756.4
            
            
            1,476.6Total
                reportable segments
            
            
            7,157.5
            
            
            6,601.8
            
            
            6,025.5Corporate/other
            
            
            (42.0
            )
            
            (48.4
            )
            
            (59.9
            )Total
                operating revenue
            
            $
            7,115.5
            
            $
            6,553.4
            
            $
            5,965.6





**Operating
                income:**MidAmerican
                Energy
            
            $
            381.1
            
            $
            355.9
            
            $
            367.9Kern
                River
            
            
            204.5
            
            
            204.8
            
            
            181.0Northern
                Natural Gas
            
            
            208.8
            
            
            190.3
            
            
            175.8CE Electric UK
            
            
            483.9
            
            
            497.4
            
            
            445.8CalEnergy
                Generation-Foreign
            
            
            185.0
            
            
            188.5
            
            
            197.5CalEnergy
                Generation-Domestic
            
            
            15.1
            
            
            21.5
            
            
            21.4HomeServices
            
            
            125.3
            
            
            112.9
            
            
            92.9Total
                reportable segments
            
            
            1,603.7
            
            
            1,571.3
            
            
            1,482.3Corporate/other
            
            
            (75.0
            )
            
            (45.9
            )
            
            (32.5
            )Total
                operating income
            
            $
            1,528.7
            
            $
            1,525.4
            
            $
            1,449.8





*MidAmerican
      Energy*





MidAmerican
      Energy owns a public utility headquartered in Iowa that is principally engaged
      in the business of generating, transmitting, distributing and selling electric
      energy and in distributing, selling and transporting natural gas. Nonregulated
      affiliates within the MidAmerican Energy platform also conduct a number of
      nonregulated business activities. MidAmerican Energy’s operating revenue and
      operating income for the years ended December 31, 2005, 2004, and 2003 are
      summarized as follows (in millions):





**Year
                Ended December 31,****2005**
            
            **2004**
            
            **2003****Operating
                revenue:**Regulated
                electric
            
            $
            1,513.2
            
            $
            1,421.7
            
            $
            1,398.0Regulated
                gas
            
            
            1,322.7
            
            
            1,010.9
            
            
            947.4Nonregulated
            
            
            330.2
            
            
            269.1
            
            
            254.8Total
                operating revenue
            
            $
            3,166.1
            
            $
            2,701.7
            
            $
            2,600.2





**Operating
                income:**Regulated
                electric
            
            $
            334.9
            
            $
            304.4
            
            $
            307.8Regulated
                gas
            
            
            31.7
            
            
            36.4
            
            
            45.9Nonregulated
            
            
            14.5
            
            
            15.1
            
            
            14.2Total
                operating income
            
            $
            381.1
            
            $
            355.9
            
            $
            367.9





44


Regulated
      Electric Operations





The
      operating results of MidAmerican Energy’s regulated electric business for the
      years ended December 31, 2005, 2004, and 2003 are summarized as follows (in
      millions, except for average number of customers):





**Year
                Ended December 31,****2005**
            
            **2004**
            
            **2003**Retail
            
            $
            1,222.0
            
            $
            1,136.7
            
            $
            1,113.2Wholesale
            
            
            291.2
            
            
            285.0
            
            
            284.8Total
                operating revenue
            
            
            1,513.2
            
            
            1,421.7
            
            
            1,398.0Cost
                of fuel, energy and capacity
            
            
            468.1
            
            
            398.6
            
            
            396.3Margin
            
            
            1,045.1
            
            
            1,023.1
            
            
            1,001.7Operating
                expense
            
            
            472.9
            
            
            483.5
            
            
            444.4Depreciation
                and amortization
            
            
            237.3
            
            
            235.2
            
            
            249.5Operating
                income
            
            $
            334.9
            
            $
            304.4
            
            $
            307.8Sales
                (gigawatt-hours):Retail
            
            
            19,044
            
            
            17,865
            
            
            17,422Wholesale
            
            
            8,378
            
            
            9,260
            
            
            9,96327,422
            
            
            27,125
            
            
            27,385Average
                number of customers
            
            
            701,111
            
            
            691,984
            
            
            684,124





MidAmerican
      Energy’s regulated electric retail revenue for 2005 increased
      $85.3 million, or 7.5%, to $1,222.0 million compared to 2004. Electric
      retail sales volumes increased 6.6% compared to 2004. Higher average
      temperatures during 2005 compared to 2004 resulted in a $43.4 million
      increase in electric retail revenue. A growing retail customer base in 2005
      improved electric retail revenue by $17.7 million compared to 2004, while
      electricity usage factors not dependent on weather, such as the size of homes,
      technology changes and the use of multiple appliances, increased electric
      revenue by $9.1 million. Additionally, transmission revenue increased
      $7.9 million.





MidAmerican
      Energy’s regulated electric retail revenue for 2004 increased
      $23.5 million, or 2.1%, to $1,136.7 million compared to 2003, and
      related sales volumes increased 2.5%. Electricity usage factors not dependent
      on
      weather, such as the size of homes, technology changes and the use of multiple
      appliances, improved electric revenue by $21.6 million compared to 2003,
      and an increase in the average number of electric retail customers increased
      electric retail revenue by $20.7 million. Lower average temperatures during
      2004 compared to 2003 resulted in a $26.9 million decrease in electric
      retail revenue.





In
      addition to retail sales, MidAmerican Energy sells electric energy to other
      utilities, marketers and municipalities. These sales are referred to as
      wholesale sales. MidAmerican Energy’s wholesale revenue for 2005 increased
      $6.2 million, or 2.2%, to $291.2 million compared to 2004. The effect of
      higher electric energy prices, offset partially by a higher proportion of
      lower-priced, off-peak sales, increased wholesale energy revenue in 2005 by
      $33.3 million. Wholesale units for 2005 decreased 9.5% from 2004, resulting
      in a $27.1 million decrease in revenue. The primary reason for the decrease
      in
      wholesale sales volumes for 2005 was the timing of planned generation outages
      for the Louisa Generating Station and the loss of generating capacity at the
      Ottumwa Generating Station Unit No. 1 (“OGS Unit No. 1”), which experienced a
      failure of its step-up transformer on February 20, 2005. OGS Unit No. 1
      returned to service on May 3, 2005.





MidAmerican
      Energy’s wholesale revenue for 2004 increased $0.2 million, or 0.1%, to
      $285.0 million compared to 2003. Wholesale energy revenue in 2004 increased
      by
      $20.3 million due to the impact of higher average wholesale prices. This
      was largely offset by a decrease in wholesale units of 7.1% from 2003, which
      resulted in a $20.1 million decrease in revenue.





Cost
      of
      fuel, energy and capacity for 2005 increased $69.5 million, or 17.4%,
      compared to 2004 due principally to the cost of replacement power in connection
      with the generating station outages previously discussed and the increased
      use
      of gas-fired generation, primarily from the Greater Des Moines Energy Center.
      Cost of fuel, energy and capacity for 2004 increased $2.3 million, or 0.6%,
      compared to 2003. The increase was principally due to the cost of replacement
      power as a result of generating stations taken out of service for preventive
      maintenance in 2004.


45


Regulated
      electric operating expense for 2005 decreased $10.6 million compared to
      2004 due principally to the timing of generating plant maintenance and lower
      postretirement benefit costs, partially offset by higher distribution and
      transmission operations costs. Regulated electric operating expense for 2004
      increased $39.1 million compared to 2003 due primarily to the timing of
      generating plant maintenance and increased generating plant operations expense.
      Additionally, electric distribution maintenance and operations expense and
      transmission operations expense were higher in 2004 compared to
      2003.





Regulated
      electric depreciation and amortization expense for 2005 increased
      $2.1 million compared to 2004 as a result of an $11.1 million increase
      in electric utility plant depreciation and amortization due primarily to assets
      being placed in-service, the most significant being the second phase of the
      Greater Des Moines Energy Center and 160.5 MW of wind power facilities in
      December 2004 and, to a lesser extent, an additional 200 MW of wind power
      facilities in late 2005. The increase in utility plant depreciation was
      partially offset by a $9.9 million decrease in regulatory expense pursuant
      to a revenue sharing arrangement with the state of Iowa due to lower Iowa
      electric equity returns. Regulated electric depreciation and amortization
      expense for 2004 decreased $14.3 million compared to 2003 due to a $9.8
      million decrease
      related to the revenue sharing arrangements with the states of Illinois and
      Iowa. Additionally, electric utility plant depreciation and amortization
      decreased due in part to software assets that became fully depreciated in
      2003.





Regulated
      Natural Gas Operations





Regulated
      natural gas revenue includes purchased gas adjustment clauses through which
      MidAmerican Energy is allowed to recover the cost of gas sold from its retail
      gas utility customers. Consequently, fluctuations in the cost of gas sold do
      not
      affect gross margin or operating income because revenues reflect comparable
      fluctuations through the purchased gas adjustment clauses. Compared to 2004,
      MidAmerican Energy’s average per-unit cost of gas sold increased 32.8%,
      resulting in a $271.6 million increase in revenue and cost of gas sold for
      2005. The remainder of the increase in cost of gas sold and gas revenues was
      primarily due to an increase in wholesale sales volumes. Additionally, an
      increase in the average number of retail customers contributed to the increase
      in gas revenues for 2005.





MidAmerican
      Energy’s average per-unit cost of gas sold for 2004 increased 7.4%, resulting in
      a $54.3 million increase in revenue and cost of gas sold compared to 2003.
      The remainder of the increase in cost of gas sold and gas revenues was due
      to an
      increase in wholesale sales volumes. A decrease in gas retail sales volumes,
      in
      part due to milder temperature conditions in 2004 compared to 2003, reduced
      gas
      revenues for 2004. An increase in the average number of retail customers
      partially offset the decrease due to retail sales volumes.





*Kern
      River*





Operating
      revenue at Kern River is principally derived by providing firm or interruptible
      transportation services under long-term transportation service agreements
      related to its interstate natural gas transportation pipeline system. On
      May 1, 2003, Kern River placed into service a $1.2 billion, 717-mile
      expansion project (“2003 Expansion Project”), which increased the design
      capacity of Kern River’s pipeline system by 885,575 Dth per day to its current
      1,755,575 Dth per day.





Operating
      income remained relatively flat in 2005 compared to 2004 and increased
      $23.8 million, or 13.1%, in 2004 compared to 2003. The increase in 2004 was
      primarily due to higher capacity reservation charges earned in connection with
      the completion of the 2003 Expansion Project.





Operating
      revenue for 2005 increased $7.5 million, or 2.4%, to $323.6 million
      from the comparable period in 2004. The increase in operating revenue resulted
      from higher demand and commodity transportation revenues of $14.0 million
      due mainly to higher rates, subject to refund, for the current rate proceeding
      which became effective on November 1, 2004. This increase was partially offset
      by lower interruptible transportation revenue of $5.9 million. Operating
      revenue for 2004 increased $55.9 million, or 21.5%, to $316.1 million
      from the comparable period in 2003. The increase in operating revenue resulted
      primarily from higher demand and commodity transportation revenues, net of
      revenue sharing, of $52.2 million, associated with the full-year effect of
      higher capacity reservation charges on the additional capacity from the 2003
      Expansion Project.





Depreciation
      and amortization expense for 2005 increased $9.1 million to
      $62.4 million from the comparable period in 2004 due to higher depreciation
      rates in connection with the current rate proceeding. Operating expenses and
      depreciation and amortization for 2004 increased $15.7 million, or 36.9%,
      and $16.5 million, or 44.8%, respectively, from the comparable period in
      2003 due to the completion of the 2003 Expansion Project.


46


*Northern
      Natural Gas*





Operating
      revenue at Northern Natural Gas is principally derived by providing firm or
      interruptible transportation and storage services under long-term transportation
      storage service agreements related to its interstate natural gas transportation
      pipeline system.





Operating
      income for 2005 increased $18.5 million, or 9.7%, to $208.8 million
      from the comparable period in 2004. Northern Natural Gas recognized net
      benefits, due to the settlement of its consolidated rate case proceeding and
      its
      SLA settlement, to operating income during the year ended December 31, 2005
      of
      $15.7 million reflecting final settlement adjustments and the ongoing
      operating impact of lower depreciation and amortization expense due to changes
      in the useful lives of its transmission, storage and intangible assets,
      partially offset by higher regulatory amortization of the remaining SLA
      balance.





Operating
      revenue for 2005 increased $24.3 million, or 4.5%, to $569.1 million from the
      comparable period in 2004. The increase was mainly due to higher gas and liquids
      sales of $25.6 million, due to higher sales of gas from operational storage
      utilized to manage physical flows on the pipeline system, and higher
      transportation and storage revenues of $8.3 million, due to changes in the
      composition of transportation contracts. These increases were partially offset
      by the net effects of the consolidated rate case and SLA settlements, which
      decreased operating revenue by $11.5 million.





Operating
      expenses for 2005 also increased $12.4 million from the comparable period in
      2004 due to a $29.0 million long-lived asset impairment charge for West Hugoton
      recognized in the fourth quarter of 2005, partially offset by a gain of $19.7
      million recognized in the second quarter of 2005 from the sale of an idled
      section of pipeline in Oklahoma and Texas. Northern Natural Gas entered into
      separate purchase and sale agreements (“PSA”) relative to the West Hugoton and
      Beaver non-strategic sections of its interstate pipeline system in the fourth
      quarter of 2005. No impairment charge was needed for the Beaver pipeline as
      the
      sale price agreed to in the Beaver PSA exceeded the carrying value of the Beaver
      pipeline. The sales of the West Hugoton and Beaver assets are expected to close
      in mid to late 2006.





Operating
      income for 2004 increased $14.5 million, or 8.2%, to $190.3 million
      from the comparable period in 2003. Northern Natural Gas’ operating revenue for
      2004, which reflects the effectuation of rate increases on November 1, 2004
      and 2003, and higher gas and liquids sales, increased $57.9 million, or
      11.9%, to $544.8 million from the comparable period in 2003. In 2004 and
      2003, gas and liquids sales were subject to a regulatory tracking procedure
      and,
      therefore, any fluctuations in the amount of such sales had a corresponding
      effect on cost of sales. Depreciation and amortization for 2004 increased
      $15.2 million compared to 2003 due primarily to higher depreciation rates
      included in the filed rate cases.





*CE Electric UK*





CE
      Electric UK owns two electricity distribution companies which operate in Great
      Britain, Northern Electric and Yorkshire Electricity. The distribution
      companies’ main income is earned from charges for the use of their electrical
      infrastructure levied on supply companies. CE Electric UK also owns an
      engineering contracting company, a gas exploration and production company and
      various other more minor subsidiaries.





Operating
      income for 2005 decreased $13.5 million, or 2.7%, to $483.9 million
      compared with 2004. Operating revenue for 2005 decreased $52.3 million, or
      5.6%, to $884.1 million compared with 2004 due primarily to
      $37.0 million of lower distribution revenues, $9.1 million of lower
      contracting revenues and a $6.9 million adverse impact of the exchange rate.
      Cost of sales for 2005 decreased $7.5 million due mainly to lower
      contracting work and exit charges from the National Grid Company. Operating
      expenses for 2005 decreased $29.4 million due mainly to $13.3 million
      of gains recognized on the partial disposal of certain CE Gas Australian
      assets and lower costs of $11.2 million associated with the withdrawal from
      the metering market.





Operating
      income for 2004 increased $51.6 million, or 11.6%, to $497.4 million
      compared with 2003. Operating revenue for 2004 increased $106.4 million, or
      12.8%, to $936.4 million compared with 2003 due primarily as a result of
      the weaker U.S. dollar and increased contracting revenue. Cost of sales for
      2004
      increased $16.7 million mainly due to increased contracting activity and
      the weaker U.S. dollar, partially offset by lower exit charges from the National
      Grid Company at both Northern Electric and Yorkshire Electricity. Operating
      expenses for 2004 increased $16.5 million due to higher pension costs and
      the weaker U.S. dollar in 2004, and a gain on the sale of a local operational
      dispatch facility in 2003. Depreciation and amortization for 2004 increased
      $12.7 million primarily due to the weaker U.S. dollar.





47


*CalEnergy
      Generation-Foreign*





The
      CalEnergy Generation-Foreign platform consists of MEHC’s indirect ownership of
      the Upper Mahiao, Mahanagdong and Malitbog projects (collectively, the “Leyte
      Projects”), and a combined irrigation and hydroelectric power generation project
      located in the central part of the island of Luzon in the Philippines (the
      “Casecnan Project”).





Operating
      income for 2005 decreased $3.5 million, or 1.9%, to $185.0 million
      compared with 2004. Operating revenue for 2005 increased $4.9 million, or
      1.6%, to $312.3 million compared with 2004. The increase in operating
      revenue was mainly due to higher capacity prices at the Leyte Projects and
      higher water delivery fees at the Casecnan Project pursuant to contractual
      escalation factors.





Operating
      income for 2004 decreased $9.0 million, or 4.6%, to $188.5 million
      compared with 2003. Operating revenue for 2004 decreased $19.0 million, or
      5.8%, to $307.4 million compared with 2003. Each decrease was primarily due
      to lower water delivery fees in 2004 resulting from the NIA arbitration
      settlement at CE Casecnan, partially offset by higher contractually-specified
      capacity and water delivery prices in 2004 and by the reversal of accrued
      revenue in connection with the settlement of various disputes between the Leyte
      Projects and the PNOC-EDC in 2003.





*HomeServices*





HomeServices’
      operating revenue and cost of sales consists mainly of commission revenue from
      real estate brokerage transactions and associated commissions on the
      transactions. HomeServices separately acquired 13 real estate companies for
      an
      aggregate purchase price of $78.5 million throughout 2005, 2004 and
      2003.





Operating
      income for 2005 increased $12.4 million, or 11.0%, to $125.3 million
      from the comparable period in 2004. Operating revenue for 2005 increased
      $112.1 million, or 6.4%, to $1,868.5 million and cost of sales
      increased $78.2 million from the comparable period in 2004. The increase in
      operating revenue was due to growth from existing businesses totaling
      $62.1 million reflecting primarily higher average sales prices and
      acquisitions not included in the comparable 2004 period totaling
      $49.4 million.





Operating
      expenses for 2005 increased $24.5 million from the comparable period in
      2004 mainly due to $12.8 million related to acquisitions not included in
      the comparable 2004 period and $11.7 million in higher operating expense at
      existing businesses due primarily to higher marketing and occupancy expenses.
      Depreciation and amortization for 2005 was $3.1 million lower than the
      comparable period in 2004 due primarily to lower amortization of acquisition
      related costs in 2005 as compared to the same period in 2004.





Operating
      income for 2004 increased $20.0 million, or 21.5%, to $112.9 million
      from the comparable period in 2003. Operating revenue for 2004 increased
      $279.8 million, or 18.9%, to $1,756.4 million and cost of sales
      increased $211.8 million from the comparable period in 2003. The increase
      in operating revenue was due to growth from existing businesses totaling
      $154.7 million reflecting primarily higher average sales prices and
      acquisitions not included in the comparable 2003 period totaling
      $125.1 million.





Operating
      expenses for 2004 increased $44.8 million from the comparable period in
      2003 mainly due to $27.8 million related to acquisitions not included in
      the comparable 2003 period and $17.0 million in higher operating expense at
      existing businesses due primarily to higher salaries and employee benefits,
      marketing and occupancy expenses. Depreciation and amortization for 2004 was
      $3.3 million higher than the comparable period in 2003 due primarily to
      higher amortization of acquisition related costs in 2004 as compared to the
      same
      period in 2003.





48


Consolidated
      Other Income and Expense Items





*Interest
      Expense*





Interest
      expense for 2005 decreased $12.2 million to $891.0 million from
      $903.2 million for the same period in 2004. Interest expense was lower in
      2005 due to maturities of and principal repayments on parent company senior
      and
      subordinated debt and subsidiary and project debt, partially offset by
      additional interest expense on the £350.0 million of 5.125% bonds issued by
      certain indirect wholly-owned subsidiaries of CE Electric UK in May
      2005 and MidAmerican Energy’s 4.65%, $350.0 million notes issued in
      October 2004 and 5.75%, $300.0 million notes issued in November 2005.
      Additionally, in the first quarter of 2005, the Company incurred a
      $10.2 million charge to exercise the call option on the £155.0 million
      Variable Rate Reset Trust Securities at CE Electric UK.





Interest
      expense for 2004 increased $142.2 million to $903.2 million from
      $761.0 million for the same period in 2003. On October 1, 2003, the Company
      adopted FIN 46R related to certain finance subsidiaries. The adoption required
      that amounts previously recorded in minority interest and preferred dividends
      of
      subsidiaries be recorded prospectively as interest expense in the accompanying
      consolidated statement of operations. For the year ended December 31, 2004
      and the three-month period ended December 31, 2003, the Company recorded
      $196.9 million and $49.8 million, respectively, of interest expense
      related to these finance subsidiaries. In accordance with the requirements
      of
      FIN 46R, no amounts prior to adoption on October 1, 2003 were reclassified.
      The
      amount included in minority interest and preferred dividends of subsidiaries
      related to these finance subsidiaries for the nine-month period ended September
      30, 2003, was $170.2 million. Other interest expense decreased
      $4.9 million. The Company incurred lower interest expense of
      $42.9 million due mainly to the Company's scheduled redemption of
      $215.0 million of 6.96% senior notes in September 2003, redemption in full
      of the outstanding shares of the Yorkshire Capital Trust I, 8.08% trust
      securities in June 2003, and reductions in subsidiary project debt. The Company
      incurred additional interest expense, totaling $38.0 million, on the
      Company’s debt issuances of $450.0 million of 3.5% senior notes in May 2003
      and $250.0 million of 5.0% senior notes in February 2004 and the effects of
      the weaker U.S. dollar.





*Other
      Income, Net*





Other
      income, net for the years ended December 31, 2005, 2004, and 2003 is summarized
      as follows (in millions):





**Year
                Ended December 31,****2005**
            
            **2004**
            
            **2003**Capitalized
                interest
            
            $
            16.7
            
            $
            20.0
            
            $
            30.5Interest
                and dividend income
            
            
            58.1
            
            
            38.9
            
            
            47.9Other
                income
            
            
            74.5
            
            
            128.2
            
            
            96.7Other
                expense
            
            
            (22.1
            )
            
            (10.1
            )
            
            (5.9
            )Total
                other income, net
            
            $
            127.2
            
            $
            177.0
            
            $
            169.2





Capitalized
      interest for 2005 decreased due to lower capitalization at Northern Electric
      and
      Yorkshire Electricity, partially offset by higher capitalized interest at
      MidAmerican Energy associated with an increase in the construction of generation
      facilities. Capitalized interest for 2004 decreased $10.5 million to
      $20.0 million from $30.5 million for the same period in 2003. Kern
      River capitalized $17.2 million of interest in 2003 related to its 2003
      Expansion Project. This was partially offset by increased construction activity
      at MidAmerican Energy’s generation projects.





Interest
      and dividend income for 2005 increased $19.2 million to $58.1 million
      from $38.9 million for the same period in 2004 mainly due to earnings on
      guaranteed investment contracts (£100.0 million at 4.75% and
£200.0 million at 4.73%) purchased by certain indirect wholly-owned
      subsidiaries of CE Electric UK in May 2005 as well as earnings on
      higher cash balances and higher short-term interest rates.





Interest
      and dividend income for 2004 decreased $9.0 million to $38.9 million
      from $47.9 million for the same period in 2003. The decrease was mainly due
      to dividend income received in 2003 from the Company’s investment in Williams
      Cumulative Convertible Preferred Stock that was sold in June 2003, partially
      offset by higher interest income at CE Electric UK resulting from higher cash
      balances.


49


Other
      income for 2005 decreased $53.7 million from the comparable period in 2004,
      which increased $31.5 million from the comparable period in 2003. Refer to
      Note 16 of Notes to Consolidated Financial Statements included in Item 8.
      Financial Statements and Supplementary Data of this Form 10-K for additional
      information regarding the components of other income. In 2005, the Company
      realized gains from sales of certain non-strategic investments at MidAmerican
      Funding of $13.4 million and CE Electric UK of $8.4 million.
      In 2004, the Company recognized a $72.2 million gain on Northern Natural
      Gas’ sale of the Enron Note Receivable and a $14.8 million gain on amounts
      collected by Kern River on its claim for damages against Mirant. In 2003, the
      Company recognized a $31.9 million gain in connection with the NIA
      arbitration settlement and a $13.8 million gain on the sale of Williams
      Cumulative Convertible Preferred Stock. Additionally, the allowance for equity
      funds used during construction for 2005 increased $5.7 million compared to
      2004 due to increased levels of capital project expenditures at MidAmerican
      Energy, while the allowance for equity funds used during construction for 2004
      decreased $6.2 million compared to 2003 due primarily to the completion of
      Kern River’s 2003 Expansion Project in May 2003.





Included
      in other expense for 2005 are losses for other-than-temporary impairments of
      MidAmerican Funding’s investments in commercial passenger aircraft leased to
      major domestic airlines, which are accounted for as leveraged leases, of
      $15.8 million. These impairments result from MidAmerican Funding’s
      evaluation of these investments in light of the continued deterioration of
      the
      airline industry and the bankruptcy filings of two major airline carriers during
      2005. The remaining carrying values of MidAmerican Funding’s commercial aircraft
      leveraged leases are not material.





*Income
      Tax Expense*





Income
      tax expense for 2005 decreased $20.3 million to $244.7 million from
      $265.0 million for the same period in 2004. The effective tax rate was
      32.0% and 33.2% for 2005 and 2004, respectively. The lower effective tax rate
      in
      2005 was mainly due to the effects of production tax credits related to energy
      produced by MidAmerican Energy’s wind facilities, the first of which were placed
      in service on December 31, 2004, and lower income taxes on foreign earnings
      in 2005, partially offset by a change in the state of Iowa’s income tax laws in
      2004 related to bonus depreciation that lowered income tax expense and benefits
      from CE Electric UK’s settlement of various positions with the Inland Revenue
      department.





Income
      tax expense for 2004 decreased $5.3 million to $265.0 million from
      $270.3 million for the same period in 2003. The effective tax rate was
      33.2% and 31.5% for 2004 and 2003, respectively. The increase in the effective
      tax rate in 2004 was mainly due to the effect of the $170.2 million of tax
      deductible interest on subordinated debt not included in income from continuing
      operations before income tax expense, minority interest and preferred dividends
      of subsidiaries and equity income in 2003, partially offset by the
      $24.4 million tax payment made in connection with the NIA arbitration
      settlement at CE Casecnan in 2003, CE Electric UK’s settlement of various
      positions with the Inland Revenue department and a change in the state of Iowa’s
      income tax laws in 2004 related to bonus depreciation that lowered income tax
      expense.





*Equity
      Income*





Equity
      income for 2005 increased $36.4 million to $53.3 million compared with
      $16.9 million for the same period in 2004. The increase is mainly due to
      higher earnings at CE Generation due to higher energy rates, partially
      offset by higher fuel costs, mainly at its natural gas-fired generation
      facilities and increased production at the Imperial Valley Projects due to
      the
      timing and length of scheduled outages and lower major maintenance costs,
      partially offset by higher fuel costs. Additionally, 2004 results included
      MEHC’s $16.8 million after-tax portion of a charge as a result of the
      partial impairment of the carrying value of CE Generation’s Power Resources
      project.





Equity
      income for 2004 decreased $21.4 million to $16.9 million compared with
      $38.3 million for the same period in 2003, mainly due to MEHC’s
      $16.8 million after-tax portion of the Power Resources project impairment.
      Additionally, HomeServices’ mortgage joint ventures had lower income due to
      lower refinancing activity.





*Discontinued
      Operations*





On
      September 10, 2004, management made the decision to cease operations of the
      Zinc Recovery Project. In connection with ceasing operations, the Zinc Recovery
      Project’s assets have been dismantled and sold and certain employees of the
      operator of the Zinc Recovery Project were paid one-time termination benefits.
      Implementation of the decommissioning plan began in September 2004 and, as
      of
      December 31, 2005, the dismantling, decommissioning, and sale of remaining
      assets of the Zinc Recovery Project was completed.


50


The
      income from discontinued operations, net of income tax, of $5.1 million for
      the year ended December 31, 2005 reflects the proceeds received from the
      sale of assets, partially offset by the disposal costs incurred, in connection
      with the September 2004 decision to cease the operations of the Zinc Recovery
      Project. The loss from discontinued operations, net of income tax, of
      $367.6 million for the year ended December 31, 2004 consists primarily
      of a $340.3 million impairment charge recognized in connection with ceasing
      the operations of the Zinc Recovery Project. The $27.1 million loss from
      discontinued operations, net of income tax, for the year ended December 31,
      2003 reflects losses incurred from operating the Zinc Recovery
      Project.





**Liquidity
      and Capital Resources**





In
      May
      2005, MEHC reached a definitive agreement with ScottishPower and its subsidiary,
      PacifiCorp Holdings, Inc., to acquire 100% of the common stock of
      ScottishPower’s wholly-owned indirect subsidiary, PacifiCorp, a regulated
      electric utility providing service to approximately 1.6 million customers
      in California, Idaho, Oregon, Utah, Washington and Wyoming. MEHC will purchase
      all of the outstanding shares of the PacifiCorp common stock for approximately
      $5.1 billion in cash. The long-term debt and preferred stock of PacifiCorp,
      which aggregated $4.3 billion at December 31, 2005, will remain
      outstanding. As of March 1, 2006, all state and federal approvals required
      for the acquisition were obtained, subject to the completion of a “most favored
      states” process in Wyoming, Washington, Utah, Idaho and Oregon that allows each
      such state to make applicable to that state any acquisition commitments or
      conditions accepted in other PacifiCorp states. Subject to the most favored
      states process and other customary closing conditions, the transaction is
      expected to close in March 2006. MEHC expects to fund the acquisition of
      PacifiCorp with the proceeds from an investment by Berkshire Hathaway and other
      existing shareholders of approximately $3.4 billion in MEHC common stock
      and the issuance by MEHC of $1.7 billion of either additional common stock
      to Berkshire Hathaway or long-term senior notes to third parties.





The
      applications filed with the public utility commissions in the six states where
      PacifiCorp has retail customers propose a number of regulatory commitments
      by
      MEHC and PacifiCorp upon which approval of the transaction would be conditioned,
      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 MEHC and PacifiCorp include investments, generally
      to
      be made over several years following the purchase, in emissions reduction
      technology for PacifiCorp’s existing coal plants and in PacifiCorp’s
      transmission and distribution system of approximately $812 million and
      $520 million, respectively. PacifiCorp generally expects at least
      $1.0 billion per year in capital expenditures over the next five years,
      including the regulatory commitments described above. Capital expenditure needs
      are reviewed regularly by management and may change significantly as a result
      of
      such reviews.





On
      February 9, 2006, following the effective date of the repeal of PUHCA 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. As a consequence, Berkshire Hathaway owns 83.4% (80.5% on a diluted
      basis) of the outstanding common stock of MEHC, will consolidate the Company
      in
      its financial statements as a majority-owned subsidiary, and will include the
      Company in its consolidated federal U.S. income tax return.





On
      March 1, 2006, MEHC and Berkshire Hathaway entered into 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, and will not be used for the PacifiCorp
      acquisition or for other future acquisitions.





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





51


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





The
      Company’s cash and cash equivalents and short-term investments, which consist
      primarily of auction rate securities that are used in the Company’s cash
      management program, were $396.2 million at December 31, 2005, compared
      to $960.9 million at December 31, 2004. In addition, the Company
      recorded separately, in restricted cash and short-term investments and in
      deferred charges and other assets, restricted cash and investments of
      $136.7 million and $164.5 million at December 31, 2005 and 2004,
      respectively. The restricted cash balance is mainly composed of amounts
      deposited in restricted accounts relating to (i) the Company’s debt service
      reserve requirements relating to certain projects, (ii) customer deposits held
      in escrow, (iii) custody deposits, and (iv) unpaid dividends declared
      obligations. The debt service funds are restricted by their respective project
      debt agreements to be used only for the related project.





Cash
      Flows from Operating Activities





The
      Company generated cash flows from operations of $1,310.8 million for the
      year ended December 31, 2005, compared with $1,424.6 million for the
      same period in 2004. The decrease was mainly due to the receipt of a
      $79.0 million federal tax refund in 2004, related to additional tax
      depreciation, partially offset by higher earnings, changes in other working
      capital and a $33.6 million reduction in 2005 of cash used at the Zinc
      Recovery Project’s discontinued operations.





Cash
      Flows from Investing Activities





Cash
      flows used in investing activities for the years ended December 31, 2005
      and 2004 were $1,551.3 million and $1,098.1 million, respectively. The
      increase was mainly due to the purchase, with the majority of the proceeds
      of
      the issuance of £350.0 million of 5.125% bonds due in 2035, of two
      guaranteed investment contracts by certain indirect wholly-owned subsidiaries
      of
      CE Electric UK totaling $556.6 million and the collection of the
      $97.0 million ROP Note and $72.2 million from the Enron Note
      Receivable in 2004, partially offset by higher proceeds from sale of
      non-strategic investments and assets in 2005 totaling
      $94.2 million.





*Capital
      Expenditures, Construction and Other Development Costs*





Capital
      expenditures, construction and other development costs were
      $1,196.2 million for the year ended December 31, 2005, compared with
      $1,179.4 million for the same period in 2004. The following table
      summarizes the expenditures by business segment (in millions):





**Year
                Ended December 31,****2005**
            
            **2004****Capital
                expenditures:**MidAmerican
                Energy
            
            $
            701.0
            
            $
            633.8Northern
                Natural Gas
            
            
            124.7
            
            
            138.8CE
                Electric UK
            
            
            342.6
            
            
            334.5Other
                reportable segments
            
            
            27.4
            
            
            53.6Segment
                capital expenditures
            
            
            1,195.7
            
            
            1,160.7Corporate/other
            
            
            0.5
            
            
            18.7**Total
                capital expenditures**
            
            $
            1,196.2
            
            $
            1,179.4





Forecasted
      capital expenditures, construction and other development costs for fiscal 2006
      are approximately $1.3 billion, which does not include any amounts for the
      planned acquisition of PacifiCorp. Capital expenditure needs are reviewed
      regularly by management and may change significantly as a result of such
      reviews. The Company expects to meet these capital expenditures with cash flows
      from operations and the issuance of debt. Capital expenditures relating to
      operating projects, consisting of recurring expenditures and the funding of
      growing load requirements, were $796.3 million for the year ended
      December 31, 2005. Construction and other development costs were
      $399.9 million for the year ended December 31, 2005. These costs
      consist mainly of expenditures for large scale, generation projects as
      follows:





52


MidAmerican
      Energy anticipates a continuing increase in demand for electricity from its
      regulated customers. To meet anticipated demand and ensure adequate electric
      generation in its service territory, MidAmerican Energy is currently
      constructing CBEC Unit 4, a 790-MW (expected accreditation)
      super-critical-temperature, coal-fired generating plant. MidAmerican Energy
      will
      operate the plant and hold an undivided ownership interest as a tenant in common
      with the other owners of the plant. MidAmerican Energy’s current ownership
      interest is 60.67%, equating to 479 MW of output. Municipal, cooperative and
      public power utilities will own the remainder, which is a typical ownership
      arrangement for large base-load plants in Iowa. The facility will provide
      service to regulated retail electricity customers. Wholesale sales may also
      be
      made from the facility to the extent the power is not immediately needed for
      regulated retail service. MidAmerican Energy has obtained regulatory approval
      to
      include the Iowa portion of the actual cost of the generation project in its
      Iowa rate base as long as the actual cost does not exceed the agreed cap that
      MidAmerican Energy has deemed to be reasonable. If the cap is exceeded,
      MidAmerican Energy has the right to demonstrate the prudence of the expenditures
      above the cap, subject to regulatory review. MidAmerican Energy expects to
      invest approximately $737 million in CBEC Unit 4, including transmission
      facilities and excluding allowance for funds used during construction. Through
      December 31, 2005, MidAmerican Energy has invested $502.0 million in the
      project, including $121.3 million for MidAmerican Energy’s share of deferred
      payments allowed by the construction contract.





On
      December 16, 2005, MidAmerican Energy filed with the IUB a settlement
      agreement between MidAmerican Energy and the OCA regarding ratemaking principles
      for up to 545 MW (nameplate rating) of additional wind generation capacity
      in
      Iowa. Generally speaking, accredited capacity ratings for wind power facilities
      are considerably less than the nameplate ratings due to the varying nature
      of
      wind. The settlement agreement is subject to approval by the IUB.





MidAmerican
      Energy’s total accredited net generating capability in the summer of 2005 was
      5,098 MW. Accredited net generating capability represents the amount of
      generation available to meet the requirements on MidAmerican Energy’s system and
      consists of MidAmerican Energy-owned generation of 4,659 MW and the net amount
      of capacity purchases and sales of 439 MW. Accredited capacity may vary from
      the
      nameplate capacity ratings. Additionally, the actual amount of generation
      capacity available at any time may be less than the accredited capacity due
      to
      regulatory restrictions, transmission constraints, fuel restrictions and
      generating units being temporarily out of service for inspection, maintenance,
      refueling, modifications or other reasons.





*Put
      of ROP Note and Receipt of Cash*





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





*Sale
      of Enron Note Receivable and Receipt of Cash*





Northern
      Natural Gas had a note receivable of approximately $259.0 million (the
“Enron Note Receivable”) with Enron. As a result of Enron filing for bankruptcy
      on December 2, 2001, Northern Natural Gas filed a bankruptcy claim against
      Enron seeking to recover payment of the Enron Note Receivable. As of
      December 31, 2001, Northern Natural Gas had written-off the note. By
      stipulation, Enron and Northern Natural Gas agreed to a value of
      $249.0 million for the claim and received approval of the stipulation from
      Enron’s Bankruptcy Court on August 26, 2004. On November 23, 2004,
      Northern Natural Gas sold its stipulated general, unsecured claim against Enron
      of $249.0 million to a third party investor for $72.2 million, which
      was recorded as other income in the fourth quarter of 2004.





*HomeServices’
      Acquisitions*





In
      2005,
      HomeServices separately acquired three real estate companies for an aggregate
      purchase price of $5.1 million, net of cash acquired, plus working capital
      and certain other adjustments. For the year ended December 31, 2004, these
      real estate companies had combined revenue of $21.8 million on
      approximately 3,400 closed sides representing $0.8 billion of sales volume.
      In 2004, HomeServices separately acquired six real estate companies for an
      aggregate purchase price of $30.7 million, net of cash acquired, plus
      working capital and certain other adjustments. For the year ended
      December 31, 2003, these real estate companies had combined revenue of
      $95.7 million on approximately 15,000 closed sides representing
      $3.2 billion of sales volume. Additionally in 2004, HomeServices paid an
      earnout related to its 2003 acquisition of $6.0 million based on 2004
      financial performance measures. These purchases were financed using
      HomeServices’ cash balances.


53


Cash
      Flows from Financing Activities





Cash
      flows used in financing activities for the year ended December 31, 2005
      were $219.1 million. Uses of cash totaled $1,331.2 million and
      consisted primarily of $875.4 million for repayments of subsidiary and
      project debt and $448.5 million for repayments of parent company senior and
      subordinated debt. Sources of cash totaled $1,112.1 million and consisted
      of $1,050.6 million of proceeds from the issuance of subsidiary and project
      debt and $51.0 million of net proceeds from MEHC’s revolving credit
      facility.





Cash
      flows used in financing activities for the year ended December 31, 2004
      were $105.4 million. Uses of cash totaled $730.5 million and consisted
      mainly of $504.8 million for repayments of subsidiary and project debt,
      including $136.4 million of cash flows from discontinued operations,
      $100.0 million for repayments of parent company subordinated debt and
      $43.9 million of net repayments of subsidiary short-term debt. Sources of
      cash totaled $625.1 million and consisted of $375.3 million of
      proceeds from the issuance of subsidiary and project debt and
      $249.8 million of proceeds from the issuance of parent company senior
      debt.





*Recent
      Debt Issuances, Redemptions and Maturities*





In
      addition to the debt issuances, redemption and maturities discussed herein,
      MEHC
      and its subsidiaries made scheduled repayments on parent company subordinated
      debt and subsidiary and project debt totaling approximately $565 million
      during the year ended December 31, 2005.





In
      February 2005, a subsidiary of CE Electric UK exercised a call
      option to purchase, and then cancelled, its £155.0 million Variable Rate
      Reset Trust Securities, due in 2020. A charge to exercise the call option of
      $10.2 million was recognized in interest expense in the accompanying
      consolidated statement of operations.





On
      February 15, 2005, MidAmerican Energy’s 7% series of mortgage bonds,
      totaling $90.5 million, were repaid upon maturity.





On
      April 4, 2005, CE Electric UK and certain of its subsidiaries
      entered into a variable rate, five-year, £100.0 million committed revolving
      credit facility.





On
      April 14, 2005, Northern Natural Gas issued $100.0 million of 5.125%
      senior notes due May 1, 2015. The proceeds were used by Northern Natural
      Gas to repay its outstanding $100.0 million 6.875% senior notes due
      May 1, 2005.





On
      May 5, 2005, Northern Electric Finance plc, an indirect wholly-owned
      subsidiary of CE Electric UK, issued £150.0 million of 5.125% bonds due
      2035, guaranteed by Northern Electric and guaranteed as to scheduled payments
      of
      principal and interest by Ambac. Additionally, on May 5, 2005, Yorkshire
      Electricity, a wholly-owned subsidiary of CE Electric UK, issued
£200.0 million of 5.125% bonds due 2035, guaranteed as to scheduled
      payments of principal and interest by Ambac. The
      proceeds from the offerings are being invested and used for general corporate
      purposes. Investments
      include a £100.0 million, 4.75%, fixed rate guaranteed investment contract
      maturing in December 2007 and a £200.0 million, 4.73%, fixed rate
      guaranteed investment contract maturing in February 2008. The proceeds from
      the
      maturing guaranteed investment contracts will be used to repay certain long-term
      debt of subsidiaries of CE Electric UK. In connection with the issuance of
      such
      bonds, CE Electric UK entered into agreements amending certain terms
      and conditions of its £200.0 million 7.25% bonds due 2022.





On
      August 26, 2005, MEHC entered into a $400.0 million, variable rate
      (LIBOR or a base rate plus a margin), credit facility pursuant to a credit
      agreement. The credit agreement is unsecured and has a termination date of
      August 26, 2010. As of December 31, 2005, the outstanding balance and
      amount of letters of credit issued under the credit agreement totaled
      $51.0 million and $41.9 million, respectively. The interest rate on
      the balance outstanding under the facility at December 31, 2005 was
      4.85%.





On
      September 15, 2005, MEHC’s 7.23% senior notes, totaling
      $260.0 million, were repaid upon maturity.





On
      November 1, 2005, MidAmerican Energy issued $300.0 million of 5.75%
      medium-term notes due in 2035. The proceeds are being used to support
      construction of its electric generation projects and for general corporate
      purposes.





54


**The
      Energy Policy Act**





On
      August 8, 2005, the Energy Policy Act was signed into law. That law
      potentially impacts many segments of the energy industry. A tax provision
      extended the federal production tax credit for new renewable electricity
      generation projects through December 31, 2007. In part as a result of that
      portion of the law, MidAmerican Energy began development efforts to add
      additional wind generation. The law also results in expanding the FERC’s
      regulatory authority in areas such as mandatory electric system reliability
      standards, electric transmission expansion incentives and pricing, regulation
      of
      utility holding companies, and enforcement authority to issue substantial civil
      penalties.





**CalEnergy
      Generation-Foreign**





The
      10-year cooperation periods for the Leyte Projects end in June 2006 and July
      2007, respectively, at which time each project will be transferred to the
      PNOC-EDC at no cost on an “as-is” basis. For the year ended December 31,
      2005, the Upper Mahiao Project’s financial results represented 0.6%, 1.7% and
      2.3%, respectively, and the Mahanagdong and Malitbog Projects’ combined
      financial results represented 2.1%, 7.9% and 7.4%, respectively, of MEHC’s total
      consolidated operating revenue, income from continuing operations and operating
      cash flows from continuing operations. Additionally, the net properties, plants
      and equipment and the project debt of the Leyte Projects represented less than
      1%, respectively, of MEHC’s total consolidated net properties, plants and
      equipment and subsidiary and project debt at December 31,
      2005.





**Credit
      Ratings**





Debt
      and
      preferred securities of MEHC and its subsidiaries may be rated by nationally
      recognized credit rating agencies. Assigned credit ratings are based on each
      rating agency’s assessment of the rated company’s ability to, in general, meet
      the obligations of its debt or preferred securities. The credit ratings are
      not
      a recommendation to buy, sell or hold securities, and there is no assurance
      that
      a particular credit rating will continue for any given period of time. Other
      than the agreements discussed below, MEHC and its 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 its risk management activities, MidAmerican Energy must meet
      credit quality standards as required by counterparties. In accordance with
      industry practice, master agreements that govern MidAmerican Energy’s energy
      supply and marketing activities either specifically require it to maintain
      investment grade credit ratings or provide the right for counterparties to
      demand “adequate assurances” in the event of a material adverse change in
      MidAmerican Energy’s creditworthiness. If one or more of MidAmerican Energy’s
      credit ratings decline below investment grade, MidAmerican Energy may be
      required to post cash collateral, letters of credit or other similar credit
      support to facilitate ongoing wholesale energy supply and marketing activities.
      As of March 1, 2006, MidAmerican Energy’s credit ratings from the three
      recognized credit rating agencies were investment grade; however if the ratings
      fell below investment grade, MidAmerican Energy’s estimated potential collateral
      requirements totaled approximately $267 million. MidAmerican Energy’s
      collateral requirements could fluctuate considerably due to seasonality, market
      price volatility, and a loss of key MidAmerican Energy generating facilities
      or
      other related factors.





Yorkshire
      Power Group Limited (“YPGL”), a subsidiary of CE Electric UK, has in effect
      certain currency rate swap agreements for its Yankee bonds with three large
      multi-national financial institutions. The swap agreements effectively convert
      the U.S. dollar fixed interest rate to a fixed rate in sterling for
      $281.0 million of 6.496% Yankee bonds outstanding at December 31,
      2004. The agreements extend until February 25, 2008 and convert the U.S.
      dollar interest rate to a fixed sterling rate ranging from 7.3175% to 7.3450%.
      The estimated fair value of these swap agreements at December 31, 2005 was
      $63.8 million based on quotes from the counterparties to these instruments
      and represents the estimated amount that the Company would expect to pay if
      these agreements were terminated. Certain of these counterparties have the
      option to terminate the swap agreements and demand payment of the fair value
      of
      the swaps if YPGL’s credit ratings from the three recognized credit rating
      agencies decline below investment grade. As of March 1, 2006, YPGL’s credit
      ratings from the three recognized credit rating agencies were investment grade;
      however, if the ratings fell below investment grade, payment requirements would
      have been $29.8 million.





**Inflation**





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


55


**Obligations
      and Commitments**





The
      Company has contractual obligations and commercial commitments that may affect
      its financial condition. Contractual obligations to make future payments arise
      from parent company and subsidiary long-term debt and notes payable, operating
      leases 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, 2005, which do not include any amounts
      associated with the pending acquisition of PacifiCorp, are as follows (in
      millions):





**Payments
                Due By Periods****<**
            
            **2-3**
            
            **4-5**
            
            **>5****Total**
            
            **1
                Year**
            
            **Years**
            
            **Years**
            
            **Years**Contractual
                Cash Obligations:Parent
                company senior debt
            
            $
            2,775.0
            
            $
            -
            
            $
            1,550.0
            
            $
            -
            
            $
            1,225.0Parent
                company subordinated debt
            
            
            1,663.8
            
            
            234.0
            
            
            468.0
            
            
            422.5
            
            
            539.3Subsidiary
                and project debt
            
            
            7,052.4
            
            
            313.7
            
            
            945.4
            
            
            399.2
            
            
            5,394.1Interest
                payments on long-term debt(1)
            
            
            8,168.4
            
            
            785.4
            
            
            1,377.4
            
            
            1,001.3
            
            
            5,004.3Coal,
                electricity and natural gas contract commitments(2)
            
            
            742.3
            
            
            181.1
            
            
            248.6
            
            
            118.3
            
            
            194.3Operating
                leases(2)
            
            
            376.8
            
            
            74.8
            
            
            124.8
            
            
            81.0
            
            
            96.2Deferred
                costs on construction contract(3)
            
            
            200.0
            
            
            -
            
            
            200.0
            
            
            -
            
            
            -Total
                contractual cash obligations
            
            $
            20,978.7
            
            $
            1,589.0
            
            $
            4,914.2
            
            $
            2,022.3
            
            $
            12,453.2





**Commitment
                Expiration per Period****<**
            
            **2-3**
            
            **4-5**
            
            **>5****Total**
            
            **1
                Year**
            
            **Years**
            
            **Years**
            
            **Years**Other
                Commercial Commitments:Unused
                revolving credit facilities and lines of credit -Parent
                company revolving credit facility
            
            $
            307.1
            
            $
            -
            
            $
            -
            
            $
            307.1
            
            $
            -Subsidiary
                revolving credit facilities and lines of credit
            
            
            612.6
            
            
            21.3
            
            
            -
            
            
            591.3
            
            
            -Total
                unused revolving credit facilities and lines of credit
            
            $
            919.7
            
            $
            21.3
            
            $
            -
            
            $
            898.4
            
            $
            -Parent
                company letters of credit outstanding
            
            $
            43.0
            
            $
            41.9
            
            $
            1.1
            
            $
            -
            
            $
            -


**______________**





(1)
            Excludes
                interest payments on variable rate long-term debt.(2)
            The
                coal, electricity and natural gas contract commitments and operating
                leases are not reflected on the consolidated balance
                sheets.(3)
            MidAmerican
                Energy is allowed to defer up to $200.0 million in payments to the
                contractor under its contract to build CBEC Unit 4. Approximately
                39.3% of
                this commitment is expected to be funded by the joint owners of CBEC
                Unit
                4.





The
      Company has other types of commitments that are subject to change and relate
      primarily to the items listed below. For additional information, refer, where
      applicable, to the respective referenced note of Notes to Consolidated Financial
      Statements included in Item 8. Financial Statements and Supplemental Data of
      this Form 10-K.





·
            Debt
                service reserve guarantees (see Note
                13)


·
            Asset
                retirement obligations (see Note
                14)


·
            Nuclear
                decommissioning costs (see Note 20)


·
            Residual
                guarantees on operating leases (see Note
                20)


·
            Pension
                and postretirement commitments (see Note
                21)


56


**Off-Balance
      Sheet Arrangements**





The
      Company has certain investments that are accounted for under the equity method
      in accordance with accounting principles generally accepted in the United States
      of America (“GAAP”). Accordingly, an amount is recorded on the Company’s balance
      sheet as an equity investment and is increased or decreased for the Company’s
      pro-rata share of earnings or losses, respectively, less any dividend
      distribution from such investments.





As
      of
      December 31, 2005, the Company’s investments which are accounted for under
      the equity method had $745.8 million of debt and $87.0 million in
      outstanding letters of credit. As of December 31, 2005, the Company’s
      pro-rata share of such debt and outstanding letters of credit, which is all
      non-recourse to MEHC except for a $23.1 million outstanding letter of
      credit (included in the Obligations and Commitments table), was
      $368.3 million and $41.4 million, respectively.





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





**New
      Accounting Pronouncements**





In
      December 2004, the FASB issued Statement of Financial Accounting Standards
      (“SFAS”) No. 123R, “Share-Based Payment” (“SFAS 123R”), which replaces SFAS No.
      123, “Accounting for Stock-Based Compensation,” and supersedes Accounting
      Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.”
SFAS 123R establishes standards for the accounting for transactions in which
      an
      entity exchanges its equity instruments for goods or services, primarily
      focusing on the accounting for transactions in which an entity obtains employee
      services in share-based payment transactions. SFAS 123R requires entities to
      measure compensation costs for all share-based payments, including stock
      options, at fair value and expense such payments over the service period. Since
      MEHC is considered a nonpublic entity under the criteria of SFAS 123R, this
      standard is effective for annual periods beginning after December 15, 2005.
      Adoption of this standard will not have an effect on the Company’s financial
      position, results of operations or cash flows as all of the Company’s
      outstanding stock options were fully vested at the date of issuance of SFAS
      123R. Modifications to outstanding stock options after the effective date of
      the
      standard may result in additional compensation expense pursuant to the
      provisions of SFAS 123R.





**Critical
      Accounting Policies**





The
      preparation of financial statements and related documents in conformity with
      GAAP requires management to make judgments, assumptions and estimates that
      affect the amounts reported in the consolidated financial statements and
      accompanying notes. Note 2 to the consolidated financial statements for the
      year
      ended December 31, 2005 included in this annual report describes the
      significant accounting policies and methods used in the preparation of the
      consolidated financial statements. Estimates are used for, but not limited
      to,
      the accounting for the effects of certain types of regulation, impairment of
      long-lived assets and goodwill, accrued pension and post-retirement expense,
      income taxes and revenue. Actual results could differ from these estimates.
      The
      following critical accounting policies are impacted significantly by judgments,
      assumptions and estimates used in the preparation of the consolidated financial
      statements.





*Accounting
      for the Effects of Certain Types of Regulation*





MidAmerican
      Energy, Kern River and Northern Natural Gas prepare their financial statements
      in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of
      Certain Types of Regulation (“SFAS 71”), which differs in certain respects from
      the application of GAAP by non-regulated businesses. In general, SFAS 71
      recognizes that accounting for rate-regulated enterprises should reflect the
      economic effects of regulation. As a result, a regulated utility is required
      to
      defer the recognition of costs (a regulatory asset) or the recognition of
      obligations (a regulatory liability) if it is probable that, through the
      rate-making process, there will be a corresponding increase or decrease in
      future rates. Accordingly, MidAmerican Energy, Kern River and Northern Natural
      Gas have deferred certain costs and accrued certain obligations, which will
      be
      amortized over various future periods. The Company periodically evaluates the
      applicability of SFAS 71 and considers factors such as regulatory changes and
      the impact of competition. If cost-based regulation ends or competition
      increases, the Company may have to reduce its asset balances to reflect a market
      basis less than cost and write-off the associated regulatory assets and
      liabilities.





57


Management
      continually assesses whether the regulatory assets are probable of future
      recovery by considering factors such as applicable regulatory environment
      changes, recent rate orders received by other regulated entities, and the status
      of any pending or potential deregulation legislation. Based upon this continual
      assessment, management believes the existing regulatory assets are probable
      of
      recovery. This assessment reflects the current political and regulatory climate
      at the state and federal levels, and is subject to change in the future. If
      future recovery of costs ceases to be probable, the asset and liability
      write-offs would be required to be recognized in operating income. Total
      regulatory assets were $441.1 million and $451.8 million as of December 31,
      2005
      and 2004, respectively. Total regulatory liabilities were $773.9 million and
      $682.8 million as of December 31, 2005 and 2004, respectively. Refer to Note
      5
      of Notes to Consolidated Financial Statements included in Item 8. Financial
      Statements and Supplementary Data of this Form 10-K for additional information
      regarding the Company’s regulatory assets and liabilities.





*Impairment
      of Long-Lived Assets and Goodwill*





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





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





The
      Company evaluates the impairment of goodwill under SFAS No. 142, “Goodwill and
      Other Intangible Assets.” The majority of the Company’s goodwill at
      December 31, 2005, relates to the Teton Transaction completed in 2000. The
      remainder relates to the acquisitions of Yorkshire Electricity in 2001, Kern
      River and Northern Natural Gas in 2002 and various acquisitions at HomeServices.
      The Company performs an annual goodwill impairment test and updates the test
      if
      events or circumstances occur that would more likely than not reduce the fair
      value of a reporting unit below its carrying value. Key assumptions used in
      the
      analysis include, but are not limited to, the use of an appropriate discount
      rate and estimated future cash flows. Estimated future cash flows are impacted
      by, among other factors, assumptions regarding comprehensive energy regulation,
      changes in regulations and rates, and estimates of future commodity prices.
      In
      estimating cash flows, the Company incorporates current market information,
      as
      well as, historical factors. During 2005 and 2004, the Company recognized
      impairments on several of its long-lived assets and goodwill. For additional
      discussion of these impairments refer to Notes 4, 7 and 17 of Notes to
      Consolidated Financial Statements included in Item 8. Financial Statements
      and
      Supplementary Data of this Form 10-K.





The
      Company records goodwill adjustments for (i) changes in the estimates of 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.





58


*Accrued
      Pension and Postretirement Expense*





The
      Company sponsors pension and other retirement and postretirement benefit plans
      in various forms covering all employees who meet eligibility requirements.
      The
      Company accounts for these benefits under SFAS No. 87, “Employers’ Accounting
      for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement
      Benefits Other Than Pensions,” respectively. Refer to Note 21 of Notes to
      Consolidated Financial Statements included in Item 8. Financial Statements
      and
      Supplementary Data of this Form 10-K for additional disclosures regarding the
      Company’s pension and postretirement commitments. The measurement of the pension
      and postretirement obligations, costs and liabilities is dependent on a variety
      of assumptions used by the actuaries and the Company. The critical assumptions
      used in developing the required estimates include the following key
      factors:





·
            discount
                rate;


·
            expected
                return
                on plan assets; and


·
            health
                care cost trend rates.





Other
      assumptions, such as retirement, mortality, and turnover, are evaluated
      periodically and updated to reflect actual experience.





For
      its
      pension and other postretirement plans, the Company assumed that its plans’
assets would generate an expected return on plan assets of 7.0% for its domestic
      and United Kingdom plans as of December 31, 2005. These assets are
      maintained in master trusts. The investment objective of the master trusts
      is to
      achieve reasonable returns on trust assets, subject to a prudent level of
      portfolio risk, for the purpose of enhancing the security of benefits for plan
      participants. The asset allocation targets were set after considering the
      investment objectives and the risk profiles with respect to each trust. Equity
      securities, debt securities, real estate and other securities are held for
      return potential and diversification benefits. Investments within asset classes
      are to be diversified to achieve broad market participation and reduce the
      impact of individual managers or investments. The Company regularly reviews
      its
      actual asset allocations and periodically rebalances its investments to its
      targeted allocations when considered appropriate.





For
      its
      pension and other postretirement plans, the Company assumed a discount rate
      of
      5.75% in determining the benefit obligations and benefit costs for its
      domestic plans as of and for the year ended December 31, 2005. Discount
      rates of 4.75% and 5.25%, respectively, were used in determining the benefit
      obligations and benefit costs for the Company’s United Kingdom plan as of
      and for the year ended December 31, 2005. Advice from the actuaries and
      current market conditions were used to determine discount rates. The discount
      rates used for all plans approximate the discount rates of hypothetical bond
      portfolios that match the Company’s expected payment obligations.





The
      actuarial assumptions used may differ materially from actual results due to
      changing market and economic conditions, higher or lower withdrawal rates or
      longer or shorter life spans of participants. These differences may result
      in a
      significant impact to the amount of pension and postretirement benefit expense
      recorded. If a 100 basis point change were to occur for the following
      assumptions, the approximate effect on the financial statements would be as
      follows:





Domestic
                PlansOther
                Postretirement
            
            United
                KingdomPension
                Plans
            
            Benefit
                Plans
            
            Pension
                Plan+1.0%
            
            -1.0%
            
            +1.0%
            
            -1.0%
            
            +1.0%
            
            -1.0%(in
                millions)**Effect
                on December 31, 2005,****Benefit
                Obligations:**Discount
                rate
            
            $
            (62.1
            )
            $
            75.2
            
            $
            (28.7
            )
            $
            35.7
            
            $
            (220.3
            )
            $
            280.5Health
                care trend rate
            
            
            N/A
            
            
            N/A
            
            
            (26.4
            )
            
            21.4
            
            
            N/A
            
            
            N/A**Effect
                on 2005 Periodic Cost:**Discount
                rate
            
            $
            (4.1
            )
            $
            1.9
            
            $
            (2.1
            )
            $
            2.1
            
            $
            (16.4
            )
            $
            18.2Health
                care trend rate
            
            
            N/A
            
            
            N/A
            
            
            (2.4
            )
            
            1.9
            
            
            N/A
            
            
            N/AExpected
                return on assets
            
            
            (5.6
            )
            
            5.6
            
            
            (1.4
            )
            
            1.4
            
            
            (14.6
            )
            
            14.6





59


*Income
      Taxes*





The
      Company recognizes deferred tax assets and liabilities based on the difference
      between the financial statement and tax basis of assets and liabilities using
      estimated tax rates in effect for the year in which the differences are expected
      to reverse. Based on existing regulatory precedent, MidAmerican Energy is not
      allowed to recognize deferred income tax expense related to certain temporary
      differences resulting from accelerated tax depreciation and other property
      related basis differences. For these differences, MidAmerican Energy establishes
      deferred tax liabilities and regulatory assets on the consolidated balance
      sheets since MidAmerican Energy is allowed to recover the increased tax expense
      when these differences turn around.





The
      Company has not provided U.S. 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. These earnings
      related to ongoing operations and were approximately $600 million at
      December 31, 2005. 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. The Company periodically evaluates its cash
      requirements in the U.S. and abroad and evaluates its short-term and long-term
      operational and fiscal objectives in determining whether the earnings of its
      foreign subsidiaries are indefinitely invested outside the U.S. or will be
      remitted to the U.S. within the foreseeable future.





In
      preparing the Company’s tax returns, management is required to interpret complex
      tax laws and regulations. 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 Internal Revenue
      Service has closed examination of the Company’s income tax returns through 1998.
      Although the ultimate resolution of the Company’s tax examinations is uncertain,
      the Company believes it has made adequate provisions for income tax payables
      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 condition, results of operations or cash flows. Tax
      contingency reserves are included in accrued property and other taxes and other
      long-term accrued liabilities, as appropriate, in the accompanying consolidated
      balance sheets.





*Revenue
      Recognition - Unbilled Revenue*





Unbilled
      revenues were $199.4 million and $185.5 million, respectively, at
      December 31, 2005 and 2004.





*Electric
      and Natural Gas Retail Revenues and Electric Distribution
      Revenues*





Revenue
      is recorded based upon services rendered and electricity and natural gas
      delivered, distributed or supplied to the end of the period. MidAmerican Energy
      records unbilled revenue representing the estimated amounts customers will
      be
      billed between the meter reading dates in a particular month and the end of
      that
      month. The distribution businesses in Great Britain record unbilled revenue
      representing the estimated amounts that customers will be billed for electricity
      distributed during the period based upon information received from the national
      settlement system.





For
      MidAmerican Energy, the determination of sales to individual customers is based
      on the reading of their meters, which is performed on a systematic basis
      throughout the month. At the end of each month, amounts of electricity and
      natural gas delivered to customers since the date of their last meter readings
      are estimated and the corresponding unbilled revenue accrual is then recorded.
      This estimate is reversed in the following month and actual revenue is recorded
      based on meter readings.





The
      monthly estimate for unbilled revenues is calculated by MidAmerican Energy
      using
      a number of inputs, including the estimation of total energy provided during
      the
      period, line losses, total energy billed, and the average rate per customer
      class. The estimate of total energy provided and unbilled volumes can vary
      from
      period to period depending on seasonal weather patterns, customer usage,
      production levels due to economic activity, and changes in the composition
      of
      customer classes or other variables. The distribution businesses in Great
      Britain follow a similar process in the determination of revenue, except that
      the information regarding units distributed through the systems is received
      from
      the national settlement system. Differences between the actual and estimated
      amounts have historically been immaterial.





60


*Natural
      Gas Transportation and Storage*





The
      majority of the pipelines’ transportation and storage revenues are derived from
      firm reservation charges which are fixed based on contractual quantities and
      rates. The remaining revenue, consisting primarily of commodity charges, is
      based on contractual rates and actual or estimated usage based on scheduled
      quantities and is subject to volume estimates including estimates of meter
      reading and loss and unaccounted for volumes. Amounts are generally billed
      on or
      before the ninth business day of the following month. Historically, any
      differences between estimated quantities and actual quantities have been
      immaterial.





**Item
      7A.** **Quantitative
      and Qualitative Disclosures About Market
      Risk.**





The
      Company is exposed to market risks associated with electric and natural gas
      prices, foreign currency exchange rates, interest rates, and credit risks.
      Risk
      is an inherent part of MEHC’s business and activities. 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. To assist in managing the risk, management enters into various
      transactions, including derivative transactions, consistent with these
      established procedures. These activities are generally described below. Notes
      2
      and 14 of Notes to Consolidated Financial Statements included in Item 8.
      Financial Statements and Supplementary Data of this Form 10-K contain additional
      information regarding the
      accounting for derivative contracts pursuant to Statement
      of Financial Accounting Standards No. 133, “Accounting for Derivative
      Instruments and Hedging Activities” ** (“SFAS
      133”), at
      the
      Company’s platforms.





As
      of
      December 31, 2005, the Company held derivative instruments with the
      following fair values (in millions):





CommodityNorthern
            
            
            
            Foreign
            
            InterestMidAmerican
            
            Natural
            
            
            
            Exchange
            
            RateEnergy
            
            Gas
            
            Other
            
            Swaps
            
            Locks
            
            TotalMaturity:2006
            
            $
            (9.0
            )
            $
            1.2
            
            $
            (6.0
            )
            $
            -
            
            $
            -
            
            $
            (13.8
            )2007
                - 2009
            
            
            (5.2
            )
            
            (6.7
            )
            
            (4.8
            )
            
            (77.5
            )
            
            -
            
            
            (94.2
            )After
                2009
            
            
            -
            
            
            (0.6
            )
            
            -
            
            
            -
            
            
            -
            
            
            (0.6
            )Total
            
            $
            (14.2
            )
            $
            (6.1
            )
            $
            (10.8
            )
            $
            (77.5
            )
            $
            -
            
            $
            (108.6
            )





Commodity
      Price Risk





*MidAmerican
      Energy - Gas*





Under
      the
      current regulatory framework, MidAmerican Energy is allowed to recover its
      cost
      of gas from all of its regulated gas customers through a purchased gas
      adjustment clause included in revenue. Accordingly, MidAmerican Energy’s
      regulated gas customers, although ensured of the availability of gas supplies,
      retain the risk associated with market price volatility. In order to mitigate
      a
      portion of the market price risk retained by its regulated gas customers through
      the purchased gas adjustment clause, MidAmerican Energy uses natural gas
      futures, options and over-the-counter agreements. The realized gains and losses
      on these derivative instruments are assigned to regulated gas customers through
      the purchased gas adjustment clause.





*MidAmerican
      Energy - Electric*





MidAmerican
      Energy is exposed to variations in the price of fuel for generation and the
      price of wholesale power to be purchased or sold. Under typical operating
      conditions, MidAmerican Energy has sufficient generation to supply its regulated
      retail electric needs, but may, at times, need to purchase electric power.
      MidAmerican Energy may incur a loss if the costs of fuel for generation or
      purchases of electric power are higher than MidAmerican Energy is permitted
      to
      recover from its customers under current electric rates. MidAmerican Energy
      uses
      physical and financial forward contracts to mitigate these regulated electric
      price risks.


61


Derivative
      instruments are used to economically hedge both committed and forecasted energy
      purchases and sales. Realized gains and losses on all hedges are recognized
      in
      income as operating revenues, cost of fuel, energy and capacity; or cost of
      gas
      sold, depending upon the nature of the item being hedged. Net unrealized gains
      and losses on hedges utilized for regulated purposes are recorded as regulatory
      assets or liabilities.





*Northern
      Natural Gas*





On
      an
      annual basis, Northern Natural Gas enters into equivalent volume forward
      transactions at negotiated fixed prices that generally provide for the sale
      of
      gas in the first six months of the year and the purchase of equivalent volumes
      in the final six months of the year to lock in the cash flows relating to
      anticipated near-term index-based sales and purchases of operational storage
      volumes. Since these sale and purchase transactions are a normal and recurring
      method of managing seasonal changes in operational storage volumes and are
      expected to result in physical deliveries, such transactions are deemed to
      be
      normal sales and purchases that qualify for the exemption from fair value
      accounting under SFAS 133.





Northern
      Natural Gas has also entered into longer term natural gas commodity swaps of
      equivalent volume transactions at negotiated fixed prices to hedge the cash
      flows of anticipated longer term operational gas sales and purchases. These
      agreements are designated as cash flow hedges under SFAS 133.





Additionally,
      Northern Natural Gas has entered into natural gas commodity swaps to hedge
      the
      cash flows of anticipated future preferred delivery storage contracts. The
      objective of these transactions is to lock in the cash flows relating to the
      price spreads of natural gas storage contracts that are sensitive to gas
      commodity prices. These agreements are also designated as cash flow hedges
      under
      SFAS 133.





Currency
      Exchange Rate Risk





*CE Electric UK*





MEHC
      is
      exposed to foreign currency risk from investments in businesses owned and
      operated by CE Electric UK. At December 31, 2005, MEHC’s primary foreign
      currency rate exposures were with the sterling. A 10% devaluation in the
      currency exchange rate would result in the Company’s consolidated balance sheet
      being negatively impacted by a $132.3 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 $21.0 million in 2005.





CE
      Electric UK has entered into certain currency rate swap agreements for its
      senior notes and Yankee bonds with large multi-national financial institutions.
      The swap agreements effectively convert the U.S. dollar fixed interest rate
      to a
      fixed rate in sterling for $237.0 million of 6.995% senior notes and
      $281.0 million of 6.496% Yankee bonds outstanding at December 31,
      2005. The agreements extend until December 30, 2007 and February 25,
      2008, respectively. The estimated fair value of these swap agreements at
      December 31, 2005 and 2004, was $77.5 million and $131.8 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.





A
      10%
      devaluation of the U.S. dollar versus sterling from the value at
      December 31, 2005 would increase the amount owed by the Company if these
      swap agreements were terminated by approximately
      $62.0 million.





*CalEnergy
      Generation-Foreign*





CalEnergy
      Generation-Foreign has mitigated a significant portion of its foreign currency
      risk as PNOC-EDC’s and NIA’s obligations under the project agreements are
      substantially denominated in U.S. dollars.





62


Interest
      Rate Risk





At
      December 31, 2005, the Company had fixed-rate long-term debt of
      $11,348.0 million in aggregate principal amount and having a fair value of
      $12,066.0 million. These instruments are fixed-rate and therefore do not
      expose the Company to the risk of earnings loss due to changes in market
      interest rates. However, the fair value of these instruments would decrease
      by
      approximately $434 million if interest rates were to increase by 10% from
      their levels at December 31, 2005. In general, such a decrease in fair
      value would impact earnings and cash flows only if the Company were to reacquire
      all or a portion of these instruments prior to their maturity.





At
      December 31, 2004, the Company had fixed-rate long-term debt of
      $11,503.4 million in aggregate principal amount and having a fair value of
      $12,416.2 million. These instruments were fixed-rate and therefore did not
      expose the Company to the risk of earnings loss due to changes in market
      interest rates.





At
      December 31, 2005, the Company had floating-rate obligations of
      $166.7 million that expose the Company to the risk of increased interest
      expense in the event of increases in short-term interest rates. These
      obligations are not hedged; however, any increase in floating rates would not
      have a material effect on the Company’s consolidated interest
      expense.





At
      December 31, 2004, the Company had floating-rate obligations of
      $493.4 million that exposed the Company to the risk of increased interest
      expense in the event of increases in short-term interest rates. These
      obligations were not hedged.





The
      Company may enter into contractual agreements to hedge exposure to interest
      rate
      risk. Changes in fair value of interest rate “locks” used as cash flow hedges
      are reported in accumulated other comprehensive income to the extent the hedge
      is effective until the forecasted transaction occurs, at which time they are
      recorded as adjustments to interest expense over the term of the related debt
      issuance. In May 2005, MEHC entered into a treasury rate lock agreement in
      the
      notional amount of $1.6 billion to protect against a rise in interest rates
      related to the anticipated financing of the PacifiCorp acquisition. At
      December 31, 2005, the market value of this agreement was
      zero.





Credit
      Risk





*Domestic
      Regulated Operations*





MidAmerican
      Energy’s utility operations grant unsecured credit to its retail electric and
      gas customers, substantially all of whom are local businesses and residents,
      which totaled $186.0 million at December 31, 2005. MidAmerican Energy
      also extends unsecured credit to other utilities, energy marketers, financial
      institutions and certain commercial and industrial end-users in conjunction
      with
      wholesale energy marketing activities. MidAmerican Energy analyzes the financial
      condition of each significant counterparty before entering into any
      transactions, establishes limits on the amount of unsecured credit to be
      extended to each counterparty, and evaluates the appropriateness of unsecured
      credit limits on a daily basis. MidAmerican Energy seeks to negotiate
      contractual arrangements with wholesale counterparties to provide for net
      settlement of monthly accounts receivable and accounts payable and net
      settlement of contracts for future performance in the event of default. At
      December 31, 2005, 84.4% of MidAmerican Energy’s credit exposure, net of
      collateral, from wholesale operations was with counterparties having “investment
      grade” credit ratings from Moody’s or Standard & Poor’s, while an additional
      7.4% of MidAmerican Energy’s credit exposure, net of collateral, from wholesale
      operations was with counterparties having financial characteristics deemed
      equivalent to “investment grade” by 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 electric generating
      companies and energy marketing and trading companies in the western United
      States. 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.





63


*CE
      Electric UK*





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 or traders and sell the electricity to end-use
      customers, use Northern Electric’s and Yorkshire Electricity’s distribution
      networks pursuant to an industry standard “Distribution 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. Northern Electric’s and Yorkshire Electricity’s customers are
      concentrated in a small number of electricity supply businesses with Npower
      accounting for approximately 44% of distribution revenues in 2005. Ofgem has
      determined a framework which sets credit limits for each supply business 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 cover
      must be 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.





*CalEnergy
      Generation-Foreign*





PNOC-EDC’s
      and NIA’s obligations under the project agreements are the Leyte Projects’ and
      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
      obligations under the project agreements 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 CalEnergy Generation-Foreign was $312.3 million for the year ended
      December 31, 2005. The Leyte Projects’ agreements expire in June 2006
      and July 2007, respectively, while the Casecnan Project’s agreement expires in
      December 2021.





64


**Item
      8.** **Financial
      Statements and Supplementary
      Data.**








Report
                of Independent Registered Public Accounting
                Firm
            66Consolidated
                Balance Sheets as of December 31, 2005
                and 2004
            67Consolidated
                Statements of Operations for the Years
                Ended December 31, 2005, 2004 and 2003
            68Consolidated
                Statements of Stockholders’ Equity for
                the Years Ended December 31, 2005, 2004 and 2003
            69Consolidated
                Statements of Cash Flows for the Years Ended
                December 31, 2005, 2004 and 2003
            70Notes
                to Consolidated Financial
                Statements
            71





65








**REPORT
      OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
      FIRM**





To
      the
      Board of Directors and Stockholders


MidAmerican
      Energy Holdings Company


Des
      Moines, Iowa





We
      have
      audited the accompanying consolidated balance sheets of MidAmerican Energy
      Holdings Company and subsidiaries (the “Company”) as of December 31, 2005
      and 2004, and the related consolidated statements of operations, stockholders’
equity, and cash flows for each of the three years in the period ended
      December 31, 2005. Our audits also included the financial statement
      schedules listed in the Index at Item 15. These financial statements and
      financial statement schedules are the responsibility of the Company’s
      management. Our responsibility is to express an opinion on the financial
      statements and financial statement schedules based on our audits.





We
      conducted our audits in accordance with 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, 2005 and 2004, and the results of their
      operations and their cash flows for each of the three years in the period ended
      December 31, 2005, 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.





/s/  Deloitte
      & Touche LLP





Des
      Moines, Iowa


March 3,
      2006








66


**MIDAMERICAN
      ENERGY HOLDINGS COMPANY AND SUBSIDIARIES**


**CONSOLIDATED
      BALANCE SHEETS**


(Amounts
      in thousands)


**As
                of December 31,****2005**
            
            **2004****ASSETS**Current
                assets:Cash
                and cash equivalents
            
            $
            357,845
            
            $
            837,353Short-term
                investments
            
            
            38,393
            
            
            123,550Restricted
                cash and short-term investments
            
            
            102,900
            
            
            129,316Accounts
                receivable, net
            
            
            802,599
            
            
            695,761Amounts
                held in trust
            
            
            108,546
            
            
            111,708Inventories
            
            
            128,184
            
            
            125,079Other
                current assets
            
            
            194,131
            
            
            141,194Total
                current assets
            
            
            1,732,598
            
            
            2,163,961Properties,
                plants and equipment, net
            
            
            11,915,413
            
            
            11,607,264Goodwill
            
            
            4,156,180
            
            
            4,306,751Regulatory
                assets
            
            
            441,098
            
            
            451,830Other
                investments
            
            
            798,683
            
            
            261,575Equity
                investments
            
            
            236,209
            
            
            216,935Deferred
                charges and other assets
            
            
            912,779
            
            
            895,246**Total
                assets**
            
            $
            20,192,960
            
            $
            19,903,562**LIABILITIES
                AND STOCKHOLDERS’ EQUITY**Current
                liabilities:Accounts
                payable
            
            $
            523,602
            
            $
            410,319Accrued
                interest
            
            
            198,263
            
            
            197,813Accrued
                property and other taxes
            
            
            189,099
            
            
            166,639Amounts
                held in trust
            
            
            108,546
            
            
            111,708Other
                liabilities
            
            
            451,018
            
            
            420,452Short-term
                debt
            
            
            70,066
            
            
            9,090Current
                portion of long-term debt
            
            
            313,661
            
            
            1,145,598Current
                portion of parent company subordinated debt
            
            
            234,021
            
            
            188,543Total
                current liabilities
            
            
            2,088,276
            
            
            2,650,162Other
                long-term accrued liabilities
            
            
            2,226,904
            
            
            2,171,616Parent
                company senior debt
            
            
            2,776,211
            
            
            2,771,957Parent
                company subordinated debt
            
            
            1,354,106
            
            
            1,585,810Subsidiary
                and project debt
            
            
            6,836,626
            
            
            6,304,923Deferred
                income taxes
            
            
            1,361,874
            
            
            1,281,833Total
                liabilities
            
            
            16,643,997
            
            
            16,766,301Deferred
                income
            
            
            53,931
            
            
            62,443Minority
                interest
            
            
            21,419
            
            
            14,119Preferred
                securities of subsidiaries
            
            
            88,362
            
            
            89,540Commitments
                and contingencies (Note 20)Stockholders’
                equity:Zero
                coupon convertible preferred stock - authorized 50,000 shares, no
                par
                value; 41,263 shares issued and outstanding
            
            
            -
            
            
            -Common
                stock - authorized 60,000 shares, no par value; 9,281 and 9,081 shares
                issued and outstanding at December 31, 2005 and 2004,
                respectively
            
            
            -
            
            
            -Additional
                paid-in capital
            
            
            1,963,343
            
            
            1,950,663Retained
                earnings
            
            
            1,719,497
            
            
            1,156,843Accumulated
                other comprehensive loss, net
            
            
            (297,589
            )
            
            (136,347
            )Total
                stockholders’ equity
            
            
            3,385,251
            
            
            2,971,159**Total
                liabilities and stockholders’ equity**
            
            $
            20,192,960
            
            $
            19,903,562





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





67


**MIDAMERICAN
      ENERGY HOLDINGS COMPANY AND SUBSIDIARIES**


**CONSOLIDATED
      STATEMENTS OF OPERATIONS**


(Amounts
      in thousands)





**Year
                Ended December 31,****2005**
            
            **2004**
            
            **2003****Operating
                revenue**
            
            $
            7,115,539
            
            $
            6,553,388
            
            $
            5,965,630**Costs
                and expenses:**Cost
                of sales
            
            
            3,284,876
            
            
            2,751,856
            
            
            2,400,536Operating
                expense
            
            
            1,693,783
            
            
            1,637,922
            
            
            1,512,345Depreciation
                and amortization
            
            
            608,198
            
            
            638,209
            
            
            602,934Total
                costs and expenses
            
            
            5,586,857
            
            
            5,027,987
            
            
            4,515,815**Operating
                income**
            
            
            1,528,682
            
            
            1,525,401
            
            
            1,449,815**Other
                income (expense):**Interest
                expense
            
            
            (890,979
            )
            
            (903,217
            )
            
            (760,956
            )Capitalized
                interest
            
            
            16,716
            
            
            20,040
            
            
            30,494Interest
                and dividend income
            
            
            58,070
            
            
            38,889
            
            
            47,908Other
                income
            
            
            74,516
            
            
            128,205
            
            
            96,643Other
                expense
            
            
            (22,127
            )
            
            (10,125
            )
            
            (5,913
            )Total
                other income (expense)
            
            
            (763,804
            )
            
            (726,208
            )
            
            (591,824
            )**Income
                from continuing operations before income tax expense, minority interest
                and preferred dividends of subsidiaries and equity
                income**
            
            
            764,878
            
            
            799,193
            
            
            857,991Income
                tax expense
            
            
            244,709
            
            
            264,986
            
            
            270,276Minority
                interest and preferred dividends of subsidiaries
            
            
            15,962
            
            
            13,301
            
            
            183,203**Income
                from continuing operations before equity income**
            
            
            504,207
            
            
            520,906
            
            
            404,512Equity
                income
            
            
            53,313
            
            
            16,861
            
            
            38,224**Income
                from continuing operations**
            
            
            557,520
            
            
            537,767
            
            
            442,736Income
                (loss) from discontinued operations, net of tax (Note 17)
            
            
            5,134
            
            
            (367,561
            )
            
            (27,118
            )**Net
                income available to common and preferred
                stockholders**
            
            $
            562,654
            
            $
            170,206
            
            $
            415,618





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


68


**MIDAMERICAN
      ENERGY HOLDINGS COMPANY AND SUBSIDIARIES**


**CONSOLIDATED
      STATEMENTS OF STOCKHOLDERS’
EQUITY**


**FOR
      THE THREE YEARS ENDED DECEMBER 31, 2005**


(Amounts
      in thousands)





**Accumulated****Outstanding**
            
            
            
            **Additional**
            
            
            
            **Other****Common**
            
            **Common**
            
            **Paid-in**
            
            **Retained**
            
            **Comprehensive****Shares**
            
            **Stock**
            
            **Capital**
            
            **Earnings**
            
            **Loss**
            
            **Total****Balance,
                January 1, 2003**
            
            
            9,281
            
            $
            -
            
            $
            1,956,509
            
            $
            584,009
            
            $
            (246,235
            )
            $
            2,294,283Net
                income
            
            
            -
            
            
            -
            
            
            -
            
            
            415,618
            
            
            -
            
            
            415,618Other
                comprehensive income:Foreign
                currency translation adjustment
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            58,148
            
            
            58,148Fair
                value adjustment on cash flow hedges, net of tax of $7,202
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            16,769
            
            
            16,769Minimum
                pension liability adjustment, net of tax of $(6,425)
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            (14,989
            )
            
            (14,989
            )Unrealized
                gains on securities, net of tax of $566
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            848
            
            
            848Total
                comprehensive income
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            476,394Other
                equity transactions
            
            
            -
            
            
            -
            
            
            768
            
            
            -
            
            
            -
            
            
            768**Balance**,**December
                31, 2003**
            
            
            9,281
            
            
            -
            
            
            1,957,277
            
            
            999,627
            
            
            (185,459
            )
            
            2,771,445Net
                income
            
            
            -
            
            
            -
            
            
            -
            
            
            170,206
            
            
            -
            
            
            170,206Other
                comprehensive income:Foreign
                currency translation adjustment
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            107,370
            
            
            107,370Fair
                value adjustment on cash flow hedges, net of tax of
                $(6,069)
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            (12,270
            )
            
            (12,270
            )Minimum
                pension liability adjustment, net of tax of $(19,898)
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            (46,429
            )
            
            (46,429
            )Unrealized
                gains on securities, net of tax of $294
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            441
            
            
            441Total
                comprehensive income
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            219,318Common
                stock purchase
            
            
            (200
            )
            
            -
            
            
            (7,010
            )
            
            (12,990
            )
            
            -
            
            
            (20,000
            )Other
                equity transactions
            
            
            -
            
            
            -
            
            
            396
            
            
            -
            
            
            -
            
            
            396**Balance,
                December 31, 2004**
            
            
            9,081
            
            
            -
            
            
            1,950,663
            
            
            1,156,843
            
            
            (136,347
            )
            
            2,971,159Net
                income
            
            
            -
            
            
            -
            
            
            -
            
            
            562,654
            
            
            -
            
            
            562,654Other
                comprehensive income:Foreign
                currency translation adjustment
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            (186,156
            )
            
            (186,156
            )Fair
                value adjustment on cash flow hedges, net of tax of
                $(9,828)
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            (19,541
            )
            
            (19,541
            )Minimum
                pension liability adjustment, net of tax of $17,994
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            43,724
            
            
            43,724Unrealized
                gains on securities, net of tax of $487
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            731
            
            
            731Total
                comprehensive income
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            401,412Exercise
                of common stock options
            
            
            200
            
            
            -
            
            
            5,801
            
            
            -
            
            
            -
            
            
            5,801Tax
                benefit from exercise of common stock options
            
            
            -
            
            
            -
            
            
            6,236
            
            
            -
            
            
            -
            
            
            6,236Other
                equity transactions
            
            
            -
            
            
            -
            
            
            643
            
            
            -
            
            
            -
            
            
            643**Balance,
                December 31, 2005**
            
            
            9,281
            
            $
            -
            
            $
            1,963,343
            
            $
            1,719,497
            
            $
            (297,589
            )
            $
            3,385,251





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


69


**MIDAMERICAN
      ENERGY HOLDINGS COMPANY AND SUBSIDIARIES**


**CONSOLIDATED
      STATEMENTS OF CASH FLOWS**


(Amounts
      in thousands)


**Year
                Ended December 31,****2005**
            
            **2004**
            
            **2003****Cash
                flows from operating activities:**Income
                from continuing operations
            
            $
            557,520
            
            $
            537,767
            
            $
            442,736Adjustments
                to reconcile income from continuing operations to cash flows from
                continuing operations:Distributions
                less income on equity investments
            
            
            (18,927
            )
            
            20,022
            
            
            40,160Gain
                on other items, net
            
            
            (6,338
            )
            
            (71,757
            )
            
            (29,264
            )Depreciation
                and amortization
            
            
            608,198
            
            
            638,209
            
            
            602,934Amortization
                of regulatory assets and liabilities
            
            
            38,725
            
            
            (1,586
            )
            
            (14,363
            )Amortization
                of deferred financing costs
            
            
            16,110
            
            
            20,875
            
            
            27,748Provision
                for deferred income taxes
            
            
            129,964
            
            
            176,591
            
            
            220,136Other
            
            
            (37,690
            )
            
            16,981
            
            
            8,211Changes
                in other items:Accounts
                receivable and other current assets
            
            
            (136,013
            )
            
            (43,600
            )
            
            (25,900
            )Accounts
                payable and other accrued liabilities
            
            
            167,351
            
            
            171,457
            
            
            (17,835
            )Deferred
                income
            
            
            (7,832
            )
            
            (6,465
            )
            
            (9,344
            )Net
                cash flows from continuing operations
            
            
            1,311,068
            
            
            1,458,494
            
            
            1,245,219Net
                cash flows from discontinued operations
            
            
            (262
            )
            
            (33,846
            )
            
            (27,296
            )Net
                cash flows from operating activities
            
            
            1,310,806
            
            
            1,424,648
            
            
            1,217,923**Cash
                flows from investing activities:**Capital
                expenditures relating to operating projects
            
            
            (796,319
            )
            
            (778,300
            )
            
            (616,804
            )Construction
                and other development costs
            
            
            (399,918
            )
            
            (401,090
            )
            
            (602,564
            )Purchases
                of available-for-sale securities
            
            
            (2,842,392
            )
            
            (2,819,701
            )
            
            (1,937,834
            )Proceeds
                from sale of available-for-sale securities
            
            
            2,913,060
            
            
            2,737,999
            
            
            1,900,152Purchase
                of other investments
            
            
            (556,590
            )
            
            -
            
            
            -Proceeds
                from sale of other investments
            
            
            -
            
            
            -
            
            
            288,750Acquisitions,
                net of cash acquired
            
            
            (10,247
            )
            
            (36,706
            )
            
            (54,263
            )Proceeds
                from sale of assets
            
            
            102,825
            
            
            8,602
            
            
            13,113Proceeds
                from notes receivable
            
            
            -
            
            
            169,210
            
            
            -Proceeds
                from (purchase of) affiliate notes
            
            
            4,391
            
            
            14,118
            
            
            (32,406
            )(Increase)
                decrease in restricted cash and investments
            
            
            26,652
            
            
            (18,455
            )
            
            (60,426
            )Other
            
            
            775
            
            
            25,257
            
            
            19,976Net
                cash flows from continuing operations
            
            
            (1,557,763
            )
            
            (1,099,066
            )
            
            (1,082,306
            )Net
                cash flows from discontinued operations
            
            
            6,423
            
            
            966
            
            
            (11,666
            )Net
                cash flows from investing activities
            
            
            (1,551,340
            )
            
            (1,098,100
            )
            
            (1,093,972
            )**Cash
                flows from financing activities:**Proceeds
                from subsidiary and project debt
            
            
            1,050,578
            
            
            375,351
            
            
            1,157,649Proceeds
                from parent company senior debt
            
            
            -
            
            
            249,765
            
            
            449,295Repayments
                of subsidiary and project debt
            
            
            (875,433
            )
            
            (368,417
            )
            
            (1,490,986
            )Repayments
                of parent company senior and subordinated debt
            
            
            (448,544
            )
            
            (100,000
            )
            
            (412,551
            )Net
                proceeds from (repayment of) subsidiary short-term debt
            
            
            10,443
            
            
            (43,949
            )
            
            (31,750
            )Net
                proceeds from parent company revolving credit facility
            
            
            51,000
            
            
            -
            
            
            -Purchase
                and retirement of common stock
            
            
            -
            
            
            (20,000
            )
            
            -Other
            
            
            (7,193
            )
            
            (60,868
            )
            
            (28,306
            )Net
                cash flows from continuing operations
            
            
            (219,149
            )
            
            31,882
            
            
            (356,649
            )Net
                cash flows from discontinued operations
            
            
            -
            
            
            (137,297
            )
            
            (1,407
            )Net
                cash flows from financing activities
            
            
            (219,149
            )
            
            (105,415
            )
            
            (358,056
            )Effect
                of exchange rate changes
            
            
            (19,825
            )
            
            28,531
            
            
            27,364**Net
                change in cash and cash equivalents**
            
            
            (479,508
            )
            
            249,664
            
            
            (206,741
            )**Cash
                and cash equivalents at beginning of period**
            
            
            837,353
            
            
            587,689
            
            
            794,430**Cash
                and cash equivalents at end of period**
            
            $
            357,845
            
            $
            837,353
            
            $
            587,689





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





70


**MIDAMERICAN
      ENERGY HOLDINGS COMPANY AND SUBSIDIARIES**


**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS**





**1.** **Organization
      and Operations**





MidAmerican
      Energy Holdings Company (“MEHC”) and its subsidiaries (together with MEHC, the
“Company”) are organized and managed as seven distinct platforms: MidAmerican
      Funding, LLC (“MidAmerican Funding”) (which primarily includes MidAmerican
      Energy Company (“MidAmerican Energy”)), Kern River Gas Transmission Company
      (“Kern River”), Northern Natural Gas Company (“Northern Natural Gas”), 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 (the subsidiaries owning the Upper Mahiao, Malitbog and
      Mahanagdong Projects (collectively the “Leyte Projects”) and the Casecnan
      Project), CalEnergy Generation-Domestic (the subsidiaries 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 a combined electric and natural gas
      utility company in the United States, two natural gas pipeline companies in
      the
      United States, two electricity distribution companies in Great Britain, a
      diversified portfolio of domestic and international independent power projects
      and the second largest residential real estate brokerage firm in the United
      States.





On
      March 14, 2000, MEHC and an investor group including Berkshire Hathaway
      Inc. (“Berkshire Hathaway”), Walter Scott, Jr., a director of MEHC, David L.
      Sokol, Chairman and Chief Executive Officer of MEHC, and Gregory E. Abel,
      President and Chief Operating Officer of MEHC, executed a definitive agreement
      and plan of merger whereby the investor group acquired all of the outstanding
      common stock of MEHC (the “Teton Transaction”). As of December 31, 2005
      Walter Scott, Jr. (including family members and related entities), Berkshire
      Hathaway, David L. Sokol and Gregory E. Abel owned 86.2%, 9.7%,
      3.5% and 0.6%, respectively, of MEHC’s voting common stock and held diluted
      ownership interests of 15.3%, 80.5%, 2.9% and 1.3%, respectively (see Note
      3).





In
      connection with the Teton Transaction, MEHC issued 34.6 million shares of
      no par, zero-coupon convertible preferred stock valued at $1,211.4 million
      to Berkshire Hathaway. In connection with the Kern River acquisition and the
      purchase of $275.0 million of The Williams Companies, Inc. (“Williams”)
      preferred stock, MEHC issued 6.7 million shares of no par, zero-coupon
      convertible preferred stock valued at $402.0 million to Berkshire Hathaway.
      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. Additionally, the
      prior approval of the holders of convertible preferred stock was required for
      certain fundamental transactions by MEHC. Such transactions include, among
      others: (a) significant asset sales or dispositions; (b) merger transactions;
      (c) significant business acquisitions or capital expenditures; (d) issuances
      or
      repurchases of equity securities; and (e) the removal or appointment of the
      Chief Executive Officer.





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





71


**2.**
            **Summary
                of Significant Accounting
                Policies**





*Principles
      of Consolidation*





The
      consolidated financial statements include the accounts of MEHC and its
      wholly-owned subsidiaries, except for certain trusts formed to hold trust
      preferred securities which were deconsolidated under Financial Accounting
      Standards Board (“FASB”) Interpretation No. 46R, “Consolidation of Variable
      Interest Entities, an interpretation of Accounting Research Bulletin No. 51”
(“FIN 46R”). Subsidiaries which are less than 100% owned but greater than 50%
      owned are consolidated with a minority interest. Subsidiaries that are 50%
      owned
      or less, but where the Company has the ability to exercise significant
      influence, are accounted for under the equity method of accounting. Investments
      where the Company’s ability to influence is limited are accounted for under the
      cost method of accounting. All inter-enterprise transactions and accounts have
      been eliminated. The results of operations of the Company include the Company’s
      proportionate share of results of operations of entities acquired from the
      date
      of each acquisition for purchase business combinations.





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





*Reclassifications*





Certain
      amounts in the fiscal 2004 and 2003 consolidated financial statements and
      supporting note disclosures have been reclassified to conform to the fiscal
      2005
      presentation, including the reclassifications of changes in restricted cash
      and
      investments and auction rate securities. Such reclassifications did not impact
      previously reported net income or retained earnings.





The
      accompanying consolidated statements of cash flows for the years ended
      December 31, 2004 and 2003 reflect a reclassification of changes in
      restricted cash and investments from a financing activity to an investing
      activity. This reclassification resulted in an increase in cash used in
      investing activities and a corresponding decrease in cash used in financing
      activities totaling $17.4 million and $68.3 million for the years
      ended December 31, 2004 and 2003, respectively.





The
      accompanying consolidated balance sheet as of December 31, 2004, reflects a
      reclassification of instruments used in the Company’s cash management program
      from cash and cash equivalents to short-term investments of $123.6 million.
      This reclassification is to present certain auction rate securities as
      short-term investments rather than as cash equivalents due to the stated
      maturities of these investments. Additionally, in the accompanying consolidated
      statements of cash flows, cash and cash equivalents were reduced by
      $123.6 million, $72.5 million and $50.0 million at
      December 31, 2004, 2003 and 2002, respectively, to reflect the
      reclassification of these instruments from cash and cash equivalents to
      short-term investments.





*Use
      of Estimates*





Preparation
      of the consolidated financial statements in conformity with accounting
      principles generally accepted in the United States of America requires
      management to make estimates and assumptions that affect the reported amounts
      of
      assets and liabilities and the disclosure of contingent assets and liabilities
      at the date of the consolidated financial statements and the reported amounts
      of
      revenue and expenses during the period. Management believes the most complex
      and
      sensitive judgments, because of their significance to the consolidated financial
      statements, result primarily from the need to make estimates about the effects
      of matters that are inherently uncertain. Actual results could differ materially
      from management’s estimates.





*Accounting
      for the Effects of Certain Types of Regulation*





MidAmerican
      Energy, Kern River and Northern Natural Gas prepare their financial statements
      in accordance with the provisions of Statement of Financial Accounting Standards
      (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation”
(“SFAS 71”), which differs in certain respects from the application of generally
      accepted accounting principles by non-regulated businesses. In general, SFAS
      71
      recognizes that accounting for rate-regulated enterprises should reflect the
      economic effects of regulation. As a result, a regulated entity is required
      to
      defer the recognition of costs (a regulatory asset) or the recognition of
      obligations (a regulatory liability) if it is probable that, through the
      rate-making process, there will be a corresponding increase or decrease in
      future rates. Accordingly, MidAmerican Energy, Kern River and Northern Natural
      Gas have deferred certain costs and accrued certain obligations, which will
      be
      amortized over various future periods. The Company periodically evaluates the
      applicability of SFAS 71 and considers factors such as regulatory changes and
      the impact of competition. If cost-based regulation ends or competition
      increases, the Company may have to reduce its asset balances to reflect a market
      basis less than cost and write-off the associated regulatory assets and
      liabilities.





72


Management
      continually assesses whether the regulatory assets are probable of future
      recovery by considering factors such as applicable regulatory environment
      changes, recent rate orders received by other regulated entities, and the status
      of any pending or potential deregulation legislation. Based upon this continual
      assessment, management believes the existing regulatory assets are probable
      of
      recovery. If future recovery of costs ceases to be probable, the asset and
      liability write-offs would be required to be recognized in operating
      income.





*Revenue
      Recognition*





*Electric
      and Natural Gas Retail Revenues and Electric Distribution
      Revenues*





Revenue
      is recorded based upon services rendered and electricity and natural gas
      delivered, distributed or supplied to the end of the period. MidAmerican Energy
      records unbilled revenue representing the estimated amounts customers will
      be
      billed between the meter reading dates in a particular month and the end of
      that
      month. The distribution businesses in Great Britain record unbilled revenue
      representing the estimated amounts that customers will be billed for electricity
      distributed during the period based upon information received from the national
      settlement system.





In
      the
      distribution businesses in Great Britain, revenue is not recognized when
      billings for electric distribution services exceed the maximum related amounts
      available under the regulatory formula. This over recovered amount is deducted
      from revenue and included in other liabilities and is available to be earned
      throughout the remainder of the current or future regulatory periods. Where
      there is an under recovered position (billings are less than the maximum related
      amounts available under the regulatory formula), no anticipation of any
      potential future recovery is made and revenue is recognized based upon the
      estimated billed amounts.





*Natural
      Gas Transportation and Storage*





The
      majority of the pipelines’ transportation and storage revenues are derived from
      firm reservation charges which are fixed based on contractual quantities and
      rates. The remaining revenue, consisting primarily of commodity charges, is
      based on contractual rates and actual or estimated usage based on scheduled
      quantities and is subject to estimates including estimates of meter reading
      and
      loss and unaccounted for volumes.





Kern
      River and Northern Natural Gas are subject to the Federal Energy Regulatory
      Commission’s (“FERC”) regulations and, accordingly, certain revenue collected
      may be subject to possible refunds upon final orders in pending rate
      proceedings. Kern River and Northern Natural Gas may record revenue that is
      subject to refund based on their best estimates of the final outcomes of these
      proceedings and other third party regulatory proceedings, advice of counsel
      and
      estimated total exposure, as well as collection and other risks. Estimates
      of
      any refunds are recorded in other current liabilities in the accompanying
      consolidated balance sheets.





*Philippine
      Contracts*





The
      Company invoices its customers, which consist of the Philippine National Oil
      Company-Energy Development Corporation (“PNOC-EDC”) for the Leyte Projects and
      the Philippine National Irrigation Administration (“NIA”) for the Casecnan
      Project, on a monthly basis for the delivery of electricity and water pursuant
      to the provisions of their respective project agreements. The project agreements
      are accounted for as arrangements that contain both an operating lease and
      a
      service contract to operate the projects. The project agreements were classified
      as operating leases due to significant uncertainties that existed at the
      inception of the leases regarding both the collection of future amounts and
      the
      amount of unreimbursable costs yet to be incurred mainly due to the existence
      of
      political, economic and other uncertainties associated with the Philippines.
      The
      Leyte Projects’ primary source of revenue is from capacity fees recognized on a
      straight-line basis over the cooperation periods and subject to semi-annual
      adjustment pursuant to changes in the United States producer price
      index.




73


Additionally,
      for the Casecnan Project, the annual water delivery revenue is recorded on
      the
      basis of the contractual minimum guaranteed water delivery threshold for the
      respective contract year. If and when actual cumulative deliveries within a
      contract year exceed the minimum threshold, additional revenue is recognized
      and
      calculated as the product of the water deliveries in excess of the minimum
      threshold and the applicable unit price up to the maximum contractually allowed
      water delivery volume. The Company defers revenue recognition on the difference
      between the actual water delivery fees earned and water delivery fees invoiced
      pursuant to the project agreement. Revenue from electricity consists of
      guaranteed energy fees, recognized on a straight-line basis over the cooperation
      period, and a variable energy fee. The variable energy fee is recognized when
      deliveries of energy exceed the guaranteed energy in any contract
      year.


*Retail
      Commission Revenue and Related Fees*





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 the closing. Loan origination and commitment fees
      received in connection with the origination of mortgage loans and certain direct
      loan origination costs are deferred until such loans are sold to investors.
      Fees
      related to brokered loan originations are recognized at closing, which is when
      services have been provided.





*Short-term
      Investments*





As
      of
      December 31, 2005 and 2004, the Company had $38.4 million and
      $123.6 million, respectively, of short-term investments consisting
      primarily of auction rate securities. These instruments are classified as
      available-for-sale securities as management does not intend to hold them to
      maturity nor are they bought and sold with the objective of generating profits
      on short-term differences in price. The carrying value of these instruments
      approximates their fair value.





*Restricted
      Cash and Investments*





The
      restricted cash and investments balance recorded separately in restricted cash
      and short-term investments and in deferred charges and other assets, was
      $136.7 million and $164.5 million at December 31, 2005 and 2004,
      respectively, and includes commercial paper and money market securities. The
      balance is mainly composed of amounts deposited in restricted accounts relating
      to (i) the Company’s debt service reserve requirements relating to certain
      projects, (ii) customer deposits held in escrow, (iii) custody deposits, and
      (iv) unpaid dividends declared obligations. The debt service funds are
      restricted by their respective project debt agreements to be used only for
      the
      related project.





Investments
      which the Company has the positive intent and ability to hold to maturity are
      classified as held-to-maturity and carried at amortized cost. The carrying
      amount of held-to-maturity investments approximates their fair value.
      Investments which the Company intends to hold indefinitely, but not necessarily
      to maturity, are classified as available-for-sale and carried at fair value.
      Unrealized gains and losses on available-for-sale securities are reported as
      a
      separate component of stockholders’ equity, net of deferred taxes and
      reclassification adjustments, except for those available-for-sale securities
      that comprise MidAmerican Energy’s nuclear decommissioning trust funds, which
      are reported as an adjustment to regulatory assets or regulatory
      liabilities.





*Allowance
      for Doubtful Accounts*





The
      allowance for doubtful accounts is based on the Company’s assessment of the
      collectibility of payments from its customers. This assessment requires judgment
      regarding the outcome of pending disputes, arbitrations and the ability of
      customers to pay the amounts owed to the Company. At December 31, 2005 and
      2004, the allowance for doubtful accounts totaled $21.4 million and
      $26.0 million, respectively.





*Amounts
      Held in Trust*





Amounts
      held in trust consist of separately designated trust accounts for homebuyers’
earnest money and other deposits. The Company holds such funds until sold
      properties are closed and subsequently disburses amounts in accordance with
      the
      settlement instructions. The Company does not earn or pay interest on the
      amounts held in trust.





74


*Inventories*





Inventories
      consist mainly of materials and supplies, coal stocks, gas in storage and fuel
      oil, which are valued at the lower of cost, determined primarily using average
      cost, or market.





*Properties,
      Plants and Equipment, Net*





Properties,
      plants and equipment are recorded at historical cost. The Company capitalizes
      all construction related material and direct labor costs as well as indirect
      construction costs. Indirect construction costs include general engineering,
      taxes and costs of funds used during construction. The cost of major additions
      and betterments are capitalized, while replacements, maintenance, and repairs
      that do not improve or extend the lives of the respective assets are expensed.
      Depreciation is generally computed using the straight-line method based on
      economic lives or regulatorily mandated recovery periods. The Company believes
      the useful lives assigned to the depreciable assets, which generally range
      from
      3 to 67 years, are reasonable.





When
      the
      Company retires its regulated properties, plant and equipment, it charges the
      original cost plus the cost of retirement, less salvage value, to the cost
      of
      removal accrued regulatory liability. When it sells entire regulated, or retires
      or sells non-regulated, properties, plant and equipment, the original cost
      is
      removed from the property accounts and the related accumulated depreciation
      and
      amortization accounts are reduced. Any gain or loss is recorded as income,
      unless otherwise required by the applicable regulatory body.





The
      Company recognizes an asset retirement obligation (“ARO”) in accordance with
      SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), for
      legal obligations associated with the retirement of long-lived assets that
      result from the acquisition, construction, development and/or normal use of
      the
      assets. SFAS 143 requires that the fair value of a liability for an ARO be
      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. The difference between the ARO liability, the
      corresponding ARO net asset and amounts recovered from regulated customers
      to
      satisfy such liabilities is recorded as a regulatory asset or
      liability.





*Impairment
      of Long-Lived Assets*





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





*Goodwill*





The
      provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”),
      which establishes the accounting for acquired goodwill and other intangible
      assets, and provides that goodwill and indefinite-lived intangible assets will
      not be amortized, requires allocating goodwill to each reporting unit and
      testing for impairment using a two-step approach. The goodwill impairment test
      is performed annually or whenever an event has occurred that would more likely
      than not reduce the fair value of a reporting unit below its carrying amount.
      The Company completed its annual review pursuant to SFAS 142 for its reporting
      units as of October 31, 2005 primarily using a discounted cash flow
      methodology. No impairment was indicated as a result of these
      assessments.





The
      Company records goodwill adjustments for (i) changes in the estimates of 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.





75


*Deferred
      Financing Costs*





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





*Accruals
      for Loss Contingencies*





The
      Company establishes accruals for estimated loss contingencies, such as
      environmental, legal and regulatory matters, when it is management’s assessment
      that a loss is probable and the amount of the loss can be reasonably estimated.
      If the information available indicates that the amount of loss can only be
      estimated as a range of possible amounts with some amount within the range
      appearing to be a better estimate than any other amount within the range, that
      amount is accrued. If no specific amount within the range represents the most
      likely amount of loss, the minimum amount of the range is accrued. Accruals
      for
      loss contingencies are recorded in the period in which different facts or
      information become known or circumstances change that affect the previous
      assumptions with respect to the likelihood or amount of loss. Accruals for
      loss
      contingencies and subsequent revisions are reflected in income when accruals
      are
      recorded or as regulatory treatment dictates. Accruals for loss contingencies
      are based upon management’s assumptions and estimates, and advice of legal
      counsel or other third parties regarding the probable outcomes of the matter.
      Should the outcomes differ from the assumptions and estimates, revisions to
      the
      estimated accruals for loss contingencies would be required.





*Risk
      Management and Hedging Activities*




The
      Company employs a number of different derivative and non-derivative instruments
      in connection with its electric and natural gas, foreign currency exchange
      rate
      and interest rate risk management activities, including forward contracts,
      futures, swaps and options. All derivative instruments not designated and
      qualifying for the normal purchases and normal sales exceptions under SFAS
      133,
“Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as
      amended, are recorded on the consolidated balance sheet at their fair values
      as
      either assets or liabilities.





For
      all
      hedge contracts, the Company provides formal documentation of the hedge in
      accordance with SFAS 133. In addition, at inception and on a quarterly basis
      the
      Company formally assesses whether the hedge contract is highly effective in
      offsetting changes in cash flows or fair values of 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 statement of
      stockholders’ equity and comprehensive income as accumulated other comprehensive
      income (“AOCI”) until the hedged item is realized. 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 income. Gains
      and
      losses related to discontinued hedges that were previously accumulated in AOCI
      will remain in AOCI until the hedged item is realized, unless it is no longer
      probable that the hedged forecasted transaction will 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
      MidAmerican Energy are recoverable through retail rates. Accordingly, unrealized
      changes in fair value of these contracts are deferred as regulatory assets
      or
      liabilities pursuant to SFAS 71.





Derivative
      contracts for commodities used in the Company’s 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
      provided by SFAS 133. Recognition of these contracts in revenue or cost of
      sales
      in the consolidated statement of operations occurs when the contracts
      settle.





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 valuation
      techniques or models.





76


*Fair
      Value of Financial Instruments*





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





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





Investments - The
      fair value of all investments is primarily based on quoted market prices as
      provided by the third-party financial institution holding the
      investments.





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





Debt
      instruments - The
      fair value of all debt instruments has been estimated based upon quoted market
      prices as supplied by third-party broker dealers, where available, or at the
      present value of future cash flows discounted at rates consistent with
      comparable maturities with similar credit risks.





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





*Income
      Taxes*





MEHC
      and
      its subsidiaries file a consolidated U.S. federal income tax return and other
      state and federal jurisdictional returns as required. Deferred tax assets and
      liabilities are recognized based on the difference between the financial
      statement and tax basis of assets and liabilities using estimated tax rates
      in
      effect for the year in which the differences are expected to reverse. Based
      on
      existing regulatory precedent, MidAmerican Energy is not allowed to recognize
      state deferred income tax expense related to certain temporary differences
      resulting from accelerated tax depreciation and other property related basis
      differences. For these differences, MidAmerican Energy establishes deferred
      tax
      liabilities and regulatory assets on the consolidated balance sheets since
      MidAmerican Energy is allowed to recover the increased tax expense when these
      differences turn around. Investment tax credits have been deferred and are
      being
      amortized over the estimated useful lives of the related
      properties.





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. These
      earnings related to ongoing operations and were approximately $600 million
      at December 31, 2005. 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
      preparing the Company’s tax returns, management is required to interpret complex
      tax laws and regulations. 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 Internal Revenue
      Service has closed examination of the Company’s income tax returns through 1998.
      Although the ultimate resolution of the Company’s tax examinations is uncertain,
      the Company believes it has made adequate provisions for income tax payables
      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 condition, results of operations or cash flows. Tax
      contingency reserves are included in accrued property and other taxes and other
      long-term accrued liabilities, as appropriate, in the accompanying consolidated
      balance sheets.





77


*Allowance
      for Funds Used During Construction*





Allowance
      for funds used during construction (“AFUDC”) represents the approximate net
      composite interest cost of borrowed funds and a reasonable return on the equity
      funds used for construction. Although AFUDC increases both properties, plants
      and equipment and earnings, it is realized in cash through depreciation
      provisions included in rates for MidAmerican Energy, Kern River and Northern
      Natural Gas, the subsidiaries that apply SFAS 71. AFUDC for subsidiaries that
      apply SFAS 71 are capitalized as a component of construction in progress and
      will be amortized over the assets’ estimated useful lives.





*Other
      Comprehensive Income*





The
      differences between net income and total comprehensive income for the Company
      are due to foreign currency translation adjustments, minimum pension liability
      adjustments, unrealized holding gains and losses of marketable securities during
      the periods, and the effective portion of net gains and losses of derivative
      instruments classified as cash flow hedges. Reclassification adjustments
      resulting from gains and losses on sales of marketable securities and cash
      flow
      hedges included in net income for the years ended December 31, 2005, 2004
      and 2003 were not material.





*Consolidated
      Statements of Cash Flows*





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





The
      supplemental disclosures to the accompanying consolidated statements of cash
      flows were as follows (in thousands):





**Year
                Ended December 31,****2005**
            
            **2004**
            
            **2003**Interest
                paid, net of interest capitalized
            
            $
            844,719
            
            $
            855,399
            
            $
            656,152Income
                taxes (refunded) paid
            
            $
            60,483
            
            $
            (16,616
            )
            $
            9,911Non-cash
                transaction - ROP note received in NIA Arbitration
                Settlement
            
            $
            -
            
            $
            -
            
            $
            97,000





For
      the
      year ended December 31, 2003, $170.2 million of preferred dividends of
      subsidiaries was not included in cash paid for interest as the Company adopted
      and applied the provisions of FIN 46R, related to certain finance subsidiaries,
      as of October 1, 2003. The adoption required the deconsolidation of certain
      finance subsidiaries, which resulted in amounts that were previously recorded
      as
      minority interest and preferred dividends of subsidiaries being prospectively
      recorded as interest expense in the accompanying consolidated statements of
      operations. For the years ended December 31, 2005 and 2004, and the
      three-month period ended December 31, 2003, the Company has recorded
      $184.4 million, $196.9 million and $49.8 million, respectively,
      of interest expense related to these securities. In accordance with the
      requirements of FIN 46R, no amounts prior to adoption of FIN 46R on
      October 1, 2003 have been reclassified.





*New
      Accounting Pronouncements*





In
      December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment” (“SFAS
      123R”), which replaces SFAS No. 123, “Accounting for Stock-Based Compensation,”
and supersedes Accounting Principles Board Opinion No. 25, “Accounting for Stock
      Issued to Employees.” SFAS 123R establishes standards for the accounting for
      transactions in which an entity exchanges its equity instruments for goods
      or
      services, primarily focusing on the accounting for transactions in which an
      entity obtains employee services in share-based payment transactions. SFAS
      123R
      requires entities to measure compensation costs for all share-based payments,
      including stock options, at fair value and expense such payments over the
      service period. Since MEHC is considered a nonpublic entity under the criteria
      of SFAS 123R, this standard is effective for annual period beginning after
      December 15, 2005. Adoption of this standard will not have an effect on the
      Company’s financial position, results of operations or cash flows as all of the
      Company’s outstanding stock options were fully vested at the date of issuance of
      SFAS 123R. Modifications to outstanding stock options after the effective date
      of the standard may result in additional compensation expense pursuant to the
      provisions of SFAS 123R.





78


**3.**
            **Recent
                Developments Involving PacifiCorp and Berkshire
                Hathaway**





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, a regulated electric utility providing service to approximately
      1.6 million customers in California, Idaho, Oregon, Utah, Washington and
      Wyoming. MEHC will purchase all of the outstanding shares of the PacifiCorp
      common stock for approximately $5.1 billion in cash. The long-term debt and
      preferred stock of PacifiCorp, which aggregated $4.3 billion at
      December 31, 2005, will remain outstanding. As of March 1, 2006, all
      state and federal approvals required for the acquisition were
      obtained, subject to  completion of a "most favored states"
      process in Wyoming, Washington, Utah, Idaho and Oregon that
      allows  each such state to  make applicable to that state
      any acquisition commitments or conditions accepted in other
      PacifiCorp states. Subject to the most favored states process and other
      customary closing conditions, the transaction is expected to close in March
      2006. MEHC expects to fund the acquisition of PacifiCorp with the proceeds
      from
      an investment by Berkshire Hathaway and other existing shareholders of
      approximately $3.4 billion in MEHC common stock and the issuance by MEHC of
      $1.7 billion of either additional common stock to Berkshire Hathaway or
      long-term senior notes to third parties.





On
      February 9, 2006, following the effective date of the repeal of PUHCA 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. As a consequence, Berkshire Hathaway owns 83.4% (80.5% on a diluted
      basis) of the outstanding common stock of MEHC, will consolidate the Company
      in
      its financial statements as a majority-owned subsidiary, and will include the
      Company in its consolidated federal U.S. income tax return.





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, and will not be used for the PacifiCorp acquisition
      or for other future acquisitions.





On
      March 2, 2006, MEHC amended its Articles of Incorporation to (i) increase
      the amount of its common stock authorized for issuance to 115.0 million shares
      and (ii) no longer provide for the authorization to issue any preferred stock
      of
      MEHC.





**4.**
            **Properties,
                Plants and Equipment, Net**





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





**Depreciation****Life**
            
            **2005**
            
            **2004**Utility
                generation and distribution system
            
            
            10-50
                years
            
            $
            10,499,120
            
            $
            10,230,628Interstate
                pipelines’ assets
            
            
            3-67
                years
            
            
            3,700,073
            
            
            3,566,578Independent
                power plants
            
            
            10-30
                years
            
            
            1,384,553
            
            
            1,384,660Other
                assets
            
            
            3-30
                years
            
            
            476,488
            
            
            472,744Total
                operating assets
            
            
            
            
            
            16,060,234
            
            
            15,654,610Accumulated
                depreciation and amortization
            
            
            
            
            
            (4,992,431
            )
            
            (4,620,007
            )Net
                operating assets
            
            
            
            
            
            11,067,803
            
            
            11,034,603Construction
                in progress
            
            
            
            
            
            847,610
            
            
            572,661Properties,
                plants and equipment, net
            
            
            
            
            $
            11,915,413
            
            $
            11,607,264





The
      utility generation and distribution system and interstate pipelines’ assets are
      the regulated assets of MidAmerican Energy, Kern River, Northern Natural Gas
      and
      CE Electric UK. At December 31, 2005 and 2004, accumulated
      depreciation and amortization related to the Company’s regulated assets totaled
      $4.1 billion and $3.8 billion, respectively. Additionally,
      substantially all of the construction in progress at December 31, 2005 and
      2004 relates to the construction of regulated assets.





79


Northern
      Natural Gas entered into a purchase and sale agreement (“PSA”) relative to the
      West Hugoton non-strategic section of its interstate pipeline system in the
      fourth quarter of 2005. As a result of entering into the PSA, Northern Natural
      Gas recognized a non-cash impairment charge of $29.0 million ($17.5 million
      after-tax), in accordance with SFAS No. 144, “Accounting for the Impairment of
      Long-Lived Assets” (“SFAS 144”), to write down the carrying value of the West
      Hugoton pipeline to its fair value. The fair value was determined based on
      the
      sale price agreed to in the PSA. The impairment charge is recorded in operating
      expense in the accompanying consolidated statement of operations for the year
      ended December 31, 2005.





**5.**
            **Regulatory
                Assets and Liabilities**





The
      components of the Company’s regulatory assets consist of the following as of
      December 31 (in thousands):





**As
                of December 31,****Weighted
                Average****Remaining
                Life**
            
            **2005**
            
            **2004**Deferred
                income taxes, net
            
            
            27
                years
            
            $
            173,864
            
            $
            160,662Computer
                systems development costs(1)
                (2)
            
            
            6
                years
            
            
            54,446
            
            
            63,637Unrealized
                loss on regulated hedges
            
            
            1
                year
            
            
            45,431
            
            
            36,794System
                levelized account(1)
                (2)
            
            
            2
                years
            
            
            26,543
            
            
            53,576Pipe
                recoating and reconditioning costs(1)
            
            
            67
                years
            
            
            23,256
            
            
            22,406Asset
                retirement obligations
            
            
            8
                years
            
            
            20,979
            
            
            20,875Postretirement
                benefit costs
            
            
            7
                years
            
            
            20,066
            
            
            22,933Debt
                refinancing costs
            
            
            8
                years
            
            
            11,998
            
            
            15,365Minimum
                pension liability adjustment
            
            
            17
                years
            
            
            11,694
            
            
            18,203Migration
                and pipeline system upgrade costs(1)
            
            
            9
                years
            
            
            10,508
            
            
            10,480Nuclear
                generation assets(1)
            
            
            14
                years
            
            
            6,487
            
            
            6,727Environmental
                costs
            
            
            1
                year
            
            
            4,907
            
            
            9,284Other
            
            
            Various
            
            
            30,919
            
            
            10,888Total
            
            
            
            
            $
            441,098
            
            $
            451,830





(1) These
      regulatory assets are included in rate base and earn a return.





(2) The
      return earned on these regulatory assets is less than the stipulated
      return.





The
      components of the Company’s regulatory liabilities, which are included in other
      long-term accrued liabilities in the accompanying consolidated balance sheets,
      consist of the following as of December 31 (in thousands):





**As
                of December 31,****Weighted
                Average****Remaining
                Life**
            
            **2005**
            
            **2004**Cost
                of removal accrual(1)
            
            
            27
                years
            
            $
            448,493
            
            $
            428,719Iowa
                electric settlement accrual(1)
            
            
            2
                years
            
            
            213,135
            
            
            181,188Asset
                retirement obligations(1)
            
            
            32
                years
            
            
            65,966
            
            
            53,259Unrealized
                gain on regulated hedges
            
            
            1
                year
            
            
            29,648
            
            
            7,462Other
            
            
            Various
            
            
            16,616
            
            
            12,139Total
            
            
            
            
            $
            773,858
            
            $
            682,767





(1) These
      regulatory liabilities are deducted from rate base or otherwise accrue a
      carrying cost.





Refer
      to
      Note 12 for a discussion of the cost of removal accrual and asset retirement
      obligations and to Note 19 regarding the Iowa electric settlement
      accrual.





80


**6.**
            **Other
                Investments**





Other
      investments are classified as non-current in the accompanying consolidated
      balance sheets as management does not intend to use them in current operations.
      Gross unrealized gains and losses of other investments are not material at
      December 31, 2005 and 2004. Other investments consist of the following (in
      thousands):





**2005**
            
            **2004**Guaranteed
                investment contracts
            
            $
            516,330
            
            $
            -Nuclear
                decommissioning trust fund
            
            
            228,070
            
            
            207,464CE
                Generation, LLC ("CE Generation") and Salton Sea Funding Corporation
                bonds
            
            
            23,244
            
            
            27,641Other
            
            
            31,039
            
            
            26,470Total
                other investments
            
            $
            798,683
            
            $
            261,575





In
      May
      2005, certain indirect wholly-owned subsidiaries of CE Electric UK
      purchased £300.0 million of fixed rate guaranteed investment contracts
      (£100.0 million at 4.75% and £200.0 million at 4.73%) with a portion
      of the proceeds of the issuance of £350.0 million of 5.125% bonds due in
      2035. These guaranteed investment contracts mature in December 2007
      (£100.0 million) and February 2008 (£200.0 million), respectively, the
      proceeds of which will be used to repay certain long-term debt of subsidiaries
      of CE Electric UK. The guaranteed investment contracts are reported at
      cost.





MidAmerican
      Energy has established trusts for the investment of funds for decommissioning
      the Quad Cities Station. These investments in debt and equity securities are
      classified as available-for-sale and are reported at fair value. An amount
      equal
      to the net unrealized gains and losses on those investments is recorded as
      an
      adjustment to regulatory assets or regulatory liabilities in the accompanying
      consolidated balance sheets. Funds are invested in the trust in accordance
      with
      applicable federal investment guidelines and are restricted for use as
      reimbursement for costs of decommissioning MidAmerican Energy’s Quad Cities
      Station. As of December 31, 2005, approximately 55.5% of the fair value of
      the trusts’ funds was invested in domestic common equity securities, 12.3% in
      domestic corporate debt and the remainder in investment grade municipal and
      U.S.
      Treasury bonds. As of December 31, 2004, approximately 55.3% of the fair
      value of the trusts’ funds was invested in domestic common equity securities,
      14.4% in domestic corporate debt and the remainder in investment grade municipal
      and U.S. Treasury bonds.





**7.** **Equity
      Investments**





Equity
      investments consist mainly of MEHC’s 50% investment in CE Generation and
      HomeServices’ equity investments in various entities that generally conduct
      title and mortgage activities primarily related to the real estate brokerage
      business. Equity investments and related equity income consist of the following
      (in thousands):





**As
                of December 31,****2005**
            
            **2004**MEHC’s
                investment in CE Generation
            
            $
            207,794
            
            $
            188,670HomeServices’
                equity investments
            
            
            18,739
            
            
            19,047Other
            
            
            9,676
            
            
            9,218Total
                equity investments
            
            $
            236,209
            
            $
            216,935**Year
                Ended December 31,****2005**
            
            
            **2004**
            
            
            **2003**MEHC’s
                investment in CE Generation
            
            $
            32,313
            
            $
            (1,542
            )
            $
            17,437HomeServices’
                equity investments
            
            
            19,971
            
            
            17,858
            
            
            23,138Other
            
            
            1,029
            
            
            545
            
            
            (2,351
            )Total
                equity income
            
            $
            53,313
            
            $
            16,861
            
            $
            38,224





81


The
      following is summarized financial information for CE Generation as of and for
      the years ended December 31 (in thousands):





**2005**
            
            **2004**
            
            **2003**Operating
                revenue
            
            $
            483,956
            
            $
            439,866
            
            $
            483,397Income
                (loss) before cumulative effect of change in accounting
                principle
            
            
            64,626
            
            
            (3,084
            )
            
            37,341Net
                income (loss)
            
            
            64,626
            
            
            (3,084
            )
            
            34,874Current
                assets
            
            
            151,363
            
            
            127,853Total
                assets
            
            
            1,418,099
            
            
            1,450,507Current
                liabilities
            
            
            120,888
            
            
            118,623Long-term
                debt, including current portion
            
            
            653,037
            
            
            722,650





CE
      Generation determined on December 9, 2004 that a portion of the carrying
      value of the Power Resources project’s long-lived assets was no longer
      recoverable. As a result, CE Generation recognized a non-cash impairment charge
      of $54.5 million ($33.5 million after-tax), in accordance with SFAS
      144, to write down the long-lived assets to their fair value. The fair value
      was
      determined based on discounted estimated cash flows from the future use of
      the
      long-lived assets. The impairment charge will not result in any current or
      future cash expenditures. MEHC’s $16.8 million after-tax portion of the
      Power Resources impairment is reflected in income on equity investments in
      the
      accompanying consolidated statement of operations for the year ended
      December 31, 2004.





The
      following is summarized financial information for HomeServices’ equity investees
      as of and for the years ended December 31 (in thousands):





**2005**
            
            **2004**
            
            **2003**Revenue
            
            $
            167,247
            
            $
            156,959
            
            $
            168,446Operating
                expense
            
            
            88,311
            
            
            80,997
            
            
            83,284Net
                income
            
            
            40,347
            
            
            36,473
            
            
            46,719Current
                assets
            
            
            52,749
            
            
            35,957Total
                assets
            
            
            134,146
            
            
            170,888Current
                liabilities
            
            
            44,317
            
            
            27,444Total
                liabilities
            
            
            101,034
            
            
            137,207





**8.**
            **Short-Term
                Debt**





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





**2005**
            
            **2004**MEHC
            
            $
            51,000
            
            $
            -CE
                Electric UK
            
            
            10,361
            
            
            38HomeServices
            
            
            8,705
            
            
            9,052Total
                short-term debt
            
            $
            70,066
            
            $
            9,090





*Parent
      Company Revolving Credit Facilities*





In
      the
      second quarter of 2005, the Company terminated its $100.0 million credit
      facility. On August 26, 2005, the Company closed on a new unsecured
      $400.0 million revolving credit facility which expires on August 26,
      2010. The facility supports letters of credit for the benefit of certain
      subsidiaries and affiliates of which $41.9 million were outstanding at
      December 31, 2005. Borrowings of $51.0 million were outstanding at
      December 31, 2005, and no borrowings were outstanding on the prior facility
      at December 31, 2004. The facility carries a variable interest rate based
      on LIBOR or a base rate, at MEHC’s option, plus a margin. The interest rate on
      the balance outstanding under the facility at December 31, 2005 was 4.85%.
      The prior facility was not drawn on during 2004. As of December 31, 2005,
      MEHC was in compliance with all covenants related to its revolving credit
      facility.


82


*MidAmerican
      Energy Revolving Credit Facilities and Short-Term Debt*





As
      of
      December 31, 2005, MidAmerican Energy has in place a $425.0 million
      revolving credit facility expiring on November 18, 2009, which supports its
      $304.6 million commercial paper program and its variable rate pollution
      control revenue obligations. 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 as of the last day of any
      quarter. In addition, MidAmerican Energy has a $5.0 million line of credit,
      which expires July 1, 2006. As of December 31, 2005 and 2004,
      MidAmerican Energy had no commercial paper or bank notes outstanding, and the
      full amount of the revolving credit facility and line of credit was available.
      As of December 31, 2005, MidAmerican Energy was in compliance with all
      covenants related to its short-term borrowings. At December 31, 2005, the
      credit facility had a variable interest rate based on LIBOR plus 0.40% and
      the
      line of credit had a variable interest rate based on LIBOR plus
      0.25%.





*CE
      Electric UK Revolving Credit Facilities*





On
      April 4, 2005, CE Electric UK closed on a new £100.0 million revolving
      credit facility which expires on April 4, 2010. The facility carries a
      variable interest rate based on sterling LIBOR plus a margin. Borrowings of
      $10.4 million were outstanding at December 31, 2005, at an interest
      rate of 5.14%. CE Electric UK also has a total of £35.0 million in
      uncommitted, variable rate, lines of credit, none of which were drawn on, at
      December 31, 2005.





*HomeServices
      Revolving Credit Facilities and Short-Term Debt*





HomeServices
      entered into a new $125.0 million senior revolving credit facility in
      December 2005, which expires in December 2010. This credit facility replaced
      the
      existing $125.0 million facility, which expired in November 2005. Amounts
      outstanding under the new revolving credit facility are unsecured and bear
      interest, at HomeServices’ option, at the prime lending rate or LIBOR plus a
      fixed spread of 0.5% to 1.125%, which varies based on HomeServices’ total debt
      ratio. The spread was 0.5% at December 31, 2005. No borrowings were
      outstanding at December 31, 2005 or, under the prior facility, at
      December 31, 2004.





Additionally,
      in 2005, HomeServices has in place a mortgage warehouse line of credit totaling
      $25.0 million, which expires in April 2006 and bears interest at LIBOR plus
      a margin ranging from 1.75% to 2.00% depending on the type of mortgage loan
      funded. The balance outstanding on this mortgage warehouse line of credit at
      December 31, 2005 was $8.7 million at a weighted average interest rate
      of 6.14%. In 2004, HomeServices had in place two mortgage warehouse lines of
      credit totaling $20.0 million, which expired in 2005. The balance
      outstanding on these mortgage warehouse lines of credit at December 31,
      2004, totaled $9.1 million at weighted average interest rates of 4.54% and
      4.21%, respectively.





**9.**
            **Parent
                Company Senior Debt**





Parent
      company senior debt represents unsecured senior obligations of MEHC and consists
      of the following, including fair value adjustments and unamortized premiums
      and
      discounts, at December 31 (in thousands):





**Par
                Value**
            
            **2005**
            
            **2004**7.23%
                Senior Notes, due 2005
            
            $
            -
            
            $
            -
            
            $
            258,7974.625%
                Senior Notes, due 2007
            
            
            200,000
            
            
            199,622
            
            
            199,4037.63%
                Senior Notes, due 2007
            
            
            350,000
            
            
            347,354
            
            
            346,0003.50%
                Senior Notes, due 2008
            
            
            450,000
            
            
            449,638
            
            
            449,4977.52%
                Senior Notes, due 2008
            
            
            450,000
            
            
            444,539
            
            
            442,8287.52%
                Senior Notes, due 2008 (Series B)
            
            
            100,000
            
            
            100,789
            
            
            101,0375.875%
                Senior Notes, due 2012
            
            
            500,000
            
            
            499,915
            
            
            499,9065.00%
                Senior Notes, due 2014
            
            
            250,000
            
            
            249,800
            
            
            249,7978.48%
                Senior Notes, due 2028
            
            
            475,000
            
            
            484,554
            
            
            484,692Total
                Parent Company Senior Debt
            
            $
            2,775,000
            
            $
            2,776,211
            
            $
            3,031,957





83


**10.**
            **Parent
                Company Subordinated Debt**





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





The
      financial terms of MEHC’s various subordinated debentures held by such Trusts
      are essentially identical to the corresponding terms of the mandatorily
      redeemable preferred securities issued by such Trusts (the “Trust
      Securities”).





Pursuant
      to Preferred Securities Guarantee Agreements (collectively, the “Guarantees”),
      between MEHC and a trustee, MEHC has agreed irrevocably to pay to the holders
      of
      the Trust Securities, to the extent that the applicable Trust has funds
      available to make such payments, quarterly distributions, redemption payments
      and liquidation payments on the Trust Securities. MEHC owns all of the common
      securities of the Trusts. The CalEnergy Capital and MidAmerican Capital Trust
      Securities have liquidation preferences of $50 and $25 each, respectively,
      (plus
      accrued and unpaid dividends thereon to the date of payment) and represent
      undivided beneficial ownership interests in each of the Trusts. The assets
      of
      the Trusts consist solely of Subordinated Debentures of MEHC (collectively,
      the
“Junior Debentures”) issued pursuant to their respective indentures. The
      indentures include agreements by MEHC to pay expenses and obligations incurred
      by the Trusts. Considered together, the undertakings contained in the
      Declarations, Junior Debentures, Indentures and Guarantees constitute full
      and
      unconditional guarantees on a subordinated basis by MEHC of the Trusts’
obligations under the Trust Securities.





Parent
      company subordinated debt consists of the following, including fair value
      adjustments, at December 31 (in thousands):





**Par
                Value**
            
            **2005**
            
            **2004**CalEnergy
                Capital Trust II - 6.25%, due 2012
            
            $
            104,645
            
            $
            92,724
            
            $
            91,328CalEnergy
                Capital Trust III - 6.5%, due 2027
            
            
            269,980
            
            
            206,175
            
            
            205,253MidAmerican
                Capital Trust I - 11%, due 2010
            
            
            409,295
            
            
            409,295
            
            
            454,772MidAmerican
                Capital Trust II - 11%, due 2011
            
            
            600,000
            
            
            600,000
            
            
            700,000MidAmerican
                Capital Trust III - 11%, due 2012
            
            
            279,933
            
            
            279,933
            
            
            323,000Total
                Parent Company Subordinated Debt
            
            $
            1,663,853
            
            $
            1,588,127
            
            $
            1,774,353





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





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





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





84


**11.**
            **Subsidiary
                and Project Debt**





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





The
      restrictions on distributions at these separate legal entities include various
      covenants including, but not limited to, leverage ratios, interest coverage
      ratios and debt service coverage ratios. As of December 31, 2005, the
      separate legal entities were in compliance with all applicable covenants.
      However, Cordova Energy’s 537 MW gas-fired power plant in the Quad Cities,
      Illinois area 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, at December 31 (in
      thousands):





**Par
                Value**
            
            **2005**
            
            **2004**MidAmerican
                Funding
            
            $
            700,000
            
            $
            648,390
            
            $
            645,926MidAmerican
                Energy
            
            
            1,637,118
            
            
            1,631,760
            
            
            1,422,527CE
                Electric UK
            
            
            2,346,459
            
            
            2,507,533
            
            
            2,571,889Kern
                River
            
            
            1,157,256
            
            
            1,157,256
            
            
            1,214,808Northern
                Natural Gas
            
            
            800,000
            
            
            799,560
            
            
            799,614CE
                Casecnan
            
            
            142,345
            
            
            140,635
            
            
            194,660Leyte
                Projects
            
            
            42,630
            
            
            42,630
            
            
            105,664Cordova
                Funding
            
            
            198,787
            
            
            196,210
            
            
            203,995HomeServices
            
            
            27,788
            
            
            26,313
            
            
            31,438Total
                Subsidiary and Project Debt
            
            $
            7,052,383
            
            $
            7,150,287
            
            $
            7,190,521





*MidAmerican
      Funding*





The
      components of MidAmerican Funding’s senior notes and bonds consist of the
      following, including fair value adjustments, at December 31 (in
      thousands):





**Par
                Value**
            
            **2005**
            
            **2004**6.339%
                Senior Notes, due 2009
            
            $
            175,000
            
            $
            167,903
            
            $
            166,0536.75%
                Senior Notes, due 2011
            
            
            200,000
            
            
            200,000
            
            
            200,0006.927%
                Senior Bonds, due 2029
            
            
            325,000
            
            
            280,487
            
            
            279,873Total
                MidAmerican Funding
            
            $
            700,000
            
            $
            648,390
            
            $
            645,926





The
      subsidiaries of MidAmerican Funding 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 its common equity level above 42% of total capitalization unless
      circumstances beyond its control result in the common equity level decreasing
      to
      below 39% of total capitalization. MidAmerican Energy must seek approval from
      the IUB of a reasonable utility capital structure if MidAmerican Energy’s common
      equity level decreases below 42% of total capitalization, unless the decrease
      is
      beyond the control of MidAmerican Energy. MidAmerican Energy is also required
      to
      seek the approval of the IUB if MidAmerican Energy’s equity level decreases to
      below 39%, even if the decrease is due to circumstances beyond the control
      of
      MidAmerican Energy.





85


*MidAmerican
      Energy*





The
      components of MidAmerican Energy’s mortgage bonds, pollution control revenue
      obligations and notes consist of the following, including unamortized premiums
      and discounts, at December 31 (in thousands):





**Par
                Value**
            
            **2005**
            
            **2004**Mortgage
                bonds, 7% Series, due 2005
            
            $
            -
            
            $
            -
            
            $
            90,497Pollution
                control revenue obligations:6.1%
                Series, due 2007
            
            
            1,000
            
            
            1,000
            
            
            1,0005.95%
                Series, due 2023, secured by general mortgage bonds
            
            
            29,030
            
            
            29,030
            
            
            29,030Variable
                rate series:Due
                2016 and 2017, 3.59% and 2.05%
            
            
            37,600
            
            
            37,600
            
            
            37,600Due
                2023, secured by general mortgage bonds, 3.59% and 2.05%
            
            
            28,295
            
            
            28,295
            
            
            28,295Due
                2023, 3.59% and 2.05%
            
            
            6,850
            
            
            6,850
            
            
            6,850Due
                2024, 3.59% and 2.05%
            
            
            34,900
            
            
            34,900
            
            
            34,900Due
                2025, 3.59% and 2.05%
            
            
            12,750
            
            
            12,750
            
            
            12,750Notes:6.375%
                Series, due 2006
            
            
            160,000
            
            
            159,969
            
            
            159,8935.125%
                Series, due 2013
            
            
            275,000
            
            
            274,581
            
            
            274,5214.65%
                Series, due 2014
            
            
            350,000
            
            
            349,721
            
            
            349,6896.75%
                Series, due 2031
            
            
            400,000
            
            
            395,628
            
            
            395,4595.75%
                Series, due 2035
            
            
            300,000
            
            
            299,743
            
            
            -Other
            
            
            1,693
            
            
            1,693
            
            
            2,043Total
                MidAmerican Energy
            
            $
            1,637,118
            
            $
            1,631,760
            
            $
            1,422,527





On
      November 1, 2005, MidAmerican Energy issued $300.0 million of 5.75%
      medium-term notes due in 2035. The proceeds are being used to support
      construction of its electric generation projects and for general corporate
      purposes.





*CE
      Electric UK*





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, at December 31 (in thousands):





**Par
                Value**
            
            **2005**
            
            **2004**Variable
                Rate Reset Trust Securities, due 2020, 5.88%
            
            $
            -
            
            $
            -
            
            $
            308,3618.625%
                Bearer Bonds, due 2005
            
            
            -
            
            
            -
            
            
            193,6886.995%
                Senior Notes, due 2007
            
            
            237,000
            
            
            232,547
            
            
            230,5726.496%
                Yankee Bonds, due 2008
            
            
            281,000
            
            
            281,061
            
            
            281,1138.875%
                Bearer Bonds, due 2020(1)
            
            
            172,110
            
            
            208,912
            
            
            230,2159.25%
                Eurobonds, due 2020(1)
            
            
            344,220
            
            
            429,501
            
            
            485,6547.25%
                Sterling Bonds, due 2022(1)
            
            
            344,220
            
            
            371,457
            
            
            411,2877.25%
                Eurobonds, due 2028(1)
            
            
            319,264
            
            
            338,370
            
            
            378,2025.125%
                Bonds, due 2035(1)
            
            
            344,220
            
            
            342,528
            
            
            -5.125%
                Bonds, due 2035(1)
            
            
            258,165
            
            
            256,897
            
            
            -CE
                Gas Credit Facility, 6.86% and 6.36%(1)
            
            
            46,260
            
            
            46,260
            
            
            52,797Total
                CE Electric UK
            
            $
            2,346,459
            
            $
            2,507,533
            
            $
            2,571,889




(1)
              The
                  par values for these debt instruments are denominated in sterling
                  and have
                  been converted to U.S. dollars at the applicable exchange
                  rate.




Pursuant
      to a call option exercised in February 2005, at a cost of $17.5 million, a
      subsidiary of CE Electric UK purchased, and then cancelled, its variable rate
      reset trust securities, due in 2020, at a par value of £155.0 million.
      Accordingly, the Company included the entire principal amount of these
      securities in its current portion of long-term debt in the accompanying
      consolidated balance sheet at December 31, 2004.


86


On
      May 5, 2005, Northern Electric Finance plc, an indirect wholly-owned
      subsidiary of CE Electric UK, issued £150.0 million of 5.125%
      bonds due 2035, guaranteed by Northern Electric and guaranteed as to scheduled
      payments of principal and interest by Ambac Assurance UK Limited (“Ambac”).
      Additionally, on May 5, 2005, Yorkshire Electricity, an indirect
      wholly-owned subsidiary of CE Electric UK, issued £200.0 million of 5.125%
      bonds due 2035, guaranteed as to scheduled payments of principal and interest
      by
      Ambac. The proceeds from the offerings are being invested and used for general
      corporate purposes. Investments include a £100.0 million 4.75% fixed rate
      guaranteed investment contract maturing December 2007 and a £200.0 million
      4.73% fixed rate guaranteed investment contract maturing February
      2008.





*Kern
      River*





The
      components of Kern River’s term notes consist of the following at
      December 31 (in thousands):





**Par
                Value**
            
            **2005**
            
            **2004**6.676%
                Senior Notes, due 2016
            
            $
            415,167
            
            $
            415,167
            
            $
            439,0004.893%
                Senior Notes, due 2018
            
            
            742,089
            
            
            742,089
            
            
            775,808Total
                Kern River
            
            $
            1,157,256
            
            $
            1,157,256
            
            $
            1,214,808





*Northern
      Natural Gas*





The
      components of Northern Natural Gas’ senior notes consist of the following,
      including unamortized premiums and discounts, at December 31 (in
      thousands):





**Par
                Value**
            
            **2005**
            
            **2004**6.875%
                Senior Notes, due 2005
            
            $
            -
            
            $
            -
            
            $
            99,9636.75%
                Senior Notes, due 2008
            
            
            150,000
            
            
            150,000
            
            
            150,0007.00%
                Senior Notes, due 2011
            
            
            250,000
            
            
            250,000
            
            
            250,0005.375%
                Senior Notes, due 2012
            
            
            300,000
            
            
            299,688
            
            
            299,6515.125%
                Senior Notes, due 2015
            
            
            100,000
            
            
            99,872
            
            
            -Total
                Northern Natural Gas
            
            $
            800,000
            
            $
            799,560
            
            $
            799,614





On
      April 14, 2005, Northern Natural Gas issued $100.0 million of 5.125%
      senior notes due May 1, 2015. The proceeds were used by Northern Natural
      Gas to repay its
      outstanding $100.0 million 6.875% senior notes due May 1,
      2005 .





*CE
      Casecnan*





CE
      Casecnan Water and Energy Company, Inc.’s (“CE Casecnan”) term notes and bonds
      consist of the following, including fair value adjustments, at December 31
      (in thousands):





**Par
                Value**
            
            **2005**
            
            **2004**11.45%
                Senior Secured Series A Notes, due in 2005
            
            $
            -
            
            $
            -
            
            $
            47,43211.95%
                Senior Secured Series B Bonds, due in 2010
            
            
            142,345
            
            
            140,635
            
            
            147,228Total
                CE Casecnan
            
            $
            142,345
            
            $
            140,635
            
            $
            194,660





*Leyte
      Projects*





The
      Leyte
      Projects’ term loans consist of the following at December 31 (in
      thousands):





**Par
                Value**
            
            **2005**
            
            **2004**Mahanagdong
                Project 6.92% Term Loan, due 2007
            
            $
            30,922
            
            $
            30,922
            
            $
            51,537Mahanagdong
                Project 7.60% Term Loan, due 2007
            
            
            6,857
            
            
            6,857
            
            
            11,428Malitbog
                Project 4.99% and 3.67%, due 2005
            
            
            -
            
            
            -
            
            
            11,866Malitbog
                Project 9.176% Term Loan, due 2005
            
            
            -
            
            
            -
            
            
            6,580Upper
                Mahiao Project 5.95% Term Loan, due 2006
            
            
            4,851
            
            
            4,851
            
            
            24,253Total
                Leyte Projects
            
            $
            42,630
            
            $
            42,630
            
            $
            105,664





87


MEHC
      provides debt service reserve letters of credit in amounts equal to the next
      semi-annual principal and interest payments due on the loans which were equal
      to
      $18.8 million and $44.6 million at December 31, 2005 and 2004,
      respectively.





*Cordova
      Funding*





Cordova
      Funding Corporation’s (“Cordova Funding”) senior secured bonds are due in
      semi-annual installments and consist of the following, including fair value
      adjustments, at December 31 (in thousands):





**Par
                Value**
            
            **2005**
            
            **2004**8.48%
                Senior Secured Bonds, due 2019
            
            $
            11,269
            
            $
            11,269
            
            $
            11,7168.64%
                Senior Secured Bonds, due 2019
            
            
            82,620
            
            
            80,457
            
            
            83,6558.79%
                Senior Secured Bonds, due 2019
            
            
            27,661
            
            
            27,247
            
            
            28,3288.82%
                Senior Secured Bonds, due 2019
            
            
            51,350
            
            
            51,350
            
            
            53,3849.07%
                Senior Secured Bonds, due 2019
            
            
            25,887
            
            
            25,887
            
            
            26,912Total
                Cordova Funding
            
            $
            198,787
            
            $
            196,210
            
            $
            203,995





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 $37.0 million. MEHC has also
      issued a debt service reserve guarantee, the maximum amount of which is equal
      at
      any given time to the difference between the next succeeding debt service
      payment ($11.0 million as of December 31, 2005) and the amount then on
      deposit in the debt service reserve fund ($9.0 million at December 31,
      2005).





As
      of
      December 31, 2005, Cordova Funding is currently prohibited from making
      distributions by the terms of its indenture due to its failure to meet its
      debt
      service coverage ratio requirement.





*HomeServices*





The
      components of HomeServices’ long-term debt consist of the following, including
      fair value adjustments, at December 31 (in thousands):





**Par
                Value**
            
            **2005**
            
            **2004**7.12%
                Senior Notes, due 2010
            
            $
            25,000
            
            $
            23,525
            
            $
            28,475Other
            
            
            2,788
            
            
            2,788
            
            
            2,963Total
                HomeServices
            
            $
            27,788
            
            $
            26,313
            
            $
            31,438





*Annual
      Repayments of Long-Term Debt*





The
      annual repayments of parent company and subsidiary and project debt for the
      years beginning January 1, 2006 and thereafter, excluding fair value
      adjustments and unamortized premiums and discounts, are as follows (in
      thousands):





**2006**
            
            **2007**
            
            **2008**
            
            **2009**
            
            **2010**
            
            **Thereafter**
            
            **Total**Parent
                company senior debt
            
            $
            -
            
            $
            550,000
            
            $
            1,000,000
            
            $
            -
            
            $
            -
            
            $
            1,225,000
            
            $
            2,775,000Parent
                company subordinated debt
            
            
            234,021
            
            
            234,021
            
            
            234,021
            
            
            234,021
            
            
            188,543
            
            
            539,226
            
            
            1,663,853MidAmerican
                Funding
            
            
            -
            
            
            -
            
            
            -
            
            
            175,000
            
            
            -
            
            
            525,000
            
            
            700,000MidAmerican
                Energy
            
            
            160,509
            
            
            1,651
            
            
            448
            
            
            32
            
            
            32
            
            
            1,474,446
            
            
            1,637,118CE
                Electric UK
            
            
            5,190
            
            
            251,481
            
            
            291,326
            
            
            8,208
            
            
            5,763
            
            
            1,784,491
            
            
            2,346,459Kern
                River
            
            
            71,360
            
            
            69,472
            
            
            72,816
            
            
            74,906
            
            
            78,668
            
            
            790,034
            
            
            1,157,256Northern
                Natural Gas
            
            
            -
            
            
            -
            
            
            150,000
            
            
            -
            
            
            -
            
            
            650,000
            
            
            800,000CE
                Casecnan
            
            
            36,015
            
            
            37,730
            
            
            37,730
            
            
            13,720
            
            
            17,150
            
            
            -
            
            
            142,345Leyte
                Projects
            
            
            30,037
            
            
            12,593
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            42,630Cordova
                Funding
            
            
            4,500
            
            
            4,163
            
            
            4,725
            
            
            6,412
            
            
            9,000
            
            
            169,987
            
            
            198,787HomeServices
            
            
            6,050
            
            
            5,855
            
            
            5,409
            
            
            5,156
            
            
            5,152
            
            
            166
            
            
            27,788Totals
            
            $
            547,682
            
            $
            1,166,966
            
            $
            1,796,475
            
            $
            517,455
            
            $
            304,308
            
            $
            7,158,350
            
            $
            11,491,236





88


*Fair
      Value*





At
      December 31, 2005, the Company had fixed-rate long-term debt of
      $11,348.0 million in principal amount and having a fair value of
      $12,066.0 million. In addition, at December 31, 2005, the Company had
      floating-rate obligations of $166.7 million that expose the Company to the
      risk of increased interest expense in the event of increases in short-term
      interest rates. The fair value of the floating-rate obligations and the
      short-term debt approximates their carrying amounts.





At
      December 31, 2004, the Company had fixed-rate long-term debt of
      $11,503.4 million in principal amount and having a fair value of
      $12,416.2 million. In addition, at December 31, 2004, the Company had
      floating-rate obligations of $493.4 million. The fair value of the
      floating-rate obligations and the short-term debt approximates their carrying
      amounts.





**12.** **Asset
      Retirement Obligations**





On
      December 31, 2005, the Company adopted FASB Interpretation No. 47,
“Accounting for Conditional Asset Retirement Obligations, an interpretation
      of
      FASB Statement No. 143” (“FIN 47”). FIN 47 clarifies
      that the term *conditional
      asset retirement obligation* as used
      in SFAS 143 refers to a legal obligation to perform an asset retirement activity
      in which the timing and/or method of settlement are conditional on a future
      event that may or may not be within the control of the entity. Accordingly,
      the
      Company is required to recognize a liability for the fair value of a conditional
      ARO if the fair value of the liability can be reasonably estimated. Uncertainty
      about the timing or method of settlement of a conditional ARO should be factored
      into the measurement of the liability when sufficient information exists.





In
      conjunction with the adoption of FIN 47, the Company recorded $11.4 million
      of ARO liabilities; $0.8 million of associated ARO assets, net of
      accumulated depreciation; and a $10.6 million reduction of regulatory
      liabilities. Adoption of FIN 47 did not impact net income.





The
      change in the balance of the ARO liability, which is included in other long-term
      accrued liabilities in the accompanying consolidated balance sheets, for the
      years ended December 31 is summarized as follows (in
      thousands):





**2005**
            
            **2004**Balance,
                January 1
            
            $
            185,781
            
            $
            284,377Adoption
                of FIN 47
            
            
            11,422
            
            
            -Revisions
            
            
            1,120
            
            
            (120,098
            )Additions
            
            
            3,897
            
            
            5,602Retirements
            
            
            (4,331
            )
            
            -Accretion
            
            
            10,659
            
            
            15,900Balance,
                December 31
            
            $
            208,548
            
            $
            185,781





At
      December 31, 2005, $163.0 million of the total ARO liability pertained
      to the decommissioning of Quad Cities Station. Assets of $228.1 million,
      reflected in other investments in the accompanying consolidated balance sheet,
      are restricted for satisfying the Quad Cities Station ARO
      liability.





Revisions
      for the year ended December 31, 2004 include a revision to the nuclear
      decommissioning ARO liability as a result of a change in the assumed life of
      Quad Cities Station pursuant to a 20-year extension to the operating license
      of
      the plant by the NRC in October 2004 and its impact on the timing of related
      cash flows.





The
      total
      ARO liability, computed on a pro forma basis as if FIN 47 had been applied
      during each of the periods presented in the consolidated financial statements,
      would have been as follows (in millions):





As
                of January 1, 2003
            
            $
            300.4As
                of December 31, 2003
            
            
            295.2As
                of December 31, 2004
            
            
            197.0





89


In
      addition to the ARO liabilities, MidAmerican Energy has accrued for the cost
      of
      removing other electric and natural gas assets through its depreciation rates,
      in accordance with accepted regulatory practices. These accruals, totaling
      $448.5 million and $428.7 million at December 31, 2005 and 2004,
      respectively, are reflected as regulatory liabilities and included in other
      long-term accrued liabilities in the accompanying consolidated balance
      sheets.





**13.** **Preferred
      Securities of Subsidiaries**





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
      $31.1 million. The aggregate total the holders of all preferred securities
      outstanding at December 31, 2005, are entitled to upon involuntary
      bankruptcy is $30.3 million plus accrued dividends. The total annual
      dividend requirements for all preferred securities outstanding at
      December 31, 2005 were $1.2 million.





The
      total
      outstanding 8.061% cumulative preferred securities of a subsidiary of CE
      Electric UK, which are redeemable in the event of the revocation of the
      subsidiary’s electricity distribution license by the Secretary of State, was
      $56.0 million as of December 31, 2005 and 2004,
      respectively.





**14.** **Risk
      Management and Hedging Activities**





The
      Company is directly exposed to the impact of market fluctuations in the prices
      of natural gas and electricity as a result of its ownership of MidAmerican
      Energy, Northern Natural Gas and CE Electric UK. Exposure to foreign
      currency risk exists from investment in businesses, primarily
      CE Electric UK, operated in foreign countries. The Company is exposed
      to interest rate risk as a result of the issuance of fixed rate debt. 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 ,
      swaps
      and options. 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.





As
      of
      December 31, 2005, the Company held derivative instruments with the
      following fair values (in millions):




CommodityNorthern
              
              
              
              Foreign
              
              InterestMidAmerican
              
              Natural
              
              
              
              Exchange
              
              RateEnergy
              
              Gas
              
              Other
              
              Swaps
              
              Locks
              
              TotalMaturity:2006
              
              $
              (9.0
              )
              $
              1.2
              
              $
              (6.0
              )
              $
              -
              
              $
              -
              
              $
              (13.8
              )2007
                  - 2009
              
              
              (5.2
              )
              
              (6.7
              )
              
              (4.8
              )
              
              (77.5
              )
              
              -
              
              
              (94.2
              )After
                  2009
              
              
              -
              
              
              (0.6
              )
              
              -
              
              
              -
              
              
              -
              
              
              (0.6
              )Total
              
              $
              (14.2
              )
              $
              (6.1
              )
              $
              $(10.8
              )
              $
              (77.5
              )
              $
              -
              
              $
              (108.6
              )





Commodity
      Cash Flow Hedges





Some
      of
      MEHC’s subsidiaries are exposed to market price fluctuations of various
      commodities related to their ongoing power generation and natural gas gathering,
      distribution, processing and marketing activities. The Company closely monitors
      the potential impacts of commodity price changes and, where appropriate, enters
      into contracts to lock-in prices for a portion of the future sales, generation
      revenue and fuel expenses.





Certain
      derivative electric and gas contracts utilized by the regulated operations
      of
      MidAmerican Energy are recoverable through retail rates. Accordingly, unrealized
      changes in fair value of these contracts are deferred as regulatory assets
      or
      liabilities pursuant to SFAS 71. At December 31, 2005, $32.7 million of
      derivative assets and $47.6 million of derivative liabilities were used for
      regulated purposes.





Other
      MEHC subsidiaries use derivative instruments such as swaps, futures, forwards
      and options as cash flow hedges for natural gas and other
      transactions.


90


Currency
      Exchange Rate Risk





CE
      Electric UK has entered into certain currency rate swap agreements for its
      senior notes and Yankee bonds with large multi-national financial institutions.
      The swap agreements effectively convert the U.S. dollar fixed interest rate
      to a
      fixed rate in sterling for $237.0 million of 6.995% senior notes and
      $281.0 million of 6.496% Yankee bonds outstanding at December 31,
      2005. The agreements extend until December 30, 2007 and February 25,
      2008, respectively. The estimated fair value of these swap agreements at
      December 31, 2005 and 2004, was $77.5 million and $131.8 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.





Interest
      Rate Hedges





The
      Company may enter into contractual agreements to hedge exposure to interest
      rate
      risk. Changes in fair value of interest rate “locks” used as cash flow hedges
      are reported in accumulated other comprehensive income to the extent the hedge
      is effective until the forecasted transaction occurs, at which time they are
      recorded as adjustments to interest expense over the term of the related debt
      issuance. In May 2005, MEHC entered into a treasury rate lock agreement in
      the
      notional amount of $1.6 billion to protect against a rise in interest rates
      related to the anticipated financing of the PacifiCorp acquisition. For the
      year
      ended December 31, 2005, the amount of the deferred gain included in other
      comprehensive income was $ - million.





Credit
      Risk





*Domestic
      Regulated Operations*





MidAmerican
      Energy’s utility operations grant unsecured credit to its retail electric and
      gas customers, substantially all of whom are local businesses and residents,
      which totaled $186.0 million at December 31, 2005. MidAmerican Energy
      also extends unsecured credit to other utilities, energy marketers, financial
      institutions and certain commercial and industrial end-users in conjunction
      with
      wholesale energy marketing activities. MidAmerican Energy analyzes the financial
      condition of each significant counterparty before entering into any
      transactions, establishes limits on the amount of unsecured credit to be
      extended to each counterparty, and evaluates the appropriateness of unsecured
      credit limits on a daily basis. MidAmerican Energy seeks to negotiate
      contractual arrangements with wholesale counterparties to provide for net
      settlement of monthly accounts receivable and accounts payable and net
      settlement of contracts for future performance in the event of default. At
      December 31, 2005, 84.4% of MidAmerican Energy’s credit exposure, net of
      collateral, from wholesale operations was with counterparties having “investment
      grade” credit ratings from Moody’s or Standard & Poor’s, while an additional
      7.4% of MidAmerican Energy’s credit exposure, net of collateral, from wholesale
      operations was with counterparties having financial characteristics deemed
      equivalent to “investment grade” by 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 electric generating
      companies and energy marketing and trading companies in the western United
      States. 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.





*CE
      Electric UK*





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 an industry standard “Distribution 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. 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 44% of distribution revenues in 2005. The
      Office of Gas and Electricity Markets (“Ofgem”) has determined a framework which
      sets credit limits for each supply business 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 cover must be 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.





91


*CalEnergy
      Generation-Foreign*





PNOC-EDC’s
      and NIA’s obligations under the project agreements are the Leyte Projects’ and
      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
      obligations under the project agreements 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 CalEnergy Generation-Foreign was $312.3 million for the year ended
      December 31, 2005. The Leyte Projects’ agreements expire in June 2006
      and July 2007, respectively, while the Casecnan Project’s agreement expires in
      December 2021.





**15.**
            **Income
                Taxes**





Income
      tax expense on continuing operations consists of the following (in
      thousands):





**Year
                Ended December 31,****2005**
            
            **2004**
            
            **2003**Current:Federal
            
            $
            35,535
            
            $
            18,794
            
            $
            (48,911
            )State
            
            
            5,366
            
            
            (9,862
            )
            
            10,901Foreign
            
            
            73,844
            
            
            79,463
            
            
            88,150114,745
            
            
            88,395
            
            
            50,140Deferred:Federal
            
            
            52,944
            
            
            112,719
            
            
            141,795State
            
            
            9,959
            
            
            607
            
            
            10,833Foreign
            
            
            67,061
            
            
            63,265
            
            
            67,508129,964
            
            
            176,591
            
            
            220,136Total
            
            $
            244,709
            
            $
            264,986
            
            $
            270,276





A
      reconciliation of the federal statutory tax rate to the effective tax rate
      on
      continuing operations applicable to income before income tax expense
      follows:





**2005**
            
            **2004**
            
            **2003**Federal
                statutory rate
            
            
            35.0
            %
            
            35.0
            %
            
            35.0
            %General
                business tax credits
            
            
            (2.0
            )
            
            (0.6
            )
            
            (0.5
            )State
                taxes, net of federal tax effect
            
            
            1.5
            
            
            2.2
            
            
            1.8Equity
                income
            
            
            2.4
            
            
            0.7
            
            
            1.6Dividends
                on preferred securities of subsidiaries
            
            
            -
            
            
            -
            
            
            (6.9
            )Tax
                effect of foreign income
            
            
            (2.0
            )
            
            0.3
            
            
            0.5Dividends
                received deduction
            
            
            (1.3
            )
            
            -
            
            
            (1.1
            )Effects
                of ratemaking
            
            
            (0.8
            )
            
            (0.9
            )
            
            0.9Other
                items, net
            
            
            (0.8
            )
            
            (3.5
            )
            
            0.2Effective
                tax rate
            
            
            32.0
            %
            
            33.2
            %
            
            31.5
            %





92


The
      net
      deferred tax liability consists of the following at December 31 (in
      thousands):





**2005**
            
            **2004****Deferred
                tax assets:**Minimum
                pension liability adjustment
            
            $
            145,767
            
            $
            163,761Revenue
                sharing accruals
            
            
            92,040
            
            
            80,220Accruals
                not currently deductible for tax purposes
            
            
            80,798
            
            
            54,402Deferred
                income
            
            
            20,050
            
            
            34,458Nuclear
                reserve and decommissioning
            
            
            14,962
            
            
            27,112Net
                operating loss (“NOL”) and credit carryforwards
            
            
            265,408
            
            
            267,051Other
            
            
            4,551
            
            
            16,569Total
                deferred tax assets
            
            
            623,576
            
            
            643,573**Deferred
                tax liabilities:**Properties,
                plants and equipment, net
            
            
            1,756,340
            
            
            1,700,884Income
                taxes recoverable through future rates
            
            
            176,108
            
            
            163,108Employee
                benefits
            
            
            40,632
            
            
            51,509Fuel
                cost recoveries
            
            
            9,897
            
            
            6,028Reacquired
                debt
            
            
            2,473
            
            
            3,877Total
                deferred tax liabilities
            
            
            1,985,450
            
            
            1,925,406Net
                deferred tax liability
            
            $
            1,361,874
            
            $
            1,281,833





At
      December 31, 2005, the Company has available unused NOL and credit
      carryforwards that may be applied against future taxable income and that expire
      at various intervals between 2007 and 2026.





**16.**
            **Other
                Income and Expense**





Other
      income for the years ending December 31 consists of the following (in
      thousands):





**2005**
            
            **2004**
            
            **2003**Allowance
                for equity funds used during construction
            
            $
            26,170
            
            $
            20,476
            
            $
            26,708Gains
                on sales of non-strategic assets and investments
            
            
            23,298
            
            
            3,609
            
            
            4,183Gains
                on Enron note receivable and other claims
            
            
            6,358
            
            
            72,210
            
            
            -Corporate-owned
                life insurance income
            
            
            5,150
            
            
            5,447
            
            
            6,317Gain
                on Mirant bankruptcy claim
            
            
            -
            
            
            14,750
            
            
            -Gain
                on CE Casecnan settlement
            
            
            -
            
            
            -
            
            
            31,889Gain
                on Williams preferred stock
            
            
            -
            
            
            -
            
            
            13,750Other
            
            
            13,540
            
            
            11,713
            
            
            13,796Total
                other income
            
            $
            74,516
            
            $
            128,205
            
            $
            96,643





*Non-Strategic
      Assets and Investments*





Included
      in gains on sales of non-strategic assets and investments for the year ended
      December 31, 2005, are gains from sales of certain non-strategic, passive
      investments at MidAmerican Funding of $13.4 million and
      CE Electric UK of $8.4 million.





*Enron
      Note Receivable and Other Claims*





Northern
      Natural Gas had a note receivable of approximately $259.0 million (the
“Enron Note Receivable”) with Enron. As a result of Enron filing for bankruptcy
      on December 2, 2001, Northern Natural Gas filed a bankruptcy claim against
      Enron seeking to recover payment of the Enron Note Receivable. As of
      December 31, 2001, Northern Natural Gas had written-off the note. By
      stipulation, Enron and Northern Natural Gas agreed to a value of
      $249.0 million for the claim and received approval of the stipulation from
      Enron’s Bankruptcy Court on August 26, 2004. On November 23, 2004,
      Northern Natural Gas sold its stipulated general, unsecured claim against Enron
      of $249.0 million to a third party investor for $72.2 million.





93


*Mirant
      Americas Energy Marketing (“Mirant”) Claim*





Mirant
      was one of the shippers that entered into a 15-year, 2003 Expansion Project,
      firm gas transportation contract (90,000 Dth per day) with Kern River 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 and Kern River subsequently drew on the letter of
      credit and held the proceeds thereof, $14.8 million, as cash collateral.
      The bankruptcy court ultimately determined that Kern River was entitled to
      the
      $14.8 million cash collateral which resulted in Kern River recognizing such
      amount as other income.





*CE
      Casecnan Arbitration Settlement*





On
      October 15, 2003, CE Casecnan, an indirect, majority-owned subsidiary of
      the Company, closed a transaction settling the arbitration, which arose from
      a
      Statement of Claim made on August 19, 2002, by CE Casecnan against the
      Republic of the Philippines (“ROP”) NIA. As a result of the agreement, CE
      Casecnan recorded $31.9 million of other income and $24.4 million of
      associated income taxes. In connection with the settlement, the NIA delivered
      to
      CE Casecnan a $97.0 million 8.375% ROP Note due 2013 (the “ROP Note”),
      which contained a put provision granting CE Casecnan the right to put the ROP
      Note to the ROP for a price of par plus accrued interest for a 30-day period
      commencing on January 14, 2004. On January 14, 2004, CE Casecnan
      exercised its right to put the ROP Note to the ROP and, in accordance with
      the
      terms of the put, CE Casecnan received $99.2 million (representing
      $97.0 million par value plus accrued interest) from the ROP on
      January 21, 2004.





*Williams
      Preferred Stock*





On
      March 27, 2002, the Company invested $275.0 million in Williams in
      exchange for shares of 9.875% cumulative convertible preferred stock of
      Williams. Dividends on the Williams preferred stock were received quarterly,
      commencing July 1, 2002. On June 10, 2003, Williams repurchased, for
      $288.8 million, plus accrued dividends, all of the shares of its 9.875%
      Cumulative Convertible Preferred Stock originally acquired by the Company in
      March 2002 for $275.0 million. The Company recorded a pre-tax gain of
      $13.8 million on the transaction.





*Other
      Expense*





The
      Company’s other expense totaled $22.1 million, $10.1 million and
      $5.9 million, respectively, for the years ended December 31, 2005,
      2004 and 2003. MidAmerican Funding has investments in commercial passenger
      aircraft leased to major domestic airlines, which are accounted for as leveraged
      leases. During 2005, the airline industry continued to deteriorate and two
      major
      airline carriers filed for bankruptcy. MidAmerican Funding evaluated its
      investments in commercial passenger aircraft and recognized losses totaling
      $15.6 million for other-than-temporary impairments of those
      investments.





**17.**
            **Discontinued
                Operations - Zinc Recovery Project and Mineral
                Assets**





Indirect
      wholly-owned subsidiaries of MEHC own the rights to commercial quantities of
      extractable minerals from elements in solution in the geothermal brine and
      fluids utilized at certain geothermal energy generation facilities located
      in
      the Imperial Valley of California and a zinc recovery plant constructed near
      the
      geothermal energy generation facilities designed to recover zinc from the
      geothermal brine through an ion exchange, solvent extraction, electrowinning
      and
      casting process (the “Zinc Recovery Project”).





The
      Zinc
      Recovery Project began limited production during December 2002 and continued
      limited production until September 10, 2004. On September 10, 2004,
      management made the decision to cease operations of the Zinc Recovery Project.
      Based on this decision, a non-cash, after-tax impairment charge of
      $340.3 million was recorded to write-off the Zinc Recovery Project, rights
      to quantities of extractable minerals, and allocated goodwill (collectively,
      the
“Mineral Assets”). The charge and the related activity of the Mineral Assets are
      classified separately as discontinued operations in the accompanying
      consolidated statements of operations and include the following (in
      thousands):


94




**Year
                  Ended December 31.****2005**
              
              **2004**
              
              **2003**Operating
                  revenue
              
              $
              -
              
              $
              3,401
              
              $
              659Losses
                  from discontinued operations
              
              $
              -
              
              $
              (42,695
              )
              $
              (46,423
              )Proceeds
                  from (costs of) disposal activities, net
              
              
              7,634
              
              
              (4,134
              )
              
              -Asset
                  impairment charges
              
              
              -
              
              
              (479,233
              )
              
              -Goodwill
                  impairment charges
              
              
              -
              
              
              (52,776
              )
              
              -Income
                  tax (expense) benefit
              
              
              (2,500
              )
              
              211,277
              
              
              19,305Income
                  (loss) from discontinued operations, net of tax
              
              $
              5,134
              
              $
              (367,561
              )
              $
              (27,118
              )
  In
      connection with ceasing operations, the Zinc Recovery Project’s assets have been
      dismantled and sold and certain employees of the operator of the Zinc Recovery
      Project were paid one-time termination benefits. Implementation of the
      decommissioning plan began in September 2004 and, as of December 31, 2005,
      the dismantling, decommissioning, and sale of remaining assets of the Zinc
      Recovery Project was completed. Proceeds from the sale of the Zinc Recovery
      Project’s assets exceeded the cost of disposal activities during the year ended
      December 31, 2005. Salvage proceeds were recognized in the period earned.
      Costs were recognized in the period in which the related liability was incurred.
      Cash expenditures of approximately $4.1 million, consisting of pre-tax
      disposal costs, termination benefit costs and property taxes, were made through
      December 31, 2004.





**18.** **Stock
      Transactions**





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





There
      were no common stock options granted, forfeited or allowed to expire during
      each
      of the three years in the period ended December 31, 2005. Common stock
      options exercised during each of the three years in the period ended
      December 31, 2005 consisted solely of 200,000 in 2005 held by
      Mr. Sokol 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 at December 31, 2005.
      1,145,000 of the outstanding and exercisable common stock options have 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 have 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 at December 31,
      2004, 2003 and 2002.





**19.**
            **Regulatory
                Matters**





*MidAmerican
      Energy*





Under
      a
      series of settlement agreements between MidAmerican Energy, the Iowa Office
      of
      Consumer Advocate (“OCA”) and other interveners approved by the IUB, MidAmerican
      Energy has agreed not to seek a general increase in electric rates to become
      effective prior to January 1, 2012 unless its Iowa jurisdictional electric
      return on equity for any year falls below 10%. 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 seek any decrease in MidAmerican Energy’s
      Iowa electric rates prior to January 1, 2012. 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 portions of revenues associated with Iowa retail electric returns on equity
      within specified ranges will be recorded as a regulatory liability.





95


Under
      a
      settlement agreement approved by the IUB on December 31, 2001, which was
      effective through December 31, 2005, an amount equal to 50% of revenues
      associated with returns on equity between 12% and 14%, and 83.33% of revenues
      associated with returns on equity above 14%, in each year was recorded as a
      regulatory liability. A settlement agreement, which was filed in conjunction
      with MidAmerican Energy’s application for ratemaking principles on its 2004/2005
      wind power project and approved by the IUB on October 17, 2003, provided
      that during the period January 1, 2006 through December 31, 2010, an
      amount equal to 40% of revenues associated with returns on equity between 11.75%
      and 13%, 50% of revenues associated with returns on equity between 13% and
      14%,
      and 83.3% of revenues associated with returns on equity above 14%, in each
      year
      will be recorded as a regulatory liability.





A
      settlement agreement approved by the IUB on January 31, 2005, in
      conjunction with MidAmerican Energy’s 2005 expansion of its wind power project
      extended through 2011 MidAmerican Energy’s commitment not to seek a general
      increase in electric rates unless its Iowa jurisdictional electric return on
      equity falls below 10%. It also extended the revenue sharing mechanism through
      2011, and the OCA agreed not to seek any decrease in Iowa electric base rates
      to
      become effective before January 1, 2012.





On
      December 16, 2005, MidAmerican Energy filed with the IUB a settlement
      agreement between MidAmerican Energy and the OCA regarding ratemaking principles
      for up to 545 MW of additional wind generation capacity in Iowa, based on
      nameplate ratings. The settlement agreement, which is subject to IUB approval,
      extends through 2012 MidAmerican Energy’s commitment not to seek a general
      increase in electric rates unless its Iowa jurisdictional electric return on
      equity for the calendar year 2011 falls below 10%. Additionally, the revenue
      sharing mechanism is extended through 2012, and the OCA agrees not to seek
      any
      decrease in Iowa electric base rates to become effective prior to January 1,
      2013.





The
      regulatory liabilities created by the settlement agreements are recorded as
      a
      regulatory charge in depreciation and amortization expense when the liability
      is
      accrued. Additionally, interest expense is accrued on the portion of the
      regulatory liability balance recorded in prior years. The regulatory liabilities
      created for the years through 2010 are expected to be reduced as they are
      credited against plant in service associated with generating plant additions.
      As
      a result of the credit applied to generating plant balances from the reduction
      of the regulatory liabilities, future depreciation will be reduced. The
      regulatory liability accrued for 2011 and 2012, if any, will be credited to
      customer bills in 2012 and 2013, respectively.





*Kern
      River*





Kern
      River’s tariff rates are designed to give it an opportunity to recover all
      actually and prudently incurred operations and maintenance costs of its pipeline
      system, taxes, interest, depreciation and amortization and a regulated equity
      return. 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. If the Kern River system is converted to a traditional rate
      design as a result of the 2004 general rate case, the depreciation of Kern
      River’s transmission system would be calculated on a straight-line basis over
      the expected economic life of its facilities. Under the traditional methodology,
      transportation rates do not remain constant over the lives of the shipper
      contracts, but rather are adjusted in each rate case to reflect current
      operating costs, updated depreciation rates and the rate base investment then
      in
      effect.





Kern
      River was required to file its 2004 general rate case no later than May 1,
      2004 pursuant to the terms of its 1998 FERC Docket No. RP99-274 rate case
      settlement. Kern River filed its rate case on April 30, 2004, which
      supports an annual revenue increase of $40.1 million representing a 13%
      increase from its existing cost of service and a proposed overall cost of
      service of $347.4 million. The rate increase became effective on
      November 1, 2004, subject to refund. Since its previous rate case, Kern
      River increased the capacity of its system from 724,500 Dth per day to 1,755,575
      Dth per day at a cost of approximately $1.2 billion. The filing employed
      the levelized rate methodology.





The
        Kern
        River 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. Briefs on exceptions will be due on April 3, 2006, and briefs opposing
        exceptions are due April 26, 2006. The administrative law judge’s initial
        decision is non-binding and after briefing, the FERC will issue its initial
        decision on the case. The initial FERC decision, which may result in rate
        refunds, typically becomes binding on all parties while rehearing requests
        on
        the FERC decision and/or court appeals are pending. The initial FERC decision
        is
        not expected until late 2006 or early 2007. The final resolution of the rate
        case is dependent on receiving a final, non-appealable decision on the case
        from
        the FERC, or approval of a settlement of the case by the FERC.


96


*Northern
      Natural Gas*





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





On
      May 1, 2003, Northern Natural Gas filed a general rate case proceeding for
      increased rates with the FERC and filed an additional rate case proceeding
      on
      January 30, 2004 to reflect further cost increases. The FERC consolidated
      the 2003 and 2004 rate cases due to the similarity of issues in both cases
      and
      the updated costs. On March 25, 2005, as modified on April 22, 2005,
      Northern Natural Gas filed a stipulation and agreement with the FERC (the
“Settlement”) resolving the consolidated rate cases. On June 20, 2005, the
      FERC approved the Settlement without modification. The Settlement represents
      the
      agreement Northern Natural Gas reached with its customers to settle the base
      tariff rates and related tariff issues in the consolidated cases. The Settlement
      provided for, among other things, rates designed to generate revenues on an
      annual basis above the base rates which were in effect as of October 31,
      2003, as follows: $48 million for the period November 1, 2003 through
      October 31, 2004, $53 million for the period November 1, 2004
      through October 31, 2005, $58 million for the period November 1,
      2005 through October 31, 2006, and $62 million beginning
      November 1, 2006. Northern Natural Gas provided refunds including interest
      of $71.5 million to its customers in the third quarter of 2005 consistent
      with the terms of the Settlement, generally reflecting the difference between
      the rate increases implemented on November 1, 2003 and November 1,
      2004 and the revenue generated using the Settlement rates.





In
      April
      2004, Northern Natural Gas also filed tariff sheets with the FERC in relation
      to
      its system levelized account (“SLA”) (an imbalance recovery mechanism) with the
      new rates going into effect on June 1, 2004, subject to refund. On
      February 14, 2005, Northern Natural Gas received FERC approval of the SLA
      settlement. The SLA settlement provides for recovery of the final SLA balance
      as
      of December 31, 2004, over a forty-eight month period beginning
      November 1, 2003. Under the SLA settlement, Northern Natural Gas is
      responsible for the financial impacts of managing operational storage
      volumes.





*CE
      Electric UK*





Most
      of
      the revenue of the DLHs in Great Britain is controlled by a distribution price
      control formula which is set out in the license of each DLH. It has been the
      practice of Ofgem (and its predecessor body, the Office of Electricity
      Regulation), to review and reset the formula at five-year intervals, although
      the formula has been, and may be, further reviewed at other times at the
      discretion of the regulator. Any such resetting of the formula requires the
      consent of the DLH. If the DLH does not consent to the formula reset, it is
      reviewed by the British competition commission, whose recommendations can then
      be given effect by license modifications made by Ofgem.





The
      current formula requires that regulated distribution income per unit is
      increased or decreased each year by RPI-Xd where RPI means the Retail Prices
      Index, reflecting the average of the 12-month inflation rates recorded for
      each
      month in the previous July to December period. The Xd factor in the formula
      was
      established by Ofgem at the price control review effective in April 2005 (and
      through March 31, 2010, is expected to continue to be set) at 0%. The
      formula also takes account of a variety of other factors including the changes
      in system electrical losses, the number of customers connected and the voltage
      at which customers receive the units of electricity distributed. The
      distribution price control formula determines the maximum average price per
      unit
      of electricity distributed (in pence per kWh) which a DLH is entitled to charge.
      The distribution price control formula permits DLHs to receive additional
      revenue due to increased distribution of units and the increase in the number
      of
      end users. The price control does not seek to constrain the profits of a DLH
      from year to year. It is a control on revenue that operates independently of
      most of the DLH’s costs. During the term of the price control, cost savings or
      additional costs have a direct impact on income and cash flow.





97


The
      procedure and methodology adopted at a price control review are at the
      reasonable discretion of Ofgem. Generally, Ofgem’s judgment of the future
      allowed revenue of licensees has been based upon, among other
      things:





·
            the
                actual operating costs of each of the
                licensees;


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


·
            the
                taxes that each licensee is expected to
                pay;


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


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


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


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





As
      a
      result of the review concluded in 2004, the allowed revenue of Northern
      Electric’s distribution business was reduced by 4%, in real terms, and the
      allowed revenue of Yorkshire Electricity’s distribution business was reduced by
      9%, in real terms, with effect from April 1, 2005. Ofgem indicated that
      during the period 2005 to 2010, the retention of the benefits of any
      out-performance from the operating cost assumptions made by Ofgem 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.





The
      triennial process of valuing the UK pension plan’s assets and liabilities, which
      valued the plan assets and liabilities as of March 31, 2004, was completed
      in 2005. This valuation set a revised level of contributions for the next three
      years. The report of the actuaries conducting the valuation showed a funding
      deficiency of £190.3 million. Based on this valuation, CE Electric UK will
      contribute £23.1 million to the pension plan each year in respect of the
      existing funding deficiency. The amount in respect of the funding deficiency
      has
      been calculated based on eliminating the funding deficiency over 12 years
      commencing April 1, 2005. In setting the allowed revenue of Northern
      Electric and Yorkshire Electricity (and all other DLHs) with effect from
      April 1, 2005, Ofgem made a specific allowance for an amount in respect of
      each DLH’s pension costs, which reflects recovery of a significant portion of
      the deficiency payments.





With
      effect from April 1, 2005, a number of incentive schemes operate to
      encourage DLHs to provide an appropriate quality of service. Payments in respect
      of each failure to meet a prescribed standard of service are set out in
      regulations. The aggregate of payments that may be due is uncapped, although
      payments are excused in certain force majeure circumstances. In storm conditions
      the obligations relating to the period within which supplies should be restored
      are relaxed and the overall, annual exposure under the restoration standard
      in
      storm conditions is limited to 2% of a DLH’s allowed revenue. There also is a
      discretionary reward scheme of up to £1 million per annum, and other
      incentive schemes pursuant to which a DLH’s allowed revenue may increase by up
      to 3.3% or decrease by up to 3.5% in any year.





**20.**
            **Commitments
                and Contingencies**





MidAmerican
      Energy, Kern River, Northern Natural Gas, CE Electric UK, CalEnergy
      Generation-Domestic and HomeServices have non-cancelable operating leases
      primarily for computer equipment, office space and rail cars. Rental payments
      on
      non-cancelable operating leases totaled $77.4 million for 2005,
      $71.1 million for 2004, and $65.8 million for 2003. The minimum
      payments under these leases are $74.8 million, $67.8 million,
      $57.0 million, $45.7 million, and $35.3 million for the years
      2006 through 2010, respectively, and $96.2 million for the total of the
      years thereafter.





*MidAmerican
      Energy*





*Fuel
      and Energy Commitments*





MidAmerican
      Energy has coal supply and related transportation contracts for its
      fossil-fueled generating stations. As of December 31, 2005, the contracts,
      with expiration dates ranging from 2006 to 2010, require minimum payments of
      $87.4 million, $70.0 million, $35.6 million, $35.2 million
      and $16.1 million for the years 2006 through 2010, respectively.
      MidAmerican Energy expects to supplement these coal contracts with additional
      contracts and spot market purchases to fulfill its future fossil fuel needs.
      Additionally, MidAmerican Energy has a transportation contract for a natural
      gas-fired generating plant. The contract, which expires in 2012, requires
      minimum annual payments of $6.0 million.





98


MidAmerican
      Energy also has contracts to purchase electric capacity. As of December 31,
      2005, the contracts, with expiration dates ranging from 2006 to 2028, require
      minimum payments of $26.2 million, $27.5 million, $35.7 million,
      $28.9 million and $9.4 million for the years 2006 through 2010,
      respectively, and $165.3 million for the total of the years
      thereafter.





MidAmerican
      Energy has various natural gas supply and transportation contracts for its
      gas
      operations. As of December 31, 2005, the contracts, with expiration dates
      ranging from 2006 to 2017, require minimum payments of $61.5 million,
      $51.0 million, $16.7 million, $10.9 million and $5.7 million
      for the years 2006 through 2010, respectively, and $16.9 million for the
      total of the years thereafter.





MidAmerican
      Energy is the lessee on operating leases for coal railcars that contain
      guarantees of the residual value of such equipment throughout the term of the
      leases. Events triggering the residual guarantees include termination of the
      lease, loss of the equipment or purchase of the equipment. Lease terms are
      for
      five years with provisions for extensions. As of December 31, 2005, the
      maximum amount of such guarantees specified in these leases totaled
      $29.4 million. These guarantees are not reflected in the accompanying
      consolidated balance sheets.





On
      February 12, 2003, MidAmerican Energy executed a contract with Mitsui &
Co. Energy Development, Inc. (“Mitsui”) for engineering, procurement and
      construction of a 790 MW (based on expected accreditation) coal-fired generating
      plant expected to be completed in the summer of 2007. MidAmerican Energy
      currently holds a 60.67% individual ownership interest as a tenant in common
      with the other owners of the plant. Under the contract, MidAmerican Energy
      is
      allowed to defer payments, including the other owners’ shares, for up to
      $200.0 million of billed construction costs through the end of the project.
      Deferred payments as of December 31, 2005 and 2004, totaled
      $200.0 million and $152.3 million, respectively, and are reflected in
      other long-term accrued liabilities in the accompanying consolidated balance
      sheets.





An
      asset
      representing the other owners’ share of the deferred payments is reflected in
      deferred charges and other assets in the accompanying consolidated balance
      sheets and totaled $78.7 million and $59.9 million, respectively, as
      of December 31, 2005 and 2004. MidAmerican Energy will bill each of the
      other owners for its share of the deferred payments when payment is made to
      Mitsui.





*Air
      Quality*





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





The
      EPA
      has in recent years implemented more stringent national ambient air quality
      standards for ozone and new standards for fine particulate matter. These
      standards set the minimum level of air quality that must be met throughout
      the
      United States. Areas that achieve the standards, as determined by ambient air
      quality monitoring, are characterized as being in attainment of the standard.
      Areas that fail to meet the standard are designated as being nonattainment
      areas. Generally, once an area has been designated as a nonattainment area,
      sources of emissions that contribute to the failure to achieve the ambient
      air
      quality standards are required to make emissions reductions. The EPA has
      concluded that the entire state of Iowa, where MidAmerican Energy’s major
      emission sources are located, is in attainment of the ozone standards and the
      fine particulate matter standards.





On
      December 20, 2005, the EPA proposed strengthening the ambient air quality
      standard for fine particulates, suggesting a range of prospective new levels
      for
      fine particulate matter and suggesting maintaining the annual standard at the
      current level while reducing the 24-hour standard. The EPA established a 90-day
      public comment period on its plan, which closes on April 17, 2006, and
      final rules are anticipated to be issued in September 2006 *.* Until
      the public comment period closes and the EPA takes final action on the proposal,
      the impact of the proposed rules on MidAmerican Energy cannot be
      determined.





On
      March 10, 2005, the EPA released the final Clean Air Interstate Rule
      (“CAIR”), calling for reductions of sulfur dioxide (“SO 2 ”)
      and
      nitrogen oxides (“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 is implementing rules that exercise the option of the market-based cap
      and
      trade system. While the state of Iowa has been determined to be in attainment
      of
      the 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 final
      CAIR, the first phase reductions of SO 2 emissions are effective on January 1, 2010, with the second phase
      reductions effective January 1, 2015. For NO x ,
      the
      first phase emissions reductions are effective January 1, 2009, and the
      second phase reductions are effective January 1, 2015. The CAIR calls for
      overall reductions of SO 2 and
      NO x in Iowa
      of 68% and 67%, respectively, by 2015. The CAIR will impact the operation of
      MidAmerican Energy’s generating facilities and will require MidAmerican Energy
      to either reduce emissions from those facilities through the installation of
      emission controls or purchase additional emission allowances, or some
      combination thereof.





99


On
      March 15, 2005, the EPA released the final Clean Air Mercury Rule (“CAMR”).
      The CAMR utilizes a market-based cap and trade mechanism to reduce mercury
      emissions from coal-burning power plants from the current nationwide level
      of
      48 tons to 15 tons at full implementation. The CAMR’s two-phase reduction
      program requires initial reductions of mercury emission in 2010 and an overall
      reduction in mercury emissions from coal-burning power plants of 70% by 2018.
      The CAMR will impact MidAmerican Energy’s coal-burning generating facilities and
      will require MidAmerican Energy to either reduce emissions from those facilities
      through the installation of emission controls or purchase additional emission
      allowances, or some combination thereof.





The
      CAIR
      or the CAMR could, in whole or in part, be superseded or made more stringent
      by
      one of a number of multi-pollutant emission reduction proposals currently under
      consideration at the federal level, including pending legislative proposals
      that
      contemplate 70% to 90% reductions of SO2, NOX and mercury, as well as possible
      new federal regulation of carbon dioxide and other gases that may affect global
      climate change. In addition to any federal legislation that could be enacted
      by
      Congress to supersede the CAIR and the CAMR, the rules could be changed or
      overturned as a result of litigation. The sufficiency of the standards
      established by both the CAIR and the CAMR has been legally challenged in the
      United States District Court for the District of Columbia. Until the court
      makes
      a determination regarding the merits of the challenges to the CAIR and the
      CAMR,
      the full impact of the rules on MidAmerican Energy cannot be
      determined.





MidAmerican
      Energy has implemented a planning process that forecasts the site-specific
      controls and actions that may be required to meet emissions reductions as
      promulgated by the EPA. In accordance with an Iowa law passed in 2001,
      MidAmerican Energy has on file with the IUB its current multi-year plan and
      budget for managing SO2 and NOX from its generating facilities in a
      cost-effective manner. The plan, which is required to be updated every two
      years, provides specific actions to be taken at each coal-fired generating
      facility and the related costs and timing for each action. On July 17,
      2003, the IUB issued an order that affirmed an administrative law judge’s
      approval of the initial plan filed on April 1, 2002, as amended. On
      October 4, 2004, the IUB issued an order approving MidAmerican Energy’s
      second biennial plan as revised in a settlement MidAmerican Energy entered
      into
      with the OCA. That plan covers the time period from April 1, 2004 through
      December 31, 2006. Neither IUB order resulted in any changes to electric
      rates for MidAmerican Energy. The effect of the orders is to approve the
      prudence of expenditures made consistent with the plans. Pursuant to an
      unrelated rate settlement agreement approved by the IUB on October 17,
      2003, if, prior to January 1, 2011, capital and operating expenditures to
      comply with environmental requirements cumulatively exceed $325 million,
      then MidAmerican Energy may seek to recover the additional expenditures from
      customers.





Under
      the
      existing New Source Review (“NSR”) provisions of the Clean Air Act, a utility is
      required to obtain a permit from the EPA or a state regulatory agency prior
      to
      (1) beginning construction of a new major stationary source of an NSR-regulated
      pollutant or (2) making a physical or operational change to an existing facility
      that potentially increases 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 (“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.





In
      recent
      years, the EPA has requested from several utilities information and supporting
      documentation regarding their capital projects for various generating plants.
      The requests were issued as part of an industry-wide investigation to assess
      compliance with the NSR and the New Source Performance Standards of the Clean
      Air Act. In December 2002 and April 2003, MidAmerican Energy received requests
      from the EPA to provide documentation related to its capital projects from
      January 1, 1980, to April 2003 for a number of its generating plants.
      MidAmerican Energy has submitted information to the EPA in responses to these
      requests, and there are currently no outstanding data requests pending from
      the
      EPA. MidAmerican Energy cannot predict the outcome of these requests at this
      time.




100




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, until such time as the legal challenges are resolved and the rules are
        effective, MidAmerican Energy will continue to manage projects at its generating
        plants in accordance with the rules in effect prior to 2002. On June 24,
        2005, the Washington D.C. Circuit Court upheld portions of the EPA’s 2002 NSR
        rule but invalidated other portions. On October 13, 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
        modifications to existing power plants and opened a public comment period,
        which
        ended on February 17, 2006. The impact of these proposed changes on
        MidAmerican Energy cannot be determined until after the rule is finalized
        and
        implemented.




*Nuclear
      Decommissioning Costs*





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





MidAmerican
      Energy’s share of estimated decommissioning costs for Quad Cities Station as of
      December 31, 2005, was $163.0 million and is the ARO liability for
      Quad Cities Station. MidAmerican Energy has established trusts for the
      investment of funds for decommissioning the Quad Cities Station. The fair value
      of the assets held in the trusts was $228.1 million at December 31,
      2005 and is reflected in other investments in the accompanying consolidated
      balance sheets.





*Nuclear
      Insurance*





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





Exelon
      Generation purchases private market nuclear liability insurance for Quad Cities
      Station in the maximum available amount of $300.0 million, which includes
      coverage for MidAmerican Energy’s ownership. In accordance with the
      Price-Anderson Amendments Act of 1988, as amended and extended by the Energy
      Policy Act, excess liability protection above that amount is provided by a
      mandatory industry-wide Secondary Financial Protection program under which
      the
      licensees of nuclear generating facilities could be assessed for liability
      incurred due to a serious nuclear incident at any commercial nuclear reactor
      in
      the United States. Currently, MidAmerican Energy’s aggregate maximum potential
      share of an assessment for Quad Cities Station is approximately
      $50.3 million per incident, payable in installments not to exceed
      $7.5 million annually.





The
      property insurance covers property damage, stabilization and decontamination
      of
      the facility, disposal of the decontaminated material and premature
      decommissioning arising out of a covered loss. For Quad Cities Station, Exelon
      Generation purchases primary and excess property insurance protection for the
      combined interests in Quad Cities Station, with coverage limits totaling
      $2.1 billion. MidAmerican Energy also directly purchases extra expense
      coverage for its share of replacement power and other extra expenses in the
      event of a covered accidental outage at Quad Cities Station. The property and
      related coverages purchased directly by MidAmerican Energy and by Exelon
      Generation, which includes the interests of MidAmerican Energy, are underwritten
      by an industry mutual insurance company and contain provisions for retrospective
      premium assessments should two or more full policy-limit losses occur in one
      policy year. Currently, the maximum retrospective amounts that could be assessed
      against MidAmerican Energy from industry mutual policies for its obligations
      associated with Quad Cities Station total $9.0 million.





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





101


*Legal
      Matters*





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


*CalEnergy
      Generation-Foreign*





Pursuant
      to the share ownership adjustment mechanism in the CE Casecnan stockholder
      agreement, which is based upon pro forma financial projections of the Casecnan
      project prepared following commencement of commercial operations, in February
      2002, MEHC’s indirect wholly-owned subsidiary, CE Casecnan Ltd., advised the
      minority stockholder 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., KEIL Casecnan Ltd. (“KE”), a former stockholder, 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 On January 21, 2004, CE Casecnan
      Ltd., LPG and CE Casecnan entered into a status quo agreement pursuant to which
      the parties agreed to set aside certain distributions related to the shares
      subject to the LPG dispute and CE Casecnan agreed not to take any further
      actions with respect to such distributions without at least 15 days prior notice
      to LPG. Accordingly, 15% of the CE Casecnan dividend distributions declared
      in
      2004 and 2005, totaling $17.6 million, was set aside in a separate bank
      account in the name of CE Casecnan and is shown as restricted cash and
      short-term investments and other current liabilities in the accompanying
      consolidated balance sheets.





On
      August 4, 2005, the court issued a decision, ruling in favor of LPG on five
      of the eight disputed issues in the first phase of the litigation. On
      September 12, 2005, LPG filed a motion seeking the release of the funds
      which have been set aside pursuant to the status quo agreement referred to
      above. MEHC and CE Casecnan Ltd. filed an opposition to the motion on October
      3,
      2005, and at the hearing on October 26, 2005, the court denied LPG’s
      motion. On January 3, 2006, the court entered a judgment in favor of LPG
      against CE Casecnan Ltd. and KE. According to the judgment LPG would retain
      its
      ownership of 15% of the shares of CE Casecnan and distributions of the amounts
      deposited into escrow plus interest at 9% per annum. On February 28, 2006,
      CE Casecnan Ltd. and KE filed an appeal of this judgment and the August 4,
      2005
      decision. The appeal is expected to be resolved sometime in 2007. The impact,
      if
      any, of this litigation on the Company cannot be determined at this
      time.





In
      February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. (“San
      Lorenzo”), an original shareholder substantially all of whose shares in CE
      Casecnan were purchased by MEHC in 1998, threatened to initiate legal action
      against the Company in the Philippines in connection with certain aspects of
      its
      option to repurchase such shares. 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.
      The motion was heard on October 21, 2005, and the court took the matter
      under advisement. 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
      Casecnan, that it is the rightful owner of such shares, and that it is due
      all
      dividends paid on such shares. 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.





**21.**
            **Pension
                and Postretirement
                Commitments**





*Domestic
      Operations*





MidAmerican
      Energy sponsors a noncontributory defined benefit pension plan covering
      substantially all employees of MEHC and its domestic energy subsidiaries.
      Benefit obligations under the plan are based on a cash balance arrangement
      for
      salaried employees and certain union employees and final average pay formulas
      for most union employees. Funding to the established trust is based upon the
      actuarially determined costs of the plan and the requirements of the Internal
      Revenue Code and the Employee Retirement Income Security Act. The Company also
      maintains noncontributory, nonqualified defined benefit supplemental executive
      retirement plans for active and retired participants.




102


MidAmerican
        Energy also sponsors certain postretirement health care and life insurance
        benefits covering substantially all retired employees of MEHC and its domestic
        energy subsidiaries. Under the plans, covered employees may become eligible
        for
        these benefits if they reach retirement age while working for the Company.
        On
        July 1, 2004, the postretirement benefit plan was amended for non-union
        participants. As a result, non-union employees hired July 1, 2004, and
        after are no longer eligible for postretirement benefits other than pensions.
        The plan, as amended, establishes retiree medical accounts for participants
        to
        which the Company makes fixed contributions until the employee’s retirement.
        Participants will use such accounts to pay a portion of their medical premiums
        during retirement. The Company retains the right to change these benefits
        anytime, subject to provisions in its collective bargaining
        agreements.




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. Net periodic
      pension benefit cost, including supplemental retirement, and postretirement
      benefit cost included the following components for MEHC and its domestic energy
      subsidiaries for the years ended December 31:





**Pension
                Cost**
            
            **Postretirement
                Cost****2005**
            
            **2004**
            
            **2003**
            
            **2005**
            
            **2004**
            
            **2003**(in
                thousands)Service
                cost
            
            $
            25,840
            
            $
            25,568
            
            $
            24,693
            
            $
            6,669
            
            $
            7,842
            
            $
            8,175Interest
                cost
            
            
            36,518
            
            
            35,159
            
            
            34,533
            
            
            13,455
            
            
            15,716
            
            
            16,065Expected
                return on plan assets
            
            
            (38,188
            )
            
            (38,258
            )
            
            (38,396
            )
            
            (9,611
            )
            
            (8,437
            )
            
            (6,008
            )Amortization
                of net transition obligation
            
            
            -
            
            
            (792
            )
            
            (2,591
            )
            
            2,403
            
            
            3,283
            
            
            4,110Amortization
                of prior service cost
            
            
            2,766
            
            
            2,758
            
            
            2,761
            
            
            -
            
            
            296
            
            
            593Amortization
                of prior year (gain) loss
            
            
            1,271
            
            
            1,569
            
            
            1,483
            
            
            1,554
            
            
            3,299
            
            
            3,716Regulatory
                expense
            
            
            -
            
            
            -
            
            
            3,320
            
            
            -
            
            
            -
            
            
            -Net
                periodic benefit cost
            
            $
            28,207
            
            $
            26,004
            
            $
            25,803
            
            $
            14,470
            
            $
            21,999
            
            $
            26,651





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





**2005**
            
            **2004**
            
            **2003**
            
            **2005**
            
            **2004**
            
            **2003**Discount
                rate
            5.75%
            
            5.75%
            
            5.75%
            
            5.75%
            
            5.75%
            
            5.75%Rate
                of compensation increase
            5.00%
            
            5.00%
            
            5.00%
            
            Not
                applicable





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





**2005**
            
            **2004**
            
            **2003**
            
            **2005**
            
            **2004**
            
            **2003**Discount
                rate
            5.75%
            
            5.75%
            
            5.75%
            
            5.75%
            
            5.75%
            
            5.75%Expected
                return on plan assets
            7.00%
            
            7.00%
            
            7.00%
            
            7.00%
            
            7.00%
            
            7.00%Rate
                of compensation increase
            5.00%
            
            5.00%
            
            5.00%
            
            Not
                applicable





Assumed
      health care cost trend rates at December 31:





**2005**
            
            **2004**Health
                care cost trend rate assumed for next year
            9.00%
            
            10.00%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
            2010
            
            2010





103


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





Increase
                (Decrease) in ExpenseOne
                Percentage-
            
            One
                Percentage-Point
                Increase
            
            Point
                DecreaseEffect
                on total service and interest cost
            
            $
            2,418
            
            $
            (1,891
            )Effect
                on postretirement benefit obligation
            
            $
            26,434
            
            $
            (21,350
            )





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





**Pension
                Benefits**
            
            **Postretirement
                Benefits****2005**
            
            **2004**
            
            **2005**
            
            **2004**Reconciliation
                of the fair value of plan assets:Fair
                value of plan assets at beginning of year
            
            $
            591,628
            
            $
            551,568
            
            $
            179,375
            
            $
            157,849Employer
                contributions
            
            
            5,786
            
            
            5,083
            
            
            16,615
            
            
            23,782Participant
                contributions
            
            
            -
            
            
            -
            
            
            9,096
            
            
            7,733Actual
                return on plan assets
            
            
            46,966
            
            
            63,151
            
            
            5,958
            
            
            9,698Benefits
                paid
            
            
            (31,551
            )
            
            (28,174
            )
            
            (20,144
            )
            
            (19,687
            )Fair
                value of plan assets at end of year
            
            
            612,829
            
            
            591,628
            
            
            190,900
            
            
            179,375Reconciliation
                of benefit obligation:Benefit
                obligation at beginning of year
            
            
            657,406
            
            
            620,048
            
            
            256,044
            
            
            297,433Service
                cost
            
            
            25,840
            
            
            25,568
            
            
            6,669
            
            
            7,841Interest
                cost
            
            
            36,518
            
            
            35,159
            
            
            13,455
            
            
            15,716Participant
                contributions
            
            
            -
            
            
            -
            
            
            9,096
            
            
            7,733Plan
                amendments
            
            
            (3,184
            )
            
            -
            
            
            (421
            )
            
            (19,219
            )Actuarial
                (gain) loss
            
            
            (6,917
            )
            
            4,805
            
            
            (15,141
            )
            
            (33,773
            )Benefits
                paid
            
            
            (31,551
            )
            
            (28,174
            )
            
            (20,144
            )
            
            (19,687
            )Benefit
                obligation at end of year
            
            
            678,112
            
            
            657,406
            
            
            249,558
            
            
            256,044Funded
                status
            
            
            (65,283
            )
            
            (65,778
            )
            
            (58,658
            )
            
            (76,669
            )Amounts
                not recognized in consolidated balance sheets:Unrecognized
                net (gain) loss
            
            
            (51,285
            )
            
            (34,319
            )
            
            29,725
            
            
            42,768Unrecognized
                prior service cost
            
            
            9,207
            
            
            15,157
            
            
            -
            
            
            -Unrecognized
                net transition obligation (asset)
            
            
            -
            
            
            -
            
            
            16,820
            
            
            19,641Net
                amount recognized in the consolidated balance sheets
            
            $
            (107,361
            )
            $
            (84,940
            )
            $
            (12,113
            )
            $
            (14,260
            )Net
                amount recognized in the consolidated balandce sheets consists
                of:Accrued
                benefit liability
            
            $
            (135,506
            )
            $
            (117,357
            )
            $
            (12,113
            )
            $
            (14,260
            )Intangible
                assets
            
            
            11,939
            
            
            14,653
            
            
            -
            
            
            -Regulatory
                assets
            
            
            11,694
            
            
            17,764
            
            
            -
            
            
            -Accumulated
                other comprehensive income
            
            
            4,512
            
            
            -
            
            
            -
            
            
            -Net
                amount recognized
            
            $
            (107,361
            )
            $
            (84,940
            )
            $
            (12,113
            )
            $
            (14,260
            )





The
      portion of the pension projected benefit obligation, included in the table
      above, related to the supplemental executive retirement plan was
      $105.7 million and $106.5 million as of December 31, 2005 and
      2004, respectively. The supplemental executive retirement plan has no assets,
      and accordingly, the fair value of its plan assets was zero as of
      December 31, 2005 and 2004. The accumulated benefit obligation for all
      defined benefit pension plans was $608.4 million and $585.4 million at
      December 31, 2005 and 2004, respectively. Of these amounts, the
      supplemental executive retirement plan accumulated benefit obligation totaled
      $102.2 million and $102.3 million for 2005 and 2004,
      respectively.


104


Although
      the supplemental executive retirement plan had no assets as of December 31,
      2005, the Company has Rabbi trusts that hold corporate-owned life insurance
      and
      other investments to provide funding for the future cash requirements. Because
      this plan is nonqualified, the assets in the Rabbi trusts are not considered
      plan assets. The cash surrender value of the policies included in the Rabbi
      trusts plus the fair market value of other Rabbi trust investments was
      $102.9 million and $98.8 million at December 31, 2005 and 2004,
      respectively.





Plan
      Assets





The
      Company’s investment policy for its domestic pension and postretirement plans is
      to balance risk and return through a diversified portfolio of high-quality
      equity and fixed income securities. Equity targets for the pension and
      postretirement plans are as indicated in the tables below. Maturities for fixed
      income securities are managed 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 the Company’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.





The
      Company’s pension plan asset allocations at December 31, 2005 and 2004 are
      as follows:





**Percentage
                of****Plan
                Assets****at
                December 31**
            
            **Target****2005**
            
            **2004**
            
            **Range****Asset
                Category**Equity
                securities
            66%
            
            71%
            
            65-75%Debt
                securities
            26%
            
            22%
            
            20-30%Real
                estate
            6%
            
            6%
            
            0-10%Other
            2%
            
            1%
            
            0-5%Total
            100%
            
            100%





The
      Company’s postretirement benefit plan asset allocations at December 31,
      2005 and 2004 are as follows:





**Percentage
                of****Plan
                Assets****at
                December 31**
            
            **Target****2005**
            
            **2004**
            
            **Range****Asset
                Category**Equity
                securities
            50%
            
            49%
            
            45-55%Debt
                securities
            48%
            
            47%
            
            45-55%Other
            2%
            
            4%
            
            0-10%Total
            100%
            
            100%





Cash
      Flows





The
      Company’s expected benefit payments to participants for its pension and
      postretirement plans for 2006 through 2010 and for the five years thereafter
      are
      summarized below (in thousands):





Postretirement
                BenefitsPension
                Benefits
            
            Gross
            
            Medicare
                Subsidy
            
            Net
                of Subsidy2006
            
            $
            32,545
            
            $
            14,054
            
            $
            2,350
            
            $
            11,7042007
            
            
            34,771
            
            
            15,336
            
            
            2,533
            
            
            12,8032008
            
            
            37,347
            
            
            16,434
            
            
            2,719
            
            
            13,7152009
            
            
            41,125
            
            
            17,419
            
            
            2,888
            
            
            14,5312010
            
            
            45,030
            
            
            18,525
            
            
            3,032
            
            
            15,4932011-2015
            
            
            275,118
            
            
            107,131
            
            
            17,728
            
            
            89,403





105


Employer
      contributions to the domestic pension and postretirement plans are currently
      expected to be $6.7 million and $14.5 million, respectively, for 2006.
      The Company’s policy is to contribute the minimum required amount to the pension
      plan and the amount expensed to its postretirement plans.





The
      Company sponsors defined contribution pension plans (401(k) plans) covering
      substantially all domestic employees. The Company’s contributions vary depending
      on the plan but are based primarily on each participant’s level of contribution
      and cannot exceed the maximum allowable for tax purposes. The Company’s total
      contributions were $17.3 million, $17.1 million and $15.5 million
      for 2005, 2004 and 2003, respectively.





In
      December 2003, the President signed into law the Medicare Prescription Drug,
      Improvement and Modernization Act of 2003 (“Medicare Act”). The Medicare Act
      introduces a prescription drug benefit under Medicare as well as a subsidy
      to
      sponsors of retiree health care plans that provide a benefit to participants
      that is at least actuarially equivalent to Medicare Part D. Detailed regulations
      pertaining to the Medicare Act were promulgated in 2004 resulting in a $23.8
      million subsidy to the Company to be used for any valid business purpose. The
      subsidy is reflected as an actuarial gain in benefit obligation in 2004 in
      the
      table above. The impact of the Medicare Act on the net periodic postretirement
      benefit expense is reflected in 2005.





*United
      Kingdom Operations*





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 substantially all employees of CE Electric UK’s
      certain wholly-owned subsidiaries.





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. Net periodic
      pension benefit cost included the following components for CE Electric UK for
      the years ended December 31:





**2005**
            
            **2004**
            
            **2003**Service
                cost
            
            $
            15,292
            
            $
            12,100
            
            $
            9,485Interest
                cost
            
            
            76,460
            
            
            73,515
            
            
            62,632Expected
                return on plan assets
            
            
            (96,849
            )
            
            (98,448
            )
            
            (89,124
            )Amortization
                of prior service cost
            
            
            1,890
            
            
            1,915
            
            
            1,472Amortization
                of loss
            
            
            22,761
            
            
            12,742
            
            
            537Net
                periodic expense (benefit)
            
            $
            19,554
            
            $
            1,824
            
            $
            (14,998
            )





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





**2005**
            
            **2004**
            
            **2003**Discount
                rate
            4.75%
            
            5.25%
            
            5.50%Rate
                of compensation increase
            2.75%
            
            2.75%
            
            2.75%





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





**2005**
            
            **2004**
            
            **2003**Discount
                rate
            5.25%
            
            5.50%
            
            5.75%Expected
                return on plan assets
            7.00%
            
            7.00%
            
            7.00%Rate
                of compensation increase
            2.75%
            
            2.75%
            
            2.50%





106


The
      following table presents a reconciliation of the beginning and ending balances
      of the benefit obligation, fair value of plan assets and the funded status
      of
      the UK Plan to the net amounts measured and recognized in the accompanying
      consolidated balance sheets as of December 31 (in thousands):





**2005**
            
            **2004**Reconciliation
                of the fair value of plan assets:Fair
                value of plan assets at beginning of year
            
            $
            1,364,722
            
            $
            1,206,216Employer
                contributions
            
            
            55,663
            
            
            17,600Participant
                contributions
            
            
            6,190
            
            
            6,417Actual
                return on plan assets
            
            
            211,723
            
            
            106,515Benefits
                paid
            
            
            (67,176
            )
            
            (65,265
            )Foreign
                currency exchange rate changes
            
            
            (151,559
            )
            
            93,239Fair
                value of plan assets at end of year
            
            
            1,419,563
            
            
            1,364,722Reconciliation
                of benefit obligation:Benefit
                obligation at beginning of year
            
            
            1,571,579
            
            
            1,334,587Service
                cost
            
            
            15,292
            
            
            12,100Interest
                cost
            
            
            76,460
            
            
            73,515Participant
                contributions
            
            
            6,190
            
            
            6,417Benefits
                paid
            
            
            (67,176
            )
            
            (65,265
            )Experience
                loss and change of assumptions
            
            
            127,617
            
            
            104,315Foreign
                currency exchange rate changes
            
            
            (170,645
            )
            
            105,910Benefit
                obligation at end of year
            
            
            1,559,317
            
            
            1,571,579Funded
                status
            
            
            (139,754
            )
            
            (206,857
            )Unrecognized
                net loss
            
            
            561,050
            
            
            614,182Net
                amount recognized in the consolidated balance sheets
            
            $
            421,296
            
            $
            407,325Amounts
                recognized in the consolidated balance sheets consist of:Prepaid
                benefit cost
            
            $
            421,296
            
            $
            407,325Accrued
                benefit liability
            
            
            (492,550
            )
            
            (561,988
            )Intangible
                assets
            
            
            12,908
            
            
            16,119Accumulated
                other comprehensive income
            
            
            479,642
            
            
            545,869Net
                amount recognized
            
            $
            421,296
            
            $
            407,325





The
      accumulated benefit obligation for the defined benefit pension plan was
      $1.5 billion at December 31, 2005 and 2004, respectively.





The
      Company recorded a minimum pension liability as of December 31, 2005 and
      2004 in the amount of $479.6 million and $545.9 million, respectively.
      The pension liability is primarily due to the decline in market value of the
      pension plan assets during 2002 combined with the effects of lower discount
      rates and higher rates of compensation increases used to value the plan’s
      liabilities in 2005 and 2004, as well as, mortality assumption changes which
      increased the liability. As of December 31, 2005 and 2004, the minimum
      pension liability is measured as the amount of the plan’s accumulated benefit
      obligation that is in excess of the plan’s market value of assets at
      December 31, 2005 and 2004 plus the prepaid asset balance. A charge equal
      to the excess was recorded to the Company’s stockholders’ equity, net of income
      tax benefits, as a component of comprehensive loss in the amount of
      $(46.4) million and $46.4 million in 2005 and 2004, respectively. This
      adjustment does not impact current year earnings, or the funding requirements
      of
      the plan.





Plan
      Assets





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


107


CE
      Electric UK’s pension plan asset allocation consists of the following at
      December 31:





**Percentage
                of****Plan
                Assets****at
                December 31****,****2005**
            
            **2004**
            
            **Target****Asset
                Category**Equity
                securities
            51%
            
            49%
            
            50%Debt
                securities
            37%
            
            39%
            
            40%Real
                estate
            11%
            
            11%
            
            10%Other
            1%
            
            1%
            
            -%Total
            100%
            
            100%
            
            100%





Cash
      Flows





CE
      Electric UK's expected benefit payments relative to the UK Plan for 2006 through
      2010 and for the five years thereafter are summarized below (in
      millions):





2006
            
            $
            66.22007
            
            
            67.12008
            
            
            67.72009
            
            
            70.22010
            
            
            70.72011-2015
            
            
            378.9





The
      triennial process of valuing the UK Plan's assets and liabilities, which valued
      the plan assets and liabilities as of March 31, 2004, was completed in
      2005. This valuation set a revised level of contributions for the next three
      years. The report of the actuaries conducting the valuation showed a funding
      deficiency of £190.3 million. Based on this valuation, CE Electric UK will
      contribute £23.1 million to the UK Plan each year in respect of the
      existing funding deficiency. The amount in respect of the funding deficiency
      has
      been calculated based on eliminating the funding deficiency over 12 years
      commencing April 1, 2005. Employer contributions to the UK Plan for the
      year ended December 31, 2005 totaled $55.7 million and consisted of
      $24.6 million to fund ongoing liabilities and $31.1 million in respect
      of the existing funding deficiency. Employer contributions to the UK Plan,
      including the £23.1 million deficiency funding, are currently expected to
      be £35.0 million for 2006.


108


**22.**
            **Segment
                Information**





The
      Company has identified seven reportable segments: MidAmerican Energy, Kern
      River, Northern Natural Gas, CE Electric UK, CalEnergy Generation-Foreign,
      CalEnergy Generation-Domestic and HomeServices. The Company’s determination of
      reportable segments considers the strategic units under which the Company is
      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. The reportable segment financial
      information includes all necessary adjustments and eliminations needed to
      conform to the Company’s significant accounting policies including the
      allocation of goodwill. Additionally, the activity of the Company’s Mineral
      Assets, which was previously reported in the CalEnergy Generation-Domestic
      reportable segment, is presented as discontinued operations within the
      accompanying consolidated financial statements. Information related to the
      Company’s reportable segments is shown below (in thousands):





**Year
                Ended December 31,****2005**
            
            **2004**
            
            **2003****Operating
                revenue:**MidAmerican
                Energy
            
            $
            3,166,084
            
            $
            2,701,700
            
            $
            2,600,239Kern
                River
            
            
            323,561
            
            
            316,131
            
            
            260,182Northern
                Natural Gas
            
            
            569,055
            
            
            544,822
            
            
            486,878CE
                Electric UK
            
            
            884,115
            
            
            936,364
            
            
            829,993CalEnergy
                Generation-Foreign
            
            
            312,346
            
            
            307,395
            
            
            326,454CalEnergy
                Generation-Domestic
            
            
            33,825
            
            
            38,960
            
            
            45,154HomeServices
            
            
            1,868,495
            
            
            1,756,454
            
            
            1,476,569Total
                reportable segments
            
            
            7,157,481
            
            
            6,601,826
            
            
            6,025,469Corporate/other(1)
            
            
            (41,942
            )
            
            (48,438
            )
            
            (59,839
            )Total
                operating revenue
            
            $
            7,115,539
            
            $
            6,553,388
            
            $
            5,965,630**Depreciation
                and amortization:**MidAmerican
                Energy
            
            $
            269,142
            
            $
            266,409
            
            $
            281,001Kern
                River
            
            
            62,365
            
            
            53,250
            
            
            36,771Northern
                Natural Gas
            
            
            30,351
            
            
            67,913
            
            
            52,716CE
                Electric UK
            
            
            135,731
            
            
            137,746
            
            
            125,000CalEnergy
                Generation-Foreign
            
            
            90,391
            
            
            90,328
            
            
            87,928CalEnergy
                Generation-Domestic
            
            
            8,748
            
            
            8,721
            
            
            8,882HomeServices
            
            
            17,774
            
            
            20,827
            
            
            17,560Total
                reportable segments
            
            
            614,502
            
            
            645,194
            
            
            609,858Corporate/other(1)
            
            
            (6,304
            )
            
            (6,985
            )
            
            (6,924
            )Total
                depreciation and amortization
            
            $
            608,198
            
            $
            638,209
            
            $
            602,934**Interest
                expense:**MidAmerican
                Energy
            
            $
            137,658
            
            $
            125,189
            
            $
            123,395Kern
                River
            
            
            73,158
            
            
            76,671
            
            
            79,272Northern
                Natural Gas
            
            
            52,590
            
            
            53,100
            
            
            56,008CE
                Electric UK
            
            
            217,909
            
            
            202,067
            
            
            180,207CalEnergy
                Generation-Foreign
            
            
            31,302
            
            
            42,696
            
            
            59,603CalEnergy
                Generation-Domestic
            
            
            18,266
            
            
            18,971
            
            
            19,736HomeServices
            
            
            2,442
            
            
            2,837
            
            
            3,864Total
                reportable segments
            
            
            533,325
            
            
            521,531
            
            
            522,085Corporate/other(1)
            
            
            173,210
            
            
            184,811
            
            
            189,083Parent
                company subordinated debt(2)
            
            
            184,444
            
            
            196,875
            
            
            49,788Total
                interest expense
            
            $
            890,979
            
            $
            903,217
            
            $
            760,956








109





**Year
                Ended December 31,****2005**
            
            **2004**
            
            **2003****Operating
                income:**MidAmerican
                Energy
            
            $
            381,084
            
            $
            355,947
            
            $
            367,868Kern
                River
            
            
            204,488
            
            
            204,776
            
            
            180,978Northern
                Natural Gas
            
            
            208,848
            
            
            190,337
            
            
            175,770CE
                Electric UK
            
            
            483,935
            
            
            497,358
            
            
            445,803CalEnergy
                Generation-Foreign
            
            
            184,986
            
            
            188,529
            
            
            197,527CalEnergy
                Generation-Domestic
            
            
            15,059
            
            
            21,468
            
            
            21,403HomeServices
            
            
            125,321
            
            
            112,928
            
            
            92,874Total
                reportable segments
            
            
            1,603,721
            
            
            1,571,343
            
            
            1,482,223Corporate/other(1)
            
            
            (75,039
            )
            
            (45,942
            )
            
            (32,408
            )Total
                operating income
            
            
            1,528,682
            
            
            1,525,401
            
            
            1,449,815Interest
                expense
            
            
            (890,979
            )
            
            (903,217
            )
            
            (760,956
            )Capitalized
                interest
            
            
            16,716
            
            
            20,040
            
            
            30,494Interest
                and dividend income
            
            
            58,070
            
            
            38,889
            
            
            47,908Other
                income
            
            
            74,516
            
            
            128,205
            
            
            96,643Other
                expense
            
            
            (22,127
            )
            
            (10,125
            )
            
            (5,913
            )Total
                income from continuing operations before income tax expense, minority
                interest and preferred dividends of subsidiaries and equity
                income
            
            $
            764,878
            
            $
            799,193
            
            $
            857,991**Income
                tax expense:**MidAmerican
                Energy
            
            $
            91,371
            
            $
            87,336
            
            $
            110,078Kern
                River
            
            
            50,421
            
            
            54,148
            
            
            51,319Northern
                Natural Gas
            
            
            70,549
            
            
            84,423
            
            
            50,599CE
                Electric UK
            
            
            92,766
            
            
            80,211
            
            
            91,539CalEnergy
                Generation-Foreign
            
            
            55,855
            
            
            62,548
            
            
            62,130CalEnergy
                Generation-Domestic
            
            
            (995
            )
            
            1,217
            
            
            1,078HomeServices
            
            
            56,359
            
            
            52,996
            
            
            43,587Total
                reportable segments
            
            
            416,326
            
            
            422,879
            
            
            410,330Corporate/other(1)
            
            
            (171,617
            )
            
            (157,893
            )
            
            (140,054
            )Total
                income tax expense
            
            $
            244,709
            
            $
            264,986
            
            $
            270,276**Capital
                expenditures:**MidAmerican
                Energy
            
            $
            700,954
            
            $
            633,807
            
            $
            346,449Kern
                River
            
            
            7,367
            
            
            26,936
            
            
            433,125Northern
                Natural Gas
            
            
            124,739
            
            
            138,747
            
            
            104,400CE
                Electric UK
            
            
            342,585
            
            
            334,458
            
            
            301,896CalEnergy
                Generation-Foreign
            
            
            562
            
            
            4,633
            
            
            8,497CalEnergy
                Generation-Domestic
            
            
            574
            
            
            1,341
            
            
            6,619HomeServices
            
            
            18,874
            
            
            20,786
            
            
            18,311Total
                reportable segments
            
            
            1,195,655
            
            
            1,160,708
            
            
            1,219,297Corporate/other(1)
            
            
            582
            
            
            18,682
            
            
            71Total
                capital expenditures
            
            $
            1,196,237
            
            $
            1,179,390
            
            $
            1,219,368





110





**As
                of December 31,****2005**
            
            **2004**
            
            **2003****Total
                assets:**MidAmerican
                Energy
            
            $
            8,003,423
            
            $
            7,274,999
            
            $
            6,596,849Kern
                River
            
            
            2,099,625
            
            
            2,135,265
            
            
            2,200,201Northern
                Natural Gas
            
            
            2,245,308
            
            
            2,200,846
            
            
            2,167,621CE
                Electric UK
            
            
            5,742,718
            
            
            5,794,887
            
            
            5,038,880CalEnergy
                Generation-Foreign
            
            
            643,130
            
            
            767,465
            
            
            951,155CalEnergy
                Generation-Domestic
            
            
            555,078
            
            
            553,741
            
            
            1,113,172HomeServices
            
            
            814,280
            
            
            737,085
            
            
            567,736Total
                reportable segments
            
            
            20,103,562
            
            
            19,464,288
            
            
            18,635,614Corporate/other(1)
            
            
            89,398
            
            
            439,274
            
            
            509,338Total
                assets
            
            $
            20,192,960
            
            $
            19,903,562
            
            $
            19,144,952**Long-lived
                assets:**MidAmerican
                Energy
            
            $
            4,447,509
            
            $
            3,892,031
            
            $
            3,385,056Kern
                River
            
            
            1,891,027
            
            
            1,945,094
            
            
            1,976,213Northern
                Natural Gas
            
            
            1,585,029
            
            
            1,491,428
            
            
            1,430,475CE
                Electric UK
            
            
            3,501,218
            
            
            3,691,459
            
            
            3,227,723CalEnergy
                Generation-Foreign
            
            
            430,590
            
            
            520,406
            
            
            621,674CalEnergy
                Generation-Domestic
            
            
            241,701
            
            
            256,429
            
            
            738,296HomeServices
            
            
            62,292
            
            
            59,827
            
            
            53,518Total
                reportable segments
            
            
            12,159,366
            
            
            11,856,674
            
            
            11,432,955Corporate/other(1)
            
            
            (243,953
            )
            
            (249,410
            )
            
            (251,976
            )Total
                long-lived assets
            
            $
            11,915,413
            
            $
            11,607,264
            
            $
            11,180,979





(1)
            The
                remaining differences between the segment amounts and the consolidated
                amounts described as “Corporate/other” relate principally to intersegment
                eliminations for operating revenue and, for the other items presented,
                to
                (i) corporate functions, including administrative costs, interest
                expense,
                corporate cash and related interest income, (ii) intersegment eliminations
                and (iii) fair value adjustments relating to
                acquisitions.(2)
            The
                Company adopted and applied the provisions of FIN 46R, related to
                certain
                finance subsidiaries, as of October 1, 2003. The adoption required
                the deconsolidation of certain finance subsidiaries, which resulted
                in
                amounts that were previously recorded as minority interest and preferred
                dividends of subsidiaries being prospectively recorded as interest
                expense
                in the accompanying consolidated statements of operations. For the
                years
                ended December 31, 2005 and 2004, and the three-month period ended
                December 31, 2003, the Company has recorded $184.4 million,
                $196.9 million and $49.8 million, respectively, of interest
                expense related to these securities. In accordance with the requirements
                of FIN 46R, no amounts prior to adoption of FIN 46R on October 1,
                2003 have been reclassified. The amount included in minority interest
                and
                preferred dividends of subsidiaries related to these securities for
                the
                nine-month period ended September 30, 2003 was
                $170.2 million.


111


The
      following table shows the change in the carrying amount of goodwill by
      reportable segment for the years ended December 31, 2005 and 2004 (in
      thousands):





**Northern**
            
            **CE**
            
            **CalEnergy****MidAmerican**
            
            **Kern**
            
            **Natural**
            
            **Electric**
            
            **Generation**
            
            **Home-****Energy**
            
            **River**
            
            **Gas**
            
            **UK**
            
            **Domestic**
            
            **Services**
            
            **Total****Balance,
                January 1, 2004**
            
            $
            2,139,223
            
            $
            33,900
            
            $
            379,148
            
            $
            1,261,583
            
            $
            126,308
            
            $
            365,481
            
            $
            4,305,643Goodwill
                from acquisitions during the year
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            32,120
            
            
            32,120Foreign
                currency translation adjustment
            
            
            -
            
            
            -
            
            
            -
            
            
            72,218
            
            
            -
            
            
            -
            
            
            72,218Impairment
                losses(1)
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            (52,776
            )
            
            -
            
            
            (52,776
            )Other
                goodwill adjustments(2)
            
            
            (18,098
            )
            
            -
            
            
            (24,236
            )
            
            (4,010
            )
            
            (1,038
            )
            
            (3,072
            )
            
            (50,454
            )**Balance,
                December 31, 2004**
            
            
            2,121,125
            
            
            33,900
            
            
            354,912
            
            
            1,329,791
            
            
            72,494
            
            
            394,529
            
            
            4,306,751Goodwill
                from acquisitions during the year
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            3,630
            
            
            3,630Foreign
                currency translation adjustment
            
            
            -
            
            
            -
            
            
            -
            
            
            (106,354
            )
            
            -
            
            
            -
            
            
            (106,354
            )Other
                goodwill adjustments(2)
            
            
            (3,489
            )
            
            -
            
            
            (27,808
            )
            
            (16,229
            )
            
            (151
            )
            
            (170
            )
            
            (47,847
            )**Balance,
                December 31, 2005**
            
            $
            2,117,636
            
            $
            33,900
            
            $
            327,104
            
            $
            1,207,208
            
            $
            72,343
            
            $
            397,989
            
            $
            4,156,180





(1)
            Impairment
                losses relate to the write-off of the Mineral Assets - see Note
                17.





(2)
            Other
                goodwill adjustments include primarily income tax
                adjustments.





112


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





None.





**Item
      9A.** **Controls
      and Procedures.**





An
      evaluation was performed under the supervision and with the participation of
      the
      Company’s management, including the chief executive officer and chief financial
      officer, regarding the effectiveness of the design and operation of the
      Company’s disclosure controls and procedures (as defined in Rule 13a-15(e)
      promulgated under the Securities and Exchange Act of 1934, as amended) as of
      December 31, 2005. Based on that evaluation, the Company’s management,
      including the chief executive officer and chief financial officer, concluded
      that the Company’s disclosure controls and procedures were effective. There have
      been no changes during the fourth quarter of 2005 in the Company’s internal
      control over financial reporting that has materially affected, or is reasonably
      likely to materially affect, the Company’s internal control over financial
      reporting.





**Item
      9B.** **Other
      Information.**





On
      March 1, 2006, MEHC and Berkshire Hathaway entered into 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, and will not be used for the PacifiCorp
      acquisition or for other future acquisitions.





Effective
      March 1, 2006, Messrs. W. David Scott, Edgar D. Aronson, John K. Boyer,
      Stanley J. Bright and Richard R. Jaros resigned from the Board of Directors
      of
      MEHC. Mr. Jaros was a member of MEHC’s Audit Committee.





On
      November 16, 2005, MEHC issued 200,000 shares of its common stock, no par
      value, to Mr. David L. Sokol, its Chairman and Chief Executive Officer, upon
      the
      exercise by Mr. Sokol of 200,000 of his outstanding common stock options. The
      common stock options were exercisable at a price of $29.01 per share and the
      aggregate exercise price paid by Mr. Sokol was $5.8 million. The issuance
      was pursuant to a private placement and was exempt from the registration
      requirements of the Securities Act of 1933, as amended.


113


**PART
      III**





**Item
      10.** **Directors
      and Executive Officers of the
      Registrant.**





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





**Name**
            **Position**David
                L. Sokol
            Chairman
                of the Board of Directors and Chief Executive OfficerGregory
                E. Abel
            President,
                Chief Operating Officer and DirectorPatrick
                J. Goodman
            Senior
                Vice President and Chief Financial OfficerDouglas
                L. Anderson
            Senior
                Vice President, General Counsel and Corporate SecretaryMaureen
                E. Sammon
            Senior
                Vice President, Human Resources, Information Technology and
                InsuranceKeith
                D. Hartje
            Senior
                Vice President, Communications, General Services and Safety Audit
                and
                ComplianceWarren
                E. Buffett
            DirectorWalter
                Scott Jr.
            DirectorMarc
                D. Hamburg
            Director





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





Set
      forth
      below is certain information, as of March 1, 2006, with respect to each of
      the foregoing officers and directors:





DAVID
      L.
      SOKOL, 49, Chairman of the Board of Directors and Chief Executive Officer.
      Mr. Sokol has been the Chief Executive Officer since April 19, 1993
      and served as President of MEHC from April 19, 1993 until January 21,
      1995. Mr. Sokol has been Chairman of the Board of Directors since May 1994
      and a director since March 1991. Formerly, among other positions held in the
      independent power industry, Mr. Sokol served as President and Chief Executive
      Officer of Kiewit Energy Company, which at that time was a wholly owned
      subsidiary of Peter Kiewit & Sons’, Inc., and Ogden Projects,
      Inc.





GREGORY
      E. ABEL, 43, President, Chief Operating Officer and Director. Mr. Abel joined
      MEHC in 1992 and initially served as Vice President and Controller.
      Mr. Abel is a Chartered Accountant and from 1984 to 1992 was employed by
      PricewaterhouseCoopers. As a Manager in the San Francisco office of
      PricewaterhouseCoopers, he was responsible for clients in the energy
      industry.





PATRICK
      J. GOODMAN, 39, Senior Vice President and Chief Financial Officer.
      Mr. Goodman joined MEHC in 1995 and has served in various financial
      positions including Chief Accounting Officer. Prior to joining MEHC, Mr. Goodman
      was a financial manager for National Indemnity Company and a senior associate
      at
      PricewaterhouseCoopers.





DOUGLAS
      L. ANDERSON, 47, Senior Vice President, General Counsel and Corporate Secretary.
      Mr. Anderson joined MEHC in February 1993 and has served in various legal
      positions including General Counsel of the Company’s independent power
      affiliates. Prior to that, Mr. Anderson was a corporate attorney in private
      practice.





MAUREEN
      E. SAMMON, 42, Senior Vice President, Human Resources, Information Technology
      and Insurance. Ms. Sammon has been with MidAmerican Energy and its predecessor
      companies since 1986. In that time, she has held several positions, including
      Manager of Benefits and Vice President, Human Resources and
      Insurance.





KEITH
      D.
      HARTJE, 56, Senior Vice President, Communications, General Services and Safety
      Audit and Compliance. Mr. Hartje has been with MidAmerican Energy and its
      predecessor companies since 1973. In that time, he has held a number of
      positions, including General Counsel and Corporate Secretary, District Vice
      President for southwest Iowa operations, and Vice President, Corporate
      Communications.





WARREN
      E.
      BUFFETT, 75, Director. Mr. Buffett has been a director of MEHC since March
      2000. He is Chairman of the Board and Chief Executive Office of Berkshire
      Hathaway. Mr. Buffett is a Director of the Coca Cola Company and The
      Washington Post Company.


114


WALTER
      SCOTT, JR., 74, Director. Mr. Scott has been a director of MEHC since June
      1991. Mr. Scott was the Chairman and Chief Executive Officer of MEHC from
      January 8, 1992 until April 19, 1993. For more than five years, he has
      been Chairman of the Board of Directors of Level 3 Communications, Inc., a
      successor to certain businesses of Peter Kiewit & Sons’, Inc. Mr. Scott
      is a director of Peter Kiewit & Sons’, Inc., Berkshire Hathaway, Burlington
      Resources, Inc., Valmont Industries, Inc. and Commonwealth Telephone
      Enterprises, Inc.





MARC
      D.
      HAMBURG, 56, Director. Mr. Hamburg has been a director of MEHC since March
      2000. He has served as Vice President - Chief Financial Officer of Berkshire
      Hathaway since October 1, 1992 and Treasurer since June 1, 1987, his
      date of employment with Berkshire Hathaway.





**Audit
      Committee Members and Financial Experts**





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. Mr. Hamburg is not independent within
      the
      meaning of Item 7(d)(3)(iv) of Schedule 14A under the Exchange Act.





**Code
      of Ethics**





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





**Item
      11.** **Executive
      Compensation.**





The
      following table sets forth the compensation of MEHC’s Chief Executive Officer
      and its four other most highly compensated executive officers who were employed
      as of December 31, 2005, which MEHC refers to as its Named Executive
      Officers. Information is provided regarding its Named Executive Officers for
      the
      last three fiscal years during which they were its executive officers, if
      applicable.





**Name
                and Principal Positions**
            
            **Year**
              **Ended**
              **Dec.
                31**
            
            **Salary****(1)**
            
            **Bonus****(1)**
            
            **Other**
              **Annual**
              **Comp****(2)**
            
            **LTIP**
              **Payouts**
            
            **All**
              **Other**
              **Comp****(3)**David
                L. Sokol
            
            
            2005
            
            $
            850,000
            
            $
            13,750,000
            
            $
            103,929
            
            $
            -
            
            $
            10,290Chairman
                and Chief
            
            
            2004
            
            
            800,000
            
            
            2,500,000
            
            
            131,644
            
            
            -
            
            
            9,995Executive
                Officer
            
            
            2003
            
            
            800,000
            
            
            2,750,000
            
            
            141,501
            
            
            -
            
            
            9,800Gregory
                E. Abel
            
            
            2005
            
            
            740,000
            
            
            13,450,000
            
            
            -
            
            
            -
            
            
            10,290President
                and
            
            
            2004
            
            
            720,000
            
            
            2,200,000
            
            
            80,424
            
            
            -
            
            
            9,995Chief
                Operating Officer
            
            
            2003
            
            
            700,000
            
            
            2,200,000
            
            
            87,162
            
            
            -
            
            
            9,800Patrick
                J. Goodman
            
            
            2005
            
            
            297,500
            
            
            325,000
            
            
            -
            
            
            107,212
            
            
            67,269Senior
                Vice President and
            
            
            2004
            
            
            290,000
            
            
            295,000
            
            
            -
            
            
            257,694
            
            
            88,391Chief
                Financial Officer
            
            
            2003
            
            
            275,000
            
            
            285,000
            
            
            -
            
            
            -
            
            
            108,631Douglas
                L. Anderson
            
            
            2005
            
            
            275,000
            
            
            265,000
            
            
            -
            
            
            87,769
            
            
            60,456Senior
                Vice President and
            
            
            2004
            
            
            270,000
            
            
            240,000
            
            
            -
            
            
            151,585
            
            
            77,145General
                Counsel
            
            
            2003
            
            
            260,000
            
            
            240,000
            
            
            -
            
            
            -
            
            
            83,703Maureen
                E. Sammon
            
            
            2005
            
            
            175,000
            
            
            110,000
            
            
            -
            
            
            -
            
            
            39,397Senior
                Vice President, Human Resources,
            
            
            2004
            
            
            165,000
            
            
            80,000
            
            
            -
            
            
            -
            
            
            42,236Information
                Technology and Insurance
            
            
            2003
            
            
            147,500
            
            
            65,000
            
            
            -
            
            
            -
            
            
            35,223





115


**______________**





(1)
            Includes
                amounts voluntarily deferred by the executive, if applicable. Pursuant
                to
                MEHC’s Executive Incremental Profit Sharing Plan, Messrs. Sokol and
                Abel each received a profit sharing award of $11.25 million based
                upon achieving the specified adjusted diluted earnings per share
                target
                for the year ended December 31, 2005. Messrs. Sokol and Abel are
                each eligible to receive additional profit sharing awards of
                $7.5 million or $26.25 million based upon achieving specified
                adjusted diluted earnings per share targets for any calendar year
                2006 and
                2007. In 2005, Messrs. Goodman and Anderson and Ms. Sammon each received
                a
                performance award related to the pending acquisition of
                PacifiCorp.(2)
            Consists
                of perquisites and other benefits if the aggregate amount of such
                benefits
                exceeds the lesser of either $50,000 or 10% of the total of salary
                and
                bonus reported for the Named Executive Officer. The amounts shown
                include
                the personal use of aircraft for 2005 for Mr. Sokol of
                $76,811.(3)
            Consists
                of the 2005 earnings on the MEHC Long-Term Incentive Partnership
                Plan
                (“LTIP”) awards not paid out in 2005 and 401(k) plan contributions. For
                2005, LTIP earnings on awards not paid out in 2005 were $56,979 for
                Mr. Goodman, $50,166 for Mr. Anderson and $29,457 for Ms.
                Sammon. Messrs. Sokol and Abel are not participants in the LTIP.
                Additionally, the amounts shown include company 401(k) contributions
                for
                2005 for Messrs. Sokol, Abel, Goodman and Anderson of $10,290 and for
                Ms. Sammon of $9,940.





**Option
      Grants in Last Fiscal Year**





MEHC
      did
      not grant any options during 2005.





**Aggregated
      Option Exercises in Last Fiscal Year and Fiscal Year End Option
      Values**





The
      following table sets forth the option exercises and the number of securities
      underlying exercisable and unexercisable options held by each of its Named
      Executive Officers at December 31, 2005.





**Shares
                Acquired**
            
            **Value**
            
            **Underlying
                Unexercised**
            
            **Value
                of Unexercised****On
                Exercise**
            
            **Realized**
            
            **Options
                Held (#)**
            
            **In-the-money
                Options ($)****(1)****Name**
            
            **(#)**
            
            **($)**
            
            **Exercisable**
            
            **Unexercisable**
            
            **Exercisable**
            
            **Unexercisable**David
                Sokol
            
            
            200,000
            
            $
            16,798,740
            
            
            1,199,277
            
            
            -
            
            $
            134,652,051
            
            
            N/AGregory
                E. Abel
            
            
            -
            
            
            -
            
            
            649,052
            
            
            -
            
            $
            76,518,336
            
            
            N/APatrick
                J. Goodman
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Douglas
                L. Anderson
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Maureen
                E. Sammon
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -





**______________**





(1)
            On
                March 14, 2000, MEHC was acquired by a private investor group and on
                February 9, 2006, became a majority-owned subsidiary of Berkshire
                Hathaway. As a privately held company, MEHC has no publicly traded
                equity
                securities. The value shown is based on an assumed fair market value
                of
                the common stock of $145 per share as of December 31, 2005, as agreed
                to by MEHC stockholders.





116


**Long-Term
      Incentive Plans - Awards in Last Fiscal Year**





**Number
                of Shares,**
            
            **Performance
                  or****Units
                or Other**
            
            **Other
                Period
                Until**
            
            **Threshold**
            
            **Target**
            
            **Maximum****Name**
            
            **Rights
                (#)**
            
            **Maturation
                or Payout**
            
            **($)****(1)**
            
            **($)****(1)**
            
            **($)****(1)**Patrick
                J. Goodman
            
            
            N/A
            
            
            December
                31, 2009
            
            $
            446,250
            
            
            N/A
            
            
            N/ADouglas
                L. Anderson
            
            
            N/A
            
            
            December
                31, 2009
            
            $
            404,406
            
            
            N/A
            
            
            N/AMaureen
                E. Sammon
            
            
            N/A
            
            
            December
                31, 2009
            
            $
            262,500
            
            
            N/A
            
            
            N/A





**______________**





(1)
            The
                awards shown in the foregoing table are made pursuant to the LTIP.
                The
                amounts shown are dollar amounts credited to an investment account
                for the
                benefit of the named executive officers and such amounts vest equally
                over
                five years (starting with year 2005) with any unvested balances forfeited
                upon termination of employment. Vested balances (including any investment
                performance profits or losses thereon) are paid to the participant
                at the
                time of termination. Once an award is fully vested, the participant
                may
                elect to defer or receive payment of part or the entire award. Awards
                are
                credited or reduced with annual interest or loss based on a composite
                of
                funds or indices. Because the amounts to be paid out may increase
                or
                decrease depending on investment performance, the ultimate benefits
                are
                undeterminable and the payouts do not have a “target” or “maximum”
                amount.





**Compensation
      of Directors**





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





**Retirement
      Plans**





The
      MidAmerican Energy Company Supplemental Retirement Plan for Designated Officers
      (the “SERP”), provides additional retirement benefits to designated
      participants, as determined by the Board of Directors. Messrs. Sokol, Abel
      and Goodman are participants in the SERP. The SERP provides annual retirement
      benefits up to sixty-five percent of a participant’s Total Cash Compensation in
      effect immediately prior to retirement, subject to a $1 million maximum
      retirement benefit. “Total Cash Compensation” means the highest amount payable
      to a participant as monthly base salary during the five years immediately prior
      to retirement multiplied by 12 plus the average of the participant’s last three
      years awards under an annual incentive bonus program and special, additional
      or
      non-recurring bonus awards, if any, that are required to be included in Total
      Cash Compensation pursuant to a participant’s employment agreement or approved
      for inclusion by the Board. Participants must be credited with five years of
      service to be eligible to receive benefits under the SERP. Each of the
      Messrs. Sokol, Abel and Goodman has five years of credited service with the
      Company and will be eligible to receive benefits under the SERP. A participant
      who elects early retirement is entitled to reduced benefits under the SERP,
      however, in accordance with their respective employment agreements,
      Messrs. Sokol and Abel are eligible to receive the maximum retirement
      benefit at age 47. A survivor benefit is payable to a surviving spouse under
      the
      SERP. Benefits from the SERP will be paid out of general corporate funds;
      however, through a Rabbi trust, the Company maintains life insurance on the
      participants in amounts expected to be sufficient to fund the after-tax cost
      of
      the projected benefits. Deferred compensation is considered part of the salary
      covered by the SERP. The SERP benefit will be reduced by the amount of the
      participant’s regular retirement benefit under the MidAmerican Energy Company
      Cash Balance Retirement Plan (the “MidAmerican Retirement Plan”), which became
      effective January 1, 1997.





The
      MidAmerican Retirement Plan replaced retirement plans of predecessor companies
      that were structured as traditional, defined benefit plans. Under the
      MidAmerican Retirement Plan, each participant has an account, for record keeping
      purposes only, to which credits are allocated annually based upon a percentage
      of the participant’s salary paid in the plan year. In addition, all balances in
      the accounts of participants earn a fixed rate of interest that is credited
      annually. The interest rate for a particular year is based on the one-year
      constant maturity Treasury yield plus seven-tenths of one percentage point.
      At
      retirement, or other termination of employment, an amount equal to the vested
      balance then credited to the account is payable to the participant in the form
      of a lump sum or a form of annuity for the entire benefit under the MidAmerican
      Retirement Plan. The estimated annual benefit payable upon normal retirement
      age
      (65) for Mr. Anderson is $89,109 and for Ms. Sammon is $141,535. These
      estimates assume an interest credit rate of 6.0 percent and conversion to a
      life
      annuity using plan mortality and 6.0 percent interest. Mr. Anderson and Ms.
      Sammon are not participants in the SERP.





117


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





**Total
                  Cash**
              
              **Estimated
                  Annual Benefit****Compensation**
              
              **Age
                  of Retirement****at
                  Retirement ($)**
              
              **55**
              
              **60**
              
              **65**$400,000
              
              $
              220,000
              
              $
              240,000
              
              $
              260,000500,000
              
              
              275,000
              
              
              300,000
              
              
              325,000600,000
              
              
              330,000
              
              
              360,000
              
              
              390,000700,000
              
              
              385,000
              
              
              420,000
              
              
              455,000800,000
              
              
              440,000
              
              
              480,000
              
              
              520,000900,000
              
              
              495,000
              
              
              540,000
              
              
              585,0001,000,000
              
              
              550,000
              
              
              600,000
              
              
              650,0001,250,000
              
              
              687,500
              
              
              750,000
              
              
              812,5001,500,000
              
              
              825,000
              
              
              900,000
              
              
              975,0001,750,000
              
              
              962,500
              
              
              1,000,000
              
              
              1,000,0002,000,000 and greater
              
              
              1,000,000
              
              
              1,000,000
              
              
              1,000,000





**Employment
      Agreements**





Pursuant
      to his employment agreement, Mr. Sokol serves as Chairman of MEHC’s Board
      of Directors and Chief Executive Officer. The employment agreement provides
      that
      Mr. Sokol is to receive an annual base salary of not less than $750,000,
      senior executive employee benefits and annual bonus awards that shall not be
      less than $675,000. The agreement is currently scheduled to expire on
      August 21, 2006, but renews automatically from year to year subject to Mr.
      Sokol’s election to decline renewal at least 120 days prior to such date or
      termination by MEHC.





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





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





118


Under
      the
      terms of separate employment agreements with MEHC, each of Messrs. Abel and
      Goodman is entitled to receive two years base salary continuation, payments
      in
      respect of average bonuses for the prior two years and two years continued
      option vesting in the event MEHC terminates his employment other than for cause.
      If such persons were terminated without cause, Messrs. Sokol, Abel and
      Goodman would currently be entitled to be paid approximately $10,050,000,
      $5,880,000 and $1,215,000, respectively, without giving effect to any
      tax-related provisions.





**Compensation
      Committee Interlocks and Insider Participation**





The
      compensation committee of the Board of Directors is comprised of
      Messrs. Warren E. Buffett and Walter Scott, Jr. Mr. Walter Scott, Jr.
      is a former officer of the Company. See also Item 13. Certain Relationships
      and
      Related Transactions of this Form 10-K.





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





The
      following table sets forth certain information regarding beneficial ownership
      of
      the shares of MEHC’s common stock and certain information with respect to the
      beneficial ownership of each director, its Named Executive Officers and all
      directors and executive officers as a group as of March 1,
      2006.





**Number
                of Shares**
            
            **Percentage****Name
                and Address of Beneficial Owner****(1)**
            
            **Beneficially
                Owned****(2)**
            
            **Of
                Class****(2)**Common
                Stock:Berkshire
                Hathaway(3)
            
            42,164,337
            
            83.42%Walter
                Scott, Jr.(4)
            
            4,972,000
            
            9.84%David
                L. Sokol(5)
            
            1,523,482
            
            2.94%Gregory
                E. Abel(6)
            
            704,992
            
            1.38%Douglas
                L. Anderson
            
            -
            
            -Warren
                E. Buffett(7)
            
            -
            
            -Patrick
                J. Goodman
            
            -
            
            -Marc
                D. Hamburg(7)
            
            -
            
            -Maureen
                E. Sammon
            
            -
            
            -All
                directors and executive officers as a group (8 persons)
            
            7,200,474
            
            13.74%





**______________**





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





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





(3)
            Such
                beneficial owner’s address is 1440 Kiewit Plaza, Omaha, Nebraska
                68131.





(4)
            Excludes
                3,000,000 shares held by family members and family controlled trusts
                and
                corporations (“Scott Family Interests”) as to which Mr. Scott
                disclaims beneficial ownership. Such beneficial owner’s address is 1000
                Kiewit Plaza, Omaha, Nebraska
                68131.





(5)
            Includes
                options to purchase 1,199,277 shares of common stock that are exercisable
                within 60 days.





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





(7)
            Excludes
                42,164,337 shares of common stock held by Berkshire Hathaway of which
                beneficial ownership of such shares is
                disclaimed.


119


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, Walter Scott,
      Jr. 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 MEHC’s common stock for shares of Berkshire Hathaway common
      stock.





**Item
      13.** **Certain
      Relationships and Related
      Transactions.**





Under
      a
      subscription agreement with MEHC, which expires in March 2007, Berkshire
      Hathaway has agreed to purchase, under certain circumstances, additional 11%
      trust issued mandatorily redeemable preferred securities in the event that
      certain outstanding trust preferred securities of MEHC which were outstanding
      prior to the closing of its acquisition by a private investor group on
      March 14, 2000 are tendered for conversion to cash by the current
      holders.





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





The
      Energy Policy Act became law on August 8, 2005 and included the repeal of
      PUHCA 1935 effective February 8, 2006. On February 9, 2006, 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 and, upon conversion, has an 83.4% (80.5% on a diluted basis) voting
      interest in MEHC.





**Item
      14.** **Principal
      Accountant Fees and Services.**





Aggregate
      fees billed to the Company as a consolidated entity during the fiscal years
      ending December 31, 2005 and 2004 by the Company’s principal accounting
      firm, Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu,
      and their respective affiliates (collectively, the “Deloitte Entities”), are set
      forth below. The audit committee has considered whether the provision of the
      non-audit services described below is compatible with maintaining the principal
      accountant’s independence and concluded that these are not independence
      impairing services.





**Year
                Ended December 31,****2005**
            
            **2004****(in
                millions)**Audit
                Fees(1)
            
            $
            2.6
            
            $
            2.3Audit-Related
                Fees(2)
            
            
            0.1
            
            
            0.1Tax
                Fees(3)
            
            
            0.2
            
            
            0.4All
                Other Fees(4)
            
            
            -
            
            
            -Total
                aggregate fees billed
            
            $
            2.9
            
            $
            2.8





**______________**





(1)
            Includes
                the aggregate fees billed for each of the last two fiscal years for
                professional services rendered by the Deloitte Entities for the audit
                of
                the Company’s annual financial statements and the review of financial
                statements included in the Company’s Form 10-Q or for services that are
                normally provided by the Deloitte Entities in connection with statutory
                and regulatory filings or engagements for those fiscal
                years.





(2)
            Includes
                the aggregate fees billed in each of the last two fiscal years for
                assurance and related services by the Deloitte Entities that are
                reasonably related to the performance of the audit or review of the
                Company’s financial statements. Services included in this category include
                audits of benefit plans, due diligence for possible acquisitions
                and
                consultation pertaining to new and proposed accounting and regulatory
                rules.


120


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





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





The
      audit
      committee reviewed the non-audit services rendered by the Deloitte Entities
      in
      and for fiscal 2005 as set forth in the above table and concluded that such
      services were compatible with maintaining the principal accountant’s
      independence. Under the Sarbanes-Oxley Act of 2002, all audit and non-audit
      services performed by the Company’s principal accountant are approved in advance
      by the audit committee to assure that such services do not impair the principal
      accountant’s independence from the Company. Accordingly, the audit committee has
      an Audit and Non-Audit Services Pre-Approval Policy (the “Policy”) which sets
      forth the procedures and the conditions pursuant to which services to be
      performed by the principal accountant are to be pre-approved. Pursuant to the
      Policy, certain services described in detail in the Policy may be pre-approved
      on an annual basis together with pre-approved maximum fee levels for such
      services. The services eligible for annual pre-approval consist of services
      that
      would be included under the categories of Audit Fees, Audit-Related Fees and
      Tax
      Fees. If not pre-approved on an annual basis, proposed services must otherwise
      be separately approved prior to being performed by the principal accountant.
      In
      addition, any services that receive annual pre-approval but exceed the
      pre-approved maximum fee level also will require separate approval by the audit
      committee prior to being performed. The audit committee may delegate authority
      to pre-approve audit and non-audit services to any member of the audit
      committee, but may not delegate such authority to management.





121




**PART
      IV**





**Item
      15.** **Exhibits
      and Financial Statement
      Schedules.**





(a)
            Financial
                Statements and Schedules(i)
            Financial
                StatementsFinancial
                Statements are included in Item 8 of this Form 10-K.(ii)
            Financial
                Statement SchedulesSee
                Schedule I on page 123.See
                Schedule II on page 126.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.(b)
            ExhibitsThe
                exhibits listed on the accompanying Exhibit Index are filed as part
                of
                this Annual Report.(c)
            Financial
                statements required by Regulation S-X, which are excluded from the
                Annual
                Report by Rule 14a-3(b).Not
                applicable.





122





**Schedule
      I**


**MidAmerican
      Energy Holdings Company**


**Parent
      Company Only**


Condensed
      Balance Sheets


As
      of
      December 31, 2005 and 2004


(Amounts
      in thousands)





**2005**
            
            **2004****ASSETS**Current
                assets:Cash
                and cash equivalents
            
            $
            2,019
            
            $
            265,639Short-term
                investments
            
            
            -
            
            
            84,050Other
                current assets
            
            
            6,611
            
            
            21,720Total
                current assets
            
            
            8,630
            
            
            371,409Investments
                in and advances to subsidiaries and joint ventures
            
            
            6,565,651
            
            
            6,129,526Equipment,
                net
            
            
            43,916
            
            
            51,248Goodwill
            
            
            1,297,245
            
            
            1,299,560Notes
                receivable - affiliate
            
            
            54,283
            
            
            31,500Deferred
                charges and other assets
            
            
            120,343
            
            
            120,741**Total
                assets**
            
            $
            8,090,068
            
            $
            8,003,984**LIABILITIES
                AND STOCKHOLDERS**’**EQUITY**Current
                liabilities:Accounts
                payable and other liabilities
            
            $
            133,271
            
            $
            80,083Short-term
                debt
            
            
            51,000
            
            
            -Current
                portion of senior debt
            
            
            -
            
            
            260,000Current
                portion of subordinated debt
            
            
            234,021
            
            
            188,543Total
                current liabilities
            
            
            418,292
            
            
            528,626Other
                long-term accrued liabilities
            
            
            45,166
            
            
            35,800Notes
                payable - affiliate
            
            
            76,000
            
            
            76,000Senior
                debt
            
            
            2,776,211
            
            
            2,771,957Subordinated
                debt
            
            
            1,354,106
            
            
            1,585,810Total
                liabilities
            
            
            4,669,775
            
            
            4,998,193Deferred
                income
            
            
            27,833
            
            
            30,229Minority
                interest
            
            
            7,209
            
            
            4,403Stockholders’
                equity:Zero
                coupon convertible preferred stock - authorized 50,000 shares, no
                par
                value; 41,263 shares issued and outstanding
            
            
            -
            
            
            -Common
                stock - authorized 60,000 shares, no par value; 9,281 and 9,081 shares
                issued and outstanding at December 31, 2005 and 2004,
                respectively
            
            
            -
            
            
            -Additional
                paid in capital
            
            
            1,963,343
            
            
            1,950,663Retained
                earnings
            
            
            1,719,497
            
            
            1,156,843Accumulated
                other comprehensive loss, net
            
            
            (297,589
            )
            
            (136,347
            )Total
                stockholders’ equity
            
            
            3,385,251
            
            
            2,971,159**Total
                liabilities and stockholders**’**equity**
            
            $
            8,090,068
            
            $
            8,003,984


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




123


**Schedule
      I**


**MidAmerican
      Energy Holdings Company**


**Parent
      Company Only (continued)**


Condensed
      Statements of Operations


For
      the
      three years ended December 31, 2005


(Amounts
      in thousands)





**2005**
            
            **2004**
            
            **2003****Revenues:**Equity
                in undistributed earnings of subsidiary companies and joint
                ventures
            
            $
            547,122
            
            $
            103,968
            
            $
            380,293Dividends
                and distributions from subsidiary companies and joint
                ventures
            
            
            256,674
            
            
            330,678
            
            
            318,665Interest
                and other income
            
            
            19,474
            
            
            14,404
            
            
            13,894Total
                revenues
            
            
            823,270
            
            
            449,050
            
            
            712,852**Costs
                and expenses:**General
                and administration
            
            
            50,931
            
            
            30,438
            
            
            33,864Depreciation
                and amortization
            
            
            5,955
            
            
            5,219
            
            
            5,225Interest,
                net of capitalized interest
            
            
            387,499
            
            
            401,867
            
            
            250,225Total
                costs and expenses
            
            
            444,385
            
            
            437,524
            
            
            289,314**Income
                before income taxes**
            
            
            378,885
            
            
            11,526
            
            
            423,538Income
                tax benefit
            
            
            (185,024
            )
            
            (159,461
            )
            
            (162,552
            )**Income
                before minority interest and preferred dividends of
                subsidiaries**
            
            
            563,909
            
            
            170,987
            
            
            586,090Minority
                interest and preferred dividends of subsidiaries
            
            
            1,255
            
            
            781
            
            
            170,472**Net
                income available to common and preferred
                stockholders**
            
            $
            562,254
            
            $
            170,206
            
            $
            415,618


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


124


**Schedule
      I**


**MidAmerican
      Energy Holdings Company**


**Parent
      Company Only (continued)**


Condensed
      Statements of Cash Flows


For
      the
      three years ended December 31, 2005


(Amounts
      in thousands)





**2005**
            
            **2004**
            
            **2003****Cash
                flows from operating activities**
            
            $
            (154,247
            )
            $
            (196,397
            )
            $
            (266,529
            )**Cash
                flows from investing activities:**Decrease
                in advances to and investments in subsidiaries and joint
                ventures
            
            
            204,200
            
            
            142,954
            
            
            301,959Purchases
                of available-for-sale securities
            
            
            (1,666,721
            )
            
            (1,778,331
            )
            
            (1,371,126
            )Proceeds
                from sale of available-for-sale securities
            
            
            1,750,535
            
            
            1,758,184
            
            
            1,341,477Other,
                net
            
            
            17,710
            
            
            (12,339
            )
            
            (32,407
            )Net
                cash flows from investing activities
            
            
            305,724
            
            
            110,468
            
            
            239,903**Cash
                flows from financing activities:**Purchase
                and retirement of common stock
            
            
            -
            
            
            (20,000
            )
            
            -Repayment
                of subordinated debt
            
            
            (188,544
            )
            
            (100,000
            )
            
            (198,958
            )Proceeds
                from senior debt
            
            
            -
            
            
            249,765
            
            
            449,295Repayments
                of senior debt
            
            
            (260,000
            )
            
            -
            
            
            (215,000
            )Net
                proceeds from revolving credit facility
            
            
            51,000
            
            
            -
            
            
            -Net
                repayment of affiliate notes
            
            
            (22,783
            )
            
            (31,095
            )
            
            (19,200
            )Other
            
            
            5,230
            
            
            (3,328
            )
            
            (3,914
            )Net
                cash flows from financing activities
            
            
            (415,097
            )
            
            95,342
            
            
            12,223**Net
                change in cash and cash equivalents**
            
            
            (263,620
            )
            
            9,413
            
            
            (14,403
            )**Cash
                and cash equivalents at beginning of year**
            
            
            265,639
            
            
            256,226
            
            
            270,629**Cash
                and cash equivalents at end of year**
            
            $
            2,019
            
            $
            265,639
            
            $
            256,226


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


125


**Schedule
      II**


**MIDAMERICAN
      ENERGY HOLDINGS COMPANY**


**CONSOLIDATED
      VALUATION AND QUALIFYING ACCOUNTS**


**FOR
      THE THREE YEARS ENDED DECEMBER 31, 2005**


(Amounts
      in thousands)





**Column
                B**
            
            **Column
                C**
            
            
            
            **Column
                E****Balance
                at**
            
            **Charged**
            
            
            
            **Balance****Column
                A**
            
            **Beginning**
            
            **to**
            
            **Column
                D**
            
            **at
                End****Description**
            
            **of
                Year**
            
            **Income**
            
            **Deductions**
            
            **of
                Year**Reserves
                Deducted From Assets To Which They Apply:Reserve
                for uncollectible accounts receivable:Year
                ended 2005
            
            $
            26,033
            
            $
            13,069
            
            $
            (17,672
            )
            $
            21,430Year
                ended 2004
            
            $
            26,004
            
            $
            15,304
            
            $
            (15,275
            )
            $
            26,033Year
                ended 2003
            
            $
            39,742
            
            $
            13,620
            
            $
            (27,358
            )
            $
            26,004Reserves
                Not Deducted From Assets(1):Year
                ended 2005
            
            $
            10,848
            
            $
            4,019
            
            $
            (2,386
            )
            $
            12,481Year
                ended 2004
            
            $
            17,417
            
            $
            4,048
            
            $
            (10,617
            )
            $
            10,848Year
                ended 2003
            
            $
            10,981
            
            $
            10,527
            
            $
            (4,091
            )
            $
            17,417





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





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





126




**SIGNATURES**





Pursuant
      to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
      1934, the registrant has duly caused this report to be signed on its behalf
      by
      the undersigned thereunto duly authorized on this 3 rd day of
      March 2006.





MIDAMERICAN
                ENERGY HOLDINGS COMPANY/s/
                David L. Sokol*David
                L. SokolChairman
                of the Board and Chief Executive
                Officer








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





**Signature**
            **Title**
            **Date**/s/
                David L. Sokol*
            Chairman
                of the Board,
            March
                3, 2006David
                L. Sokol
            Chief
                Executive Officer, and Director/s/
                Gregory E. Abel*
            President,
                Chief Operating Officer
            March
                3, 2006Gregory
                E. Abel
            and
                Director/s/
                Patrick J. Goodman
            Senior
                Vice President and
            March
                3, 2006Patrick
                J. Goodman
            Chief
                Financial Officer/s/
                Walter Scott, Jr.*
            Director
            March
                3, 2006Walter
                Scott, Jr./s/
                Marc D. Hamburg*
            Director
            March
                3, 2006Marc
                D. Hamburg/s/
                Warren E. Buffett*
            Director
            March
                3, 2006Warren
                E. Buffett*By:  /s/
                Douglas L. Anderson
            Attorney-in-Fact
            March
                3, 2006Douglas
                L. Anderson











127





**EXHIBIT
      INDEX**





**Exhibit
                No.**3.1
            Second
                Amended and Restated Articles of Incorporation of MidAmerican Energy
                Holdings Company effective March 2, 2006.3.2
            Amended
                and Restated Bylaws of MidAmerican Energy Holdings
                Company.4.1
            Indenture,
                dated as of October 4, 2002, by and between MidAmerican Energy
                Holdings Company and The Bank of New York, relating to the 4.625%
                Senior
                Notes due 2007 and the 5.875% Senior Notes due 2012 (incorporated
                by
                reference to Exhibit 4.1 of MidAmerican Energy Holdings Company’s
                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, relating
                to
                the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due
                2012
                (incorporated by reference to Exhibit 4.2 of MidAmerican Energy Holdings
                Company’s 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, relating
                to
                the 3.50% Senior Notes due 2008 (incorporated by reference to Exhibit
                4.3
                of 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, relating
                to
                the 5.00% Senior Notes due 2014 (incorporated by reference to Exhibit
                4.4
                of MidAmerican Energy Holdings Company’s Registration Statement No.
                333-113022 dated February 23, 2004).4.5
            Indenture
                for the 6 1/4% Convertible Junior Subordinated Debentures due 2012,
                dated
                as of February 26, 1997, between MidAmerican Energy Holdings Company,
                as issuer, and the Bank of New York, as Trustee (incorporated by
                reference
                to Exhibit 10.129 to MidAmerican Energy Holdings Company’s Annual Report
                on Form 10-K for the year ended December 31,
                1995).4.6
            Indenture,
                dated as of October 15, 1997, among MidAmerican Energy Holdings
                Company and IBJ Schroder Bank & Trust Company, as Trustee
                (incorporated by reference to Exhibit 4.1 to MidAmerican Energy Holdings
                Company’s Current Report on Form 8-K dated October 23,
                1997).4.7
            Form
                of First Supplemental Indenture for the 7.63% Senior Notes in the
                principal amount of $350,000,000 due 2007, dated as of October 28,
                1997, among MidAmerican Energy Holdings Company and IBJ Schroder
                Bank
                & Trust Company, as Trustee (incorporated by reference to Exhibit 4.2
                to MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated
                October 23, 1997).4.8
            Form
                of Second Supplemental Indenture for the 6.96% Senior Notes in the
                principal amount of $215,000,000 due 2003, 7.23% Senior Notes in
                the
                principal amount of $260,000,000 due 2005, 7.52% Senior Notes in
                the
                principal amount of $450,000,000 due 2008, and 8.48% Senior Notes
                in the
                principal amount of $475,000,000 due 2028, dated as of September 22,
                1998 between MidAmerican Energy Holdings Company and IBJ Schroder
                Bank
                & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1
                to MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated
                September 17, 1998.)4.9
            Form
                of Third Supplemental Indenture for the 7.52% Senior Notes in the
                principal amount of $100,000,000 due 2008, dated as of November 13,
                1998, between MidAmerican Energy Holdings Company and IBJ Schroder
                Bank
                & Trust Company, as Trustee (incorporated by reference to MidAmerican
                Energy Holdings Company’s Current Report on Form 8-K dated
                November 10, 1998).


128





**Exhibit
                No.**4.10
            Indenture,
                dated as of March 14, 2000, among MidAmerican Energy Holdings Company
                and the Bank of New York, as Trustee (incorporated by reference to
                Exhibit
                4.9 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K/A
                for the year ended December 31, 1999).4.11
            Indenture,
                dated as of March 12, 2002, between MidAmerican Energy Holdings
                Company and the Bank of New York, as Trustee (incorporated by reference
                to
                Exhibit 4.11 to MidAmerican Energy Holdings Company’s Annual Report on
                Form 10-K for the year ended December 31, 2001).4.12
            Amended
                and Restated Declaration of Trust of MidAmerican Capital Trust III,
                dated
                as of August 16, 2002 (incorporated by reference to Exhibit 4.14 of
                MidAmerican Energy Holdings Company’s Registration Statement No.
                333-101699 dated December 6, 2002).4.13
            Amended
                and Restated Declaration of Trust of MidAmerican Capital Trust II,
                dated
                as of March 12, 2002 (incorporated by reference to Exhibit 4.15 of
                MidAmerican Energy Holdings Company’s Registration Statement No.
                333-101699 dated December 6, 2002).4.14
            Amended
                and Restated Declaration of Trust of MidAmerican Capital Trust I,
                dated as
                of March 14, 2000 (incorporated by reference to Exhibit 4.16 of
                MidAmerican Energy Holdings Company’s Registration Statement No.
                333-101699 dated December 6, 2002).4.15
            Indenture,
                dated as of August 16, 2002, between MidAmerican Energy Holdings
                Company and the Bank of New York, as Trustee (incorporated by reference
                to
                Exhibit 4.17 of MidAmerican Energy Holdings Company’s Registration
                Statement No. 333-101699 dated December 6, 2002).4.16
            Shareholders
                Agreement, dated as of March 14, 2000 (incorporated by reference to
                Exhibit 4.19 of MidAmerican Energy Holdings Company’s Registration
                Statement No. 333-101699 dated December 6, 2002).4.17
            Amendment
                No. 1 to Shareholders Agreement, dated December 7,
                2005.10.1
            Amended
                and Restated Employment Agreement between MidAmerican Energy Holdings
                Company and David L. Sokol, dated May 10, 1999 (incorporated by
                reference to Exhibit 10.1 to MidAmerican Energy Holdings Company’s Annual
                Report on Form 10-K/A for the year ended December 31,
                1999).10.2
            Amendment
                No. 1 to the Amended and Restated Employment Agreement between MidAmerican
                Energy Holdings Company and David L. Sokol, dated March 14, 2000
                (incorporated by reference to Exhibit 10.2 to MidAmerican Energy
                Holdings
                Company’s Annual Report on Form 10-K/A for the year ended
                December 31, 1999).10.3
            Non-Qualified
                Stock Option Agreements of David L. Sokol, dated March 14, 2000
                (incorporated by reference to Exhibit 10.3 of MidAmerican Energy
                Holdings
                Company’s Registration Statement No. 333-101699 dated December 6,
                2002).10.4
            Amended
                and Restated Employment Agreement between MidAmerican Energy Holdings
                Company and Gregory E. Abel, dated May 10, 1999 (incorporated by
                reference to Exhibit 10.3 to MidAmerican Energy Holdings Company’s Annual
                Report on Form 10-K/A for the year ended December 31,
                1999).10.5
            Non-Qualified
                Stock Option Agreements of Gregory E. Abel, dated March 14, 2000
                (incorporated by reference to Exhibit 10.5 of MidAmerican Energy
                Holdings
                Company’s Registration Statement No. 333-101699 dated December 6,
                2002).





129





**Exhibit
                No.**10.6
            Employment
                Agreement between MidAmerican Energy Holdings Company and Patrick
                J.
                Goodman, dated April 21, 1999 (incorporated by reference to Exhibit
                10.5 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K/A
                for the year ended December 31, 1999).10.7
            125
                MW Power Plant-Upper Mahiao Agreement, dated September 6, 1993,
                between Philippine National Oil Company-Energy Development Corporation
                and
                Ormat, Inc. as amended by the First Amendment to 125 MW Power Plant
                Upper
                Mahiao Agreement, dated as of January 28, 1994, the Letter Agreement
                dated February 10, 1994, the Letter Agreement dated February 18,
                1994 and the Fourth Amendment to 125 MW Power Plant-Upper Mahiao
                Agreement, dated as of March 7, 1994 (incorporated by reference to
                Exhibit 10.95 to MidAmerican Energy Holdings Company’s Annual Report on
                Form 10-K for the year ended December 31, 1993).10.8
            Credit
                Agreement, dated as of April 8, 1994, between CE Cebu Geothermal
                Power Company, Inc., Export-Import Bank of the United States (incorporated
                by reference to Exhibit 10.97 to MidAmerican Energy Holdings Company’s
                Annual Report on Form 10-K for the year ended December 31,
                1993).10.9
            180
                MW Power Plant-Mahanagdong Agreement, dated September 18, 1993,
                between Philippine National Oil Company-Energy Development Corporation
                and
                CE Philippines Ltd. and the Company, as amended by the First Amendment
                to
                Mahanagdong Agreement, dated June 22, 1994, the Letter Agreement
                dated July 12, 1994, the Letter Agreement dated July 29, 1994,
                and the Fourth Amendment to Mahanagdong Agreement, dated March 3,
                1995 (incorporated by reference to Exhibit 10.1 00 to MidAmerican
                Energy
                Holdings Company’s Annual Report on Form 10-K for the year ended
                December 31, 1993).10.10
            Credit
                Agreement, dated as of June 30, 1994, between CE Luzon Geothermal
                Power Company, Inc. and Export-Import Bank of the United States
                (incorporated by reference to Exhibit 10.102 to MidAmerican Energy
                Holdings Company’s Annual Report on Form 10-K for the year ended
                December 31, 1993).10.11
            Finance
                Agreement, dated as of June 30, 1994, between CE Luzon Geothermal
                Power Company, Inc. and Overseas Private Investment Corporation
                (incorporated by reference to Exhibit 10.103 to MidAmerican Energy
                Holdings Company’s Annual Report on Form 10-K for the year ended
                December 31, 1993).10.12
            Overseas
                Private Investment Corporation Contract of Insurance, dated July 29,
                1994, between Overseas Private Investment Corporation and the Company,
                CE
                International Ltd., CE Mahanagdong Ltd. and American Pacific Finance
                Company and Amendment No. 1, dated August 3, 1994 (incorporated by
                reference to Exhibit 10.105 to MidAmerican Energy Holdings Company’s
                Annual Report on Form 10-K for the year ended December 31,
                1993).10.13
            231
                MW Power Plant-Malitbog Agreement, dated September 10, 1993, between
                Philippine National Oil Company-Energy Development Corporation and
                Magma
                Power Company and the First and Second Amendments thereto, dated
                December 8, 1993 and March 10, 1994, respectively (incorporated
                by reference to Exhibit 10.106 to MidAmerican Energy Holdings Company’s
                Annual Report on Form 10-K for the year ended December 31,
                1993).10.14
            Trust
                Indenture, dated as of November 27, 1995, between the CE Casecnan
                Water and Energy Company, Inc. and Chemical Trust Company of California
                (incorporated by reference to Exhibit 4.1 to CE Casecnan Water and
                Energy
                Company, Inc.’s Registration Statement on Form S-4 dated January 25,
                1996).10.15
            Amended
                and Restated Casecnan Project Agreement, dated June 26, 1995, between
                the National Irrigation Administration and CE Casecnan Water and
                Energy
                Company Inc. (incorporated by reference to Exhibit 10.1 to CE Casecnan
                Water and Energy Company, Inc.’s Registration Statement on Form S-4 dated
                January 25, 1996).10.16
            Supplemental
                Agreement between CE Casecnan Water and Energy Company, Inc. and
                the
                Philippines National Irrigation Administration dated as of
                September 29, 2003 (incorporated by reference to Exhibit 98.1 to
                MidAmerican Energy Holdings Company's Current Report on Form 8-K
                dated
                October 15, 2003).





130





**Exhibit
                No.**10.17
            Indenture
                and First Supplemental Indenture, dated March 11, 1999, between
                MidAmerican Funding LLC and IBJ Whitehall Bank & Trust Company and the
                First Supplement thereto relating to the $700 million Senior Notes
                and Bonds (incorporated by reference to MidAmerican Energy Holdings
                Company’s Annual Report on Form 10-K for the year ended December 31,
                1998).10.18
            Second
                Supplemental Indenture, dated as of March 1, 2001, by and between
                MidAmerican Funding, LLC and The Bank of New York, as Trustee
                (incorporated by reference to Exhibit 4.4 to MidAmerican Funding
                LLC’s
                Registration Statement on Form S-3, Registration No.
                333-56624).10.19
            General
                Mortgage Indenture and Deed of Trust, dated as of January 1, 1993,
                between Midwest Power Systems Inc. and Morgan Guaranty Trust Company
                of
                New York, Trustee (incorporated by reference to Exhibit 4(b)-1 to
                the
                Midwest Resources Inc. Annual Report on Form 10-K for the year ended
                December 31, 1992, Commission File No. 1-10654).10.20
            First
                Supplemental Indenture, dated as of January 1, 1993, between Midwest
                Power Systems Inc. and Morgan Guaranty Trust Company of New York,
                Trustee
                (incorporated by reference to Exhibit 4(b)-2 to the Midwest Resources
                Inc.
                Annual Report on Form 10-K for the year ended December 31, 1992,
                Commission File No. 1-10654).10.21
            Second
                Supplemental Indenture, dated as of January 15, 1993, between Midwest
                Power Systems Inc. and Morgan Guaranty Trust Company of New York,
                Trustee
                (incorporated by reference to Exhibit 4(b)-3 to the Midwest Resources
                Inc.
                Annual Report on Form 10-K for the year ended December 31, 1992,
                Commission File No. 1-10654).10.22
            Third
                Supplemental Indenture, dated as of May 1, 1993, between Midwest
                Power Systems Inc. and Morgan Guaranty Trust Company of New York,
                Trustee
                (incorporated by reference to Exhibit 4.4 to the Midwest Resources
                Inc.
                Annual Report on Form 10-K for the year ended December 31, 1993,
                Commission File No. 1-10654).10.23
            Fourth
                Supplemental Indenture, dated as of October 1, 1994, between Midwest
                Power Systems Inc. and Harris Trust and Savings Bank, Trustee
                (incorporated by reference to Exhibit 4.5 to the Midwest Resources
                Inc.
                Annual Report on Form 10-K for the year ended December 31, 1994,
                Commission File No. 1-10654).10.24
            Fifth
                Supplemental Indenture, dated as of November 1, 1994, between Midwest
                Power Systems Inc. and Harris Trust and Savings Bank, Trustee
                (incorporated by reference to Exhibit 4.6 to the Midwest Resources
                Inc.
                Annual Report on Form 10-K for the year ended December 31, 1994,
                Commission File No. 1-10654).10.25
            Sixth
                Supplemental Indenture, dated as of July 1, 1995, between Midwest
                Power Systems Inc. and Harris Trust and Savings Bank, Trustee
                (incorporated by reference to Exhibit 4.15 to the MidAmerican Energy
                Company Annual Report on Form 10-K for the year ended December 31,
                1995, Commission File No. 1-11505).10.26
            Indenture
                dated as of December 1, 1996, between MidAmerican Energy Company and
                the First National Bank of Chicago, as Trustee (incorporated by reference
                to Exhibit 4(1) to MidAmerican Energy Company’s Registration Statement on
                Form S-3, Registration No. 333-15387).10.27
            First
                Supplemental Indenture, dated as of February 8, 2002, by and between
                MidAmerican Energy Company and The Bank of New York, as Trustee
                (incorporated by reference to Exhibit 4.3 to MidAmerican Energy Company’s
                Annual Report on Form 10-K for the year ended December 31, 2004,
                Commission File No. 333-15387).





131





**Exhibit
                No.**10.28
            Second
                Supplemental Indenture, dated as of January 14, 2003, by and between
                MidAmerican Energy Company and The Bank of New York, as Trustee
                (incorporated by reference to Exhibit 4.2 to MidAmerican Energy Company’s
                Annual Report on Form 10-K for the year ended December 31, 2004,
                Commission File No. 333-15387).10.29
            Third
                Supplemental Indenture, dated as of October 1, 2004, by and between
                MidAmerican Energy Company and The Bank of New York, as Trustee
                (incorporated by reference to Exhibit 4.1 to MidAmerican Energy Company’s
                Annual Report on Form 10-K for the year ended December 31, 2004,
                Commission File No. 333-15387).10.30
            Fourth
                Supplemental Indenture, dated November 1, 2005, by and between
                MidAmerican Energy Company and the Bank of New York Trust Company,
                NA, as
                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).10.31
            Sixth
                Amendment to 180 MW Power Plant-Mahanagdong Agreement, dated
                August 31, 2003, between Philippine National Oil Company-Energy
                Development Corporation and CE Luzon Geothermal Power Company, Inc.
                (incorporated by reference to Exhibit 10.44 to MidAmerican Energy
                Holdings
                Company’s Annual Report on Form 10-K for the year ended December 31,
                2003).10.32
            Third
                Amendment to 231 MW Power Plant-Malitbog Agreement, dated August 31,
                2003, between Philippine National Oil Company-Energy Development
                Corporation and Visayas Geothermal Power Company, Inc. (incorporated
                by
                reference to Exhibit 10.45 to MidAmerican Energy Holdings Company’s Annual
                Report on Form 10-K for the year ended December 31,
                2003).10.33
            Seventh
                Amendment to 125 MW Power Plant-Upper Mahiao Agreement, dated
                August 31, 2003, between Philippine National Oil Company-Energy
                Development Corporation and CE Cebu Geothermal Power Company, Inc.
                (incorporated by reference to Exhibit 10.46 to MidAmerican Energy
                Holdings
                Company’s Annual Report on Form 10-K for the year ended December 31,
                2003).10.34
            Fiscal
                Agency Agreement, dated as of October 15, 2002, between Northern
                Natural Gas Company and J.P. Morgan Trust Company, National Association,
                Fiscal Agent, relating to the $300,000,000 in principal amount of
                the
                5.375% Senior Notes due 2012 (incorporated by reference to Exhibit
                10.47
                to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for
                the year ended December 31, 2003).10.35
            Trust
                Indenture, dated as of August 13, 2001, among Kern River Funding
                Corporation, Kern River Gas Transmission Company and the JP Morgan
                Chase
                Bank, as Trustee, relating to the $510,000,000 in principal amount
                of the
                6.676% Senior Notes due 2016 (incorporated by reference to Exhibit
                10.48
                to MidAmerican Energy Holdings Company's Annual Report on Form 10-K
                for
                the year ended December 31, 2003).10.36
            Third
                Supplemental Indenture, dated as of May 1, 2003, among Kern River
                Funding Corporation, Kern River Gas Transmission Company and JPMorgan
                Chase Bank, as Trustee, relating to the $836,000,000 in principal
                amount
                of the 4.893% Senior Notes due 2018 (incorporated by reference to
                Exhibit
                10.49 to MidAmerican Energy Holdings Company's Annual Report on Form
                10-K
                for the year ended December 31, 2003).10.37
            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 of MidAmerican Energy Holdings Company’s
                Registration Statement No. 333-101699 dated December 6,
                2002).10.38
            MidAmerican
                Energy Holdings Company Executive Voluntary Deferred Compensation
                Plan
                (incorporated by reference to Exhibit 10.51 of MidAmerican Energy
                Holdings
                Company’s Registration Statement No. 333-101699 dated December 6,
                2002).





132





**Exhibit
                No.**10.39
            MidAmerican
                Energy Company First Amended and Restated Supplemental Retirement
                Plan for
                Designated Officers dated as of May 10, 1999 (incorporated by
                reference to Exhibit 10.52 of MidAmerican Energy Holdings Company’s
                Registration Statement No. 333-101699 dated December 6,
                2002).10.40
            MidAmerican
                Energy Company Restated Executive Deferred Compensation Plan (incorporated
                by reference to Exhibit 10.6 to MidAmerican Energy Holdings Company’s
                Annual Report on Form 10-K/A for the year ended December 31,
                1999).10.41
            MidAmerican
                Energy Holdings Company Restated Deferred Compensation Plan-Board
                of
                Directors (incorporated by reference to Exhibit 10 to MidAmerican
                Energy
                Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended
                June 30, 1999).10.42
            MidAmerican
                Energy Company Combined Midwest Resources/Iowa Resources Restated
                Deferred
                Compensation Plan-Board of Directors (incorporated by reference to
                Exhibit
                10.63 to MidAmerican Energy Holdings Company’s Annual Report on Form
                10-K/A for the year ended December 31, 1999).10.43
            MidAmerican
                Energy Holdings Company Executive Incremental Profit Sharing Plan
                (incorporated by reference to Exhibit 10.2 of MidAmerican Energy
                Holdings
                Company’s Quarterly Report on Form 10-Q for the quarter ended
                March 31, 2003.)10.44
            Trust
                Deed between CE Electric UK Funding Company, AMBAC Insurance UK Limited
                and The Law Debenture Trust Corporation, p.l.c. dated December 15,
                1997 (incorporated by reference to Exhibit 99.1 to MidAmerican Energy
                Holdings Company’s Current Report on Form 8-K dated March 30,
                2004).10.45
            Insurance
                and Indemnity Agreement between CE Electric UK Funding Company and
                AMBAC
                Insurance UK Limited dated December 15, 1997 (incorporated by reference
                to
                Exhibit 99.2 to MidAmerican Energy Holdings Company’s Current Report on
                Form 8-K dated March 30, 2004).10.46
            Supplemental
                Agreement to Insurance and Indemnity Agreement between CE Electric
                UK
                Funding Company and AMBAC Insurance UK Limited dated September 19,
                2001 (incorporated by reference to Exhibit 99.3 to MidAmerican Energy
                Holdings Company’s Current Report on Form 8-K dated March 30,
                2004).10.47
            Fiscal
                Agency Agreement, dated as of September 4, 1998, 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
                MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for
                the quarter ended March 31, 2004).10.48
            Fiscal
                Agency Agreement, dated as of May 24, 1999, 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 MidAmerican
                Energy
                Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended
                March 31, 2004).10.49
            Trust
                Indenture, dated as of September 10, 1999, 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 MidAmerican Energy Holdings Company’s Quarterly Report on
                Form 10-Q for the quarter ended March 31, 2004).10.50
            Indenture,
                dated as of December 15, 1997, among CE Electric UK Funding Company,
                The
                Bank of New York, as Trustee, and Banque Internationale A Luxembourg
                S.A.,
                as Paying Agent (incorporated by reference to Exhibit 10.72 to MidAmerican
                Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter
                ended March 31, 2004).





133





**Exhibit
                No.**10.51
            First
                Supplemental Indenture, dated as of December 15, 1997, among CE Electric
                UK Funding Company, The Bank of New York, Trustee, and Banque
                Internationale A Luxembourg S.A., Paying Agent, relating to the
                $125,000,000 in principal amount of the 6.853% Senior Notes due 2004
                and
                to the $237,000,000 in principal amount of the 6.995% Senior Notes
                due
                2007 (incorporated by reference to Exhibit 10.73 to MidAmerican Energy
                Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended
                March 31, 2004).10.52
            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 MidAmerican Energy Holdings Company’s Quarterly Report on Form
                10-Q for the quarter ended March 31, 2004).10.53
            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 MidAmerican Energy Holdings Company’s Quarterly Report on
                Form 10-Q for the quarter ended March 31, 2004).10.54
            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 MidAmerican Energy Holdings Company’s Quarterly Report on
                Form 10-Q for the quarter ended March 31, 2004).10.55
            Indenture,
                dated as of February 1, 1998, and Second Supplemental Indenture,
                dated as of February 25, 1998, each among Yorkshire Power Finance
                Limited, Yorkshire Power Group Limited, The Bank of New York, Trustee,
                and
                Banque Internationale du Luxembourg S.A., Paying Agent, relating
                to the
                $300,000,000 in principal amount of the 6.496% Notes due 2008
                (incorporated by reference to Exhibit 10.77 to MidAmerican Energy
                Holdings
                Company’s Quarterly Report on Form 10-Q for the quarter ended
                March 31, 2004).10.56
            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 MidAmerican Energy
                Holdings
                Company’s Quarterly Report on Form 10-Q for the quarter ended
                March 31, 2004).10.57
            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 8.625%
                Guaranteed Bonds due 2005 and to the £100,000,000 in principal amount of
                the 8.875% Guaranteed Bonds due 2020 (incorporated by reference to
                Exhibit
                10.81 to MidAmerican Energy Holdings Company’s Quarterly Report on Form
                10-Q for the quarter ended March 31, 2004).10.58
            Trust
                Deed, dated as of January 17, 1995, 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 MidAmerican Energy
                Holdings
                Company’s Quarterly Report on Form 10-Q for the quarter ended
                March 31, 2004).10.59
            Master
                Trust Deed, dated as of October 16, 1995, among 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
                8.625% Guaranteed Bonds due 2005 and to the £100,000,000 in principal
                amount of the 8.875% Guaranteed Bonds due 2020 (incorporated by reference
                to Exhibit 10.70 to MidAmerican Energy Holdings Company’s Annual Report on
                Form 10-K for the year ended December 31, 2004).





134





**Exhibit
                No.**10.60
            MidAmerican
                Energy Holdings Company Amended and Restated Long-Term Incentive
                Partnership Plan dated as of January 1, 2004 (incorporated by
                reference to Exhibit 10.71 to MidAmerican Energy Holdings Company’s Annual
                Report on Form 10-K for the year ended December 31,
                2004).10.61
            Fiscal
                Agency Agreement, dated April 14, 2005, by and between Northern
                Natural Gas Company, as issuer, and J.P. Morgan Trust Company, National
                Association, as 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 MidAmerican Energy Holdings Company’s Current Report on
                Form 8-K dated April 18, 2005).10.62
            £100,000,000
                Facility Agreement dated 4 April 2005 made between 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 MidAmerican Energy
                Holdings
                Company’s Current Report on Form 8-K dated April 20,
                2005).10.63
            Trust
                Deed made on 5 May 2005 between 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
                MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for
                the quarter ended March 31, 2005).10.64
            Reimbursement
                and Indemnity Agreement dated 5 May 2005 between Northern Electric
                Finance plc, Northern Electric Distribution Limited and Ambac Assurance
                UK
                Limited (incorporated by reference to Exhibit 99.2 to MidAmerican
                Energy
                Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended
                March 31, 2005).10.65
            Trust
                Deed made on 5 May 2005 between Yorkshire Electricity Distribution
                plc, Ambac Assurance UK Limited and HSBC Trustee (C.I.) Limited
                (incorporated by reference to Exhibit 99.3 to MidAmerican Energy
                Holdings
                Company’s Quarterly Report on Form 10-Q for the quarter ended
                March 31, 2005).10.66
            Reimbursement
                and Indemnity Agreement dated 5 May 2005 between Yorkshire
                Electricity Distribution plc and Ambac Assurance UK Limited (incorporated
                by reference to Exhibit 99.4 to MidAmerican Energy Holdings Company’s
                Quarterly Report on Form 10-Q for the quarter ended March 31,
                2005).10.67
            Supplemental
                Trust Deed made on 5 May 2005 between CE Electric UK Funding Company,
                Ambac Assurance UK Limited and The Law Debenture Trust Corporation
                plc
                (incorporated by reference to Exhibit 99.5 to MidAmerican Energy
                Holdings
                Company’s Quarterly Report on Form 10-Q for the quarter ended
                March 31, 2005).10.68
            Second
                Supplemental Agreement to Insurance and Indemnity Agreement made
                on
                5 May 2005 between CE Electric UK Funding Company and Ambac Assurance
                UK Limited (incorporated by reference to Exhibit 99.6 to MidAmerican
                Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter
                ended March 31, 2005).10.69
            Stock
                Purchase Agreement, dated as of May 23, 2005, by and among Scottish
                Power
                plc, PacifiCorp Holdings, Inc. and MidAmerican Energy Holdings Company
                (incorporated by reference to exhibit 99.1 to MidAmerican Energy
                Holdings
                Company’s Current Report on Form 8-K dated May 24,
                2005).10.70
            Credit
                Agreement, dated August 26, 2005, 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.
                andBNP
                Paribasas
                Co-Documentation Agents (incorporated by reference to exhibit 99.1
                to
                MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated
                September 1, 2005).





135





**Exhibit
                No.**10.71
            Credit
                Agreement among MidAmerican Energy Company, the Lending Institutions
                Party
                Hereto, as Banks, Union Bank of California, N.A., as Syndication
                Agent,
                and JPMorgan Chase Bank, N.A. as Administrative Agent, dated as of
                November 18, 2004 Union Bank of California, N.A. and J.P.Morgan
                Securities, Inc. Co-Lead Arrangers and Co-Book Runners (incorporated
                by
                reference to Exhibit 10.1 to the MidAmerican Energy Company Annual
                Report
                on Form 10-K for the year ended December 31,
                2005).10.72
            Equity
                Commitment Agreement, dated as of March 1, 2006, between Berkshire
                Hathaway, Inc. and MidAmerican Energy Holdings Company.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 MidAmerican Energy Holdings Company’s Annual Report on
                Form 10-K for the year ended December 31, 2003).21.1
            Subsidiaries
                of the Registrant.24.1
            Power
                of Attorney.31.1
            Chief
                Executive Officer’s Certificate Pursuant to Section 302 of the
                Sarbanes-Oxley Act of 2002.31.2
            Chief
                Financial Officer’s Certificate Pursuant to Section 302 of the
                Sarbanes-Oxley Act of 2002.32.1
            Chief
                Executive Officer’s Certificate Pursuant to Section 906 of the
                Sarbanes-Oxley Act of 2002.32.2
            Chief
                Financial Officer’s Certificate Pursuant to Section 906 of the
                Sarbanes-Oxley Act of 2002.




136