**UNITED
STATES**


**SECURITIES
AND EXCHANGE COMMISSION**


Washington,
D.C. 20549





**FORM
10-K**








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





For the
fiscal year ended December 31, 2004





Commission
File No. 0-25551





**MIDAMERICAN
ENERGY HOLDINGS COMPANY**


(Exact
name of registrant as specified in its charter)





Iowa
    
    94-2213782(State
      or other jurisdiction of
    
    (I.R.S.
      EmployerIncorporation
      or organization)
    
    Identification
      No.)666
      Grand Avenue, Des Moines, IA
    
    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 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  X  No  __





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
each of the registrants’ 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.  X





Indicate
by check mark whether the registrant is an accelerated filer (as defined by Rule
12b-2 of the Act).


Yes  __  No  X





All of
the shares of common equity of MidAmerican Energy Holdings Company are privately
held by a limited group of investors. As of January 31, 2005, 9,081,087
shares of common stock were outstanding.
















**TABLE
OF CONTENTS**





****


**PART I**Item 1.
    Business
    4Item 2.
    Properties
    31Item 3.
    Legal Proceedings
    32Item 4.
    Submission of Matters to a Vote of Security
      Holders
    34**PART
      II**Item 5.
    Market for Registrant’s Common Equity and Related
      Stockholder Matters
    35Item 6.
    Selected Financial Data
    35Item 7.
    Management’s Discussion and Analysis of Financial
      Condition and Results of Operations
    36Item 7A.
    Quantitative and Qualitative Disclosures About Market
      Risk
    55Item 8.
    Financial Statements and Supplementary
      Data
    57Item 9.
    Changes in and Disagreements with Accountants on Accounting
      and Financial Disclosure
    101Item 9A.
    Controls and Procedures
    101Item 9B.
    Other Information
    101**PART
      III**Item 10.
    Directors and Executive Officers of the
      Registrant
    102Item 11.
    Executive Compensation
    104Item 12.
    Security Ownership of Certain Beneficial Owners and
      Management and Related Stockholder Matters
    108Item 13.
    Certain Relationships and Related
      Transactions
    109Item 14.
    Principal Accountant Fees and Services
    110**PART
      IV**Item 15.
    Exhibits and Financial Statement
    Schedules
    111Signatures
    
    116Exhibit Index
    118





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 represent plans, expectations and beliefs and are
subject to risks, uncertainties and other factors. Many of these factors are
outside the Company’s control and could cause actual results to differ
materially from such forward-looking statements. These factors include, among
others:


·
    general
      economic and business conditions in the jurisdictions in which its
      facilities are located;
·
    the
      financial condition and creditworthiness of our significant customers and
      suppliers;
·
    governmental,
      statutory, regulatory or administrative initiatives or ratemaking actions
      affecting the Company or the electric or gas utility, pipeline or power
      generation industries;
·
    weather
      effects on sales and revenue;
·
    general
      industry trends;
·
    increased
      competition in the power generation, electric and gas utility or pipeline
      industries;
·
    fuel
      and power costs and availability;
·
    continued
      availability of accessible gas reserves;
·
    changes
      in business strategy, development plans or customer or vendor
      relationships;
·
    availability,
      term 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 Securities and Exchange Commission (“SEC”) and similar entities with
      regulatory oversight;
·
    other
      risks or unforeseen events, including wars, the effects of terrorism,
      embargos 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.

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 on seven distinct platforms: MidAmerican
Energy Company (“MidAmerican Energy”), Kern River Gas Transmission Company
(“Kern River”), Northern Natural Gas Company (“Northern Natural Gas”), CE
Electric UK Funding (“CE Electric UK”) (which includes Northern Electric
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 23 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 the United Kingdom, a diversified portfolio of
domestic and international independent power projects and the second largest
residential real estate brokerage firm in the United States.





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 680,000
natural gas customers. Its natural gas pipeline subsidiaries operate interstate
natural gas transmission systems with approximately 18,300 miles of pipeline in
operation and peak delivery capacity of 6.4 billion cubic feet of natural gas
per day. The Company has interests in 6,777 net owned megawatts of power
generation facilities in operation and under construction, including 5,203 net
owned megawatts in facilities that are part of the regulated return 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.





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





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.





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 the United Kingdom and
references to “pesos” are to the currency of the Philippines. References to kW
means kilowatts, MW means megawatts, GW means gigawatts, kWh means kilowatt
hours, MWh means megawatt hours, GWh means 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.




4








**MidAmerican
Energy**





*Business*





MidAmerican
Energy, an indirect wholly-owned subsidiary of MEHC, owns a public utility
headquartered in Iowa with $5.1 billion of assets as of December 31, 2004,
and operating revenues for 2004 totaling $2.7 billion. MidAmerican Energy 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, 2004, MidAmerican Energy had approximately 698,000 regulated
retail electric customers and 680,000 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.





MidAmerican
Energy’s regulated electric and gas operations are conducted under franchises,
certificates, permits and licenses obtained from state and local authorities.
The franchises, 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.





For the
year ended December 31, 2004, MidAmerican Energy derived 53% of its gross
operating revenues from its regulated electric business, 37% from its regulated
gas business and 10% from its nonregulated business activities. For 2003 and
2002, the corresponding percentages were 54% electric, 36% gas and 10%
nonregulated; and 61% electric, 31% gas and 8% nonregulated,
respectively.





*Electric
Operations*





For the
year ended December  31, 2004,
regulated electric sales by MidAmerican Energy by customer class were as
follows: 20% were to residential customers, 14% were to small general service
customers, 27% were to large general service customers, 5% were to other
customers, and 34% were wholesale sales. For the year ended December 31,
2004, regulated electric sales by MidAmerican Energy by jurisdiction were as
follows: 89% to Iowa, 10% to Illinois and 1% to South Dakota.





The
annual hourly peak demand on MidAmerican Energy’s electric system usually occurs
as a result of air conditioning use during the cooling season. In August 2003,
MidAmerican Energy reached a record hourly peak demand of 3,935 MW. For 2004,
MidAmerican Energy recorded an hourly peak demand of 3,894 MW on July
20.




5








The
following table sets out certain information concerning MidAmerican Energy’s
power generation facilities based upon summer 2004 accreditation and expected
accredited generating capacity of projects recently completed or under
construction:





**Facility
      Net****Capacity**
    
    **Net
      MW****Operating
      Project****(1)**
    
    
    **(MW)****(2)**
    
    
    **Owned****(2)**
    
    
    **Fuel**
    
    
    **Location**
    
    
    **Operation**Steam
      Electric Generating Facilities:Council
      Bluffs Energy Center Units 1 & 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 & 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
    
    
    715
    
    
    372
    
    
    Coal
    
    
    Iowa
    
    
    1981Riverside
      Generation Station
    
    
    135
    
    
    135
    
    
    Coal
    
    
    Iowa
    
    
    1925-61Total
      steam electric generating facilities
    
    
    3,967
    
    
    2,869Other
      Facilities:Combustion
      Turbines(3)
    
    
    1,116
    
    
    1,116
    
    
    Gas/Oil
    
    
    Iowa
    
    
    1969-2003Quad
      Cities Generating Station
    
    
    1,748
    
    
    437
    
    
    Nuclear
    
    
    Illinois
    
    
    1974Portable
      Power Modules
    
    
    56
    
    
    56
    
    
    Oil
    
    
    Iowa
    
    
    2000Moline
      Water Power
    
    
    3
    
    
    3
    
    
    Hydro
    
    
    Illinois
    
    
    1970Total
      other facilities
    
    
    2,923
    
    
    1,612Total
      accredited generating capacity
    
    
    6,890
    
    
    4,481Projects
      Recently Completed or Under Construction:Greater
      Des Moines Energy Center(3)
    
    
    190
    
    
    190
    
    
    Gas
    
    
    Iowa
    
    
    2004Council
      Bluffs Energy Center Unit 4
    
    
    790
    
    
    479
    
    
    Coal
    
    
    Iowa
    
    
    2007Northern
      Iowa Wind Power
    
    
    53
    
    
    53
    
    
    Wind
    
    
    Iowa
    
    
    2005Total
      projects recently completed or under construction
    
    
    1,033
    
    
    7227,923
    
    
    5,203





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





(2)
    Represents
      accredited net generating capability from the summer of 2004 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 2004 as approved by the
      Mid-Continent Area Power Pool (“MAPP”).





(3)
    The
      Greater Des Moines Energy Center project was completed in two phases.
      Commercial operation in the simple cycle mode began in May 2003, resulting
      in 327 MW (included in “Other Facilities — Combustion Turbines” above) of
      accredited capacity throughout 2004. Commercial operation of the combined
      cycle mode began in December 2004 and additional accredited capacity is
      expected to be 190 MW.





MidAmerican
Energy’s total accredited net generating capability in the summer of 2004 was
4,897 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 4,481 MW and the net amount
of capacity purchases and sales of 416 MW. The actual amount of generation
capacity available at any time may be less than the accredited capability due to
regulatory restrictions, transmission constraints, fuel restrictions and
generating units being temporarily out of service for inspection, maintenance,
refueling, modifications or other reasons.




6








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 recently completed its
combined cycle combustion turbine project and is currently constructing the 790
MW (expected accreditation) super-critical-temperature, coal-fired Council
Bluffs Energy Center Unit No. 4 (“CBEC Unit 4”) and a 310 MW (nameplate rating)
wind power project in Iowa. The projects will provide service to regulated
retail electricity customers. MidAmerican Energy has obtained regulatory
approval to include the Iowa portion of the actual costs of the generation
projects in its Iowa rate base as long as actual costs do not exceed the agreed
caps that MidAmerican Energy has deemed to be reasonable. If the caps are
exceeded, MidAmerican Energy has the right to demonstrate the prudence of the
expenditures above the caps, subject to regulatory review. Wholesale sales may
also be made from the projects to the extent the power is not immediately needed
for regulated retail service. MidAmerican Energy expects to invest approximately
$1.1 billion in the CBEC Unit 4 and wind generation projects, of which
$350.4 million has been invested through December 31,
2004.





MidAmerican
Energy recently completed work on its Greater Des Moines Energy Center, a
natural gas-fired, combined cycle plant located near Pleasant Hill, Iowa.
Construction of the plant was completed in two phases. Commercial operation of
the simple cycle mode began on May 5, 2003, and continued through most of
2004, providing 327 MW of accredited capacity in the summer of 2004. Commercial
operation of the combined cycle mode began on December 16, 2004. The
additional accredited capacity from the completion of the second phase is
expected to be 190 MW. MidAmerican Energy expects the total cost of the Greater
Des Moines Energy Center to be under the $357.0 million cost cap
established by the Iowa Utilities Board (“IUB”).





MidAmerican
Energy is currently constructing the CBEC Unit 4, a 790 MW (based on expected
accreditation) super-critical-temperature, low-sulfur coal-fired plant.
MidAmerican Energy will operate the plant and hold an undivided ownership
interest as a tenant in common with the other owners of the plant. MidAmerican
Energy’s ownership interest is 60.67%, equating to 479 MW of output. MidAmerican
Energy expects its share of the estimated cost of the project, including
transmission facilities, to be approximately $737.0 million, excluding
allowance for funds used during construction. Municipal, cooperative and public
power utilities will own the remainder, which is a typical ownership arrangement
for large base-load plants in Iowa. On February 12, 2003, MidAmerican
Energy executed a contract with Mitsui & Co. Energy Development, Inc.
(“Mitsui”) for the engineering, procurement and construction of the plant. On
September 9, 2003, MidAmerican Energy began construction of the plant,
which it expects to be completed in the summer of 2007. On December 29,
2004, MidAmerican Energy received an order from the IUB approving construction
of the associated transmission facilities and is proceeding with
construction.





The
second electric generating project currently under construction consists of wind
power facilities located at two sites in north central Iowa totaling 310 MW
based on the nameplate rating. Generally speaking, accredited capacity ratings
for wind power facilities are considerably less than the nameplate ratings due
to the varying nature of wind. The current projected accredited capacity for
these wind power facilities is approximately 53 MW. MidAmerican Energy will own
and operate these facilities, which are expected to cost approximately
$323.0 million, including transmission facilities and excluding the
allowance for funds used during construction. As of December 31, 2004, wind
turbines totaling 160.5 MW at one of the sites were completed and in service.
Completion of the remaining turbines is expected by the middle of 2005. On
January 31, 2005, the IUB approved ratemaking principles related to
expanding the wind power project. An additional 50 MW of capacity, based on the
nameplate rating, is expected to be constructed at the sites in 2005 at an
estimated cost of $63.0 million.





MidAmerican
Energy is interconnected with Iowa utilities and utilities in neighboring states
and is party to an electric generation and transmission pooling agreement
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 facilitates operation of the
transmission system, is responsible for the safety and reliability of the bulk
electric system, and has responsibility for administration of the MAPP’s
Open-Access Transmission Tariff.





Each MAPP
participant is required to maintain for emergency purposes a net generating
capability reserve of at least 15% above its system peak demand. MidAmerican
Energy’s reserve margin at peak demand for 2004 was approximately 26%.
MidAmerican Energy believes it has adequate electric capacity reserve through
2010, 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 appropriate reserve, significant
penalties could be contractually imposed by the MAPP.




7







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.





*Gas
Operations*





MidAmerican
Energy is engaged in the procurement, transportation, storage and distribution
of natural gas for customers in the midwest region of the United States.
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 2004, 45% of
total gas delivered through MidAmerican Energy's system for end-use customers
was under gas transportation services.





For the
year ended December 31, 2004, regulated gas sales, excluding transportation
throughput, by MidAmerican Energy by customer class were as follows: 40% were to
residential customers, 20% were to small general service customers, 2% were to
large general service customers and 38% were wholesale sales. For the year ended
December 31, 2004, regulated gas sales, excluding transportation
throughput, by MidAmerican Energy by jurisdiction were as follows: 78% to Iowa,
11% to South Dakota, 10% to Illinois and 1% to Nebraska.





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





MidAmerican
Energy purchases gas supplies from producers and third party marketers. To
ensure system reliability, a geographically diverse supply portfolio with
varying terms and contract conditions is utilized for the 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 clause discussed below.





MidAmerican
Energy has rights to firm pipeline capacity to transport 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 clause.





MidAmerican
Energy is allowed to recover its cost of gas from all of its regulated gas
customers through purchased gas adjustment clauses. Accordingly, MidAmerican
Energy’s regulated gas customers retain the risk associated with the market
price of gas. MidAmerican Energy uses several strategies to reduce the market
price risk for its 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
typically replaced during the summer months when the demand for gas has
historically been 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 gas purchases
during the volatile winter heating season.




8







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 gas
procurement costs to an index-based reference price. If MidAmerican Energy’s
cost of 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, 2005. 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 January 31,
2005, MidAmerican Energy’s 2004/2005 winter heating season peak-day delivery of
997,058 Dth was reached on January 14, 2005. This peak-day delivery
included 76% traditional sales service and 24% transportation
service.





**Kern
River**





*Business*





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. In 2003, a 717 mile expansion project (“2003 Expansion Project”),
which was placed in service on May 1, 2003, 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.





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 pipeline, 628 miles of 36-inch 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, 2004) and Mojave Pipeline Company (“Mojave”), a
wholly owned subsidiary of El Paso Corporation (“El Paso”) (approximately 23.2%
as of December 31, 2004), as tenants-in-common. Kern River’s ownership
percentage in the common facilities will increase or decrease pursuant to
subsequently completed expansions 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.





*Transportation
Service Agreements*





As of
December 31, 2004, Kern River had under contract 1,661,575 Dth per day of
capacity under long-term firm gas transportation service agreements under which
the pipeline receives natural gas on behalf of shippers at designated receipt
points, transports the gas on a firm basis up to each shipper’s maximum daily
quantity and delivers thermally equivalent quantities of gas at designated
delivery points. Each shipper pays Kern River the aggregate amount specified in
its long-term firm 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 gas transported.





With
respect to Kern River’s mainline facilities in existence prior to the 2003
Expansion Project, at December 31, 2004, Kern River had 27 long-term firm gas
transportation service agreements with 16 shippers, for a total of 848,949 Dth
per day of capacity. All but one of these long-term firm gas transportation
service agreements expires on or before April 30, 2017. 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 gas distribution utility which provides services in
Nevada and California.





With
respect to Kern River’s 2003 Expansion Project, at December 31, 2004, Kern River
had 19 long-term firm 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 gas transportation service agreements
expiring on April 30, 2018. The remaining 17% of capacity is contracted for
10 years, with five long-term firm 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.





9


****


**Northern
Natural Gas**





*Business*





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 16,500 miles of natural gas pipelines with a
design capacity of 4.4 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 small 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
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.





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 70% of Northern
Natural Gas’ firm transportation contracts extend beyond 2007.





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 2004, approximately 85% of Northern Natural
Gas’ revenue was from capacity charges under firm transportation and storage
contracts and approximately 80% of that revenue was from LDCs. In 2004,
approximately 71% of Northern Natural Gas’ 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 2004, approximately 19% of Northern Natural Gas’
revenue was generated from Field Area customer transportation
contracts.




10





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 at Garner, Iowa and Wrenshall, Minnesota.
The three underground natural gas storage facilities and Northern Natural Gas’
two LNG storage peaking units have a total working 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 loadswing requirements. In 2004, approximately 10% of
Northern Natural Gas’ revenue was generated from storage services.





Northern
Natural Gas’ system is characterized by significant seasonal swings in demand,
which provide opportunities to deliver high value-added services. 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, Pony Express Pipeline 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, other parts of the Midwest and
Texas.





*Kern
River and Northern Natural Gas Competition*





Each of
Kern River and Northern Natural Gas has several customers who account for
greater than 10% of its revenue. The loss of any one or more of these, if not
replaced, could have a material adverse effect on Kern River’s and Northern
Natural Gas’ respective businesses.





Pipelines
compete on the basis of cost (including both transportation costs and the
relative costs of the natural gas they transport), flexibility, reliability of
service and overall customer service. Industrial end-users often have the
ability to choose from alternative fuel sources 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 serving the
southern California, Las Vegas, Nevada and Salt Lake City, Utah market areas, in
order to market any unutilized or unsubscribed capacity. Kern River provides its
customers with supply diversity through pipeline interconnections with Northwest
Pipeline, Colorado Interstate, Overland Trail Pipeline, and Questar Pipeline.
These interconnections, in addition to the direct interconnections to natural
gas processing facilities, allow Kern River to access natural gas reserves in
Colorado, northwestern New Mexico, Wyoming, Utah and the Western Canadian
Sedimentary Basin.





Kern
River is the only interstate pipeline that presently delivers natural gas
directly from a gas supply basin into the intrastate California market, which
enables its 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 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
expanded at comparatively lower costs 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 under
expansion rates and settlement rates also provide customers with greater rate
certainty. Kern River’s market position depends to a significant degree,
however, on the availability and favorable price of gas produced in the Rocky
Mountain area, an area that in recent years has attracted considerable expansion
of pipeline capacity serving markets other than California and Nevada. In
addition, Kern River’s 2003 Expansion Project 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.





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 relatively high load factor throughput, which lowers the cost
per unit of transportation. Although Northern Natural Gas has experienced
pipeline system bypass 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.




11





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 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 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
expansion. 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 the
construction of new power and ethanol plants. Over the last five years, Northern
Natural Gas has contracted approximately 281 mmcf per day of firm volume on its
system from such new facilities, of which approximately 262 mmcf per day is
currently in service and approximately 19 mmcf per day is scheduled to begin
service in 2005.





**Pipeline
Development Project**





MEHC and
a subsidiary, Alaska Gas Transmission Company, LLC (“Alaska Gas”), are 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 which would be subject to FERC regulation
and would extend from the North Slope area near Prudhoe Bay, Alaska south to the
Alaska-Yukon border near Beaver Creek, Alaska. The State of Alaska is expected
to select a preferred party for the project by the end of the second quarter of
2005. If either MEHC or Alaska Gas are selected, further approvals, including
from FERC, would be required and significant development and construction risk
would remain with respect to the pipeline project.





**CE
Electric UK**





*Business*





CE
Electric UK, an indirect wholly-owned subsidiary of MEHC, owns, primarily, two
companies that distribute electricity in the United Kingdom, Northern Electric
and Yorkshire Electricity. Northern Electric and Yorkshire Electricity,
collectively, are the third largest electricity distribution business in the
United Kingdom, serving more than 3.7 million customers in an area of
approximately 10,000 square miles.





*Electricity
Distribution*





Northern
Electric’s and Yorkshire Electricity’s operations consist primarily of the
distribution of electricity in the United Kingdom. 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 service areas are
connected to the Northern Electric and Yorkshire Electricity networks and
electricity can only be delivered 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
“Use of System Agreement”, which Northern Electric and Yorkshire Electricity
separately entered into with the various suppliers of electricity in their
respective distribution areas. One such supplier, Innogy Holdings plc (“Innogy”)
and certain of its affiliates, represented approximately 47% of the total
revenues of Northern Electric and Yorkshire Electricity in 2004. The fees that
may be charged by Northern Electric and Yorkshire Electricity for use of their
distribution systems are controlled by a formula prescribed by the United
Kingdom’s electricity regulatory body that limits increases (and may require
decreases) based upon the rate of inflation in the United Kingdom and other
regulatory action.





12








At
December 31, 2004, 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 64,000 kilometers of underground cables. In addition to the
circuits referred to above, at December 31, 2004, Northern Electric’s and
Yorkshire Electricity’s distribution facilities also included approximately
58,000 transformers and approximately 750 primary substations. Substantially all
substations are owned, with the balance being leased from third parties, most of
which have 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 on behalf of Northern Electric’s and Yorkshire Electricity’s
distribution businesses 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 20% interest. The project, operated
by Origin Energy of Australia, is nearing completion and includes an
approximately 145 kilometer subsea pipeline across the Bass Strait off southern
Victoria. The Bass Project is expected to be fully operational in 2005. The gas
from the project will be sold to Origin Energy’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. Also in the Bass Basin, CE Gas holds a 23.5% interest in
the Trefoil discovery. This gas and gas liquids discovery was drilled in late
2004 and the commercial development potential is currently under evaluation. The
Otway project, in which CE Gas holds a 6% interest, is operated by Woodside of
Australia. This project received construction approval during 2004. Construction
has now commenced with first production expected in 2006. Further prospecting in
the three Otway Basin exploration permits in which CE Gas holds a 6% interest
continues to be investigated. CE Gas also has a one-third interest in permit EP
437 in the onshore northern Perth Basin. The permitting process for this project
was successfully completed in 2004.





In the
United Kingdom, CE Gas continues to retain its 5% interest in the Victor Field,
which is a gas field located in the North Sea, and during 2004, successfully
applied for, and was granted, a new exploration permit in which CE Gas has a
100% interest.





In
Poland, CE Gas retains its development interest in the Polish Trough. CE Gas,
together with its joint venture partners FX Energy and the Polish Oil and Gas
Company, has drilled the Zaniemysl #3 well in the Fences I Concession. This
resulted in a commercial gas discovery early in 2004 in which CE Gas holds a
24.5% interest. This discovery is currently being developed and it is
anticipated that the field will be on production in early 2006.





**CalEnergy
Generation-Foreign**





*Business*





The
CalEnergy Generation-Foreign platform consists of MEHC’s indirect ownership of
the Upper Mahiao, Mahanagdong and Malitbog projects, which are geothermal power
plants located on the island of Leyte in the Philippines, and the Casecnan
project, a combined irrigation and hydroelectric power generation project
located in the central part of the island of Luzon in the Philippines. 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.




13








The
following table sets out certain information concerning CalEnergy
Generation-Foreign’s non-utility power projects in operation as of
December 31, 2004:





**Facility****Net**
    
    
    
    
    
    
    
    **Power****Capacity**
    
    **Net
      MW**
    
    
    
    **Contract**
    
    **Purchaser/****Project****(1)**
    
    **(MW)****(2)**
    
    **Owned****(2)**
    
    **Fuel**
    
    **Expiration**
    
    **Guarantor****(3)**Upper
      Mahiao
    
    
    119
    
    
    119
    
    
    Geo
    
    
    2006
    
    
    PNOC-EDC/ROPMahanagdong
    
    
    155
    
    
    150
    
    
    Geo
    
    
    2007
    
    
    PNOC-EDC/ROPMalitbog
    
    
    216
    
    
    216
    
    
    Geo
    
    
    2007
    
    
    PNOC-EDC/ROPCasecnan(4)
    
    
    150
    
    
    150
    
    
    Hydro
    
    
    2021
    
    
    NIA/ROPTotal
      International Projects
    
    
    640
    
    
    635





(1)
    All
      projects are located in the Philippines, are governed by contracts which
      are mainly payable in U.S. dollars 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 undertakings of the ROP
      support PNOC-EDC’s and NIA’s respective obligations for each
      project.(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.





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 18, 2006, the end of the ten-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 on a “take-or-pay” basis, 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 entered
into on 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 5% 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. PNOC-EDC’s payment requirements, and its other obligations under the
Upper Mahiao agreement, are supported by the ROP through a performance
undertaking.





The
Mahanagdong project is a 155 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.




14








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 ten
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 entered into on August 31, 2003, CE Luzon and PNOC-EDC
agreed that the plant capacity would equal the contractually specified level,
which declines from approximately 155 MW in 2004 to approximately 153 MW in the
last year of the cooperation period. The capacity fees are approximately 97% of
total revenue at the contractually agreed capacity levels and the energy fees
are approximately 3% of such total revenue. PNOC-EDC’s payment requirements, and
its other obligations under the Mahanagdong agreement, are supported by the ROP
through a performance undertaking.





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
electrical energy produced by the facility is sold to PNOC-EDC on a
“take-or-pay” basis. These capacity payments equal 100% of total revenue.
Pursuant to an amendment to the Malitbog energy conversion agreement entered
into on 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 will
generally be made to a peso-denominated account and will be used to pay
peso-denominated operation and maintenance expenses with respect to the Malitbog
project and Philippine withholding taxes, if any, on the Malitbog project’s debt
service. The ROP has entered into a performance undertaking, which provides that
all of PNOC-EDC’s obligations pursuant to the Malitbog energy conversion
agreement carry the full faith and credit of, and are affirmed and guaranteed
by, the ROP. The Malitbog energy conversion agreement ten 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.





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 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. The seasonality of rainfall patterns and the variability of
rainfall from year to year, all of which are outside the control of CE Casecnan,
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. Summarized below
are significant provisions of the Project Agreement as modified by the
Supplemental Agreement.




15


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.


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.





The ROP
has provided a Performance Undertaking under which NIA’s obligations under the
Project Agreement, as supplemented by the Supplemental Agreement, are guaranteed
by the full faith and credit of the ROP. The Project Agreement and the
Performance Undertaking provide for the resolution of disputes by binding
arbitration in Singapore under international arbitration rules.





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.




16








**CalEnergy
Generation-Domestic**





*Business*





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, 2004:





**Facility**
    
    
    
    
    
    
    
    **Power****Net**
    
    **Net**
    
    
    
    
    
    **Purchase****Capacity**
    
    **MW**
    
    
    
    
    
    **Agreement**
    
    **Power****Operating
      Project**
    
    **(MW)****(1)**
    
    **Owned****(1)**
    
    **Fuel**
    
    **Location**
    
    **Expiration**
    
    **Purchaser****(2)**Cordova
    
    
    537
    
    
    537
    
    
    Gas
    
    
    Illinois
    
    
    2017
    
    
    El
      PasoSalton
      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
    
    
    Varies
    
    
    VariousSaranac
    
    
    240
    
    
    90
    
    
    Gas
    
    
    NewYork
    
    
    2009
    
    
    NYSE&GPower
      Resources
    
    
    212
    
    
    106
    
    
    Gas
    
    
    Texas
    
    
    2005
    
    
    ONEOKYuma
    
    
    50
    
    
    25
    
    
    Gas
    
    
    Arizona
    
    
    2024
    
    
    SDG&ERoosevelt
      Hot Springs
    
    
    23
    
    
    17
    
    
    Geo
    
    
    Utah
    
    
    2020
    
    
    UP<otal
      Domestic Operating Projects
    
    
    1,389
    
    
    939





(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)
    El
      Paso; Southern California Edison Company (“Edison”); New York State
      Electric & Gas Corporation (“NYSE&G”); ONEOK Energy, Marketing and
      Trading Company, L.P. (“ONEOK”); San Diego Gas & Electric Company
      (“SDG&E”); and Utah Power & Light Company
      (“UP&L”).





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. Cordova Energy entered into a power purchase
agreement with a unit of El Paso, under which El Paso will purchase all of the
capacity and energy from the project until December 31, 2019. 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 from El Paso 50% of the output of the Cordova Project, reducing
El Paso’s purchase obligation to 50% of the output during such contract year.
Cordova Energy exercised such option for the contract year ended May 14, 2004,
and the recalled output was sold to MidAmerican Energy. Cordova Energy did not
exercise the recall option for the contract year which commenced on May 15,
2004, and El Paso is required to purchase 100% of the capacity and energy from
the project for the current contract year and, subject to future exercises of
the recall option, for the remainder of the term of the power purchase
agreement. The Company is aware there have been public announcements that El
Paso’s financial condition has deteriorated as a result of, among other things,
reduced liquidity and will continue to monitor the situation.





MEHC has
a 50% ownership interest in CE Generation, LLC (“CE Generation”) whose
affiliates currently operate ten geothermal plants in the Imperial Valley in
California (the “Imperial Valley Projects”). The Imperial Valley Projects
include the “Salton Sea Projects” consisting of the Salton Sea I, Salton Sea II,
Salton Sea III, Salton Sea IV and Salton Sea V projects and the “Partnership
Projects” consisting of the Vulcan, Elmore, Leathers, Del Ranch and CE Turbo
projects.




17








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, Salton Sea V and CE Turbo
projects), 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
commencing May 1, 2002 for a five-year period. Following the five-year
period, the energy payments revert back to Edison’s Avoided Cost of
Energy.





For the
years ended December 31, 2004, 2003 and 2002, Edison’s average Avoided Cost
of Energy was 5.9 cents per kWh, 5.4 cents per kWh and 3.5 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.





On
May 20, 2003, Salton Sea Power LLC (“Salton Sea Power”) entered into a
power sales agreement with Riverside. Under the terms of the agreement, Salton
Sea Power sells up to 20 MW of energy generated from the Salton Sea V project to
Riverside. Sales under the agreement commenced June 1, 2003 and will
terminate May 31, 2013.





Pursuant
to 33-year power sales agreements, the Salton Sea V and CE Turbo projects had
sold a portion of their net output to CalEnergy Minerals LLC (“Minerals”) for
the Zinc Recovery Project’s full electrical energy requirements. The agreements
provide for energy payments based on the market rates available to the Salton
Sea V and CE Turbo projects, adjusted for wheeling costs. On September 10,
2004, Minerals ceased operations of the Zinc Recovery Project. Accordingly,
except for sales during the dismantling and decommissioning phases of the Zinc
Recovery Project, no further sales to Minerals are expected. The Salton Sea V
project sells its remaining output and the CE Turbo project sells its available
power under the transaction agreement as described in the next
paragraph.





Pursuant
to a transaction agreement dated January 29, 2003, the Salton Sea V project
and the CE Turbo project began selling available power to TransAlta USA Inc.
(“TransAlta”) on February 12, 2003 based on percentages of the Dow Jones
SP-15 Index. The transaction agreement shall continue until the earlier of (a)
30 days following a written notice of termination and (b) any other termination
date mutually agreed to by the parties. No such notice of termination has been
given by either party.





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, ArcLight Capital Holdings and General
Electric Capital Corporation. 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 2009.





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. The agreement commenced October 1, 2003 and expires
December 31, 2005. Under the terms of the agreement, Power Resources, as an
exempt wholesale generator ("EWG"), sells its electricity and capacity to ONEOK
for a fixed amount per kW-month plus a variable operating and maintenance fee
per MWh. In addition, ONEOK pays annual turbine start-up costs.





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 PPA"). MEHC has guaranteed all of the obligations of YCA
under the Yuma PPA or any other agreement with SDG&E relating to or arising
out of the Yuma PPA. YCA also has executed steam sales contracts with Queen
Carpet, Inc. to act as its thermal host.




18


The
Roosevelt Hot Springs project is a geothermal steam field which supplies
geothermal steam to a 23 net MW power plant owned by UP&L located on the
Roosevelt Hot Springs property under a 30-year steam sales contract expiring in
2020. The Company obtained a cash prepayment under a pre-sale agreement with
UP&L whereby UP&L paid in advance for the steam produced by the steam
field. MEHC guarantees the performance of this subsidiary and must make certain
penalty payments to UP&L if the steam produced does not meet certain
quantity and quality requirements.





*Zinc
Recovery Project*





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”).





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





On
September 10, 2004, management made the decision to cease operations of the Zinc
Recovery Project. In connection with ceasing operations, the Zinc Recovery
Project’s assets are being dismantled and sold and certain employees of the
operator of the Zinc Recovery Project have been paid one-time termination
benefits. Implementation of a disposal plan began in September 2004 and will
continue in 2005. Refer to Note 3 of Notes to Consolidated Financial Statements
included in “Item 8. Financial Statements and Supplementary Data” of this Form
10-K for additional discussion regarding the Company’s discontinued
operations.





*Development
Projects*





MEHC’s
indirect wholly-owned subsidiary, CE Obsidian Energy LLC (“Obsidian”), is
evaluating the development of a 185 net MW geothermal facility in the Imperial
Valley in California. Substantially all of the output of the facility would be
sold to the Imperial Irrigation District (“IID”) pursuant to a power purchase
agreement. TransAlta is currently funding 50% of the development costs of this
project. Significant development and construction risk remains with this
project.





**HomeServices**





*Business*





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, mortgage banking, title and closing services
and other related services. 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, 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, Missouri; Des
Moines, Iowa; Omaha and Lincoln, Nebraska; Birmingham and Auburn, Alabama;
Tucson, Arizona; Winston-Salem and Charlotte, North Carolina; Louisville and
Lexington, Kentucky; Annapolis, Maryland; Atlanta, Georgia; Miami, Florida and
Springfield, Missouri.


19








*Acquisitions*





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.





**Regulatory
Matters**


**General
Regulation**





The
Company’s operating platforms are subject to a number of federal, state, local
and international regulations.





*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 could be restricted.





With the
elimination of its energy adjustment clause in Iowa in 1997, MidAmerican Energy
is financially exposed to movements in energy prices. Although MidAmerican
Energy believes it has sufficient generation under typical operating conditions
for its retail electric needs, a loss of adequate generation by MidAmerican
Energy requiring the purchase of replacement power at a time of high market
prices could subject MidAmerican Energy to losses on its energy
sales.





Under
three settlement agreements between MidAmerican Energy, the Iowa Office of
Consumer Advocate (“OCA”) and other intervenors, approved by the IUB,
MidAmerican Energy has agreed not to seek a general increase in electric rates
prior to 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 request or support 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 the
first settlement agreement, which was approved by the IUB on December 21,
2001, and is effective through December 31, 2005, an amount equal to 50% of
revenues associated with returns on equity between 12% and 14%, and 83.33% of
revenues associated with returns on equity above 14%, in each year is recorded
as a regulatory liability. The second settlement agreement, which was filed in
conjunction with MidAmerican Energy’s application for ratemaking principles on
its wind power project and was approved by the IUB on October 17, 2003,
provides that during the period January 1, 2006 through December 31,
2010, an amount equal to 40% of revenues associated with returns on equity
between 11.75% and 13%, 50% of revenues associated with returns on equity
between 13% and 14%, and 83.3% of revenues associated with returns on equity
above 14%, in each year will be recorded as a regulatory liability.




20





The third
settlement agreement was approved by the IUB on January 31, 2005, in
conjunction with MidAmerican Energy’s proposed expansion of its wind power
project by up to 90 MW. This settlement 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. In addition, the OCA agreed to
commit not to seek any decrease in Iowa electric base rates to become effective
before January 1, 2012. The total capacity added as the result of the wind
expansion project is currently projected to be 50 MW.





The
regulatory liabilities created by the three settlements 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 in amounts equal to the allowance for funds
used during construction 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.





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





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





If
implemented, the FERC’s July 2002 proposed rule for SMD would require sweeping
changes to the use and expansion of the interstate transmission and wholesale
bulk power systems in the United States. However, it is unclear when or even
whether the FERC will issue a final rule and what form the final rule would
ultimately take. In response to significant criticism of its proposed rule, the
FERC subsequently indicated that it had changed its proposal and would adopt a
flexible approach to SMD that would accommodate regional differences. Any final
rule on SMD or similar FERC action could impact the costs of MidAmerican
Energy’s electricity and transmission products. Such FERC action could directly
or indirectly influence how transmission services are priced, the availability
of transmission services, how transmission services are obtained and market
prices for electricity in markets in which MidAmerican Energy buys and sells
electricity. Although MidAmerican Energy is not presently a member of an RTO,
two RTOs - Midwest Independent System Operator and PJM Interconnection - are
directly interconnected with MidAmerican Energy’s transmission facilities.
MidAmerican Energy cannot predict what impact, if any, the evolution of these
RTOs, or others, may have on how wholesale electricity is bought and sold, as
well as the geographic scope of the wholesale marketplace in which MidAmerican
Energy buys or sells electricity.





On
June 3, 2004, the FERC’s Division of Operational Investigations of the
Office of Market Oversight and Investigations informed MidAmerican Energy that
it was commencing an audit to determine whether and how MidAmerican Energy and
its subsidiaries and affiliates are complying with (1) requirements of the
standards of conduct and open access same-time information system of the FERC’s
regulations, (2) codes of conduct, and (3) transmission practices. The FERC has
commenced several such audits of utilities in 2003 and 2004. The audit is
on-going, and MidAmerican Energy expects it to be completed within the first
half of 2005. 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.





On
July 13, 2004, the FERC issued an order requiring MidAmerican Energy to
conduct a study to determine whether MidAmerican Energy or its affiliates
possess generation market power. MidAmerican Energy is being required to show
the absence of generation market power in order to be allowed to continue to
sell wholesale electric power at market-based rates. The FERC order is intended
to have MidAmerican Energy conform to what has become the FERC’s general
practice for utilities given authorization to make wholesale market-based sales.
Under this general practice, utilities authorized to make market-based electric
sales must submit a new market power study to the FERC every three years. In
accordance with the FERC order, MidAmerican Energy’s market-based sales became
subject to refund beginning November 1, 2004, and will remain so until the
matter is resolved. 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.




21





*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.





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.





Kern
River’s tariff rates were 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 are set using a “levelized cost-of-service”
methodology so that the rate is constant over the contract period. This is
achieved by using a FERC-approved depreciation schedule in which depreciation
increases as interest expense decreases.





Kern
River was required to file a general rate case no later than May 1, 2004
pursuant to the terms of its 1998 FERC Docket No. RP99-274 rate case settlement.
Kern River filed its rate case on April 30, 2004, which supports a revenue
increase of $40.1 million representing a 13% increase from its existing
cost of service and a proposed overall cost of service of $347.4 million.
Since its last rate case, Kern River has increased the capacity of its system
from 724,500 Dth per day to 1,755,575 Dth per day at a cost of approximately
$1.3 billion resulting in a total rate base of approximately $1.8 billion. The
rate increase became effective on November 1, 2004, subject to refund, and
the FERC set a procedural order with a hearing scheduled for March
2005.





On
February 10, 2005, Kern River received notice from the Office of Market
Oversight and Investigations of the FERC that it is instituting a non-public
audit to determine Kern River's compliance with the FERC's standards of conduct
in regards to communications with any of Kern River's marketing and energy
affiliates. The time period of the audit generally covers September 22, 2004, to
the present although some questions cover time periods from November 25, 2003.
Kern River understands that virtually all interstate pipelines are expected to
be audited by the FERC in 2005. Kern River believes it is in compliance with the
standards of conduct in all material respects and the outcome of this audit is
not expected to have a material effect on Kern River's results of operations,
financial position or cash flows.





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





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





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




22





On
February 16, 2005, Northern Natural Gas reached a tentative agreement with the
majority of its customers to settle the consolidated rate cases. Definitive
terms of the settlement must be agreed by all settling parties and must then be
documented in a settlement agreement which must be agreed to by all settling
parties. Thereafter, the settlement must be certified by the presiding
administrative law judge and approved by the FERC. The terms of the agreement in
principle provide for an annual revenue increase of $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. As a result of the settlement,
Northern Natural Gas will be required to refund an amount generally reflecting
the difference between the rate increases implemented on November 1, 2003
and November 1, 2004 and the final settled revenue amounts.


Additional
proposals and proceedings that might affect the interstate 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.





*Other
United States Regulation*





The
Public Utility Regulatory Policies Act of 1978, as amended ("PURPA") and the
Public Utility Holding Company Act of 1935, as amended (“PUHCA”), are two of the
laws (including the regulations thereunder) that affect MEHC and certain of its
subsidiaries’ operations. PURPA provides to qualified facilities (“QF”) certain
exemptions from federal and state laws and regulations, including
organizational, rate and financial regulation. PUHCA extensively regulates and
restricts the activities of registered public utility holding companies and
their subsidiaries. Any legislation altering PUHCA or PURPA, if adopted, could
adversely impact the Company's existing domestic projects.





The
Company is currently exempt from regulation under all provisions of PUHCA,
except the provisions that regulate the acquisition of securities of public
utility companies, based on the intrastate exemption in Section 3(a)(1) of
PUHCA. In order to maintain this exemption, MEHC and each of its public utility
subsidiaries from which it derives a material part of its income (currently only
MidAmerican Energy) must be predominantly intrastate in character and organized
in and carry on MEHC’s and MidAmerican Energy’s respective utility operations
substantially in MidAmerican Energy’s state of organization (currently Iowa).
Except for MidAmerican Energy’s generating plant assets, the majority of the
Company's domestic power plant operations and all of its foreign utility
operations are not public utilities within the meaning of PUHCA as a result of
their status as QFs under PURPA (with the Company’s ownership interest therein
limited to 50%), EWGs or foreign utility companies, or are otherwise exempted
from the definition of “public utility” under PUHCA. Although the Company
believes that it will continue to qualify for exemption from additional
regulation under PUHCA, it is possible that as a result of the expansion of its
public utility operations, loss of exempt status by one or more of its domestic
power plants or foreign utilities, or amendments to PUHCA or the interpretation
of PUHCA, the Company could become subject to additional regulation under PUHCA
in the future. There can be no assurances that such regulation would not have a
material adverse effect on the Company.





In the
event the Company was unable to avoid the loss of QF status for one or more of
its affiliate’s facilities, such an event could result in termination of a given
project’s power sales agreement and a default under the project subsidiary’s
project financing agreements, which, in the event of the loss of QF status for
one or more facilities, could have a material adverse effect on the
Company.





Regulatory
requirements applicable in the future to nuclear generating facilities could
adversely affect the results of operations of MEHC and MidAmerican Energy, in
particular. The Company is subject to certain generic risks associated with
utility nuclear generation, including risks arising from the operation of
nuclear facilities and the storage, handling and disposal of high-level and
low-level radioactive materials; risks of a serious nuclear incident;
limitations on the amounts and types of insurance commercially available in
respect of losses that might arise in connection with nuclear operations; and
uncertainties with respect to the technological and financial aspects of
decommissioning nuclear plants at the end of their licensed lives. The Nuclear
Regulatory Commission (“NRC”) has broad authority under federal law to impose
licensing and safety-related requirements for the operation of nuclear
generating facilities. Revised safety requirements promulgated by the NRC have,
in the past, necessitated substantial capital expenditures at nuclear plants,
including the Quad Cities units, in which MidAmerican Energy has an ownership
interest, and additional such expenditures could be required in the
future.




23





*Pipeline
Safety Regulation*





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 system. 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
facilities 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 things, 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 which could pose a hazard
to navigation or public safety. In addition, the amendments narrowed the scope
of its gas pipeline exemption pertaining to underground storage tanks under the
Resource Conservation and Recovery Act. The Company believes its pipeline
operations 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 a major new final rule, effective February 14, 2004,
that requires interstate pipeline operators to: develop comprehensive integrity
management programs, identify applicable threats to pipeline segments that could
impact High Consequence Areas, assess these segments, and provide ongoing
mitigation and monitoring. The Company believes its pipeline operations comply
in all material respects with the PSIA.





*CE
Electric UK*





Since
1990, the electricity generation, supply and distribution industries in Great
Britain have been privatized, and competition has been introduced in generation
and supply. 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 service
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 holders of an electricity distribution license.
The residual elements of the electricity supply licenses were transferred to
Innogy 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 (the “Yorkshire Swap”).





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.





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




24





The
current formula requires that regulated distribution income per unit is
increased or decreased each year by RPI-Xd where RPI means the Retail Price
Index, 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 2000 (and
through March 31, 2005, will continue to be set) at 3%. 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.





The
procedure and methodology adopted at a price control review is 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 most efficient
      licensees;

·
    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 1999, the allowed revenue of Northern
Electric’s distribution business was reduced by 24%, in real terms, and the
allowed revenue of Yorkshire Electricity’s distribution business was reduced by
23%, in real terms, with effect from April 1, 2000.





Ofgem’s
process of reviewing each DLH’s existing price control formula, with a revised
formula for each DLH (including Northern Electric and Yorkshire Electricity) to
take effect from April 1, 2005 for an expected period of five years was
recently completed. As a result of the review, 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. The Xd factor was set at
zero. 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 may depend on the successful
implementation of revised cost reporting guidelines to be prescribed by Ofgem
and applied by all DLHs. 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.





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 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 a £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.





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 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.




25





*CalEnergy
Generation-Foreign*





In June
2004, Philippine President Gloria Macapagal-Arroyo was re-elected for a six-year
term, through June 2010. President Macapagal-Arroyo has announced a plan to
pursue policies targeting balanced economic growth, strong market-based
industry, and poverty alleviation. In connection with those policies, the
Philippine Department of Energy has announced an energy plan focused on
attaining a 100 percent electrification level throughout the Philippines,
further developing and utilizing renewable energy sources for power and
electrification, and enhancing private sector participation in all energy
activities.





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
Philippines power industry as a whole, the effect of which is not yet
determinable or estimable.





In
connection with an interagency review of approximately 40 independent power
project contracts in the Philippines pursuant to EPIRA, in 2003 the Casecnan
project (together with four other unrelated projects) had reportedly been
identified as raising legal and financial questions and, with those projects,
had been prioritized for renegotiation. As part 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. MEHC’s indirect
subsidiaries’ Leyte Projects also had reportedly been identified as raising
financial questions. In connection with the entering into of amendments to the
energy conversion agreement for each of the Leyte Projects with PNOC-EDC, the
Company believes that any issues raised by the interagency review of independent
power producers in the Philippines with respect to the Leyte Projects have been
resolved.





*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. QF status under PURPA provides two primary benefits.
First, regulations under PURPA exempt QFs from PUHCA, the FERC rate regulation
under 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 require 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. There can be no assurance that the QF status of such CalEnergy
Generation - Domestic facilities will be maintained.





Cordova
Energy and Power Resources are exempt from regulation under PUHCA because they
are EWGs. PUHCA provides that a EWG is not considered to be an electric utility
company. A EWG is permitted to sell capacity and electricity in the wholesale
markets, but not in the retail markets.





If an 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. On
July  29, 2002,
HUD issued a proposed regulation under the Real Estate Settlement and Procedures
Act.(“RESPA”) HUD has characterized the proposal as “fundamentally changing the
way in which payments to mortgage brokers are recorded and reported to
consumers,” “significantly” improving the disclosure of settlement costs on the
Good Faith Estimate making it firmer and more usable, and “removing regulatory
barriers to allow guaranteed packages of settlement services and mortgages to be
made available to consumers.” The proposal was submitted to the Office of
Management and Budget on December 16, 2003, and was voluntarily withdrawn
by HUD on March 22, 2004. The House Committee on Financial Services, the Senate
Committee on Banking, Housing and Urban Affairs and HUD each has indicated that
reforming the RESPA regulation is a priority in 2005. It is unknown whether a
proposed rule will be introduced or finalized in 2005. Accordingly, the Company
is presently unable to quantify the likely impact of any proposed rule, if
issued.




26





**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 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 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.





Clean
Air Standards





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





The EPA
has in recent years implemented more stringent 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
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 in the area 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 is in attainment of the ozone standards
and the fine particulate standards.





On
December 4, 2003, the EPA announced the development of its Interstate Air
Quality Rule, now known as the Clean Air Interstate Rule, a proposal to require
coal-burning power plants in 29 states, including Iowa, and the District of
Columbia to reduce emissions of sulfur dioxide (“SO 2 ”) and
nitrogen oxides (“NO X ”) in an
effort to reduce ozone and fine particulate matter in the Eastern United States.
It is likely that MidAmerican Energy’s coal-burning facilities will be impacted
by this proposal.





In
December 2000, the EPA concluded that mercury emissions from coal-fired
generating stations should be regulated. The EPA is currently considering two
regulatory alternatives that would reduce emissions of mercury from coal-fired
utilities. One of these alternatives would require reductions of mercury from
all coal-fired facilities greater than 25 MW through application of Maximum
Achievable Control Technology with compliance assessed on a facility basis. The
other alternative would regulate the mercury emissions of coal-fired facilities
that pose a health hazard through a market based cap-and-trade mechanism similar
to the SO 2 allowance system. The EPA is currently under a deadline to finalize the mercury
reduction rule by March 2005.





The Clean
Air Interstate Rule or the mercury reduction rule 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 the “Clear Skies Initiative,” and other pending legislative proposals
that contemplate 70% to 90% reductions of SO 2 ,
NO X and
mercury, as well as possible new federal regulation of carbon dioxide and other
gasses that may affect global climate change.




27





Depending
on the outcome of the final Clean Air Interstate Rule and the mercury reduction
rule or any superseding legislation by Congress, MidAmerican Energy may be
required to install control equipment on its generating stations, purchase
emission allowances or decrease the number of hours during which its generating
stations operate. However, until final regulatory or legislative action is
taken, the impact of the regulations on MidAmerican Energy cannot be
predicted.





MidAmerican
Energy has implemented a planning process that forecasts the site-specific
controls and actions that may be required to meet emissions reductions as
contemplated 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 SO 2 and
NO X 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 Iowa Consumer Advocate Division of the Department of
Justice. 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 $325.0 million,
then MidAmerican Energy may seek to recover the additional expenditures from
customers. At this time, MidAmerican Energy does not expect these capital
expenditures to exceed such amount.





Under the
New Source Review (“NSR”) provisions of the Clean Air Act, a utility is required
to obtain a permit from the EPA or a state regulatory agency prior to (1)
beginning construction of a new major stationary source of an NSR-regulated
pollutant or (2) making a physical or operational change 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 support
regarding their capital projects for various generating plants. The requests
were issued as part of an industry-wide investigation to assess compliance with
the NSR and the New Source Performance Standards of the Clean Air Act. In
December 2002 and April 2003, MidAmerican Energy received requests from the EPA
to provide documentation related to its capital projects from January 1,
1980, to 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. However, on
August 27, 2003, the EPA announced changes to its NSR rules that clarify
what constitutes routine repair, maintenance and replacement for purposes of
triggering NSR requirements. The EPA concluded equipment that is repaired,
maintained or replaced with an expenditure not greater than 20 percent of the
value of the source will not trigger the NSR provisions of the Clean Air Act. A
number of states and local air districts challenged the EPA’s clarification of
the NSR rule and a panel of the U.S. Circuit Court of Appeals for the District
of Columbia Circuit issued an order on December 24, 2003, staying the EPA’s
implementation of its clarifications of the equipment replacement rule. On
July 1, 2004, the EPA published a notice of stay of the final equipment
replacement rule in the *Federal
Register* ,
consistent with the judicial stay. Additionally, on the same date, the EPA
published a Notice of Reconsideration and Request for Comment on the equipment
replacement rule in response to the Petitioners’ legal challenges. Until such
time as the EPA takes final action on the equipment replacement rule, the
previous rules without the clarified exemption remain in effect.





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.




28





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 informed MidAmerican Energy that existing
on-site storage capability at Quad Cities Station is sufficient to permit
interim storage in 2005. For Quad Cities Station, Exelon Generation has begun to
develop 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. Exelon
Generation has completed the bulk of the construction work on the first pad and
expects the first cask loading to take place in 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 2004 was
$8.3 million.





*United
Kingdom*





CE
Electric UK’s businesses are subject to extensive regulatory requirements with
respect to the protection of the environment.





The
United Kingdom government introduced new contaminated land legislation in April
2000 that requires local governmental authorities to put in place a program for
investigating land in their area in order to identify contamination. Local
authorities (and the Environment Agency where controlled waters are affected)
can enforce remedial action where such contamination of land poses a threat to
the greater environment. If the “person” who contaminated the land cannot be
found, the land owner will be held responsible.





The UK
local authorities have not identified any CE Electric UK sites that require any
action under these regulations. CE Electric UK evaluations of three potential
sites confirm this conclusion. A project with an environmental remediation
company is in progress at one of these sites where there is an agreement to
reduce pockets of localized contamination to an acceptable
standard.




29





The
Environmental Protection Act (Disposal of PCB’s and other Dangerous Substances)
Regulations 2001 were introduced on May 5, 2000. The regulations required
that transformers containing over 50 parts per million of PCB’s and other
dangerous substances be registered with the Environment Agency. Transformers
containing 500 parts per million had to be de-contaminated by December 31,
2000. As of December 31, 2004, CE Electric UK had 360 transformers
containing between 50 and 500 parts per million of such substances registered
with the Environment Agency and is continuing with its sampling, labeling and
registration program. CE Electric UK believes it is in compliance and these
regulations are not expected to have a material impact on the
Company.





The 1998
Groundwater Regulations seek to prevent listed hazardous substances from
entering groundwater and strengthens the United Kingdom Environment Agency’s
powers to require additional protective measures, especially in areas of
important groundwater supplies. Mineral oils and hydrocarbons are included in
the list of more tightly controlled substances (“List I substances”). This
affects the high voltage fluid filled electricity cable network incorporating an
insulating fluid that is currently in List I. The existing voluntary Operating
Code of Practice, as agreed between the Environment Agency and companies in the
electricity industry, is undergoing revision to address the regulatory changes.
The existing voluntary Operating Code of Practice is, and any revised Operating
Code of Practice will be, incorporated into the operating practices of Northern
Electric and Yorkshire Electricity. Any revisions which are made are not
expected to have a material impact on the Company.





The Oil
Storage Regulations became effective in 2002 and require the phased introduction
of secondary containment measures (bunding) for all above ground oil storage
locations where the capacity is more than 200 liters. The primary containers
must be in sound condition, leak free, and positioned away from vehicle traffic
routes. The secondary containment must be impermeable to water and oil (without
drainage valve) and be subject to routine maintenance. The capacity of the bund
must be sufficient to hold up to 110% of the largest stored vessel or 25% of the
maximum stored capacity, whichever is the greater. On March 1, 2002, these
regulations came into effect for all new oil storage facilities. On
September 1, 2003, the regulations became effective for existing storage
facilities at “significant risk” (i.e. within 10 meters of a water course), and
on September 1, 2005, the regulations come into effect for all remaining
storage facilities. A detailed study of the impacts has been carried out and a
plan of action prepared to ensure compliance. The Company expects that the cost
of compliance with the remaining provisions of such regulations will not have a
material impact.





The
Electricity Act 1989 obligates either the United Kingdom Secretary of State or
the Director General of Electric Supply to take into account the effect of
electricity generation, transmission and supply activities on the physical
environment when approving applications for the construction of overhead power
lines. The Electricity Act requires CE Electric UK to consider the desirability
of preserving natural beauty and the conservation of natural and man-made
features of particular interest when it formulates proposals for development in
connection with certain of its activities. CE Electric UK mitigates the effects
its proposals have on natural and man-made features and administers an
environmental assessment when it intends to lay cables, construct overhead lines
or carry out any other development in connection with its licensed activities.
The Company expects that the cost of compliance with these obligations and the
mitigation thereof will not have a material impact.





CE
Electric UK’s policy is to carry out its activities in such a manner as to
minimize the impact of its works and operations on the environment, and in
accordance with environmental legislation and good practice. There have not been
any significant regulatory environmental compliance issues and there are no
material legal or administrative proceedings pending against CE Electric UK with
respect to any environmental matter.





Environmental
laws and regulations in the United Kingdom currently have, and future
modifications may increasingly have, the effect of requiring modification of CE
Electric UK’s facilities and increasing its operating costs.





*Philippines*





On
June 23, 1999, the Philippine Congress enacted the Philippine Clean Air Act
of 1999. 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 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 Clean Air Act. The gas dispersion project was put into
commercial operation in December 2003.





30








**Employees**





At
December 31, 2004, the Company employed approximately 11,540 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 expires February 28, 2006, and covers approximately 1,700 employee
members.





**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. See
Notes 6 and 23 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.





**MidAmerican
Energy**





MidAmerican
Energy’s most significant properties are its electric generation facilities.
Refer to the MidAmerican Energy discussion in “Item 1. Business” of this Form
10-K for additional information about MidAmerican Energy’s generation
facilities.





The
electric transmission system of MidAmerican Energy at December 31, 2004,
included 918 miles of 345-kV lines and 1,128 miles of 161-kV lines. MidAmerican
Energy’s electric distribution system included approximately 222,300
transformers and 382 substations at December 31, 2004.





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, 2004, included approximately 21,548
miles of gas mains and services pipelines.





**Kern
River and Northern Natural Gas**





At
December 31, 2004, Kern River’s pipeline consisted of two distinguishable
sections: the mainline section and the common facilities. The mainline section
consists of the original 682 miles of 36-inch pipeline, 628 miles of 36-inch
loop pipeline related to the 2003 Expansion Project and 68 miles of various
laterals that connect to the mainline, and extends from the pipeline’s point of
origination near Opal, Wyoming through the Central Rocky Mountains area into
Daggett, California and is owned entirely by Kern River. The common facilities
consist of the 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 (currently approximately 76.8%) and
Mojave (currently approximately 23.2%) as tenants-in-common.





At
December 31, 2004, Northern Natural Gas’ system was comprised of
approximately 7,300 miles of mainline transmission pipelines and approximately
9,200 miles of lateral pipelines. Northern Natural Gas’ storage services are
provided through the operation of three underground storage fields, in Redfield,
Iowa, and Lyons and Cunningham, Kansas. Northern Natural Gas’ three underground
natural gas storage facilities and two LNG storage peaking units have a total
storage capacity of approximately 59 Bcf. Northern Natural Gas’ two LNG
liquefaction/vaporization facilities are located near Garner, Iowa and
Wrenshall, Minnesota with storage capacity of 2 Bcf each.





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.




31





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.





**CE
Electric UK**





At
December 31, 2004, Northern Electric’s and Yorkshire Electricity’s
electricity distribution networks (excluding service connection to consumers) on
a combined basis included approximately 33,000 kilometers of overhead lines and
approximately 64,000 kilometers of underground cables. In addition to the
circuits referred to above, at December 31, 2004, Northern Electric’s and
Yorkshire Electricity’s distribution facilities also included approximately
58,000 transformers and approximately 750 primary substations.





**Other
Properties**





At
December 31, 2004, MEHC’s most significant physical properties, other than
those owned by MidAmerican Energy, Kern River, Northern Natural Gas and CE
Electric UK, are its current interests in operating power facilities and its
plants under construction and related real property interests, as well as leases
of office space for its residential real estate brokerage operations. See “Item
1. Business” of this Form 10-K for further detail.





**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.





**Pipeline
Litigation**





In 1998,
the United States Department of Justice informed the then current owners of Kern
River and Northern Natural Gas that Jack Grynberg, an individual, had filed
claims in the United States District Court for the District of Colorado under
the False Claims Act against such entities and certain of their subsidiaries
including Kern River and Northern Natural Gas. Mr. Grynberg has also filed
claims against numerous other energy companies and alleges that the defendants
violated the False Claims Act in connection with the measurement and purchase of
hydrocarbons. The relief sought is an unspecified amount of royalties allegedly
not paid to the federal government, treble damages, civil penalties, attorneys’
fees and costs. On April 9, 1999, the United States Department of Justice
announced that it declined to intervene in any of the Grynberg qui tam cases,
including the actions filed against Kern River and Northern Natural Gas in the
United States District Court for the District of Colorado. On October 21,
1999, the Panel on Multi-District Litigation transferred the Grynberg qui tam
cases, including the ones filed against Kern River and Northern Natural Gas, to
the United States District Court for the District of Wyoming for pre-trial
purposes. Motions to dismiss the complaint, filed by various defendants
including Northern Natural Gas and The Williams Companies, Inc. (“Williams”),
which was the former owner of Kern River, were denied on May 18, 2001. On
October 9, 2002, the United States District Court for the District of
Wyoming dismissed Grynberg’s royalty valuation claims. On November 19,
2002, the United States District Court for the District of Wyoming denied
Grynberg’s motion for clarification and dismissed his royalty valuation claims.
Grynberg appealed this dismissal to the United States Court of Appeals for the
Tenth Circuit and on May 13, 2003, the Tenth Circuit Court dismissed his
appeal. Motions to Dismiss based on various jurisdictional grounds were filed on
June 4, 2004. Grynberg filed his brief and other pleadings in opposition to
the Motions to Dismiss on October 22, 2004. In connection with the purchase
of Kern River from Williams in March 2002, Williams agreed to indemnify MEHC
against any liability for this claim; however, no assurance can be given as to
the ability of Williams to perform on this indemnity should it become necessary.
No such indemnification was obtained in connection with the purchase of Northern
Natural Gas in August 2002. The Company believes that the Grynberg cases filed
against Kern River and Northern Natural Gas are without merit and that Williams,
on behalf of Kern River pursuant to its indemnification, and Northern Natural
Gas, intend to defend these actions vigorously.




32





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





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





**Natural
Gas Commodity Litigation**





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





The
original complaint in this matter, *Cornerstone
Propane Partners, L.P. v. Reliant, et al. (“Cornerstone”),* was
filed on August 18, 2003 in the United States District Court, Southern
District of New York naming MidAmerican Energy and MEHC. On October 1,
2003, a second complaint, *Roberto,
E. Calle Gracey, et al. (“Calle Gracey”),* was
filed in the same court but did not name MidAmerican Energy or MEHC. On
November 14, 2003, a third complaint, *Dominick
Viola (“Viola”),*  *et* al., was
filed in the same court and named MidAmerican Energy and MEHC as defendants. On
November 19, 2003, an Order of Voluntary Dismissal Without Prejudice of
MEHC was entered by the court dismissing MEHC from the *Cornerstone* and *Viola* complaints.
On December 5, 2003, the court entered Pretrial Order No. 1, which among
other procedural matters, ordered the consolidation of the *Cornerstone,
Calle Gracey* and *Viola* complaints
and permitted plaintiffs to file an amended complaint in this matter. On
January 20, 2004, plaintiffs filed *In
Re: Natural Gas Commodity Litigation* as the
amended complaint reasserting their previous allegations. On February 19,
2004, MidAmerican Energy filed a Motion to Dismiss and joined with several other
defendants to file a joint Motion to Dismiss. The plaintiffs filed a response on
May 19, 2004, contesting both Motions to Dismiss. On September 24,
2004, the pending Motions to Dismiss were denied. On October 14, 2004, the
plaintiffs filed an amended consolidated class action complaint reasserting
their previous allegations. On January 25, 2005, the plaintiffs filed their
motion for class certification. MidAmerican Energy will continue to coordinate
with the other defendants and vigorously defend the allegations against
it.




33





**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, LaPrairie Group Contractors (International) Ltd. (“LPG”),
that MEHC’s 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, among others, CE Casecnan Ltd. and MEHC. On
January 21, 2004, CE Casecnan Ltd. and LPG 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 distribution without
at least 15 days prior notice to LPG. Accordingly, 15% of the CE Casecnan
dividend distributions declared in 2004, totaling $15.9 million, was set
aside by CE Casecnan in an unsecured CE Casecnan account and is shown as
restricted cash and short-term investments and other current liabilities in the
accompanying consolidated balance sheet included in “Item 8. Financial
Statements and Supplementary Data” of this Form 10-K.  The court is
currently expected to rule on the first phase of the litigation before the end
of the first quarter of 2005. The impact, if any, of this litigation on the
Company cannot be determined at this time.





**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 under the Mirant Agreement.
In July 2003, Mirant filed for Chapter 11 bankruptcy protection and continued to
perform under the Mirant Agreement post-bankruptcy. In October 2003, Mirant
informed Kern River that it would not renew its letter of credit and Kern River
drew on the letter of credit and held the proceeds thereof, $14.8 million,
as cash collateral. Effective December 18, 2003, Mirant rejected the Mirant
Agreement pursuant to procedures under the Bankruptcy Code and paid all
post-petition amounts then due and owing under the Mirant Agreement through
December 18, 2003. On January 13, 2004, Kern River filed a proof of
claim with the bankruptcy court for an aggregate total amount of
$210.2 million (the “Kern River Claim”), which Kern River believed was
secured to the extent of the $14.8 million in proceeds received from the
letter of credit and held as a cash security deposit. The claims underpinning
the proof of claim arise from damages caused by Mirant’s rejection of the Mirant
Agreement. On May 25, 2004, the bankruptcy court issued an order permitting Kern
River to apply 100% of the $14.8 million cash security deposit to its claim
for damages. On October 12, 2004, Mirant raised an objection to the Kern River
Claim asserting, among other things, that Kern River had not included a discount
adjustment or mitigation to the claim. On November 11, 2004, Kern River filed an
amended proof of claim of $138.8 million, reflecting discounting, mitigation and
other adjustments, and which excludes the $14.8 million already received by
Kern River. Kern River can not determine at this time if it will collect any
portion of the balance of the Kern River Claim or be able to remarket the
rejected Mirant Agreement capacity.





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





Not
applicable.




34





**PART
II**





**Item
5.****Market
for Registrant’s Common Equity and Related Stockholder
Matters.**





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





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





The
following table sets forth selected financial data, which should be read in
conjunction with the Company’s consolidated financial statements and the related
notes to those statements included in “Item 8. Financial Statements and
Supplementary Data” and with “Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations” appearing elsewhere in this Form
10-K. The selected financial data as of and for the years ended
December 31, 2004, 2003, 2002 and 2001, and as of December 31, 2000
and for the period from March 14, 2000 through December 31, 2000, have
been derived from the Company’s historical consolidated financial statements.
The selected financial data from January 1, 2000 through March 13,
2000, have been derived from MEHC (Predecessor)’s historical consolidated
financial statements.





**MEHC****(Predecessor)****March
      14**
      **2000**
    
    **January
      1,**
      **2000****Year
      Ended December 31,**
    
    **through**
      **December 31,**
    
    **through**
      **March 13,****2004**
    
    **2003**
    
    **2002****(1)**
    
    **2001****(2)**
    
    **2000****(3)**
    
    **2000****(4)**(Amounts
      in millions)**Statement
      of Operations Data:**Operating
      revenue
    
    $
    6,553.4
    
    $
    5,965.6
    
    $
    4,795.2
    
    $
    4,696.8
    
    $
    3,918.1
    
    $
    1,056.4Income
      from continuing operations
    
    
    537.8
    
    
    442.7
    
    
    397.4
    
    
    148.4
    
    
    84.1
    
    
    51.4Loss
      from discontinued operations, net of tax(5)
    
    
    (367.6
    )
    
    (27.1
    )
    
    (17.4
    )
    
    (5.7
    )
    
    (2.8
    )
    
    (0.1
    )Net
      income
    
    $
    170.2
    
    $
    415.6
    
    $
    380.0
    
    $
    142.7
    
    $
    81.3
    
    $
    51.3**Balance
      Sheet Data:**Total
      assets
    
    $
    19,903.6
    
    $
    19,145.0
    
    $
    18,434.9
    
    $
    12,994.6
    
    $
    11,960.4
    
    
    N/AParent
      company senior debt(6)
    
    
    2,772.0
    
    
    2,777.9
    
    
    2,323.4
    
    
    1,834.5
    
    
    1,830.0
    
    
    N/AParent
      company subordinated debt(6)
    
    
    1,585.8
    
    
    1,772.1
    
    
    -
    
    
    -
    
    
    -
    
    
    N/ACompany-obligated
      mandatory redeemable preferred securities of subsidiary
    trusts
    
    
    -
    
    
    -
    
    
    2,063.4
    
    
    788.2
    
    
    786.5
    
    
    N/ASubsidiary
      and project debt(6)
    
    
    6,304.9
    
    
    6,674.6
    
    
    7,077.1
    
    
    4,754.8
    
    
    3,398.7
    
    
    N/ASubsidiary-obligated
      mandatorily redeemable preferred securities of subsidiary
      trusts
    
    
    -
    
    
    -
    
    
    -
    
    
    100.0
    
    
    100.0
    
    
    N/APreferred
      securities of subsidiaries
    
    
    89.5
    
    
    92.1
    
    
    93.3
    
    
    121.2
    
    
    145.7
    
    
    N/ATotal
      stockholders’ equity
    
    $
    2,971.2
    
    $
    2,771.4
    
    $
    2,294.3
    
    $
    1,708.2
    
    $
    1,576.4
    
    
    N/A





35








(1)
    Reflects
      the acquisitions of Kern River on March 27, 2002 and Northern Natural Gas
      on August 16, 2002.(2)
    Reflects
      the Yorkshire Swap on September 21, 2001 and includes
      $15.2 million of after-tax income related to the sale of the Northern
      Electric electricity and gas supply business, the sale of the Telephone
      Flat Project, the sale of Western States Geothermal, the transfer of Bali
      Energy Ltd. shares, and the Teesside Power Limited (‘‘TPL’’) asset
      valuation impairment charge.(3)
    Reflects
      the Teton Transaction on March 14, 2000.(4)
    Includes
      $7.6 million of expenses related to the Teton
      Transaction.(5)
    Reflects
      MEHC’s 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
      and for the periods January 1, 2000 through March 13, 2000 and
      March 14, 2000 through December 31, 2000, are classified
      separately as discontinued operations.(6)
    Excludes
      current portion.





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





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





**General**





The
Company’s operations are organized and managed on seven distinct platforms:
MidAmerican Energy, Kern River, Northern Natural Gas, CE Electric UK (which
includes Northern Electric and Yorkshire Electricity), CalEnergy
Generation-Foreign, CalEnergy Generation-Domestic, and
HomeServices.





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





The
Company’s principal energy subsidiaries generate, transmit, store, distribute
and supply energy. The Company’s electric and natural gas utility subsidiaries
currently serve approximately 4.4 million electricity customers and
approximately 680,000 natural gas customers. Its natural gas pipeline
subsidiaries operate interstate natural gas transmission systems with
approximately 18,300 miles of pipeline in operation and peak delivery capacity
of 6.4 Bcf of natural gas per day. The Company has interests in 6,777 net owned
MW of power generation facilities in operation and under construction, including
5,203 net owned MW in facilities that are part of the regulated return asset
base of its electric utility business and 1,574 net owned MW in non-utility
power generation facilities. Substantially all of the non-utility power
generation facilities have long-term contracts for the sale of energy and/or
capacity from the facilities.





36











**Executive
Summary**





The
following significant events and changes, as discussed in more detail herein,
highlight some factors that affect the comparability of our financial results,
for the years ended December 31, 2004, 2003 and 2002,
respectively:







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






|· | In
      December 2004, MidAmerican Energy placed into service the second phase of
      its 327 MW natural gas-fired combined cycle generating plant. The plant is
      the first of three electric generating projects to be completed by
      MidAmerican Energy. MidAmerican Energy expects to invest approximately
      $1.1 billion in the two remaining projects through 2007. Both projects are
      currently under construction and $350.4 million of the $1.1 billion
      had been invested through December 31,
2004.
|- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------






|· | The
      Company made significant investments in its natural gas pipeline business
      by acquiring Kern River in March 2002 for $419.7 million, net of cash
      acquired, and Northern Natural Gas in August 2002 for $882.7 million,
      net of cash acquired, and completing the 2003 Expansion Project in May
      2003 at a total cost of $1.2 billion. These pipelines serve major markets
      in the midwest and western United States.
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------






|· | HomeServices
      separately acquired 13 real estate companies throughout 2004, 2003 and
      2002. Operating revenue has grown from $1.1 billion in 2002 to $1.8
      billion in 2004.
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------






|· | CE
      Electric UK operates mainly in Great Britain and the majority of its
      transactions are in Pounds Sterling. The weighted average ratio of U.S.
      Dollars to Pounds Sterling was 1.84, 1.64 and 1.49 during each of the
      years ended December 31, 2004, 2003 and 2002, respectively, which
      continues to produce positive revenue and profit comparisons on a year
      over year basis.
|- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------






|· | Both
      Kern River and Northern Natural Gas have filed for rate increases with the
      FERC and have hearings scheduled in 2005. New rates for Northern Natural
      Gas’ May 2003 rate case went into effect on November 1, 2003, subject to
      refund. New rates for the Northern Natural Gas’ January 2004 and Kern
      River’s April 2004 rate cases each went into effect on November 1,
      2004, subject to refund. Additionally, 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 will be reduced by 4% and 9%, respectively, in
      real terms, effective April 1, 2005.
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------






|· | CE
      Casecnan reached an arbitration settlement with the NIA effective during
      the fourth quarter of 2003. As part of the settlement, NIA paid CE
      Casecnan $17.7 million plus Philippines pesos of 39.9 million
      (approximately $0.7 million) and delivered a ROP $97.0 million
      8.375% Note due in 2013. In exchange, CE Casecnan agreed to modify certain
      provisions of the 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. In January 2004, CE Casecnan exercised its
      right to put the note and received $99.2 million (representing par
      plus accrued interest) from the ROP.
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------






|· | On
      November 23, 2004, Northern Natural Gas sold its stipulated general,
      unsecured claim of $249.0 million against Enron Corp. (“Enron”) to a
      third party investor for $72.2 million and recorded the proceeds
      received as other income in 2004.
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------






|· | In
      the fourth quarter of 2004, CE Generation recorded a $16.8 million charge
      as a result of the partial impairment of the carrying value of the Power
      Resources project.
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------






|· | In
      February 2004, MEHC issued $250.0 million of 5.00% senior notes due
      February 15, 2014. The proceeds from these issuances were used
      to satisfy a demand made by MEHC’s affiliate, Salton Sea Funding
      Corporation (“Funding Corporation”), for the amount remaining on MEHC’s
      guarantee of Funding Corporation’s 7.475% Senior Secured Series F Bonds
      (“Series F Bonds”) and for other general corporate purposes. In October
      2004, MidAmerican Energy issued $350.0 million of 4.65% medium-term
      notes due October 2014, which were used for general corporate purposes.
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------







37


****


****


**Results
of Operations for the Year Ended December 31, 2004 and the Year Ended
December 31, 2003**





The
following table summarizes net income for the years ended December 31(in
millions):





**2004**
    
    
    **2003****Income
      from continuing operations before income tax expense, minority interest
      and preferred dividends of subsidiaries and equity
      income:**MidAmerican
      Energy
    
    $
    267.8
    
    $
    271.4Kern
      River
    
    
    142.6
    
    
    133.7Northern
      Natural Gas
    
    
    218.0
    
    
    127.3CE
      Electric UK
    
    
    325.9
    
    
    288.7CalEnergy
      Generation-Foreign
    
    
    165.7
    
    
    177.6CalEnergy
      Generation-Domestic
    
    
    3.1
    
    
    2.1HomeServices
    
    
    111.9
    
    
    90.0Total
      reportable segments
    
    
    1,235.0
    
    
    1,090.8Corporate/other
    
    
    (435.8
    )
    
    (232.9
    )**Income
      from continuing operations before income tax expense, minority interest
      and preferred dividends of subsidiaries and equity
      income**
    
    
    799.2
    
    
    857.9Income
      tax expense
    
    
    265.0
    
    
    270.3Minority
      interest and preferred dividends of subsidiaries
    
    
    13.3
    
    
    183.2**Income
      from continuing operations before equity income**
    
    
    520.9
    
    
    404.4Equity
      income
    
    
    16.9
    
    
    38.3**Income
      from continuing operations**
    
    
    537.8
    
    
    442.7Loss
      from discontinued operations, net of tax benefits
    
    
    (367.6
    )
    
    (27.1
    )**Net
      income available to common and preferred
    stockholders**
    
    $
    170.2
    
    $
    415.6





The
$367.6 million loss from discontinued operations, net of tax benefits, for
the year ended December 31, 2004 included a $340.3 million non-cash
impairment charge recognized in connection with ceasing operations of the
Company’s Zinc Recovery Project and a $27.1 million loss from operations, net of
tax, of the Zinc Recovery Project.





Income
from continuing operations for the year ended December 31, 2004, increased
$95.1 million, or 21.5%, to $537.8 million compared with
$442.7 million for the same period in 2003.





Equity
income for the year ended December 31, 2004, decreased $21.4 million to
$16.9 million compared with $38.3 million for the same period in 2003.
CE Generation recorded a $16.8 million charge as a result of the partial
impairment of the carrying value of the Power Resources project. Additionally,
HomeServices’ mortgage joint ventures had lower income due to lower refinancing
activity.





Minority
interest and preferred dividends for the year ended December 31, 2004,
decreased $169.9 million to $13.3 million from $183.2 million for
the same period in 2003. The decrease was due to the Company’s adoption, as of
October 1, 2003, of FASB Interpretation No. 46R, “Consolidation of Variable
Interest Entities” (“FIN 46R”) related to certain finance subsidiaries. The
adoption required the deconsolidation of certain finance subsidiaries, which
resulted in the amounts previously classified as mandatorily redeemable
preferred securities of subsidiary trusts being reclassified as parent company
subordinated debt in the Company’s consolidated balance sheet at
December 31, 2003. The adoption also required that amounts previously
recorded in minority interest and preferred dividends of subsidiaries be
recorded as interest expense in the Company’s consolidated statements of
operations, prospectively. In accordance with the requirements of FIN 46R, no
amounts prior to adoption, on October 1, 2003, have been reclassified. The
amount remaining in minority interest and preferred dividends of subsidiaries
related to these mandatorily redeemable preferred securities of subsidiary
trusts for the nine-month period ended September 30, 2003, was
$170.2 million.





Income
tax expense for the year ended December 31, 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 the years ended
December 31, 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, and the settlement by CE Electric UK of
various positions with the Inland Revenue department and a change in the State
of Iowa’s income tax laws in 2004.




38








Income
from continuing operations before income tax expense, minority interest and
preferred dividends of subsidiaries and equity income decreased
$58.7 million, or 6.8%, to $799.2 million in 2004 from
$857.9 million in 2003. The decrease was due to the following:





*Reportable
Segments*




·
    Kern
      River's pre-tax earnings were $8.9 million higher due to the
      completion of the 2003 Expansion Project in May 2003, partially offset by
      lower capitalized interest in connection with completing the expansion. In
      2004, Kern River collected $14.8 million on its claim for damages
      against Mirant for the rejection by Mirant of its firm gas transportation
      contract. The income was largely offset by revenue lost related to the
      rejection of the agreement.
 ·
    Northern
      Natural Gas' pre-tax earnings were $90.7 million higher due to a
      $72.2 million pre-tax gain on the sale of the Enron Note Receivable
      and improved results associated with the May 2003 rate case which resulted
      in higher rates commencing November 1,
2003.
 ·
    CE
      Electric UK's pre-tax earnings were $37.2 million higher primarily
      from the approximately $34.0 million favorable earnings impact of the
      continued weakness of the U.S. dollar relative to the British pound,
      partially offset by the $8.9 million gain from the sale of a local
      operational and dispatch facility at Northern Electric in
      2003.
 ·
    CalEnergy
      Generation-Foreign's pre-tax earnings were $11.9 million lower in
      2004 compared to 2003. In 2003, CE Casecnan recorded
      $31.9 million of income in connection with the settlement of its
      arbitration with the NIA. That gain was partially offset by the settlement
      of various disputes which the Leyte Projects had with PNOC-EDC, which
      resulted in the reversal of accrued revenue totaling $11.3 million.
      In 2004, CE Casecnan had lower revenue as a result of its contract
      arbitration settlement, which was fully offset by higher revenue at the
      Leyte Projects due to price indices and lower interest expense on the
      repayment of project debt. Also in 2004, CalEnergy Generation-Foreign
      earned higher interest income on affiliate loans of $8.7
      million.
 ·
    Pre-tax
      earnings at HomeServices were $21.9 million higher due to higher
      average home sales prices and acquisitions not included in the comparable
      2003 period.
 
 *Corporate*
 
 ·
    The
      Company’s adoption of FIN 46R, as previously described, required that
      amounts previously recorded in minority interest and preferred dividends
      of subsidiaries be recorded as interest expense in the Company’s
      consolidated statements of operations prospectively. As a result, the
      charges for interest expense related to securities of the Company’s
      finance subsidiaries increased by $147.1 million to
      $196.9 million in 2004 from $49.8 million in 2003.
 ·
    During
      June 2003, the Company sold its investment in Williams Cumulative
      Convertible Preferred Stock. As a result, 2003 pre-tax earnings included
      $32.6 million from the gain on the sale and dividend
    income.
 ·
    The
      Company's corporate interest expense increased $11.5 million
      primarily as a result of the issuance of the $250.0 million of 5.00%
      senior notes in February 2004.


39








*Revenue*





Operating
revenue for the year ended December 31, 2004 increased $587.8 million
or 9.9% to $6,553.4 million from $5,965.6 million for the same period
in 2003. The following table summarizes operating revenue by segment for the
years ended December 31 (in millions):





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





MidAmerican
Energy’s operating revenue for the year ended December 31, 2004, increased
$101.5 million, or 3.9%, to $2,701.7 million. Regulated and
non-regulated natural gas revenue increased $53.8 million, or 4.8%, to
$1,166.5 million mainly due to higher prices for natural gas purchased for
regulated customers, which is passed directly to the customer, and regulated
wholesale volumes. Average natural gas prices increased 7.4 % from 2003
to 2004. These price increases were partially offset by lower regulated retail
and non-regulated volumes. Regulated and non-regulated electric revenue
increased $49.8 million, or 3.4%, to $1,518.9 million mainly due to
higher regulated retail and non-regulated volumes as well as prices of wholesale
sales. These increases were partially offset by lower regulated wholesale
volumes and regulated retail prices.





Operating
revenue at Kern River and Northern Natural Gas is principally derived by
providing firm or interruptible transportation services under long-term gas
transportation service agreements. Northern Natural Gas also derives part of its
revenue from storing gas. Kern River’s operating revenue for the year ended
December 31, 2004, increased $55.9 million, or 21.5%, to
$316.1 million primarily due to the transportation fees earned in
connection with the 2003 Expansion Project, which began operations May 1,
2003. Northern Natural Gas’ operating revenue, which reflects the impact of the
new rates beginning November 1, 2004 and 2003, and higher gas and liquid
sales, increased $57.9 million, or 11.9%, to $544.8 million for the
year ended December 31, 2004.





CE
Electric UK’s operating revenue for the year ended December 31, 2004,
increased $106.4 million, or 12.8%, to $936.4 million primarily as a
result of the weaker U.S. dollar. Additionally, CE Electric UK experienced
increased revenue at its contracting business.





Operating
revenue for CalEnergy Generation-Foreign for the year ended December 31,
2004, decreased $19.0 million, or 5.8%, to $307.4 million primarily
due to lower water delivery fees in connection with the NIA arbitration
settlement at CE Casecnan effective in the fourth quarter of 2003, partially
offset by higher energy fees due to increased generation on higher water flows
in 2004.





HomeServices’
operating revenue for the year ended December 31, 2004, consisting mainly
of commission revenue from real estate brokerage transactions, increased
$279.8 million, or 18.9%, to $1,756.4 million. The increase is due
primarily to growth at existing businesses of $154.7 million due primarily
to higher average home sales prices and acquisitions not included in the
comparable 2003 period totaling $125.1 million. During the year ended
December 31, 2004, HomeServices participated in $59.8 billion of
transactions, an increase of $11.2 billion from 2003. About 24% of the
increase came from the six acquisitions made during the year.




40





*Costs
and expenses*





Cost of
sales for the year ended December 31, 2004, increased $351.4 million,
or 14.6%, to $2,751.9 million from $2,400.5 million for the same
period in 2003. HomeServices’ cost of sales, consisting primarily of commissions
on real estate brokered transactions, increased $211.8 million due to
higher commission expense on incremental sales at existing business units and
acquisitions not included in the comparable 2003 period. MidAmerican Energy’s
costs of sales increased $87.4 million due mainly to an increase in the per
unit cost of natural gas, higher regulated wholesale natural gas, regulated
retail electric and non-regulated electric volumes, partially offset by lower
regulated retail and non-regulated natural gas volumes. Northern Natural Gas’
cost of sales increased $18.9 million due to higher gas and liquid sales.
CE Electric UK’s cost of sales increased $16.7 million mainly due to
increased activity at its contracting business 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 the year ended December 31, 2004, increased
$125.6 million, or 8.3%, to $1,637.9 million from
$1,512.3 million for the same period in 2003. HomeServices’ operating
expenses, consisting mainly of compensation, marketing and other administrative
costs, increased $44.8 million due mainly to acquisitions not included in
the comparable 2003 period. MidAmerican Energy’s operating expenses increased
$40.3 million due mainly to higher generation maintenance costs, Quad
Cities Station expenses, and transmission expenses. CE Electric UK’s operating
expenses increased $39.3 million, mainly 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. Kern River’s operating expenses increased
$16.4 million due to the commencement of operations of the 2003 Expansion
Project. CalEnergy Generation-Foreign’s operating expenses decreased
$12.5 million mainly due to lower legal and other costs in
2004.





Depreciation
and amortization for the year ended December  31, 2004,
increased $35.3 million to $638.2 million from $602.9 million for
the same period in 2003. Kern River’s expense increased $16.5 million due
to the completion of the 2003 Expansion Project. Northern Natural Gas’ expense
increased $15.2 million due to higher depreciation rates consistent with
the filed rate case. CE Electric UK’s expense increased $12.7 million
primarily due to the weaker U.S. dollar. Partially offsetting these increases
was a decrease in MidAmerican Energy’s expense of $14.6 million due
primarily to a decrease in regulatory expense related to its revenue sharing
arrangements.





*Other
income and expense*





Interest
expense for the year ended December 31, 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 as interest expense
in the accompanying consolidated statement of operations, prospectively. For the
year ended December 31, 2004 and the three-month period ended
December 31, 2003, the Company has 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 have been 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.





Capitalized
interest for the year ended December 31, 2004, decreased $10.5 million
to $20.0 million from $30.5 million for the same period in 2003. The
decrease was mainly due to the discontinuance of capitalizing interest on Kern
River’s 2003 Expansion Project, partially offset by increased construction
activity at MidAmerican Energy’s generation projects.





Interest
and dividend income for the year ended December 31, 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.




41





Other
income for the year ended December 31, 2004, increased $31.6 million
to $128.2 million from $96.6 million for the same period in 2003. 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 the year ended December 31, 2004, decreased
$6.2 million due primarily to the completion of Kern River’s expansion in
2003.





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





The
following table summarizes net income for the years ended December 31(in
millions):





**2003**
    
    
    **2002****Income
      from continuing operations before income tax expense, minority interest
      and preferred dividends of subsidiaries and equity
      income:**MidAmerican
      Energy
    
    $
    271.4
    
    $
    238.8Kern
      River
    
    
    133.7
    
    
    60.7Northern
      Natural Gas
    
    
    127.3
    
    
    42.9CE
      Electric UK
    
    
    288.7
    
    
    266.8CalEnergy
      Generation-Foreign
    
    
    177.6
    
    
    147.9CalEnergy
      Generation-Domestic
    
    
    2.1
    
    
    (1.2
    )HomeServices
    
    
    90.0
    
    
    61.2Total
      reportable segments
    
    
    1,090.8
    
    
    817.1Corporate/other
    
    
    (232.9
    )
    
    (185.4
    )**Income
      from continuing operations before income tax expense, minority interest
      and preferred dividends of subsidiaries and equity
      income**
    
    
    857.9
    
    
    631.7Income
      tax expense
    
    
    270.3
    
    
    111.3Minority
      interest and preferred dividends of subsidiaries
    
    
    183.2
    
    
    163.5**Income
      from continuing operations before equity income**
    
    
    404.4
    
    
    356.9Equity
      income
    
    
    38.3
    
    
    40.5**Income
      from continuing operations**
    
    
    442.7
    
    
    397.4Loss
      from discontinued operations, net of tax benefits
    
    
    (27.1
    )
    
    (17.4
    )**Net
      income available to common and preferred
    stockholders**
    
    $
    415.6
    
    $
    380.0





The loss
from discontinued operations, net of tax benefits, for the year ended
December 31, 2003, was $27.1 million as compared to $17.4 million
for 2002 and consists of losses from the operation of the Company’s Zinc
Recovery Project.





Income
from continuing operations for the year ended December 31, 2003, increased
$45.3 million, or 11.4%, to $442.7 million compared with
$397.4 million for the same period in 2002.





Equity
income for the year ended December 31, 2003, decreased $2.2 million to
$38.3 million compared with $40.5 million for the same period in 2003.
Equity income from non-regulated generation equity investments decreased
$16.6 million to $14.8 million from $31.4 million in 2002 mainly
due to the expiration of a contract at the Power Resources project and a charge
associated with an equity investment. Equity income from HomeServices for the
year ended December 31, 2003 increased $14.8 million to
$23.6 million primarily due to increased refinancing activity at mortgage
joint ventures.





Minority
interest and preferred dividends for the year ended December 31, 2003,
increased $19.7 million to $183.2 million from $163.5 million for
the same period in 2002. As previously described, the Company was required to
adopt, as of October 1, 2003, FIN 46R related to certain finance
subsidiaries. The adoption required that amounts previously recorded in minority
interest and preferred dividends of subsidiaries be recorded as interest expense
in the Company’s consolidated statements of operations prospectively. In
accordance with the requirements of FIN 46R, no amounts prior to adoption, on
October 1, 2003, have been reclassified. The amount remaining in minority
interest and preferred dividends of subsidiaries related to these securities
increased $22.5 million to $170.2 million for the nine-month period
ended September 30, 2003, from $147.7 million for the year ended
December 31, 2002. Mandatorily redeemable preferred securities of
subsidiary trusts were issued in 2002 to finance the acquisitions of both Kern
River and Northern Natural Gas.




42





Income
tax expense for the year ended December 31, 2003, increased
$159.0 million to $270.3 million from $111.3 million for the same
period in 2002. The effective tax rate was 31.5% and 17.6% for the years ended
December 31, 2003 and 2002, respectively. The increase in the effective tax
rate was primarily due to increased tax expense on foreign income including the
incremental tax expense of $24.4 million in connection with the CE Casecnan
NIA arbitration settlement proceeds. The 2002 effective tax rate was unusually
low as the Company recognized tax benefits of $35.7 million in connection
with the execution of the TPL restructuring agreement at CE Electric
UK.





Income
from continuing operations before income tax expense, minority interest and
preferred dividends of subsidiaries and equity income increased
$226.2 million, or 35.8%, to $857.9 million in 2003 from
$631.7 million in 2002. The increase was due to the following:





*Reportable
Segments*





·
    Pre-tax
      earnings at MidAmerican Energy were higher by $32.6 million. The
      reportable segment earned higher regulated Iowa electric income as it
      benefited from the first phase of the Greater Des Moines Energy Center
      beginning operation in May 2003, higher equity funds used during the
      construction of its electric generation projects, and certain
      non-recurring items, including lower fuel costs resulting from a contract
      restructuring and the settlement of a bankruptcy
claim.
 ·
    Kern
      River, acquired in March 2002, and Northern Natural Gas, acquired in
      August 2002, had higher pre-tax earnings of $73.0 million and
      $84.4 million, respectively, due mainly to the inclusion of the
      acquisitions for a full-year of operations in the Company’s consolidated
      results and the completion of Kern River’s 2003 Expansion
      Project.
 ·
    CE
      Electric UK's pre-tax earnings were higher by $21.9 million.
      Approximately $20.0 million of the increase resulted from higher
      distribution revenue at Yorkshire Electricity, $18.5 million was due
      to the earnings benefit of the continued weakness of the U.S. dollar
      relative to the British pound, $11.3 million related to lower costs
      primarily achieved from economies of scale with Northern Electric and
      Yorkshire Electricity, $14.4 million was a result of the gain and
      lower interest costs associated with a bond redemption, $8.9 million
      related to the gain on sale of a local operational and dispatch facility
      at Northern Electric, and $7.0 million for rebates received from the
      National Grid Company. These increases were partially offset by the sale
      of several of its north sea, natural gas assets resulting in a pre-tax
      gain of $54.3 million.
 ·
    Pre-tax
      earnings at CalEnergy Generation-Foreign were higher by
      $29.7 million. In 2003, CE Casecnan recorded $31.9 million of
      other income in connection with the settlement of its arbitration with the
      NIA. The 2003 gain was partially offset by the settlement of various
      disputes which the Leyte Projects had with PNOC-EDC, which resulted in the
      reversal of accrued revenue totaling $11.3 million. The other
      significant difference in 2003 was the decrease in financial expense of
      $10.6 million due to repayment of debt and lower variable interest
      rates.
 ·
    HomeServices'
      pre-tax earnings were higher by $28.8 million due to acquisitions
      made throughout 2002 and 2003 and due to growth from higher home prices
      and higher mortgage refinancing activity at existing
      companies.
 
 *Corporate*
 
 ·
    The
      Company’s adoption of FIN 46R, as previously described, required that
      amounts previously recorded in minority interest and preferred dividends
      of subsidiaries be recorded as interest expense in the Company’s
      consolidated statements of operations prospectively. The charge to
      interest expense related to securities of the Company’s finance
      subsidiaries was $49.8 million in 2003 and $ - million in
      2002.


43











*Revenue*





Operating
revenue for the year ended December 31, 2003 increased
$1,170.4 million or 24.4% to $5,965.6 million from
$4,795.2 million for the same period in 2002. The following table
summarizes operating revenue by segment for the years ended December 31 (in
millions):





**Year
      Ended December 31,****2003**
    
    
    **2002****Operating
      revenue:**MidAmerican
      Energy
    
    $
    2,600.2
    
    $
    2,240.9Kern
      River
    
    
    260.2
    
    
    127.3Northern
      Natural Gas
    
    
    486.9
    
    
    178.1CE
      Electric UK
    
    
    830.0
    
    
    795.4CalEnergy
      Generation-Foreign
    
    
    326.4
    
    
    326.3CalEnergy
      Generation-Domestic
    
    
    45.2
    
    
    38.5HomeServices
    
    
    1,476.6
    
    
    1,138.3Total
      reportable segments
    
    
    6,025.5
    
    
    4,844.8Corporate/other
    
    
    (59.9
    )
    
    (49.6
    )**Total
      operating revenue**
    
    $
    5,965.6
    
    $
    4,795.2





MidAmerican
Energy’s operating revenue for the year ended December 31, 2003, increased
$359.3 million, or 16.0%, to $2,600.2 million. MidAmerican Energy’s
regulated and non-regulated gas revenue for the year ended December 31,
2003 increased $308.4 million to $1,112.7 million from
$804.3 million in 2002 mainly due to higher prices for gas purchased for
regulated customers which is passed directly to the customer. Average gas prices
increased 59.9 % or $2.24
per Dth from 2002 to 2003. Regulated electric revenue for the year ended
December 31, 2003 increased $44.6 million to $1,398.0 million
from $1,353.4 million for the same period in 2002 mainly due to higher
prices of wholesale sales during 2003.





Operating
revenue at both pipelines is principally derived by providing firm or
interruptible transportation services under long-term gas transportation service
agreements. Northern Natural Gas also derives part of its revenue from storing
gas. Kern River’s operating revenue for the year ended December 31, 2003,
increased $132.9 million to $260.2 million. The increase was primarily
due to the transportation fees earned in connection with the 2003 Expansion
Project which began operations May 1, 2003, and to a lesser degree, the
inclusion of its operations for all of 2003. Northern Natural Gas’ operating
revenue for the year ended December 31, 2003, increased $308.8 million to
$486.9 million. Northern Natural Gas was acquired on August 16, 2002.
The increase in its operating revenue relates to the timing of that acquisition
and inclusion of its operations for all of 2003.





CE
Electric UK’s operating revenue for the year ended December 31, 2004, increased
$34.6 million, or 4.4%, to $830.0 million. The increase was a result
of the weaker U.S. dollar, higher distribution revenue and higher revenue at its
contracting business. This was partially offset by lower revenue caused by the
sale of CE Gas assets in 2002.





HomeServices’
operating revenue for the year ended December 31, 2003, consisting mainly of
commission revenue from real estate brokerage transactions, increased
$338.3 million, or 29.7%, to $1,476.6 million. The increase was due to
acquisitions made throughout 2002 and 2003 and $91.3 million due to growth
at existing companies. During the year ended December 31, 2003, HomeServices
participated in $48.6 billion of transactions, an increase of $11.7 billion
from 2002. About 23% of the increase came from the four acquisitions made during
the year.





*Costs
and expenses*





Cost of
sales for the year ended December 31, 2003 increased $556.5 million,
or 30.2%, to $2,400.5 million from $1,844.0 million for the same
period in 2002. MidAmerican Energy’s cost of sales for the year ended
December 31, 2003 increased $345.6 million, or 34.9%, to
$1,334.5 million from $988.9 million for the same period in 2002.
MidAmerican Energy’s regulated and non-regulated gas cost of sales for the year
ended December 31, 2003 increased $291.1 million to
$878.1 million from $587.0 million in 2002 mainly due to the increase
in per unit cost of gas discussed in operating revenue. Electric cost of sales
increased $51.0 million in 2003 primarily due to the reclassification of
costs for energy purchased under the Cooper Nuclear Station restructured
contract between MidAmerican Energy and the Nebraska Public Power District which
expired in December 2004. Prior to August 1, 2002, the date of the
restructuring, only fuel costs for energy purchased from Cooper Nuclear Station
were classified as a cost of sales. Consistent with the restructured contract,
other costs under the contract are classified as operating expenses. Following
the restructuring, all costs for energy and capacity purchased under the
contract were included in cost of sales consistent with the new power purchase
contract. Operating expenses decreased accordingly.




44







HomeServices’
cost of sales, consisting primarily of commissions on real estate brokerage
transactions, increased $235.6 million for the year ended December 31,
2003, or 30.7%, to $1,003.2 million from $767.6 million for the same
period in 2002. Cost of sales increased $106.7 million due to acquisitions
made during 2002 and 2003. The remainder of HomeServices’ increase was due to
growth of existing companies totaling $128.9 million.





Operating
expenses for the year ended December 31, 2003 increased
$209.5 million, or 16.1%, to $1,512.3 million from
$1,302.8 million for the same period in 2002. An increase of
$146.6 million was due to Northern Natural Gas, which was owned for the
entire period in 2003. Increased operating expenses at HomeServices were
$78.8 million, primarily due to the impact of acquisitions and increased
compensation expenses. These increases were partially offset by lower operating
expenses at CE Electric UK of $39.6 million, mainly due to the sale of the
retail business in 2002 and a gain on the sale of a local operational dispatch
facility in 2003, and lower operating expenses at MidAmerican Energy of
$19.5 million primarily due to the restructuring of the Cooper
contract.





Depreciation
and amortization for the year ended December  31, 2003
increased $72.8 million, or 13.7%, to $602.9 million from
$530.1 million for the same period in 2002. An increase of
$34.6 million was due to Northern Natural Gas, which was owned for the
entire period in 2003. Increased depreciation at Kern River was
$19.6 million mainly due to the completion of the 2003 Expansion Project
and the inclusion of Kern River’s operations for the entire period. Increased
depreciation of $11.6 million at MidAmerican Energy due to higher utility
plant depreciation and increased depreciation of $8.2 million at CE
Electric UK due to a weaker U.S. dollar and an increased asset base, partially
offset by the CE Gas asset sale in 2002.





In 2002,
CE Gas executed the sale of several of its assets and recorded a pre-tax gain of
$54.3 million, which included a write off of non-deductible goodwill of
$49.6 million. 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 asset
sales.





*Other
Income and Expense*





Interest
expense for the year ended December 31, 2003 increased $128.9 million
to $761.0 million from $632.1 million for the same period in 2002. The
increase was mainly due to interest on parent company subordinated debt which
was $49.8 million for the quarter and year ended December 31, 2003.
This amount represents the interest recorded on the parent company subordinated
debt for the period from October 1, 2003, the date the Company adopted FIN
46R, through December 31, 2003. Prior to the adoption of FIN 46R, the
parent company subordinated debt was classified as company-obligated mandatorily
redeemable preferred securities of subsidiary trusts. Costs associated with
those instruments, prior to the adoption of FIN 46R, were classified as minority
interest and preferred dividends of subsidiaries in the accompanying
consolidated statements of operations. The remaining $79.1 million increase
resulted from additional interest expense totaling $38.9 million on MEHC’s
debt issuances of $700.0 million in October 2002 and $450.0 million in
May 2003, increased interest expense of $32.5 million at Northern Natural
Gas primarily due to a full year of ownership and increased interest expense at
Kern River of $32.2 million due to additional borrowings related to the
2003 Expansion Project and a full year of ownership. The increases were
partially offset by decreased interest, totaling $27.9 million, due to the
combination of the June 2003 redemption of the Yorkshire Electricity securities,
reductions in CalEnergy Generation-Foreign project debt, MEHC’s revolving credit
facility and the retirement of MEHC’s 6.96% Senior Notes.





Capitalized
interest for the year ended December 31, 2003 increased $7.1 million
to $30.5 million. The increase was mainly due to Kern River’s 2003
Expansion Project and increased construction activity at MidAmerican Energy’s
generation projects.





Interest
and dividend income for the year ended December 31, 2003 decreased
$8.1 million to $47.9 million from $56.0 million for the same
period in 2002. The decrease was primarily due to lower income at CE Electric UK
of $9.9 million due to lower cash balances partially offset by higher
dividend income on the investment in Williams Cumulative Convertible Preferred
Stock totaling $4.7 million and interest earned on higher corporate cash
balances available during 2003.




45







Other
income for the year ended December 31, 2003, increased $56.4 million
to $96.6 million from $40.2 million for the same period in 2003. 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 the year ended December 31, 2003, increased
$7.3 million due primarily to the construction of Kern River’s expansion in
2003.





Other
expense for the year ended December 31, 2003, decreased $22.7 million to
$5.9 million from $28.6 million for the same period in 2002.
In 2002, MidAmerican Energy recorded an impairment of its investment in
airplane leases and other non-regulated investments of
$21.7 million.





**Liquidity
and Capital Resources**





The
Company has available a variety of sources of liquidity and capital resources,
both internal and external. These resources provide funds required for current
operations, construction expenditures, debt retirement and other capital
requirements. The Company may from time to time seek to retire its outstanding
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.





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 were $960.9 million at
December 31, 2004, compared to $660.2 million at December 31,
2003. 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 $164.5 million and $119.5 million at
December 31, 2004 and 2003, respectively. The restricted cash balance for
both periods is comprised primarily of amounts deposited in restricted accounts
which are reserved for the service of debt obligations, customer deposits held
in escrow, custody deposits and unpaid dividends declared
obligations.





Cash
Flows from Operating Activities





The
Company generated cash flows from operations of $1,424.6 million for the
year ended December 31, 2004, compared with $1,217.9 million for the
same period in 2003. The increase was mainly due to greater income from
continuing operations and a tax refund as a result of a 2003 net operating loss
from accelerated depreciation. Also contributing to the net increase in cash
flows from operations were changes in working capital, partially offset by lower
distributions from equity investments.





Cash
Flows from Investing Activities





Cash
flows used in investing activities for the years ended December 31, 2004
and 2003 were $1,029.7 million and $1,003.2 million, respectively.
Capital expenditures, construction and other development costs for the years
ended December 31, 2004 and 2003 were $1,179.4 million and
$1,219.4 million, respectively. In addition to the capital expenditures,
contributing to the increase of cash flows used in investing activities was
$288.8 million of proceeds from the sale of convertible preferred
securities in 2003, partially offset by the receipt of the proceeds of the put
of the ROP Note, and sale of the Enron Note Receivable claim, as described
below.





*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.




46








*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.





*Capital
Expenditures, Construction and Other Development Costs*





Capital
expenditures, construction and other development costs were $1,310.3 for the
year ended December 31, 2004, compared with $1,179.8 million for the
same period in 2003. The following table summarizes the expenditures by business
segment (in millions):





**Year
      Ended December 31,****2004**
    
    
    **2003****Capital
      expenditures:**MidAmerican
      Energy
    
    $
    633.8
    
    $
    346.5Kern
      River
    
    
    26.9
    
    
    433.1Northern
      Natural Gas
    
    
    138.8
    
    
    104.4CE
      Electric UK
    
    
    334.5
    
    
    301.9CalEnergy
      Generation-Foreign
    
    
    4.6
    
    
    8.5CalEnergy
      Generation-Domestic
    
    
    1.3
    
    
    6.6HomeServices
    
    
    20.8
    
    
    18.3Segment
      capital expenditures
    
    
    1,160.7
    
    
    1,219.3Corporate/other
    
    
    18.7
    
    
    0.1**Total
      capital expenditures**
    
    $
    1,179.4
    
    $
    1,219.4





Forecasted
capital expenditures, construction and other development costs for fiscal 2005
are approximately $1.3 billion. Capital expenditure needs are reviewed regularly
by management and may change significantly as a result of such reviews. The
Company expects to meet these capital expenditures with cash flows from
operations and the issuance of debt. Capital expenditures relating to operating
projects, consisting mainly of recurring expenditures, were $778.3 million
for the year ended December 31, 2004. Construction and other development
costs were $401.0 million for the year ended December 31, 2004. These
costs consist mainly of expenditures for large scale, generation projects as
follows:





*MidAmerican
Energy*





MidAmerican
Energy anticipates a continuing increase in demand for electricity from its
regulated customers. To meet anticipated demand and ensure adequate electric
generation in its service territory, MidAmerican Energy recently completed its
combined cycle combustion turbine project and is currently constructing the 790
MW CBEC Unit 4 and a 310 MW (nameplate rating) wind power project in Iowa. A 50
MW (nameplate rating) expansion of the wind power project is also expected to be
constructed in 2005. The projects will provide service to regulated retail
electricity customers.





MidAmerican
Energy has obtained regulatory approval to include the Iowa portion of the
actual costs of the generation projects in its Iowa rate base as long as actual
costs do not exceed the agreed caps that MidAmerican Energy has deemed to be
reasonable. If the caps are exceeded, MidAmerican Energy has the right to
demonstrate the prudence of the expenditures above the caps, subject to
regulatory review. Wholesale sales may also be made from the projects to the
extent the power is not immediately needed for regulated retail service.
MidAmerican Energy expects to invest approximately $1.1 billion in the CBEC Unit
4 and wind generation projects currently under construction, of which
$350.4 million has been invested through December 31,
2004.





MidAmerican
Energy recently completed work on its Greater Des Moines Energy Center, a
natural gas-fired, combined cycle unit located near Pleasant Hill, Iowa.
Construction of the plant was completed in two phases. Commercial operation of
the simple cycle mode began on May 5, 2003, and continued through most of
2004, providing 327 MW of accredited capacity in the summer of 2004. Commercial
operation of the combined cycle mode began on December 16, 2004. The
additional accredited capacity from completion of the second phase is expected
to be 190 MW. MidAmerican Energy expects the total cost of the Greater Des
Moines Energy Center to be under the $357.0 million cost cap established by
the IUB.




47








MidAmerican
Energy is currently constructing the CBEC Unit 4, a 790 MW (based on expected
accreditation) super-critical-temperature, low-sulfur coal-fired plant.
MidAmerican Energy will operate the plant and hold an undivided ownership
interest as a tenant in common with the other owners of the plant. MidAmerican
Energy’s ownership interest is 60.67%, equating to 479 MW of output. MidAmerican
Energy expects its share of the estimated cost of the project, including
transmission facilities, to be approximately $737.0 million, excluding
allowance for funds used during construction. Municipal, cooperative and public
power utilities will own the remainder, which is a typical ownership arrangement
for large base-load plants in Iowa. On February 12, 2003, MidAmerican
Energy executed a contract with Mitsui for engineering, procurement and
construction of the plant. On September 9, 2003, MidAmerican Energy began
construction of the plant, which it expects to be completed in the summer of
2007. On December 29, 2004, MidAmerican Energy received an order from the
IUB approving construction of the associated transmission facilities and is
proceeding with construction.





The
second electric generating project currently under construction consists of wind
power facilities located at two sites in north central Iowa totaling 310 MW
based on the nameplate rating. Generally speaking, accredited capacity ratings
for wind power facilities are considerably less than the nameplate ratings due
to the varying nature of wind. The current projected accredited capacity for
these wind power facilities is approximately 53 MW. MidAmerican Energy will own
and operate these facilities, which are expected to cost approximately
$323.0 million, including transmission facilities and excluding the
allowance for funds using during construction. As of December 31, 2004,
wind turbines totaling 160.5 MW at one of the sites were completed and in
service. Completion of the remaining turbines is expected by the middle of 2005.
On January 31, 2005, the IUB approved ratemaking principles related to
expanding the wind power project. An additional 50 MW of capacity, based on
nameplate rating, is expected to be constructed at the sites in 2005 at an
estimated cost of $63.0 million.





MidAmerican
Energy’s total accredited net generating capability in the summer of 2004 was
4,897 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 4,481 MW and the net amount
of capacity purchases and sales of 416 MW. The actual amount of generation
capacity available at any time may be less than the accredited capability due to
regulatory restrictions, transmission constraints, fuel restrictions and
generating units being temporarily out of service for inspection, maintenance,
refueling, modifications or other reasons.




*HomeServices’
Acquisitions*





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.
These purchases were financed using HomeServices’ cash balances. 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.
Additionally in 2004, HomeServices paid an earnout of $6.0 million based on
2004 financial performance measures. These purchases were financed using
HomeServices’ cash balances and revolving credit facility.




48





Cash
Flows from Financing Activities





Cash
flows used in financing activities for the year ended December 31, 2004
were $122.8 million. During 2004, the Company used cash for financing
activities, totaling $747.9 million, primarily for repayments of subsidiary
and parent company obligations, including $136.4 million of cash flows from
discontinued operations, and generated cash from financing activities, totaling
$625.1 million, from the issuance of subsidiary, project and parent company
debt. Cash flows used in financing activities for the year ended
December 31, 2003 were $426.3 million. During 2003, the Company used
cash for financing activities, totaling $2,033.2 million, primarily for
repayments of subsidiary obligations and parent company debt and the retirement
of preferred securities of subsidiary trusts, and generated cash from financing
activities, totaling $1,606.9 million, from the issuance of subsidiary,
project and parent company debt.





*Recent
Debt Issuances, Redemptions and Stock Transactions*





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





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





On
October 1, 2004, MidAmerican Energy issued $350.0 million of 4.65%
medium-term notes due October 1, 2014. The proceeds were used for general
corporate purposes.





In 2004,
the Company made the required $100.0 million payment on its 11.00% parent
company subordinated debt. The payments on subsidiary and project debt made in
2004 consisted of the maturity of CE Electric UK’s 6.853% senior notes, totaling
$117.1 million, and regularly scheduled principal payments on project term
loans.





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





*Current
Maturities of Long-Term Debt*





The
Company’s current portion of long-term debt increased $644.7 million to
$1,145.6 million at December 31, 2004, from $500.9 million at December
31, 2003, due mainly to $260.0 million of 7.23% parent company senior notes
becoming due in the third quarter of 2005, and, 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 has included the entire principal amount of these securities in its
current portion of long-term debt in the accompanying consolidated balance
sheet. The Company plans to use existing cash and future debt issuances to repay
these obligations.





*Restricted
Cash and Short-Term Investments*





During
the year ended December 31, 2004, CE Casecnan increased its restricted cash
related to obligations for debt service and unpaid dividends declared.
Additionally, Northern Natural Gas increased its restricted cash related to
custody deposits.





49








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





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





In
connection with ceasing operations, the Zinc Recovery Project’s assets are being
dismantled and sold and certain employees of the operator of the Zinc Recovery
Project were paid one-time termination benefits. 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. The Company expects to make additional cash expenditures of pre-tax
disposal costs and property taxes of approximately $1.6 million.
Substantially all of such costs are expected to relate to disposal activities,
and a portion of the disposal costs is expected to be offset by proceeds from
sales of the Zinc Recovery Project’s assets. These costs are recognized in the
period in which the related liability is incurred. Salvage proceeds will be
recognized in the period earned. Implementation of a disposal plan began in
September 2004 and will continue in 2005. The Company also expects to receive
approximately $55 million in future tax benefits.





The
operating losses from discontinued operations before income taxes during the
years ended December 31, 2004, 2003 and 2002 were $42.7 million,
$46.4 million and $29.1 million, respectively.





**Credit
Ratings Risks**





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





In
conjunction with its wholesale marketing and trading activities, MidAmerican
Energy must meet credit quality standards as required by counterparties.
MidAmerican Energy has energy trading agreements that, in accordance with
industry practice, either specifically require it to maintain investment grade
credit ratings or provide the right for counterparties to demand “adequate
assurances” in the event of a material adverse change in MidAmerican Energy’s
creditworthiness. If one or more of MidAmerican Energy’s credit ratings decline
below investment grade, MidAmerican Energy may be required to post cash
collateral, letters of credit or other similar credit support to facilitate
ongoing wholesale marketing and trading activities. As of December 31,
2004, MidAmerican Energy’s estimated potential collateral requirements totaled
approximately $151.0 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, entered into
certain currency rate swap agreements for its Yankee Bonds with three large
multi-national financial institutions. The swap agreements effectively convert
the U.S. dollar fixed interest rate to a fixed rate in Sterling. For the
$281.1 million of the 6.496% Yankee Bonds outstanding at December 31,
2004, the agreements extend until February 25, 2008 and convert the U.S.
dollar interest rate to a fixed Sterling rate ranging from 7.3175% to 7.345%.
The estimated fair value of these swap agreements at December 31, 2004 was
$96.1 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 December 31, 2004, 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 approximately $44.8 million.




50







**Inflation**





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





**Obligations
and Commitments**





The
Company has contractual obligations and commercial commitments that may affect
its financial condition. Contractual obligations to make future payments arise
from parent company and subsidiary long-term debt and notes payable, preferred
equity securities, operating leases and power and fuel purchase contracts. Other
obligations arise from unused lines of credit and letters of credit. Material
obligations as of December 31, 2004 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
    
    $
    3,032.0
    
    $
    260.0
    
    $
    550.0
    
    $
    1,000.0
    
    $
    1,222.0Parent
      company subordinated debt
    
    
    1,774.4
    
    
    188.5
    
    
    468.0
    
    
    468.0
    
    
    649.9Subsidiary
      and project debt
    
    
    7,190.4
    
    
    885.6
    
    
    695.3
    
    
    844.3
    
    
    4,765.2Preferred
      securities of subsidiaries
    
    
    89.5
    
    
    -
    
    
    -
    
    
    -
    
    
    89.5Interest
      payments on long-term debt(1)
    
    
    7,588.5
    
    
    811.9
    
    
    1,417.8
    
    
    1,056.7
    
    
    4,302.1Coal,
      electricity and natural gas contract
      commitments
      (2)
    
    
    668.8
    
    
    173.0
    
    
    255.3
    
    
    122.2
    
    
    118.3Operating
      leases(2)
    
    
    375.0
    
    
    70.4
    
    
    121.0
    
    
    78.9
    
    
    104.7Deferred
      costs on construction contracts(3)
    
    
    152.3
    
    
    -
    
    
    152.3
    
    
    -
    
    
    -Total
      contractual cash obligations
    
    $
    20,870.9
    
    $
    2,389.4
    
    $
    3,659.7
    
    $
    3,570.1
    
    $
    11,251.7





**Commitment
      Expiration per Period****<**
    
    
    **2-3**
    
    
    **4-5**
    
    
    **>5****Total**
    
    
    
    
    
    **1
      Year**
    
    
    **Years**
    
    
    **Years**
    
    
    **Years**Other
      Commercial Commitments:Unused
      parent company revolving lines of credit
    
    $
    30.0
    
    $
    -
    
    $
    30.0
    
    $
    -
    
    $
    -Parent
      company letters of credit
    
    
    71.1
    
    
    71.1
    
    
    -
    
    
    -
    
    
    -Unused
      subsidiary lines of credit
    
    
    144.9
    
    
    144.9
    
    
    -
    
    
    -
    
    
    -Total
      other commercial commitments
    
    $
    246.0
    
    $
    216.0
    
    $
    30.0
    
    $
    -
    
    $
    -





**______________**





(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 Mitsui
      under its engineering, procurement and construction contract to build the
      CBEC Unit 4, which is expected to be complete in the summer of
      2007.





51





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.





·
    Construction
      expenditures (see Note 6)


·
    Asset
      retirement obligations (see Note 10)


·
    Debt service
      reserve guarantees (see Note 14)


·
    Nuclear
      decommissioning costs (see Note 21)


·
    Residual
      guarantees on operating leases (see Note
21)





**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, 2004, the Company’s investments which are accounted for under
the equity method had $861.3 million of debt and $40.2 million in
outstanding letters of credit. As of December 31, 2004, the Company’s
pro-rata share of such debt and outstanding letters of credit, which is all
non-recourse to MEHC, was $430.3 million and $20.1 million,
respectively.





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 2003, the FASB issued FIN 46R, which served to clarify guidance in FASB
Interpretation No. 46, “Consolidation of Variable Interest Entities, an
Interpretation of Accounting Research Bulletin No. 51” (“FIN 46”). The Company
adopted and applied the provisions of FIN 46R, related to certain finance
subsidiaries, as of October 1, 2003. The adoption required the
deconsolidation of certain finance subsidiaries, which resulted in the amounts
previously classified as mandatorily redeemable preferred securities of
subsidiary trusts, in the amount of $1.9 billion, being reclassified to parent
company subordinated debt in the accompanying consolidated balance sheets. In
addition, amounts previously recorded as minority interest and preferred
dividends of subsidiaries are now recorded as interest expense in the
accompanying consolidated statements of operations prospectively. For the year
ended December 31, 2004, and the three-month period ended December 31,
2003, the Company has recorded $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 amounts included in minority
interest and preferred dividends of subsidiaries related to these securities for
the nine-month period ended September 30, 2003, and the year ended
December 31, 2002, were $170.2 million and $147.7 million,
respectively. The Company adopted the provisions of FIN 46R related to
non-special purpose entities in the first quarter of 2004. The Company
considered the provisions of FIN 46R for all subsidiaries and their related
power purchase, power sale, or tolling agreements. Factors considered in the
analysis include the duration of the agreements, how capacity and energy
payments are determined, source and payment terms for fuel, as well as
responsibility and payment for operating and maintenance expenses. As a result
of these considerations, the Company has determined its power purchase, power
sale and tolling agreements do not represent significant variable interests.
Accordingly, the Company concluded that it is appropriate to continue to
consolidate the power plant projects with ownership interests greater than 50%
and not to consolidate the power plants from which it purchases
power.





In
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.




52





****


**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, 2004 included in this annual report describes the
significant accounting policies and methods used in the preparation of the
consolidated financial statements. Estimates are used for, but not limited to,
the accounting for the effects of certain types of regulation, impairment of
long-lived assets, contingent liabilities, accrued pension and post-retirement
expense and revenue. Actual results could differ from these estimates. The
following critical accounting policies are impacted significantly by judgments,
assumptions and estimates used in the preparation of the consolidated financial
statements.





*Accounting
for the Effects of Certain Types of Regulation*





MidAmerican
Energy, Kern River and Northern Natural Gas prepare their financial statements
in accordance with the provisions of 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, which will be amortized over various future
periods. To the extent that collection of such costs or payment of such
obligations is no longer probable as a result of changes in regulation, the
associated regulatory asset or liability is charged or credited to
income.





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





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





*Impairment
of Long-Lived Assets and Goodwill*





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





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





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.




53




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, 2004, primarily using a discounted cash flow
methodology. No impairment was indicated as a result of these
assessments.





*Contingent
Liabilities*





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.
Revisions to contingent liabilities 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 contingent liabilities and subsequent revisions are reflected in
income when accruals are recorded or as regulatory treatment dictates. Accruals
for contingent liabilities are based upon management’s assumptions and
estimates, and advice of legal counsel or other third parties regarding the
probable outcomes of the matter. Should the outcomes differ from the assumptions
and estimates, revisions to the estimated accruals for contingent liabilities
would be required.





*Accrued
Pension and Postretirement Expense*





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





*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 $1.5 billion at
December 31, 2004. 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
calculation of current and deferred income taxes requires management to apply
judgment relating to the application of complex tax laws or related
interpretations and uncertainties related to the outcome of tax audits. Changes
in such factors may result in changes to management’s estimates, which could
require the Company to adjust its currently recorded tax assets and liabilities
and record additional income tax expense or benefits.




54








*Revenue
Recognition*





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





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





Revenue
from the transportation and storage of gas is recognized based on contractual
terms and the related volumes. Kern River and Northern Natural Gas are subject
to the FERC’s regulations and, accordingly, certain revenue collected may be
subject to possible refunds upon final orders in pending rate proceedings. Kern
River and Northern Natural Gas record revenue which is subject to refund based
on their best estimate of the final outcome of these proceedings and other third
party regulatory proceedings, advice of counsel and estimated total exposure, as
well as collection and other risks. The estimate of the refund is recorded in
other current liabilities in the accompanying consolidated balance
sheets.





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





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





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





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





**Interest
Rate Risk**





At
December 31, 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 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 $396.0 million if interest rates were to increase by 10% from
their levels at December 31, 2004. 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, 2003, the Company had fixed-rate long-term debt of
$11,369.4 million in aggregate principal amount and having a fair value of
$12,015.1 million. These instruments 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, 2004, the Company had floating-rate obligations of
$493.4 million that expose the Company to the risk of increased interest
expense in the event of increases in short-term interest rates. These
obligations are not hedged. If the floating rates were to increase by 1%, the
Company’s consolidated interest expense for unhedged floating-rate obligations
would increase by approximately $0.4 million each month in which such
increase continued based upon December 31, 2004 principal
balances.





At
December 31, 2003, the Company had floating-rate obligations of
$459.8 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.




55





**Currency
Exchange Rate Risk**





CE
Electric UK entered into currency rate swap agreements for its Senior Notes 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 outstanding at December 31, 2004. The
agreements extend until maturity on December 30, 2007 and convert the U.S.
dollar interest rate to a fixed Sterling rate of 7.737%. The estimated fair
value of these swap agreements at December 31, 2004 and 2003 was
$35.7 million and $16.0 million, respectively, based on quotes from the
counterparty to these instruments and represents the estimated amount that the
Company would expect to pay if these agreements were terminated.





A
subsidiary of CE Electric UK entered into certain currency rate swap agreements
for its Yankee Bonds with three large multi-national financial institutions. The
swap agreements effectively convert the U.S. dollar fixed interest rate to a
fixed rate in Sterling for $281.1 million of 6.496% Yankee Bonds
outstanding at December 31, 2004. The agreements extend until maturity on
February 25, 2008 and convert the U.S. dollar interest rate to a fixed
Sterling rate ranging from 7.3175% to 7.345%. The estimated fair value of these
swap agreements at December 31, 2004 and 2003 was $96.1 million and
$62.6 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, 2004 would increase the amount owed by the Company if these
swap agreements were terminated by approximately
$69.9 million.





**Derivatives**





As of
December 31, 2004, MidAmerican Energy held derivative instruments used for
non-trading and trading purposes with the following fair values (in
thousands):





**Contract
      Type**
    
    **Maturity**
      **in
      2005**
    
    **Maturity**
      **in
      2006-08**
    
    **Total**Non-trading:Regulated
      electric assets
    
    $
    2,260
    
    $
    431
    
    $
    2,691Regulated
      electric (liabilities)
    
    
    (10,057
    )
    
    (4,817
    )
    
    (14,874
    )Regulated
      gas assets
    
    
    2,973
    
    
    1,798
    
    
    4,771Regulated
      gas (liabilities)
    
    
    (21,921
    )
    
    -
    
    
    (21,921
    )Regulated
      weather (liabilities)
    
    
    (4,495
    )
    
    -
    
    
    (4,495
    )Nonregulated
      electric assets
    
    
    1,957
    
    
    372
    
    
    2,329Nonregulated
      electric (liabilities)
    
    
    (1,158
    )
    
    (214
    )
    
    (1,372
    )Nonregulated
      gas assets
    
    
    5,937
    
    
    1,919
    
    
    7,856Nonregulated
      gas (liabilities)
    
    
    (6,606
    )
    
    (1,558
    )
    
    (8,164
    )Total
    
    
    (31,110
    )
    
    (2,069
    )
    
    (33,179
    )Trading:Nonregulated
      gas assets
    
    
    993
    
    
    -
    
    
    993Nonregulated
      gas (liabilities)
    
    
    (430
    )
    
    (100
    )
    
    (530
    )Total
    
    
    563
    
    
    (100
    )
    
    463Total
      MidAmerican Energy assets
    
    $
    14,120
    
    $
    4,520
    
    $
    18,640Total
      MidAmerican Energy (liabilities)
    
    $
    (44,667
    )
    $
    (6,689
    )
    $
    (51,356
    )







56










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





Report
      of****Independent
      Registered Public Accounting Firm
    58Consolidated Balance Sheets as of December 31, 2004 and
      2003
    59Consolidated
      Statements of****Operations
      for the Years Ended December 31, 2004, 2003 and 2002
    60Consolidated Statements of Stockholders’ Equity for
      the Years Ended December 31, 2004, 2003 and 2002
    61Consolidated
      Statements of Cash****Flows
      for the Years Ended December 31, 2004, 2003 and 2002
    62Notes to Consolidated Financial
    Statements
    63





57











**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, 2004
and 2003, and the related consolidated statements of operations, stockholders’
equity, and cash flows for each of the three years in the period ended
December 31, 2004. Our audits also included the consolidated financial
statement schedules listed in the Index at Item 15. These financial statements
and financial statement schedules are the responsibility of the Company’s
management. Our responsibility is to express an opinion on the financial
statements and financial statement schedules based on our audits.





We
conducted our audits in accordance with 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. An audit includes 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, 2004 and 2003, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2004, in conformity with accounting principles generally
accepted in the United States of America. Also, in our opinion, such
consolidated financial statement schedules, when considered in relation to the
basic consolidated financial statements taken as a whole, present fairly in all
material respects the information set forth therein.





As
discussed in Notes 2 and 10 to the consolidated financial statements, the
Company changed its accounting policy for asset retirement obligations and for
variable interest entities in 2003.





/s/  Deloitte
& Touche LLP





Des
Moines, Iowa


February
25, 2005





58










**MIDAMERICAN
ENERGY HOLDINGS COMPANY**


**CONSOLIDATED BALANCE SHEETS**


(Amounts
in thousands)


**As
      of December 31,****2004**
    
    **2003****ASSETS**Current
      assets:Cash
      and cash equivalents
    
    $
    960,903
    
    $
    660,213Restricted
      cash and short-term investments
    
    
    129,316
    
    
    55,281Accounts
      receivable, net of allowance for doubtful accounts of $26,033and$26,004
    
    
    695,761
    
    
    666,063Inventories
    
    
    125,079
    
    
    123,301Other
      current assets
    
    
    278,219
    
    
    348,618Total
      current assets
    
    
    2,189,278
    
    
    1,853,476Properties,
      plants and equipment, net
    
    
    11,607,264
    
    
    11,180,979Goodwill
    
    
    4,306,751
    
    
    4,305,643Regulatory
      assets
    
    
    451,830
    
    
    512,549Other
      investments
    
    
    236,258
    
    
    228,896Equity
      investments
    
    
    210,430
    
    
    234,370Deferred
      charges and other assets
    
    
    901,751
    
    
    829,039**Total
      assets**
    
    $
    19,903,562
    
    $
    19,144,952**LIABILITIES
      AND STOCKHOLDERS’ EQUITY**Current
      liabilities:Accounts
      payable
    
    $
    410,319
    
    $
    345,237Accrued
      interest
    
    
    197,813
    
    
    189,635Accrued
      property and other taxes
    
    
    166,639
    
    
    112,823Other
      liabilities
    
    
    532,160
    
    
    420,294Short-term
      debt
    
    
    9,090
    
    
    48,036Current
      portion of long-term debt
    
    
    1,145,598
    
    
    500,941Current
      portion of parent company subordinated debt
    
    
    188,543
    
    
    100,000Total
      current liabilities
    
    
    2,650,162
    
    
    1,716,966Other
      long-term accrued liabilities
    
    
    2,171,616
    
    
    1,961,695Parent
      company senior debt
    
    
    2,771,957
    
    
    2,777,878Parent
      company subordinated debt
    
    
    1,585,810
    
    
    1,772,146Subsidiary
      and project debt
    
    
    6,304,923
    
    
    6,674,640Deferred
      income taxes
    
    
    1,281,833
    
    
    1,299,082Total
      liabilities
    
    
    16,766,301
    
    
    16,202,407Deferred
      income
    
    
    62,443
    
    
    69,201Minority
      interest
    
    
    14,119
    
    
    9,754Preferred
      securities of subsidiaries
    
    
    89,540
    
    
    92,145Commitments
      and contingencies (Note 21)Stockholders’
      equity:Zero
      coupon convertible preferred stock — authorized 50,000 shares, no par
      value; 41,263 shares issued and outstanding
    
    
    -
    
    
    -Common
      stock — authorized 60,000 shares, no par value; 9,081 and 9,281 shares
      issued and outstanding at December 31, 2004 and 2003,
      respectively
    
    
    -
    
    
    -Additional
      paid-in capital
    
    
    1,950,663
    
    
    1,957,277Retained
      earnings
    
    
    1,156,843
    
    
    999,627Accumulated
      other comprehensive loss, net
    
    
    (136,347
    )
    
    (185,459
    )Total
      stockholders’ equity
    
    
    2,971,159
    
    
    2,771,445**Total
      liabilities and stockholders’ equity**
    
    $
    19,903,562
    
    $
    19,144,952





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




59


**MIDAMERICAN
ENERGY HOLDINGS COMPANY**


**CONSOLIDATED
STATEMENTS OF OPERATIONS**


(Amounts
in thousands)





**Year
      Ended December 31,****2004**
    
    **2003**
    
    **2002****Operating
      revenue**
    
    $
    6,553,388
    
    $
    5,965,630
    
    $
    4,795,179**Costs
      and expenses:**Cost
      of sales
    
    
    2,751,856
    
    
    2,400,536
    
    
    1,843,955Operating
      expense
    
    
    1,637,922
    
    
    1,512,345
    
    
    1,302,780Depreciation
      and amortization
    
    
    638,209
    
    
    602,934
    
    
    530,078Gain
      on CE Gas asset sale (Note 5)
    
    
    -
    
    
    -
    
    
    (54,345
    )Total
      costs and expenses
    
    
    5,027,987
    
    
    4,515,815
    
    
    3,622,468**Operating
      income**
    
    
    1,525,401
    
    
    1,449,815
    
    
    1,172,711**Other
      income (expense):**Interest
      expense
    
    
    (903,217
    )
    
    (760,956
    )
    
    (632,133
    )Capitalized
      interest
    
    
    20,040
    
    
    30,494
    
    
    23,361Interest
      and dividend income
    
    
    38,889
    
    
    47,908
    
    
    56,037Other
      income
    
    
    128,205
    
    
    96,643
    
    
    40,223Other
      expense
    
    
    (10,125
    )
    
    (5,913
    )
    
    (28,561
    )Total
      other income (expense)
    
    
    (726,208
    )
    
    (591,824
    )
    
    (541,073
    )**Income
      from continuing operations before income tax expense, minority interest
      and preferred dividends of subsidiaries and equity
      income**
    
    
    799,193
    
    
    857,991
    
    
    631,638Income
      tax expense
    
    
    264,986
    
    
    270,276
    
    
    111,278Minority
      interest and preferred dividends of subsidiaries
    
    
    13,301
    
    
    183,203
    
    
    163,468**Income
      from continuing operations before equity income**
    
    
    520,906
    
    
    404,512
    
    
    356,892Equity
      income
    
    
    16,861
    
    
    38,224
    
    
    40,520**Income
      from continuing operations**
    
    
    537,767
    
    
    442,736
    
    
    397,412Loss
      from discontinued operations, net of tax benefits (Note 3)
    
    
    (367,561
    )
    
    (27,118
    )
    
    (17,369
    )**Net
      income available to common and preferred
    stockholders**
    
    $
    170,206
    
    $
    415,618
    
    $
    380,043





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




60


**MIDAMERICAN
ENERGY HOLDINGS COMPANY**


**CONSOLIDATED
STATEMENTS OF STOCKHOLDERS’ EQUITY**


**FOR
THE THREE YEARS ENDED DECEMBER 31, 2004**


(Amounts
in thousands)





**Accumulated****Outstanding**
    
    
    
    **Additional**
    
    
    
    **Other****Common**
    
    **Common**
    
    **Paid-in**
    
    **Retained**
    
    **Comprehensive****Shares**
    
    **Stock**
    
    **Capital**
    
    **Earnings**
    
    **Loss**
    
    **Total****Balance,
      January 1, 2002**
    
    
    9,281
    
    $
    -
    
    $
    1,553,073
    
    $
    223,926
    
    $
    (68,832
    )
    $
    1,708,167Net
      income
    
    
    -
    
    
    -
    
    
    -
    
    
    380,043
    
    
    **-**
    
    
    380,043Other
      comprehensive income:Foreign
      currency translationadjustment
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    166,880
    
    
    166,880Fair
      value adjustment on cash flow  hedges, net of tax of
      $(10,106)
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    (27,623
    )
    
    (27,623
    )Minimum
      pension liability adjustment, net of tax of $(135,707)
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    (313,456
    )
    
    (313,456
    )Unrealized
      losses on securities, net  of tax of $(1,813)
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    (3,204
    )
    
    (3,204
    )Total
      comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    202,640Issuance
      of zero-coupon convertible preferred stock
    
    
    -
    
    
    -
    
    
    402,000
    
    
    -
    
    
    -
    
    
    402,000Retirement
      of stock options
    
    
    -
    
    
    -
    
    
    815
    
    
    (19,960
    )
    
    -
    
    
    (19,145
    )Other
      equity transactions
    
    
    -
    
    
    -
    
    
    621
    
    
    -
    
    
    -
    
    
    621**Balance,
      December 31, 2002**
    
    
    9,281
    
    
    -
    
    
    1,956,509
    
    
    584,009
    
    
    (246,235
    )
    
    2,294,283Net
      income
    
    
    -
    
    
    -
    
    
    -
    
    
    415,618
    
    
    -
    
    
    415,618Other
      comprehensive income:Foreign
      currency translationadjustment
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    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 translationadjustment
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    107,370
    
    
    107,370Fair
      value adjustment on cash flowhedges,
      net of tax of $(6,069)
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    (12,270
    )
    
    (12,270
    )Minimum
      pension liabilityadjustment,
      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
    )
    $
    2,971,159


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




61







**MIDAMERICAN
ENERGY HOLDINGS COMPANY**


**CONSOLIDATED
STATEMENTS OF CASH FLOWS**


(Amounts
in thousands)





**Year
      Ended December 31,****2004**
    
    
    **2003**
    
    
    **2002****Cash
      flows from operating activities:**Income
      from continuing operations
    
    $
    537,767
    
    $
    442,736
    
    $
    397,412Adjustments
      to reconcile income from continuing operations to cash flows from
      continuing operations:Distributions
      less income on equity investments
    
    
    20,022
    
    
    40,160
    
    
    (11,383
    )Gain
      on other items
    
    
    (71,757
    )
    
    (29,264
    )
    
    (47,086
    )Depreciation
      and amortization
    
    
    638,209
    
    
    602,934
    
    
    530,078Amortization
      of regulatory assets and liabilities
    
    
    (1,586
    )
    
    (14,363
    )
    
    8,709Amortization
      of deferred financing costs
    
    
    20,875
    
    
    27,748
    
    
    28,433Provision
      for deferred income taxes
    
    
    176,591
    
    
    220,136
    
    
    (18,020
    )Other
    
    
    16,981
    
    
    8,211
    
    
    8,356Changes
      in other items:Accounts
      receivable and other current assets
    
    
    (43,600
    )
    
    (25,900
    )
    
    (200,760
    )Accounts
      payable and other accrued liabilities
    
    
    171,457
    
    
    (17,835
    )
    
    78,813Deferred
      income
    
    
    (6,465
    )
    
    (9,344
    )
    
    (4,839
    )Net
      cash flows from continuing operations
    
    
    1,458,494
    
    
    1,245,219
    
    
    769,713Net
      cash flows from discontinued operations
    
    
    (33,846
    )
    
    (27,296
    )
    
    (11,987
    )Net
      cash flows from operating activities
    
    
    1,424,648
    
    
    1,217,923
    
    
    757,726**Cash
      flows from investing activities:**Capital
      expenditures relating to operating projects
    
    
    (778,300
    )
    
    (616,804
    )
    
    (528,950
    )Construction
      and other development costs
    
    
    (401,090
    )
    
    (602,564
    )
    
    (813,348
    )Proceeds
      from notes receivable
    
    
    169,210
    
    
    -
    
    
    -Acquisitions,
      net of cash acquired
    
    
    (36,706
    )
    
    (54,263
    )
    
    (1,416,937
    )Proceeds
      from (purchase of) affiliate notes, net
    
    
    14,118
    
    
    (32,406
    )
    
    -Sale
      (purchase) of convertible preferred securities
    
    
    -
    
    
    288,750
    
    
    (275,000
    )Other
    
    
    2,148
    
    
    25,786
    
    
    189,984Net
      cash flows from continuing operations
    
    
    (1,030,620
    )
    
    (991,501
    )
    
    (2,844,251
    )Net
      cash flows from discontinued operations
    
    
    966
    
    
    (11,666
    )
    
    (63,560
    )Net
      cash flows from investing activities
    
    
    (1,029,654
    )
    
    (1,003,167
    )
    
    (2,907,811
    )**Cash
      flows from financing activities:**Proceeds
      from subsidiary and project debt
    
    
    375,351
    
    
    1,157,649
    
    
    1,485,349Proceeds
      from parent company senior debt
    
    
    249,765
    
    
    449,295
    
    
    700,000Repayments
      of subsidiary and project debt
    
    
    (368,417
    )
    
    (1,490,986
    )
    
    (393,264
    )Repayments
      of parent company senior and subordinated debt
    
    
    (100,000
    )
    
    (412,551
    )
    
    -Net
      repayment of subsidiary short-term debt
    
    
    (43,949
    )
    
    (31,750
    )
    
    (472,835
    )Purchase
      and retirement of common stock
    
    
    (20,000
    )
    
    -
    
    
    -Proceeds
      from issuance of trust preferred securities
    
    
    -
    
    
    -
    
    
    1,273,000Proceeds
      from issuance of preferred stock
    
    
    -
    
    
    -
    
    
    402,000Net
      repayment of parent company revolving credit facility
    
    
    -
    
    
    -
    
    
    (153,500
    )Repayment
      of other obligations
    
    
    -
    
    
    -
    
    
    (94,297
    )Increase
      in restricted cash and investments
    
    
    (48,515
    )
    
    (4,024
    )
    
    (41,524
    )Redemption
      of preferred securities of subsidiaries
    
    
    (2,606
    )
    
    (1,176
    )
    
    (127,908
    )Other
    
    
    (27,167
    )
    
    (91,387
    )
    
    (40,962
    )Net
      cash flows from continuing operations
    
    
    14,462
    
    
    (424,930
    )
    
    2,536,059Net
      cash flows from discontinued operations
    
    
    (137,297
    )
    
    (1,407
    )
    
    19,175Net
      cash flows from financing activities
    
    
    (122,835
    )
    
    (426,337
    )
    
    2,555,234Effect
      of exchange rate changes
    
    
    28,531
    
    
    27,364
    
    
    52,536**Net
      change in cash and cash equivalents**
    
    
    300,690
    
    
    (184,217
    )
    
    457,685**Cash
      and cash equivalents at beginning of period**
    
    
    660,213
    
    
    844,430
    
    
    386,745**Cash
      and cash equivalents at end of period**
    
    $
    960,903
    
    $
    660,213
    
    $
    844,430


The
accompanying notes are an integral part of these financial
statements.
 
 62





**MIDAMERICAN
ENERGY HOLDINGS COMPANY**


**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**





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





MidAmerican
Energy Holdings Company (“MEHC”) and its subsidiaries (together with MEHC, the
“Company”) are organized and managed on seven distinct platforms: MidAmerican
Energy Company (“MidAmerican Energy”), Kern River Gas Transmission Company
(“Kern River”), Northern Natural Gas Company (“Northern Natural Gas”), CE
Electric UK Funding (“CE Electric UK”) (which includes Northern Electric
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 and related operations) and HomeServices of America, Inc. (collectively
with its subsidiaries, “HomeServices”). Through these platforms, the Company
owns and operates a combined electric and natural gas utility company in the
United States, two natural gas pipeline companies in the United States, two
electricity distribution companies in the United Kingdom, a diversified
portfolio of domestic and international independent power projects and the
second largest residential real estate brokerage firm in the United
States.





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





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





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





**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. Under Financial Accounting Standards Board (“FASB”)
Interpretation No. 46R, “Consolidation of Variable Interest Entities” (“FIN
46R”) these trusts, by design, are considered variable interest entities, with
no variable interest holder being considered the primary beneficiary, thus
requiring the reporting entity to deconsolidate the trust. 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.





63





*Reclassifications*





Certain
amounts in the fiscal 2003 and 2002 consolidated financial statements and
supporting note disclosures have been reclassified to conform to the fiscal 2004
presentation, including the reclassification of activity as discontinued
operations (see Note 3). Such reclassification did not impact previously
reported net income or retained earnings.





*Use
of Estimates*





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





*Accounting
for the Effects of Certain Types of Regulation*





MidAmerican
Energy, Kern River and Northern Natural Gas prepare their financial statements
in accordance with the provisions of Statement of Financial Accounting Standards
(“SFAS”) No. 71, “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, which will be amortized over various future
periods. To the extent that collection of such costs or payment of such
obligations is no longer probable as a result of changes in regulation, the
associated regulatory asset or liability is charged or credited to
income.





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





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





*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,****2004**
    
    **2003**
    
    **2002**Interest
      paid, net of interest capitalized
    
    $
    867,181
    
    $
    706,039
    
    $
    588,972Income
      taxes (refunded) paid
    
    $
    (16,616
    )
    $
    9,911
    
    $
    101,225Non-cash
      transaction - ROP note received under NIA Arbitration
      Settlement
    
    $
    -
    
    $
    97,000
    
    $
    -





Cash paid
for interest for the years ended December 31, 2003 and 2002 does not
include $170,151 and $147,667, respectively, of interest paid on subordinated
debt, which is included in minority interest and preferred dividends of
subsidiaries in the consolidated statements of operations. These amounts were
not reclassified pursuant to the FIN 46R.





64





*Restricted
Cash and Investments*





The
restricted cash and short-term investments balance recorded separately in
restricted cash and short-term investments and in deferred charges and other
assets, was $164.5 million and $119.5 million at December 31,
2004 and 2003, respectively, and includes commercial paper and money market
securities. The balance is mainly composed of amounts deposited in restricted
accounts from which the Company will source its debt service reserve
requirements relating to the projects, customer deposits held in escrow, custody
deposits, and unpaid dividends declared obligations. The debt service funds are
restricted by their respective project debt agreements to be used only for the
related project.





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





*Allowance
for Doubtful Accounts*





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





*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.





*Fair
Value of Financial Instruments*





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





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





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





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





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





*Properties,
Plants and Equipment, Net*





Properties,
plants and equipment are recorded at historical cost. The cost of major
additions and betterments are capitalized, while replacements, maintenance, and
repairs that do not improve or extend the lives of the respective assets are
expensed. Depreciation is computed using the straight-line method based on
economic lives or regulatorily mandated recovery periods. The Company believes
the useful lives assigned to the depreciable assets, which generally range from
3 to 87 years, are reasonable.





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





65








*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 would be recognized to write down the asset to its fair value that is based
on discounted estimated cash flows from the future use of the
asset.





*Goodwill*





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, 2004 primarily using a discounted cash flow
methodology. No impairment was indicated as a result of these
assessments.





*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 subsidiaries that apply SFAS 71. Interest and
AFUDC for subsidiaries that apply SFAS 71 are capitalized as a component of
projects under construction and will be amortized over the assets’ estimated
useful lives.





*Deferred
Financing Cost*





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





*Contingent
Liabilities*





The
Company establishes 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.





*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 $1.5 billion at
December 31, 2004. 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.





66





The
calculation of current and deferred income taxes requires management to apply
judgment relating to the application of complex tax laws or related
interpretations and uncertainties related to the outcome of tax audits. Changes
in such factors may result in changes to management’s estimates, which could
require the Company to adjust its currently recorded tax assets and liabilities
and record additional income tax expense or benefits.





*Revenue
Recognition*





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





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





Revenue
from the transportation and storage of gas are recognized based on contractual
terms and the related volumes. Kern River and Northern Natural Gas are subject
to the Federal Energy Regulatory Commission’s (“FERC”) regulations and,
accordingly, certain revenue collected may be subject to possible refunds upon
final orders in pending rate proceedings. Kern River and Northern Natural Gas
record revenue which is subject to refund based on their best estimate of the
final outcome of these proceedings and other third party regulatory proceedings,
advice of counsel and estimated total exposure, as well as collection and other
risks. The estimate of the refund is recorded in other current liabilities in
the accompanying consolidated balance sheets.





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





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





*Financial
Instruments*





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





67


*New
Accounting Pronouncements*





In
December 2003, the FASB issued FIN 46R, which served to clarify guidance in FASB
Interpretation No. 46, “Consolidation of Variable Interest Entities, an
Interpretation of Accounting Research Bulletin No. 51.” The Company adopted and
applied the provisions of FIN 46R, related to certain finance subsidiaries, as
of October 1, 2003. The adoption required the deconsolidation of certain
finance subsidiaries, which resulted in the amounts previously classified as
mandatorily redeemable preferred securities of subsidiary trusts, in the amount
of $1.9 billion, being reclassified to parent company subordinated debt in the
accompanying consolidated balance sheets. In addition, amounts previously
recorded as minority interest and preferred dividends of subsidiaries are now
recorded as interest expense in the accompanying consolidated statements of
operations, prospectively. For the year ended December 31, 2004, and the
three-month period ended December 31, 2003, the Company has recorded
$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 amounts included in minority interest and preferred dividends
of subsidiaries related to these securities for the nine-month period ended
September 30, 2003, and the year ended December 31, 2002, were
$170.2 million and $147.7 million, respectively. The Company adopted
the provisions of FIN 46R related to non-special purpose entities in the first
quarter of 2004. The Company considered the provisions of FIN 46R for all
subsidiaries and their related power purchase, power sale, or tolling
agreements. Factors considered in the analysis include the duration of the
agreements, how capacity and energy payments are determined, source and payment
terms for fuel, as well as responsibility and payment for operating and
maintenance expenses. As a result of these considerations, the Company has
determined its power purchase, power sale and tolling agreements do not
represent significant variable interests. Accordingly, the Company concluded
that it is appropriate to continue to consolidate the power plant projects with
ownership interests greater than 50% and not to consolidate the power plants
from which it purchases power.




In
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.





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





On
September 10, 2004, management made the decision to cease operations of the Zinc
Recovery Project. Based on this decision, a non-cash, after-tax impairment
charge of $340.3 million has been 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):





**Year
      Ended December 31.****2004**
    
    **2003**
    
    **2002**Total
      revenue
    
    $
    3,401
    
    $
    659
    
    $
    288Losses
      from discontinued operations
    
    $
    (42,695
    )
    $
    (46,423
    )
    $
    (29,059
    )Costs
      of disposal activities, net
    
    
    (4,134
    )
    
    -
    
    
    -Asset
      impairment charges, including goodwill
    
    
    (532,009
    )
    
    -
    
    
    -Income
      tax benefits
    
    
    211,277
    
    
    19,305
    
    
    11,690Loss
      from discontinued operations, net of tax
    
    $
    (367,561
    )
    $
    (27,118
    )
    $
    (17,369
    )





68





In
connection with ceasing operations, the Zinc Recovery Project’s assets are being
dismantled and sold and certain employees of the operator of the Zinc Recovery
Project were paid one-time termination benefits. 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. The Company expects to make additional cash expenditures of pre-tax
disposal costs and property taxes of approximately $1.6 million.
Substantially all of such costs are expected to relate to disposal activities,
and a portion of the disposal costs is expected to be offset by proceeds from
sales of the Zinc Recovery Project’s assets. These costs are recognized in the
period in which the related liability is incurred. Salvage proceeds will be
recognized in the period earned. Implementation of a disposal plan began in
September 2004 and will continue in 2005. The Company also expects to receive
approximately $55 million in future tax benefits.





**4.**  **Acquisitions**





*HomeServices*





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. These purchases were financed using HomeServices’
cash balances.





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. Additionally in 2004, HomeServices paid an
earnout of $6.0 million based on 2004 financial performance measures. These
purchases were financed using HomeServices’ cash balances and revolving credit
facility.





In 2002,
HomeServices separately acquired three real estate companies for an aggregate
purchase price of $106.1 million, net of cash acquired, plus working
capital and certain other adjustments. Additionally in 2003, HomeServices paid
an earnout of $17.6 million based on 2002 financial performance measures.
These purchases were financed using HomeServices’ cash balances, revolving
credit facility and $40.0 million from MEHC, which was contributed to
HomeServices as equity.





*Kern
River*





On
March 27, 2002, the Company acquired Kern River from The Williams
Companies, Inc. (“Williams”). At the date of acquisition, Kern River owned a
926-mile interstate pipeline transporting Rocky Mountain and Canadian natural
gas to markets in California, Nevada and Utah.





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





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





·  Opportunities
for expansion;


·  Generally
high credit quality shippers contracting with Kern River;


·  Kern
River’s strong competitive position;


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


·  Strong
demand for gas in the Western markets; and


·  An ample
supply of low-cost gas.





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





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




69





**


*Northern
Natural Gas*





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





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





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





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


·  Northern
Natural Gas’ strong competitive position;


·  Strategic
location in the high demand Upper Midwest markets;


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


·  Exceptional
operating track record; and


·  Opportunities
for expansion.





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





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





The
following pro forma financial information of the Company represents the
unaudited pro forma results of operations as if the Kern River and Northern
Natural Gas acquisitions, and the related financings, had occurred at the
beginning of 2002. These pro forma results have been prepared for comparative
purposes only and do not profess to be indicative of the results of operations
which would have been achieved had these transactions been completed at the
beginning of the year, nor are the results indicative of the Company’s future
results of operations (in millions):





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





**5.**  **Dispositions
and Other Items**





*CE
Gas Asset Sale*





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





70





*Teesside
Power Limited (“TPL”)*





The
Company has a 15.4% interest in TPL, which owns and operates a 1,875 MW combined
cycle gas-fired power plant. Enron Corp. (“Enron”), which through its
subsidiaries has a 42.5% interest, previously operated TPL. TPL is now in
administration and administrators have been appointed to run its business and
are attempting to find a buyer. The Company wrote-off its investment in TPL
during 2001. Shareholders in TPL had previously utilized TPL’s taxable losses
with an obligation to reimburse TPL later in the project’s life. In May 2002,
TPL executed a restructuring and stabilization agreement with its lenders. The
contract included an agreement between TPL and its shareholders with respect to
the waiver of these repayment obligations. In May 2002, TPL released
$35.7 million due to the repayment obligation being waived which is
reflected as a tax benefit in income tax expense in 2002.





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





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





**Depreciation****Life**
    
    **2004**
    
    **2003**Utility
      generation and distribution system
    
    
    10-50
      years
    
    $
    10,149,818
    
    $
    8,987,158Interstate
      pipelines’ assets
    
    
    3-87
      years
    
    
    3,566,578
    
    
    3,470,117Independent
      power plants
    
    
    10-30
      years
    
    
    1,384,660
    
    
    1,395,782Mineral
      and gas reserves and exploration assets
    
    
    5-30
      years
    
    
    101,472
    
    
    554,780Utility
      non-operational assets
    
    
    3-30
      years
    
    
    465,297
    
    
    429,228Other
      assets
    
    
    3-10
      years
    
    
    167,150
    
    
    146,286Total
      operating assets
    
    
    
    
    
    15,834,975
    
    
    14,983,351Accumulated
      depreciation and amortization
    
    
    
    
    
    (4,800,372
    )
    
    (4,260,643
    )Net
      operating assets
    
    
    
    
    
    11,034,603
    
    
    10,722,708Construction
      in progress
    
    
    
    
    
    572,661
    
    
    458,271Properties,
      plants and equipment, net
    
    
    
    
    $
    11,607,264
    
    $
    11,180,979





**7.**  **Investment
in CE Generation**





The
Company holds a 50% interest in CE Generation, LLC (“CE Generation”) and
accounts for this interest as an equity investment. The equity investment in CE
Generation at December 31, 2004 and 2003 was $188.7 million and
$209.4 million, respectively. The following is summarized financial
information for CE Generation as of and for the years ended December 31 (in
thousands):





**2004**
    
    
    **2003**
    
    
    **2002**Revenue
    
    $
    444,228
    
    $
    487,422
    
    $
    510,082Income
      (loss) before cumulative effect of change inaccounting
      principle
    
    
    (3,084
    )
    
    37,341
    
    
    58,314Net
      income (loss)
    
    
    (3,084
    )
    
    34,874
    
    
    58,314Current
      assets
    
    
    124,734
    
    
    260,551Total
      assets
    
    
    1,447,388
    
    
    1,708,742Current
      liabilities
    
    
    115,153
    
    
    253,237Long-term
      debt, including current portion
    
    
    722,650
    
    
    924,565





As part
of its annual impairment test, CE Generation determined on December 9, 2004 that
a portion of the carrying value of the Power Resources project’s long-lived
assets were 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 No. 144, “Accounting for the Impairment of Long-Lived
Assets,” 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 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.




71





****


**8.**  **Other
Income and Expense**





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





**2004**
    
    **2003**
    
    **2002**Gain
      on Enron note receivable
    
    $
    72,210
    
    $
    -
    
    $
    -Gain
      on CE Casecnan settlement
    
    
    -
    
    
    31,889
    
    
    -Allowance
      for equity funds used during construction
    
    
    20,476
    
    
    26,708
    
    
    19,366Gain
      on Mirant bankruptcy claim
    
    
    14,750
    
    
    -
    
    
    -Gain
      on Williams preferred stock
    
    
    -
    
    
    13,750
    
    
    2,750Corporate-owned
      life insurance income
    
    
    5,447
    
    
    6,317
    
    
    1,330Gain
      on sale of other assets and investments
    
    
    3,609
    
    
    4,183
    
    
    7,519Other
    
    
    11,713
    
    
    13,796
    
    
    9,258Total
      other income
    
    $
    128,205
    
    $
    96,643
    
    $
    40,223





Other
expense for the years ending December 31, 2004, 2003 and 2002 was
$10.1 million, $5.9 million and $28.6 million, respectively.
In 2002, MidAmerican Energy recorded an impairment of its investment in
airplane leases and other non-regulated investments of
$21.7 million.





*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.





*CE
Casecnan Water and Energy Company (“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”) National Irrigation Administration (“NIA”).
As a result of the agreement, CE Casecnan recorded $31.9 million of other
income and $24.4 million of associated income taxes. In connection with the
settlement, the NIA delivered to CE Casecnan a ROP $97.0 million 8.375%
Note due 2013 (the “ROP Note”), which contained a put provision granting CE
Casecnan the right to put the ROP Note to the ROP for a price of par plus
accrued interest for a 30-day period commencing on January 14, 2004. The
ROP Note is included in other current assets in the accompanying consolidated
balance sheet at December 31, 2003.





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.





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





In July
2003, Mirant filed Chapter 11 bankruptcy. On January 13, 2004, Kern River filed
a proof of claim with the bankruptcy court for an aggregate total of
$210.2 million, which Kern River believed was secured by the
$14.8 million in proceeds received from its letter of credit and held as a
cash security deposit. In May 2004, the bankruptcy court issued an order
permitting Kern River to apply 100% of the $14.8 million it held in cash
collateral to its claim for damages. On October 12, 2004, Mirant raised an
objection to Kern River’s claim asserting, among other things, that Kern River
had not included a discount adjustment or mitigation to the claim. On November
11, 2004, Kern River filed an amended proof of claim of $138.8 million,
reflecting discounting, mitigation and other adjustments. The amended proof of
claim excludes the $14.8 million already received by Kern River. Kern River
can not determine at this time if it will collect any portion of the balance of
the claim or be able to remarket the rejected capacity.




72





*William* s *Preferred Stock*





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





**9.**  **Regulatory
Assets and Liabilities**





The
principal components of the Company’s regulatory assets and liabilities were as
follows as of December 31 (in thousands):





**As
      of December 31,****Weighted
      Average****Remaining
      Life**
    
    
    **2004**
    
    
    **2003**Regulatory
      assets:Deferred
      income taxes, net
    
    
    24
      years
    
    $
    160,662
    
    $
    138,192Computer
      systems development costs
    
    
    7
      years
    
    
    63,637
    
    
    72,787System
      levelized account
    
    
    25
      years
    
    
    53,576
    
    
    54,109Minimum
      pension liability adjustment
    
    
    N/A
    
    
    41,136
    
    
    36,795Unrealized
      loss on regulated hedges
    
    
    1
      year
    
    
    36,794
    
    
    14,248Pipe
      recoating and reconditioning costs
    
    
    87
      years
    
    
    22,406
    
    
    22,315Asset
      retirement obligations
    
    
    9
      years
    
    
    20,875
    
    
    90,556Debt
      refinancing costs
    
    
    7
      years
    
    
    15,365
    
    
    19,698Environmental
      costs
    
    
    3
      years
    
    
    9,284
    
    
    13,995Nuclear
      generation assets
    
    
    28
      years
    
    
    6,727
    
    
    7,522Cooper
      Nuclear Station capital improvement costs
    
    
    -
    
    
    -
    
    
    7,314Other
    
    
    Various
    
    
    21,368
    
    
    35,018Total
    
    
    
    
    $
    451,830
    
    $
    512,549Regulatory
      liabilities:Cost
      of removal accrual
    
    
    24
      years
    
    $
    428,719
    
    $
    408,608Iowa
      electric settlement accrual
    
    
    3
      years
    
    
    181,188
    
    
    144,418Asset
      retirement obligations
    
    
    49
      years
    
    
    53,259
    
    
    -Unrealized
      gain on regulated hedges
    
    
    2
      years
    
    
    7,462
    
    
    15,122Environmental
      insurance recovery
    
    
    3
      years
    
    
    3,599
    
    
    3,781Nuclear
      insurance reserve
    
    
    49
      years
    
    
    3,262
    
    
    2,561Other
    
    
    Various
    
    
    5,278
    
    
    10,250Total
    
    
    
    
    $
    682,767
    
    $
    584,740





Of the
regulatory assets listed above, only the nuclear generation assets at
MidAmerican Energy and the computer systems development costs, the system
levelized account, and the pipe recoating and reconditioning costs at Northern
Natural Gas are included in rate base and earn a return.





The
decrease in the asset retirement obligation regulatory asset and the
establishment of a related regulatory liability is the result of a 20-year
extension to the operating license of Quad Cities Generating Station and its
impact on the timing of related cash flows. Regulatory liabilities are included
in other long-term accrued liabilities in the accompanying consolidated balance
sheets.





73





**10.**  **Asset
Retirement Obligations**





On
January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset
Retirement Obligations” and recognized a liability for legal retirement
obligations for nuclear decommissioning, wet and dry ash landfills and offshore
and minor lateral pipeline facilities. Concurrent with the recognition of the
liability, the estimated cost of the asset retirement obligation (“ARO”) was
capitalized and is being depreciated over the remaining life of the asset. The
difference between the ARO liability, the ARO net asset and amounts recovered
from regulated customers to satisfy such liabilities is recorded as a regulatory
asset or liability.





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):





**2004**
    
    **2003**Balance,
      January 1
    
    $
    284,007
    
    $
    289,323Revision
      to nuclear decommissioning ARO liability
    
    
    (120,098
    )
    
    (21,902
    )Addition
      for new wind power facilities
    
    
    2,777
    
    
    -Accretion
    
    
    15,877
    
    
    16,586Balance,
      December 31
    
    $
    182,563
    
    $
    284,007





At
December 31, 2004, $154.2 million of the ARO liability pertained to
the decommissioning of Quad Cities Station. Also, at December 31, 2004,
$207.5 million of assets reflected in other investments in the accompanying
consolidated balance sheet are restricted for satisfying the Quad Cities Station
ARO liability.





The 2004
revision is 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
Nuclear Regulatory Commission (“NRC”) in October 2004 and its impact on the
timing of related cash flows. The 2003 revision to the nuclear decommissioning
ARO liability was due to the results of a decommissioning study performed by the
plant operator.





In
addition to the ARO liabilities, MidAmerican Energy has accrued for the cost of
removing other electric and gas assets through its depreciation rates, in
accordance with accepted regulatory practices. These accruals are reflected in
other long-term accrued liabilities in the accompanying consolidated balance
sheets and total $428.7 million and $408.6 million at
December 31, 2004 and 2003, respectively.





**11.**  **Short-Term
Debt**





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





**2004**
    
    
    **2003**MidAmerican
      Energy commercial paper
    
    $
    -
    
    $
    48,000HomeServices
      revolving credit facilities
    
    
    9,052
    
    
    -Other
    
    
    38
    
    
    36Total
      short-term debt
    
    $
    9,090
    
    $
    48,036





*Parent
Company Revolving Credit Facilities*





In the
second quarter of 2003, the Company terminated its $400.0 million credit
facility. On June 6, 2003, the Company closed on a new $100.0 million
revolving credit facility which expires on June 6, 2006. The facility
supports letters of credit of which $70.0 million were outstanding at
December 31, 2004. No borrowings were outstanding at December 31, 2004
or 2003. The facility, which was not drawn on during 2004, carries a variable
interest rate based on LIBOR and ranged from 2.02% to 2.255% in
2003.





74





*MidAmerican
Energy Short-Term Debt*





As of
December 31, 2004, MidAmerican Energy has in place a $425.0 million
revolving credit facility, which expires on November 18, 2009, and supports
its $304.6 million commercial paper program and its variable rate pollution
control revenue obligations, all of which was available at December 31,
2004. In addition, MidAmerican Energy has a $5.0 million line of credit
which expires on July 1, 2005. There was no commercial paper outstanding at
December 31, 2004, and commercial paper totaled $48.0 million at
December 31, 2003. MHC Inc., an indirect wholly-owned subsidiary of the
Company, has a $4.0 million line of credit, expiring July 1, 2005,
under which no borrowings were outstanding at December 31, 2004 or 2003.
The commercial paper, bank notes and outstanding line of credit had a weighted
average interest rate of 0.98% at December 31, 2003.





*HomeServices
Revolving Credit Facilities*





HomeServices
maintains a $125.0 million senior secured revolving credit facility, which
expires in November 2005. Amounts outstanding under this revolving credit
facility are secured by a pledge of the capital stock of all of the existing and
future subsidiaries of HomeServices and bear interest, at HomeServices’ option,
at either the prime lending rate or LIBOR plus a fixed spread of 1.25% to 2.25%,
which varies based on HomeServices’ cash flow leverage ratio. The spread was
1.25% at December 31, 2004 and 2003. No borrowings were outstanding at
December 31, 2004 or 2003. In addition, HomeServices has in place two
mortgage warehouse lines of credit totaling $20.0 million, which expire on
March 31, 2005 and October 31, 2005, and bear interest at LIBOR plus
1.75% and LIBOR plus 2.25%, respectively. The balances outstanding on these
mortgage warehouse lines of credit at December 31, 2004, totaled
$9.1 million. There were no borrowings outstanding at December 31,
2003. The mortgage warehouse lines of credit had weighted average interest rates
of 4.54% and 4.21%, respectively, at December 31, 2004.





**12.** **Parent
Company Senior Debt**





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





**2004**
    
    
    **2003**7.23%
      Senior Notes, due 2005
    
    $
    260,000
    
    $
    260,0004.625%
      Senior Notes, due 2007
    
    
    199,403
    
    
    199,2257.63%
      Senior Notes, due 2007
    
    
    350,000
    
    
    350,0003.50%
      Senior Notes, due 2008
    
    
    449,497
    
    
    449,3737.52%
      Senior Notes, due 2008
    
    
    450,000
    
    
    450,0007.52%
      Senior Notes, due 2008 (Series B)
    
    
    101,037
    
    
    101,2675.875%
      Senior Notes, due 2012
    
    
    499,906
    
    
    499,8985.00%
      Senior Notes, due 2014
    
    
    249,797
    
    
    -8.48%
      Senior Notes, due 2028
    
    
    475,000
    
    
    475,000Fair
      value adjustments and other
    
    
    (2,683
    )
    
    (6,885
    )Total
      Parent Company Senior Debt
    
    
    3,031,957
    
    
    2,777,878Less
      current portion
    
    
    (260,000
    )
    
    -Total
      Long-Term Parent Company Senior Debt
    
    $
    2,771,957
    
    $
    2,777,878





On
February 12, 2004, MEHC issued $250.0 million, net of discount, of its
5.00% Senior Notes with a final maturity on February 15, 2014. The proceeds
were used to satisfy a demand made by its affiliate, Salton Sea Funding
Corporation (“Funding Corporation”), for $136.4 million, the amount
remaining on MEHC’s guarantee of Funding Corporation’s 7.475% Senior Secured
Series F Bonds due November 30, 2018 (“Series F Bonds”), and for other
general corporate purposes.





On
May 16, 2003, MEHC issued $450.0 million, net of discount, of its
3.50% Senior Notes with a final maturity on May 15, 2008. The proceeds were
used for general corporate purposes.





75





**13.**  **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. 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 at December 31 (in
thousands):





**2004**
    
    
    **2003**CalEnergy
      Capital Trust II — 6.25%, due 2012
    
    $
    104,645
    
    $
    104,645CalEnergy
      Capital Trust III — 6.5%, due 2027
    
    
    269,980
    
    
    269,980MidAmerican
      Capital Trust I — 11%, due 2010
    
    
    454,772
    
    
    454,772MidAmerican
      Capital Trust II — 11%, due 2011
    
    
    700,000
    
    
    800,000MidAmerican
      Capital Trust III — 11%, due 2012
    
    
    323,000
    
    
    323,000Fair
      value adjustment
    
    
    (78,044
    )
    
    (80,251
    )Total
      Parent Company Subordinated Debt
    
    
    1,774,353
    
    
    1,872,146Less
      current portion
    
    
    (188,543
    )
    
    (100,000
    )Long-Term
      Parent Company Subordinated Debt
    
    $
    1,585,810
    
    $
    1,772,146





MEHC owns
all of the common securities of the Trusts. The Trust Securities have a
liquidation preference of $50 each (plus accrued and unpaid dividends thereon to
the date of payment) and represent undivided beneficial ownership interests in
each of the Trusts. The assets of the Trusts consist solely of Subordinated
Debentures of MEHC (collectively, the “Junior Debentures”) issued pursuant to
their respective indentures. The indentures include agreements by MEHC to pay
expenses and obligations incurred by the Trusts.





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





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





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


76





**14.**  **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, 2004, the
separate legal entities were in compliance with all applicable covenants.
However, Cordova Energy’s 537 MW gas-fired power plant in the Quad Cities,
Illinois area (the “Cordova project”) is currently prohibited from making
distributions by the terms of its indenture due to its failure to meet its debt
service coverage ratio requirement.





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





**2004**
    
    
    **2003**MidAmerican
      Funding
    
    $
    700,000
    
    $
    700,000MidAmerican
      Energy
    
    
    1,422,527
    
    
    1,128,647CE
      Electric UK
    
    
    2,504,801
    
    
    2,467,214Kern
      River
    
    
    1,214,808
    
    
    1,276,174Northern
      Natural Gas
    
    
    799,614
    
    
    799,472CE
      Casecnan
    
    
    197,098
    
    
    246,458Leyte
      Projects
    
    
    105,664
    
    
    172,813Cordova
      Funding
    
    
    206,663
    
    
    214,761Funding
      Corporation
    
    
    -
    
    
    136,384HomeServices
    
    
    32,963
    
    
    37,558Other,
      including fair value adjustments
    
    
    6,383
    
    
    (3,900
    )Total
      Subsidiary and Project Debt
    
    
    7,190,521
    
    
    7,175,581Less
      current portion
    
    
    (885,598
    )
    
    (500,941
    )Total
      Long-Term Subsidiary and Project Debt
    
    $
    6,304,923
    
    $
    6,674,640





*MidAmerican
Funding*





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





**2004**
    
    
    **2003**6.339%
      Senior Notes, due 2009
    
    $
    175,000
    
    $
    175,0006.75%
      Senior Notes, due 2011
    
    
    200,000
    
    
    200,0006.927%
      Senior Bonds, due 2029
    
    
    325,000
    
    
    325,000Total
      MidAmerican Funding
    
    $
    700,000
    
    $
    700,000





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







77





**


*MidAmerican
Energy*





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





**2004**
    
    
    **2003**Mortgage
      bonds:7.7%
      Series, due 2004
    
    $
    -
    
    $
    55,6307%
      Series, due 2005
    
    
    90,500
    
    
    90,500Pollution
      control revenue obligations:6.1%
      Series, due 2007
    
    
    1,000
    
    
    1,0005.95%
      Series, due 2023
    
    
    29,030
    
    
    29,030Variable
      rate series:Due
      2016 and 2017, 2.05% and 1.26%
    
    
    37,600
    
    
    37,600Due
      2023 secured by general mortgage bond, 2.05% and 1.26%
    
    
    28,295
    
    
    28,295Due
      2023, 2.05% and 1.26%
    
    
    6,850
    
    
    6,850Due
      2024, 2.05% and 1.26%
    
    
    34,900
    
    
    34,900Due
      2025, 2.05% and 1.26%
    
    
    12,750
    
    
    12,750Notes:6.375%
      Series, due 2006
    
    
    160,000
    
    
    160,0005.125%
      Series, due 2013
    
    
    275,000
    
    
    275,0004.65%
      Series, due 2014
    
    
    350,000
    
    
    -6.75%
      Series, due 2031
    
    
    400,000
    
    
    400,000Obligations
      under capital lease
    
    
    1,524
    
    
    2,060Unamortized
      debt premium and discount, net
    
    
    (4,922
    )
    
    (4,968
    )Total
      MidAmerican Energy
    
    $
    1,422,527
    
    $
    1,128,647





MidAmerican
Energy’s 7.7% series of mortgage bonds, totaling $55.6 million, matured on
May 17, 2004. On October 1, 2004, MidAmerican Energy issued
$350.0 million of 4.65% medium-term notes due October 1, 2014. The
proceeds were used for general corporate purposes.





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





*CE
Electric UK*





The
components of CE Electric UK and its subsidiaries’ long-term debt consist of the
following at December 31 (in thousands):





**2004**
    
    
    **2003**6.853%
      Senior Notes, due 2004
    
    $
    -
    
    $
    117,1128.625%
      Bearer bonds, due 2005
    
    
    192,045
    
    
    178,8776.995%
      Senior Notes, due 2007
    
    
    237,000
    
    
    236,1746.496%
      Yankee Bonds, due 2008
    
    
    281,113
    
    
    281,149Variable
      Rate Reset Trust Securities, due 2020 (5.88% and 4.39%)
    
    
    308,361
    
    
    287,5398.875%
      Bearer bonds, due 2020
    
    
    191,955
    
    
    178,6449.25%
      Eurobonds, due 2020
    
    
    485,654
    
    
    458,1877.25%
      Sterling Bonds, due 2022
    
    
    377,674
    
    
    351,2427.25%
      Eurobonds, due 2028
    
    
    378,202
    
    
    352,768CE
      Gas Credit Facility, 6.36%
    
    
    52,797
    
    
    25,522Total
      CE Electric UK
    
    $
    2,504,801
    
    $
    2,467,214





78





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 has 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.





*Kern
River*





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





**2004**
    
    
    **2003**6.676%
      Senior Notes, due 2016
    
    $
    439,000
    
    $
    464,0004.893%
      Senior Notes, due 2018
    
    
    775,808
    
    
    812,174Total
      Kern River
    
    $
    1,214,808
    
    $
    1,276,174





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





On
May 1, 2003, Kern River Funding Corporation, a wholly owned subsidiary of
Kern River, issued $836.0 million of its 4.893% Senior Notes with a final
maturity on April 30, 2018. The proceeds were used to repay all of the
$815.0 million of outstanding borrowings under Kern River’s
$875.0 million credit facility. Kern River entered into this credit
facility in 2002 to finance the construction of its 717 mile
expansion.





*Northern
Natural Gas*





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





**2004**
    
    
    **2003**6.875%
      Senior Notes, due 2005
    
    $
    100,000
    
    $
    100,0006.75%
      Senior Notes, due 2008
    
    
    150,000
    
    
    150,0007.00%
      Senior Notes, due 2011
    
    
    250,000
    
    
    250,0005.375%
      Senior Notes, due 2012
    
    
    300,000
    
    
    300,000Unamortized
      debt discount
    
    
    (386
    )
    
    (528
    )Total
      Northern Natural Gas
    
    $
    799,614
    
    $
    799,472





*CE
Casecnan*





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





**2004**
    
    
    **2003**11.45%
      Senior Secured Series A Notes, due in 2005
    
    $
    48,750
    
    $
    91,25011.95%
      Senior Secured Series B Bonds, due in 2010
    
    
    148,348
    
    
    155,208Total
      CE Casecnan
    
    $
    197,098
    
    $
    246,458





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





79





*Leyte
Projects*





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





**2004**
    
    
    **2003**Mahanagdong
      Project 6.92% Term Loan, due 2007
    
    $
    51,537
    
    $
    72,151Mahanagdong
      Project 7.60% Term Loan, due 2007
    
    
    11,428
    
    
    16,000Malitbog
      Project 4.99% and 3.67%, due 2005
    
    
    11,866
    
    
    26,378Malitbog
      Project 9.176% Term Loan, due 2006
    
    
    6,580
    
    
    14,628Upper
      Mahiao Project 5.95% Term Loan, due 2006
    
    
    24,253
    
    
    43,656Total
      Leyte Projects
    
    $
    105,664
    
    $
    172,813





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
$44.6 million and $40.3 million at December 31, 2004 and 2003,
respectively.





*Cordova
Funding*





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





**2004**
    
    
    **2003**8.48%
      Senior Secured Bonds, due 2019
    
    $
    11,716
    
    $
    12,1758.64%
      Senior Secured Bonds, due 2019
    
    
    85,893
    
    
    89,2608.79%
      Senior Secured Bonds, due 2019
    
    
    28,758
    
    
    29,8858.82%
      Senior Secured Bonds, due 2019
    
    
    53,384
    
    
    55,4769.07%
      Senior Secured Bonds, due 2019
    
    
    26,912
    
    
    27,965Total
      Cordova Funding
    
    $
    206,663
    
    $
    214,761





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 of which such maximum amount was $13.0
million as of December 31, 2004.





As of
December 31, 2004, 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.





*Funding
Corporation*





CalEnergy
Minerals LLC (“Minerals”), a wholly-owned indirect subsidiary of MEHC, was one
of several guarantors of the Funding Corporation’s debt. As a result of a note
allocation agreement, Minerals was primarily responsible for $136.4 million
of the Series F Bonds. In 1999, MEHC guaranteed a specified portion of the
scheduled debt service on the Series F Bonds equal to the then current principal
amount of $136.4 million and associated interest.





On
March 1, 2004, Funding Corporation completed the redemption of an aggregate
principal amount of $136.4 million of the Series F Bonds, pro rata, at a
redemption price of 100% of such aggregate outstanding principal amount, plus
accrued interest to the date of redemption. Funding Corporation also made a
demand on MEHC for the full amount remaining on MEHC’s guarantee of the Series F
Bonds in order to fund the redemption. MEHC made the requisite payment and, as a
result, it has no further liability with respect to its guarantee. The Company
had a non-cash, after-tax loss, recorded in loss from discontinued operations in
the accompanying consolidated statement of operations, of $6.4 million as a
result of the redemption of the Series F Bonds.





80





*HomeServices*





In
November 1998, HomeServices issued $35.0 million of 7.12% fixed-rate
private placement senior notes due in annual increments of $5.0 million
beginning in 2004. As of December 31, 2004 and 2003, the balance of the
HomeServices Senior Notes was $30.0 million and $35.0 million,
respectively.





In
addition to the senior notes, HomeServices has outstanding capital leases and
other long-term debt, with varying interest rates, totaling $3.0 million
and $2.6 million at December 31, 2004 and 2003,
respectively.





*Annual
Repayments of Long-Term Debt*





The
annual repayments of parent company, subsidiary and project debt for the years
beginning January 1, 2005 and thereafter are as follows (in
thousands):




**2005**
    
    **2006**
    
    **2007**
    
    **2008**
    
    **2009**
    
    **Thereafter**
    
    **Total**Parent
      Company senior debt
    
    $260,000
    
    $-
    
    $550,000
    
    $1,000,000
    
    $-
    
    $1,221,957
    
    $3,031,957Parent
      Company subordinated debt
    
    188,543
    
    234,021
    
    234,021
    
    234,021
    
    234,021
    
    649,726
    
    1,774,353MidAmerican
      Funding
    
    -
    
    -
    
    -
    
    -
    
    175,000
    
    525,000
    
    700,000MidAmerican
      Energy
    
    91,018
    
    160,000
    
    1,000
    
    -
    
    -
    
    1,170,509
    
    1,422,527CE
      Electric UK
    
    500,406
    
    9,720
    
    253,925
    
    294,051
    
    4,913
    
    1,441,786
    
    2,504,801Kern
      River
    
    62,784
    
    66,128
    
    69,472
    
    72,816
    
    74,906
    
    868,702
    
    1,214,808Northern
      Natural Gas
    
    99,963
    
    -
    
    -
    
    150,000
    
    -
    
    549,651
    
    799,614CE
      Casecnan
    
    54,753
    
    36,016
    
    37,730
    
    37,730
    
    13,720
    
    17,149
    
    197,098Leyte
      Projects
    
    63,034
    
    30,037
    
    12,593
    
    -
    
    -
    
    -
    
    105,664Cordova
      Funding
    
    7,875
    
    4,500
    
    4,163
    
    4,725
    
    6,412
    
    178,988
    
    206,663HomeServices
    
    5,765
    
    5,000
    
    5,000
    
    5,000
    
    5,000
    
    7,198
    
    32,963Other,
      including purchase accounting adjustments
    
    -
    
    -
    
    -
    
    -
    
    -
    
    6,383
    
    6,383Totals
    
    $1,334,141
    
    $545,422
    
    $1,167,904
    
    $1,798,343
    
    $513,972
    
    $6,637,049
    
    $11,996,831


Fair
Value





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 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, 2003, the Company had fixed-rate long-term debt of
$11,369.4 million in principal amount and having a fair value of
$12,015.1 million. In addition, at December 31, 2003, the Company had
floating-rate obligations of $459.8 million. The fair value of the
floating-rate obligations and the short-term debt approximates their carrying
amounts.





81





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





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





**Year
      Ended December 31,****2004**
    
    
    **2003**
    
    
    **2002**Current:Federal
    
    $
    18,794
    
    $
    (48,911
    )
    $
    57,236State
    
    
    (9,862
    )
    
    10,901
    
    
    17,476Foreign
    
    
    79,463
    
    
    88,150
    
    
    54,58688,395
    
    
    50,140
    
    
    129,298Deferred:Federal
    
    
    112,719
    
    
    141,795
    
    
    (4,900
    )State
    
    
    607
    
    
    10,833
    
    
    (13,640
    )Foreign
    
    
    63,265
    
    
    67,508
    
    
    520176,591
    
    
    220,136
    
    
    (18,020
    )Total
    
    $
    264,986
    
    $
    270,276
    
    $
    111,278





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





**2004**
    
    
    **2003**
    
    
    **2002**Federal
      statutory rate
    
    
    35.0
    %
    
    35.0
    %
    
    35.0
    %Investment
      and energy tax credits
    
    
    (0.6
    )
    
    (0.5
    )
    
    (0.7
    )State
      taxes, net of federal tax effect
    
    
    2.2
    
    
    1.8
    
    
    1.2Equity
      income
    
    
    0.7
    
    
    1.6
    
    
    2.3Dividends
      on preferred securities of subsidiaries
    
    
    -
    
    
    (6.9
    )
    
    (8.3
    )Tax
      effect of foreign income
    
    
    0.3
    
    
    0.5
    
    
    (4.8
    )Non-recurring
      items on CE Electric UK, net of tax effect of foreign
    income
    
    
    -
    
    
    (0.5
    )
    
    (8.3
    )Dividends
      received deduction
    
    
    -
    
    
    (1.1
    )
    
    (1.9
    )Effects
      of ratemaking
    
    
    (0.9
    )
    
    0.9
    
    
    1.0Other
      items, net
    
    
    (3.5
    )
    
    0.7
    
    
    2.1Effective
      tax rate
    
    
    33.2
    %
    
    31.5
    %
    
    17.6
    %





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





**2004**
    
    
    **2003**Properties,
      plants and equipment, net
    
    $
    1,700,884
    
    $
    1,611,744Income
      taxes recoverable through future rates
    
    
    163,108
    
    
    142,597Employee
      benefits
    
    
    56,656
    
    
    43,005Reacquired
      debt
    
    
    3,877
    
    
    5,665Fuel
      cost recoveries
    
    
    6,028
    
    
    12,8641,930,553
    
    
    1,815,875Minimum
      pension liability adjustment
    
    
    (172,350
    )
    
    (147,279
    )Revenue
      sharing accruals
    
    
    (80,220
    )
    
    (64,192
    )Accruals
      not currently deductible for tax purposes
    
    
    (54,402
    )
    
    (55,290
    )Nuclear
      reserve and decommissioning
    
    
    (27,112
    )
    
    (35,955
    )Deferred
      income
    
    
    (34,458
    )
    
    (37,819
    )Net
      operating loss (“NOL”) and credit carryforwards
    
    
    (267,051
    )
    
    (161,659
    )Other
    
    
    (13,127
    )
    
    (14,599
    )(648,720
    )
    
    (516,793
    )Net
      deferred income taxes
    
    $
    1,281,833
    
    $
    1,299,082





82








At
December 31, 2004, 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 2024.





**16.**  **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, 2004, are entitled to upon involuntary
bankruptcy is $30.3 million plus accrued dividends. The annual dividend
requirements for all preferred securities outstanding at December 31, 2004,
total $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 by the
Secretary of State of the subsidiary’s electricity distribution license, was
$56.0 million as of December 31, 2004 and 2003,
respectively.





**17.**  **Convertible
Preferred Stock**





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





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





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





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





As of
December 31, 2004, there were 2,048,329 options outstanding which are
exercisable until the end of the term on March 14, 2008 at exercise prices
ranging from $15.94 to $35.05 per share.





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





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





83





**19.**  **Accounting
for Derivatives**





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





*Currency
Exchange Rate Risk*





CE
Electric UK entered into currency rate swap agreements for its Senior Notes 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 outstanding at December  31,
2004. The agreements extend until maturity on December 30, 2007 and convert
the U.S. dollar interest rate to a fixed Sterling rate of 7.737%. The estimated
fair value of these swap agreements at December 31, 2004 and 2003, was
$35.7 million and $16.0 million, respectively, based on quotes from
the counterparty to these instruments and represents the estimated amount that
the Company would expect to pay if these agreement were terminated.





A
subsidiary of CE Electric UK entered into certain currency rate swap agreements
for its Yankee Bonds with three large multi-national financial institutions. The
swap agreements effectively convert the U.S. dollar fixed interest rate to a
fixed rate in Sterling for $281.1 million of the 6.496% Yankee Bonds
outstanding at December 31, 2004. The agreements extend until maturity on
February 25, 2008 and convert the U.S. dollar interest rate to a fixed
Sterling rate ranging from 7.3175% to 7.345%. The estimated fair value of these
swap agreements at December 31, 2004 and 2003, was $96.1 million and
$62.6 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.





*Derivatives*





As of
December 31, 2004, MidAmerican Energy held derivative instruments used for
non-trading and trading purposes with the following fair values (in
thousands):





**Contract
      Type**
    
    **Maturity**
      **in
      2005**
    
    **Maturity**
      **in
      2006-08**
    
    **Total**Non-trading:Regulated
      electric assets
    
    $
    2,260
    
    $
    431
    
    $
    2,691Regulated
      electric (liabilities)
    
    
    (10,057
    )
    
    (4,817
    )
    
    (14,874
    )Regulated
      gas assets
    
    
    2,973
    
    
    1,798
    
    
    4,771Regulated
      gas (liabilities)
    
    
    (21,921
    )
    
    -
    
    
    (21,921
    )Regulated
      weather (liabilities)
    
    
    (4,495
    )
    
    -
    
    
    (4,495
    )Nonregulated
      electric assets
    
    
    1,957
    
    
    372
    
    
    2,329Nonregulated
      electric (liabilities)
    
    
    (1,158
    )
    
    (214
    )
    
    (1,372
    )Nonregulated
      gas assets
    
    
    5,937
    
    
    1,919
    
    
    7,856Nonregulated
      gas (liabilities)
    
    
    (6,606
    )
    
    (1,558
    )
    
    (8,164
    )Total
    
    
    (31,110
    )
    
    (2,069
    )
    
    (33,179
    )Trading:Nonregulated
      gas assets
    
    
    993
    
    
    -
    
    
    993Nonregulated
      gas (liabilities)
    
    
    (430
    )
    
    (100
    )
    
    (530
    )Total
    
    
    563
    
    
    (100
    )
    
    463Total
      MidAmerican Energy assets
    
    $
    14,120
    
    $
    4,520
    
    $
    18,640Total
      MidAmerican Energy (liabilities)
    
    $
    (44,667
    )
    $
    (6,689
    )
    $
    (51,356
    )





84





**20.**  **Regulatory
Matters**





*MidAmerican
Energy*





Under
three settlement agreements between MidAmerican Energy, The Iowa Office of
Consumer Advocate (“OCA”) and other intervenors approved by the IUB, MidAmerican
Energy has agreed not to seek a general increase in electric rates prior to 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
request or support 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 the
first settlement agreement, which was approved by the IUB on December 21,
2001, and is effective through December 31, 2005, an amount equal to 50% of
revenues associated with returns on equity between 12% and 14%, and 83.33% of
revenues associated with returns on equity above 14%, in each year is recorded
as a regulatory liability. The second settlement agreement, which was filed in
conjunction with MidAmerican Energy’s application for ratemaking principles on
its wind power project and was approved by the IUB on October 17, 2003,
provides that during the period January 1, 2006 through December 31,
2010, an amount equal to 40% of revenues associated with returns on equity
between 11.75% and 13%, 50% of revenues associated with returns on equity
between 13% and 14%, and 83.3% of revenues associated with returns on equity
above 14%, in each year will be recorded as a regulatory liability.





The third
settlement agreement was approved by the IUB on January 31, 2005, in
conjunction with MidAmerican Energy’s proposed expansion of its wind power
project by up to 90 MW. This settlement 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. In addition, the OCA agreed to
commit not to seek any decrease in Iowa electric base rates to become effective
before January 1, 2012. The total capacity added as the result of the wind
expansion project is currently projected to be 50 MW.





The
regulatory liabilities created by the three 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 in amounts equal to the AFUDC
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. As of December 31, 2004 and 2003, the
related regulatory liability reflected in the accompanying consolidated balance
sheets was $181.2 million and $144.4 million, respectively. The
regulatory liability for 2011 will be credited to customer bills in
2012.





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





*Kern
River*





Kern
River’s tariff rates were 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 are set using a “levelized cost-of-service”
methodology so that the rate is constant over the contract period. This is
achieved by using a FERC-approved depreciation schedule in which depreciation
increases as interest expense decreases.




85





Kern
River was required to file a general rate case no later than May 1, 2004
pursuant to the terms of its 1998 FERC Docket No. RP99-274 rate case settlement.
Kern River filed its rate case on April 30, 2004, which supports a revenue
increase of $40.1 million representing a 13% increase from its existing
cost of service and a proposed overall cost of service of $347.4 million.
Since its last rate case, Kern River has increased the capacity of its system
from 724,500 Dth per day to 1,755,575 Dth per day at a cost of approximately
$1.3 billion, resulting in a total rate base of approximately $1.8 billion. The
rate increase became effective on November 1, 2004, subject to refund, and
the FERC set a procedural order with a hearing scheduled for March
2005.





*Northern
Natural Gas*





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





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





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




On
February 16, 2005, Northern Natural Gas reached a tentative agreement with the
majority of its customers to settle the consolidated rate cases. Definitive
terms of the settlement must be agreed by all settling parties and must then be
documented in a settlement agreement which must be agreed to by all settling
parties. Thereafter, the settlement must be certified by the presiding
administrative law judge and approved by the FERC. The terms of the agreement in
principle provide for an annual revenue increase of $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. As a result of the settlement,
Northern Natural Gas will be required to refund an amount generally reflecting
the difference between the rate increases implemented on November 1, 2003
and November 1, 2004 and the final settled revenue
amounts.


**


*CE
Electric UK*





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





The
current formula requires that regulated distribution income per unit is
increased or decreased each year by RPI-Xd where RPI means the Retail Price
Index, 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 2000 (and
through March 31, 2005, will continue to be set) at 3%. 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.





86





Ofgem’s
process of reviewing each DLH’s existing price control formula, with a revised
formula for each DLH (including Northern Electric and Yorkshire Electricity) to
take effect from April 1, 2005 for an expected period of five years was recently
completed. As a result of the review, 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. The Xd factor was set at zero. 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 may depend on the successful implementation of revised
cost reporting guidelines to be prescribed by Ofgem and applied by all DLHs. 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.





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 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.





**21.**  **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 $71.1 million for 2004,
$65.8 million for 2003, and $60.1 million for 2002. The minimum
payments under these leases are $70.4 million, $64.3 million,
$56.7 million, $45.9 million, and $33.0 million for the years
2005 through 2009, respectively, and $104.7 million for the total of the
years thereafter.





*MidAmerican
Energy*





*Fuel,
Energy and Operating Lease Commitments*





MidAmerican
Energy has supply and related transportation contracts for its fossil fueled
generating stations. As of December 31, 2004, the contracts, with
expiration dates ranging from 2005 to 2010, require minimum payments of
$83.5 million, $67.4 million, $62.8 million, $22.0 million
and $15.8 million for the years 2005 through 2009, respectively, and
$15.5 million for the total of the years thereafter. MidAmerican Energy
expects to supplement these coal contracts with additional contracts and spot
market purchases to fulfill its future fossil fuel needs. Additionally,
MidAmerican Energy has a supply and transportation contract for a natural
gas-fired generating plant. The contract, which expires in 2012, requires
minimum annual payments of $6.2 million.





MidAmerican
Energy also has contracts to purchase electric capacity. As of December 31,
2004, the contracts, with expiration dates ranging from 2005 to 2028, require
minimum payments of $29.1 million, $25.1 million, $27.3 million,
$35.8 million and $28.9 million for the years 2005 through 2009,
respectively, and $73.9 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, 2004, the contracts, with expiration dates
ranging from 2005 to 2013, require minimum payments of $54.2 million,
$35.1 million, $25.2 million, $4.4 million and $2.9 million
for the years 2005 through 2009, respectively, and $10.3 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, 2004, the
maximum amount of such guarantees specified in these leases totaled
$30.2 million. These guarantees are not reflected in the accompanying
consolidated balance sheets.


87








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 will
hold 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, 2004 and 2003, totaled $152.3 million and
$23.4 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 $59.9 million and $9.2 million, respectively, as of
December 31, 2004 and 2003. 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’s generating facilities are subject to applicable provisions of the Clean
Air Act and related air quality standards promulgated by the 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
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 in the area 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 is in attainment of the ozone standards
and the fine particulate standards.





On
December 4, 2003, the EPA announced the development of its Interstate Air
Quality Rule, now known as the Clean Air Interstate Rule, a proposal to require
coal-burning power plants in 29 states, including Iowa, and the District of
Columbia to reduce emissions of sulfur dioxide (“SO 2 ”) and
nitrogen oxides (“NO X ”) in an
effort to reduce ozone and fine particulate matter in the Eastern United States.
It is likely that MidAmerican Energy’s coal-burning facilities will be impacted
by this proposal.





In
December 2000, the EPA concluded that mercury emissions from coal-fired
generating stations should be regulated. The EPA is currently considering two
regulatory alternatives that would reduce emissions of mercury from coal-fired
utilities. One of these alternatives would require reductions of mercury from
all coal-fired facilities greater than 25 MW through application of Maximum
Achievable Control Technology with compliance assessed on a facility basis. The
other alternative would regulate the mercury emissions of coal-fired facilities
that pose a health hazard through a market based cap-and-trade mechanism similar
to the SO 2 allowance system. The EPA is currently under a deadline to finalize the mercury
reduction rule by March 2005.





The Clean
Air Interstate Rule or the mercury reduction rule 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 the “Clear Skies Initiative,” and other pending legislative proposals
that contemplate 70% to 90% reductions of SO 2 ,
NO X and
mercury, as well as possible new federal regulation of carbon dioxide and other
gasses that may affect global climate change.





Depending
on the outcome of the final Clean Air Interstate Rule and the mercury reduction
rule or any superseding legislation by Congress, MidAmerican Energy may be
required to install control equipment on its generating stations, purchase
emission allowances or decrease the number of hours during which its generating
stations operate. However, until final regulatory or legislative action is
taken, the impact of the regulations on MidAmerican Energy cannot be
predicted.




88





MidAmerican
Energy has implemented a planning process that forecasts the site-specific
controls and actions that may be required to meet emissions reductions as
contemplated by the United States Environmental Protection Agency (“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 SO 2 and
NO X 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 Iowa Consumer Advocate Division of the Department of
Justice. 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 $325.0 million,
then MidAmerican Energy may seek to recover the additional expenditures from
customers. At this time, MidAmerican Energy does not expect these capital
expenditures to exceed such amount.





Under the
New Source Review (“NSR”) provisions of the Clean Air Act, a utility is required
to obtain a permit from the EPA or a state regulatory agency prior to (1)
beginning construction of a new major stationary source of an NSR-regulated
pollutant or (2) making a physical or operational change 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 support
regarding their capital projects for various generating plants. The requests
were issued as part of an industry-wide investigation to assess compliance with
the NSR and the New Source Performance Standards of the Clean Air Act. In
December 2002 and April 2003, MidAmerican Energy received requests from the EPA
to provide documentation related to its capital projects from January 1,
1980, to 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. However, on
August 27, 2003, the EPA announced changes to its NSR rules that clarify
what constitutes routine repair, maintenance and replacement for purposes of
triggering NSR requirements. The EPA concluded equipment that is repaired,
maintained or replaced with an expenditure not greater than 20 percent of the
value of the source will not trigger the NSR provisions of the Clean Air Act. A
number of states and local air districts challenged the EPA’s clarification of
the NSR rule and a panel of the U.S. Circuit Court of Appeals for the District
of Columbia Circuit issued an order on December 24, 2003, staying the EPA’s
implementation of its clarifications of the equipment replacement rule. On
July 1, 2004, the EPA published a notice of stay of the final equipment
replacement rule in the *Federal
Register* ,
consistent with the judicial stay. Additionally, on the same date, the EPA
published a Notice of Reconsideration and Request for Comment on the equipment
replacement rule in response to the Petitioners’ legal challenges. Until such
time as the EPA takes final action on the equipment replacement rule, the
previous rules without the clarified exemption remain in effect.





*Nuclear
Decommissioning Costs*





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





MidAmerican
Energy’s share of expected decommissioning costs for Quad Cities Station, in
2004 dollars, is $154.0 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 is reflected in other investments in the accompanying consolidated
balance sheets.





89





*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. The general types of coverage are:
nuclear liability, property coverage and nuclear worker liability.





Exelon
Generation purchases nuclear liability insurance for Quad Cities Station in the
maximum available amount of $300.0 million, which includes coverage for
MidAmerican Energy’s ownership. In accordance with the Price-Anderson Amendments
Act of 1988, excess liability protection above that amount is provided by a
mandatory industry-wide Secondary Financial Protection program under which the
licensees of nuclear generating facilities could be assessed for liability
incurred due to a serious nuclear incident at any commercial nuclear reactor in
the United States. Currently, MidAmerican Energy’s aggregate maximum potential
share of an assessment for Quad Cities Station is approximately
$50.3 million per incident, payable in installments not to exceed
$5.0 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 purchased primary and excess property insurance protection for the
combined interests in Quad Cities Station, with coverage limits totaling $2.1
billion. MidAmerican Energy also directly purchased extra expense or business
interruption coverage for its share of replacement power and other extra
expenses in the event of a covered accidental outage at Quad Cities Station. The
property and related coverages purchased directly by MidAmerican Energy and by
Exelon Generation, which includes the interests of MidAmerican Energy, are
underwritten by an industry mutual insurance company and contain provisions for
retrospective premium assessments should two or more full policy-limit losses
occur in one policy year. Currently, the maximum retrospective amounts that
could be assessed against MidAmerican Energy from industry mutual policies for
its obligations associated with Quad Cities Station total
$8.8 million.





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





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





*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, LaPrairie Group Contractors (International) Ltd. (“LPG”),
that MEHC’s 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, among others, CE Casecnan Ltd. and MEHC. On
January 21, 2004, CE Casecnan Ltd. and LPG 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, totaling to
$15.9 million, was set aside by CE Casecnan in an unsecured CE Casecnan
account and is shown as restricted cash and short-term investments and other
current liabilities in the accompanying consolidated balance sheet. The court is
currently expected to rule on the first phase of the litigation before the end
of the first quarter of 2005. The impact, if any, of this litigation on the
Company cannot be determined at this time.




90





**22.**  **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 participants’ compensation,
years of service and age at retirement. 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.





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. Non-union employees hired July 1, 2004, and after will no
longer be eligible for postretirement benefits other than pensions. The
amendment establishes retiree medical accounts for participants to which the
Company will make fixed contributions. 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.





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. 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.





**Pension
      Cost**
    
    **Postretirement
      Cost****2004**
    
    **2003**
    
    **2002**
    
    **2004**
    
    **2003**
    
    **2002**(in
      thousands)Service
      cost
    
    $
    25,568
    
    $
    24,693
    
    $
    20,235
    
    $
    7,842
    
    $
    8,175
    
    $
    6,028Interest
      cost
    
    
    35,159
    
    
    34,533
    
    
    34,177
    
    
    15,716
    
    
    16,065
    
    
    13,928Expected
      return on plan assets
    
    
    (38,258
    )
    
    (38,396
    )
    
    (38,213
    )
    
    (8,437
    )
    
    (6,008
    )
    
    (4,880
    )Amortization
      of net transition obligation
    
    
    (792
    )
    
    (2,591
    )
    
    (2,591
    )
    
    3,283
    
    
    4,110
    
    
    4,110Amortization
      of prior service cost
    
    
    2,758
    
    
    2,761
    
    
    2,729
    
    
    296
    
    
    593
    
    
    425Amortization
      of prior year (gain) loss
    
    
    1,569
    
    
    1,483
    
    
    (2,482
    )
    
    3,299
    
    
    3,716
    
    
    2,385Regulatory
      expense
    
    
    -
    
    
    3,320
    
    
    6,639
    
    
    -
    
    
    -
    
    
    -Net
      periodic benefit cost
    
    $
    26,004
    
    $
    25,803
    
    $
    20,494
    
    $
    21,999
    
    $
    26,651
    
    $
    21,996





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





**2004**
    
    
    **2003**
    
    
    **2002**
    
    
    **2004**
    
    
    **2003**
    
    
    **2002**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:





**2004**
    
    
    **2003**
    
    
    **2002**
    
    
    **2004**
    
    
    **2003**
    
    
    **2002**Discount
      rate
    
    
    5.75
    %
    
    5.75
    %
    
    6.50
    %
    
    5.75
    %
    
    5.75
    %
    
    6.50
    %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





91








Assumed
health care cost trend rates at December 31:





**2004**
    
    
    **2003**Health
      care cost trend rate assumed for next year
    
    
    10.00
    %
    
    11.00
    %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





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 Expense****One
      Percentage-**
    
    
    **One
      Percentage-****Point
      Increase**
    
    
    **Point
      Decrease**Effect
      on total service and interest cost
    
    $
    4,855
    
    $
    (3,740
    )Effect
      on postretirement benefit obligation
    
    $
    29,420
    
    $
    (24,066
    )





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****2004**
    
    
    **2003**
    
    
    **2004**
    
    
    **2003**Reconciliation
      of the fair value of plan assets:Fair
      value of plan assets at beginning of year
    
    $
    551,568
    
    $
    467,773
    
    $
    157,849
    
    $
    122,655Employer
      contributions
    
    
    5,083
    
    
    5,044
    
    
    23,782
    
    
    32,566Participant
      contributions
    
    
    -
    
    
    -
    
    
    7,733
    
    
    6,371Actual
      return on plan assets
    
    
    63,151
    
    
    105,438
    
    
    9,698
    
    
    15,853Benefits
      paid
    
    
    (28,174
    )
    
    (26,687
    )
    
    (19,687
    )
    
    (19,596
    )Fair
      value of plan assets at end of year
    
    $
    591,628
    
    $
    551,568
    
    $
    179,375
    
    $
    157,849Reconciliation
      of benefit obligation:Benefit
      obligation at beginning of year
    
    $
    620,048
    
    $
    593,179
    
    $
    297,433
    
    $
    291,441Service
      cost
    
    
    25,568
    
    
    24,693
    
    
    7,841
    
    
    8,175Interest
      cost
    
    
    35,159
    
    
    34,533
    
    
    15,716
    
    
    16,065Participant
      contributions
    
    
    -
    
    
    -
    
    
    7,733
    
    
    6,371Plan
      amendments
    
    
    -
    
    
    -
    
    
    (19,219
    )
    
    -Actuarial
      (gain) loss
    
    
    4,805
    
    
    (5,670
    )
    
    (33,773
    )
    
    (5,023
    )Benefits
      paid
    
    
    (28,174
    )
    
    (26,687
    )
    
    (19,687
    )
    
    (19,596
    )Benefit
      obligation at end of year
    
    $
    657,406
    
    $
    620,048
    
    $
    256,044
    
    $
    297,433Funded
      status
    
    $
    (65,778
    )
    $
    (68,480
    )
    $
    (76,669
    )
    $
    (139,584
    )Amounts
      not recognized in consolidated balance sheets:Unrecognized
      net (gain) loss
    
    
    (34,319
    )
    
    (12,907
    )
    
    42,768
    
    
    83,509Unrecognized
      prior service cost
    
    
    15,157
    
    
    17,915
    
    
    -
    
    
    5,451Unrecognized
      net transition obligation (asset)
    
    
    -
    
    
    (792
    )
    
    19,641
    
    
    36,992Net
      amount recognized in the consolidated balance sheets
    
    $
    (84,940
    )
    $
    (64,264
    )
    $
    (14,260
    )
    $
    (13,632
    )Net
      amount recognized in the consolidated balance sheets consists
      of:Prepaid
      benefit cost
    
    $
    -
    
    $
    39
    
    $
    -
    
    $
    -Accrued
      benefit liability
    
    
    (117,357
    )
    
    (100,490
    )
    
    (14,260
    )
    
    (13,632
    )Intangible
      assets
    
    
    14,653
    
    
    17,367
    
    
    -
    
    
    -Regulatory
      assets
    
    
    17,764
    
    
    18,820
    
    
    -
    
    
    -Net
      amount recognized
    
    $
    (84,940
    )
    $
    (64,264
    )
    $
    (14,260
    )
    $
    (13,632
    )





92





The
portion of the pension projected benefit obligation, included in the table
above, related to the supplemental executive retirement plan was
$106.5 million and $105.1 million as of December 31, 2004 and 2003,
respectively. The supplemental executive retirement plan has no assets, and
accordingly, the fair value of its plan assets was zero as of December 31, 2004
and 2003. The accumulated benefit obligation for all defined benefit pension
plans was $585.4 million and $554.6 million at December 31, 2004 and
2003, respectively. Of these amounts, the supplemental executive retirement plan
accumulated benefit obligation totaled $102.3 million and
$100.5 million for 2004 and 2003, respectively.





Although
the supplemental executive retirement plan had no assets as of December 31,
2004, 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 cash surrender value of these assets is not
included in the plan assets. The cash surrender value of the Rabbi trust
investments was $98.8 million and $88.1 million at December 31,
2004 and 2003, respectively.





Plan
Assets





The
Company’s investment policy for its domestic pension and postretirement plans is
to balance risk and return through a diversified portfolio of high-quality
equity and fixed income securities. Equity targets for the pension and
postretirement plans are as indicated in the tables below. Maturities for fixed
income securities are managed such that sufficient liquidity exists to meet
near-term benefit payment obligations. The plans retain outside investment
advisors to manage plan investments within the parameters outlined by the
Company’s Pension 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, 2004 and 2003, are
as follows:





**Percentage
      of****Plan
      Assets****at
      December 31**
    
    **Target****2004**
    
    
    **2003**
    
    
    **Range****Asset
      Category**Equity
      securities
    
    
    71
    %
    
    70
    %
    
    65-75
    %Debt
      securities
    
    
    22
    %
    
    23
    %
    
    20-30
    %Real
      estate
    
    
    6
    %
    
    7
    %
    
    0-10
    %Other
    
    
    1
    %
    
    -
    %
    
    0-5
    %Total
    
    
    100
    %
    
    100
    %





The
Company’s postretirement benefit plan asset allocations at December 31,
2004, and 2003, are as follows:





**Percentage
      of****Plan
      Assets****at
      December 31**
    
    **Target****2004**
    
    
    **2003**
    
    
    **Range****Asset
      Category**Equity
      securities
    
    
    49
    %
    
    49
    %
    
    45-55
    %Debt
      securities
    
    
    47
    %
    
    48
    %
    
    45-55
    %Other
    
    
    4
    %
    
    3
    %
    
    0-10
    %Total
    
    
    100
    %
    
    100
    %





93





Cash
Flows





MidAmerican
Energy’s expected benefit payments for its pension and postretirement plans for
2005 through 2009 and for the five years thereafter are summarized below (in
thousands):





Pension
      Benefits
    
    Postretirement
      Benefits2005
    
    $
    30,670
    
    $
    12,2412006
    
    
    32,728
    
    
    11,7312007
    
    
    34,972
    
    
    12,6182008
    
    
    38,092
    
    
    13,4322009
    
    
    42,339
    
    
    14,3212010-14
    
    $
    267,549
    
    $
    87,264





Employer
contributions to the domestic pension and postretirement plans are currently
expected to be $6.6 million and $15.8 million, respectively, for 2005.
The Company’s policy is to contribute the minimum required amount to the pension
plan and the amount expensed to its postretirement plans.





The
Company sponsors defined contribution pension plans (401(k) plans) covering
substantially all domestic employees. The Company’s contributions vary depending
on the plan but are based primarily on each participant’s level of contribution
and cannot exceed the maximum allowable for tax purposes. Total contributions
were $17.1 million, $15.5 million and $12.0 million for 2004,
2003 and 2002, 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. The Medicare Act is
expected to ultimately reduce the Company’s postretirement costs from what they
would have been absent such changes. Detailed regulations pertaining to the
Medicare Act were promulgated in July 2004, resulting in a $23.8 million
reduction in the accumulated postretirement obligation, which has been reflected
as an actuarial gain in the table above. The impact of the Medicare Act on the
net periodic postretirement benefit expense will initially be recognized in 2005
in conjunction with the next valuation of the postretirement plans.





*United
Kingdom Operations*





Certain
wholly-owned subsidiaries of CE Electric UK participate in the Electricity
Supply Pension Scheme (the “UK Plan”), which provides pension and other related
defined benefits, based on final pensionable pay, to substantially all employees
throughout the electricity supply industry in the United Kingdom.





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





**Pension
      Cost****2004**
    
    
    **2003**
    
    
    **2002**Service
      cost
    
    $
    12,100
    
    $
    9,485
    
    $
    8,718Interest
      cost
    
    
    73,515
    
    
    62,632
    
    
    56,817Expected
      return on plan assets
    
    
    (98,448
    )
    
    (89,124
    )
    
    (85,927
    )Amortization
      of prior service cost
    
    
    1,915
    
    
    1,472
    
    
    1,202Amortization
      of loss
    
    
    12,742
    
    
    537
    
    
    -Curtailment
      loss
    
    
    -
    
    
    -
    
    
    6,463Net
      periodic expense (benefit)
    
    $
    1,824
    
    $
    (14,998
    )
    $
    (12,727
    )





94





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





**2004**
    
    
    **2003**
    
    
    **2002**Discount
      rate
    
    
    5.25
    %
    
    5.50
    %
    
    5.75
    %Rate
      of compensation increase
    
    
    2.75
    %
    
    2.75
    %
    
    2.50
    %





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





**2004**
    
    
    **2003**
    
    
    **2002**Discount
      rate
    
    
    5.50
    %
    
    5.75
    %
    
    5.75
    %Expected
      return on plan assets
    
    
    7.00
    %
    
    7.00
    %
    
    7.00
    %Rate
      of compensation increase
    
    
    2.75
    %
    
    2.50
    %
    
    2.50
    %





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):





**Pension
      Benefits****2004**
    
    
    **2003**Reconciliation
      of the fair value of plan assets:Fair
      value of plan assets at beginning of year
    
    $
    1,206,216
    
    $
    976,427Employer
      contributions
    
    
    17,600
    
    
    14,391Participant
      contributions
    
    
    6,417
    
    
    4,742Actual
      return on plan assets
    
    
    106,515
    
    
    152,246Benefits
      paid
    
    
    (65,265
    )
    
    (57,726
    )Foreign
      currency exchange rate changes
    
    
    93,239
    
    
    116,136Fair
      value of plan assets at end of year
    
    $
    1,364,722
    
    $
    1,206,216Reconciliation
      of benefit obligation:Benefit
      obligation at beginning of year
    
    $
    1,334,587
    
    $
    1,102,730Service
      cost
    
    
    12,100
    
    
    9,485Interest
      cost
    
    
    73,515
    
    
    62,632Participant
      contributions
    
    
    6,417
    
    
    4,742Benefits
      paid
    
    
    (65,265
    )
    
    (57,726
    )Experience
      loss and change of assumptions
    
    
    104,315
    
    
    83,890Foreign
      currency exchange rate changes
    
    
    105,910
    
    
    128,834Benefit
      obligation at end of year
    
    $
    1,571,579
    
    $
    1,334,587Funded
      status
    
    $
    (206,857
    )
    $
    (128,371
    )Unrecognized
      net loss
    
    
    614,182
    
    
    507,039Net
      amount recognized in the consolidated balance sheets
    
    $
    407,325
    
    $
    378,668Amounts
      recognized in the consolidated balance sheets consist of:Prepaid
      benefit cost
    
    $
    407,325
    
    $
    378,668Accrued
      benefit liability
    
    
    (561,988
    )
    
    (496,147
    )Intangible
      assets
    
    
    16,119
    
    
    16,604Accumulated
      other comprehensive income
    
    
    545,869
    
    
    479,543Net
      amount recognized
    
    $
    407,325
    
    $
    378,668





The
accumulated benefit obligation for the defined benefit pension plan was $1.5
billion and $1.3 billion at December 31, 2004 and 2003, respectively.





The
Company recorded a minimum pension liability as of December 31, 2004 and
2003 in the amount of $545.9 million and $479.5 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 2004 and 2003, as well as, mortality assumption changes which
increased the liability. As of December 31, 2004 and 2003, 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, 2004 and 2003 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 $27.1 million in 2004 and 2003, respectively. This
adjustment does not impact current year earnings, or the funding requirements of
the plan.




95





Plan
Assets





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





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





**Percentage
      of****Plan
      Assets****at
      December 31****,****2004**
    
    
    **2003**
    
    
    **Target****Asset
      Category**Equity
      securities
    
    
    49
    %
    
    64
    %
    
    50
    %Debt
      securities
    
    
    39
    %
    
    26
    %
    
    40
    %Real
      estate
    
    
    11
    %
    
    9
    %
    
    10
    %Other
    
    
    1
    %
    
    1
    %
    
    -Total
    
    
    100
    %
    
    100
    %
    
    100
    %





Cash
Flows





CE
Electric UK's expected benefit payments relative to the UK Plan for 2005 through
2009 and for the five years thereafter are summarized below (in
millions):





2005
    $
    67.52006
    
    67.02007
    
    67.72008
    
    68.12009
    
    70.52010-14
    $
    369.8





Employer
contributions to fund the ongoing liabilities of the UK Plan were approximately
$14.7 million in 2004. The triennial process of valuing the UK Plan's assets and
liabilities, which will value the plan assets and liabilities as of
March 31, 2004, is underway. This valuation will set a revised level
of contributions for the next three years. The preliminary report of the
actuaries conducting the valuation showed a funding deficiency of $365.2
million. Based on the preliminary valuation, CE Electric UK has proposed that
its subsidiaries contribute $63.6 million to the UK Plan each year, which
amount includes $42.7 million 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. Discussions on the appropriate level of contributions
continue with the UK Plan trustees in accordance with the UK Plan
rules.




96








**23.**  **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 and
CalEnergy Generation-Foreign. 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
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 accompanying consolidated financial statements. Information related
to the Company’s reportable segments is shown below (in thousands).





**Year
      Ended December 31,****2004**
    
    
    **2003**
    
    
    **2002****Operating
      revenue:**MidAmerican
      Energy
    
    $
    2,701,700
    
    $
    2,600,239
    
    $
    2,240,879Kern
      River
    
    
    316,131
    
    
    260,182
    
    
    127,254Northern
      Natural Gas
    
    
    544,822
    
    
    486,878
    
    
    178,118CE
      Electric UK
    
    
    936,364
    
    
    829,993
    
    
    795,366CalEnergy
      Generation-Foreign
    
    
    307,395
    
    
    326,454
    
    
    326,316CalEnergy
      Generation-Domestic
    
    
    38,960
    
    
    45,154
    
    
    38,478HomeServices
    
    
    1,756,454
    
    
    1,476,569
    
    
    1,138,332Total
      reportable segments
    
    
    6,601,826
    
    
    6,025,469
    
    
    4,844,743Corporate/other(1)
    
    
    (48,438
    )
    
    (59,839
    )
    
    (49,564
    )Total
      operating revenue
    
    $
    6,553,388
    
    $
    5,965,630
    
    $
    4,795,179**Depreciation
      and amortization:**MidAmerican
      Energy
    
    $
    266,409
    
    $
    281,001
    
    $
    269,412Kern
      River
    
    
    53,250
    
    
    36,771
    
    
    17,165Northern
      Natural Gas
    
    
    67,913
    
    
    52,716
    
    
    18,151CE
      Electric UK
    
    
    137,746
    
    
    125,000
    
    
    116,792CalEnergy
      Generation-Foreign
    
    
    90,328
    
    
    87,928
    
    
    88,036CalEnergy
      Generation-Domestic
    
    
    8,721
    
    
    8,882
    
    
    8,648HomeServices
    
    
    20,827
    
    
    17,560
    
    
    22,072Total
      reportable segments
    
    
    645,194
    
    
    609,858
    
    
    540,276Corporate/other(1)
    
    
    (6,985
    )
    
    (6,924
    )
    
    (10,198
    )Total
      depreciation and amortization
    
    $
    638,209
    
    $
    602,934
    
    $
    530,078**Interest
      expense:**MidAmerican
      Energy
    
    $
    125,189
    
    $
    123,395
    
    $
    122,561Kern
      River
    
    
    76,671
    
    
    79,272
    
    
    47,034Northern
      Natural Gas
    
    
    53,100
    
    
    56,008
    
    
    23,550CE
      Electric UK
    
    
    202,067
    
    
    180,207
    
    
    189,554CalEnergy
      Generation-Foreign
    
    
    42,696
    
    
    59,603
    
    
    68,338CalEnergy
      Generation-Domestic
    
    
    18,971
    
    
    19,736
    
    
    20,043HomeServices
    
    
    2,837
    
    
    3,864
    
    
    4,256Total
      reportable segments
    
    
    521,531
    
    
    522,085
    
    
    475,336Corporate/other(1)
    
    
    184,811
    
    
    189,083
    
    
    156,797Parent
      company subordinated debt(2)
    
    
    196,875
    
    
    49,788
    
    
    -Total
      interest expense
    
    $
    903,217
    
    $
    760,956
    
    $
    632,133







97








**Year
      Ended December 31,****2004**
    
    
    **2003**
    
    
    **2002****Income
      from continuing operations before income tax expense, minority interest
      and preferred dividends of subsidiaries and equity
      income:**MidAmerican
      Energy
    
    $
    267,838
    
    $
    271,437
    
    $
    238,761Kern
      River
    
    
    142,643
    
    
    133,720
    
    
    60,700Northern
      Natural Gas
    
    
    217,981
    
    
    127,307
    
    
    42,882CE
      Electric UK
    
    
    325,844
    
    
    288,720
    
    
    266,755CalEnergy
      Generation-Foreign
    
    
    165,703
    
    
    177,568
    
    
    147,936CalEnergy
      Generation-Domestic
    
    
    3,071
    
    
    2,120
    
    
    (1,155
    )HomeServices
    
    
    111,906
    
    
    89,981
    
    
    61,202Total
      reportable segments
    
    
    1,234,986
    
    
    1,090,853
    
    
    817,081Corporate/other(1)
      (2)
    
    
    (435,793
    )
    
    (232,862
    )
    
    (185,443
    )Total
      income from continuing operations before income tax expense, minority
      interest and preferred dividends of subsidiaries and equity
      income
    
    $
    799,193
    
    $
    857,991
    
    $
    631,638**Income
      tax expense:**MidAmerican
      Energy
    
    $
    87,336
    
    $
    110,078
    
    $
    99,782Kern
      River
    
    
    54,148
    
    
    51,319
    
    
    23,014Northern
      Natural Gas
    
    
    84,423
    
    
    50,599
    
    
    16,947CE
      Electric UK
    
    
    80,211
    
    
    91,539
    
    
    25,245CalEnergy
      Generation-Foreign
    
    
    62,548
    
    
    62,130
    
    
    31,924CalEnergy
      Generation-Domestic
    
    
    1,217
    
    
    1,078
    
    
    (4,611
    )HomeServices
    
    
    52,996
    
    
    43,587
    
    
    28,207Total
      reportable segments
    
    
    422,879
    
    
    410,330
    
    
    220,508Corporate/other(1)
    
    
    (157,893
    )
    
    (140,054
    )
    
    (109,230
    )Total
      income tax expense
    
    $
    264,986
    
    $
    270,276
    
    $
    111,278**Capital
      expenditures:**MidAmerican
      Energy
    
    $
    633,807
    
    $
    346,449
    
    $
    332,845Kern
      River
    
    
    26,936
    
    
    433,125
    
    
    692,586Northern
      Natural Gas
    
    
    138,747
    
    
    104,400
    
    
    62,409CE
      Electric UK
    
    
    334,458
    
    
    301,896
    
    
    222,622CalEnergy
      Generation-Foreign
    
    
    4,633
    
    
    8,497
    
    
    7,830CalEnergy
      Generation-Domestic
    
    
    1,341
    
    
    6,619
    
    
    (1,640
    )HomeServices
    
    
    20,786
    
    
    18,311
    
    
    18,273Total
      reportable segments
    
    
    1,160,708
    
    
    1,219,297
    
    
    1,334,925Corporate/other(1)
    
    
    18,682
    
    
    71
    
    
    7,373Total
      capital expenditures
    
    $
    1,179,390
    
    $
    1,219,368
    
    $
    1,342,298





98








**As
      of December 31,****2004**
    
    **2003**
    
    **2002****Total
      assets:**MidAmerican
      Energy
    
    $
    7,274,999
    
    $
    6,596,849
    
    $
    6,411,143Kern
      River
    
    
    2,135,265
    
    
    2,200,201
    
    
    1,797,850Northern
      Natural Gas
    
    
    2,200,846
    
    
    2,167,621
    
    
    2,162,367CE
      Electric UK
    
    
    5,794,887
    
    
    5,038,880
    
    
    4,714,459CalEnergy
      Generation-Foreign
    
    
    767,465
    
    
    951,155
    
    
    974,852CalEnergy
      Generation-Domestic
    
    
    553,741
    
    
    1,113,172
    
    
    1,145,456HomeServices
    
    
    724,592
    
    
    567,736
    
    
    488,324Total
      reportable segments
    
    
    19,451,795
    
    
    18,635,614
    
    
    17,694,451Corporate/other(1)
    
    
    451,767
    
    
    509,338
    
    
    740,469Total
      assets
    
    $
    19,903,562
    
    $
    19,144,952
    
    $
    18,434,920**Long-lived
      assets:**MidAmerican
      Energy
    
    $
    3,892,031
    
    $
    3,385,056
    
    $
    3,236,046Kern
      River
    
    
    1,945,094
    
    
    1,976,213
    
    
    1,650,387Northern
      Natural Gas
    
    
    1,491,428
    
    
    1,430,475
    
    
    1,403,748CE
      Electric UK
    
    
    3,691,459
    
    
    3,227,723
    
    
    2,741,277CalEnergy
      Generation-Foreign
    
    
    520,406
    
    
    621,674
    
    
    724,908CalEnergy
      Generation-Domestic
    
    
    256,429
    
    
    738,296
    
    
    739,940HomeServices
    
    
    59,827
    
    
    53,518
    
    
    45,078Total
      reportable segments
    
    
    11,856,674
    
    
    11,432,955
    
    
    10,541,384Corporate/other(1)
    
    
    (249,410
    )
    
    (251,976
    )
    
    (256,897
    )Total
      long-lived assets
    
    $
    11,607,264
    
    $
    11,180,979
    
    $
    10,284,487





(1)
    The
      remaining differences between the segment amounts and the consolidated
      amounts described as “Corporate/other” relate principally to the corporate
      functions including administrative costs, interest expense, corporate cash
      and related interest income, intersegment eliminations and 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
      amounts previously recorded in minority interest and preferred dividends
      of subsidiaries to be recorded as interest expense in the accompanying
      consolidated statements of operations. For the year ended
      December 31, 2004, and the three-month period ended December 31,
      2003, the Company has recorded $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 amounts
      included in minority interest and preferred dividends of subsidiaries
      related to these securities for the nine-month period ended
      September 30, 2003, and the year ended December 31, 2002, were
      $170.2 million and $147.7 million,
  respectively.




99





The
following table shows the change in the carrying amount of goodwill by
reportable segment for the years ended December 31, 2004 and 2003 (in
thousands):




**MidAmerican
      Energy**
    
    **Kern**
      **River**
    
    **Northern**
      **Natural**
      **Gas**
    
    **CE
      Electric**
      **UK**
    
    **Cal
      Energy**
      **Generation**
      **Domestic**
    
    **Home-**
      **Services**
    
    **Total****Balance,
      January 1, 2003**
    $2,149,282
    
    $32,547
    
    $414,721
    
    $1,195,321
    
    $126,440
    
    $339,821
    
    $4,258,132Goodwill
      from acquisitions during the year
    -
    
    -
    
    -
    
    -
    
    -
    
    26,648
    
    26,648Other
      goodwill adjustments**(1)**
    (10,059)
    
    1,353
    
    (35,573)
    
    66,262
    
    (132)
    
    (988)
    
    20,863**Balance,
      December 31, 2003**
    2,139,223
    
    33,900
    
    379,148
    
    1,261,583
    
    126,308
    
    365,481
    
    4,305,643Goodwill
      from acquisitions during the year
    -
    
    -
    
    -
    
    -
    
    -
    
    32,120
    
    32,120Impairment
      losses**(2)**
    -
    
    -
    
    -
    
    -
    
    (52,776)
    
    -
    
    (52,776)Other
      goodwill adjustments**(1)**
    (18,098)
    
    -
    
    (24,236)
    
    68,208
    
    (1,038)
    
    (3,072)
    
    21,764**Balance,
      December 31, 2004**
    $2,121,125
    
    $33,900
    
    $354,912
    
    $1,329,791
    
    $72,494
    
    $394,529
    
    $4,306,751
   (1)
    Other
      goodwill adjustments include income tax, foreign currency translation and
      purchase price adjustments.
 
 (2)
    Impairment
      losses relate to the write-off of the Mineral Assets - see Note
      3.








100


****




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, 2004. Based on that evaluation, the Company’s management,
including the chief executive officer and chief financial officer, concluded
that the Company’s disclosure controls and procedures were effective. There have
been no significant changes during the fourth quarter of 2004 in the Company’s
internal controls or in other factors that could significantly affect internal
controls.


****


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





None.




101





**PART
III**




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





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





**Name**
    **Position**David
      L. Sokol
    Chairman
      of the Board, Chief Executive Officer and DirectorGregory
      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 SecretaryKeith
      D. Hartje
    Senior
      Vice President, Communications, General Services and Safety Audit and
      ComplianceWarren
      E. Buffett
    DirectorWalter
      Scott Jr.
    DirectorMarc
      D. Hamburg
    DirectorW.
      David Scott
    DirectorEdgar
      D. Aronson
    DirectorJohn
      K. Boyer
    DirectorStanley
      J. Bright
    DirectorRichard
      R. Jaros
    Director





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





Set forth
below is certain information, as of January 1, 2005, with respect to each
of the foregoing officers and directors:





DAVID L.
SOKOL, 48, 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, 42, 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
Price Waterhouse. As a Manager in the San Francisco office of Price Waterhouse,
he was responsible for clients in the energy industry.





PATRICK
J. GOODMAN, 38, Senior Vice President and Chief Financial Officer.
Mr. Goodman joined MEHC in 1995 and served in various accounting positions
including Senior Vice President and Chief Accounting Officer. Prior to joining
MEHC, Mr. Goodman was a financial manager for National Indemnity Company
and a senior associate at Coopers & Lybrand.





DOUGLAS
L. ANDERSON, 46, Senior Vice President and General Counsel. Mr. Anderson joined
MEHC in February 1993 and has served in various legal positions including
General Counsel of the Company’s independent power affiliates. From 1990 to
1993, Mr. Anderson was a corporate attorney with Fraser, Stryker in Omaha,
NE. Prior to that Mr. Anderson was a principal in the firm Anderson and
Anderson.





KEITH D.
HARTJE, 54, Senior Vice President, 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.




102





WARREN E.
BUFFETT, 74, 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, the Gillette
Company and The Washington Post Company.





WALTER
SCOTT, JR., 73, Director. Mr. Scott has been a director of MEHC since June
1991. Mr. Scott was the Chairman and Chief Executive Officer of MEHC from
January 8, 1992 until April 19, 1993. For more than the past five years, he has
been Chairman of the Board of Directors of Level 3 Communications, Inc., a
successor to certain businesses of Peter Kiewit & Sons’, Inc. Mr. Scott
is a director of Peter Kiewit & Sons’, Inc., Berkshire Hathaway, Burlington
Resources, Inc., ConAgra, Inc., Valmont Industries, Inc., Kiewit Materials Co.,
Commonwealth Telephone Enterprises, Inc. and RCN Corporation. Mr. Scott is
the father of W. David Scott.





MARC D.
HAMBURG, 55, 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.





W. DAVID
SCOTT, 43, Director. Mr. Scott has been a director of MEHC since March
2000. Mr. Scott formed Magnum Resources, Inc., a commercial real estate
investment and management company, in October 1994 and has served as its
President and Chief Executive Officer since its inception. Before forming Magnum
Resources, Mr. Scott worked for America First Companies, Cornerstone
Banking Group and Peter Kiewit & Sons’, Inc. Mr. Scott has been a
director of America First Mortgage Investments, Inc., a mortgage REIT, since
1998. Mr. Scott is the son of Walter Scott, Jr.





EDGAR D.
ARONSON, 70, Director. Mr. Aronson has been a director of MEHC since 1983.
Mr. Aronson founded EDACO, Inc., a private venture capital company, in
1981, and has been President of EDACO, Inc. since that time. Prior to that,
Mr. Aronson was Chairman of Dillon, Read International from 1979 to 1981
and a General Partner in charge of the International Department of Salomon
Brothers Inc. from 1973 to 1979. Mr. Aronson served during 1962-1968 as
Vice President consecutively in the International Departments of First National
Bank of Chicago and Republic National Bank of New York. He founded the
International Department of Salomon Brothers and Hutzler in 1968.





JOHN K.
BOYER, 60, Director. Mr. Boyer has been a director of MEHC since March
2000. He is a partner with Fraser, Stryker, Meusey, Olson, Boyer & Bloch,
P.C. where he has practiced from 1973 to present with emphasis on corporate,
commercial, federal, state, and local taxation.





STANLEY
J. BRIGHT, 64, Director. Mr. Bright was Chairman and Chief Executive
Officer of MidAmerican Energy from July 1, 1995 until March 1999. Mr. Bright
joined Iowa-Illinois Gas and Electric Company (a predecessor of MidAmerican
Energy) as Vice President and Chief Financial Officer in 1986, became a director
in 1987, President and Chief Operating Officer in 1990, and Chairman and Chief
Executive Officer in 1991.





RICHARD
R. JAROS, 52, Director. Mr. Jaros has been a director of MEHC since March
1991. Mr. Jaros served as President and Chief Operating Officer of MEHC
from January 8, 1992 to April 19, 1993 and as Chairman of the Board
from April 19, 1993 to May 1994. Until July 1997, Mr. Jaros was
Executive Vice President and Chief Financial Officer of Peter Kiewit &
Sons’, Inc. and President of Kiewit Diversified Group, Inc., which is now Level
3 Communications, Inc. Mr. Jaros serves as director of Commonwealth
Telephone Enterprises, Inc., RCN Corporation and Level 3 Communications,
Inc.





**Audit
Committee Members and Financial Experts**





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





**Code
of Ethics**





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





103


****
 ****
 **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, 2004, 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
    
    
    2004
    
    $
    800,000
    
    $
    2,500,000
    
    $
    131,644
    
    $
    -
    
    $
    9,995Chairman
      and Chief
    
    
    2003
    
    
    800,000
    
    
    2,750,000
    
    
    141,501
    
    
    -
    
    
    9,800Executive
      Officer
    
    
    2002
    
    
    800,000
    
    
    2,750,000
    
    
    27,232,047
    
    
    -
    
    
    8,850Gregory
      E. Abel
    
    
    2004
    
    
    720,000
    
    
    2,200,000
    
    
    80,424
    
    
    -
    
    
    9,995President
      and
    
    
    2003
    
    
    700,000
    
    
    2,200,000
    
    
    87,162
    
    
    -
    
    
    9,800Chief
      Operating Officer
    
    
    2002
    
    
    540,000
    
    
    2,200,000
    
    
    -
    
    
    -
    
    
    8,857Patrick
      J. Goodman
    
    
    2004
    
    
    290,000
    
    
    295,000
    
    
    -
    
    
    257,664
    
    
    88,391Senior
      Vice President and
    
    
    2003
    
    
    275,000
    
    
    285,000
    
    
    -
    
    
    -
    
    
    108,631Chief
      Financial Officer
    
    
    2002
    
    
    248,000
    
    
    260,000
    
    
    209,970
    
    
    -
    
    
    (16,342
    )Douglas
      L. Anderson
    
    
    2004
    
    
    270,000
    
    
    240,000
    
    
    -
    
    
    151,585
    
    
    77,145Senior
      Vice President and
    
    
    2003
    
    
    260,000
    
    
    240,000
    
    
    -
    
    
    -
    
    
    83,703General
      Counsel
    
    
    2002
    
    
    200,000
    
    
    220,000
    
    
    -
    
    
    -
    
    
    (7,289
    )Keith
      D. Hartje
    
    
    2004
    
    
    180,000
    
    
    65,000
    
    
    -
    
    
    128,847
    
    
    54,774Senior
      Vice President,
    
    
    2003
    
    
    180,000
    
    
    65,000
    
    
    -
    
    
    -
    
    
    71,317Communications,
      General
    
    
    2002
    
    
    180,000
    
    
    65,000
    
    
    -
    
    
    -
    
    
    (3,015
    )Services
      and Safety Audit andCompliance





**______________**





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





(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 2004 for Mr. Sokol of $100,726 and
      for Mr. Abel of $73,859.





(3)
    Consists
      of the 2004 earnings on the MEHC Long-Term Incentive Partnership Plan
      (“LTIP”) awards not paid out in 2004 and 401(k) plan contributions. For
      2004, LTIP earnings on awards not paid out in 2004 were $78,396 for
      Mr. Goodman, $67,150 for Mr. Anderson and $44,979 for
      Mr. Hartje. Messrs. Sokol and Abel are not participants in the
      LTIP. Additionally, the amounts shown include company 401(k) contributions
      for 2004 for Messrs. Sokol, Abel, Goodman and Anderson of $9,995 and
      for Mr. Hartje of $9,795.





Pursuant
to MEHC’s Executive Incremental Profit Sharing Plan, Messrs. Sokol and Abel
are each eligible to receive a one-time profit sharing award of
$11.25 million, $18.75 million or $37.5 million based upon
achieving specified adjusted diluted earnings per share targets for any calendar
year from 2004 through 2007 and continued employment during such
time.





**Option
Grants in Last Fiscal Year**





MEHC did
not grant any options during 2004.





104





**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, 2004.





**Shares****Acquired****On**
    
    
    
    
    
    **Underlying
      Unexercised**
    
    
    **Value
      of Unexercised****Exercise**
    
    
    **Value**
    
    
    **Options
      Held (#)**
    
    
    **In-the-money
      Options ($)****(1)****Name**
    
    
    **(#**)****
    
    
    **Realized**
    
    
    **Exercisable**
    
    
    **Unexercisable**
    
    
    **Exercisable**
    
    
    **Unexercisable**David
      Sokol
    
    
    -
    
    
    -
    
    
    1,399,277
    
    
    -
    
    $
    113,073,927
    
    
    N/AGregory
      E. Abel
    
    
    -
    
    
    -
    
    
    649,052
    
    
    -
    
    $
    55,748,672
    
    
    N/APatrick
      J. Goodman
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Douglas
      L. Anderson
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Keith
      D. Hartje
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -




**______________**





(1)
    On
      March 14, 2000, MEHC was acquired by a private investor group. As a
      privately held company, MEHC has no publicly traded equity securities. The
      value shown is based on an assumed fair market value of the stock of $113
      per share as of December 31, 2004, as agreed to by MEHC
      stockholders.





****


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





**Number
      of**
    
    **Performance
      or****Shares,**
    
    **Other
      Period Until****Units
      or Other**
    
    **Maturation**
    
    **Threshold**
    
    **Target**
    
    **Maximum****Name**
    
    **Rights
      (#)**
    
    **Or
      Payout**
    
    **($)****(1)**
    
    **($)****(1)**
    
    **($)****(1)**Patrick
      J. Goodman
    
    N/A
    
    December
      31, 2008
    
    40,000
    
    N/A
    
    N/ADouglas
      L. Anderson
    
    N/A
    
    December
      31, 2008
    
    40,000
    
    N/A
    
    N/AKeith
      D. Hartje
    
    N/A
    
    December
      31, 2008
    
    40,000
    
    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 2004) 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**





All
directors, excluding Messrs. Sokol, Abel, Buffett and Walter Scott Jr., are
paid an annual retainer fee of $24,000 and a fee of $500 per day for attendance
at Board and Committee meetings. Directors who are employees are not entitled to
receive such fees. All directors are reimbursed for their expenses incurred in
attending Board meetings.





105





**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,
Goodman and Hartje 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 Company’s Named Executive Officers has or will have five years of
credited service with the Company as of their respective normal retirement age
and will be eligible to receive benefits under the 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, and
by benefits under the Iowa Resources Inc. and Subsidiaries Supplemental
Retirement Income Plan (the “IOR Supplemental Plan”), as
applicable.





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





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





106





The table
below shows the estimated aggregate 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
    
    1,000,000$2,000,000
    and
      greater
    
    $1,000,000
    
    $1,000,000
    
    $1,000,000


**Employment
Agreements**





Pursuant
to his employment agreement, Mr. Sokol serves as Chairman of MEHC’s Board
of Directors and Chief Executive Officer. The employment agreement provides that
Mr. Sokol is to receive an annual base salary of not less than $750,000,
senior executive employee benefits and annual bonus awards that shall not be
less than $675,000. Subject to an annual renewal provision, such agreement is
scheduled to expire on August 21, 2005.





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.





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





107





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





The
following table sets forth certain information regarding beneficial ownership of
the shares of MEHC’s common stock and certain information with respect to the
beneficial ownership of each director, its Named Executive Officers and all
directors and executive officers as a group as of January 31,
2005.





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





**______________**





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





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





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





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





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





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





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





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





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





108







Pursuant
to a shareholders agreement, following March 14, 2003, Walter Scott, Jr. or
any of the Scott Family Interests are able to require Berkshire Hathaway to
purchase, for an agreed value or an appraised value, any or all of Walter Scott,
Jr.’s and the Scott Family Interests’ shares of MEHC’s common stock, provided
that Berkshire Hathaway is then a purchaser of a type which is able to
consummate such a purchase without causing it or any of its affiliates or MEHC
or any of its subsidiaries to become subject to regulation as a registered
holding company or a subsidiary of a registered holding company under PUHCA.
Berkshire Hathaway is not currently such a purchaser. The consummation of such a
transaction could result in a change in control with respect to
MEHC.





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





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





Under a
subscription agreement with MEHC, 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.





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





In order
to finance its acquisition of Northern Natural Gas, on August 16, 2002,
MEHC sold to Berkshire Hathaway $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.





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





**Compensation
Committee Interlocks and Insider Participation**





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





109





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





Aggregate
fees billed to the Company as a consolidated entity during the fiscal years
ending December 31, 2004 and 2003 by the Company’s principal accounting
firm, Deloitte & Touche LLP and the member firms of Deloitte Touche
Tohmatsu, and their respective affiliates (collectively, “Deloitte &
Touche”), are set forth below. The audit committee has considered whether the
provision of the non-audit services described below is compatible with
maintaining the principal accountant’s independence.





**Year
      Ended December 31,****2004**
    
    **2003****(in
      millions)**Audit
      Fees(1)
    
    $
    3.2
    
    $
    2.6Audit-Related
      Fees(2)
    
    
    0.1
    
    
    0.3Tax
      Fees(3)
    
    
    0.4
    
    
    0.9All
      Other Fees(4)
    
    
    -
    
    
    -Total
      aggregate fees billed
    
    $
    3.7
    
    $
    3.8





**______________**





(1)
    Includes
      the aggregate fees billed for each of the last two fiscal years for
      professional services rendered by Deloitte & Touche 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 Deloitte & Touche 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 Deloitte & Touche 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.





(3)
    Includes
      the aggregate fees billed in each of the last two fiscal years for
      professional services rendered by Deloitte & Touche 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 Deloitte & Touche, other than the
      services reported as “Audit Fees,” “Audit-Related Fees,” or “Tax
      Fees”.





The audit
committee reviewed the non-audit services rendered by Deloitte & Touche in
and for fiscal 2004 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.





110








**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 112.See
      Schedule II on page 115.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.





111








**Schedule
I**


**MidAmerican
Energy Holdings Company**


**Parent
Company Only**


Condensed
Balance Sheets


As of
December 31, 2004 and 2003


(Amounts
in thousands)





**2004**
    
    
    **2003****ASSETS**Current
      assets:Cash
      and cash equivalents
    
    $
    349,689
    
    $
    328,750Investments
      in and advances to subsidiaries and joint ventures
    
    
    6,141,843
    
    
    5,731,915Equipment,
      net
    
    
    18,881
    
    
    15,388Goodwill
    
    
    1,299,560
    
    
    1,370,241Deferred
      charges and other assets
    
    
    168,805
    
    
    180,331**Total
      assets**
    
    $
    7,978,778
    
    $
    7,626,625**LIABILITIES
      AND STOCKHOLDERS**’**EQUITY**Current
      liabilities:Accounts
      payable and other liabilities
    
    $
    55,535
    
    $
    52,934Current
      portion of senior debt
    
    
    260,000
    
    
    -Current
      portion of subordinated debt
    
    
    188,543
    
    
    100,000Total
      current liabilities
    
    
    504,078
    
    
    152,934Other
      long-term accrued liabilities
    
    
    35,142
    
    
    31,298Notes
      payable — affiliate
    
    
    76,000
    
    
    86,045Senior
      debt
    
    
    2,771,957
    
    
    2,777,878Subordinated
      debt
    
    
    1,585,810
    
    
    1,772,146Total
      liabilities
    
    
    4,972,987
    
    
    4,820,301Deferred
      income
    
    
    30,229
    
    
    32,916Minority
      interest
    
    
    4,403
    
    
    1,963Stockholders’
      equity:Zero
      coupon convertible preferred stock — authorized 50,000 shares, no par
      value; 41,263 shares outstanding
    
    
    -
    
    
    -Common
      stock — authorized 60,000 shares, no par value; 9,081 and 9,281 shares
      issued and outstanding at December 31, 2004 and 2003,
      respectively
    
    
    -
    
    
    -Additional
      paid in capital
    
    
    1,950,663
    
    
    1,957,277Retained
      earnings
    
    
    1,156,843
    
    
    999,627Accumulated
      other comprehensive loss, net
    
    
    (136,347
    )
    
    (185,459
    )Total
      stockholders’ equity
    
    
    2,971,159
    
    
    2,771,445**Total
      liabilities and stockholders**’**equity**
    
    $
    7,978,778
    
    $
    7,626,625





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




112





**Schedule
I**


**MidAmerican
Energy Holdings Company**


**Parent
Company Only (continued)**


Condensed
Statements of Operations


For the
three years ended December 31, 2004


(Amounts
in thousands)





**2004**
    
    **2003**
    
    **2002****Revenues:**Equity
      in undistributed earnings of subsidiary companies and joint
      ventures
    
    $
    103,176
    
    $
    375,666
    
    $
    250,517Dividends
      and distributions from subsidiary companies and joint
    ventures
    
    
    330,678
    
    
    318,665
    
    
    351,847Interest
      and other income
    
    
    11,713
    
    
    19,377
    
    
    778Total
      revenues
    
    
    445,567
    
    
    713,708
    
    
    603,142**Costs
      and expenses:**General
      and administration
    
    
    30,209
    
    
    35,503
    
    
    31,914Depreciation
      and amortization
    
    
    5,219
    
    
    5,225
    
    
    5,271Interest,
      net of capitalized interest
    
    
    399,394
    
    
    247,509
    
    
    164,290Total
      costs and expenses
    
    
    434,822
    
    
    288,237
    
    
    201,475**Income
      before income taxes**
    
    
    10,745
    
    
    425,471
    
    
    401,667Income
      tax benefit
    
    
    (159,461
    )
    
    (160,298
    )
    
    (126,043
    )**Income
      before preferred dividends of subsidiaries**
    
    
    170,206
    
    
    585,769
    
    
    527,710Preferred
      dividends of subsidiaries
    
    
    -
    
    
    170,151
    
    
    147,667**Net
      income available to common and preferred
    stockholders**
    
    $
    170,206
    
    $
    415,618
    
    $
    380,043





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





113


Schedule
I


****


**MidAmerican
Energy Holdings Company**


**Parent
Company Only (continued)**


Condensed
Statements of Cash Flows


For the
three years ended December 31, 2004


(Amounts
in thousands)





**2004**
    
    **2003**
    
    **2002****Cash
      flows from operating activities**
    
    $
    (228,468
    )
    $
    (230,354
    )
    $
    (211,704
    )**Cash
      flows from investing activities:**Decrease
      (increase) in advances to and investments in subsidiaries and joint
      ventures
    
    
    116,167
    
    
    228,083
    
    
    (1,654,755
    )Other,
      net
    
    
    6,803
    
    
    (21,031
    )
    
    (2,840
    )Net
      cash flows from investing activities
    
    
    122,970
    
    
    207,052
    
    
    (1,657,595
    )**Cash
      flows from financing activities:**Purchase
      and retirement of common stock
    
    
    (20,000
    )
    
    -
    
    
    -Repayment
      of subordinated debt
    
    
    (100,000
    )
    
    (198,958
    )
    
    -Proceeds
      from senior debt
    
    
    249,765
    
    
    449,295
    
    
    700,000Repayments
      of senior debt
    
    
    -
    
    
    (215,000
    )
    
    -Proceeds
      from issuance of preferred stock
    
    
    -
    
    
    -
    
    
    402,000Proceeds
      from issuance of trust preferred securities
    
    
    -
    
    
    -
    
    
    1,273,000Net
      repayment of revolving credit facility
    
    
    -
    
    
    -
    
    
    (153,500
    )Other
    
    
    (3,328
    )
    
    (3,914
    )
    
    (34,096
    )Net
      cash flows from financing activities
    
    
    126,437
    
    
    31,423
    
    
    2,187,404**Net
      change in cash and cash equivalents**
    
    
    20,939
    
    
    8,121
    
    
    318,105**Cash
      and cash equivalents at beginning of year**
    
    
    328,750
    
    
    320,629
    
    
    2,524**Cash
      and cash equivalents at end of year**
    
    $
    349,689
    
    $
    328,750
    
    $
    320,629**Supplemental
      disclosures:**Interest
      paid, net of interest capitalized
    
    $
    392,390
    
    $
    219,910
    
    $
    164,267Income
      tax receipts
    
    $
    (138,757
    )
    $
    (135,025
    )
    $
    (81,656
    )





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




114





**Schedule
II**


**MIDAMERICAN
ENERGY HOLDINGS COMPANY**


**CONSOLIDATED
VALUATION AND QUALIFYING ACCOUNTS**


**FOR
THE THREE YEARS ENDED DECEMBER 31, 2004**


(Amounts
in thousands)





**Column
      B**
    
    **Column
      C**
    
    
    
    **Column
      E****Balance
      at**
    
    **Charged**
    
    
    
    
    
    
    
    **Balance****Column
      A**
    
    **Beginning**
    
    **to**
    
    **Other**
    
    **Acquisition**
    
    **Column
      D**
    
    **at
      End****Description**
    
    **of
      Year**
    
    **Income**
    
    **Accounts**
    
    **Reserves****(2)**
    
    **Deductions**
    
    **of
      Year**Reserves
      Deducted From Assets To Which They Apply:Reserve
      for uncollectible accounts receivable:Year
      ended 2004
    
    $
    26,004
    
    $
    15,304
    
    $
    -
    
    $
    -
    
    $
    (15,275
    )
    $
    26,033Year
      ended 2003
    
    $
    39,742
    
    $
    13,620
    
    $
    -
    
    $
    -
    
    $
    (27,358
    )
    $
    26,004Year
      ended 2002
    
    $
    7,319
    
    $
    27,782
    
    $
    -
    
    $
    10,142
    
    $
    (5,501
    )
    $
    39,742Reserves
      Not Deducted From Assets(1):Year
      ended 2004
    
    $
    17,417
    
    $
    4,048
    
    $
    -
    
    $
    -
    
    $
    (10,617
    )
    $
    10,848Year
      ended 2003
    
    $
    10,981
    
    $
    10,527
    
    $
    -
    
    $
    -
    
    $
    (4,091
    )
    $
    17,417Year
      ended 2002
    
    $
    13,631
    
    $
    2,798
    
    $
    247
    
    $
    -
    
    $
    (5,695
    )
    $
    10,981








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





(1)
    Reserves
      not deducted from assets include estimated liabilities for losses retained
      by MEHC for workers compensation, public liability and property damage
      claims.(2)
    Acquisition
      reserves represent the reserves recorded at Kern River and Northern
      Natural Gas at the date of acquisition.







115





**SIGNATURES**





Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the Registrant has duly caused this report to be signed on its behalf by
the undersigned thereunto duly authorized, in the City of Des Moines, State of
Iowa, on this 28 th day of
February 2005.





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**
    
    **Date**/s/
      David L. Sokol*
    
    February
      28, 2005David
      L. SokolChairman
      of the Board,Chief
      Executive Officer, and Director/s/
      Gregory E. Abel*
    
    February
      28, 2005Gregory
      E. AbelPresident,
      Chief Operating Officerand
      Director/s/
      Patrick J. Goodman*Patrick
      J. Goodman
    
    February
      28, 2005Senior
      Vice President andChief
      Financial Officer/s/
      Edgar D. Aronson*Edgar
      D. Aronson
    
    February
      28, 2005Director/s/
      Stanley J. Bright*Stanley
      J. Bright
    
    February
      28, 2005Director/s/
      Walter Scott, Jr.*Walter
      Scott, Jr.
    
    February
      28, 2005Director/s/
      Marc D. Hamburg*Marc
      D. Hamburg
    
    February
      28, 2005Director/s/
      Warren E. Buffett*Warren
      E. Buffett
    
    February
      28, 2005Director





116











**Signature**
    
    **Date**/s/
      John K. Boyer*John
      K. Boyer
    
    February
      28, 2005Director/s/
      W. David Scott*W.
      David Scott
    
    February
      28, 2005Director/s/
      Richard R. Jaros*Richard
      R. Jaros
    
    February
      28, 2005Director*By:  /s/
      Douglas L. AndersonDouglas
      L. Anderson
    
    February
      28, 2005Attorney-in-Fact




117











**EXHIBIT INDEX**





**Exhibit
      No.**3.1
    Amended
      and Restated Articles of Incorporation of MidAmerican Energy Holdings
      Company effective March 6, 2002 (incorporated by reference to Exhibit
      3.3 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K
      for the year ended December 31, 2001).3.2
    Bylaws
      of MidAmerican Energy Holdings Company (incorporated by reference to
      Exhibit 3.2 to MidAmerican Energy Holdings Company’s Annual Report on Form
      10-K/A for the year ended December 31, 1999).4.1
    Indenture,
      dated as of October 4, 2002, by and between 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
    Registration
      Rights Agreement, dated as of October 1, 2002, by and between
      MidAmerican Energy Holdings Company and Credit Suisse First Boston (as
      Representative for the Initial Purchasers) (incorporated by reference to
      Exhibit 4.3 of MidAmerican Energy Holdings Company’s Registration
      Statement No. 333-101699 dated December 6, 2002).4.4
    Indenture
      for the 6 1/4% Convertible Junior Subordinated Debentures due 2012, dated
      as of February 26, 1997, between 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).4.5
    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).4.6
    Form
      of First Supplemental Indenture for the 7.63% Senior Notes in the
      principal amount of $350,000,000 due 2007, dated as of October 28,
      1997, among 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).4.7
    Form
      of Second Supplemental Indenture for the 6.96% Senior Notes in the
      principal amount of $215,000,000 due 2003, 7.23% Senior Notes in the
      principal amount of $260,000,000 due 2005, 7.52% Senior Notes in the
      principal amount of $450,000,000 due 2008, and 8.48% Senior Notes in the
      principal amount of $475,000,000 due 2028, dated as of September 22,
      1998 between 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.)4.8
    Form
      of Third Supplemental Indenture for the 7.52% Senior Notes in the
      principal amount of $100,000,000 due 2008, dated as of November 13,
      1998, between 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).





118











**Exhibit
      No.**4.9
    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).4.10
    Subscription
      Agreement, dated as of March 14, 2000, executed by Berkshire Hathaway
      Inc. (incorporated by reference to Exhibit 4.10 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
    Subscription
      Agreement, dated as of March 7, 2002, executed by Berkshire Hathaway
      Inc. (incorporated by reference to Exhibit 4.12 to MidAmerican Energy
      Holdings Company’s Annual Report on Form 10-K for the year ended
      December 31, 2001).4.13
    Subscription
      Agreement, dated as of March 12, 2002, executed by Berkshire Hathaway
      Inc. (incorporated by reference to Exhibit 4.13 to MidAmerican Energy
      Holdings Company’s Annual Report on Form 10-K for the year ended
      December 31, 2001).4.14
    Amended
      and Restated Declaration of Trust of MidAmerican Capital Trust III, dated
      as of August 16, 2002 (incorporated by reference to Exhibit 4.14 of
      MidAmerican Energy Holdings Company’s Registration Statement No.
      333-101699 dated December 6, 2002).4.15
    Amended
      and Restated Declaration of Trust of MidAmerican Capital Trust II, dated
      as of March 12, 2002 (incorporated by reference to Exhibit 4.15 of
      MidAmerican Energy Holdings Company’s Registration Statement No.
      333-101699 dated December 6, 2002).4.16
    Amended
      and Restated Declaration of Trust of MidAmerican Capital Trust I, dated as
      of March 14, 2000 (incorporated by reference to Exhibit 4.16 of
      MidAmerican Energy Holdings Company’s Registration Statement No.
      333-101699 dated December 6, 2002).4.17
    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).4.18
    Subscription
      Agreement, dated as of August 16, 2002, executed by Berkshire
      Hathaway Inc. (incorporated by reference to Exhibit 4.18 of MidAmerican
      Energy Holdings Company’s Registration Statement No. 333-101699 dated
      December 6, 2002).4.19
    Shareholders
      Agreement, dated as of March 14, 2000 (incorporated by reference to
      Exhibit 4.19 of MidAmerican Energy Holdings Company’s Registration
      Statement No. 333-101699 dated December 6, 2002).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).
  119
 
  **Exhibit
      No.**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).





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 PNOC- Energy Development Corporation and Ormat, Inc. as amended by
      the First Amendment to 125 MW Power Plant Upper Mahiao Agreement, dated as
      of January 28, 1994, the Letter Agreement dated February 10,
      1994, the Letter Agreement dated February 18, 1994 and the Fourth
      Amendment to 125 MW Power Plant-Upper Mahiao Agreement, dated as of
      March 7, 1994 (incorporated by reference to Exhibit 10.95 to
      MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the
      year ended December 31, 1993).10.8
    Credit
      Agreement, dated April 8, 1994, among CE Cebu Geothermal Power
      Company, Inc., the Banks thereto, Credit Suisse as Agent (incorporated by
      reference to Exhibit 10.96 to MidAmerican Energy Holdings Company’s Annual
      Report on Form 10-K for the year ended December 31,
      1993).10.9
    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).10.10
    Pledge
      Agreement, dated as of April 8, 1994, among CE Philippines Ltd,
      Ormat-Cebu Ltd., Credit Suisse as Collateral Agent and CE Cebu Geothermal
      Power Company, Inc. (incorporated by reference to Exhibit 10.98 to
      MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the
      year ended December 31, 1993).10.11
    Overseas
      Private Investment Corporation Contract of Insurance, dated April 8,
      1994, between the Overseas Private Investment Corporation and the Company
      through its subsidiaries CE International Ltd., CE Philippines Ltd., and
      Ormat-Cebu Ltd. (incorporated by reference to Exhibit 10.99 to MidAmerican
      Energy Holdings Company’s Annual Report on Form 10-K for the year ended
      December 31, 1993).10.12
    180
      MW Power Plant-Mahanagdong Agreement, dated September 18, 1993,
      between PNOC- Energy Development Corporation and CE Philippines Ltd. and
      the Company, as amended by the First Amendment to Mahanagdong Agreement,
      dated June 22, 1994, the Letter Agreement dated July 12, 1994,
      the Letter Agreement dated July 29, 1994, and the Fourth Amendment to
      Mahanagdong Agreement, dated March 3, 1995 (incorporated by reference
      to Exhibit 10.1 00 to MidAmerican Energy Holdings Company’s Annual Report
      on Form 10-K for the year ended December 31,
1993).10.13
    Credit
      Agreement, dated as of June 30, 1994, among CE Luzon Geothermal Power
      Company, Inc., American Pacific Finance Company, the Lenders party
      thereto, and Bank of America National Trust and Savings Association as
      Administrative Agent (incorporated by reference to Exhibit 10.101 to
      MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for the
      year ended December 31, 1993).




120








**Exhibit
      No.**10.14
    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).10.15
    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).10.16
    Pledge
      Agreement, dated as of June 30, 1994, among CE Mahanagdong Ltd.,
      Kiewit Energy International (Bermuda) Ltd., Bank of America National Trust
      and Savings Association as Collateral Agent and CE Luzon Geothermal Power
      Company, Inc. (incorporated by reference to Exhibit 10.104 to MidAmerican
      Energy Holdings Company’s Annual Report on Form 10-K for the year ended
      December 31, 1993).10.17
    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).10.18
    231
      MW Power Plant-Malitbog Agreement, dated September 10, 1993, between
      PNOC- Energy Development Corporation and Magma Power Company and the First
      and Second Amendments thereto, dated December 8, 1993 and
      March 10, 1994, respectively (incorporated by reference to Exhibit
      10.106 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K
      for the year ended December 31, 1993).10.19
    Credit
      Agreement, dated as of November 10, 1994, among Visayas Power Capital
      Corporation, the Banks parties thereto and Credit Suisse, as Bank Agent
      (incorporated by reference to Exhibit 10.107 to MidAmerican Energy
      Holdings Company’s Annual Report on Form 10-K for the year ended
      December 31, 1993).10.20
    Finance
      Agreement, dated as of November 10, 1994, between Visayas Geothermal
      Power Company and Overseas Private Investment Corporation (incorporated by
      reference to Exhibit 10.108 to MidAmerican Energy Holdings Company’s
      Annual Report on Form 10-K for the year ended December 31,
      1993).10.21
    Pledge
      and Security Agreement, dated as of November 10, 1994, among Broad
      Street Contract Services, Inc., Magma Power Company, Magma Netherlands
      B.V. and Credit Suisse, as Bank Agent (incorporated by reference to
      Exhibit 10.109 to MidAmerican Energy Holdings Company’s Annual Report on
      Form 10-K for the year ended December 31, 1993).10.22
    Overseas
      Private Investment Corporation Contract of Insurance, dated
      December 21, 1994, between Overseas Private Investment Corporation
      and Magma Netherlands, B.V. (incorporated by reference to Exhibit 10.110
      to MidAmerican Energy Holdings Company’s Annual Report on Form10-K for the
      year ended December 31, 1993).10.23
    Agreement
      as to Certain Common Representations, Warranties, Covenants and Other
      Terms, dated November 10, 1994, between Visayas Geothermal Power
      Company, Visayas Power Capital Corporation, Credit Suisse, as Bank Agent,
      Overseas Private Investment Corporation and the Banks named therein
      (incorporated by reference to Exhibit 10.111 to MidAmerican Energy
      Holdings Company’s 1994 Annual Report on Form 10-K for the year ended
      December 31, 1993).10.24
    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).




121








**Exhibit
      No.**10.25
    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).10.26
    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).10.27
    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).10.28
    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).10.29
    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).10.30
    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).10.31
    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).10.32
    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).10.33
    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).10.34
    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).10.35
    Sixth
      Amendment to 180 MW Power Plant-Mahanagdong Agreement, dated
      August 31, 2003, between PNOC-Energy Development Corporation and CE
      Luzon Geothermal Power Company, Inc. (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).




122





**Exhibit
      No.**10.36
    Third
      Amendment to 231 MW Power Plant-Malitbog Agreement, dated August 31,
      2003, between PNOC-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).10.37
    Seventh
      Amendment to 125 MW Power Plant-Upper Mahiao Agreement, dated
      August 31, 2003, between PNOC-Energy Development Corporation and CE
      Cebu Geothermal Power Company, Inc. (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).10.38
    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).10.39
    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).10.40
    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).10.41
    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).10.42
    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).10.43
    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).10.44
    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).10.45
    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).10.46
    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).10.47
    Share
      Sale Agreement, dated as of August 6, 2001, among NPower Yorkshire
      Limited, Innogy Holdings plc, CE Electric UK plc and Northern Electric plc
      (incorporated by reference to Exhibit 10.63 of MidAmerican Energy Holdings
      Company’s Registration Statement No. 333-101699 dated December 6,
      2002).




123








**Exhibit
      No.**10.48
    Purchase
      Agreement, dated as of March 7, 2002, among The Williams Companies,
      Inc., Williams Gas Pipeline Company, LLC, Williams Western Pipeline
      Company LLC, Kern River Acquisition, LLC and MidAmerican Energy Holdings
      Company, KR Holding, LLC, KR Acquisition 1, LLC and KR Acquisition 2, LLC
      (incorporated by reference to Exhibit 99.2 to MidAmerican Energy Holdings
      Company’s Current Report on Form 8-K dated March 28,
      2002).10.49
    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.)10.50
    Purchase
      and Sale Agreement, dated as of July 28, 2002, between Dynegy Inc., NNGC
      Holding Company, Inc. and MidAmerican Energy Holdings Company
      (incorporated by reference to Exhibit 99.2 to MidAmerican Energy Holdings
      Company's Current Report on Form 8-K dated July 30,
  2002).10.51
    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).10.52
    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).10.53
    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).10.54
    Fiscal
      Agency Agreement, dated as of May 4, 1993, among Northern Natural Gas
      Company, Enron Corp. and Continental Bank, National Association, Fiscal
      Agent, relating to the $100,000,000 in principal amount of the 6.875%
      Senior Notes due 2005 (incorporated by reference to Exhibit 10.68 to
      MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for
      the quarter ended March 31, 2004).10.55
    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).10.56
    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).10.57
    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).10.58
    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).
  124
  **Exhibit
      No.**10.59
    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)10.60
    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).10.61
    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).10.62
    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).10.63
    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).10.64
    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).10.65
    First
      Supplemental Indenture, dated as of February 16, 2000, among Yorkshire
      Power Finance 2 Limited, Yorkshire Power Group Limited and The Bank of New
      York, Trustee, relating to the £155,000,000 in principal amount of the
      Reset Senior Notes due 2020 (incorporated by reference to Exhibit 10.79 to
      MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for
      the quarter ended March 31, 2004).10.66
    Trust
      Agreement, dated as of February 1, 2000, among Yorkshire Power Group
      Limited, YPG Holdings LLC and The Bank of New York, Trustee, relating to
      the $250,000,000 in principal amount of the 8.25% Pass-Through Asset Trust
      Securities due 2005 (incorporated by reference to Exhibit 10.80 to
      MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for
      the quarter ended March 31, 2004).10.67
    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).




125





**Exhibit
      No.**10.68
    Stock
      Redemption Agreement, dated as of January 8, 2004, between David L. Sokol
      and MidAmerican Energy Holdings Company (incorporated by reference to
      Exhibit 10.82 to MidAmerican Energy Holdings Company’s Quarterly Report on
      Form 10-Q for the quarter ended March 31, 2004).10.69
    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).10.70
    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 2020.10.71
    MidAmerican
      Energy Holdings Company Amended and Restated Long-Term Incentive
      Partnership Plan dated as of January 1, 2004.14.1
    MidAmerican
      Energy Holdings Company Code of Ethics for Chief Executive Officer, Chief
      Financial Officer and Other Covered Officers.21.1
    Subsidiaries
      of the Registrant.24.1
    Power
      of Attorney.31.1
    Chief
      Executive Officer’s Certificate Pursuant to Section 302 of the
      Sarbanes-Oxley Act of 2002.31.2
    Chief
      Financial Officer’s Certificate Pursuant to Section 302 of the
      Sarbanes-Oxley Act of 2002.32.1
    Chief
      Executive Officer’s Certificate Pursuant to Section 906 of the
      Sarbanes-Oxley Act of 2002.32.2
    Chief
      Financial Officer’s Certificate Pursuant to Section 906 of the
      Sarbanes-Oxley Act of 2002.







126