Document/ExhibitDescriptionPagesSize 1: 10-K Midamerican Energy Holdings Company 10-K 2005 HTML 2.02M
2: EX-3.1 Second Amended and Restated Articles of HTML 39K
Incorporation
3: EX-3.2 Amended and Restated Bylaws HTML 71K
4: EX-4.17 Amendment No. 1 to Shareholders Agreement HTML 63K
5: EX-10.72 Equity Commitment Agreement HTML 56K
6: EX-21.1 Subsidiaries of the Registrant HTML 81K
7: EX-24.1 Power of Attorney HTML 10K
8: EX-31.1 Section 302 CEO Certification HTML 16K
9: EX-31.2 Section 302 CFO Certification HTML 16K
10: EX-32.1 Section 906 CEO Certification HTML 9K
11: EX-32.2 Section 906 CFO Certification HTML 9K
(Exact
name of registrant as specified in its charter)
Iowa
94-2213782
(State
or other jurisdiction of
(I.R.S.
Employer
incorporation
or organization)
Identification
No.)
666
Grand Avenue, Des Moines, Iowa
50309
(Address
of principal executive offices)
(Zip
Code)
(515)
242-4300
(Registrant’s
telephone number, including area
code)
Securities
registered pursuant to Section 12(b) of the Act: N/A
Securities
registered pursuant to Section 12(g) of the Act: N/A
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined
in
Rule 405 of the Securities Act.
Yes
¨
No
T
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act.
Yes
T
No
o
Indicate
by check mark whether the registrant: (1) has filed all reports required to
be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements
for
the past 90 days. Yes ¨
No
T
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of the registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this
Form 10-K. T
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See the definition of
“accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange
Act. (Check one):
Large
accelerated filer ¨ Accelerated
filer ¨ Non-accelerated
filer T
Indicate
by check mark whether the registrant is a shell company (as defined in rule
12b-2 of the Exchange Act).
Yes
¨
No
T
All
of
the shares of common equity of MidAmerican Energy Holdings Company are privately
held by a limited group of investors. As of March 1, 2006, 50,544,482 shares
of
common stock were outstanding.
This
report contains statements that do not directly or exclusively relate to
historical facts. These statements are “forward-looking statements” within the
meaning of the Private Securities Litigation Reform Act of 1995. You can
typically identify forward-looking statements by the use of forward-looking
words, such as “may,”“will,”“could,”“project,”“believe,”“anticipate,”“expect,”“estimate,”“continue,”“potential,”“plan,”“forecast,” and similar
terms. These statements are based upon the Company’s current intentions,
assumptions, expectations and beliefs and are subject to risks, uncertainties
and other important factors. Many of these factors are outside the Company’s
control and could cause actual results to differ materially from those expressed
or implied by the Company’s forward-looking statements. These factors include,
among others:
·
general
economic, political and business conditions in the jurisdictions
in which
the Company’s facilities are
located;
·
the
financial condition and creditworthiness of the Company’s significant
customers and suppliers;
·
governmental,
statutory, legislative, regulatory or administrative initiatives,
including those relating to the recently enacted Energy Policy Act
of 2005
(“Energy Policy Act”), or ratemaking actions affecting the Company or the
electric or gas utility, pipeline or power generation
industries;
·
the
outcome of general rate cases and other proceedings conducted before
regulatory authorities;
·
weather
effects on sales and revenue;
·
changes
in expected customer growth or usage of electricity or
gas;
·
economic
or industry trends that could impact electricity or gas
usage;
·
increased
competition in the power generation, electric and gas utility or
pipeline
industries;
·
fuel,
fuel transportation and power costs and
availability;
·
continued
availability of accessible gas
reserves;
·
changes
in business strategy, development plans or customer or vendor
relationships;
·
availability,
terms and deployment of capital;
·
availability
of qualified personnel;
·
unscheduled
outages or repairs;
·
risks
relating to nuclear generation;
·
financial
or regulatory accounting principles or policies imposed by the Public
Company Accounting Oversight Board, the Financial Accounting Standards
Board (“FASB”), the U.S. Securities and Exchange Commission (“SEC”), the
Federal Energy Regulatory Commission (“FERC”), state public utility
commissions and similar entities with regulatory
oversight;
·
changes
in, and compliance with, environmental laws, regulations, decisions
and
policies that could increase operating and capital improvement costs
or
affect plant output and/or delay plant
construction;
·
the
Company’s ability to consummate the acquisition of PacifiCorp and,
following the consummation of such acquisition, to successfully integrate
PacifiCorp’s operations into the Company’s
business;
·
other
risks or unforeseen events, including wars, the effects of terrorism,
embargoes and other catastrophic events;
and
·
other
business or investment considerations that may be disclosed from
time to
time in SEC filings or in other publicly disseminated written
documents.
Further
details of the potential risks and uncertainties affecting the Company are
described in MidAmerican Energy Holdings Company’s filings with the SEC,
including Item 1A. Risk Factors and other discussions contained in this Form
10-K. MidAmerican Energy Holdings Company undertakes no obligation to publicly
update or revise any forward-looking statements, whether as a result of new
information, future events or otherwise. The foregoing review of factors should
not be construed as exclusive.
MidAmerican
Energy Holdings Company (“MEHC”) and its subsidiaries (together with MEHC, the
“Company”) are organized and managed as seven distinct platforms: MidAmerican
Funding, LLC (“MidAmerican Funding”) (which primarily includes MidAmerican
Energy Company (“MidAmerican Energy”)), Kern River Gas Transmission Company
(“Kern River”), Northern Natural Gas Company (“Northern Natural Gas”), CE
Electric UK Funding Company (“CE Electric UK”) (which primarily includes
Northern Electric Distribution Limited (“Northern Electric”) and Yorkshire
Electricity Distribution plc (“Yorkshire Electricity”)), CalEnergy
Generation-Foreign (the subsidiaries owning the Upper Mahiao, Malitbog and
Mahanagdong projects (collectively, the “Leyte Projects”) and the Casecnan
Project), CalEnergy Generation-Domestic (the subsidiaries owning interests
in
independent power projects in the United States), and HomeServices of America,
Inc. (collectively with its subsidiaries, “HomeServices”). Refer to Note 22 of
Notes to Consolidated Financial Statements included in Item 8. Financial
Statements and Supplementary Data of this Form 10-K for additional segment
information regarding the Company’s platforms. Through these platforms, the
Company owns and operates a combined electric and natural gas utility company
in
the United States, two natural gas pipeline companies in the United States,
two
electricity distribution companies in Great Britain, a diversified portfolio
of
domestic and international independent power projects and the second largest
residential real estate brokerage firm in the United States.
MEHC’s
energy subsidiaries generate, transmit, store, distribute and supply energy.
MEHC’s electric and natural gas utility subsidiaries currently serve
approximately 4.4 million electricity customers and approximately 688,000
natural gas customers. MEHC's natural gas pipeline subsidiaries operate
interstate natural gas transmission systems that have approximately 18,100
miles
of pipeline in operation, a peak delivery capacity of 6.6 billion cubic
feet of natural gas per day and transported approximately 7.8% of the total
natural gas consumed in the United States in 2005. The Company has interests
in
6,740 net owned megawatts of power generation facilities in operation and under
construction, including 5,166 net owned megawatts in facilities that are part
of
the regulated asset base of its electric utility business and 1,574 net owned
megawatts in non-utility power generation facilities. Substantially all of
the
non-utility power generation facilities have long-term contracts for the sale
of
energy and/or capacity from the facilities.
Each
of
MEHC’s direct and indirect subsidiaries is organized as a legal entity separate
and apart from MEHC and its other subsidiaries. Pursuant to separate project
financing agreements, all or substantially all of the assets of each subsidiary
are or may be pledged or encumbered to support or otherwise provide the security
for their own project or subsidiary debt. It should not be assumed that any
asset of any such subsidiary will be available to satisfy the obligations of
MEHC or any of its other such subsidiaries; provided, however, that unrestricted
cash or other assets which are available for distribution may, subject to
applicable law and the terms of financing arrangements of such parties, be
advanced, loaned, paid as dividends or otherwise distributed or contributed
to
MEHC or affiliates thereof.
On
March 14, 2000, MEHC and an investor group including Berkshire Hathaway
Inc. (“Berkshire Hathaway”), Walter Scott, Jr., a director of MEHC, David L.
Sokol, Chairman and Chief Executive Officer of MEHC, and Gregory E. Abel,
President and Chief Operating Officer of MEHC, executed a definitive agreement
and plan of merger whereby the investor group acquired all of the outstanding
common stock of MEHC (the “Teton Transaction”). As of December 31, 2005
Walter Scott, Jr. (including family members and related entities), Berkshire
Hathaway, David L. Sokol and Gregory E. Abel owned 86.2%, 9.7%,
3.5% and 0.6%, respectively, of MEHC’s voting common stock and held diluted
ownership interests of 15.3%, 80.5%, 2.9% and 1.3%, respectively.
The
principal executive offices of MEHC are located at 666 Grand Avenue, Des Moines,
Iowa50309 and its telephone number is (515) 242-4300. MEHC initially
incorporated in 1971 under the laws of the state of Delaware and reincorporated
in 1999 in Iowa, at which time it changed its name from CalEnergy Company,
Inc.
to MidAmerican Energy Holdings Company.
4
In
this
annual report, references to “U.S. dollars,”“dollars,”“$” or “cents” are to
the currency of the United States, references to “pounds sterling,”“£,”“sterling,”“pence” or “p” are to the currency of Great Britain and references
to “pesos” are to the currency of the Philippines. References to kW means
kilowatts, MW means megawatts, GW means gigawatts, kWh means kilowatt hours,
MWh
means megawatt hours, GWh means gigawatt hours, kV means kilovolts, MMcf means
million cubic feet, Bcf means billion cubic feet, Tcf means trillion cubic
feet
and Dth means decatherms or one million British thermal units.
Recent
Developments Regarding the Pending PacifiCorp Acquisition
In
May
2005, MEHC reached a definitive agreement with Scottish Power plc
(“ScottishPower”) and its subsidiary, PacifiCorp Holdings, Inc., to acquire 100%
of the common stock of ScottishPower’s wholly-owned indirect subsidiary,
PacifiCorp, a regulated electric utility providing service to approximately
1.6 million customers in California, Idaho, Oregon, Utah, Washington and
Wyoming. MEHC will purchase all of the outstanding shares of the PacifiCorp
common stock for approximately $5.1 billion in cash. The long-term debt and
preferred stock of PacifiCorp, which aggregated $4.3 billion at
December 31, 2005, will remain outstanding. As of March 1, 2006, all
state and federal approvals required for the acquisition were
obtained, subject to completion of a "most favored states"
process in Wyoming, Washington, Utah, Idaho and Oregon that
allows each such state to make applicable to that state
any acquisition commitments or conditions accepted in other
PacifiCorp states. Subject to the most favored states process and other
customary closing conditions, the transaction is expected to close in March
2006. MEHC expects to fund the acquisition of PacifiCorp with the proceeds
from
an investment by Berkshire Hathaway and other existing shareholders of
approximately $3.4 billion in MEHC common stock and the issuance by MEHC of
$1.7 billion of either additional common stock to Berkshire Hathaway or
long-term senior notes to third parties.
Recent
Developments Regarding Berkshire Hathaway
On
February 9, 2006, following the effective date of the repeal of the Public
Utility Holding Company Act of 1935 (“PUHCA 1935”), Berkshire Hathaway converted
its 41,263,395 shares of MEHC’s no par zero-coupon convertible preferred stock
into an equal number of shares of MEHC’s common stock. As a consequence,
Berkshire Hathaway owns 83.4% (80.5% on a diluted basis) of the outstanding
common stock of MEHC, will consolidate the Company in its financial statements
as a majority-owned subsidiary, and will include the Company in its consolidated
federal U.S. income tax return.
On
March 1, 2006, MEHC and Berkshire Hathaway entered into an Equity
Commitment Agreement (the “Berkshire Equity Commitment”) pursuant to which
Berkshire Hathaway has agreed to purchase up to $3.5 billion of common
equity of MEHC upon any requests authorized from time to time by the Board
of
Directors of MEHC. The proceeds of any such equity contribution shall only
be
used for the purpose of (a) paying when due MEHC’s debt obligations and (b)
funding the general corporate purposes and capital requirements of the Company’s
regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund
any such request. The Berkshire Equity Commitment will expire on
February 28, 2011, and will not be used for the PacifiCorp acquisition
or for other future acquisitions.
MidAmerican
Energy
MidAmerican
Energy, an indirect wholly-owned subsidiary of MEHC, is a public utility company
headquartered in Iowa and is principally engaged in the business of generating,
transmitting, distributing and selling electric energy and in distributing,
selling and transporting natural gas. MidAmerican Energy distributes electricity
at retail in Council Bluffs, Des Moines, Fort Dodge, Iowa City, Sioux City
and
Waterloo, Iowa; the Quad Cities (Davenport and Bettendorf, Iowa and Rock Island,
Moline and East Moline, Illinois); and a number of adjacent communities and
areas. It also distributes natural gas at retail in Cedar Rapids, Des Moines,
Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities; Sioux
Falls, South Dakota; and a number of adjacent communities and areas.
Additionally, MidAmerican Energy transports natural gas through its distribution
system for a number of end-use customers who have independently secured their
supply of natural gas. As of December 31, 2005, MidAmerican Energy had
approximately 706,000 regulated retail electric customers and 688,000 regulated
retail and transportation natural gas customers.
In
addition to retail sales and natural gas transportation, MidAmerican Energy
sells electric energy and natural gas to other utilities, marketers and
municipalities. These sales are referred to as wholesale sales.
5
MidAmerican
Energy’s regulated electric and gas operations are conducted under franchise
agreements, certificates, permits and licenses obtained from state and local
authorities. The franchise agreements, with various expiration dates, are
typically for 25-year terms.
MidAmerican
Energy has a diverse customer base consisting of residential, agricultural,
and
a variety of commercial and industrial customer groups. Among the primary
industries served by MidAmerican Energy are those that are concerned with food
products, the manufacturing, processing and fabrication of primary metals,
real
estate, farm and other non-electrical machinery, and cement and gypsum
products.
MidAmerican
Energy also conducts a number of nonregulated business activities, which include
a variety of activities outside of the traditional regulated electric and
natural gas services.
MidAmerican
Energy derived its operating revenues from the following business
activities.
Small
general service generally includes commercial and industrial customers
with a demand of 200 kilowatts or less.
(2)
Large
general service generally includes commercial and industrial customers
with a demand of more than 200 kilowatts.
(3)
Wholesale
generally includes other utilities, marketers and municipalities
to whom
electric energy is sold at wholesale for resale to ultimate
customers.
The
percentage of regulated electric revenue by jurisdiction follows:
There
are
seasonal variations in MidAmerican Energy’s electric business that are
principally related to the use of electricity for air conditioning. In general,
35-40% of MidAmerican Energy’s regulated electric revenues are reported in the
months of June, July, August and September.
The
annual hourly peak demand on MidAmerican Energy’s electric system usually occurs
as a result of air conditioning use during the cooling season. On July 20,2005, retail customer usage of electricity caused a new record hourly peak
demand of 4,040 MW on MidAmerican Energy’s electric system, an increase of 105
MW from the previous record of 3,935 MW set in August 2003.
MidAmerican
Energy is exposed to fluctuations in energy costs relating to retail sales
in
Iowa as it does not have an energy adjustment clause. Under its Illinois and
South Dakota electric tariffs, MidAmerican Energy is allowed to recover
fluctuations in the cost of all fuels and purchased energy used for retail
electric generation through a fuel cost adjustment clause.
The
following table sets out certain information concerning MidAmerican Energy’s
power generation facilities based upon summer 2005 accreditation and expected
accredited generating capacity of projects recently completed or under
construction:
Facility
Net
Capacity
Net
MW
Energy
Year
Operating
Project(1)
(MW)(2)
Owned(2)
Source
Location
In-Service
Steam
Electric Generating Facilities:
Council
Bluffs Energy Center Units 1 and 2
133
133
Coal
Iowa
1954,
1958
Council
Bluffs Energy Center Unit 3
690
546
Coal
Iowa
1978
Louisa
Generation Station
700
616
Coal
Iowa
1983
Neal
Generation Station Units 1 and 2
435
435
Coal
Iowa
1964,
1972
Neal
Generation Station Unit 3
515
371
Coal
Iowa
1975
Neal
Generation Station Unit 4
644
261
Coal
Iowa
1979
Ottumwa
Generation Station
673
350
Coal
Iowa
1981
Riverside
Generation Station
135
135
Coal
Iowa
1925,
1961
Total
steam electric generating facilities
3,925
2,847
Other
Facilities:
Combustion
Turbines
792
792
Gas/Oil
Iowa
Various(3)
Combined
Cycle - Greater Des Moines Energy Center
491
491
Gas
Iowa
2003-2004
Quad
Cities Generating Station
1,748
437
Nuclear
Illinois
1972
Portable
Power Modules
56
56
Oil
Iowa
2000
Wind
- Intrepid(4)
33
33
Wind
Iowa
2005
Moline
Water Power
3
3
Water
Illinois
1970
Total
other facilities
3,123
1,812
Total
accredited generating capacity
7,048
4,659
Projects
Recently Completed or Under Construction:
Council
Bluffs Energy Center Unit 4
790
479
Coal
Iowa
2007
Wind
- Century(4)
28
28
Wind
Iowa
2005
Total
projects recently completed or under construction
818
507
7,866
5,166
7
______________
(1)
MidAmerican
Energy operates all such power generation facilities other than Quad
Cities Generating Station and Ottumwa Generation
Station.
(2)
Represents accredited net generating capacity from
the
summer of 2005 and the expected accredited generating capacity of projects
recently completed or under construction. Actual MW may vary depending
on
operating conditions and plant design for operating projects. Net MW
Owned
indicates ownership of accredited capacity for the summer of 2005 as
approved by the Mid-Continent Area Power Pool
(“MAPP”).
(3)
A
total of 629 MW were placed in-service between 1966 and 1978 while
the
three turbines totaling 120 MW at the Pleasant Hill facility were
placed
in-service between 1990 and 1994.
(4)
MidAmerican
Energy owns 360.5 MW (nameplate rating) of wind power facilities.
The 61
MW of accredited capacity ratings for these wind power facilities
included
in the table above are considerably less than the nameplate ratings
due to
the varying nature of wind.
MidAmerican
Energy’s total accredited net generating capability in the summer of 2005 was
5,098 MW. Accredited net generating capability represents the amount of
generation available to meet the requirements on MidAmerican Energy’s system and
consists of MidAmerican Energy-owned generation of 4,659 MW and the net amount
of capacity purchases and sales of 439 MW. Accredited capacity may vary from
the
nameplate capacity ratings. Additionally, the actual amount of generation
capacity available at any time may be less than the accredited capacity due
to
regulatory restrictions, transmission constraints, fuel restrictions and
generating units being temporarily out of service for inspection, maintenance,
refueling, modifications or other reasons.
In
2005,
MidAmerican Energy completed construction of its 360.5 MW (nameplate rating)
wind power project that consists of facilities located at two sites in north
central Iowa. As of December 31, 2004, wind turbines totaling 160.5 MW at
the Intrepid site were completed and in service, and in the third quarter of
2005, wind turbines totaling 150 MW at the Century site were placed in service.
The remaining 50 MW of wind turbines were completed in December 2005, of which
35 MW are located at the Century site and 15 MW are at the Intrepid site.
Generally speaking, accredited capacity ratings for wind power facilities are
considerably less than the nameplate ratings due to the varying nature of wind.
The current total projected accredited capacity for these wind power facilities
is approximately 61 MW. MidAmerican Energy owns and operates these facilities.
On December 16, 2005, MidAmerican Energy made a filing with the Iowa
Utilities Board (“IUB”) for approval to add up to 545 MW (nameplate rating) of
additional wind generation capacity in Iowa.
MidAmerican
Energy is currently constructing Council Bluffs Energy Center Unit No. 4 (“CBEC
Unit 4”), a 790 MW (based on expected accreditation) super-critical-temperature,
low sulfur coal-fired generating plant. MidAmerican Energy will operate the
plant and hold an undivided ownership interest as a tenant in common with the
other owners of the plant. MidAmerican Energy’s current ownership interest is
60.67%, equating to 479 MW of output. Municipal, cooperative and public power
utilities will own the remainder, which is a typical ownership arrangement
for
large base-load plants in Iowa. The facility will provide service to regulated
retail electricity customers. Wholesale sales may also be made from the project
to the extent the power is not immediately needed for regulated retail service.
MidAmerican Energy has obtained regulatory approval to include the Iowa portion
of the actual cost of the generation project in its Iowa rate base as long
as
the actual cost does not exceed the agreed cap that MidAmerican Energy has
deemed to be reasonable. If the cap is exceeded, MidAmerican Energy has the
right to demonstrate the prudence of the expenditures above the cap, subject
to
regulatory review. MidAmerican Energy expects to invest approximately
$737 million in CBEC Unit 4, including transmission facilities and
excluding allowance for funds used during construction. Through
December 31, 2005, MidAmerican Energy has invested $502.0 million in
the project, including $121.3 million for MidAmerican Energy’s share of
deferred payments allowed by the construction contract.
MidAmerican
Energy is interconnected with Iowa utilities and utilities in neighboring
states. MidAmerican Energy is also party to an electric generation reserve
sharing pool and regional transmission group administered by the MAPP. The
MAPP
is a voluntary association of electric utilities doing business in Minnesota,
Nebraska, North Dakota and the Canadian provinces of Saskatchewan and Manitoba
and portions of Iowa, Montana, South Dakota and Wisconsin. Its membership also
includes power marketers, regulatory agencies and independent power producers.
The MAPP performs functions including administration of its short-term regional
Open Access Transmission Tariff (“OATT”), coordination of regional planning and
operations, and operation of the generation reserve sharing pool.
8
Each
MAPP
generation reserve participant is required to maintain for emergency purposes
a
net generating capability reserve of at least 15% above its system peak demand
on a 12-month rolling basis. MidAmerican Energy’s reserve margin at peak demand
for 2005 was approximately 26%. MidAmerican Energy believes it has adequate
electric capacity reserve through 2009, including capacity provided by the
generating projects discussed above. However, significantly higher-than-normal
temperatures during the cooling season could cause MidAmerican Energy’s reserve
to fall below the 15% minimum. If MidAmerican Energy fails to maintain the
required minimum reserve, significant penalties could be contractually imposed
by the MAPP.
MidAmerican
Energy’s transmission system connects its generating facilities with
distribution substations and interconnects with 14 other transmission providers
in Iowa and five adjacent states. Under normal operating conditions, MidAmerican
Energy’s transmission system has adequate capacity to deliver energy to
MidAmerican Energy’s distribution system and to export and import energy with
other interconnected systems. The electric transmission system of MidAmerican
Energy at December 31, 2005, included 911 miles of 345-kV lines and 1,128
miles of 161-kV lines. MidAmerican Energy’s electric distribution system
included approximately 227,000 transformers and 400 substations at
December 31, 2005.
Natural
Gas Operations
MidAmerican
Energy is engaged in the procurement, transportation, storage and distribution
of natural gas for customers in the Midwest. MidAmerican Energy purchases
natural gas from various suppliers, transports it from the production area
to
MidAmerican Energy's service territory under contracts with interstate
pipelines, stores it in various storage facilities to manage fluctuations in
system demand and seasonal pricing, and distributes it to customers through
MidAmerican Energy's distribution system.
MidAmerican
Energy sells natural gas and transportation services to end-use, or retail,
customers and natural gas to other utilities, marketers and municipalities.
MidAmerican Energy also transports through its distribution system natural
gas
purchased independently by a number of end-use customers. During 2005, 46%
of
total natural gas delivered through MidAmerican Energy's system for end-use
customers was under natural gas transportation service.
There
are
seasonal variations in MidAmerican Energy’s natural gas business that are
principally due to the use of natural gas for heating. In general, 45-55% of
MidAmerican Energy’s regulated natural gas revenue is reported in the months of
January, February, March and December.
The
percentage of regulated natural gas revenue, excluding transportation
throughput, by customer class follows:
Small
and large general service customers are classified primarily based
on the
nature of their business and gas usage. Small general service customers
are business customers whose gas usage is principally for heating.
Large
general service customers are business customers whose principal
gas usage
is for their manufacturing processes.
(2)
Wholesale
generally includes other utilities, marketers and municipalities
to whom
natural gas is sold at wholesale for eventual resale to ultimate
end-use
customers.
9
The
percentage of regulated natural gas revenue, excluding transportation
throughput, by jurisdiction follows:
MidAmerican
Energy purchases natural gas supplies from producers and third-party marketers.
To enhance system reliability, a geographically diverse supply portfolio with
varying terms and contract conditions is utilized for the natural gas supplies.
MidAmerican Energy attempts to optimize the value of its regulated assets by
engaging in wholesale sales transactions. IUB and South Dakota Public Utilities
Commission (“SDPUC”) rulings have allowed MidAmerican Energy to retain 50% of
the respective jurisdictional margins earned on wholesale sales of natural
gas,
with the remaining 50% being returned to customers through the purchased gas
adjustment clauses discussed below.
MidAmerican
Energy has rights to firm pipeline capacity to transport natural gas to its
service territory through direct interconnects to the pipeline systems of
Northern Natural Gas (an affiliate company), Natural Gas Pipeline Company of
America (“NGPL”), Northern Border Pipeline Company (“Northern Border”) and ANR
Pipeline Company (“ANR”). At times, the capacity available through MidAmerican
Energy’s firm capacity portfolio may exceed the demand on MidAmerican Energy’s
distribution system. Firm capacity in excess of MidAmerican Energy’s system
needs can be resold to other companies to achieve optimum use of the available
capacity. Past IUB and SDPUC rulings have allowed MidAmerican Energy to retain
30% of the respective jurisdictional margins earned on the resold capacity,
with
the remaining 70% being returned to customers through the purchased gas
adjustment clauses.
MidAmerican
Energy is allowed to recover its cost of natural gas from all of its regulated
natural gas customers through purchased gas adjustment clauses. Accordingly,
as
long as MidAmerican Energy is prudent in its procurement practices, MidAmerican
Energy’s regulated natural gas customers retain the risk associated with the
market price of natural gas. MidAmerican Energy uses several strategies to
reduce the market price risk for its natural gas customers, including the use
of
storage gas and peak-shaving facilities, sharing arrangements to share savings
and costs with customers and short-term and long-term financial and physical
gas
purchase agreements.
MidAmerican
Energy utilizes leased gas storage to meet peak day requirements and to manage
the daily changes in demand due to changes in weather. The storage gas is
withdrawn during periods of peak demand and is typically replaced during
off-peak months when the demand for natural gas is historically lower than
during the heating season. In addition, MidAmerican Energy also utilizes three
liquefied natural gas (“LNG”) plants and two propane-air plants to meet peak day
demands in the winter. The storage and peak shaving facilities reduce
MidAmerican Energy’s dependence on natural gas purchases during the volatile
winter heating season. MidAmerican Energy can deliver approximately 50% of
its
design day sales requirements from its storage and peak shaving supply
sources.
In
1995,
the IUB gave initial approval of MidAmerican Energy’s Incentive Gas Supply
Procurement Program. In November 2004, the IUB extended the program through
October 31, 2006. Under the program, as amended, MidAmerican Energy is
required to file with the IUB every six months a comparison of its natural
gas
procurement costs to a reference price. If MidAmerican Energy’s cost of natural
gas for the period is less or greater than an established tolerance band around
the reference price, then MidAmerican Energy shares a portion of the savings
or
costs with customers. A similar program is currently in effect in South Dakota
through October 31, 2010. Since the implementation of the program,
MidAmerican Energy has successfully achieved and shared savings with its natural
gas customers.
On
February 2, 1996, MidAmerican Energy had its highest peak-day delivery of
1,143,026 Dth. This peak-day delivery consisted of 88% traditional sales service
and 12% transportation service of customer-owned gas. As of March 1, 2006,
MidAmerican Energy’s 2005/2006 winter heating season peak-day delivery of
1,004,109 Dth was reached on February 17, 2006. This peak-day delivery
included 74% traditional sales service and 26% transportation
service.
10
Natural
gas property consists primarily of natural gas mains and services pipelines,
meters, and related distribution equipment, including feeder lines to
communities served from natural gas pipelines owned by others. The gas
distribution facilities of MidAmerican Energy at December 31, 2005,
included approximately 21,900 miles of gas mains and services
pipelines.
Interstate
Pipeline Companies
Kern
River
Kern
River, an indirect wholly-owned subsidiary of MEHC, owns an interstate natural
gas transportation pipeline system comprising 1,679 miles of pipeline, with
an
approximate design capacity of 1,755,575 Dth per day, extending from supply
areas in the Rocky Mountains to consuming markets in Utah, Nevada and
California. On May 1, 2003, Kern River placed into service a 717-mile
expansion project (“2003 Expansion Project”), which increased the design
capacity of Kern River’s pipeline system by 885,575 Dth per day to its current
1,755,575 Dth per day. Except for quantities of natural gas owned for system
operations, Kern River does not own the natural gas that is transported through
its system. Kern River’s transportation operations are subject to a Federal
Energy Regulatory Commission (“FERC”) regulated tariff that is designed to allow
it an opportunity to recover its costs together with a regulated return on
equity.
Kern
River’s pipeline consists of two sections: the mainline section and the common
facilities. Kern River owns the entire mainline section, which extends from
the
pipeline’s point of origination near Opal, Wyoming through the Central Rocky
Mountains area into Daggett, California. The mainline section consists of the
original 682 miles of 36-inch diameter pipeline, 628 miles of 36-inch diameter
loop pipeline related to the 2003 Expansion Project and 68 miles of various
laterals that connect to the mainline.
The
common facilities consist of a 219-mile section of original pipeline that
extends from the point of interconnection with the mainline in Daggett to
Bakersfield, California and an additional 82 miles related to the 2003 Expansion
Project. The common facilities are jointly owned by Kern River (approximately
76.8% as of December 31, 2005) and Mojave Pipeline Company (“Mojave”), a
wholly-owned subsidiary of El Paso Corporation (“El Paso”), (approximately 23.2%
as of December 31, 2005) as tenants-in-common. Kern River’s ownership
percentage in the common facilities will increase or decrease pursuant to the
capital contributions made by the respective joint owners. Kern River has
exclusive rights to approximately 1,570,500 Dth per day of the common
facilities’ capacity, and Mojave has exclusive rights to 400,000 Dth per day of
capacity. Operation and maintenance of the common facilities are the
responsibility of Mojave Pipeline Operating Company, an affiliate of
Mojave.
As
of
December 31, 2005, Kern River had 1,661,575 Dth per day of capacity under
long-term firm natural gas transportation service agreements pursuant to which
the pipeline receives natural gas on behalf of shippers at designated receipt
points, transports the natural gas on a firm basis up to each shipper’s maximum
daily quantity and delivers thermally equivalent quantities of natural gas
at
designated delivery points. Each shipper pays Kern River the aggregate amount
specified in its long-term firm natural gas transportation service agreement
and
Kern River’s tariff, with such amount consisting primarily of a fixed monthly
reservation fee based on each shipper’s maximum daily quantity and a commodity
charge based on the actual amount of natural gas transported.
With
respect to Kern River’s mainline facilities in existence prior to the 2003
Expansion Project, at December 31, 2005, Kern River had 28 long-term firm
natural gas transportation service agreements with 16 shippers, for a total
of
848,949 Dth per day of capacity. These long-term firm natural gas transportation
service agreements expire between September 30, 2011 and April 30,2018. Several of these shippers are major oil and gas companies or affiliates
of
such companies. These shippers also include electric generating companies,
energy marketing and trading companies, and a natural gas distribution utility
which provides services in Nevada and California.
With
respect to Kern River’s 2003 Expansion Project, at December 31, 2005, Kern River
had 19 long-term firm natural gas transportation service agreements with 16
shippers, for a total of 812,626 Dth per day of capacity from the pipeline’s
point of origination near Opal, Wyoming to delivery points primarily in
California. Approximately 83% of the 2003 Expansion Project’s capacity is
contracted for 15 years, with 14 of the long-term firm natural gas
transportation service agreements expiring on April 30, 2018. The remaining
17% of capacity is contracted for 10 years, with five long-term firm natural
gas
transportation service agreements expiring on April 30, 2013. Over 95% of
the 2003 Expansion Project’s capacity has primary delivery points in California,
with the flexibility to access secondary delivery points in Nevada and Utah.
Kern River has an additional 94,000 Dth per day of available firm capacity
associated with the 2003 Expansion Project that was recently sold to a number
of
shippers at a discounted daily demand rate for the period of April 2006 through
September 2008 on a short-term basis. Kern River will continue to market this
capacity or use it for any future expansion needs for any period beyond
September 2008.
11
Calpine
Corp., including Calpine Energy Services, L.P. (“Calpine”), filed for Chapter 11
bankruptcy protection on December 20, 2005. Calpine holds two 50,000 Dth
per day incremental 2003 Expansion Project firm transportation contracts that
have termination dates of April 30, 2018. Pursuant to Kern River's credit
requirements, Calpine provided approximately $19 million as cash security for
the transportation contracts, which is expected to be applied against Calpine's
pre-petition invoices. Post-petition, to date, Calpine has continued to nominate
on its transportation contracts and pay its post-petition invoices; however,
Calpine has indicated that it has not yet determined whether it will assume
or
reject the transportation contracts.
Northern
Natural Gas
Northern
Natural Gas, an indirect wholly-owned subsidiary of MEHC, owns one of the
largest interstate natural gas pipeline systems in the United States. It reaches
from Texas to Michigan’s Upper Peninsula and is engaged in the transmission and
storage of natural gas for utilities, municipalities, other pipeline companies,
gas marketers, industrial and commercial users and other end users. Northern
Natural Gas operates approximately 16,400 miles of natural gas pipelines,
consisting of approximately 7,000 miles of mainline transmission pipelines
and
approximately 9,400 miles of lateral pipelines, with a design capacity of 4.6
Bcf per day. Based on a review of relevant industry data, the Northern Natural
Gas system is believed to be the largest single pipeline in the United States
as
measured by pipeline miles and the ninth largest as measured by throughput.
Northern Natural Gas’ revenue is derived from the interstate transportation and
storage of natural gas for third parties. Except for quantities of natural
gas
owned for system operations, Northern Natural Gas does not own the natural
gas
that is transported through its system. Northern Natural Gas’ transportation and
storage operations are subject to a FERC regulated tariff that is designed
to
allow it an opportunity to recover its costs together with a regulated return
on
equity.
Northern
Natural Gas’ system consists of two distinct but operationally integrated
markets. Its traditional end-use and distribution market area is at the northern
end of the system, including delivery points in Michigan, Illinois, Iowa,
Minnesota, Nebraska, Wisconsin and South Dakota, which Northern Natural Gas
refers to as the Market Area, and the natural gas supply and service area is
at
the southern end of the system, including Kansas, Oklahoma, Texas and New
Mexico, which Northern Natural Gas refers to as the Field Area. Northern Natural
Gas’ Field Area is interconnected with many interstate and intrastate pipelines
in the national grid system. A majority of Northern Natural Gas’ capacity in
both the Market Area and the Field Area is dedicated to Market Area customers
under long-term firm transportation contracts. Approximately 54% of Northern
Natural Gas’ current firm transportation capacity in the Market Area is
contracted beyond 2008 and approximately 38% of such capacity is contracted
beyond 2015.
Northern
Natural Gas’ pipeline system transports natural gas primarily to end-user and
local distribution markets in the Market Area. Customers consist of local
distribution companies (“LDCs”), municipalities, other pipeline companies, gas
marketers and end-users. While eight large LDCs account for the majority of
Market Area volumes, Northern Natural Gas also serves numerous small communities
through these large LDCs as well as municipalities or smaller LDCs and directly
serves several large end-users. In 2005, over 85% of Northern Natural Gas’
transportation and storage revenue was from capacity charges under firm
transportation and storage contracts and approximately 80% of that revenue
was
from LDCs. In 2005, approximately 71% of Northern Natural Gas’ transportation
and storage revenue was generated from Market Area customer
contracts.
The
Field
Area of Northern Natural Gas’ system provides access to natural gas supply from
key production areas including the Hugoton, Permian and Anadarko Basins. In
each
of these areas, Northern Natural Gas has numerous interconnecting receipt and
delivery points, with volumes received in the Field Area consisting of both
directly connected supply and volumes from interconnections with other pipeline
systems. In addition, Northern Natural Gas has the ability to aggregate
processable natural gas for deliveries to various gas processing
facilities.
In
the
Field Area, customers holding transportation capacity consist of LDCs,
marketers, producers, and end-users. The majority of Northern Natural Gas’ Field
Area firm transportation is provided to Northern Natural Gas’ Market Area firm
customers under long-term firm transportation contracts with such volumes
supplemented by volumes transported on an interruptible basis or pursuant to
short-term firm contracts. In 2005, approximately 19% of Northern Natural Gas’
transportation and storage revenue was generated from Field Area customer
transportation contracts.
12
Northern
Natural Gas’ storage services are provided through the operation of one
underground storage field in Iowa, two underground storage facilities in Kansas
and one LNG storage peaking unit each in Iowa and Minnesota. The three
underground natural gas storage facilities and Northern Natural Gas’ two LNG
storage peaking units have a total firm service storage capacity of
approximately 59 Bcf and over 1.3 Bcf per day of peak day deliverability. These
storage facilities provide Northern Natural Gas with operational flexibility
for
the daily balancing of its system and providing services to customers for
meeting their year-round load requirements. In 2005, approximately 10% of
Northern Natural Gas’ transportation and storage revenue was generated from
storage services.
Northern
Natural Gas’ system experiences significant seasonal swings in demand, with the
highest demand occurring during the months of November through March. This
seasonality provides Northern Natural Gas opportunities to deliver high
value-added services, such as firm and interruptible storage services, as well
as no notice services, particularly during the lower demand months. Because
of
its location and multiple interconnections with other interstate and intrastate
pipelines, Northern Natural Gas is able to access natural gas from both
traditional production areas, such as the Hugoton, Permian and Anadarko Basins,
as well as growing supply areas such as the Rocky Mountains, through Trailblazer
Pipeline Company, Kinder Morgan Interstate Gas Transmission, Cheyenne Plains
Gas
Pipeline Company and Colorado Interstate Gas Pipeline Company (“Colorado
Interstate”), and from Canadian production areas through Northern Border, Great
Lakes Gas Transmission Limited Partnership (“Great Lakes”) and Viking Gas
Transmission Company (“Viking”). As a result of Northern Natural Gas’ geographic
location in the middle of the United States and its many interconnections with
other pipelines, Northern Natural Gas augments its steady end-user and LDC
revenue by taking advantage of opportunities to provide intermediate
transportation through pipeline interconnections for customers in other markets,
including Chicago, Illinois and other parts of the Midwest and
Texas.
Kern
River and Northern Natural Gas Competition
Pipelines
compete on the basis of cost (including both transportation costs and the
relative costs of the natural gas they transport), flexibility, reliability
of
service, location and overall customer service. Industrial end-users often
have
the ability to choose from alternative fuel sources in addition to natural
gas,
such as fuel oil and coal. Natural gas competes with other forms of energy,
including electricity, coal and fuel oil, primarily on the basis of price.
Legislation and governmental regulations, the weather, the futures market,
production costs and other factors beyond the control of Kern River and Northern
Natural Gas influence the price of natural gas.
Kern
River competes with various interstate pipelines and its shippers in order
to
market any unutilized or unsubscribed capacity in serving the southern
California, Las Vegas, Nevada and Salt Lake City, Utah market areas. Kern River
provides its customers with supply diversity through pipeline interconnections
with Northwest Pipeline, Colorado Interstate, Overland Trail Pipeline,
Overthrust Pipeline and Questar Pipeline. These interconnections, in addition
to
the direct interconnections to natural gas supply and processing facilities,
allow Kern River to access natural gas reserves in Colorado, northwestern New
Mexico, Wyoming, Utah and the Western Canadian Sedimentary Basin.
Kern
River is the only interstate pipeline that presently delivers natural gas
directly from a gas supply basin into the intrastate California market. This
enables direct connect customers to avoid paying a “rate stack” (i.e.,
additional transportation costs attributable to the movement from one or more
interstate pipeline systems to an intrastate system within California). Kern
River believes that its historic levelized rate structure and access to upstream
pipelines/storage facilities and to economic Rocky Mountain gas reserves
increases its competitiveness and attractiveness to end-users. Kern River
believes it is advantaged relative to other competing interstate pipelines
because its relatively new pipeline can be economically expanded and will
require significantly less capital expenditure to comply with the Pipeline
Safety Improvement Act of 2002 (“PSIA”) than other systems. Kern River’s
levelized rate structures has been challenged in its 2004 general rate case.
Certain parties have advocated converting the system to a traditional, declining
rate base rate structure. Kern River’s favorable market position is tied to the
availability and favorable price of gas reserves in the Rocky Mountain area,
an
area that in recent years has attracted considerable interest for increased
pipeline capacity serving markets other than California and Nevada. In addition,
Kern River’s 2003 Expansion Project relies substantially on long-term
transportation service agreements with several electric generation companies,
who face significant competitive and financial pressures due to, among other
things, the financial stress of energy markets and apparent over-building of
electric generation capacity in California and other markets. This condition
is
expected to ease over time as demand for electric generation in Kern River’s
market territory increases and older, less efficient power plants in the region
are retired.
13
Northern
Natural Gas has been able to provide cost competitive service because of its
access to a variety of relatively low cost gas supply basins, its cost-control
measures and its competitive load factor, which lowers the cost per unit of
transportation. Although Northern Natural Gas has periodically experienced
bypasses of the pipeline system affecting a small percentage of its market,
to
date Northern Natural Gas has been able to more than offset any load lost to
bypass in the Northern Natural Gas Market Area through expansion
projects.
Major
competitors in the Northern Natural Gas Market Area include; ANR, Northern
Border and NGPL. Other competitors include Great Lakes and Viking. In the Field
Area, Northern Natural Gas competes with a large number of other competitors.
Particularly in the Field Area, a significant amount of Northern Natural Gas’
capacity is used on an interruptible or short-term firm basis. In summer months,
Northern Natural Gas’ Market Area customers often release significant amounts of
their unused firm capacity to other shippers, which released capacity competes
with Northern Natural Gas’ short-term firm or interruptible
services.
Although
Northern Natural Gas will need to aggressively compete to retain and build
load,
Northern Natural Gas believes that current and anticipated changes in its
competitive environment have created opportunities to serve existing customers
more efficiently and to meet certain growing supply needs. While LDCs’ peak day
growth is driven by population growth and alternative fuel replacement, new
off-peak demand growth is being driven primarily by power and ethanol plant
expansions. Off-peak demand growth is important to Northern Natural Gas as
this
demand can generally be satisfied with little or no requirement for the
construction of new facilities. Northern Natural Gas has been successful in
competing for a significant amount of the increased demand related to electric
generation and ethanol plants. Over the last five years, Northern Natural Gas
has contracted approximately 319 MMcf per day of firm volume on its system
from
such new facilities, of which approximately 255 MMcf per day is currently in
service and approximately 64 MMcf per day is scheduled to begin service in
2006.
The recent passage of the Energy Policy Act has continued to encourage ethanol
development and has had a positive effect of increasing demand on Northern
Natural Gas’ system.
Kern
River has one customer who accounts for greater than 10% of its revenue.
Northern Natural Gas has two customers who each account for greater than 10%
of
its revenue. Northern Natural Gas has agreements to retain the vast majority
of
both of these customers’ volumes through at least 2017. The loss of any one or
more of these customers, if not replaced, could have a material adverse effect
on Kern River’s and Northern Natural Gas’ respective businesses.
Development
Project
MEHC
and
a subsidiary, Alaska Gas Transmission Company, LLC (“Alaska Gas”), were two of
several other parties, including existing producers of oil from Alaska’s North
Slope, involved in a competitive selection process to develop and construct
a
proposed 745-mile natural gas pipeline that would extend from the North Slope
area near Prudhoe Bay, Alaska south to the Alaska-Yukon border near Beaver
Creek, Alaska. Due to unfavorable developments, MEHC and Alaska Gas ceased
discussions with the state of Alaska in 2005.
CE
Electric UK
CE
Electric UK, an indirect wholly-owned subsidiary of MEHC, owns, primarily,
two
companies that distribute electricity in Great Britain, Northern Electric and
Yorkshire Electricity. Northern Electric and Yorkshire Electricity, together,
constitute the third largest distributor of electricity in Great Britain,
serving more than 3.7 million customers in an area of approximately 10,000
square miles.
Electricity
Distribution
Northern
Electric and Yorkshire Electricity receive electricity from the national grid
transmission system and distribute it to their customers’ premises using their
network of transformers, switchgear and cables. Substantially all of the end
users in Northern Electric’s and Yorkshire Electricity’s distribution services
areas are connected to the Northern Electric and Yorkshire Electricity networks
and electricity can only be delivered to such end users through their
distribution system, thus providing Northern Electric and Yorkshire Electricity
with distribution volume that is relatively stable from year to year. Northern
Electric and Yorkshire Electricity charge fees for the use of the distribution
system to the suppliers of electricity. The suppliers, which purchase
electricity from generators and sell the electricity to end-user customers,
use
Northern Electric’s and Yorkshire Electricity’s distribution networks pursuant
to an industry standard “Distribution Use of System Agreement”, which Northern
Electric and Yorkshire Electricity separately entered into with the various
suppliers of electricity in their respective distribution services areas. One
such supplier, RWE Npower PLC (“Npower”) and certain of its affiliates,
represented approximately 44% of the total distribution revenues of Northern
Electric and Yorkshire Electricity in 2005.
14
At
December 31, 2005, Northern Electric’s and Yorkshire Electricity’s
electricity distribution network (excluding service connections to consumers)
on
a combined basis included approximately 33,000 kilometers of overhead lines
and
approximately 65,000 kilometers of underground cables. In addition to the
circuits referred to above, at December 31, 2005, Northern Electric’s and
Yorkshire Electricity’s distribution facilities also included approximately
60,000 transformers and approximately 700 primary substations. Substantially
all
substations are owned, with the balance being leased from third parties and
mostly having remaining terms of at least 10 years.
Utility
Services
Integrated
Utility Services Limited, CE Electric UK's indirect wholly-owned subsidiary,
is
an engineering contracting company whose main business is providing electrical
connection services for Northern Electric and Yorkshire Electricity and
providing electrical infrastructure contracting services to third
parties.
Gas
Exploration and Production
CalEnergy
Gas (Holdings) Limited (“CE Gas”), CE Electric UK’s indirect wholly-owned
subsidiary, is a gas exploration and production company that is focused on
developing integrated upstream gas projects in Australia, the United Kingdom
and
Poland. Its upstream gas business consists of exploration, development and
production projects, resulting in the sale of gas to third parties.
In
Australia, CE Gas has construction and development projects in the Bass, Otway
and Perth Basins. The Yolla construction project in the Bass Basin is a gas
and
gas liquids project in which CE Gas holds a 15% interest. The project, operated
by Origin Energy Limited of Australia, is nearing completion and includes an
approximately 145 kilometer sub-sea pipeline across the Bass Strait off southern
Victoria. The Bass Project is expected to be fully operational in 2006. The
gas
from the project will be sold to Origin Energy Limited’s retail affiliate, the
liquefied petroleum gas will be sold to Elgas Limited, the largest marketer
of
liquefied petroleum gas in Australia, and the condensate will be sold to The
Shell Company of Australia Limited. The Otway project, in which CE Gas holds
a
5% interest, is operated by Woodside Exploration Limited of Australia. This
project received construction approval during 2004. Construction has now
commenced with first production expected around mid-2006.
In
the
United Kingdom, CE Gas continues to retain its 5% interest in the Victor Field,
which is a gas field, located in the Southern North Sea. CE Gas is also
developing certain new exploration in the North Sea.
CalEnergy
Generation-Foreign
The
CalEnergy Generation-Foreign platform consists of MEHC’s indirect ownership of
the Leyte Projects, which are geothermal power plants located on the island
of
Leyte in the Philippines, and a combined irrigation and hydroelectric power
generation project located in the central part of the island of Luzon in the
Philippines (the “Casecnan Project”). Each plant possesses an operating margin
that allows for production in excess of the amount listed below. Utilization
of
this operating margin is based upon a variety of factors and can be expected
to
vary between calendar quarters under normal operating conditions.
15
The
following table sets out certain information concerning CalEnergy
Generation-Foreign’s non-utility power projects in operation as of
December 31, 2005:
All
projects are located in the Philippines and carry political risk
insurance.
(2)
Actual
MW may vary depending on operating, geothermal reservoir and water
flow
conditions, as well as plant design. Facility Net Capacity (MW) represents
the contract capacity for the facility. Net MW Owned indicates current
legal ownership, but, in some cases, does not reflect the current
allocation of distributions.
(3)
Philippine
National Oil Company-Energy Development Corporation (“PNOC-EDC”), Republic
of the Philippines (“ROP”), and National Irrigation Administration
(“NIA”). NIA also pays CE Casecnan Water and Energy Company, Inc. (“CE
Casecnan”), an indirect subsidiary of MEHC, for the delivery of water and
electricity by CE Casecnan. Separate sovereign performance
undertakings of the ROP support PNOC-EDC’s obligations for the Leyte
Projects. The ROP has also provided a performance undertaking under
which
NIA’s obligations under the Casecnan Project agreement, as supplemented
by
the Supplemental Agreement, are guaranteed by the full faith and
credit of
the ROP.
(4)
Net
MW Owned of approximately 150 MW is subject to repurchase rights
of up to
15% of the project by an initial minority shareholder and a dispute
with
the other initial minority shareholder regarding an additional 15%
of the
project. Refer to Item 3. Legal Proceedings of this Form 10-K for
additional information.
PNOC-EDC’s
and NIA’s obligations under the project agreements are substantially denominated
in U.S. dollars and are the Leyte Projects’ and Casecnan Project’s sole source
of operating revenue. Because of the dependence on a single customer, any
material failure of the customer to fulfill its obligations under the project
agreements and any material failure of the ROP to fulfill its obligation under
the performance undertaking would significantly impair the ability to meet
existing and future obligations, including obligations pertaining to the
outstanding project debt.
The
Upper
Mahiao project is a 119 net MW geothermal power project owned and operated
by CE
Cebu Geothermal Power Company, Inc. (“CE Cebu”), a Philippine corporation that
is 100% indirectly owned by MEHC. On June 25, 2006, the end of the 10-year
cooperation period, the Upper Mahiao facility will be transferred to PNOC-EDC
at
no cost on an “as-is” basis.
The
Upper
Mahiao project takes geothermal steam and fluid, provided by PNOC-EDC at no
cost, and converts its thermal energy into electrical energy which is sold
to
PNOC-EDC, which in turn sells the power to the National Power Corporation
(“NPC”), the government-owned and controlled corporation that is the primary
supplier of electricity in the Philippines, for distribution on the island
of
Cebu. PNOC-EDC pays CE Cebu a fee based on the plant capacity. Pursuant to
an
amendment to the Upper Mahiao energy conversion agreement dated August 31,2003, CE Cebu and PNOC-EDC agreed that the plant capacity for purposes of the
fee would equal the contractually specified level of 118.5 MW. PNOC-EDC also
pays CE Cebu a fee based on the electricity actually delivered to PNOC-EDC
(approximately 2% of total contract revenue). Payments under the Upper Mahiao
agreement are denominated in U.S. dollars, or computed in U.S. dollars and
paid
in pesos at the then-current exchange rate, except for the energy
fee.
16
The
Mahanagdong project is a 154 net MW geothermal power project owned and operated
by CE Luzon Geothermal Power Company, Inc. (“CE Luzon”), a Philippine
corporation of which MEHC indirectly owns 100% of the common stock. Another
industrial company owns an approximate 3% preferred equity interest in the
Mahanagdong project. The Mahanagdong project sells 100% of its capacity to
PNOC-EDC, which in turn sells the power to the NPC for distribution on the
island of Luzon.
The
terms
of the Mahanagdong energy conversion agreement are substantially similar to
those of the Upper Mahiao agreement. On July 25, 2007, the end of the
10-year cooperation period, the Mahanagdong facility will be transferred to
PNOC-EDC at no cost on an “as-is” basis. PNOC-EDC pays CE Luzon a fee based on
the plant capacity. Pursuant to an amendment to the Mahanagdong energy
conversion agreement dated August 31, 2003, CE Luzon and PNOC-EDC agreed
that the plant capacity would equal the contractually specified level, which
declines from approximately 154 MW in 2005 to approximately 153 MW in the last
year of the cooperation period. The capacity fees are approximately 99% of
total
revenue at the contractually agreed capacity levels and the energy fees are
approximately 1% of such total revenue.
The
Malitbog project is a 216 net MW geothermal project owned and operated by
Visayas Geothermal Power Company (“VGPC”), a Philippine general partnership that
is indirectly wholly owned by MEHC. VGPC sells 100% of its capacity on
substantially the same basis as described above for the Upper Mahiao project
to
PNOC-EDC, which sells the power to the NPC for distribution on the islands
of
Cebu and Luzon.
The
Malitbog energy conversion agreement 10-year cooperation period expires on
July 25, 2007, at which time the facility will be transferred to PNOC-EDC
at no cost on an “as-is” basis. Capacity payments under the agreement equal 100%
of total revenue. Pursuant to an amendment to the Malitbog energy conversion
agreement dated August 31, 2003, VGPC and PNOC-EDC agreed that the plant
capacity would equal the contractually specified level of 216 MW. A substantial
majority of the capacity payments are required to be made by PNOC-EDC in U.S.
dollars. The portion of capacity payments payable to PNOC-EDC in pesos is
expected to vary over the term of the Malitbog project energy conversion
agreement from 10% of VGPC’s revenue in the early years of the cooperation
period to 23% of VGPC’s revenue at the end of the cooperation period. Payments
made in pesos are generally made to a peso-denominated account and are used
to
pay peso-denominated expenses with respect to the Malitbog project.
The
Casecnan Project is a combined irrigation and hydroelectric power generation
project. The Casecnan Project consists generally of diversion structures in
the
Casecnan and Taan rivers that capture and divert excess water in the Casecnan
watershed by means of concrete, in-stream diversion weirs and transfer that
water through a transbasin tunnel of approximately 23 kilometers. During the
water transfer, the elevation differences between the two watersheds allows
electrical energy to be generated at an approximately 150 MW rated capacity
power plant, which is located in an underground powerhouse cavern at the end
of
the transbasin water tunnel. A tailrace discharge tunnel then delivers water
to
the existing underutilized water storage reservoir at Pantabangan, providing
additional water for irrigation and increasing the potential electrical
generation at two existing downstream hydroelectric facilities of NPC. Once
in
the reservoir at Pantabangan, the water is under the control of
NIA.
CE
Casecnan owns and operates the Casecnan Project under the terms of the Project
Agreement between CE Casecnan and NIA, which was modified by a Supplemental
Agreement between CE Casecnan and NIA effective on October 15, 2003 (the
“Supplemental Agreement”). CE Casecnan will own and operate the project for a
20-year cooperation period which commenced on December 11, 2001, the start
of the Casecnan Project’s commercial operations, after which ownership and
operation of the project will be transferred to NIA at no cost on an “as-is”
basis. The Casecnan Project is dependant upon sufficient rainfall to generate
electricity and deliver water. Rainfall varies within the year and from year
to
year, which is outside the control of CE Casecnan, and may have a material
impact on the amounts of electricity generated and water delivered by the
Casecnan Project. Rainfall has historically been highest from June through
December and lowest from January through May. The contractual terms for water
delivery fees and variable energy fees (described below) can produce significant
variability in revenue between reporting periods.
Under
the
Supplemental Agreement, CE Casecnan is paid a fee for the delivery of water
and
a fee for the generation of electricity. With respect to water deliveries,
the
water delivery fee is payable in a fixed monthly payment based upon an average
annual water delivery of 801.9 million cubic meters, pro-rated to
approximately 66.8 million cubic meters per month, multiplied by the
applicable per cubic meter rate through December 25, 2008. For each
contract year starting from December 25, 2003, and ending on
December 25, 2008, a water delivery credit (deferred revenue) is computed
equal to 801.9 million cubic meters minus the greater of actual water
deliveries or 700.0 million cubic meters - the minimum threshold. The water
delivery credit at the end of the contract year is available to be earned in
the
succeeding contract years ending December 25, 2008. The cumulative water
delivery credit at December 25, 2008, if any, shall be amortized from
December 25, 2008 through December 25, 2013. Accordingly, in
recognizing revenue, the water delivery fees are recorded each month pro-rated
to approximately 58.3 million cubic meters per month until the minimum
threshold has been reached for the contract year. Subsequent water delivery
fees
within the contract year are based on actual water delivered.
17
With
respect to electricity, CE Casecnan is paid a guaranteed energy delivery fee
each month equal to the product obtained by multiplying 19 GWh times $0.1596
per
kWh. The guaranteed energy delivery fee is payable regardless of the amount
of
energy actually generated and delivered by CE Casecnan in any month. NIA also
pays CE Casecnan an excess energy delivery fee, which is a variable amount
based
on actual electrical energy, if any, delivered in each month in excess of
19 GWh multiplied by (i) $0.1509 per kWh through the end of 2008 and (ii)
commencing in 2009, $0.1132 (escalating at 1% per annum thereafter) per kWh,
provided that any deliveries of energy in excess of 490 GWh but less than 550
GWh per year are paid for at a rate of 1.3 pesos per kWh and deliveries in
excess of 550 GWh per year are at no cost to NIA. Within each contract year,
no
variable energy fees are payable until energy in excess of the cumulative 19
GWh
per month for the contract year to date has been delivered. If the Casecnan
Project is not dispatched up to 150 MW whenever water is available, NIA will
pay
for energy that could have been generated but was not as a result of such
dispatch constraint.
In
connection with the signing of the Supplemental Agreement, CE Casecnan received
written confirmation from the Private Sector Assets and Liabilities Management
Corporation that the issues with respect to the Casecnan Project that had been
raised by the interagency review of independent power producers in the
Philippines or that may have existed with respect to the project under certain
provisions of the Electric Power Industry Reform Act of 2001 (“EPIRA”), which
authorized the ROP to seek to renegotiate certain contracts such as the Project
Agreement, have been satisfactorily addressed by the Supplemental
Agreement.
CalEnergy
Generation-Domestic
The
subsidiaries comprising the Company's CalEnergy Generation-Domestic platform
own
interests in 15 operating non-utility power projects in the United States.
The
following table sets out certain information concerning CalEnergy
Generation-Domestic’s non-utility power projects in operation as of
December 31, 2005:
Facility
Power
Net
Net
Purchase
Capacity
MW
Energy
Agreement
Power
Operating
Project
(MW)(1)
Owned(1)
Source
Location
Expiration
Purchaser(2)
Cordova
537
537
Gas
Illinois
2019
Constellation
Roosevelt
Hot Springs
23
17
Geo
Utah
2020
PacifiCorp
CE
Generation:(3)
Geothermal
-
Salton
Sea I
10
5
Geo
California
2017
Edison
Salton
Sea II
20
10
Geo
California
2020
Edison
Salton
Sea III
50
25
Geo
California
2019
Edison
Salton
Sea IV
40
20
Geo
California
2026
Edison
Salton
Sea V
49
25
Geo
California
Varies
Various
Vulcan
34
17
Geo
California
2016
Edison
Elmore
38
19
Geo
California
2018
Edison
Leathers
38
19
Geo
California
2019
Edison
Del
Ranch
38
19
Geo
California
2019
Edison
CE
Turbo
10
5
Geo
California
2029
APS
327
164
Natural-Gas
Fired -
Saranac
240
90
Gas
New
York
2009
NYSE&G
Power
Resources
212
106
Gas
Texas
N/A
Market
sales
Yuma
50
25
Gas
Arizona
2024
SDG&E
502
221
829
385
Total(4)
1,389
939
18
(1)
Represents
nominal net generating capability (accredited for Cordova and contract
capacity for most others). Actual MW may vary depending on operating
and
reservoir conditions and plant design. Net MW Owned indicates current
legal ownership, but, in some cases, does not reflect the current
allocation of partnership distributions.
(2)
Constellation
Energy Commodities Group (“Constellation”); Southern California Edison
Company (“Edison”); Arizona Public Service (“APS”) New York State Electric
& Gas Corporation (“NYSE&G”); and San Diego Gas & Electric
Company (“SDG&E”).
(3)
MEHC
has a 50% ownership interest in CE Generation, LLC (“CE Generation”) whose
affiliates currently operate ten geothermal plants in the Imperial
Valley
of California (the “Imperial Valley Projects”) and three natural gas-fired
power generation facilities.
(4)
The
totals do not include MEHC’s 50% ownership of the Wailuku hydroelectric
project (facility net capacity of 10 MW), which was obtained on
February 17, 2006.
Cordova
Energy owns a 537 MW gas-fired power plant in the Quad Cities, Illinois area
(the “Cordova Project”). CalEnergy Generation Operating Company, an indirect
wholly owned subsidiary of MEHC, operates the Cordova Project which commenced
commercial operations in June 2001. On July 6, 1999, Cordova Energy entered
into a power purchase agreement with a unit of El Paso, under which El Paso
was obligated to purchase all of the capacity and energy generated from the
project until December 31, 2019. Effective January 1, 2006, El Paso
assigned all of its rights and obligations under the power purchase agreement
to
Constellation. In connection with the assignment, Constellation Energy Group,
Inc., the ultimate parent of Constellation, issued a limited guarantee of
Constellation’s obligations under the power purchase agreement. The contract
year under the power purchase agreement extends from May 15th in a year to
May 14th in the subsequent year. For each contract year, Cordova Energy has
an option to recall 50% of the output of the Cordova Project.
Each
of
the Imperial Valley Projects, excluding the Salton Sea V and CE Turbo projects,
sells electricity to Edison pursuant to a separate Standard Offer No. 4
Agreement (“SO4 Agreement”) or a negotiated power purchase agreement. Each power
purchase agreement is independent of the others, and the performance
requirements specified within one such agreement apply only to the project
subject to the agreement. The power purchase agreements provide for capacity
payments, capacity bonus payments and energy payments. Edison makes fixed annual
capacity payments and capacity bonus payments to the applicable projects to
the
extent that capacity factors exceed certain benchmarks. The price for capacity
is fixed for the life of the SO4 Agreements and is significantly higher in
the
months of June through September.
Energy
payments under the original SO4 Agreements were based on the cost that Edison
avoids by purchasing energy from the project instead of obtaining the energy
from other sources (“Avoided Cost of Energy”). In June and November 2001, the
Imperial Valley Projects (except the Salton Sea IV project, which remained
on
Edison’s Avoided Cost of Energy) which receive Edison’s Avoided Cost of Energy
entered into agreements that provide for amended energy payments under the
SO4
Agreements. The amendments provide for fixed energy payments per kWh in lieu
of
Edison’s Avoided Cost of Energy. The fixed energy payment was 3.25 cents per kWh
from December 1, 2001 through April 30, 2002 and is 5.37 cents per kWh
from May 1, 2002 through April 30, 2007. Beginning May 1, 2007,
the energy payments revert back to Edison’s Avoided Cost of Energy. For the
years ended December 31, 2005, 2004 and 2003, Edison’s average Avoided Cost
of Energy was 7.7 cents per kWh, 5.9 cents per kWh and 5.4 cents per kWh,
respectively. Estimates of Edison’s future Avoided Cost of Energy vary
substantially from year to year primarily based on the future cost of natural
gas and may be impacted by regulatory proceedings and other commodity
factors.
The
Saranac project is a 240 net MW natural gas-fired cogeneration facility located
in Plattsburgh, New York owned by the Saranac Partnership, which is indirectly
owned by subsidiaries of CE Generation, Osaka Gas Energy America Corporation
and
General Electric Capital Corporation. Osaka Gas Energy America Corporation
acquired ArcLight Capital Holdings’ interest in the project on December 15,2005. The Saranac project has entered into a 15-year power purchase agreement
with NYSE&G, 15-year steam purchase agreements with Georgia-Pacific
Corporation and Pactiv Corporation and a 15-year natural gas supply contract
with Coral Energy to supply 100% of the Saranac project’s fuel requirements.
Each of the power purchase agreement, the steam purchase agreements and the
natural gas supply contract contains rates that are fixed for the respective
contract terms and expire in June 2009.
19
The
Power
Resources project is a 212 net MW natural gas-fired cogeneration project owned
by Power Resources Ltd. (“Power Resources”), an indirect wholly-owned subsidiary
of CE Generation. On August 5, 2003, Power Resources entered into a Tolling
Agreement with ONEOK Energy, Marketing and Trading Company, L.P. The agreement
commenced October 1, 2003 and expired on December 31, 2005.
Power
Resources currently operates as a merchant power plant and is subject to
electricity and gas markets to economically dispatch its output. Power Resources
entered into a one-year Energy Management Service Agreement with Mpower Trade
and Marketing (“Mpower”) effective January 1, 2006. Mpower is engaged to
provide energy services required to manage the electrical
generation, steam, and ancillary services capacity and related natural gas
requirements of the plant. Mpower is due 10% of all net margins generated
and Mpower’s credit is used in all transactions with no credit assurance
required from Power Resources.
The
Yuma
project is a 50 net MW natural gas-fired cogeneration project in Yuma, Arizona
owned by Yuma Cogeneration Associates (“YCA”), providing its electricity to
SDG&E under an existing 30-year power purchase contract which commenced in
May 1994 (the “Yuma Contract”). MEHC has guaranteed all of the obligations of
YCA under the Yuma Contract or any other agreement with SDG&E relating to or
arising out of the Yuma Contract. YCA also has executed steam sales contracts
with Queen Carpet, Inc. to act as its thermal host.
Development
Project
MEHC’s
indirect wholly-owned subsidiary, CE Obsidian Energy LLC (“Obsidian”), has
evaluated the development of a 185 net MW geothermal facility in the Imperial
Valley of California. Substantially all of the output of the facility would
be
sold to the Imperial Irrigation District pursuant to a power purchase agreement.
Due to current unfavorable project economics, MEHC and Obsidian are not actively
developing this project.
HomeServices
HomeServices
is the second largest full-service residential real estate brokerage firm in
the
United States. In addition to providing traditional residential real estate
brokerage services, HomeServices offers other integrated real estate services,
including mortgage originations and mortgage banking, primarily through joint
ventures, title and closing services and other related services. HomeServices’
real estate brokerage business is subject to seasonal fluctuations because
more
home sale transactions tend to close during the second and third quarters of
the
year. As a result, HomeServices’ operating results and profitability are
typically higher in the second and third quarters relative to the remainder
of
the year. HomeServices currently operates in 18 states under the following
brand
names: Carol Jones REALTORS, CBSHOME Real Estate, Champion Realty, Edina Realty
Home Services, Esslinger-Wooten-Maxwell REALTORS, First Realty/GMAC, HOME Real
Estate, Iowa Realty, Jenny Pruitt and Associates REALTORS, Long Realty,
Prudential California Realty, Prudential Carolinas Realty, RealtySouth,
Rector-Hayden REALTORS, Reece & Nichols, Roberts Brothers, Inc., Semonin
REALTORS and Woods Bros. Realty. HomeServices generally occupies the number
one
or number two market share position in each of its major markets based on
aggregate closed transaction sides. HomeServices’ major markets consist of the
following metropolitan areas: Minneapolis and St. Paul, Minnesota; Los Angeles
and San Diego, California; Kansas City, Kansas; Kansas City and Springfield,
Missouri; Des Moines, Iowa; Omaha and Lincoln, Nebraska; Birmingham, Auburn
and
Mobile, Alabama; Tucson, Arizona; Winston-Salem and Charlotte, North Carolina;
Louisville and Lexington, Kentucky; Annapolis, Maryland; Atlanta, Georgia;
and
Miami, Florida.
In
2005,
HomeServices separately acquired three real estate companies for an aggregate
purchase price of $5.1 million, net of cash acquired, plus working capital
and certain other adjustments. For the year ended December 31, 2004, these
real estate companies had combined revenue of $21.8 million on
approximately 3,400 closed sides representing $0.8 billion of sales volume.
In 2004, HomeServices separately acquired six real estate companies for an
aggregate purchase price of $30.7 million, net of cash acquired, plus
working capital and certain other adjustments. For the year ended
December 31, 2003, these real estate companies had combined revenue of
$95.7 million on approximately 15,000 closed sides representing
$3.2 billion of sales volume. In 2003, HomeServices separately acquired
four real estate companies for an aggregate purchase price of
$36.7 million, net of cash acquired, plus working capital and certain other
adjustments. For the year ended December 31, 2002, these real estate
companies had combined revenue of $102.9 million on approximately 16,000
closed sides representing $3.6 billion of sales volume.
20
Regulatory
Matters
General
Regulation
The
Company’s businesses are subject to a number of federal, state, local and
international regulations. In addition to the discussion contained herein,
refer
to Note 19 of Notes to Consolidated Financial Statements included in Item 8.
Financial Statements and Supplementary Data of this Form 10-K for additional
regulatory matter information regarding the Company’s businesses.
MidAmerican
Energy
MidAmerican
Energy is subject to comprehensive regulation by the FERC as well as utility
regulatory agencies in Iowa, Illinois and South Dakota that significantly
influences the operating environment and the recoverability of costs from
utility customers. Except for Illinois, that regulatory environment has to
date,
in general, given MidAmerican Energy an exclusive right to serve electricity
customers within its service territory and, in turn, the obligation to provide
electric service to those customers. In Illinois, all customers are free to
choose their electricity provider and MidAmerican Energy has an obligation
to
serve customers at regulated rates that leave MidAmerican Energy’s system, but
later choose to return. To date, there has been no significant loss of customers
from MidAmerican Energy’s existing regulated Illinois rates.
In
conjunction with the March 1999 approval by the IUB of the MidAmerican Energy
acquisition and March 2000 affirmation as part of the Company’s acquisition by a
private investor group, MidAmerican Energy committed to the IUB to use
commercially reasonable efforts to maintain an investment grade rating on its
long-term debt and to maintain its common equity level above 42% of total
capitalization unless circumstances beyond its control result in the common
equity level decreasing to below 39% of total capitalization. MidAmerican Energy
must seek the approval of the IUB of a reasonable utility capital structure
if
MidAmerican Energy’s common equity level decreases below 42% of total
capitalization, unless the decrease is beyond the control of MidAmerican Energy.
MidAmerican Energy is also required to seek the approval of the IUB if
MidAmerican Energy’s equity level decreases to below 39%, even if the decrease
is due to circumstances beyond the control of MidAmerican Energy. If MidAmerican
Energy’s common equity level were to drop below the required thresholds,
MidAmerican Energy’s ability to issue debt and declare dividends could be
restricted.
Under
a
series of settlement agreements between MidAmerican Energy, the Iowa Office
of
Consumer Advocate (“OCA”) and other interveners approved by the IUB, MidAmerican
Energy has agreed not to seek a general increase in electric rates to become
effective prior to January 1, 2012 unless its Iowa jurisdictional electric
return on equity for any year falls below 10%. These settlement agreements
further provide that earnings exceeding a return on equity of 12% through
December 31, 2005 and 11.75% for January 1, 2006 through December 31, 2011,
will be recorded as a regulatory liability and shared with ratepayers. Prior
to
filing for a general increase in electric rates, MidAmerican Energy is required
to conduct 30 days of good faith negotiations with the signatories to the
settlement agreements to attempt to avoid a general increase in such rates.
As a
party to the settlement agreements, the OCA has agreed not to seek any decrease
in MidAmerican Energy’s Iowa electric rates prior to January 1, 2012. The
settlement agreements specifically allow the IUB to approve or order electric
rate design or cost-of-service rate changes that could result in changes to
rates for specific customers as long as such changes do not result in an overall
increase in revenues for MidAmerican Energy. The settlement agreements also
each
provide that portions of revenues associated with Iowa retail electric returns
on equity within specified ranges will be recorded as a regulatory
liability.
Under
Iowa law, there are two options for temporary collection of higher rates
following the filing of a request for a rate increase. Collection can begin,
subject to refund, either within 10 days of filing, without IUB review, or
90
days after filing, with approval by the IUB. If the 10-day option is selected,
Iowa law provides that if the utility is required to make refunds, the refunds
may be based on overpayments made by each customer class, group or rate zone
of
the difference between final rates and the rates that would have been collected
if temporary rates had been based upon prior regulatory principles. If the
90-day option is selected, Iowa law provides that the IUB shall prescribe the
manner of refunding the difference between final rates and the rates based
on
prior ratemaking principles and a rate of return on common equity previously
approved by the IUB. In either case, if the IUB has not issued a final order
within ten months after the filing date, the temporary rates become final and
any difference between the requested rate increase and the temporary rates
may
then be collected subject to refund until receipt of a final order. Exceptions
to the ten-month limitation provide for extensions due to a utility's lack
of
due diligence in the rate proceeding, judicial appeals and situations involving
new generating units being placed in service. MidAmerican Energy's cost of
gas
is collected in its Iowa gas rates through the Iowa Uniform Purchased Gas
Adjustment Clause, which is updated monthly to reflect changes in actual
costs.
21
South
Dakota law authorizes the SDPUC to suspend new rates for up to six months during
the pendency of rate proceedings; however, the rates are permitted to be
implemented after six months subject to refund pending a final order in the
proceeding.
Under
Illinois law, new rates may become effective 45 days after filing with the
ICC,
or on such earlier date as the ICC may approve, subject to its authority to
suspend the proposed new rates, subject to hearing, for a period not to exceed
approximately eleven months after filing. Under Illinois electric tariffs,
MidAmerican Energy's Fuel Cost Adjustment Clause reflects changes in the cost
of
all fuels used for retail electric generation, including certain fuel
transportation costs, nuclear fuel disposition costs and the cost of energy
purchased from other utilities. MidAmerican Energy's cost of gas is reflected
in
its Illinois gas rates through the Illinois Uniform Purchased Gas Adjustment
Clause. Both of the adjustment clauses are updated on a monthly basis to reflect
changes in actual costs.
In
December 1997, Illinois enacted a law to restructure Illinois’ electric utility
industry. The law changed how and what electric services are regulated by the
ICC and transitions portions of the traditional electric services to a
competitive environment. In general for the transition period that extends
through 2006, the law allows for certain limits on the ICC’s regulatory
authority over a utility’s generation and also relaxes its regulatory authority
over many corporate transactions, such as the transfer of generation assets
to
affiliates. Special authority and limitations of authority apply during the
transition to a competitive marketplace. Also, the law permits utilities to
eliminate their fuel adjustment clauses and incorporates provisions by which
earnings in excess of allowed amounts are either partially refunded to customers
or are used to accelerate a company's asset recovery. Electric rates in Illinois
are frozen until January 1, 2007, subject to certain exceptions allowing
for increases, at which time bundled rates are subject to cost-based
ratemaking.
The
FERC
regulates MidAmerican Energy’s rates charged to wholesale customers for energy
and transmission services. Most of MidAmerican Energy’s electric wholesale sales
and purchases take place under market-based pricing allowed by the FERC and
are
therefore subject to market volatility. The FERC conducts a triennial review
of
MidAmerican Energy’s market-based pricing authority. Margins earned on wholesale
sales have historically been included as a component of retail cost of service
upon which retail rates are based.
On
July 22, 2005, MidAmerican Energy made a filing with the FERC requesting
its approval to establish a transmission service coordinator (“TSC”). The TSC
would be a third party administrator of various MidAmerican Energy OATT
functions for transmission service. On December 16, 2005, the FERC issued
an order conditionally accepting MidAmerican Energy’s request to establish a
TSC. The order requires MidAmerican Energy to make modifications to the draft
TSC agreement filed with the FERC as part of the request and to file a final
executed TSC agreement with the FERC for its review prior to the agreement
becoming effective. MidAmerican Energy has entered into a contract with a
third-party vendor to administer MidAmerican Energy’s OATT. MidAmerican Energy
does not believe that the incremental costs will have a material impact on
its
results of operations, financial position or cash flows. Subject to FERC
approval, the TSC is scheduled to commence operations in the third quarter
of
2006. Under the contract, the vendor would provide its tariff administration
and
planning services into the fall of 2009.
On
June 3, 2004, the FERC’s Division of Operational Investigations of the
Office of Market Oversight and Investigations (“OMOI”) informed MidAmerican
Energy that it was commencing an audit to determine whether and how MidAmerican
Energy and its subsidiaries and affiliates are complying with (1) requirements
of the standards of conduct and open access same-time information system of
the
FERC’s regulations, and (2) codes of conduct. In addition, OMOI sought to review
MidAmerican Energy’s transmission practices. The FERC commenced several such
audits of utilities in 2003 and 2004. On September 29, 2005, the FERC
approved the audit findings and MidAmerican Energy agreed to take certain
corrective actions. Accordingly, MidAmerican Energy will build $9.2 million
in previously unscheduled transmission system upgrades. That capital expenditure
will be excluded from MidAmerican Energy’s rate base for six years during which
time MidAmerican Energy will not earn a return on the transmission upgrades.
In
addition, MidAmerican Energy has agreed to accelerate $14.7 million of
scheduled transmission system upgrades. MidAmerican Energy has implemented
a
compliance plan to address certain aspects of the audit findings relating to
transmission practices and the administration of the OATT.
22
On
July 13, 2004, the FERC issued an order requiring MidAmerican Energy to
conduct a study to determine whether MidAmerican Energy or its affiliates
possess generation market power. MidAmerican Energy is being required to show
the absence of generation market power in order to be allowed to continue to
sell wholesale electric power at market-based rates. The FERC order is intended
to have MidAmerican Energy conform to what has become the FERC’s general
practice for utilities given authorization to make wholesale market-based sales.
Under this general practice, utilities authorized to make market-based electric
sales must submit a new market power study to the FERC every three years.
MidAmerican Energy filed the required study on October 29, 2004. On
June 1, 2005, the FERC issued an order setting for investigation the
reasonableness of MidAmerican Energy’s market-based rates within its control
area. The order also terminated the previously established November 1, 2004
refund date and instead required that market-based sales made by MidAmerican
Energy within its control area beginning August 7, 2005 be subject to
refund until the matter is resolved. The FERC also required MidAmerican Energy
to file additional information by July 1, 2005, and August 1, 2005. In
its August 1, 2005 filing, MidAmerican Energy filed a proposed cost-based
sales tariff applicable to sales made within its control area to replace its
market-based sales tariff. The FERC is currently reviewing the proposed tariff.
MidAmerican Energy does not expect the outcome of this issue to have a material
effect on its results of operations, financial position or cash
flows.
Kern
River and Northern Natural Gas
Kern
River and Northern Natural Gas are subject to regulation by various federal
and
state agencies. As owners of interstate natural gas pipelines, Northern Natural
Gas’ and Kern River’s rates, services and operations are subject to regulation
by the FERC. The FERC administers, among other things, the Natural Gas Act
and
the Natural Gas Policy Act of 1978. Additionally, interstate pipeline companies
are subject to regulation by the United States Department of Transportation
(“DOT”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”), which
establishes safety requirements in the design, construction, operations and
maintenance of interstate natural gas transmission facilities, and the PSIA,
which implemented additional safety and pipeline integrity regulations for
high
consequence areas.
The
FERC
has jurisdiction over, among other things, the construction and operation of
pipelines and related facilities used in the transportation, storage and sale
of
natural gas in interstate commerce, including the modification or abandonment
of
such facilities. The FERC also has jurisdiction over the rates and charges
and
terms and conditions of service for the transportation of natural gas in
interstate commerce.
Additional
proposals and proceedings that might affect the interstate natural gas pipeline
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. We cannot predict when or if any new proposals
might be implemented or, if so, how Kern River and Northern Natural Gas might
be
affected.
The
Company’s pipeline operations are subject to regulation by the DOT under the
NGPSA relating to design, installation, testing, construction, operation and
management of its pipeline systems. The NGPSA requires any entity that owns
or
operates pipeline facilities to comply with applicable safety standards, to
establish and maintain inspection and maintenance plans and to comply with
such
plans. The Company’s pipeline operations conduct internal audits of their major
facilities at least every four years, with more frequent reviews of those it
deems of higher risk. The DOT also routinely audits these pipeline facilities.
Compliance issues that arise during these audits or during the normal course
of
business are addressed on a timely basis.
The
aging
pipeline infrastructure in the United States has led to heightened regulatory
and legislative scrutiny of pipeline safety and integrity practices. The NGPSA
was amended by the Pipeline Safety Act of 1992 to require the DOT’s Office of
Pipeline Safety to consider protection of the environment when developing
minimum pipeline safety regulations. In addition, the amendments require that
the DOT issue pipeline regulations concerning, among other issues, the
circumstances under which emergency flow restriction devices should be required,
training and qualification standards for personnel involved in maintenance
and
operation, and requirements for periodic integrity inspections, as well as
periodic inspection of facilities in navigable waters that pose a hazard to
navigation or public safety. In addition, the amendments narrowed the scope
of
the exemption for gas pipelines from the underground storage tank requirements
under the Resource Conservation and Recovery Act. The Company believes its
pipeline systems comply in all material respects with the NGPSA.
The
PSIA
requires major new programs in the areas of operator qualification, risk
analysis and integrity management. The PSIA requires the periodic inspection
or
testing of pipelines in areas where the potential consequences of a gas pipeline
accident may be significant or may do considerable harm to people and their
property, which are referred to as High Consequence Areas. Pursuant to the
PSIA,
the DOT promulgated new regulations, effective February 14, 2004, that
require interstate pipeline operators to (i) develop comprehensive integrity
management programs, (ii) identify applicable threats to pipeline segments
that
could impact High Consequence Areas, (iii) assess these segments, and (iv)
provide ongoing mitigation and monitoring. The Company believes its pipeline
operations comply in all material respects with the PSIA.
23
Energy
Policy Act
On
August 8, 2005, the Energy Policy Act was signed into law. That law
potentially impacts many segments of the energy industry. The law will result
in
expanding the FERC’s regulatory authority in areas such as mandatory electric
system reliability standards, electric transmission expansion incentives and
pricing, regulation of utility holding companies, and gives the FERC enforcement
authority to issue substantial civil penalties. While the FERC has now issued
rules and decisions on multiple aspects of the Energy Policy Act, the full
impact of those decisions remains uncertain.
The
Energy Policy Act repealed PUHCA 1935 and enacted the Public Utility Holding
Company Act of 2005 (“PUHCA 2005”), effective February 8, 2006. PUHCA 1935
extensively regulated and restricted the activities of registered public utility
holding companies and their subsidiaries. PUHCA 2005 and the rules issued by
the
FERC to implement PUHCA 2005 require, among other things, public utility holding
companies to permit access by the FERC to the books and records of the holding
company and its affiliates transacting business with the public utility, unless
such requirement is exempted or waived, and to comply with the FERC’s record
retention requirements. The repeal of PUHCA 1935 enabled Berkshire Hathaway
to
convert all of its outstanding no par, zero-coupon convertible preferred stock
into an equal number of shares of MEHC’s common stock thereby becoming the
majority owner of MEHC.
The
Energy Policy Act also substantially amended the Public Utility Regulatory
Policies Act of 1978 (“PURPA”). PURPA and the regulations issued thereunder
affected MEHC and certain of its subsidiaries’ operations by providing to
qualifying facilities (“QF”) certain exemptions from federal and state laws and
regulations, including organizational, rate and financial regulation. New
Section 210(m) eliminates the requirement that public utilities purchase the
capacity and energy of QFs if the FERC determines that the requisite competitive
market criteria are satisfied. In January 2006, the FERC instituted a rulemaking
process to implement this section of the Energy Policy Act. The Energy Policy
Act removed the 50% limitation on electric utility and electric utility holding
company ownership of QFs. The Energy Policy Act does not authorize the
termination of any existing contract and the Company does not expect the
amendments to PURPA to have an adverse effect on the Company.
CE
Electric UK
Since
1990, the electricity generation, transmission, supply and distribution
industries in Great Britain have been privatized, and competition has been
introduced in generation and supply, and, to a much more limited extent, in
some
aspects of distribution such as new connections and metering. Electricity is
produced by generators, transmitted through the national grid transmission
system and distributed to customers by the fourteen Distribution License Holders
(“DLHs”) in their respective distribution services areas.
Under
the
Utilities Act 2000, the public electricity supply license created pursuant
to
the Electricity Act 1989 was replaced by two separate licenses - the electricity
distribution license and the electricity supply license. When the relevant
provision of the Utilities Act 2000 became effective on October 1, 2001,
the public electricity supply licenses formerly held by Northern Electric plc
(“NE”) and Yorkshire Electricity Group plc (“YE”) were split so that separate
subsidiaries held licenses for electricity distribution and electricity supply.
In order to comply with the Utilities Act 2000 and to facilitate this license
splitting, NE and YE (and each of the other holders of the former public
electricity supply licenses) each made a statutory transfer scheme that was
approved by the Secretary of State for Trade and Industry. These schemes
provided for the transfer of certain assets and liabilities to the licensed
subsidiaries. This occurred on October 1, 2001, a date set by the Secretary
of State for Trade and Industry. As a consequence of these schemes, the
electricity distribution businesses of NE and YE were transferred to Northern
Electric and Yorkshire Electricity, respectively. Northern Electric and
Yorkshire Electricity are each a DLH. The residual elements of the electricity
supply licenses were transferred to Innogy Holdings plc (“Innogy”), the
predecessor of Npower, in connection with the sale of NE’s electricity and gas
supply business to Innogy and the purchase by NE of YE’s electricity
distribution business from Innogy on September 21, 2001.
Each
of
the DLHs is required to offer terms for connection to its distribution system
and for use of its distribution system to any person. In providing the use
of
its distribution system, a DLH must not discriminate between users, nor may
its
charges differ except where justified by differences in cost.
24
Under
the
Utilities Act 2000, the Gas and Electricity Markets Authority (“GEMA”) is able
to impose financial penalties on license holders who contravene (or have in
the
past contravened) any of their license duties or certain of their duties under
the Electricity Act 1989, as amended, or who are failing (or have in the past
failed) to achieve a satisfactory performance in relation to the individual
standards of performance prescribed by GEMA. Any penalty imposed must be
reasonable and may not exceed 10% of the licensee’s revenue.
The
fees
that may be charged by Northern Electric and Yorkshire Electricity for use
of
their distribution systems are controlled by a formula prescribed by the British
electricity regulatory body and was last reset on April 1, 2005. The
distribution price control formula is generally reviewed and reset at five-year
intervals. Through March 31, 2010, the change in revenue is expected to be
mainly influenced by the rate of inflation in the United Kingdom, system losses,
the number of customers connected to the network and customer service
performance. The Office of Gas and Electricity Markets (“Ofgem”) completed the
process of reviewing the existing price control formula for Northern Electric
and Yorkshire Electricity in November 2004. As a result of the review, the
allowed revenue of Northern Electric’s and Yorkshire Electricity’s distribution
businesses were reduced by 4% and 9%, respectively, in real terms, effective
April 1, 2005.
CalEnergy
Generation-Foreign
The
Philippine Congress has passed EPIRA, which is aimed at restructuring the
Philippine power industry, privatizing the NPC and introducing a competitive
electricity market, among other initiatives. The implementation of EPIRA may
have an impact on the Company’s future operations in the Philippines and the
Philippine power industry as a whole, the effect of which is not yet
determinable or estimable.
In
connection with the signing of the Supplemental Agreement, CE Casecnan received
written confirmation from the Private Sector Assets and Liabilities Management
Corporation that the issues with respect to the Casecnan Project that had been
raised by the interagency review of independent power producers in the
Philippines or that may have existed with respect to the project under certain
provisions of EPIRA, which authorized the ROP to seek to renegotiate certain
contracts such as the Project Agreement, have been satisfactorily addressed
by
the Supplemental Agreement.
CalEnergy
Generation-Domestic
Each
of
the domestic power facilities in the CalEnergy Generation-Domestic platform,
excluding Cordova Energy and Power Resources, meets the requirements promulgated
under PURPA to be a QF. Prior to passage of the Energy Policy Act, QF status
under PURPA provided two primary benefits. First, regulations under PURPA
exempted QFs from PUHCA 1935, the FERC rate regulation under Sections 205 and
206 of the Federal Power Act and the state laws concerning rates of electric
utilities and financial and organization regulations of electric utilities.
Second, the FERC’s regulations promulgated under PURPA required that (1)
electric utilities purchase electricity generated by QFs, the construction
of
which commenced on or after November 9, 1978, at a price based on the
purchasing utility’s Avoided Cost of Energy, (2) electric utilities sell
back-up, interruptible, maintenance and supplemental power to QFs on a
non-discriminatory basis, and (3) electric utilities interconnect with QFs
in
their service territories. Following the effective date of repeal of PUHCA
1935,
the exemption from PUHCA 1935 is no longer relevant, but QFs remain exempt
from
the accounting and reporting requirements of PUHCA 2005. QF sales that occur
pursuant to existing contracts will continue to be exempt from FERC rate
regulation under Sections 205 and 206 of the Federal Power Act. However, with
respect to new contracts, QFs are no longer exempt from FERC’s regulation of
rates under Sections 205 and 206 of the Federal Power Act, unless the relevant
sales are made pursuant to a state regulatory authority’s implementation of
PURPA,
In
addition, in January 2006, the FERC issued a notice of proposed rulemaking
to
implement a provision of the Energy Policy Act, which eliminates the electric
utilities’ mandatory purchase obligation under PURPA if the FERC determines that
certain conditions regarding QF access to transmission facilities and
competitive markets are satisfied. Although the proposed rule does not permit
electric utilities to terminate existing agreements, such as those now in place
with CalEnergy Generation-Domestic, if the final rule is adopted substantially
as proposed, the effect on the Company when the existing agreements terminate
could be adverse. QF owners are required to provide notice to the FERC of a
“material change” in facts in an application for recertification or notice of
self-recertification. Subsequent notices of self-recertification for the same
QF
need only refer to changes which have occurred with respect to the facility
since the prior notice or the prior FERC certification.
25
In
another rulemaking proceeding to implement part of the Energy Policy Act, the
FERC stated that exempt wholesale generators (“EWG”) like Cordova Energy and
Power Resources are not considered to be an electric utility company for the
limited purpose of the FERC’s access to the books and records of holding company
systems under PUHCA 2005. As such, a EWG is permitted to sell capacity and
electricity in the wholesale markets, but not in the retail markets. If a EWG
is
subject to a “material change” in facts that might affect its continued
eligibility for EWG status, within 60 days of such material change, the EWG
must
(1) file a written explanation of why the material change does not affect its
EWG status, (2) file a new application for EWG status, or (3) notify the FERC
that it no longer wishes to maintain EWG status.
HomeServices
HomeServices
is subject to regulations promulgated by the U.S. Department of Housing and
Urban Development (“HUD”) as well as regulatory agencies in the states within
which it operates that significantly influence its operating environment. The
House Committee on Financial Services, the Senate Committee on Banking, Housing
and Urban Affairs and HUD each had indicated that reforming the Real Estate
Settlement and Procedures Act (“RESPA”) regulation was a priority in 2005. On
June 27, 2005, HUD announced their plan to hold six roundtables to discuss
with the industry what provisions a new RESPA reform rule should contain. Those
roundtables were held across the country in July and August 2005. HUD stated
that it would publish its RESPA proposal in late 2005 and the Final Rule in
2006. As of December 31, 2005, HUD did not publish a RESPA proposal and has
not indicated when a Final Rule will be issued in 2006. It is believed that
this
delay has been caused, in part, by the damage caused by hurricanes Katrina
and
Wilma. It is unknown whether a proposed rule will be introduced or finalized
in
2006. Accordingly, the Company is presently unable to quantify the likely impact
of any proposed rule, if issued.
Environmental
Regulation
Domestic
The
Company’s domestic operations are subject to a number of federal, state and
local environmental and environmentally related laws and regulations affecting
many aspects of its present and future operations in the United States. Such
laws and regulations generally require the Company’s domestic operations to
obtain and comply with a wide variety of licenses, permits and other approvals.
The Company believes that its operating power facilities and natural gas
pipeline operations are currently in material compliance with all applicable
federal, state and local laws and regulations. However, no guarantee can be
given that in the future the Company’s domestic operations will be in material
compliance with all applicable environmental statutes and regulations or that
all necessary permits will be obtained or approved. In addition, the
construction of new power facilities and natural gas pipeline operations is
a
costly and time-consuming process requiring a multitude of complex environmental
permits and approvals prior to the start of construction that may create the
risk of expensive delays or material impairment of project value if projects
cannot function as planned due to changing regulatory requirements or local
opposition. The Company cannot provide assurance that existing regulations
will
not be revised or that new regulations will not be adopted or become applicable
to it which could have an adverse impact on its capital or operating costs
or
its operations.
Under
various federal, state and local environmental laws and regulations, a current
or previous owner or operator of any facility may be required to investigate
and
remediate past releases or threatened releases of hazardous or toxic substances
or petroleum products located at the facility, and may be held liable to a
governmental entity or to third parties for property damage, personal injury
and
investigation and remediation costs incurred by a party in connection with
certain releases or threatened releases. In certain cases liability for damages
to natural resources may also be assessed. These laws, including the
Comprehensive Environmental Response, Compensation and Liability Act of 1980,
as
amended by the Superfund Amendments and Reauthorization Act of 1986, impose
liability without regard to whether the owner knew of or caused the release
of
the hazardous substances, and courts have interpreted liability under such
laws
to be strict and joint and several. The cost of investigation, remediation
or
removal of substances may be substantial. In connection with the Company’s
ownership and operation of its power facilities and pipeline systems, the
Company may become liable for such costs. Given the use of hazardous substances
and/or petroleum products within its power facilities and pipeline systems,
often within areas that have a long history of industrial use, it is possible
that the Company will discover currently unknown contamination or that future
spills or other causes of contamination will occur. As a result, even at those
sites where the Company is not presently aware of any contamination that
currently requires remediation, it is possible that the Company may become
liable for additional remediation costs.
26
Clean
Air Standards
MidAmerican
Energy is subject to applicable provisions of the Clean Air Act and related
air
quality standards promulgated by the United States Environmental Protection
Agency (“EPA”). The Clean Air Act provides the framework for regulation of
certain air emissions and permitting and monitoring associated with those
emissions. MidAmerican Energy believes it is in material compliance with current
air quality requirements. In addition to the discussion contained herein, refer
to Note 20 of Notes to Consolidated Financial Statements included in Item 8.
Financial Statements and Supplementary Data of this Form 10-K for additional
clean air standards information regarding MidAmerican Energy’s
operations.
On
February 16, 2005, the Kyoto Protocol became effective, requiring 35
developed countries to reduce greenhouse gas emissions by approximately 5%
between 2008 and 2012. While the United States did not ratify the protocol,
the
ratification and implementation of its requirements in other countries has
resulted in increased attention to the climate change issue in the United
States. In 2005, the Senate adopted a “sense of the Senate” resolution that puts
the Senate on record that Congress should enact a comprehensive and effective
national program of mandatory, market-based limits and incentives on emissions
of greenhouse gases that slow, stop, and reverse the growth of such emissions
at
a rate and in a manner that will not significantly harm the United States
economy; and will encourage comparable action by other nations that are major
trading partners and key contributors to global emissions. It is anticipated
that the resolution may be further addressed by Congress in 2006. While debate
continues at the national level over the direction of domestic climate policy,
several states are developing state-specific or regional legislative initiatives
to reduce greenhouse gas emissions. In December 2005, the states of Connecticut,
Delaware, Maine, New Hampshire, New Jersey, New York and Vermont signed a
mandatory regional pact to reduce greenhouse gas emissions. Litigation was
filed
in the federal district court for the southern district of New York seeking
to
require reductions of carbon dioxide emissions from generating facilities of
five large electric utilities. The court dismissed the public nuisance suit,
holding that such critical issues affecting the United States such as greenhouse
gas emissions reductions are not the domain of the court and should be resolved
by the Executive Branch and the U.S. Congress. This ruling has been appealed
to
the Second Circuit Court of Appeals. The outcome of climate change litigation
and federal and state initiatives cannot be determined at this time; however,
adoption of stringent limits on greenhouse gas emissions could significantly
impact the Company’s fossil-fueled facilities and, therefore, its results of
operations.
The
EPA’s
regulation of certain pollutants under the Clean Air Act, and its failure to
regulate other pollutants, is being challenged by various lawsuits brought
by
both individual state attorney generals and environmental groups. To the extent
that these actions may be successful in imposing additional and/or more
stringent regulation of emissions on fossil-fueled facilities in general and
MidAmerican’s facilities in particular, such actions could significantly impact
the Company’s fossil-fueled facilities and, therefore, its results of
operations.
Clean
Water Standards
Section
316(b) of the Clean Water Act requires that cooling water intake structures
reflect the best technology available for minimizing "adverse environmental
impacts" to aquatic organisms. On February 16, 2004, EPA Administrator
Michael Leavitt signed the final Phase II rule for existing electric generating
facilities. The rule sets significant new national technology-based performance
standards aimed at minimizing the adverse environmental impacts of cooling
water
intake structures by reducing the number of aquatic organisms lost as a result
of water withdrawals. MidAmerican Energy has completed a review of its
historical Section 316(b) studies, as well as filed Proposals for Information
Collection describing MidAmerican Energy’s plans for conducting biological field
studies adjacent to its cooling water intake structures over the next two years.
Although the impact of the MidAmerican Energy intake structures on aquatic
organisms is unknown at this time, the previous Section 316(b) studies suggest
that the impingement impact at the facility intake structures is minimal and
that little if any intake structure expenditures will be necessary to meet
the
Section 316(b) impingement standard. Because of the high flow rate of the
Missouri and Mississippi Rivers as compared to the withdrawal rates of the
intake structures, the entrainment criteria of the Section 316(b) rule is not
applicable to the MidAmerican Energy facilities. However, should the new
impingement studies show that the intakes are impacting the fish species, the
intake structures may need to be modified to meet best technology standards.
This could include significant expenditures involved with limiting the amount
of
water withdrawn from the Missouri or Mississippi Rivers, and restrictions on
the
intake flow velocity.
Nuclear
Regulation
MidAmerican
Energy is subject to the jurisdiction of the NRC with respect to its license
and
25% ownership interest in Quad Cities Station Units 1 and 2. Exelon Generation
Company, LLC (“Exelon Generation”) is the operator of Quad Cities Station and is
under contract with MidAmerican Energy to secure and keep in effect all
necessary NRC licenses and authorizations.
27
The
NRC
regulations control the granting of permits and licenses for the construction
and operation of nuclear generating stations and subject such stations to
continuing review and regulation. On October 29, 2004, the NRC granted
renewed licenses for both Quad Cities Station Unit 1 and Unit 2 that provide
for
operation until December 14, 2032, which is in effect a 20-year extension
of the licenses. The NRC review and regulatory process covers, among other
things, operations, maintenance, and environmental and radiological aspects
of
such stations. The NRC may modify, suspend or revoke licenses and impose civil
penalties for failure to comply with the Atomic Energy Act, the regulations
under such Act or the terms of such licenses.
Federal
regulations provide that any nuclear operating facility may be required to
cease
operation if the NRC determines there are deficiencies in state, local or
utility emergency preparedness plans relating to such facility, and the
deficiencies are not corrected. Exelon Generation has advised MidAmerican Energy
that an emergency preparedness plan for Quad Cities Station has been approved
by
the NRC. Exelon Generation has also advised MidAmerican Energy that state and
local plans relating to Quad Cities Station have been approved by the Federal
Emergency Management Agency.
The
NRC
also regulates the decommissioning of nuclear power plants including the
planning and funding for the eventual decommissioning of the plants. In
accordance with these regulations, MidAmerican Energy submits a report to the
NRC every two years providing reasonable assurance that funds will be available
to pay the costs of decommissioning its share of Quad Cities
Station.
Under
the
Nuclear Waste Policy Act of 1982 (“NWPA”), the U.S. Department of Energy (“DOE”)
is responsible for the selection and development of repositories for, and the
permanent disposal of, spent nuclear fuel and high-level radioactive wastes.
Exelon Generation, as required by the NWPA, signed a contract with the DOE
under
which the DOE was to receive spent nuclear fuel and high-level radioactive
waste
for disposal beginning not later than January 1998. The DOE did not begin
receiving spent nuclear fuel on the scheduled date and remains unable to receive
such fuel and waste. The earliest the DOE currently is expected to be able
to
receive such fuel and waste is 2010. The costs to be incurred by the DOE for
disposal activities are being financed by fees charged to owners and generators
of the waste. In 2004, Exelon Generation reached a settlement with the DOE
concerning the DOE’s failure to begin accepting spent nuclear fuel in 1998. As a
result, Quad Cities Station will be billing the DOE, and the DOE will be
obligated to reimburse the station for all station costs incurred due to the
DOE’s delay. Exelon Generation has completed construction of an interim spent
fuel storage installation (“ISFSI”) at Quad Cities Station to store spent
nuclear fuel in dry casks in order to free space in the storage pool. The first
pad at the ISFSI is expected to facilitate storage of casks to support
operations at Quad Cities Station until at least 2017. The first storage in
dry
cask commenced in November 2005. In the 2017 to 2022 timeframe, Exelon
Generation plans to add a second pad to the ISFSI to accommodate storage of
spent nuclear fuel through the end of operations at Quad Cities
Station.
MidAmerican
Energy has established trusts for the investment of funds collected for nuclear
decommissioning associated with Quad Cities Station. Electric tariffs currently
in effect include provisions for annualized collection of estimated
decommissioning costs at Quad Cities Station. In Iowa, estimated Quad Cities
Station decommissioning costs are reflected in base rates. MidAmerican Energy’s
cost related to decommissioning funding in 2005 was
$8.3 million.
United
Kingdom
CE
Electric UK’s businesses are subject to a number of United Kingdom regulations
with respect to the protection of the environment. The principal legislation
behind these regulations in relation to CE Electric UK activities is the Water
Resources Act of 1991 and the Environmental Protection Act of 1990. The most
relevant regulatory requirement is the Hazardous Waste (England and Wales)
Regulations, which came into force in July 2005. These regulations widened
the
scope of hazardous waste and have reclassified many waste products as hazardous
that were previously regarded as non-hazardous waste. The cost of compliance
with these requirements has been immaterial and the Company expects the ongoing
cost of compliance will not have a material impact on the Company.
Philippines
On
June 23, 1999, the Philippine Congress enacted the Philippine Clean Air Act
of 1999 (the “Philippine Clean Air Act”). The related implementing rules and
regulations were adopted in November 2000. The law as written would require
the
Leyte Projects to comply with a maximum discharge of 200 grams of hydrogen
sulfide per gross MWh of output by June 2004. On November 13, 2002, the
Secretary of the Philippine Department of Environment and Natural Resources
issued a Memorandum Circular (“MC”) designating geothermal areas as “special
airsheds.” PNOC-EDC has advised the Leyte Projects that the MC exempts the
Mahanagdong and Malitbog plants from the need to comply with the point-source
emission standards of the Philippine Clean Air Act. CE Cebu and PNOC-EDC have
constructed a gas dispersion facility for the Upper Mahiao project which is
designed to ensure compliance with the emission standards of the Philippine
Clean Air Act. The gas dispersion project was put into commercial operation
in
December 2003.
28
Employees
At
December 31, 2005, the Company employed approximately 11,400 people, of
which approximately 3,900 are covered by union contracts. MidAmerican Energy’s
union contract with International Brotherhood of Electrical Workers locals
109
and 499 was set to expire on February 28, 2006, and covers approximately
1,700 employee members. On February 10, 2006, the contract terms with
locals 109 and 499 were extended through April 30, 2006, and the parties
agreed to a 30-day notice of strike or lockout.
Risks
Associated with the Company’s Corporate and Financial Structure
MEHC
is a holding company that depends on distributions from its subsidiaries and
joint ventures to meet its needs.
MEHC
is a
holding company and derives substantially all of its income and cash flow from
its subsidiaries and joint ventures. MEHC expects that future development and
acquisition efforts will be similarly structured to involve operating
subsidiaries and joint ventures. MEHC is dependent on the earnings and cash
flows of, and dividends, loans, advances or other distributions from, its
subsidiaries and joint ventures to generate the funds necessary to meet its
obligations. All required payments on debt and preferred stock at subsidiary
levels will be made before funds from subsidiaries are available to MEHC. The
availability of distributions from such entities is also subject
to:
Ÿ
their
earnings and capital requirements;
Ÿ
the
satisfaction of various covenants and conditions contained in financing
documents by which they are bound or in their organizational documents;
and
Ÿ
in
the case of MEHC’s regulated utility subsidiaries, regulatory restrictions
which restrict their ability to distribute profits to
MEHC.
MEHC’s
subsidiaries and joint ventures are separate and distinct legal entities
and
have no obligation, contingent or otherwise, to pay any of MEHC’s obligations or
to make any funds available, whether by dividends, loans or other payments,
for
payment of MEHC’s obligations, and do not guarantee the payment of MEHC’s
obligations.
The
Company is substantially leveraged, the terms of MEHC’s senior and subordinated
debt do not restrict its ability or its subsidiaries’ ability to incur
additional indebtedness that could have an adverse impact on the Company’s
financial condition and MEHC’s senior and subordinated debt is structurally
subordinated to the indebtedness of its subsidiaries.
The
Company’s substantial leverage level presents the risk that it might not
generate sufficient cash to service its indebtedness or that the Company’s
leveraged capital structure could limit its ability to finance future
acquisitions, develop additional projects, compete effectively and operate
successfully under adverse economic conditions. At December 31, 2005,
MEHC’s outstanding senior indebtedness was approximately $2.8 billion and
MEHC’s outstanding subordinated indebtedness was approximately
$1.6 billion. These amounts exclude MEHC’s guarantees and letters of credit
in respect of subsidiary and equity investment indebtedness aggregating
approximately $90.9 million as of December 31, 2005. The Company
expects to incur additional indebtedness in the future, including approximately
$1.7 billion of MEHC long-term senior debt.
MEHC’s
subsidiaries also have significant amounts of indebtedness. At December 31,2005, MEHC’s consolidated subsidiaries had outstanding indebtedness totaling
approximately $7.2 billion. This amount does not include (i) any trade debt
or preferred stock obligations of MEHC’s subsidiaries, (ii) its subsidiaries’
letters of credit in respect of their indebtedness, (iii) MEHC’s share of the
outstanding indebtedness of its and its subsidiaries’ equity investments, or
(iv) the outstanding indebtedness and preferred stock of PacifiCorp, which
was
approximately $4.3 billion at December 31, 2005.
29
The
terms
of MEHC’s senior and subordinated debt do not limit its ability or the ability
of its subsidiaries or joint ventures to incur additional debt or issue
additional preferred stock. Accordingly, MEHC or its subsidiaries or joint
ventures could enter into acquisitions, refinancings, recapitalizations or
other
highly leveraged transactions that could significantly increase MEHC’s or their
total amount of outstanding debt. The interest payments needed to service this
increased level of indebtedness could have a material adverse effect on MEHC’s
or its subsidiaries’ operating results. A highly leveraged capital structure
could also impair MEHC’s or its subsidiaries’ overall credit quality, making it
more difficult for the Company to finance its operations or issue future
indebtedness on favorable terms, and could result in a downgrade in the ratings
of the Company’s indebtedness by credit rating agencies. Further, if any of
MEHC’s or its subsidiaries’ indebtedness is accelerated due to an event of
default under such indebtedness and such acceleration results in an event of
default under some or all of the Company’s other indebtedness, the Company may
not have sufficient funds to repay all of the accelerated
indebtedness.
Claims
of
creditors of MEHC’s subsidiaries and joint ventures have priority over the
claims of MEHC’s senior and subordinated debt holders with respect to the assets
and earnings of MEHC’s subsidiaries and joint ventures. In addition, the stock
or assets of substantially all of MEHC’s operating subsidiaries and joint
ventures is directly or indirectly pledged to secure their financings and,
therefore, may be unavailable as potential sources of repayment of MEHC’s senior
and subordinated debt.
MEHC’s
majority stockholder, Berkshire Hathaway, could exercise control over the
Company in a manner that would benefit Berkshire Hathaway to the detriment
of
the Company’s creditors.
MEHC
became a majority owned subsidiary of Berkshire Hathaway on February 9,2006, and, therefore, Berkshire Hathaway has control over the decision of all
matters submitted for shareholder approval, including the election of MEHC’s
directors who oversee its management and affairs. In circumstances involving
a
conflict of interest between Berkshire Hathaway, on the one hand, and MEHC’s
creditors, on the other, Berkshire Hathaway could exercise its control in a
manner that would benefit Berkshire Hathaway to the detriment of MEHC’s
creditors.
The
Company’s growth has been achieved, in significant part, through strategic
acquisitions, and additional acquisitions may not be
successful.
The
Company’s growth has been achieved, in significant part, through strategic
acquisitions. The Company intends to continue to pursue selected opportunities
for acquisitions of assets and businesses, as well as business combinations,
within the Company’s industries for the foreseeable future. The Company
investigates opportunities that it believes may increase shareholder value
and
build on existing businesses. The Company has participated in the past, and
the
Company’s security holders may assume that at any time the Company may be
participating, in bidding or other negotiations for such transactions. This
participation may or may not result in a transaction for the Company. Any
transaction that does take place may involve consideration in the form of cash,
debt or equity securities.
Since
1996, the Company has completed several significant acquisitions, including
the
acquisitions of Northern Electric, Yorkshire Electricity, MidAmerican Energy,
Kern River and Northern Natural Gas. In May 2005, MEHC announced that it had
reached a definitive agreement with ScottishPower to acquire its wholly-owned
indirect subsidiary, PacifiCorp, a regulated electric utility for a cash
purchase price of approximately $5.1 billion. Subject to the most favored
states process with the regulatory authorities in certain states where
PacifiCorp has operations and other customary closing conditions, MEHC expects
this transaction to close in March 2006.
The
successful integration of any businesses the Company may acquire in the future
will entail numerous risks, including, among others, the risk of diverting
management’s attention from day-to-day operations, the risk that the acquired
businesses will require substantial capital and financial investments and the
risk that the investments will fail to perform in accordance with expectations.
Any substantial diversion of management attention and any substantial
difficulties encountered in the transition and integration process could have
a
material adverse effect on the Company’s revenues, levels of expenses and
operating results.
30
In
addition, it has been publicly reported over the past several years that many
of
the participants in the United States energy industry, including the prior
owners of Kern River and Northern Natural Gas and potentially including other
industry participants from whom the Company may choose to purchase additional
businesses in the future, have had or may have liquidity, creditworthiness
and
other financial difficulties. As a consequence, there can be no assurance that
any such sellers will not enter into bankruptcy or insolvency proceedings or
that they will otherwise be able, required or willing to perform on their
indemnification obligations to the Company if it should elect to pursue any
such
claims the Company may have against any of them under our acquisition agreements
in the future. If the Company’s due diligence efforts were or are unsuccessful
in identifying and analyzing all material liabilities relating to acquired
companies and if there were to be any material undisclosed liabilities, or
if
there were to be other unexpected consequences from any such bankruptcy or
insolvency proceeding, such as a successful challenge as to whether the prices
paid by the Company constituted reasonably equivalent value within the meaning
of the relevant bankruptcy laws, then any such bankruptcy or insolvency, or
failure by any of these sellers to perform their indemnification obligations
to
the Company, could have a material adverse effect on the Company’s business,
financial condition, results of operations and the market prices and rates
for
the Company’s securities.
The
Company cannot provide assurance that future acquisitions, if any, or any
related integration efforts will be successful, or that the Company’s ability to
repay its debt will not be adversely affected by any future
acquisitions.
The
Company is actively pursuing, developing and constructing new or expanded
facilities, the completion and expected cost of which is subject to significant
risk.
Through
MEHC’s operating subsidiaries, the Company is continuing to develop, construct,
own and operate new or expanded facilities, including new electric generating
projects in Iowa. The Company also expects that its existing subsidiaries and
PacifiCorp will make substantial annual capital expenditures relating to new
or
expanded facilities over the next five years. MEHC is under no contractual
obligation to provide capital to any of its subsidiaries. If MEHC does not
provide any required funding to any of its subsidiaries, such subsidiaries
may
be unable to fund required capital requirements and may need to postpone or
cancel planned capital expenditures. Any such postponement or cancellation
of
planned capital expenditures could result in system reliability issues,
environmental issues, penalties for outages or noncompliance with laws and
the
inability to earn a return on amounts expended.
In
the
future the Company expects to pursue the development, construction, ownership
and operation of additional new or expanded energy projects (including, without
limitation, generation, distribution, transmission, exploration/production,
storage and supply projects and related activities, infrastructure and
services), both domestically and internationally. The completion of any or
all
of these pending, proposed or future projects is subject to substantial risk
and
may expose the Company to significant costs. The Company cannot assure you
that
its development or construction efforts on any particular project or the
Company’s efforts generally, will be successful. If the Company is unable to
complete the development or construction of any such project, or if it decides
to delay or cancel a project, the Company may not be able to recover its
investment in that project.
Also,
a
proposed expansion or new project may cost more than planned to complete, and
such excess costs, if related to a regulated asset and found to be imprudent,
may not be recoverable in rates. The inability to successfully and timely
complete a project or avoid unexpected costs may require the Company to perform
under guarantees, and the inability to avoid unsuccessful projects or to recover
any excess costs may materially affect the Company’s ability to service its
obligations.
MEHC’s
subsidiaries are subject to certain operating uncertainties which may adversely
affect the Company’s financial position, results of operation and ability to
service MEHC’s senior and subordinated debt.
The
operation of complex electric and natural gas utility (including transmission
and distribution) systems, pipelines or power generating facilities which are
spread over a large geographic area involves many risks associated with
operating uncertainties and events beyond the Company’s control. These risks
include the breakdown or failure of power generation equipment, compressors,
pipelines, transmission and distribution lines or other equipment or processes,
unscheduled plant outages, work stoppages, transmission and distribution system
constraints or outages, fuel shortages or interruptions, performance below
expected levels of output, capacity or efficiency, operator error and
catastrophic events such as severe storms, fires, earthquakes or explosions.
A
casualty occurrence might result in injury or loss of life, extensive property
damage or environmental damage. The realization of any of these risks could
significantly reduce or eliminate MEHC’s affiliates’ revenues or significantly
increase MEHC’s affiliates’ expenses, thereby adversely affecting the ability to
receive distributions from subsidiaries and joint ventures. For example, if
MEHC’s affiliates cannot operate their electric or natural gas facilities at
full capacity due to restrictions imposed by environmental regulations, their
revenues could decrease due to decreased wholesale sales and their expenses
could increase due to the need to obtain energy from higher cost sources. Any
reduction of revenues for such reason, or any other reduction of MEHC’s
affiliates’ revenues or increase in their expenses resulting from the risks
described above, could decrease the Company’s net cash flow and provide the
Company with fewer funds with which to service MEHC’s senior and subordinated
debt.
31
Further,
the Company cannot provide assurance that its current and future insurance
coverage will be sufficient to replace lost revenue or cover repair and
replacement costs, especially in light of the recent catastrophic events in
the
insurance markets that make it more difficult or costly to obtain certain types
of insurance.
Acts
of sabotage and terrorism aimed at the Company’s facilities, the facilities of
the Company’s fuel suppliers or customers, or at regional transmission
facilities could adversely affect the Company’s business.
Since
the
September 11, 2001 terrorist attacks, the United States government has
issued warnings that energy assets, specifically our nation’s pipeline and
electric utility infrastructure, may be the future targets of terrorist
organizations. These developments have subjected the Company’s operations to
increased risks. Damage to the assets of the Company’s fuel suppliers, the
assets of the Company’s customers or the Company’s own assets or at regional
transmission facilities inflicted by terrorist groups or saboteurs could result
in a significant decrease in revenues and significant repair costs, force the
Company to increase security measures, cause changes in the insurance markets
and cause disruptions of fuel supplies, energy consumption and markets,
particularly with respect to natural gas and electric energy. Any of these
consequences of acts of terrorism could materially affect the Company’s results
of operations and decrease the amount of funds the Company has available to
make
payments on MEHC’s senior and subordinated debt. Instability in the financial
markets as a result of terrorism or war could also materially adversely affect
the Company’s ability to raise capital.
The
Company is subject to energy regulation, legislation and political risks and
changes in regulations and rates or legislative developments may adversely
affect the Company’s business, financial condition, results of operations and
ability to service MEHC’s senior and subordinated debt.
The
Company is subject to comprehensive governmental regulation, including
regulation in the United States by various federal, state and local regulatory
agencies, regulation in the United Kingdom and regulation in the Philippines,
all of which significantly influences the Company’s operating environment, its
rates, its capital structure, its costs and its ability to recover the Company’s
costs from customers. These regulatory agencies include, among others, the
FERC,
the EPA, the Nuclear Regulatory Commission (“NRC”), the DOT, the IUB, the ICC,
the SDPUC, other state utility boards, numerous local agencies, the GEMA, which
in discharging certain of its powers acts through its staff within Ofgem, in
the
United Kingdom, and various other governmental agencies in the United States,
the United Kingdom and the Philippines. Changes in regulations or the imposition
of additional regulations by any of these entities or new legislation could
have
a material adverse impact on the Company’s results of operations. For example,
such changes could result in increased retail competition in MidAmerican
Energy’s service territory, the acquisition by a municipality (by negotiation or
condemnation) of the Company’s distribution facilities or a negative impact on
the Company’s current transportation and cost recovery
arrangements.
The
Company also conducts its business in conformance with a multitude of federal,
state and foreign laws, which are subject to significant changes at any time.
Changes in regulations or the imposition of additional regulations by any of
these entities or new legislation could have a material adverse impact on the
Company’s results of operations. For example, such changes could result in
increased retail competition in MidAmerican Energy’s service territory,
encouragement of investments in renewable or lower-emission generation, the
acquisition by a municipality or other quasi-governmental body of MidAmerican
Energy’s distribution facilities (by negotiation, legislation or condemnation)
or a negative impact on MidAmerican Energy’s current transportation and cost
recovery arrangements.
On
August 8, 2005, the Energy Policy Act was signed into law. That law
potentially impacts many segments of the energy industry. The law will result
in
the FERC issuing new regulations and regulatory decisions in areas such as
electric system reliability, electric transmission expansion and pricing,
regulation of utility holding companies, and enforcement authority. While the
FERC has now issued rules and decisions on multiple aspects of the Energy Policy
Act, the full impact of those decisions remains uncertain. The Energy Policy
Act
also repealed PUHCA 1935, and enacted PUHCA 2005, effective February 8,2006. PUHCA 1935 extensively regulated and restricted the activities of
registered public utility holding companies and their subsidiaries. PUHCA 2005
and the rules issued by the FERC to implement PUHCA 2005 require, among other
things, public utility holding companies to permit access by the FERC to the
books and records of the holding company and its affiliates transacting business
with the public utility, unless such requirement is exempted or waived, and
to
comply with the FERC’s record retention requirements.
In
addition, as a result of past events affecting electric reliability, the Energy
Policy Act requires federal agencies, working together with non-governmental
organizations charged with electric reliability responsibilities, to adopt
and
implement measures designed to ensure the reliability of electric transmission
and distribution systems. The implementation of such measures could result
in
the imposition of more comprehensive or stringent requirements on MEHC or its
subsidiaries or other industry participants, which would result in increased
compliance costs and could have a material adverse effect on the Company’s
business, financial condition, results of operations and ability to service
its
obligations.
32
The
Company is subject to environmental, health, safety and other laws and
regulations which may adversely impact the Company.
Through
MEHC’s subsidiaries and joint ventures, it is subject to a number of
environmental, health, safety and other laws and regulations affecting many
aspects of the Company’s present and future operations, both domestic and
foreign, including air emissions, water quality, wastewater discharges, solid
wastes, hazardous substances and safety matters. The Company may incur
substantial costs and liabilities in connection with its operations as a result
of these regulations. In particular, the cost of future compliance with federal,
state and local clean air laws, such as those that require certain generators,
including some of MEHC’s subsidiaries’ electric generating facilities, to limit
nitrogen oxide emissions, sulfur dioxide, carbon dioxide, mercury emissions
and
other potential pollutants or emissions, may require the Company to make
significant capital expenditures which may not be recoverable through future
rates. In addition, these costs and liabilities may include those relating
to
claims for damages to property and persons resulting from the Company’s
operations. The implementation of regulatory changes imposing more comprehensive
or stringent requirements on the Company, to the extent such changes would
result in increased compliance costs or additional operating restrictions,
could
have a material adverse effect on the Company’s business, financial condition,
results of operations and ability to service its obligations.
In
addition, regulatory compliance for existing facilities and the construction
of
new facilities is a costly and time-consuming process, and intricate and rapidly
changing environmental regulations may require major expenditures for permitting
and create the risk of expensive delays or material impairment of value if
projects cannot function as planned due to changing regulatory requirements
or
local opposition.
PSIA
and
its implementing rules that became effective on February 14, 2004, require
interstate pipeline operators to develop comprehensive integrity management
programs, take measures to protect pipeline segments located in
‘‘high-consequence areas’’ and provide ongoing mitigation and monitoring. The
Company believes its pipeline operations currently comply in all material
respects with PSIA and related rules. However, in the future, the Company may
incur unexpected capital costs and/or operating costs in order to maintain
compliance. Moreover, regulatory agencies and the public continue to focus
on
pipeline safety issues which may result in additional inspection, monitoring,
testing, reporting and other requirements being implemented in the future that
could increase the Company’s operating costs and/or capital costs. The Company’s
FERC-approved tariffs or competition from other energy sources may not allow
the
Company to recover these increased costs of compliance.
In
addition to operational standards, environmental laws also impose obligations
to
clean up or remediate contaminated properties or to pay for the cost of such
remediation, often upon parties that did not actually cause the contamination.
Accordingly, the Company may become liable, either contractually or by operation
of law, for remediation costs even if the contaminated property is not presently
owned or operated by the Company, or if the contamination was caused by third
parties during or prior to the Company’s ownership or operation of the property.
Given the nature of the past industrial operations conducted by the Company
and
others at its properties, there can be no assurance that all potential instances
of soil or groundwater contamination have been identified, even for those
properties where an environmental site assessment or other investigation has
been conducted. Although the Company has accrued reserves for its known
remediation liabilities, future events, such as changes in existing laws or
policies or their enforcement, or the discovery of currently unknown
contamination, may give rise to additional remediation liabilities which may
be
material. Any failure to recover increased environmental, health or safety
costs
incurred by the Company may have a material adverse effect on the Company’s
business, financial condition, results of operations and ability to service
its
obligations.
One
of MEHC’s indirect wholly owned subsidiaries, MidAmerican Energy, is subject to
the unique risks associated with nuclear generation.
Regulatory
requirements applicable in the future to nuclear generating facilities could
adversely affect the results of operations of MEHC and, in particular,
MidAmerican Energy. The Company is subject to certain generic risks associated
with utility nuclear generation, which include the following:
Ÿ
the
potential harmful effects on the environment and human health resulting
from the operation of nuclear facilities and the storage, handling
and
disposal of high-level and low-level radioactive
materials;
Ÿ
limitations
on the amounts and types of insurance commercially available in
respect of
losses that might arise in connection with nuclear operations;
and
Ÿ
uncertainties
with respect to the technological and financial aspects of decommissioning
nuclear plants at the end of their licensed
lives.
33
The
NRC
has broad authority under federal law to impose licensing and safety-related
requirements for the operation of nuclear generating facilities. In the event
of
noncompliance, the NRC has the authority to impose fines or shut down a unit,
or
both, depending upon its assessment of the severity of the situation, until
compliance is achieved. Revised safety requirements promulgated by the NRC
have,
in the past, necessitated substantial capital expenditures at nuclear plants,
including the facility in which MidAmerican Energy has an ownership interest,
and additional expenditures could be required in the future. In addition,
although the Company has no reason to anticipate a serious nuclear incident
at
the facility in which MidAmerican Energy has an interest, if an incident did
occur, it could have a material but presently undeterminable adverse effect
on
the Company’s financial position, results of operations and ability to service
its obligations.
Increased
competition resulting from legislative, regulatory and restructuring efforts
could have a significant financial impact on the Company and its utility
subsidiaries and consequently decrease the Company’s revenue.
The
wholesale generation segment of the electric industry has been and will continue
to be significantly impacted by competition. Competition in the wholesale market
has resulted in a proliferation of power marketers and a substantial increase
in
market activity. Many of these marketers have experienced financial difficulties
and the market continues to be volatile. Margins from wholesale electric
transactions have a material impact on the Company’s results of operations.
Accordingly, significant changes in the wholesale electric markets could have
a
material adverse effect on the Company’s financial position, results of
operations and the ability to service its obligations.
As
a
result of FERC orders, including Order 636, the FERC’s policies favoring
competition in natural gas markets, the expansion of existing pipelines and
the
construction of new pipelines, the interstate pipeline industry has experienced
some failure to renew, or turn back, of firm capacity, as existing
transportation service agreements expire and are terminated. LDCs and end-use
customers have more choices in the new, more competitive environment and may
be
able to obtain service from more than one pipeline to fulfill their natural
gas
delivery requirements. If a pipeline experiences capacity turn back and is
unable to remarket the capacity, the pipeline or its remaining customers may
have to bear the costs associated with the capacity that is turned back. Any
new
pipelines that are constructed could compete with the Company’s pipeline
subsidiaries for customers’ service needs. Increased competition could reduce
the volumes of gas transported by the Company’s pipeline subsidiaries or, in
cases where they do not have long-term fixed rate contracts, could force the
Company’s pipeline subsidiaries to lower their rates to meet competition. This
could adversely affect the Company’s pipeline subsidiaries’ financial
results.
A
significant decrease in demand for natural gas in the markets served by the
Company’s subsidiaries’ pipeline and distribution systems would significantly
decrease the Company’s revenue and thereby adversely affect the Company’s
business, financial condition, results of operations and ability to service
its
obligations.
A
sustained decrease in demand for natural gas in the markets served by the
Company’s subsidiaries’ pipeline and distribution systems would significantly
reduce the Company’s revenues and adversely affect the Company’s ability to
service its obligations. Factors that could lead to a decrease in market demand
include:
Ÿ
a
recession or other adverse economic condition that results in a
lower
level of economic activity or reduced spending by consumers on
natural
gas;
Ÿ
an
increase in the market price of natural gas or a decrease in the
price of
other competing forms of energy, including electricity, coal and
fuel
oil;
Ÿ
higher
fuel taxes or other governmental or regulatory actions that increase,
directly or indirectly, the cost of natural gas or that limit the
use of
natural gas;
Ÿ
a
shift by consumers to more fuel-efficient or alternative fuel machinery
or
an improvement in fuel economy, whether as a result of technological
advances by manufacturers, pending legislation proposing to mandate
higher
fuel economy, or otherwise; and
Ÿ
a
shift by the Company’s pipeline and distribution customers to the use of
alternate fuels, such as fuel oil, due to price differentials or
other
incentives.
34
Cyclical
fluctuations in the residential real estate brokerage and mortgage businesses
could adversely affect HomeServices.
MEHC’s
subsidiary, HomeServices, has experienced strong revenue growth and increases
in
net income in each of the years ended December 31, 2005, 2004 and 2003. The
residential real estate brokerage and mortgage industries tend to experience
cycles of greater and lesser activity and profitability and are typically
affected by changes in economic conditions which are beyond HomeServices’
control. Any of the following could have a material adverse effect on
HomeServices’ businesses by causing a general decline in the number of home
sales, sale prices or the number of home financings which, in turn, would
adversely affect revenues and profitability:
·
rising
interest rates or unemployment
rates;
·
periods
of economic slowdown or recession in the markets
served;
·
decreasing
home
affordability; and
·
declining
demand for residential real estate as an
investment.
Failure
of the Company’s significant power purchasers, pipeline customers and British
retail suppliers to pay amounts due under their contracts or other commitments
could reduce the Company’s revenues materially.
MEHC’s
subsidiaries’ non-utility generating facilities and both of the Company’s
pipeline subsidiaries are dependent upon a relatively small number of customers
for a significant portion of their revenues. In addition, the Company’s utility
distribution businesses in Great Britain are dependent upon a relatively small
number of retail suppliers, including one retail supplier who represents
approximately 44% of the total revenues of our utility distribution businesses
in Great Britain. As a result, the Company’s profitability and ability to make
payments under its obligations generally will depend in part upon the continued
financial performance and creditworthiness of these customers. Accordingly,
failure of one or more of the Company’s most significant customers to pay for
contracted electric generating capacity, pipeline capacity reservation charges
or distribution system use charges, as applicable, for reasons related to
financial distress or otherwise, could reduce the Company’s revenues materially
if the Company is not able to make adequate alternate arrangements on a timely
basis, such as adequate replacement contracts. The replacement of any of the
Company’s existing long-term contracts or British retail suppliers, should it
become necessary, will depend on a number of factors beyond the Company’s
control, including:
·
the
availability of economically deliverable natural gas for transport
through
the Company’s pipeline system, including in particular continued
availability of adequate supplies from the Rocky Mountains, Hugoton,
Permian, Anadarko and Western Canadian supply basins currently accessible
to the Company’s pipeline
subsidiaries;
·
existing
competition to deliver natural gas to the upper Midwest and southern
California;
·
new
pipelines or expansions potentially serving the same markets as the
Company’s pipelines;
·
the
growth in demand for natural gas in the upper Midwest, southern
California, Nevada and Utah;
·
whether
transportation of natural gas pursuant to long-term contracts continues
to
be market practice;
·
the
actions of regulators, including the electricity regulator in Great
Britain;
·
the
availability and financial condition of replacement British retail
suppliers; and
·
whether
the Company’s business strategy, including its expansion strategy,
continues to be successful.
Any
failure to replace a significant portion of these contracts on adequate terms
or
to make other adequate alternate arrangements, should it become necessary,
may
have a material adverse effect on the Company’s business, financial condition,
results of operations and ability to service its obligations.
The
Company’s utility and non-utility energy businesses are subject to power and
fuel price fluctuations, other weather risks, commodity price risks and credit
risks that could adversely affect the Company’s results of
operations.
The
Company is exposed to commodity price risks, energy transmission price risks
and
credit risks in MEHC’s subsidiaries’ generation, retail distribution and
pipeline operations. Specifically, such possible risks include commodity price
changes, market supply shortages, interest rate changes and counterparty
defaults, all of which could have an adverse effect on the Company’s financial
condition, results of operations and ability to service its obligations. In
addition, the sale of electric power and natural gas is generally a seasonal
business, which seasonality results in competitive price fluctuations. The
Company’s revenues are negatively impacted by low commodity prices resulting
from low demand for electricity. Demand for electricity often peaks during
the
hottest summer months and coldest winter months and declines during the other
months. As a result of these variations in demand and resulting price
fluctuations, the Company’s overall operating results in the future may
fluctuate substantially on a seasonal basis. The Company has historically earned
less income when weather conditions are milder. The Company expects that
unusually mild weather in the future could decrease its revenues and provide
the
Company with fewer funds available to service its obligations.
35
Also,
in
Iowa, MidAmerican Energy does not have an ability to pass through fuel price
increases in its rates (an energy adjustment clause), so any significant
increase in fuel costs or purchased power costs for electricity generation
could
have a negative impact on MidAmerican Energy, despite the Company’s efforts to
minimize this negative impact through the use of hedging instruments. The impact
of these risks could result in MidAmerican Energy’s inability to fulfill
contractual obligations, significantly higher energy or fuel costs relative
to
corresponding sales contracts or increased interest expense. Any of these
consequences could decrease the Company’s net cash flow and impair its ability
to make payments on its obligations.
The
Company has significant operations outside the United States which may be
subject to increased risk because of the economic or political conditions of
the
country in which they operate.
The
Company has a number of operations outside of the United States. The
acquisition, ownership and operation of businesses outside the United States
entails significant political and financial risks (including, without
limitation, uncertainties associated with privatization efforts, inflation,
currency exchange rate fluctuations, currency repatriation restrictions, changes
in law or regulation, changes in government policy, political instability,
civil
unrest and expropriation) and other risk/structuring issues that have the
potential to cause material impairment of the value of the business being
operated, which the Company may not be capable of fully insuring against. The
risk of doing business outside of the United States could be greater than in
the
United States because of specific economic or political conditions of each
country. The uncertainty of the legal environment in certain foreign countries
in which the Company operates or may acquire projects or businesses could make
it more difficult for the Company to enforce its rights under agreements
relating to such projects or businesses. The Company’s international projects
may be subject to the risk of being delayed, suspended or terminated by the
applicable foreign governments or may be subject to the risk of contract
abrogation, expropriations or other uncertainties resulting from changes in
government policy or personnel or changes in general political or economic
conditions affecting the country or otherwise. In addition, the laws and
regulations of certain countries may limit the Company’s ability to hold a
majority interest in some of the projects or businesses that it may acquire.
Furthermore, the central bank of any such country may have the authority in
certain circumstances to suspend, restrict or otherwise impose conditions on
foreign exchange transactions or to restrict distributions to foreign investors.
Although the Company may structure certain project revenue and other agreements
to provide for payments to be made in, or indexed to, U.S. dollars or a currency
freely convertible into U.S. dollars, there can be no assurance that the Company
will be able to obtain sufficient U.S. dollars or other hard currency or that
available U.S. dollars will be allocated to pay such obligations.
The
Company faces exchange rate risk.
Payments
from some of the Company’s foreign investments, including without limitation CE
Electric UK, are made in a foreign currency and any dividends or distributions
of earnings in respect of such investments may be significantly affected by
fluctuations in the exchange rate between the U.S. dollar and the sterling
or
other applicable foreign currency, which could adversely affect the Company’s
financial condition and results of operations. Although the Company may enter
into certain transactions to hedge risks associated with exchange rate
fluctuations, there can be no assurance that such transactions will be
successful in reducing such risks.
The
Company’s utility properties consist of physical assets necessary and
appropriate to render electric and gas service in its service territories.
Electric property consists primarily of generation, transmission and
distribution facilities and related rights-of-way. Gas property consists
primarily of distribution plants, natural gas pipelines, related rights-of-way,
compressor stations and meter stations. It is the opinion of management that
the
principal depreciable properties owned by the Company are in good operating
condition and well maintained. Pursuant to separate financing agreements,
substantially all or most of the properties of each subsidiary (except CE
Electric UK and Northern Natural Gas) are pledged or encumbered to support
or
otherwise provide the security for their own project or subsidiary debt. Refer
to Item 1. Business and Note 4 and Note 22 of Notes to Consolidated Financial
Statements included in Item 8. Financial Statements and Supplementary Data
of
this Form 10-K for additional information about the Company’s
properties.
36
The
right
to construct and operate the pipelines across certain property was obtained
through negotiations and through the exercise of the power of eminent domain,
where necessary. Kern River and Northern Natural Gas continue to have the power
of eminent domain in each of the states in which they operate their respective
pipelines, but they do not have the power of eminent domain with respect to
Native American tribal lands. Although the main Kern River pipeline crosses
the
Moapa Indian Reservation, all facilities are located within a utility corridor
that is reserved to the United States Department of Interior, Bureau of Land
Management.
With
respect to real property, each of the pipelines falls into two basic categories:
(1) parcels that are owned in fee, such as certain of the compressor stations,
measurement stations and district office sites; and (2) parcels where the
interest derives from leases, easements, rights-of-way, permits or licenses
from
landowners or governmental authorities permitting the use of such land for
the
construction, operation and maintenance of the pipelines. MEHC believes that
Kern River and Northern Natural Gas each have satisfactory title to all of
the
real property making up their respective pipelines in all material
respects.
In
addition to the proceedings described below, the Company is currently party
to
various items of litigation or arbitration in the normal course of business,
none of which are reasonably expected by the Company to have a material adverse
effect on its financial position, results of operations or cash flows. See
Item
1. Business and Item 8. Financial Statements and Supplementary Data of this
Form
10-K for details relative to environmental matters affecting the
Company.
Pipeline
Litigation
In
1998,
the United States Department of Justice informed the then current owners of
Kern
River and Northern Natural Gas that Jack Grynberg, an individual, had filed
claims in the United States District Court for the District of Colorado under
the False Claims Act against such entities and certain of their subsidiaries
including Kern River and Northern Natural Gas. Mr. Grynberg has also filed
claims against numerous other energy companies and alleges that the defendants
violated the False Claims Act in connection with the measurement and purchase
of
hydrocarbons. The relief sought is an unspecified amount of royalties allegedly
not paid to the federal government, treble damages, civil penalties, attorneys’
fees and costs. On April 9, 1999, the United States Department of Justice
announced that it declined to intervene in any of the Grynberg qui tam cases,
including the actions filed against Kern River and Northern Natural Gas in
the
United States District Court for the District of Colorado. On October 21,1999, the Panel on Multi-District Litigation transferred the Grynberg qui tam
cases, including the ones filed against Kern River and Northern Natural Gas,
to
the United States District Court for the District of Wyoming for pre-trial
purposes. On October 9, 2002, the United States District Court for the
District of Wyoming dismissed Grynberg’s royalty valuation claims. On
November 19, 2002, the United States District Court for the District of
Wyoming denied Grynberg’s motion for clarification and dismissed his royalty
valuation claims. Grynberg appealed this dismissal to the United States Court
of
Appeals for the Tenth Circuit and on May 13, 2003, the Tenth Circuit Court
dismissed his appeal. On May 17, 2005, Kern River and Northern Natural Gas
each received a Special Master’s Report and Recommendations in which the Special
Master recommended that the action against Kern River and Northern Natural
Gas
be dismissed for lack of subject matter jurisdiction. Grynberg and the
coordinated defendants each filed motions relating to the Special Master’s
Report and Recommendations on June 27, 2005. Oral arguments on the parties’
motions were held on December 9, 2005, and the parties are awaiting a
ruling from the court regarding this report. In connection with the purchase
of
Kern River from The Williams Companies, Inc. (“Williams”) in March 2002,
Williams agreed to indemnify MEHC against any liability for this claim; however,
no assurance can be given as to the ability of Williams to perform on this
indemnity should it become necessary. No such indemnification was obtained
in
connection with the purchase of Northern Natural Gas in August 2002. The Company
believes that the Grynberg cases filed against Kern River and Northern Natural
Gas are without merit and that Williams, on behalf of Kern River pursuant to
its
indemnification, and Northern Natural Gas, intend to defend these actions
vigorously.
On
June 8, 2001, a number of interstate pipeline companies, including Kern
River and Northern Natural Gas, were named as defendants in a nationwide class
action lawsuit which had been pending in the 26th Judicial District, District
Court, Stevens County Kansas, Civil Department against other defendants,
generally pipeline and gathering companies, since May 20, 1999. The
plaintiffs allege that the defendants have engaged in mismeasurement techniques
that distort the heating content of natural gas, resulting in an alleged
underpayment of royalties to the class of producer plaintiffs. On May 12,2003, the plaintiffs filed a motion for leave to file a fourth amended petition
alleging a class of gas royalty owners in Kansas, Colorado and Wyoming. The
court granted the motion for leave to amend on July 28, 2003. Kern River
was not a named defendant in the amended complaint and has been dismissed from
the action. Northern Natural Gas filed an answer to the fourth amended petition
on August 22, 2003. On January 4, 2005, the plaintiffs filed their
class certification motion and brief in support of that motion. Northern Natural
Gas filed its joint brief and expert affidavits in opposition to class
certification on February 22, 2005. The plaintiffs filed their reply brief
in support of class certification on March 18, 2005. Northern Natural Gas
believes that this claim is without merit.
37
Similar
to the June 8, 2001 matter referenced above, the plaintiffs in that matter
have filed a new companion action against a number of parties, including
Northern Natural Gas but excluding Kern River, in a Kansas state district court
for damages for mismeasurement of British thermal unit content, resulting in
lower royalties. The action was filed on May 12, 2003. On January 4,2005, the plaintiffs filed their class certification motion and brief in support
of that motion. Northern Natural Gas filed its joint brief and expert affidavits
in opposition to class certification on February 22, 2005. The plaintiffs
filed their reply brief in support of class certification on March 18,2005. Northern Natural Gas believes that this claim is without
merit.
MidAmerican
Energy
Natural
Gas Commodity Litigation
MidAmerican
Energy is one of dozens of companies named as defendants in a January 20,2004 consolidated class action lawsuit filed in the United States District
Court
for the Southern District of New York. The suit alleges that the defendants
have
engaged in unlawful manipulation of the prices of natural gas futures and
options contracts traded on the New York Mercantile Exchange (“NYMEX”) during
the period January 1, 2000 to December 31, 2002. MidAmerican Energy is
mentioned as a company that has engaged in wash trades on Enron Online (an
electronic trading platform) that had the effect of distorting prices for gas
trades on the NYMEX. The plaintiffs to the class action do not specify the
amount of alleged damages. On September 9, 2005, MidAmerican Energy and
counsel for the plaintiffs executed a stipulation and agreement of settlement,
which, upon final approval by the court following notice to all class members,
MidAmerican Energy will be dismissed from the lawsuit. The settlement was filed
with the court on February 2, 2006 and approved by the court on a
preliminary basis on February 8, 2006. If finally accepted by the court,
the settlement will not have a material impact upon MidAmerican Energy.
Additionally, the court issued an order on September 29, 2005, granting the
plaintiffs’ motion for class certification.
Other
On
December 28, 2004, an apparent gas explosion and fire resulted in three
fatalities, one serious injury and property damage at a commercial building
in
Ramsey, Minnesota. According to the Minnesota Office of Pipeline Safety, an
improper installation of a pipeline connection may have been a cause of the
explosion and fire. A predecessor company to MidAmerican Energy allegedly
provided gas service in Ramsey, Minnesota at the time of the original
installation of the pipeline in 1980. In 1993, a predecessor of CenterPoint
Resources Corp. (“CenterPoint”) acquired all of the Minnesota gas properties
owned by the MidAmerican Energy predecessor company.
As
a
result of the explosion and fire, MidAmerican Energy and CenterPoint have
received settlement demands which total $15.5 million. MidAmerican Energy’s
exposure, if any, to these demands are covered under its liability insurance
coverage to which a $2.0 million retention applies. In addition, counsel
for CenterPoint stated that a replacement program has been initiated for the
purpose of locating and replacing all mechanical couplings in the former North
Central Public Service Company properties located in Minnesota. Counsel for
CenterPoint has represented that it is anticipated that the value of the
replacement claim may be in the range of $35-$45 million.
On
February 8, 2006, MidAmerican Energy was served with a Third Party
Complaint filed in U.S. District Court, District of Minnesota by CenterPoint.
The Third Party Complaint seeks contribution and indemnity on a wrongful death
claim filed by the estate of one of the decedents and all sums associated with
CenterPoint’s replacement program. An additional compliant filed by the estate
of one of the decedents seeks damages from MEHC and other defendants, including
CenterPoint, on a wrongful death claim arising from this incident. MEHC and
MidAmerican Energy intend to vigorously defend their position in these claims
and believe their ultimate outcome will not have a material impact on their
results of operations, financial position or cash flows.
38
Philippines
Pursuant
to the share ownership adjustment mechanism in the CE Casecnan stockholder
agreement, which is based upon pro forma financial projections of the Casecnan
Project prepared following commencement of commercial operations, in February
2002, MEHC’s indirect wholly-owned subsidiary, CE Casecnan Ltd., advised the
minority stockholder of CE Casecnan, LaPrairie Group Contractors
(International) Ltd. (“LPG”), that MEHC’s indirect ownership interest in
CE Casecnan had increased to 100% effective from commencement of commercial
operations. On July 8, 2002, LPG filed a complaint in the Superior Court of
the State of California, City and County of San Francisco against
CE Casecnan Ltd., KEIL Casecnan Ltd. (“KE”), a former stockholder, and
MEHC. LPG’s complaint, as amended, seeks compensatory and punitive damages
arising out of CE Casecnan Ltd.’s and MEHC’s alleged improper calculation
of the proforma financial projections. On January 21, 2004, CE Casecnan
Ltd., LPG and CE Casecnan entered into a status quo agreement pursuant to which
the parties agreed to set aside certain distributions related to the shares
subject to the LPG dispute and CE Casecnan agreed not to take any further
actions with respect to such distributions without at least 15 days prior notice
to LPG. Accordingly, 15% of the CE Casecnan dividend distributions declared
in
2004 and 2005, totaling $17.6 million, was set aside in a separate bank
account in the name of CE Casecnan and is shown as restricted cash and
short-term investments and other current liabilities in the accompanying
consolidated balance sheets included in Item 8. Financial Statements and
Supplementary Data of this Form 10-K.
On
August 4, 2005, the court issued a decision, ruling in favor of LPG on five
of the eight disputed issues in the first phase of the litigation. On
September 12, 2005, LPG filed a motion seeking the release of the funds
which have been set aside pursuant to the status quo agreement referred to
above. MEHC and CE Casecnan Ltd. filed an opposition to the motion on October3,2005, and at the hearing on October 26, 2005, the court denied LPG’s
motion. On January 3, 2006, the court entered a judgment in favor of LPG
against CE Casecnan Ltd. and KE. According to the judgment LPG would retain
its
ownership of 15% of the shares of CE Casecnan and distributions of the amounts
deposited into escrow plus interest at 9% per annum. On February 28, 2006,
CE Casecnan Ltd. and KE filed an appeal of this judgment and the August 4,2005 decision. The appeal is expected to be resolved sometime in 2007. The
impact, if any, of this litigation on the Company cannot be determined at this
time.
In
February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. (“San
Lorenzo”), an original shareholder substantially all of whose shares in CE
Casecnan were purchased by MEHC in 1998, threatened to initiate legal action
against the Company in the Philippines in connection with certain aspects of
its
option to repurchase such shares. On July 1, 2005, MEHC and
CE Casecnan Ltd. commenced an action against San Lorenzo in the
District Court of Douglas County, Nebraska, seeking a declaratory judgment
as to
MEHC’s and CE Casecnan Ltd.'s rights vis-à-vis San Lorenzo in respect of such
shares. San Lorenzo filed a motion to dismiss on September 19, 2005.
The motion was heard on October 21, 2005, and the court took the matter
under advisement. Subsequently, San Lorenzo purported to exercise its option
to
repurchase such shares. On January 30, 2006, San Lorenzo filed a
counterclaim against MEHC and CE Casecnan Ltd. seeking declaratory relief that
it has effectively exercised its option to purchase 15% of the shares of CE
Casecnan, that it is the rightful owner of such shares, and that it is due
all
dividends paid on such shares. The impact, if any, of San Lorenzo’s purported
exercise of its option and the Nebraska litigation on the Company cannot be
determined at this time. The Company intends to vigorously defend the
counterclaims.
Mirant
Americas Energy Marketing (“Mirant”) Claim
Mirant
was one of the shippers that entered into a 15-year, 2003 Expansion Project,
firm gas transportation contract (90,000 Dth per day) with Kern River (the
“Mirant Agreement”) and provided a letter of credit equivalent to 12 months of
reservation charges as security for its obligations thereunder. In July 2003,
Mirant filed for Chapter 11 bankruptcy protection and Kern River subsequently
drew on the letter of credit and held the proceeds thereof, $14.8 million,
as cash collateral. Kern River claimed $210.2 million in damages due to the
rejection of the Mirant Agreement. The bankruptcy court ultimately determined
that Kern River was entitled to a general unsecured claim of $74.4 million
in addition to the $14.8 million cash collateral. In January 2006, Mirant
emerged from bankruptcy and on February 6, 2006, a stipulated judgment was
entered that allowed Kern River to receive a pro rata amount of shares of new
Mirant stock determined by Kern River’s allowed claim amount plus interest in
relation to the unsecured creditor class of over $6 billion. On
February 10, 2006, Kern River received an initial distribution of such
shares in payment of the majority of its allowed claim.
Item
4.Submission
of Matters to a Vote of Security
Holders.
Not
applicable.
39
PART
II
Item
5.
Market
for Registrant’s Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity
Securities.
Since
March 14, 2000, MEHC’s equity securities have been owned by Berkshire
Hathaway, Walter Scott, Jr. and his family interests, David L. Sokol and Gregory
E. Abel and have not been registered with the SEC pursuant to the Securities
Act
of 1933, as amended, listed on a stock exchange or otherwise publicly held
or
traded.
The
following table sets forth selected financial data, which should be read in
conjunction with Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations and with the Company’s consolidated
financial statements and the related notes to those statements included in
Item
8. Financial Statements and Supplementary Data appearing elsewhere in this
Form
10-K. The selected financial data has been derived from the Company’s historical
consolidated financial statements.
Reflects
MEHC’s decision to cease operations of the Zinc Recovery Project effective
September 10, 2004, which resulted in a non-cash, after-tax
impairment charge of $340.3 million being recorded to write-off the
Zinc Recovery Project, rights to quantities of extractable minerals,
and
allocated goodwill (collectively, the “Mineral Assets”). The charge and
related activity of the Mineral Assets, including the reclassification
of
such activity for the years ended December 31, 2003, 2002 and 2001,
are classified separately as discontinued operations.
(3)
Excludes
current portion.
40
Item
7.Management’s
Discussion and Analysis of Financial Condition
and Results of Operations.
The
following discussion and analysis should be read in combination with the
selected financial data and the consolidated financial statements included
in
Item 6. Selected Financial Data and Item 8. Financial Statements and
Supplementary Data of this Form 10-K.
Executive
Summary
MEHC,
through its subsidiaries, owns and operates a combined electric and natural
gas
utility company in the United States, two natural gas interstate pipeline
companies in the United States, two electricity distribution companies in Great
Britain, a diversified portfolio of domestic and international independent
power
projects and the second largest residential real estate brokerage firm in the
United States. These businesses are organized and managed as seven distinct
platforms: MidAmerican Energy, Kern River, Northern Natural Gas, CE Electric
UK
(which includes Northern Electric and Yorkshire Electricity), CalEnergy
Generation-Foreign, CalEnergy Generation-Domestic, and
HomeServices.
MEHC’s
energy subsidiaries generate, transmit, store, distribute and supply energy.
MEHC’s electric and natural gas utility subsidiaries currently serve
approximately 4.4 million electricity customers and approximately 688,000
natural gas customers. MEHC's natural gas pipeline subsidiaries operate
interstate natural gas transmission systems that have approximately 18,100
miles
of pipeline in operation, a peak delivery capacity of 6.6 Bcf of natural gas
per
day and transported approximately 7.8% of the total natural gas consumed in
the
United States in 2005. The Company has interests in 6,740 net owned MW of power
generation facilities in operation and under construction, including 5,166
net
owned MW in facilities that are part of the regulated asset base of its electric
utility business and 1,574 net owned MW in non-utility power generation
facilities. Substantially all of the non-utility power generation facilities
have long-term contracts for the sale of energy and/or capacity from the
facilities.
The
following significant events occurred during the years ended December 31,2005, 2004 and 2003, respectively, as discussed in more detail herein and in
Item 1. Business of this Form 10-K, that highlight some of the factors which
affected, or may affect in the future, the Company’s financial condition,
results of operations and liquidity:
·
In
May 2005, MEHC reached a definitive agreement with ScottishPower and
its subsidiary, PacifiCorp Holdings, Inc., to acquire 100% of the
common
stock of ScottishPower’s wholly-owned indirect subsidiary, PacifiCorp, a
regulated electric utility, for approximately $5.1 billion in cash.
Subject to the most favored states process and other customary closing
conditions, the transaction is expected to close in March 2006. MEHC
expects to fund the acquisition of PacifiCorp with the proceeds from
an
investment by Berkshire Hathaway and other existing shareholders
of
approximately $3.4 billion in MEHC common stock and the issuance by
MEHC of $1.7 billion of either additional common stock to Berkshire
Hathaway or long-term senior notes to third parties. According to
PacifiCorp’s most recent Form 10-Q filed with the SEC, PacifiCorp had
total assets of $12.8 billion as of December 31, 2005, and had
$2.7 billion of operating revenue and $213.6 million of net
income, respectively, for the nine months ended December 31,2005.
·
On
February 9, 2006, following the effective date of the repeal of PUHCA
1935, Berkshire Hathaway converted its 41,263,395 shares of MEHC’s no par,
zero-coupon convertible preferred stock into an equal number of shares
of
MEHC’s common stock. As a consequence, Berkshire Hathaway owns 83.4%
(80.5% on a diluted basis) of the outstanding common stock of MEHC,
will
consolidate the Company in its financial statements as a majority-owned
subsidiary, and will include the Company in its consolidated federal
U.S.
income tax return.
·
On
March 1, 2006, MEHC and Berkshire Hathaway entered into the Berkshire
Equity Commitment pursuant to which Berkshire Hathaway has agreed
to
purchase up to $3.5 billion of common equity of MEHC upon any
requests authorized from time to time by the Board of Directors of
MEHC.
The proceeds of any such equity contribution shall only be used for
the
purpose of (a) paying when due MEHC’s debt obligations and (b) funding the
general corporate purposes and capital requirements of the Company’s
regulated subsidiaries. Berkshire Hathaway will have up to 180 days
to
fund any such request. The Berkshire Equity Commitment will expire
on
February 28, 2011, and will not be used for the PacifiCorp
acquisition or for other future
acquisitions.
41
·
MidAmerican
Energy has continued its construction of electric generation facilities
in
Iowa by placing in-service 900.5 MW (nameplate rating) of capacity
during
2005, 2004 and 2003. Projects completed include the 540 MW (nameplate
rating) combined-cycle Greater Des Moines Energy Center in 2003 and
2004
and 360.5 MW (nameplate rating) of wind turbines in 2005 and 2004.
Additionally, MidAmerican Energy is currently constructing CBEC
Unit 4, a 790 MW (expected accreditation) super-critical-temperature,
low sulfur coal-fired generating plant of which MidAmerican Energy’s share
is 479 MW, and has made a filing with the IUB for approval to add
up to
545 MW (nameplate rating) of additional wind generation
capacity.
·
Kern
River completed construction of its 2003 Expansion Project in May
2003 at
a total cost of $1.2 billion.
·
Indirect
wholly-owned subsidiaries of MEHC own the rights to commercial quantities
of extractable minerals from elements in solution in the geothermal
brine
and fluids utilized at the Imperial Valley Projects and a zinc recovery
plant constructed near the Imperial Valley Projects designed to recover
zinc from the geothermal brine through an ion exchange, solvent
extraction, electrowinning and casting process (the “Zinc Recovery
Project”). On September 10, 2004, management made the decision to
cease operations of the Zinc Recovery Project. Implementation of
the
decommissioning plan began in September 2004 and as of December 31,2005, the dismantling, decommissioning, and sale of remaining assets
of
the Zinc Recovery Project was
completed.
·
MidAmerican
Energy issued $300.0 million of 5.75%, 30-year, medium-term notes on
November 1, 2005, and $350.0 million of 4.65%, 10-year,
medium-term notes on October 1, 2004. The proceeds from each offering
are being used to support construction of its electric generation
projects
and for general corporate purposes.
·
On
May 5, 2005, certain subsidiaries of CE Electric UK collectively
issued £350.0 million of 5.125% senior bonds due 2035. The proceeds
from the offerings are being invested and used for general corporate
purposes. Proceeds from the maturing investments will be used to
repay
certain long-term debt of subsidiaries of CE Electric UK in 2007
and 2008.
·
In
February 2004, MEHC issued $250.0 million of 5.00% senior notes due
February 15, 2014. The proceeds were used to satisfy a demand made by
an affiliate on MEHC’s guarantee of certain debt related to the Zinc
Recovery Project and for general corporate
purposes.
·
Northern
Natural Gas reached agreement with its customers in June 2005 on
a FERC
approved rate settlement covering its consolidated rate case related
to
filings for rate increases made with the FERC in May 2003 and January
2004.
·
Ofgem
completed the process of reviewing the existing price control formula
for
Northern Electric and Yorkshire Electricity in November 2004. As
a result
of the review, the allowed revenue of Northern Electric’s and Yorkshire
Electricity’s distribution businesses were reduced by 4% and 9%,
respectively, in real terms, effective April 1,2005.
·
Kern
River filed for a rate increase with the FERC in April 2004, with
the new
rates being effectuated on November 1, 2004, subject to refund. The
general rate case hearing concluded in August 2005 and Kern River
is
awaiting an initial decision on the case. The final resolution of
the rate
case is dependent on receiving a final, non-appealable decision on
the
case from the FERC, or approval of a settlement of the case by the
FERC,
and is not expected at the earliest until late 2006 or early
2007.
·
CE
Casecnan reached an arbitration settlement with the NIA effective
during
the fourth quarter of 2003. In exchange for the receipt of approximately
$18 million of cash and a $97.0 million ROP Note, CE Casecnan
agreed to modify certain provisions of its project agreement, the
most
significant being the elimination of the tax compensation portion
of the
water delivery fee and modification of the threshold volume of water
used
to calculate the guaranteed water delivery
fee.
42
Results
of Operations
Summary
Operating
results for the years ended December 31, 2005, 2004 and 2003 are summarized
in the following table (in millions):
Minority
interest and preferred dividends of subsidiaries
(16.0
)
(13.3
)
(183.2
)
Equity
income
53.3
16.9
38.2
Income
from continuing operations
557.5
537.8
442.7
Income
(loss) from discontinued operations, net of tax
5.1
(367.6
)
(27.1
)
Net
income available to common and preferred stockholders
$
562.6
$
170.2
$
415.6
In
2005,
MEHC’s income from continuing operations was $557.5 million versus
$537.8 million in 2004. In 2005, MEHC benefited from favorable comparative
results at most of its domestic businesses and from gains on sales of certain
non-strategic assets and investments. These improvements were partially offset
by lower earnings from CE Electric UK, primarily associated with the
distribution businesses. In the fourth quarter of 2004, MEHC realized an
after-tax gain of $43.7 million from the realization of certain
Enron-related bankruptcy claims. Ignoring the effect of this one-time event,
MEHC’s income from continuing operations was $494.1 million, which, when
compared to 2003 results, reflects improved results at most of MEHC’s major
operating platforms.
During
the third quarter of 2004, the Company recorded an after-tax charge, which
is
reflected in discontinued operations, of $340.3 million to write down
certain assets of the Zinc Recovery Project.
Segment
Results
The
reportable segment financial information includes all necessary adjustments
and
eliminations needed to conform to the Company’s significant accounting policies.
The differences between the segment amounts and the consolidated amounts,
described as “Corporate/other,” relate principally to corporate functions
including administrative costs, intersegment eliminations and fair value
adjustments relating to acquisitions. Additionally, the activity of the
Company’s Mineral Assets, which was previously reported in the CalEnergy
Generation-Domestic reportable segment, is presented as discontinued operations
within the consolidated financial statements included in Item 8. Financial
Statements and Supplementary Data of this Form 10-K.
43
A
comparison of operating revenue and operating income for the Company’s
reportable segments for the years ended December 31, 2005, 2004, and 2003
follows (in millions):
MidAmerican
Energy owns a public utility headquartered in Iowa that is principally engaged
in the business of generating, transmitting, distributing and selling electric
energy and in distributing, selling and transporting natural gas. Nonregulated
affiliates within the MidAmerican Energy platform also conduct a number of
nonregulated business activities. MidAmerican Energy’s operating revenue and
operating income for the years ended December 31, 2005, 2004, and 2003 are
summarized as follows (in millions):
The
operating results of MidAmerican Energy’s regulated electric business for the
years ended December 31, 2005, 2004, and 2003 are summarized as follows (in
millions, except for average number of customers):
MidAmerican
Energy’s regulated electric retail revenue for 2005 increased
$85.3 million, or 7.5%, to $1,222.0 million compared to 2004. Electric
retail sales volumes increased 6.6% compared to 2004. Higher average
temperatures during 2005 compared to 2004 resulted in a $43.4 million
increase in electric retail revenue. A growing retail customer base in 2005
improved electric retail revenue by $17.7 million compared to 2004, while
electricity usage factors not dependent on weather, such as the size of homes,
technology changes and the use of multiple appliances, increased electric
revenue by $9.1 million. Additionally, transmission revenue increased
$7.9 million.
MidAmerican
Energy’s regulated electric retail revenue for 2004 increased
$23.5 million, or 2.1%, to $1,136.7 million compared to 2003, and
related sales volumes increased 2.5%. Electricity usage factors not dependent
on
weather, such as the size of homes, technology changes and the use of multiple
appliances, improved electric revenue by $21.6 million compared to 2003,
and an increase in the average number of electric retail customers increased
electric retail revenue by $20.7 million. Lower average temperatures during
2004 compared to 2003 resulted in a $26.9 million decrease in electric
retail revenue.
In
addition to retail sales, MidAmerican Energy sells electric energy to other
utilities, marketers and municipalities. These sales are referred to as
wholesale sales. MidAmerican Energy’s wholesale revenue for 2005 increased
$6.2 million, or 2.2%, to $291.2 million compared to 2004. The effect of
higher electric energy prices, offset partially by a higher proportion of
lower-priced, off-peak sales, increased wholesale energy revenue in 2005 by
$33.3 million. Wholesale units for 2005 decreased 9.5% from 2004, resulting
in a $27.1 million decrease in revenue. The primary reason for the decrease
in
wholesale sales volumes for 2005 was the timing of planned generation outages
for the Louisa Generating Station and the loss of generating capacity at the
Ottumwa Generating Station Unit No. 1 (“OGS Unit No. 1”), which experienced a
failure of its step-up transformer on February 20, 2005. OGS Unit No. 1
returned to service on May 3, 2005.
MidAmerican
Energy’s wholesale revenue for 2004 increased $0.2 million, or 0.1%, to
$285.0 million compared to 2003. Wholesale energy revenue in 2004 increased
by
$20.3 million due to the impact of higher average wholesale prices. This
was largely offset by a decrease in wholesale units of 7.1% from 2003, which
resulted in a $20.1 million decrease in revenue.
Cost
of
fuel, energy and capacity for 2005 increased $69.5 million, or 17.4%,
compared to 2004 due principally to the cost of replacement power in connection
with the generating station outages previously discussed and the increased
use
of gas-fired generation, primarily from the Greater Des Moines Energy Center.
Cost of fuel, energy and capacity for 2004 increased $2.3 million, or 0.6%,
compared to 2003. The increase was principally due to the cost of replacement
power as a result of generating stations taken out of service for preventive
maintenance in 2004.
45
Regulated
electric operating expense for 2005 decreased $10.6 million compared to
2004 due principally to the timing of generating plant maintenance and lower
postretirement benefit costs, partially offset by higher distribution and
transmission operations costs. Regulated electric operating expense for 2004
increased $39.1 million compared to 2003 due primarily to the timing of
generating plant maintenance and increased generating plant operations expense.
Additionally, electric distribution maintenance and operations expense and
transmission operations expense were higher in 2004 compared to
2003.
Regulated
electric depreciation and amortization expense for 2005 increased
$2.1 million compared to 2004 as a result of an $11.1 million increase
in electric utility plant depreciation and amortization due primarily to assets
being placed in-service, the most significant being the second phase of the
Greater Des Moines Energy Center and 160.5 MW of wind power facilities in
December 2004 and, to a lesser extent, an additional 200 MW of wind power
facilities in late 2005. The increase in utility plant depreciation was
partially offset by a $9.9 million decrease in regulatory expense pursuant
to a revenue sharing arrangement with the state of Iowa due to lower Iowa
electric equity returns. Regulated electric depreciation and amortization
expense for 2004 decreased $14.3 million compared to 2003 due to a $9.8
million decrease
related to the revenue sharing arrangements with the states of Illinois and
Iowa. Additionally, electric utility plant depreciation and amortization
decreased due in part to software assets that became fully depreciated in
2003.
Regulated
Natural Gas Operations
Regulated
natural gas revenue includes purchased gas adjustment clauses through which
MidAmerican Energy is allowed to recover the cost of gas sold from its retail
gas utility customers. Consequently, fluctuations in the cost of gas sold do
not
affect gross margin or operating income because revenues reflect comparable
fluctuations through the purchased gas adjustment clauses. Compared to 2004,
MidAmerican Energy’s average per-unit cost of gas sold increased 32.8%,
resulting in a $271.6 million increase in revenue and cost of gas sold for
2005. The remainder of the increase in cost of gas sold and gas revenues was
primarily due to an increase in wholesale sales volumes. Additionally, an
increase in the average number of retail customers contributed to the increase
in gas revenues for 2005.
MidAmerican
Energy’s average per-unit cost of gas sold for 2004 increased 7.4%, resulting in
a $54.3 million increase in revenue and cost of gas sold compared to 2003.
The remainder of the increase in cost of gas sold and gas revenues was due
to an
increase in wholesale sales volumes. A decrease in gas retail sales volumes,
in
part due to milder temperature conditions in 2004 compared to 2003, reduced
gas
revenues for 2004. An increase in the average number of retail customers
partially offset the decrease due to retail sales volumes.
Kern
River
Operating
revenue at Kern River is principally derived by providing firm or interruptible
transportation services under long-term transportation service agreements
related to its interstate natural gas transportation pipeline system. On
May 1, 2003, Kern River placed into service a $1.2 billion, 717-mile
expansion project (“2003 Expansion Project”), which increased the design
capacity of Kern River’s pipeline system by 885,575 Dth per day to its current
1,755,575 Dth per day.
Operating
income remained relatively flat in 2005 compared to 2004 and increased
$23.8 million, or 13.1%, in 2004 compared to 2003. The increase in 2004 was
primarily due to higher capacity reservation charges earned in connection with
the completion of the 2003 Expansion Project.
Operating
revenue for 2005 increased $7.5 million, or 2.4%, to $323.6 million
from the comparable period in 2004. The increase in operating revenue resulted
from higher demand and commodity transportation revenues of $14.0 million
due mainly to higher rates, subject to refund, for the current rate proceeding
which became effective on November 1, 2004. This increase was partially offset
by lower interruptible transportation revenue of $5.9 million. Operating
revenue for 2004 increased $55.9 million, or 21.5%, to $316.1 million
from the comparable period in 2003. The increase in operating revenue resulted
primarily from higher demand and commodity transportation revenues, net of
revenue sharing, of $52.2 million, associated with the full-year effect of
higher capacity reservation charges on the additional capacity from the 2003
Expansion Project.
Depreciation
and amortization expense for 2005 increased $9.1 million to
$62.4 million from the comparable period in 2004 due to higher depreciation
rates in connection with the current rate proceeding. Operating expenses and
depreciation and amortization for 2004 increased $15.7 million, or 36.9%,
and $16.5 million, or 44.8%, respectively, from the comparable period in
2003 due to the completion of the 2003 Expansion Project.
46
Northern
Natural Gas
Operating
revenue at Northern Natural Gas is principally derived by providing firm or
interruptible transportation and storage services under long-term transportation
storage service agreements related to its interstate natural gas transportation
pipeline system.
Operating
income for 2005 increased $18.5 million, or 9.7%, to $208.8 million
from the comparable period in 2004. Northern Natural Gas recognized net
benefits, due to the settlement of its consolidated rate case proceeding and
its
SLA settlement, to operating income during the year ended December 31, 2005
of
$15.7 million reflecting final settlement adjustments and the ongoing
operating impact of lower depreciation and amortization expense due to changes
in the useful lives of its transmission, storage and intangible assets,
partially offset by higher regulatory amortization of the remaining SLA
balance.
Operating
revenue for 2005 increased $24.3 million, or 4.5%, to $569.1 million from the
comparable period in 2004. The increase was mainly due to higher gas and liquids
sales of $25.6 million, due to higher sales of gas from operational storage
utilized to manage physical flows on the pipeline system, and higher
transportation and storage revenues of $8.3 million, due to changes in the
composition of transportation contracts. These increases were partially offset
by the net effects of the consolidated rate case and SLA settlements, which
decreased operating revenue by $11.5 million.
Operating
expenses for 2005 also increased $12.4 million from the comparable period in
2004 due to a $29.0 million long-lived asset impairment charge for West Hugoton
recognized in the fourth quarter of 2005, partially offset by a gain of $19.7
million recognized in the second quarter of 2005 from the sale of an idled
section of pipeline in Oklahoma and Texas. Northern Natural Gas entered into
separate purchase and sale agreements (“PSA”) relative to the West Hugoton and
Beaver non-strategic sections of its interstate pipeline system in the fourth
quarter of 2005. No impairment charge was needed for the Beaver pipeline as
the
sale price agreed to in the Beaver PSA exceeded the carrying value of the Beaver
pipeline. The sales of the West Hugoton and Beaver assets are expected to close
in mid to late 2006.
Operating
income for 2004 increased $14.5 million, or 8.2%, to $190.3 million
from the comparable period in 2003. Northern Natural Gas’ operating revenue for
2004, which reflects the effectuation of rate increases on November 1, 2004
and 2003, and higher gas and liquids sales, increased $57.9 million, or
11.9%, to $544.8 million from the comparable period in 2003. In 2004 and
2003, gas and liquids sales were subject to a regulatory tracking procedure
and,
therefore, any fluctuations in the amount of such sales had a corresponding
effect on cost of sales. Depreciation and amortization for 2004 increased
$15.2 million compared to 2003 due primarily to higher depreciation rates
included in the filed rate cases.
CE Electric UK
CE
Electric UK owns two electricity distribution companies which operate in Great
Britain, Northern Electric and Yorkshire Electricity. The distribution
companies’ main income is earned from charges for the use of their electrical
infrastructure levied on supply companies. CE Electric UK also owns an
engineering contracting company, a gas exploration and production company and
various other more minor subsidiaries.
Operating
income for 2005 decreased $13.5 million, or 2.7%, to $483.9 million
compared with 2004. Operating revenue for 2005 decreased $52.3 million, or
5.6%, to $884.1 million compared with 2004 due primarily to
$37.0 million of lower distribution revenues, $9.1 million of lower
contracting revenues and a $6.9 million adverse impact of the exchange rate.
Cost of sales for 2005 decreased $7.5 million due mainly to lower
contracting work and exit charges from the National Grid Company. Operating
expenses for 2005 decreased $29.4 million due mainly to $13.3 million
of gains recognized on the partial disposal of certain CE Gas Australian
assets and lower costs of $11.2 million associated with the withdrawal from
the metering market.
Operating
income for 2004 increased $51.6 million, or 11.6%, to $497.4 million
compared with 2003. Operating revenue for 2004 increased $106.4 million, or
12.8%, to $936.4 million compared with 2003 due primarily as a result of
the weaker U.S. dollar and increased contracting revenue. Cost of sales for
2004
increased $16.7 million mainly due to increased contracting activity and
the weaker U.S. dollar, partially offset by lower exit charges from the National
Grid Company at both Northern Electric and Yorkshire Electricity. Operating
expenses for 2004 increased $16.5 million due to higher pension costs and
the weaker U.S. dollar in 2004, and a gain on the sale of a local operational
dispatch facility in 2003. Depreciation and amortization for 2004 increased
$12.7 million primarily due to the weaker U.S. dollar.
47
CalEnergy
Generation-Foreign
The
CalEnergy Generation-Foreign platform consists of MEHC’s indirect ownership of
the Upper Mahiao, Mahanagdong and Malitbog projects (collectively, the “Leyte
Projects”), and a combined irrigation and hydroelectric power generation project
located in the central part of the island of Luzon in the Philippines (the
“Casecnan Project”).
Operating
income for 2005 decreased $3.5 million, or 1.9%, to $185.0 million
compared with 2004. Operating revenue for 2005 increased $4.9 million, or
1.6%, to $312.3 million compared with 2004. The increase in operating
revenue was mainly due to higher capacity prices at the Leyte Projects and
higher water delivery fees at the Casecnan Project pursuant to contractual
escalation factors.
Operating
income for 2004 decreased $9.0 million, or 4.6%, to $188.5 million
compared with 2003. Operating revenue for 2004 decreased $19.0 million, or
5.8%, to $307.4 million compared with 2003. Each decrease was primarily due
to lower water delivery fees in 2004 resulting from the NIA arbitration
settlement at CE Casecnan, partially offset by higher contractually-specified
capacity and water delivery prices in 2004 and by the reversal of accrued
revenue in connection with the settlement of various disputes between the Leyte
Projects and the PNOC-EDC in 2003.
HomeServices
HomeServices’
operating revenue and cost of sales consists mainly of commission revenue from
real estate brokerage transactions and associated commissions on the
transactions. HomeServices separately acquired 13 real estate companies for
an
aggregate purchase price of $78.5 million throughout 2005, 2004 and
2003.
Operating
income for 2005 increased $12.4 million, or 11.0%, to $125.3 million
from the comparable period in 2004. Operating revenue for 2005 increased
$112.1 million, or 6.4%, to $1,868.5 million and cost of sales
increased $78.2 million from the comparable period in 2004. The increase in
operating revenue was due to growth from existing businesses totaling
$62.1 million reflecting primarily higher average sales prices and
acquisitions not included in the comparable 2004 period totaling
$49.4 million.
Operating
expenses for 2005 increased $24.5 million from the comparable period in
2004 mainly due to $12.8 million related to acquisitions not included in
the comparable 2004 period and $11.7 million in higher operating expense at
existing businesses due primarily to higher marketing and occupancy expenses.
Depreciation and amortization for 2005 was $3.1 million lower than the
comparable period in 2004 due primarily to lower amortization of acquisition
related costs in 2005 as compared to the same period in 2004.
Operating
income for 2004 increased $20.0 million, or 21.5%, to $112.9 million
from the comparable period in 2003. Operating revenue for 2004 increased
$279.8 million, or 18.9%, to $1,756.4 million and cost of sales
increased $211.8 million from the comparable period in 2003. The increase
in operating revenue was due to growth from existing businesses totaling
$154.7 million reflecting primarily higher average sales prices and
acquisitions not included in the comparable 2003 period totaling
$125.1 million.
Operating
expenses for 2004 increased $44.8 million from the comparable period in
2003 mainly due to $27.8 million related to acquisitions not included in
the comparable 2003 period and $17.0 million in higher operating expense at
existing businesses due primarily to higher salaries and employee benefits,
marketing and occupancy expenses. Depreciation and amortization for 2004 was
$3.3 million higher than the comparable period in 2003 due primarily to
higher amortization of acquisition related costs in 2004 as compared to the
same
period in 2003.
48
Consolidated
Other Income and Expense Items
Interest
Expense
Interest
expense for 2005 decreased $12.2 million to $891.0 million from
$903.2 million for the same period in 2004. Interest expense was lower in
2005 due to maturities of and principal repayments on parent company senior
and
subordinated debt and subsidiary and project debt, partially offset by
additional interest expense on the £350.0 million of 5.125% bonds issued by
certain indirect wholly-owned subsidiaries of CE Electric UK in May
2005 and MidAmerican Energy’s 4.65%, $350.0 million notes issued in
October 2004 and 5.75%, $300.0 million notes issued in November 2005.
Additionally, in the first quarter of 2005, the Company incurred a
$10.2 million charge to exercise the call option on the £155.0 million
Variable Rate Reset Trust Securities at CE Electric UK.
Interest
expense for 2004 increased $142.2 million to $903.2 million from
$761.0 million for the same period in 2003. On October 1, 2003, the Company
adopted FIN 46R related to certain finance subsidiaries. The adoption required
that amounts previously recorded in minority interest and preferred dividends
of
subsidiaries be recorded prospectively as interest expense in the accompanying
consolidated statement of operations. For the year ended December 31, 2004
and the three-month period ended December 31, 2003, the Company recorded
$196.9 million and $49.8 million, respectively, of interest expense
related to these finance subsidiaries. In accordance with the requirements
of
FIN 46R, no amounts prior to adoption on October 1, 2003 were reclassified.
The
amount included in minority interest and preferred dividends of subsidiaries
related to these finance subsidiaries for the nine-month period ended September30, 2003, was $170.2 million. Other interest expense decreased
$4.9 million. The Company incurred lower interest expense of
$42.9 million due mainly to the Company's scheduled redemption of
$215.0 million of 6.96% senior notes in September 2003, redemption in full
of the outstanding shares of the Yorkshire Capital Trust I, 8.08% trust
securities in June 2003, and reductions in subsidiary project debt. The Company
incurred additional interest expense, totaling $38.0 million, on the
Company’s debt issuances of $450.0 million of 3.5% senior notes in May 2003
and $250.0 million of 5.0% senior notes in February 2004 and the effects of
the weaker U.S. dollar.
Other
Income, Net
Other
income, net for the years ended December 31, 2005, 2004, and 2003 is summarized
as follows (in millions):
Capitalized
interest for 2005 decreased due to lower capitalization at Northern Electric
and
Yorkshire Electricity, partially offset by higher capitalized interest at
MidAmerican Energy associated with an increase in the construction of generation
facilities. Capitalized interest for 2004 decreased $10.5 million to
$20.0 million from $30.5 million for the same period in 2003. Kern
River capitalized $17.2 million of interest in 2003 related to its 2003
Expansion Project. This was partially offset by increased construction activity
at MidAmerican Energy’s generation projects.
Interest
and dividend income for 2005 increased $19.2 million to $58.1 million
from $38.9 million for the same period in 2004 mainly due to earnings on
guaranteed investment contracts (£100.0 million at 4.75% and
£200.0 million at 4.73%) purchased by certain indirect wholly-owned
subsidiaries of CE Electric UK in May 2005 as well as earnings on
higher cash balances and higher short-term interest rates.
Interest
and dividend income for 2004 decreased $9.0 million to $38.9 million
from $47.9 million for the same period in 2003. The decrease was mainly due
to dividend income received in 2003 from the Company’s investment in Williams
Cumulative Convertible Preferred Stock that was sold in June 2003, partially
offset by higher interest income at CE Electric UK resulting from higher cash
balances.
49
Other
income for 2005 decreased $53.7 million from the comparable period in 2004,
which increased $31.5 million from the comparable period in 2003. Refer to
Note 16 of Notes to Consolidated Financial Statements included in Item 8.
Financial Statements and Supplementary Data of this Form 10-K for additional
information regarding the components of other income. In 2005, the Company
realized gains from sales of certain non-strategic investments at MidAmerican
Funding of $13.4 million and CE Electric UK of $8.4 million.
In 2004, the Company recognized a $72.2 million gain on Northern Natural
Gas’ sale of the Enron Note Receivable and a $14.8 million gain on amounts
collected by Kern River on its claim for damages against Mirant. In 2003, the
Company recognized a $31.9 million gain in connection with the NIA
arbitration settlement and a $13.8 million gain on the sale of Williams
Cumulative Convertible Preferred Stock. Additionally, the allowance for equity
funds used during construction for 2005 increased $5.7 million compared to
2004 due to increased levels of capital project expenditures at MidAmerican
Energy, while the allowance for equity funds used during construction for 2004
decreased $6.2 million compared to 2003 due primarily to the completion of
Kern River’s 2003 Expansion Project in May 2003.
Included
in other expense for 2005 are losses for other-than-temporary impairments of
MidAmerican Funding’s investments in commercial passenger aircraft leased to
major domestic airlines, which are accounted for as leveraged leases, of
$15.8 million. These impairments result from MidAmerican Funding’s
evaluation of these investments in light of the continued deterioration of
the
airline industry and the bankruptcy filings of two major airline carriers during
2005. The remaining carrying values of MidAmerican Funding’s commercial aircraft
leveraged leases are not material.
Income
Tax Expense
Income
tax expense for 2005 decreased $20.3 million to $244.7 million from
$265.0 million for the same period in 2004. The effective tax rate was
32.0% and 33.2% for 2005 and 2004, respectively. The lower effective tax rate
in
2005 was mainly due to the effects of production tax credits related to energy
produced by MidAmerican Energy’s wind facilities, the first of which were placed
in service on December 31, 2004, and lower income taxes on foreign earnings
in 2005, partially offset by a change in the state of Iowa’s income tax laws in
2004 related to bonus depreciation that lowered income tax expense and benefits
from CE Electric UK’s settlement of various positions with the Inland Revenue
department.
Income
tax expense for 2004 decreased $5.3 million to $265.0 million from
$270.3 million for the same period in 2003. The effective tax rate was
33.2% and 31.5% for 2004 and 2003, respectively. The increase in the effective
tax rate in 2004 was mainly due to the effect of the $170.2 million of tax
deductible interest on subordinated debt not included in income from continuing
operations before income tax expense, minority interest and preferred dividends
of subsidiaries and equity income in 2003, partially offset by the
$24.4 million tax payment made in connection with the NIA arbitration
settlement at CE Casecnan in 2003, CE Electric UK’s settlement of various
positions with the Inland Revenue department and a change in the state of Iowa’s
income tax laws in 2004 related to bonus depreciation that lowered income tax
expense.
Equity
Income
Equity
income for 2005 increased $36.4 million to $53.3 million compared with
$16.9 million for the same period in 2004. The increase is mainly due to
higher earnings at CE Generation due to higher energy rates, partially
offset by higher fuel costs, mainly at its natural gas-fired generation
facilities and increased production at the Imperial Valley Projects due to
the
timing and length of scheduled outages and lower major maintenance costs,
partially offset by higher fuel costs. Additionally, 2004 results included
MEHC’s $16.8 million after-tax portion of a charge as a result of the
partial impairment of the carrying value of CE Generation’s Power Resources
project.
Equity
income for 2004 decreased $21.4 million to $16.9 million compared with
$38.3 million for the same period in 2003, mainly due to MEHC’s
$16.8 million after-tax portion of the Power Resources project impairment.
Additionally, HomeServices’ mortgage joint ventures had lower income due to
lower refinancing activity.
Discontinued
Operations
On
September 10, 2004, management made the decision to cease operations of the
Zinc Recovery Project. In connection with ceasing operations, the Zinc Recovery
Project’s assets have been dismantled and sold and certain employees of the
operator of the Zinc Recovery Project were paid one-time termination benefits.
Implementation of the decommissioning plan began in September 2004 and, as
of
December 31, 2005, the dismantling, decommissioning, and sale of remaining
assets of the Zinc Recovery Project was completed.
50
The
income from discontinued operations, net of income tax, of $5.1 million for
the year ended December 31, 2005 reflects the proceeds received from the
sale of assets, partially offset by the disposal costs incurred, in connection
with the September 2004 decision to cease the operations of the Zinc Recovery
Project. The loss from discontinued operations, net of income tax, of
$367.6 million for the year ended December 31, 2004 consists primarily
of a $340.3 million impairment charge recognized in connection with ceasing
the operations of the Zinc Recovery Project. The $27.1 million loss from
discontinued operations, net of income tax, for the year ended December 31,2003 reflects losses incurred from operating the Zinc Recovery
Project.
Liquidity
and Capital Resources
In
May
2005, MEHC reached a definitive agreement with ScottishPower and its subsidiary,
PacifiCorp Holdings, Inc., to acquire 100% of the common stock of
ScottishPower’s wholly-owned indirect subsidiary, PacifiCorp, a regulated
electric utility providing service to approximately 1.6 million customers
in California, Idaho, Oregon, Utah, Washington and Wyoming. MEHC will purchase
all of the outstanding shares of the PacifiCorp common stock for approximately
$5.1 billion in cash. The long-term debt and preferred stock of PacifiCorp,
which aggregated $4.3 billion at December 31, 2005, will remain
outstanding. As of March 1, 2006, all state and federal approvals required
for the acquisition were obtained, subject to the completion of a “most favored
states” process in Wyoming, Washington, Utah, Idaho and Oregon that allows each
such state to make applicable to that state any acquisition commitments or
conditions accepted in other PacifiCorp states. Subject to the most favored
states process and other customary closing conditions, the transaction is
expected to close in March 2006. MEHC expects to fund the acquisition of
PacifiCorp with the proceeds from an investment by Berkshire Hathaway and other
existing shareholders of approximately $3.4 billion in MEHC common stock
and the issuance by MEHC of $1.7 billion of either additional common stock
to Berkshire Hathaway or long-term senior notes to third parties.
The
applications filed with the public utility commissions in the six states where
PacifiCorp has retail customers propose a number of regulatory commitments
by
MEHC and PacifiCorp upon which approval of the transaction would be conditioned,
including expected financial benefits in the form of reduced corporate overhead
and financing costs, certain mid- to long-term capital and other expenditures
of
significant amounts and a commitment not to seek utility rate increases
attributable solely to the change in ownership. The capital and other
expenditures proposed by MEHC and PacifiCorp include investments, generally
to
be made over several years following the purchase, in emissions reduction
technology for PacifiCorp’s existing coal plants and in PacifiCorp’s
transmission and distribution system of approximately $812 million and
$520 million, respectively. PacifiCorp generally expects at least
$1.0 billion per year in capital expenditures over the next five years,
including the regulatory commitments described above. Capital expenditure needs
are reviewed regularly by management and may change significantly as a result
of
such reviews.
On
February 9, 2006, following the effective date of the repeal of PUHCA 1935,
Berkshire Hathaway converted its 41,263,395 shares of MEHC’s no par zero-coupon
convertible preferred stock into an equal number of shares of MEHC’s common
stock. As a consequence, Berkshire Hathaway owns 83.4% (80.5% on a diluted
basis) of the outstanding common stock of MEHC, will consolidate the Company
in
its financial statements as a majority-owned subsidiary, and will include the
Company in its consolidated federal U.S. income tax return.
On
March 1, 2006, MEHC and Berkshire Hathaway entered into the Berkshire
Equity Commitment pursuant to which Berkshire Hathaway has agreed to purchase
up
to $3.5 billion of common equity of MEHC upon any requests authorized from
time to time by the Board of Directors of MEHC. The proceeds of any such equity
contribution shall only be used for the purpose of (a) paying when due MEHC’s
debt obligations and (b) funding the general corporate purposes and capital
requirements of the Company’s regulated subsidiaries. Berkshire Hathaway will
have up to 180 days to fund any such request. The Berkshire Equity Commitment
will expire on February 28, 2011, and will not be used for the PacifiCorp
acquisition or for other future acquisitions.
In
addition to the Berkshire Equity Commitment, the Company has available a variety
of sources of liquidity and capital resources, both internal and external.
These
resources provide funds required for current operations, construction
expenditures, debt retirement and other capital requirements. The Company may
from time to time seek to retire its outstanding securities through cash
purchases in the open market, privately negotiated transactions or otherwise.
Such repurchases or exchanges, if any, will depend on prevailing market
conditions, the Company’s liquidity requirements, contractual restrictions and
other factors. The amounts involved may be material.
51
Each
of
MEHC’s direct or indirect subsidiaries is organized as a legal entity separate
and apart from MEHC and its other subsidiaries. Pursuant to separate financing
agreements at each subsidiary, the assets of each subsidiary may be pledged
or
encumbered to support or otherwise provide the security for their own project
or
subsidiary debt. It should not be assumed that any asset of any subsidiary
of
MEHC will be available to satisfy the obligations of MEHC or any of its other
subsidiaries; provided, however, that unrestricted cash or other assets which
are available for distribution may, subject to applicable law and the terms
of
financing arrangements for such parties, be advanced, loaned, paid as dividends
or otherwise distributed or contributed to MEHC or affiliates
thereof.
The
Company’s cash and cash equivalents and short-term investments, which consist
primarily of auction rate securities that are used in the Company’s cash
management program, were $396.2 million at December 31, 2005, compared
to $960.9 million at December 31, 2004. In addition, the Company
recorded separately, in restricted cash and short-term investments and in
deferred charges and other assets, restricted cash and investments of
$136.7 million and $164.5 million at December 31, 2005 and 2004,
respectively. The restricted cash balance is mainly composed of amounts
deposited in restricted accounts relating to (i) the Company’s debt service
reserve requirements relating to certain projects, (ii) customer deposits held
in escrow, (iii) custody deposits, and (iv) unpaid dividends declared
obligations. The debt service funds are restricted by their respective project
debt agreements to be used only for the related project.
Cash
Flows from Operating Activities
The
Company generated cash flows from operations of $1,310.8 million for the
year ended December 31, 2005, compared with $1,424.6 million for the
same period in 2004. The decrease was mainly due to the receipt of a
$79.0 million federal tax refund in 2004, related to additional tax
depreciation, partially offset by higher earnings, changes in other working
capital and a $33.6 million reduction in 2005 of cash used at the Zinc
Recovery Project’s discontinued operations.
Cash
Flows from Investing Activities
Cash
flows used in investing activities for the years ended December 31, 2005
and 2004 were $1,551.3 million and $1,098.1 million, respectively. The
increase was mainly due to the purchase, with the majority of the proceeds
of
the issuance of £350.0 million of 5.125% bonds due in 2035, of two
guaranteed investment contracts by certain indirect wholly-owned subsidiaries
of
CE Electric UK totaling $556.6 million and the collection of the
$97.0 million ROP Note and $72.2 million from the Enron Note
Receivable in 2004, partially offset by higher proceeds from sale of
non-strategic investments and assets in 2005 totaling
$94.2 million.
Capital
Expenditures, Construction and Other Development Costs
Capital
expenditures, construction and other development costs were
$1,196.2 million for the year ended December 31, 2005, compared with
$1,179.4 million for the same period in 2004. The following table
summarizes the expenditures by business segment (in millions):
Forecasted
capital expenditures, construction and other development costs for fiscal 2006
are approximately $1.3 billion, which does not include any amounts for the
planned acquisition of PacifiCorp. Capital expenditure needs are reviewed
regularly by management and may change significantly as a result of such
reviews. The Company expects to meet these capital expenditures with cash flows
from operations and the issuance of debt. Capital expenditures relating to
operating projects, consisting of recurring expenditures and the funding of
growing load requirements, were $796.3 million for the year ended
December 31, 2005. Construction and other development costs were
$399.9 million for the year ended December 31, 2005. These costs
consist mainly of expenditures for large scale, generation projects as
follows:
52
MidAmerican
Energy anticipates a continuing increase in demand for electricity from its
regulated customers. To meet anticipated demand and ensure adequate electric
generation in its service territory, MidAmerican Energy is currently
constructing CBEC Unit 4, a 790-MW (expected accreditation)
super-critical-temperature, coal-fired generating plant. MidAmerican Energy
will
operate the plant and hold an undivided ownership interest as a tenant in common
with the other owners of the plant. MidAmerican Energy’s current ownership
interest is 60.67%, equating to 479 MW of output. Municipal, cooperative and
public power utilities will own the remainder, which is a typical ownership
arrangement for large base-load plants in Iowa. The facility will provide
service to regulated retail electricity customers. Wholesale sales may also
be
made from the facility to the extent the power is not immediately needed for
regulated retail service. MidAmerican Energy has obtained regulatory approval
to
include the Iowa portion of the actual cost of the generation project in its
Iowa rate base as long as the actual cost does not exceed the agreed cap that
MidAmerican Energy has deemed to be reasonable. If the cap is exceeded,
MidAmerican Energy has the right to demonstrate the prudence of the expenditures
above the cap, subject to regulatory review. MidAmerican Energy expects to
invest approximately $737 million in CBEC Unit 4, including transmission
facilities and excluding allowance for funds used during construction. Through
December 31, 2005, MidAmerican Energy has invested $502.0 million in the
project, including $121.3 million for MidAmerican Energy’s share of deferred
payments allowed by the construction contract.
On
December 16, 2005, MidAmerican Energy filed with the IUB a settlement
agreement between MidAmerican Energy and the OCA regarding ratemaking principles
for up to 545 MW (nameplate rating) of additional wind generation capacity
in
Iowa. Generally speaking, accredited capacity ratings for wind power facilities
are considerably less than the nameplate ratings due to the varying nature
of
wind. The settlement agreement is subject to approval by the IUB.
MidAmerican
Energy’s total accredited net generating capability in the summer of 2005 was
5,098 MW. Accredited net generating capability represents the amount of
generation available to meet the requirements on MidAmerican Energy’s system and
consists of MidAmerican Energy-owned generation of 4,659 MW and the net amount
of capacity purchases and sales of 439 MW. Accredited capacity may vary from
the
nameplate capacity ratings. Additionally, the actual amount of generation
capacity available at any time may be less than the accredited capacity due
to
regulatory restrictions, transmission constraints, fuel restrictions and
generating units being temporarily out of service for inspection, maintenance,
refueling, modifications or other reasons.
Put
of ROP Note and Receipt of Cash
On
January 14, 2004, CE Casecnan exercised its right to put the ROP Note to
the ROP and, in accordance with the terms of the put option, CE Casecnan
received $99.2 million (representing $97.0 million par value plus
accrued interest) from the ROP on January 21, 2004.
Sale
of Enron Note Receivable and Receipt of Cash
Northern
Natural Gas had a note receivable of approximately $259.0 million (the
“Enron Note Receivable”) with Enron. As a result of Enron filing for bankruptcy
on December 2, 2001, Northern Natural Gas filed a bankruptcy claim against
Enron seeking to recover payment of the Enron Note Receivable. As of
December 31, 2001, Northern Natural Gas had written-off the note. By
stipulation, Enron and Northern Natural Gas agreed to a value of
$249.0 million for the claim and received approval of the stipulation from
Enron’s Bankruptcy Court on August 26, 2004. On November 23, 2004,
Northern Natural Gas sold its stipulated general, unsecured claim against Enron
of $249.0 million to a third party investor for $72.2 million, which
was recorded as other income in the fourth quarter of 2004.
HomeServices’
Acquisitions
In
2005,
HomeServices separately acquired three real estate companies for an aggregate
purchase price of $5.1 million, net of cash acquired, plus working capital
and certain other adjustments. For the year ended December 31, 2004, these
real estate companies had combined revenue of $21.8 million on
approximately 3,400 closed sides representing $0.8 billion of sales volume.
In 2004, HomeServices separately acquired six real estate companies for an
aggregate purchase price of $30.7 million, net of cash acquired, plus
working capital and certain other adjustments. For the year ended
December 31, 2003, these real estate companies had combined revenue of
$95.7 million on approximately 15,000 closed sides representing
$3.2 billion of sales volume. Additionally in 2004, HomeServices paid an
earnout related to its 2003 acquisition of $6.0 million based on 2004
financial performance measures. These purchases were financed using
HomeServices’ cash balances.
53
Cash
Flows from Financing Activities
Cash
flows used in financing activities for the year ended December 31, 2005
were $219.1 million. Uses of cash totaled $1,331.2 million and
consisted primarily of $875.4 million for repayments of subsidiary and
project debt and $448.5 million for repayments of parent company senior and
subordinated debt. Sources of cash totaled $1,112.1 million and consisted
of $1,050.6 million of proceeds from the issuance of subsidiary and project
debt and $51.0 million of net proceeds from MEHC’s revolving credit
facility.
Cash
flows used in financing activities for the year ended December 31, 2004
were $105.4 million. Uses of cash totaled $730.5 million and consisted
mainly of $504.8 million for repayments of subsidiary and project debt,
including $136.4 million of cash flows from discontinued operations,
$100.0 million for repayments of parent company subordinated debt and
$43.9 million of net repayments of subsidiary short-term debt. Sources of
cash totaled $625.1 million and consisted of $375.3 million of
proceeds from the issuance of subsidiary and project debt and
$249.8 million of proceeds from the issuance of parent company senior
debt.
Recent
Debt Issuances, Redemptions and Maturities
In
addition to the debt issuances, redemption and maturities discussed herein,
MEHC
and its subsidiaries made scheduled repayments on parent company subordinated
debt and subsidiary and project debt totaling approximately $565 million
during the year ended December 31, 2005.
In
February 2005, a subsidiary of CE Electric UK exercised a call
option to purchase, and then cancelled, its £155.0 million Variable Rate
Reset Trust Securities, due in 2020. A charge to exercise the call option of
$10.2 million was recognized in interest expense in the accompanying
consolidated statement of operations.
On
February 15, 2005, MidAmerican Energy’s 7% series of mortgage bonds,
totaling $90.5 million, were repaid upon maturity.
On
April 4, 2005, CE Electric UK and certain of its subsidiaries
entered into a variable rate, five-year, £100.0 million committed revolving
credit facility.
On
April 14, 2005, Northern Natural Gas issued $100.0 million of 5.125%
senior notes due May 1, 2015. The proceeds were used by Northern Natural
Gas to repay its outstanding $100.0 million 6.875% senior notes due
May 1, 2005.
On
May 5, 2005, Northern Electric Finance plc, an indirect wholly-owned
subsidiary of CE Electric UK, issued £150.0 million of 5.125% bonds due
2035, guaranteed by Northern Electric and guaranteed as to scheduled payments
of
principal and interest by Ambac. Additionally, on May 5, 2005, Yorkshire
Electricity, a wholly-owned subsidiary of CE Electric UK, issued
£200.0 million of 5.125% bonds due 2035, guaranteed as to scheduled
payments of principal and interest by Ambac. The
proceeds from the offerings are being invested and used for general corporate
purposes. Investments
include a £100.0 million, 4.75%, fixed rate guaranteed investment contract
maturing in December 2007 and a £200.0 million, 4.73%, fixed rate
guaranteed investment contract maturing in February 2008. The proceeds from
the
maturing guaranteed investment contracts will be used to repay certain long-term
debt of subsidiaries of CE Electric UK. In connection with the issuance of
such
bonds, CE Electric UK entered into agreements amending certain terms
and conditions of its £200.0 million 7.25% bonds due 2022.
On
August 26, 2005, MEHC entered into a $400.0 million, variable rate
(LIBOR or a base rate plus a margin), credit facility pursuant to a credit
agreement. The credit agreement is unsecured and has a termination date of
August 26, 2010. As of December 31, 2005, the outstanding balance and
amount of letters of credit issued under the credit agreement totaled
$51.0 million and $41.9 million, respectively. The interest rate on
the balance outstanding under the facility at December 31, 2005 was
4.85%.
On
September 15, 2005, MEHC’s 7.23% senior notes, totaling
$260.0 million, were repaid upon maturity.
On
November 1, 2005, MidAmerican Energy issued $300.0 million of 5.75%
medium-term notes due in 2035. The proceeds are being used to support
construction of its electric generation projects and for general corporate
purposes.
54
The
Energy Policy Act
On
August 8, 2005, the Energy Policy Act was signed into law. That law
potentially impacts many segments of the energy industry. A tax provision
extended the federal production tax credit for new renewable electricity
generation projects through December 31, 2007. In part as a result of that
portion of the law, MidAmerican Energy began development efforts to add
additional wind generation. The law also results in expanding the FERC’s
regulatory authority in areas such as mandatory electric system reliability
standards, electric transmission expansion incentives and pricing, regulation
of
utility holding companies, and enforcement authority to issue substantial civil
penalties.
CalEnergy
Generation-Foreign
The
10-year cooperation periods for the Leyte Projects end in June 2006 and July
2007, respectively, at which time each project will be transferred to the
PNOC-EDC at no cost on an “as-is” basis. For the year ended December 31,2005, the Upper Mahiao Project’s financial results represented 0.6%, 1.7% and
2.3%, respectively, and the Mahanagdong and Malitbog Projects’ combined
financial results represented 2.1%, 7.9% and 7.4%, respectively, of MEHC’s total
consolidated operating revenue, income from continuing operations and operating
cash flows from continuing operations. Additionally, the net properties, plants
and equipment and the project debt of the Leyte Projects represented less than
1%, respectively, of MEHC’s total consolidated net properties, plants and
equipment and subsidiary and project debt at December 31,2005.
Credit
Ratings
Debt
and
preferred securities of MEHC and its subsidiaries may be rated by nationally
recognized credit rating agencies. Assigned credit ratings are based on each
rating agency’s assessment of the rated company’s ability to, in general, meet
the obligations of its debt or preferred securities. The credit ratings are
not
a recommendation to buy, sell or hold securities, and there is no assurance
that
a particular credit rating will continue for any given period of time. Other
than the agreements discussed below, MEHC and its subsidiaries do not have
any
credit agreements that require termination or a material change in collateral
requirements or payment schedule in the event of a downgrade in the credit
ratings of the respective company’s securities.
In
conjunction with its risk management activities, MidAmerican Energy must meet
credit quality standards as required by counterparties. In accordance with
industry practice, master agreements that govern MidAmerican Energy’s energy
supply and marketing activities either specifically require it to maintain
investment grade credit ratings or provide the right for counterparties to
demand “adequate assurances” in the event of a material adverse change in
MidAmerican Energy’s creditworthiness. If one or more of MidAmerican Energy’s
credit ratings decline below investment grade, MidAmerican Energy may be
required to post cash collateral, letters of credit or other similar credit
support to facilitate ongoing wholesale energy supply and marketing activities.
As of March 1, 2006, MidAmerican Energy’s credit ratings from the three
recognized credit rating agencies were investment grade; however if the ratings
fell below investment grade, MidAmerican Energy’s estimated potential collateral
requirements totaled approximately $267 million. MidAmerican Energy’s
collateral requirements could fluctuate considerably due to seasonality, market
price volatility, and a loss of key MidAmerican Energy generating facilities
or
other related factors.
Yorkshire
Power Group Limited (“YPGL”), a subsidiary of CE Electric UK, has in effect
certain currency rate swap agreements for its Yankee bonds with three large
multi-national financial institutions. The swap agreements effectively convert
the U.S. dollar fixed interest rate to a fixed rate in sterling for
$281.0 million of 6.496% Yankee bonds outstanding at December 31,2004. The agreements extend until February 25, 2008 and convert the U.S.
dollar interest rate to a fixed sterling rate ranging from 7.3175% to 7.3450%.
The estimated fair value of these swap agreements at December 31, 2005 was
$63.8 million based on quotes from the counterparties to these instruments
and represents the estimated amount that the Company would expect to pay if
these agreements were terminated. Certain of these counterparties have the
option to terminate the swap agreements and demand payment of the fair value
of
the swaps if YPGL’s credit ratings from the three recognized credit rating
agencies decline below investment grade. As of March 1, 2006, YPGL’s credit
ratings from the three recognized credit rating agencies were investment grade;
however, if the ratings fell below investment grade, payment requirements would
have been $29.8 million.
Inflation
Inflation
has not had a significant impact on the Company’s costs.
55
Obligations
and Commitments
The
Company has contractual obligations and commercial commitments that may affect
its financial condition. Contractual obligations to make future payments arise
from parent company and subsidiary long-term debt and notes payable, operating
leases and power and fuel purchase contracts. Other obligations and commitments
arise from unused lines of credit and letters of credit. Material obligations
and commitments as of December 31, 2005, which do not include any amounts
associated with the pending acquisition of PacifiCorp, are as follows (in
millions):
Payments
Due By Periods
<
2-3
4-5
>5
Total
1
Year
Years
Years
Years
Contractual
Cash Obligations:
Parent
company senior debt
$
2,775.0
$
-
$
1,550.0
$
-
$
1,225.0
Parent
company subordinated debt
1,663.8
234.0
468.0
422.5
539.3
Subsidiary
and project debt
7,052.4
313.7
945.4
399.2
5,394.1
Interest
payments on long-term debt(1)
8,168.4
785.4
1,377.4
1,001.3
5,004.3
Coal,
electricity and natural gas contract commitments(2)
Unused
revolving credit facilities and lines of credit -
Parent
company revolving credit facility
$
307.1
$
-
$
-
$
307.1
$
-
Subsidiary
revolving credit facilities and lines of credit
612.6
21.3
-
591.3
-
Total
unused revolving credit facilities and lines of credit
$
919.7
$
21.3
$
-
$
898.4
$
-
Parent
company letters of credit outstanding
$
43.0
$
41.9
$
1.1
$
-
$
-
______________
(1)
Excludes
interest payments on variable rate long-term debt.
(2)
The
coal, electricity and natural gas contract commitments and operating
leases are not reflected on the consolidated balance
sheets.
(3)
MidAmerican
Energy is allowed to defer up to $200.0 million in payments to the
contractor under its contract to build CBEC Unit 4. Approximately
39.3% of
this commitment is expected to be funded by the joint owners of CBEC
Unit
4.
The
Company has other types of commitments that are subject to change and relate
primarily to the items listed below. For additional information, refer, where
applicable, to the respective referenced note of Notes to Consolidated Financial
Statements included in Item 8. Financial Statements and Supplemental Data of
this Form 10-K.
·
Debt
service reserve guarantees (see Note
13)
·
Asset
retirement obligations (see Note
14)
·
Nuclear
decommissioning costs (see Note 20)
·
Residual
guarantees on operating leases (see Note
20)
·
Pension
and postretirement commitments (see Note
21)
56
Off-Balance
Sheet Arrangements
The
Company has certain investments that are accounted for under the equity method
in accordance with accounting principles generally accepted in the United States
of America (“GAAP”). Accordingly, an amount is recorded on the Company’s balance
sheet as an equity investment and is increased or decreased for the Company’s
pro-rata share of earnings or losses, respectively, less any dividend
distribution from such investments.
As
of
December 31, 2005, the Company’s investments which are accounted for under
the equity method had $745.8 million of debt and $87.0 million in
outstanding letters of credit. As of December 31, 2005, the Company’s
pro-rata share of such debt and outstanding letters of credit, which is all
non-recourse to MEHC except for a $23.1 million outstanding letter of
credit (included in the Obligations and Commitments table), was
$368.3 million and $41.4 million, respectively.
As
noted
above, MEHC is generally not required to support the debt service obligations
of
its equity investments. However, default with respect to this non-recourse
debt
could result in a loss of invested equity.
New
Accounting Pronouncements
In
December 2004, the FASB issued Statement of Financial Accounting Standards
(“SFAS”) No. 123R, “Share-Based Payment” (“SFAS 123R”), which replaces SFAS No.
123, “Accounting for Stock-Based Compensation,” and supersedes Accounting
Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.”
SFAS 123R establishes standards for the accounting for transactions in which
an
entity exchanges its equity instruments for goods or services, primarily
focusing on the accounting for transactions in which an entity obtains employee
services in share-based payment transactions. SFAS 123R requires entities to
measure compensation costs for all share-based payments, including stock
options, at fair value and expense such payments over the service period. Since
MEHC is considered a nonpublic entity under the criteria of SFAS 123R, this
standard is effective for annual periods beginning after December 15, 2005.
Adoption of this standard will not have an effect on the Company’s financial
position, results of operations or cash flows as all of the Company’s
outstanding stock options were fully vested at the date of issuance of SFAS
123R. Modifications to outstanding stock options after the effective date of
the
standard may result in additional compensation expense pursuant to the
provisions of SFAS 123R.
Critical
Accounting Policies
The
preparation of financial statements and related documents in conformity with
GAAP requires management to make judgments, assumptions and estimates that
affect the amounts reported in the consolidated financial statements and
accompanying notes. Note 2 to the consolidated financial statements for the
year
ended December 31, 2005 included in this annual report describes the
significant accounting policies and methods used in the preparation of the
consolidated financial statements. Estimates are used for, but not limited
to,
the accounting for the effects of certain types of regulation, impairment of
long-lived assets and goodwill, accrued pension and post-retirement expense,
income taxes and revenue. Actual results could differ from these estimates.
The
following critical accounting policies are impacted significantly by judgments,
assumptions and estimates used in the preparation of the consolidated financial
statements.
Accounting
for the Effects of Certain Types of Regulation
MidAmerican
Energy, Kern River and Northern Natural Gas prepare their financial statements
in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of
Certain Types of Regulation (“SFAS 71”), which differs in certain respects from
the application of GAAP by non-regulated businesses. In general, SFAS 71
recognizes that accounting for rate-regulated enterprises should reflect the
economic effects of regulation. As a result, a regulated utility is required
to
defer the recognition of costs (a regulatory asset) or the recognition of
obligations (a regulatory liability) if it is probable that, through the
rate-making process, there will be a corresponding increase or decrease in
future rates. Accordingly, MidAmerican Energy, Kern River and Northern Natural
Gas have deferred certain costs and accrued certain obligations, which will
be
amortized over various future periods. The Company periodically evaluates the
applicability of SFAS 71 and considers factors such as regulatory changes and
the impact of competition. If cost-based regulation ends or competition
increases, the Company may have to reduce its asset balances to reflect a market
basis less than cost and write-off the associated regulatory assets and
liabilities.
57
Management
continually assesses whether the regulatory assets are probable of future
recovery by considering factors such as applicable regulatory environment
changes, recent rate orders received by other regulated entities, and the status
of any pending or potential deregulation legislation. Based upon this continual
assessment, management believes the existing regulatory assets are probable
of
recovery. This assessment reflects the current political and regulatory climate
at the state and federal levels, and is subject to change in the future. If
future recovery of costs ceases to be probable, the asset and liability
write-offs would be required to be recognized in operating income. Total
regulatory assets were $441.1 million and $451.8 million as of December 31,2005
and 2004, respectively. Total regulatory liabilities were $773.9 million and
$682.8 million as of December 31, 2005 and 2004, respectively. Refer to Note
5
of Notes to Consolidated Financial Statements included in Item 8. Financial
Statements and Supplementary Data of this Form 10-K for additional information
regarding the Company’s regulatory assets and liabilities.
Impairment
of Long-Lived Assets and Goodwill
The
Company’s long-lived assets consist primarily of properties, plants and
equipment. Depreciation is generally computed using the straight-line method
based on economic lives or regulatorily mandated recovery periods. The Company
periodically evaluates long-lived assets, including properties, plants and
equipment, when events or changes in circumstances indicate that the carrying
value of these assets may not be recoverable. Upon the occurrence of a
triggering event, the carrying amount of a long-lived asset is reviewed to
assess whether the recoverable amount has declined below its carrying amount.
The recoverable amount is the estimated net future cash flows that the Company
expects to recover from the future use of the asset, undiscounted and without
interest, plus the asset’s residual value on disposal. Where the recoverable
amount of the long-lived asset is less than the carrying value, an impairment
loss is recognized to write down the asset to its fair value that is based
on
discounted estimated cash flows from the future use of the asset.
The
estimate of cash flows arising from future use of the asset that are used in
the
impairment analysis requires judgment regarding what the Company would expect
to
recover from future use of the asset. Any changes in the estimates of cash
flows
arising from future use of the asset or the residual value of the asset on
disposal based on changes in the market conditions, changes in the use of the
asset, management’s plans, the determination of the useful life of the asset and
technology changes in the industry could significantly change the calculation
of
the fair value or recoverable amount of the asset and the resulting impairment
loss, which could significantly affect the results of operations. The
determination of whether impairment has occurred is primarily based on an
estimate of undiscounted cash flows attributable to the assets, as compared
to
the carrying value of the assets. An impairment analysis of generating
facilities requires estimates of possible future market prices, load growth,
competition and many other factors over the lives of the facilities. A resulting
impairment loss is highly dependent on these underlying
assumptions.
The
Company evaluates the impairment of goodwill under SFAS No. 142, “Goodwill and
Other Intangible Assets.” The majority of the Company’s goodwill at
December 31, 2005, relates to the Teton Transaction completed in 2000. The
remainder relates to the acquisitions of Yorkshire Electricity in 2001, Kern
River and Northern Natural Gas in 2002 and various acquisitions at HomeServices.
The Company performs an annual goodwill impairment test and updates the test
if
events or circumstances occur that would more likely than not reduce the fair
value of a reporting unit below its carrying value. Key assumptions used in
the
analysis include, but are not limited to, the use of an appropriate discount
rate and estimated future cash flows. Estimated future cash flows are impacted
by, among other factors, assumptions regarding comprehensive energy regulation,
changes in regulations and rates, and estimates of future commodity prices.
In
estimating cash flows, the Company incorporates current market information,
as
well as, historical factors. During 2005 and 2004, the Company recognized
impairments on several of its long-lived assets and goodwill. For additional
discussion of these impairments refer to Notes 4, 7 and 17 of Notes to
Consolidated Financial Statements included in Item 8. Financial Statements
and
Supplementary Data of this Form 10-K.
The
Company records goodwill adjustments for (i) changes in the estimates of or
the
settlement of tax bases of acquired assets, liabilities and carryforwards and
items relating to acquired entities’ prior income tax returns, (ii) the tax
benefit associated with the excess of tax-deductible goodwill over the reported
amount of goodwill, and (iii) changes to the purchase price allocation prior
to
the end of the allocation period, which is generally one year from the
acquisition date.
58
Accrued
Pension and Postretirement Expense
The
Company sponsors pension and other retirement and postretirement benefit plans
in various forms covering all employees who meet eligibility requirements.
The
Company accounts for these benefits under SFAS No. 87, “Employers’ Accounting
for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement
Benefits Other Than Pensions,” respectively. Refer to Note 21 of Notes to
Consolidated Financial Statements included in Item 8. Financial Statements
and
Supplementary Data of this Form 10-K for additional disclosures regarding the
Company’s pension and postretirement commitments. The measurement of the pension
and postretirement obligations, costs and liabilities is dependent on a variety
of assumptions used by the actuaries and the Company. The critical assumptions
used in developing the required estimates include the following key
factors:
·
discount
rate;
·
expected
return
on plan assets; and
·
health
care cost trend rates.
Other
assumptions, such as retirement, mortality, and turnover, are evaluated
periodically and updated to reflect actual experience.
For
its
pension and other postretirement plans, the Company assumed that its plans’
assets would generate an expected return on plan assets of 7.0% for its domestic
and United Kingdom plans as of December 31, 2005. These assets are
maintained in master trusts. The investment objective of the master trusts
is to
achieve reasonable returns on trust assets, subject to a prudent level of
portfolio risk, for the purpose of enhancing the security of benefits for plan
participants. The asset allocation targets were set after considering the
investment objectives and the risk profiles with respect to each trust. Equity
securities, debt securities, real estate and other securities are held for
return potential and diversification benefits. Investments within asset classes
are to be diversified to achieve broad market participation and reduce the
impact of individual managers or investments. The Company regularly reviews
its
actual asset allocations and periodically rebalances its investments to its
targeted allocations when considered appropriate.
For
its
pension and other postretirement plans, the Company assumed a discount rate
of
5.75% in determining the benefit obligations and benefit costs for its
domestic plans as of and for the year ended December 31, 2005. Discount
rates of 4.75% and 5.25%, respectively, were used in determining the benefit
obligations and benefit costs for the Company’s United Kingdom plan as of
and for the year ended December 31, 2005. Advice from the actuaries and
current market conditions were used to determine discount rates. The discount
rates used for all plans approximate the discount rates of hypothetical bond
portfolios that match the Company’s expected payment obligations.
The
actuarial assumptions used may differ materially from actual results due to
changing market and economic conditions, higher or lower withdrawal rates or
longer or shorter life spans of participants. These differences may result
in a
significant impact to the amount of pension and postretirement benefit expense
recorded. If a 100 basis point change were to occur for the following
assumptions, the approximate effect on the financial statements would be as
follows:
The
Company recognizes deferred tax assets and liabilities based on the difference
between the financial statement and tax basis of assets and liabilities using
estimated tax rates in effect for the year in which the differences are expected
to reverse. Based on existing regulatory precedent, MidAmerican Energy is not
allowed to recognize deferred income tax expense related to certain temporary
differences resulting from accelerated tax depreciation and other property
related basis differences. For these differences, MidAmerican Energy establishes
deferred tax liabilities and regulatory assets on the consolidated balance
sheets since MidAmerican Energy is allowed to recover the increased tax expense
when these differences turn around.
The
Company has not provided U.S. deferred income taxes on its currency translation
adjustment or the cumulative earnings of international subsidiaries that have
been determined by management to be reinvested indefinitely. These earnings
related to ongoing operations and were approximately $600 million at
December 31, 2005. Because of the availability of U.S. foreign tax credits,
it is not practicable to determine the U.S. federal income tax liability that
would be payable if such earnings were not reinvested indefinitely. Deferred
taxes are provided for earnings of international subsidiaries when the Company
plans to remit those earnings. The Company periodically evaluates its cash
requirements in the U.S. and abroad and evaluates its short-term and long-term
operational and fiscal objectives in determining whether the earnings of its
foreign subsidiaries are indefinitely invested outside the U.S. or will be
remitted to the U.S. within the foreseeable future.
In
preparing the Company’s tax returns, management is required to interpret complex
tax laws and regulations. The Company is subject to continuous examinations
by
federal, state, local and foreign tax authorities that may give rise to
different interpretations of these complex laws and regulations. Due to the
nature of the examination process, it generally takes years before these
examinations are completed and these matters are resolved. The Internal Revenue
Service has closed examination of the Company’s income tax returns through 1998.
Although the ultimate resolution of the Company’s tax examinations is uncertain,
the Company believes it has made adequate provisions for income tax payables
and
the aggregate amount of any additional tax liabilities that may result from
these examinations, if any, will not have a material adverse affect on the
Company’s financial condition, results of operations or cash flows. Tax
contingency reserves are included in accrued property and other taxes and other
long-term accrued liabilities, as appropriate, in the accompanying consolidated
balance sheets.
Revenue
Recognition - Unbilled Revenue
Unbilled
revenues were $199.4 million and $185.5 million, respectively, at
December 31, 2005 and 2004.
Electric
and Natural Gas Retail Revenues and Electric Distribution
Revenues
Revenue
is recorded based upon services rendered and electricity and natural gas
delivered, distributed or supplied to the end of the period. MidAmerican Energy
records unbilled revenue representing the estimated amounts customers will
be
billed between the meter reading dates in a particular month and the end of
that
month. The distribution businesses in Great Britain record unbilled revenue
representing the estimated amounts that customers will be billed for electricity
distributed during the period based upon information received from the national
settlement system.
For
MidAmerican Energy, the determination of sales to individual customers is based
on the reading of their meters, which is performed on a systematic basis
throughout the month. At the end of each month, amounts of electricity and
natural gas delivered to customers since the date of their last meter readings
are estimated and the corresponding unbilled revenue accrual is then recorded.
This estimate is reversed in the following month and actual revenue is recorded
based on meter readings.
The
monthly estimate for unbilled revenues is calculated by MidAmerican Energy
using
a number of inputs, including the estimation of total energy provided during
the
period, line losses, total energy billed, and the average rate per customer
class. The estimate of total energy provided and unbilled volumes can vary
from
period to period depending on seasonal weather patterns, customer usage,
production levels due to economic activity, and changes in the composition
of
customer classes or other variables. The distribution businesses in Great
Britain follow a similar process in the determination of revenue, except that
the information regarding units distributed through the systems is received
from
the national settlement system. Differences between the actual and estimated
amounts have historically been immaterial.
60
Natural
Gas Transportation and Storage
The
majority of the pipelines’ transportation and storage revenues are derived from
firm reservation charges which are fixed based on contractual quantities and
rates. The remaining revenue, consisting primarily of commodity charges, is
based on contractual rates and actual or estimated usage based on scheduled
quantities and is subject to volume estimates including estimates of meter
reading and loss and unaccounted for volumes. Amounts are generally billed
on or
before the ninth business day of the following month. Historically, any
differences between estimated quantities and actual quantities have been
immaterial.
Item
7A.Quantitative
and Qualitative Disclosures About Market
Risk.
The
Company is exposed to market risks associated with electric and natural gas
prices, foreign currency exchange rates, interest rates, and credit risks.
Risk
is an inherent part of MEHC’s business and activities. The risk management
process established by each business platform is designed to identify, assess,
monitor, report, manage, and mitigate each of the various types of risk involved
in its business. To assist in managing the risk, management enters into various
transactions, including derivative transactions, consistent with these
established procedures. These activities are generally described below.
Notes
2
and 14 of Notes to Consolidated Financial Statements included in Item 8.
Financial Statements and Supplementary Data of this Form 10-K contain additional
information regarding the
accounting for derivative contracts pursuant to Statement
of Financial Accounting Standards No. 133, “Accounting for Derivative
Instruments and Hedging Activities”(“SFAS
133”), at
the
Company’s platforms.
Under
the
current regulatory framework, MidAmerican Energy is allowed to recover its
cost
of gas from all of its regulated gas customers through a purchased gas
adjustment clause included in revenue. Accordingly, MidAmerican Energy’s
regulated gas customers, although ensured of the availability of gas supplies,
retain the risk associated with market price volatility. In order to mitigate
a
portion of the market price risk retained by its regulated gas customers through
the purchased gas adjustment clause, MidAmerican Energy uses natural gas
futures, options and over-the-counter agreements. The realized gains and losses
on these derivative instruments are assigned to regulated gas customers through
the purchased gas adjustment clause.
MidAmerican
Energy - Electric
MidAmerican
Energy is exposed to variations in the price of fuel for generation and the
price of wholesale power to be purchased or sold. Under typical operating
conditions, MidAmerican Energy has sufficient generation to supply its regulated
retail electric needs, but may, at times, need to purchase electric power.
MidAmerican Energy may incur a loss if the costs of fuel for generation or
purchases of electric power are higher than MidAmerican Energy is permitted
to
recover from its customers under current electric rates. MidAmerican Energy
uses
physical and financial forward contracts to mitigate these regulated electric
price risks.
61
Derivative
instruments are used to economically hedge both committed and forecasted energy
purchases and sales. Realized gains and losses on all hedges are recognized
in
income as operating revenues, cost of fuel, energy and capacity; or cost of
gas
sold, depending upon the nature of the item being hedged. Net unrealized gains
and losses on hedges utilized for regulated purposes are recorded as regulatory
assets or liabilities.
Northern
Natural Gas
On
an
annual basis, Northern Natural Gas enters into equivalent volume forward
transactions at negotiated fixed prices that generally provide for the sale
of
gas in the first six months of the year and the purchase of equivalent volumes
in the final six months of the year to lock in the cash flows relating to
anticipated near-term index-based sales and purchases of operational storage
volumes. Since these sale and purchase transactions are a normal and recurring
method of managing seasonal changes in operational storage volumes and are
expected to result in physical deliveries, such transactions are deemed to
be
normal sales and purchases that qualify for the exemption from fair value
accounting under SFAS 133.
Northern
Natural Gas has also entered into longer term natural gas commodity swaps of
equivalent volume transactions at negotiated fixed prices to hedge the cash
flows of anticipated longer term operational gas sales and purchases. These
agreements are designated as cash flow hedges under SFAS 133.
Additionally,
Northern Natural Gas has entered into natural gas commodity swaps to hedge
the
cash flows of anticipated future preferred delivery storage contracts. The
objective of these transactions is to lock in the cash flows relating to the
price spreads of natural gas storage contracts that are sensitive to gas
commodity prices. These agreements are also designated as cash flow hedges
under
SFAS 133.
Currency
Exchange Rate Risk
CE Electric UK
MEHC
is
exposed to foreign currency risk from investments in businesses owned and
operated by CE Electric UK. At December 31, 2005, MEHC’s primary foreign
currency rate exposures were with the sterling. A 10% devaluation in the
currency exchange rate would result in the Company’s consolidated balance sheet
being negatively impacted by a $132.3 million cumulative translation
adjustment in accumulated other comprehensive income. A 10% devaluation in
the
average currency exchange rate would have resulted in lower reported earnings
for CE Electric UK of $21.0 million in 2005.
CE
Electric UK has entered into certain currency rate swap agreements for its
senior notes and Yankee bonds with large multi-national financial institutions.
The swap agreements effectively convert the U.S. dollar fixed interest rate
to a
fixed rate in sterling for $237.0 million of 6.995% senior notes and
$281.0 million of 6.496% Yankee bonds outstanding at December 31,2005. The agreements extend until December 30, 2007 and February 25,2008, respectively. The estimated fair value of these swap agreements at
December 31, 2005 and 2004, was $77.5 million and $131.8 million,
respectively, based on quotes from the counterparties to these instruments
and
represents the estimated amount that the Company would expect to pay if these
agreements were terminated.
A
10%
devaluation of the U.S. dollar versus sterling from the value at
December 31, 2005 would increase the amount owed by the Company if these
swap agreements were terminated by approximately
$62.0 million.
CalEnergy
Generation-Foreign
CalEnergy
Generation-Foreign has mitigated a significant portion of its foreign currency
risk as PNOC-EDC’s and NIA’s obligations under the project agreements are
substantially denominated in U.S. dollars.
62
Interest
Rate Risk
At
December 31, 2005, the Company had fixed-rate long-term debt of
$11,348.0 million in aggregate principal amount and having a fair value of
$12,066.0 million. These instruments are fixed-rate and therefore do not
expose the Company to the risk of earnings loss due to changes in market
interest rates. However, the fair value of these instruments would decrease
by
approximately $434 million if interest rates were to increase by 10% from
their levels at December 31, 2005. In general, such a decrease in fair
value would impact earnings and cash flows only if the Company were to reacquire
all or a portion of these instruments prior to their maturity.
At
December 31, 2004, the Company had fixed-rate long-term debt of
$11,503.4 million in aggregate principal amount and having a fair value of
$12,416.2 million. These instruments were fixed-rate and therefore did not
expose the Company to the risk of earnings loss due to changes in market
interest rates.
At
December 31, 2005, the Company had floating-rate obligations of
$166.7 million that expose the Company to the risk of increased interest
expense in the event of increases in short-term interest rates. These
obligations are not hedged; however, any increase in floating rates would not
have a material effect on the Company’s consolidated interest
expense.
At
December 31, 2004, the Company had floating-rate obligations of
$493.4 million that exposed the Company to the risk of increased interest
expense in the event of increases in short-term interest rates. These
obligations were not hedged.
The
Company may enter into contractual agreements to hedge exposure to interest
rate
risk. Changes in fair value of interest rate “locks” used as cash flow hedges
are reported in accumulated other comprehensive income to the extent the hedge
is effective until the forecasted transaction occurs, at which time they are
recorded as adjustments to interest expense over the term of the related debt
issuance. In May 2005, MEHC entered into a treasury rate lock agreement in
the
notional amount of $1.6 billion to protect against a rise in interest rates
related to the anticipated financing of the PacifiCorp acquisition. At
December 31, 2005, the market value of this agreement was
zero.
Credit
Risk
Domestic
Regulated Operations
MidAmerican
Energy’s utility operations grant unsecured credit to its retail electric and
gas customers, substantially all of whom are local businesses and residents,
which totaled $186.0 million at December 31, 2005. MidAmerican Energy
also extends unsecured credit to other utilities, energy marketers, financial
institutions and certain commercial and industrial end-users in conjunction
with
wholesale energy marketing activities. MidAmerican Energy analyzes the financial
condition of each significant counterparty before entering into any
transactions, establishes limits on the amount of unsecured credit to be
extended to each counterparty, and evaluates the appropriateness of unsecured
credit limits on a daily basis. MidAmerican Energy seeks to negotiate
contractual arrangements with wholesale counterparties to provide for net
settlement of monthly accounts receivable and accounts payable and net
settlement of contracts for future performance in the event of default. At
December 31, 2005, 84.4% of MidAmerican Energy’s credit exposure, net of
collateral, from wholesale operations was with counterparties having “investment
grade” credit ratings from Moody’s or Standard & Poor’s, while an additional
7.4% of MidAmerican Energy’s credit exposure, net of collateral, from wholesale
operations was with counterparties having financial characteristics deemed
equivalent to “investment grade” by MidAmerican Energy based on internal review.
Northern
Natural Gas’ primary customers include regulated local distribution companies in
the upper Midwest. Kern River’s primary customers are electric generating
companies and energy marketing and trading companies in the western United
States. As a general policy, collateral is not required for receivables from
creditworthy customers. Customers’ financial condition and creditworthiness are
regularly evaluated, and historical losses have been minimal. In order to
provide protection against credit risk, and as permitted by the separate terms
of each of Northern Natural Gas’ and Kern River’s tariffs, the companies have
required customers that lack creditworthiness, as defined by the tariffs, to
provide cash deposits, letters of credit or other security until their
creditworthiness improves.
63
CE
Electric UK
Northern
Electric and Yorkshire Electricity charge fees for the use of their electrical
infrastructure levied on supply companies. The supply companies, which purchase
electricity from generators or traders and sell the electricity to end-use
customers, use Northern Electric’s and Yorkshire Electricity’s distribution
networks pursuant to an industry standard “Distribution Use of System
Agreement,” which Northern Electric and Yorkshire Electricity separately entered
into with the various suppliers of electricity in their respective distribution
service areas. Northern Electric’s and Yorkshire Electricity’s customers are
concentrated in a small number of electricity supply businesses with Npower
accounting for approximately 44% of distribution revenues in 2005. Ofgem has
determined a framework which sets credit limits for each supply business and
requires them to provide credit cover if their value at risk (measured as being
equivalent to 45 days usage) exceeds the credit limit. Acceptable credit cover
must be provided in the form of a parent company guarantee, letter of credit
or
an escrow account. Ofgem has indicated that, provided Northern Electric and
Yorkshire Electricity have implemented credit control, billing and collection
in
line with best practice guidelines and can demonstrate compliance with the
guidelines or are able to satisfactorily explain departure from the guidelines,
any bad debt losses arising from supplier default will be recovered through
an
increase in future allowed income. Losses incurred to date have not been
material.
CalEnergy
Generation-Foreign
PNOC-EDC’s
and NIA’s obligations under the project agreements are the Leyte Projects’ and
Casecnan Project’s sole source of operating revenue. Because of the dependence
on a single customer, any material failure of the customer to fulfill its
obligations under the project agreements and any material failure of the ROP
to
fulfill its obligation under the performance undertaking would significantly
impair the ability to meet existing and future obligations, including
obligations pertaining to the outstanding project debt. Total operating revenue
for CalEnergy Generation-Foreign was $312.3 million for the year ended
December 31, 2005. The Leyte Projects’ agreements expire in June 2006
and July 2007, respectively, while the Casecnan Project’s agreement expires in
December 2021.
64
Item
8.Financial
Statements and Supplementary
Data.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM
To
the
Board of Directors and Stockholders
MidAmerican
Energy Holdings Company
Des
Moines, Iowa
We
have
audited the accompanying consolidated balance sheets of MidAmerican Energy
Holdings Company and subsidiaries (the “Company”) as of December 31, 2005
and 2004, and the related consolidated statements of operations, stockholders’
equity, and cash flows for each of the three years in the period ended
December 31, 2005. Our audits also included the financial statement
schedules listed in the Index at Item 15. These financial statements and
financial statement schedules are the responsibility of the Company’s
management. Our responsibility is to express an opinion on the financial
statements and financial statement schedules based on our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. The Company is not required to
have, nor were we engaged to perform, an audit of its internal control over
financial reporting. Our audits included consideration of internal control
over
financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company’s internal control over financial
reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures
in
the financial statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In
our
opinion, such consolidated financial statements present fairly, in all material
respects, the financial position of MidAmerican Energy Holdings Company and
subsidiaries as of December 31, 2005 and 2004, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2005, in conformity with accounting principles generally
accepted in the United States of America. Also, in our opinion, such financial
statement schedules, when considered in relation to the basic consolidated
financial statements taken as a whole, present fairly in all material respects
the information set forth therein.
MidAmerican
Energy Holdings Company (“MEHC”) and its subsidiaries (together with MEHC, the
“Company”) are organized and managed as seven distinct platforms: MidAmerican
Funding, LLC (“MidAmerican Funding”) (which primarily includes MidAmerican
Energy Company (“MidAmerican Energy”)), Kern River Gas Transmission Company
(“Kern River”), Northern Natural Gas Company (“Northern Natural Gas”), CE
Electric UK Funding Company (“CE Electric UK”) (which primarily includes
Northern Electric Distribution Limited (“Northern Electric”) and Yorkshire
Electricity Distribution plc (“Yorkshire Electricity”)), CalEnergy
Generation-Foreign (the subsidiaries owning the Upper Mahiao, Malitbog and
Mahanagdong Projects (collectively the “Leyte Projects”) and the Casecnan
Project), CalEnergy Generation-Domestic (the subsidiaries owning interests
in
independent power projects in the United States), and HomeServices of America,
Inc. (collectively with its subsidiaries, “HomeServices”). Through these
platforms, the Company owns and operates a combined electric and natural gas
utility company in the United States, two natural gas pipeline companies in
the
United States, two electricity distribution companies in Great Britain, a
diversified portfolio of domestic and international independent power projects
and the second largest residential real estate brokerage firm in the United
States.
On
March 14, 2000, MEHC and an investor group including Berkshire Hathaway
Inc. (“Berkshire Hathaway”), Walter Scott, Jr., a director of MEHC, David L.
Sokol, Chairman and Chief Executive Officer of MEHC, and Gregory E. Abel,
President and Chief Operating Officer of MEHC, executed a definitive agreement
and plan of merger whereby the investor group acquired all of the outstanding
common stock of MEHC (the “Teton Transaction”). As of December 31, 2005
Walter Scott, Jr. (including family members and related entities), Berkshire
Hathaway, David L. Sokol and Gregory E. Abel owned 86.2%, 9.7%,
3.5% and 0.6%, respectively, of MEHC’s voting common stock and held diluted
ownership interests of 15.3%, 80.5%, 2.9% and 1.3%, respectively (see Note
3).
In
connection with the Teton Transaction, MEHC issued 34.6 million shares of
no par, zero-coupon convertible preferred stock valued at $1,211.4 million
to Berkshire Hathaway. In connection with the Kern River acquisition and the
purchase of $275.0 million of The Williams Companies, Inc. (“Williams”)
preferred stock, MEHC issued 6.7 million shares of no par, zero-coupon
convertible preferred stock valued at $402.0 million to Berkshire Hathaway.
Each share of preferred stock was convertible at the option of the holder into
one share of MEHC’s common stock subject to certain adjustments as described in
MEHC’s Amended and Restated Articles of Incorporation.
The
convertible preferred stock was convertible into common stock only upon the
occurrence of specified events, including modification or elimination of the
Public Utility Holding Company Act of 1935 (“PUHCA 1935”) so that holding
company registration would not be triggered by conversion. Additionally, the
prior approval of the holders of convertible preferred stock was required for
certain fundamental transactions by MEHC. Such transactions include, among
others: (a) significant asset sales or dispositions; (b) merger transactions;
(c) significant business acquisitions or capital expenditures; (d) issuances
or
repurchases of equity securities; and (e) the removal or appointment of the
Chief Executive Officer.
In
these
notes to consolidated financial statements, references to “U.S. dollars,”“dollars,”“$” or “cents” are to the currency of the United States, references
to “pounds sterling,”“ £,”“sterling,”“pence” or “p” are to the currency of
Great Britain and references to “pesos” are to the currency of the Philippines.
References to kW means kilowatts, MW means megawatts, GW means gigawatts, kWh
means kilowatt hours, MWh means megawatt hours, GWh means gigawatts hours,
kV
means kilovolts, MMcf means million cubic feet, Bcf means billion cubic
feet, Tcf means trillion cubic feet and Dth means decatherms or one million
British thermal units.
71
2.
Summary
of Significant Accounting
Policies
Principles
of Consolidation
The
consolidated financial statements include the accounts of MEHC and its
wholly-owned subsidiaries, except for certain trusts formed to hold trust
preferred securities which were deconsolidated under Financial Accounting
Standards Board (“FASB”) Interpretation No. 46R, “Consolidation of Variable
Interest Entities, an interpretation of Accounting Research Bulletin No. 51”
(“FIN 46R”). Subsidiaries which are less than 100% owned but greater than 50%
owned are consolidated with a minority interest. Subsidiaries that are 50%
owned
or less, but where the Company has the ability to exercise significant
influence, are accounted for under the equity method of accounting. Investments
where the Company’s ability to influence is limited are accounted for under the
cost method of accounting. All inter-enterprise transactions and accounts have
been eliminated. The results of operations of the Company include the Company’s
proportionate share of results of operations of entities acquired from the
date
of each acquisition for purchase business combinations.
For
the
Company’s foreign operations whose functional currency is not the U.S. dollar,
the assets and liabilities are translated into U.S. dollars at current exchange
rates. Resulting translation adjustments are reflected as other comprehensive
income in stockholders’ equity. Revenue and expenses are translated at average
exchange rates for the period. Transaction gains and losses that arise from
exchange rate fluctuations on transactions denominated in a currency other
than
the functional currency are included in the results of operations as
incurred.
Reclassifications
Certain
amounts in the fiscal 2004 and 2003 consolidated financial statements and
supporting note disclosures have been reclassified to conform to the fiscal
2005
presentation, including the reclassifications of changes in restricted cash
and
investments and auction rate securities. Such reclassifications did not impact
previously reported net income or retained earnings.
The
accompanying consolidated statements of cash flows for the years ended
December 31, 2004 and 2003 reflect a reclassification of changes in
restricted cash and investments from a financing activity to an investing
activity. This reclassification resulted in an increase in cash used in
investing activities and a corresponding decrease in cash used in financing
activities totaling $17.4 million and $68.3 million for the years
ended December 31, 2004 and 2003, respectively.
The
accompanying consolidated balance sheet as of December 31, 2004, reflects a
reclassification of instruments used in the Company’s cash management program
from cash and cash equivalents to short-term investments of $123.6 million.
This reclassification is to present certain auction rate securities as
short-term investments rather than as cash equivalents due to the stated
maturities of these investments. Additionally, in the accompanying consolidated
statements of cash flows, cash and cash equivalents were reduced by
$123.6 million, $72.5 million and $50.0 million at
December 31, 2004, 2003 and 2002, respectively, to reflect the
reclassification of these instruments from cash and cash equivalents to
short-term investments.
Use
of Estimates
Preparation
of the consolidated financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported amounts
of
assets and liabilities and the disclosure of contingent assets and liabilities
at the date of the consolidated financial statements and the reported amounts
of
revenue and expenses during the period. Management believes the most complex
and
sensitive judgments, because of their significance to the consolidated financial
statements, result primarily from the need to make estimates about the effects
of matters that are inherently uncertain. Actual results could differ materially
from management’s estimates.
Accounting
for the Effects of Certain Types of Regulation
MidAmerican
Energy, Kern River and Northern Natural Gas prepare their financial statements
in accordance with the provisions of Statement of Financial Accounting Standards
(“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation”
(“SFAS 71”), which differs in certain respects from the application of generally
accepted accounting principles by non-regulated businesses. In general, SFAS
71
recognizes that accounting for rate-regulated enterprises should reflect the
economic effects of regulation. As a result, a regulated entity is required
to
defer the recognition of costs (a regulatory asset) or the recognition of
obligations (a regulatory liability) if it is probable that, through the
rate-making process, there will be a corresponding increase or decrease in
future rates. Accordingly, MidAmerican Energy, Kern River and Northern Natural
Gas have deferred certain costs and accrued certain obligations, which will
be
amortized over various future periods. The Company periodically evaluates the
applicability of SFAS 71 and considers factors such as regulatory changes and
the impact of competition. If cost-based regulation ends or competition
increases, the Company may have to reduce its asset balances to reflect a market
basis less than cost and write-off the associated regulatory assets and
liabilities.
72
Management
continually assesses whether the regulatory assets are probable of future
recovery by considering factors such as applicable regulatory environment
changes, recent rate orders received by other regulated entities, and the status
of any pending or potential deregulation legislation. Based upon this continual
assessment, management believes the existing regulatory assets are probable
of
recovery. If future recovery of costs ceases to be probable, the asset and
liability write-offs would be required to be recognized in operating
income.
Revenue
Recognition
Electric
and Natural Gas Retail Revenues and Electric Distribution
Revenues
Revenue
is recorded based upon services rendered and electricity and natural gas
delivered, distributed or supplied to the end of the period. MidAmerican Energy
records unbilled revenue representing the estimated amounts customers will
be
billed between the meter reading dates in a particular month and the end of
that
month. The distribution businesses in Great Britain record unbilled revenue
representing the estimated amounts that customers will be billed for electricity
distributed during the period based upon information received from the national
settlement system.
In
the
distribution businesses in Great Britain, revenue is not recognized when
billings for electric distribution services exceed the maximum related amounts
available under the regulatory formula. This over recovered amount is deducted
from revenue and included in other liabilities and is available to be earned
throughout the remainder of the current or future regulatory periods. Where
there is an under recovered position (billings are less than the maximum related
amounts available under the regulatory formula), no anticipation of any
potential future recovery is made and revenue is recognized based upon the
estimated billed amounts.
Natural
Gas Transportation and Storage
The
majority of the pipelines’ transportation and storage revenues are derived from
firm reservation charges which are fixed based on contractual quantities and
rates. The remaining revenue, consisting primarily of commodity charges, is
based on contractual rates and actual or estimated usage based on scheduled
quantities and is subject to estimates including estimates of meter reading
and
loss and unaccounted for volumes.
Kern
River and Northern Natural Gas are subject to the Federal Energy Regulatory
Commission’s (“FERC”) regulations and, accordingly, certain revenue collected
may be subject to possible refunds upon final orders in pending rate
proceedings. Kern River and Northern Natural Gas may record revenue that is
subject to refund based on their best estimates of the final outcomes of these
proceedings and other third party regulatory proceedings, advice of counsel
and
estimated total exposure, as well as collection and other risks. Estimates
of
any refunds are recorded in other current liabilities in the accompanying
consolidated balance sheets.
The
Company invoices its customers, which consist of the Philippine National Oil
Company-Energy Development Corporation (“PNOC-EDC”) for the Leyte Projects and
the Philippine National Irrigation Administration (“NIA”) for the Casecnan
Project, on a monthly basis for the delivery of electricity and water pursuant
to the provisions of their respective project agreements. The project agreements
are accounted for as arrangements that contain both an operating lease and
a
service contract to operate the projects. The project agreements were classified
as operating leases due to significant uncertainties that existed at the
inception of the leases regarding both the collection of future amounts and
the
amount of unreimbursable costs yet to be incurred mainly due to the existence
of
political, economic and other uncertainties associated with the Philippines.
The
Leyte Projects’ primary source of revenue is from capacity fees recognized on a
straight-line basis over the cooperation periods and subject to semi-annual
adjustment pursuant to changes in the United States producer price
index.
73
Additionally,
for the Casecnan Project, the annual water delivery revenue is recorded on
the
basis of the contractual minimum guaranteed water delivery threshold for the
respective contract year. If and when actual cumulative deliveries within a
contract year exceed the minimum threshold, additional revenue is recognized
and
calculated as the product of the water deliveries in excess of the minimum
threshold and the applicable unit price up to the maximum contractually allowed
water delivery volume. The Company defers revenue recognition on the difference
between the actual water delivery fees earned and water delivery fees invoiced
pursuant to the project agreement. Revenue from electricity consists of
guaranteed energy fees, recognized on a straight-line basis over the cooperation
period, and a variable energy fee. The variable energy fee is recognized when
deliveries of energy exceed the guaranteed energy in any contract
year.
Retail
Commission Revenue and Related Fees
Commission
revenue from real estate brokerage transactions and related amounts due to
agents are recognized when a real estate transaction is closed. Title fee
revenue from real estate transactions and related amounts due to the title
insurer are recognized at the closing. Loan origination and commitment fees
received in connection with the origination of mortgage loans and certain direct
loan origination costs are deferred until such loans are sold to investors.
Fees
related to brokered loan originations are recognized at closing, which is when
services have been provided.
Short-term
Investments
As
of
December 31, 2005 and 2004, the Company had $38.4 million and
$123.6 million, respectively, of short-term investments consisting
primarily of auction rate securities. These instruments are classified as
available-for-sale securities as management does not intend to hold them to
maturity nor are they bought and sold with the objective of generating profits
on short-term differences in price. The carrying value of these instruments
approximates their fair value.
Restricted
Cash and Investments
The
restricted cash and investments balance recorded separately in restricted cash
and short-term investments and in deferred charges and other assets, was
$136.7 million and $164.5 million at December 31, 2005 and 2004,
respectively, and includes commercial paper and money market securities. The
balance is mainly composed of amounts deposited in restricted accounts relating
to (i) the Company’s debt service reserve requirements relating to certain
projects, (ii) customer deposits held in escrow, (iii) custody deposits, and
(iv) unpaid dividends declared obligations. The debt service funds are
restricted by their respective project debt agreements to be used only for
the
related project.
Investments
which the Company has the positive intent and ability to hold to maturity are
classified as held-to-maturity and carried at amortized cost. The carrying
amount of held-to-maturity investments approximates their fair value.
Investments which the Company intends to hold indefinitely, but not necessarily
to maturity, are classified as available-for-sale and carried at fair value.
Unrealized gains and losses on available-for-sale securities are reported as
a
separate component of stockholders’ equity, net of deferred taxes and
reclassification adjustments, except for those available-for-sale securities
that comprise MidAmerican Energy’s nuclear decommissioning trust funds, which
are reported as an adjustment to regulatory assets or regulatory
liabilities.
Allowance
for Doubtful Accounts
The
allowance for doubtful accounts is based on the Company’s assessment of the
collectibility of payments from its customers. This assessment requires judgment
regarding the outcome of pending disputes, arbitrations and the ability of
customers to pay the amounts owed to the Company. At December 31, 2005 and
2004, the allowance for doubtful accounts totaled $21.4 million and
$26.0 million, respectively.
Amounts
Held in Trust
Amounts
held in trust consist of separately designated trust accounts for homebuyers’
earnest money and other deposits. The Company holds such funds until sold
properties are closed and subsequently disburses amounts in accordance with
the
settlement instructions. The Company does not earn or pay interest on the
amounts held in trust.
74
Inventories
Inventories
consist mainly of materials and supplies, coal stocks, gas in storage and fuel
oil, which are valued at the lower of cost, determined primarily using average
cost, or market.
Properties,
Plants and Equipment, Net
Properties,
plants and equipment are recorded at historical cost. The Company capitalizes
all construction related material and direct labor costs as well as indirect
construction costs. Indirect construction costs include general engineering,
taxes and costs of funds used during construction. The cost of major additions
and betterments are capitalized, while replacements, maintenance, and repairs
that do not improve or extend the lives of the respective assets are expensed.
Depreciation is generally computed using the straight-line method based on
economic lives or regulatorily mandated recovery periods. The Company believes
the useful lives assigned to the depreciable assets, which generally range
from
3 to 67 years, are reasonable.
When
the
Company retires its regulated properties, plant and equipment, it charges the
original cost plus the cost of retirement, less salvage value, to the cost
of
removal accrued regulatory liability. When it sells entire regulated, or retires
or sells non-regulated, properties, plant and equipment, the original cost
is
removed from the property accounts and the related accumulated depreciation
and
amortization accounts are reduced. Any gain or loss is recorded as income,
unless otherwise required by the applicable regulatory body.
The
Company recognizes an asset retirement obligation (“ARO”) in accordance with
SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), for
legal obligations associated with the retirement of long-lived assets that
result from the acquisition, construction, development and/or normal use of
the
assets. SFAS 143 requires that the fair value of a liability for an ARO be
recognized in the period in which it is incurred, if a reasonable estimate
of
fair value can be made. The fair value of the liability is added to the carrying
amount of the associated asset, which is then depreciated over the remaining
useful life of the asset. The difference between the ARO liability, the
corresponding ARO net asset and amounts recovered from regulated customers
to
satisfy such liabilities is recorded as a regulatory asset or
liability.
Impairment
of Long-Lived Assets
The
Company periodically evaluates long-lived assets, including properties, plants
and equipment, when events or changes in circumstances indicate that the
carrying value of these assets may not be recoverable. Upon the occurrence
of a
triggering event, the carrying amount of a long-lived asset is reviewed to
assess whether the recoverable amount has declined below its carrying amount.
The recoverable amount is the estimated net future cash flows that the Company
expects to recover from the future use of the asset, undiscounted and without
interest, plus the asset’s residual value on disposal. Where the recoverable
amount of the long-lived asset is less than the carrying value, an impairment
loss is recognized to write down the asset to its fair value that is based
on
discounted estimated cash flows from the future use of the asset.
Goodwill
The
provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”),
which establishes the accounting for acquired goodwill and other intangible
assets, and provides that goodwill and indefinite-lived intangible assets will
not be amortized, requires allocating goodwill to each reporting unit and
testing for impairment using a two-step approach. The goodwill impairment test
is performed annually or whenever an event has occurred that would more likely
than not reduce the fair value of a reporting unit below its carrying amount.
The Company completed its annual review pursuant to SFAS 142 for its reporting
units as of October 31, 2005 primarily using a discounted cash flow
methodology. No impairment was indicated as a result of these
assessments.
The
Company records goodwill adjustments for (i) changes in the estimates of or
the
settlement of tax bases of acquired assets, liabilities and carryforwards and
items relating to acquired entities’ prior income tax returns, (ii) the tax
benefit associated with the excess of tax-deductible goodwill over the reported
amount of goodwill, and (iii) changes to the purchase price allocation prior
to
the end of the allocation period, which is generally one year from the
acquisition date.
75
Deferred
Financing Costs
The
Company capitalizes costs associated with financings, as deferred financing
costs, and amortizes the amounts over the terms of the related financings using
the effective interest method.
Accruals
for Loss Contingencies
The
Company establishes accruals for estimated loss contingencies, such as
environmental, legal and regulatory matters, when it is management’s assessment
that a loss is probable and the amount of the loss can be reasonably estimated.
If the information available indicates that the amount of loss can only be
estimated as a range of possible amounts with some amount within the range
appearing to be a better estimate than any other amount within the range, that
amount is accrued. If no specific amount within the range represents the most
likely amount of loss, the minimum amount of the range is accrued. Accruals
for
loss contingencies are recorded in the period in which different facts or
information become known or circumstances change that affect the previous
assumptions with respect to the likelihood or amount of loss. Accruals for
loss
contingencies and subsequent revisions are reflected in income when accruals
are
recorded or as regulatory treatment dictates. Accruals for loss contingencies
are based upon management’s assumptions and estimates, and advice of legal
counsel or other third parties regarding the probable outcomes of the matter.
Should the outcomes differ from the assumptions and estimates, revisions to
the
estimated accruals for loss contingencies would be required.
Risk
Management and Hedging Activities
The
Company employs a number of different derivative and non-derivative instruments
in connection with its electric and natural gas, foreign currency exchange
rate
and interest rate risk management activities, including forward contracts,
futures, swaps and options. All derivative instruments not designated and
qualifying for the normal purchases and normal sales exceptions under SFAS
133,
“Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as
amended, are recorded on the consolidated balance sheet at their fair values
as
either assets or liabilities.
For
all
hedge contracts, the Company provides formal documentation of the hedge in
accordance with SFAS 133. In addition, at inception and on a quarterly basis
the
Company formally assesses whether the hedge contract is highly effective in
offsetting changes in cash flows or fair values of hedged items. The Company
documents hedging activity by transaction type and risk management
strategy.
Changes
in the fair value of a derivative designated and qualified as a cash flow hedge,
to the extent effective, are included in the consolidated statement of
stockholders’ equity and comprehensive income as accumulated other comprehensive
income (“AOCI”) until the hedged item is realized. The Company discontinues
hedge accounting prospectively when it has determined that a derivative no
longer qualifies as an effective hedge, or when it is no longer probable that
the hedged forecasted transaction will occur. When hedge accounting is
discontinued because the derivative no longer qualifies as an effective hedge,
future changes in the value of the derivative are charged to income. Gains
and
losses related to discontinued hedges that were previously accumulated in AOCI
will remain in AOCI until the hedged item is realized, unless it is no longer
probable that the hedged forecasted transaction will occur at which time
associated deferred amounts in AOCI are immediately recognized in current
earnings.
Certain
derivative electric and gas contracts utilized by the regulated operations
of
MidAmerican Energy are recoverable through retail rates. Accordingly, unrealized
changes in fair value of these contracts are deferred as regulatory assets
or
liabilities pursuant to SFAS 71.
Derivative
contracts for commodities used in the Company’s normal business operations that
are settled by physical delivery, among other criteria, are eligible for and
may
be designated as normal purchases and normal sales pursuant to the exemption
provided by SFAS 133. Recognition of these contracts in revenue or cost of
sales
in the consolidated statement of operations occurs when the contracts
settle.
When
available, quoted market prices or prices obtained through external sources
are
used to measure a contract’s fair value. For contracts without available quoted
market prices, fair value is determined based on internally developed valuation
techniques or models.
76
Fair
Value of Financial Instruments
The
fair
value of a financial instrument is the amount at which the instrument could
be
exchanged in a current transaction between willing parties, other than in a
forced sale or liquidation. Although management uses its best judgment in
estimating the fair value of these financial instruments, there are inherent
limitations in any estimation technique. Therefore, the fair value estimates
presented herein are not necessarily indicative of the amounts that the Company
could realize in a current transaction.
The
methods and assumptions used to estimate fair value are as follows:
Investments
- The
fair value of all investments is primarily based on quoted market prices as
provided by the third-party financial institution holding the
investments.
Short-term
debt
- Due to
the short-term nature of the short-term debt, the fair value approximates the
carrying value.
Debt
instruments
- The
fair value of all debt instruments has been estimated based upon quoted market
prices as supplied by third-party broker dealers, where available, or at the
present value of future cash flows discounted at rates consistent with
comparable maturities with similar credit risks.
Other
financial instruments
- All
other financial instruments of a material nature are short-term and the fair
value approximates the carrying amount.
Income
Taxes
MEHC
and
its subsidiaries file a consolidated U.S. federal income tax return and other
state and federal jurisdictional returns as required. Deferred tax assets and
liabilities are recognized based on the difference between the financial
statement and tax basis of assets and liabilities using estimated tax rates
in
effect for the year in which the differences are expected to reverse. Based
on
existing regulatory precedent, MidAmerican Energy is not allowed to recognize
state deferred income tax expense related to certain temporary differences
resulting from accelerated tax depreciation and other property related basis
differences. For these differences, MidAmerican Energy establishes deferred
tax
liabilities and regulatory assets on the consolidated balance sheets since
MidAmerican Energy is allowed to recover the increased tax expense when these
differences turn around. Investment tax credits have been deferred and are
being
amortized over the estimated useful lives of the related
properties.
The
Company has not provided U.S. federal deferred income taxes on its currency
translation adjustment or the cumulative earnings of international subsidiaries
that have been determined by management to be reinvested indefinitely. These
earnings related to ongoing operations and were approximately $600 million
at December 31, 2005. Because of the availability of U.S. foreign tax
credits, it is not practicable to determine the U.S. federal income tax
liability that would be payable if such earnings were not reinvested
indefinitely. Deferred taxes are provided for earnings of international
subsidiaries when the Company plans to remit those earnings.
In
preparing the Company’s tax returns, management is required to interpret complex
tax laws and regulations. The Company is subject to continuous examinations
by
federal, state, local and foreign tax authorities that may give rise to
different interpretations of these complex laws and regulations. Due to the
nature of the examination process, it generally takes years before these
examinations are completed and these matters are resolved. The Internal Revenue
Service has closed examination of the Company’s income tax returns through 1998.
Although the ultimate resolution of the Company’s tax examinations is uncertain,
the Company believes it has made adequate provisions for income tax payables
and
the aggregate amount of any additional tax liabilities that may result from
these examinations, if any, will not have a material adverse affect on the
Company’s financial condition, results of operations or cash flows. Tax
contingency reserves are included in accrued property and other taxes and other
long-term accrued liabilities, as appropriate, in the accompanying consolidated
balance sheets.
77
Allowance
for Funds Used During Construction
Allowance
for funds used during construction (“AFUDC”) represents the approximate net
composite interest cost of borrowed funds and a reasonable return on the equity
funds used for construction. Although AFUDC increases both properties, plants
and equipment and earnings, it is realized in cash through depreciation
provisions included in rates for MidAmerican Energy, Kern River and Northern
Natural Gas, the subsidiaries that apply SFAS 71. AFUDC for subsidiaries that
apply SFAS 71 are capitalized as a component of construction in progress and
will be amortized over the assets’ estimated useful lives.
Other
Comprehensive Income
The
differences between net income and total comprehensive income for the Company
are due to foreign currency translation adjustments, minimum pension liability
adjustments, unrealized holding gains and losses of marketable securities during
the periods, and the effective portion of net gains and losses of derivative
instruments classified as cash flow hedges. Reclassification adjustments
resulting from gains and losses on sales of marketable securities and cash
flow
hedges included in net income for the years ended December 31, 2005, 2004
and 2003 were not material.
Consolidated
Statements of Cash Flows
The
Company considers all investment instruments purchased with an original maturity
of three months or less to be cash equivalents. Investments other than
restricted cash are primarily commercial paper and money market securities.
Restricted cash is not considered a cash equivalent.
The
supplemental disclosures to the accompanying consolidated statements of cash
flows were as follows (in thousands):
Non-cash
transaction - ROP note received in NIA Arbitration
Settlement
$
-
$
-
$
97,000
For
the
year ended December 31, 2003, $170.2 million of preferred dividends of
subsidiaries was not included in cash paid for interest as the Company adopted
and applied the provisions of FIN 46R, related to certain finance subsidiaries,
as of October 1, 2003. The adoption required the deconsolidation of certain
finance subsidiaries, which resulted in amounts that were previously recorded
as
minority interest and preferred dividends of subsidiaries being prospectively
recorded as interest expense in the accompanying consolidated statements of
operations. For the years ended December 31, 2005 and 2004, and the
three-month period ended December 31, 2003, the Company has recorded
$184.4 million, $196.9 million and $49.8 million, respectively,
of interest expense related to these securities. In accordance with the
requirements of FIN 46R, no amounts prior to adoption of FIN 46R on
October 1, 2003 have been reclassified.
New
Accounting Pronouncements
In
December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment” (“SFAS
123R”), which replaces SFAS No. 123, “Accounting for Stock-Based Compensation,”
and supersedes Accounting Principles Board Opinion No. 25, “Accounting for Stock
Issued to Employees.” SFAS 123R establishes standards for the accounting for
transactions in which an entity exchanges its equity instruments for goods
or
services, primarily focusing on the accounting for transactions in which an
entity obtains employee services in share-based payment transactions. SFAS
123R
requires entities to measure compensation costs for all share-based payments,
including stock options, at fair value and expense such payments over the
service period. Since MEHC is considered a nonpublic entity under the criteria
of SFAS 123R, this standard is effective for annual period beginning after
December 15, 2005. Adoption of this standard will not have an effect on the
Company’s financial position, results of operations or cash flows as all of the
Company’s outstanding stock options were fully vested at the date of issuance of
SFAS 123R. Modifications to outstanding stock options after the effective date
of the standard may result in additional compensation expense pursuant to the
provisions of SFAS 123R.
78
3.
Recent
Developments Involving PacifiCorp and Berkshire
Hathaway
In
May
2005, MEHC reached a definitive agreement with Scottish Power plc
(“ScottishPower”) and its subsidiary, PacifiCorp Holdings, Inc., to acquire 100%
of the common stock of ScottishPower’s wholly-owned indirect subsidiary,
PacifiCorp, a regulated electric utility providing service to approximately
1.6 million customers in California, Idaho, Oregon, Utah, Washington and
Wyoming. MEHC will purchase all of the outstanding shares of the PacifiCorp
common stock for approximately $5.1 billion in cash. The long-term debt and
preferred stock of PacifiCorp, which aggregated $4.3 billion at
December 31, 2005, will remain outstanding. As of March 1, 2006, all
state and federal approvals required for the acquisition were
obtained, subject to completion of a "most favored states"
process in Wyoming, Washington, Utah, Idaho and Oregon that
allows each such state to make applicable to that state
any acquisition commitments or conditions accepted in other
PacifiCorp states. Subject to the most favored states process and other
customary closing conditions, the transaction is expected to close in March
2006. MEHC expects to fund the acquisition of PacifiCorp with the proceeds
from
an investment by Berkshire Hathaway and other existing shareholders of
approximately $3.4 billion in MEHC common stock and the issuance by MEHC of
$1.7 billion of either additional common stock to Berkshire Hathaway or
long-term senior notes to third parties.
On
February 9, 2006, following the effective date of the repeal of PUHCA 1935,
Berkshire Hathaway converted its 41,263,395 shares of MEHC’s no par zero-coupon
convertible preferred stock into an equal number of shares of MEHC’s common
stock. As a consequence, Berkshire Hathaway owns 83.4% (80.5% on a diluted
basis) of the outstanding common stock of MEHC, will consolidate the Company
in
its financial statements as a majority-owned subsidiary, and will include the
Company in its consolidated federal U.S. income tax return.
On
March 1, 2006, MEHC and Berkshire Hathaway entered into an Equity
Commitment Agreement (the “Berkshire Equity Commitment”) pursuant to which
Berkshire Hathaway has agreed to purchase up to $3.5 billion of common
equity of MEHC upon any requests authorized from time to time by the Board
of
Directors of MEHC. The proceeds of any such equity contribution shall only
be
used for the purpose of (a) paying when due MEHC’s debt obligations and (b)
funding the general corporate purposes and capital requirements of the Company’s
regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund
any such request. The Berkshire Equity Commitment will expire on
February 28, 2011, and will not be used for the PacifiCorp acquisition
or for other future acquisitions.
On
March 2, 2006, MEHC amended its Articles of Incorporation to (i) increase
the amount of its common stock authorized for issuance to 115.0 million shares
and (ii) no longer provide for the authorization to issue any preferred stock
of
MEHC.
4.
Properties,
Plants and Equipment, Net
Properties,
plants and equipment, net comprise the following at December 31 (in
thousands):
Depreciation
Life
2005
2004
Utility
generation and distribution system
10-50
years
$
10,499,120
$
10,230,628
Interstate
pipelines’ assets
3-67
years
3,700,073
3,566,578
Independent
power plants
10-30
years
1,384,553
1,384,660
Other
assets
3-30
years
476,488
472,744
Total
operating assets
16,060,234
15,654,610
Accumulated
depreciation and amortization
(4,992,431
)
(4,620,007
)
Net
operating assets
11,067,803
11,034,603
Construction
in progress
847,610
572,661
Properties,
plants and equipment, net
$
11,915,413
$
11,607,264
The
utility generation and distribution system and interstate pipelines’ assets are
the regulated assets of MidAmerican Energy, Kern River, Northern Natural Gas
and
CE Electric UK. At December 31, 2005 and 2004, accumulated
depreciation and amortization related to the Company’s regulated assets totaled
$4.1 billion and $3.8 billion, respectively. Additionally,
substantially all of the construction in progress at December 31, 2005 and
2004 relates to the construction of regulated assets.
79
Northern
Natural Gas entered into a purchase and sale agreement (“PSA”) relative to the
West Hugoton non-strategic section of its interstate pipeline system in the
fourth quarter of 2005. As a result of entering into the PSA, Northern Natural
Gas recognized a non-cash impairment charge of $29.0 million ($17.5 million
after-tax), in accordance with SFAS No. 144, “Accounting for the Impairment of
Long-Lived Assets” (“SFAS 144”), to write down the carrying value of the West
Hugoton pipeline to its fair value. The fair value was determined based on
the
sale price agreed to in the PSA. The impairment charge is recorded in operating
expense in the accompanying consolidated statement of operations for the year
ended December 31, 2005.
5.
Regulatory
Assets and Liabilities
The
components of the Company’s regulatory assets consist of the following as of
December 31 (in thousands):
As
of December 31,
Weighted
Average
Remaining
Life
2005
2004
Deferred
income taxes, net
27
years
$
173,864
$
160,662
Computer
systems development costs(1)
(2)
6
years
54,446
63,637
Unrealized
loss on regulated hedges
1
year
45,431
36,794
System
levelized account(1)
(2)
2
years
26,543
53,576
Pipe
recoating and reconditioning costs(1)
67
years
23,256
22,406
Asset
retirement obligations
8
years
20,979
20,875
Postretirement
benefit costs
7
years
20,066
22,933
Debt
refinancing costs
8
years
11,998
15,365
Minimum
pension liability adjustment
17
years
11,694
18,203
Migration
and pipeline system upgrade costs(1)
9
years
10,508
10,480
Nuclear
generation assets(1)
14
years
6,487
6,727
Environmental
costs
1
year
4,907
9,284
Other
Various
30,919
10,888
Total
$
441,098
$
451,830
(1) These
regulatory assets are included in rate base and earn a return.
(2) The
return earned on these regulatory assets is less than the stipulated
return.
The
components of the Company’s regulatory liabilities, which are included in other
long-term accrued liabilities in the accompanying consolidated balance sheets,
consist of the following as of December 31 (in thousands):
As
of December 31,
Weighted
Average
Remaining
Life
2005
2004
Cost
of removal accrual(1)
27
years
$
448,493
$
428,719
Iowa
electric settlement accrual(1)
2
years
213,135
181,188
Asset
retirement obligations(1)
32
years
65,966
53,259
Unrealized
gain on regulated hedges
1
year
29,648
7,462
Other
Various
16,616
12,139
Total
$
773,858
$
682,767
(1) These
regulatory liabilities are deducted from rate base or otherwise accrue a
carrying cost.
Refer
to
Note 12 for a discussion of the cost of removal accrual and asset retirement
obligations and to Note 19 regarding the Iowa electric settlement
accrual.
80
6.
Other
Investments
Other
investments are classified as non-current in the accompanying consolidated
balance sheets as management does not intend to use them in current operations.
Gross unrealized gains and losses of other investments are not material at
December 31, 2005 and 2004. Other investments consist of the following (in
thousands):
CE
Generation, LLC ("CE Generation") and Salton Sea Funding Corporation
bonds
23,244
27,641
Other
31,039
26,470
Total
other investments
$
798,683
$
261,575
In
May
2005, certain indirect wholly-owned subsidiaries of CE Electric UK
purchased £300.0 million of fixed rate guaranteed investment contracts
(£100.0 million at 4.75% and £200.0 million at 4.73%) with a portion
of the proceeds of the issuance of £350.0 million of 5.125% bonds due in
2035. These guaranteed investment contracts mature in December 2007
(£100.0 million) and February 2008 (£200.0 million), respectively, the
proceeds of which will be used to repay certain long-term debt of subsidiaries
of CE Electric UK. The guaranteed investment contracts are reported at
cost.
MidAmerican
Energy has established trusts for the investment of funds for decommissioning
the Quad Cities Station. These investments in debt and equity securities are
classified as available-for-sale and are reported at fair value. An amount
equal
to the net unrealized gains and losses on those investments is recorded as
an
adjustment to regulatory assets or regulatory liabilities in the accompanying
consolidated balance sheets. Funds are invested in the trust in accordance
with
applicable federal investment guidelines and are restricted for use as
reimbursement for costs of decommissioning MidAmerican Energy’s Quad Cities
Station. As of December 31, 2005, approximately 55.5% of the fair value of
the trusts’ funds was invested in domestic common equity securities, 12.3% in
domestic corporate debt and the remainder in investment grade municipal and
U.S.
Treasury bonds. As of December 31, 2004, approximately 55.3% of the fair
value of the trusts’ funds was invested in domestic common equity securities,
14.4% in domestic corporate debt and the remainder in investment grade municipal
and U.S. Treasury bonds.
7.Equity
Investments
Equity
investments consist mainly of MEHC’s 50% investment in CE Generation and
HomeServices’ equity investments in various entities that generally conduct
title and mortgage activities primarily related to the real estate brokerage
business. Equity investments and related equity income consist of the following
(in thousands):
The
following is summarized financial information for CE Generation as of and for
the years ended December 31 (in thousands):
2005
2004
2003
Operating
revenue
$
483,956
$
439,866
$
483,397
Income
(loss) before cumulative effect of change in accounting
principle
64,626
(3,084
)
37,341
Net
income (loss)
64,626
(3,084
)
34,874
Current
assets
151,363
127,853
Total
assets
1,418,099
1,450,507
Current
liabilities
120,888
118,623
Long-term
debt, including current portion
653,037
722,650
CE
Generation determined on December 9, 2004 that a portion of the carrying
value of the Power Resources project’s long-lived assets was no longer
recoverable. As a result, CE Generation recognized a non-cash impairment charge
of $54.5 million ($33.5 million after-tax), in accordance with SFAS
144, to write down the long-lived assets to their fair value. The fair value
was
determined based on discounted estimated cash flows from the future use of
the
long-lived assets. The impairment charge will not result in any current or
future cash expenditures. MEHC’s $16.8 million after-tax portion of the
Power Resources impairment is reflected in income on equity investments in
the
accompanying consolidated statement of operations for the year ended
December 31, 2004.
The
following is summarized financial information for HomeServices’ equity investees
as of and for the years ended December 31 (in thousands):
2005
2004
2003
Revenue
$
167,247
$
156,959
$
168,446
Operating
expense
88,311
80,997
83,284
Net
income
40,347
36,473
46,719
Current
assets
52,749
35,957
Total
assets
134,146
170,888
Current
liabilities
44,317
27,444
Total
liabilities
101,034
137,207
8.
Short-Term
Debt
Short-term
debt consists of the following at December 31 (in thousands):
2005
2004
MEHC
$
51,000
$
-
CE
Electric UK
10,361
38
HomeServices
8,705
9,052
Total
short-term debt
$
70,066
$
9,090
Parent
Company Revolving Credit Facilities
In
the
second quarter of 2005, the Company terminated its $100.0 million credit
facility. On August 26, 2005, the Company closed on a new unsecured
$400.0 million revolving credit facility which expires on August 26,2010. The facility supports letters of credit for the benefit of certain
subsidiaries and affiliates of which $41.9 million were outstanding at
December 31, 2005. Borrowings of $51.0 million were outstanding at
December 31, 2005, and no borrowings were outstanding on the prior facility
at December 31, 2004. The facility carries a variable interest rate based
on LIBOR or a base rate, at MEHC’s option, plus a margin. The interest rate on
the balance outstanding under the facility at December 31, 2005 was 4.85%.
The prior facility was not drawn on during 2004. As of December 31, 2005,
MEHC was in compliance with all covenants related to its revolving credit
facility.
82
MidAmerican
Energy Revolving Credit Facilities and Short-Term Debt
As
of
December 31, 2005, MidAmerican Energy has in place a $425.0 million
revolving credit facility expiring on November 18, 2009, which supports its
$304.6 million commercial paper program and its variable rate pollution
control revenue obligations. The related credit agreement requires that
MidAmerican Energy’s ratio of consolidated debt to total capitalization,
including current maturities, not exceed 0.65 to 1 as of the last day of any
quarter. In addition, MidAmerican Energy has a $5.0 million line of credit,
which expires July 1, 2006. As of December 31, 2005 and 2004,
MidAmerican Energy had no commercial paper or bank notes outstanding, and the
full amount of the revolving credit facility and line of credit was available.
As of December 31, 2005, MidAmerican Energy was in compliance with all
covenants related to its short-term borrowings. At December 31, 2005, the
credit facility had a variable interest rate based on LIBOR plus 0.40% and
the
line of credit had a variable interest rate based on LIBOR plus
0.25%.
CE
Electric UK Revolving Credit Facilities
On
April 4, 2005, CE Electric UK closed on a new £100.0 million revolving
credit facility which expires on April 4, 2010. The facility carries a
variable interest rate based on sterling LIBOR plus a margin. Borrowings of
$10.4 million were outstanding at December 31, 2005, at an interest
rate of 5.14%. CE Electric UK also has a total of £35.0 million in
uncommitted, variable rate, lines of credit, none of which were drawn on, at
December 31, 2005.
HomeServices
Revolving Credit Facilities and Short-Term Debt
HomeServices
entered into a new $125.0 million senior revolving credit facility in
December 2005, which expires in December 2010. This credit facility replaced
the
existing $125.0 million facility, which expired in November 2005. Amounts
outstanding under the new revolving credit facility are unsecured and bear
interest, at HomeServices’ option, at the prime lending rate or LIBOR plus a
fixed spread of 0.5% to 1.125%, which varies based on HomeServices’ total debt
ratio. The spread was 0.5% at December 31, 2005. No borrowings were
outstanding at December 31, 2005 or, under the prior facility, at
December 31, 2004.
Additionally,
in 2005, HomeServices has in place a mortgage warehouse line of credit totaling
$25.0 million, which expires in April 2006 and bears interest at LIBOR plus
a margin ranging from 1.75% to 2.00% depending on the type of mortgage loan
funded. The balance outstanding on this mortgage warehouse line of credit at
December 31, 2005 was $8.7 million at a weighted average interest rate
of 6.14%. In 2004, HomeServices had in place two mortgage warehouse lines of
credit totaling $20.0 million, which expired in 2005. The balance
outstanding on these mortgage warehouse lines of credit at December 31,2004, totaled $9.1 million at weighted average interest rates of 4.54% and
4.21%, respectively.
9.
Parent
Company Senior Debt
Parent
company senior debt represents unsecured senior obligations of MEHC and consists
of the following, including fair value adjustments and unamortized premiums
and
discounts, at December 31 (in thousands):
Par
Value
2005
2004
7.23%
Senior Notes, due 2005
$
-
$
-
$
258,797
4.625%
Senior Notes, due 2007
200,000
199,622
199,403
7.63%
Senior Notes, due 2007
350,000
347,354
346,000
3.50%
Senior Notes, due 2008
450,000
449,638
449,497
7.52%
Senior Notes, due 2008
450,000
444,539
442,828
7.52%
Senior Notes, due 2008 (Series B)
100,000
100,789
101,037
5.875%
Senior Notes, due 2012
500,000
499,915
499,906
5.00%
Senior Notes, due 2014
250,000
249,800
249,797
8.48%
Senior Notes, due 2028
475,000
484,554
484,692
Total
Parent Company Senior Debt
$
2,775,000
$
2,776,211
$
3,031,957
83
10.
Parent
Company Subordinated Debt
MEHC
has
organized special purpose Delaware business trusts (collectively, the “Trusts”)
pursuant to their respective amended and restated declarations of trusts
(collectively, the “Declarations”).
The
financial terms of MEHC’s various subordinated debentures held by such Trusts
are essentially identical to the corresponding terms of the mandatorily
redeemable preferred securities issued by such Trusts (the “Trust
Securities”).
Pursuant
to Preferred Securities Guarantee Agreements (collectively, the “Guarantees”),
between MEHC and a trustee, MEHC has agreed irrevocably to pay to the holders
of
the Trust Securities, to the extent that the applicable Trust has funds
available to make such payments, quarterly distributions, redemption payments
and liquidation payments on the Trust Securities. MEHC owns all of the common
securities of the Trusts. The CalEnergy Capital and MidAmerican Capital Trust
Securities have liquidation preferences of $50 and $25 each, respectively,
(plus
accrued and unpaid dividends thereon to the date of payment) and represent
undivided beneficial ownership interests in each of the Trusts. The assets
of
the Trusts consist solely of Subordinated Debentures of MEHC (collectively,
the
“Junior Debentures”) issued pursuant to their respective indentures. The
indentures include agreements by MEHC to pay expenses and obligations incurred
by the Trusts. Considered together, the undertakings contained in the
Declarations, Junior Debentures, Indentures and Guarantees constitute full
and
unconditional guarantees on a subordinated basis by MEHC of the Trusts’
obligations under the Trust Securities.
Parent
company subordinated debt consists of the following, including fair value
adjustments, at December 31 (in thousands):
Par
Value
2005
2004
CalEnergy
Capital Trust II - 6.25%, due 2012
$
104,645
$
92,724
$
91,328
CalEnergy
Capital Trust III - 6.5%, due 2027
269,980
206,175
205,253
MidAmerican
Capital Trust I - 11%, due 2010
409,295
409,295
454,772
MidAmerican
Capital Trust II - 11%, due 2011
600,000
600,000
700,000
MidAmerican
Capital Trust III - 11%, due 2012
279,933
279,933
323,000
Total
Parent Company Subordinated Debt
$
1,663,853
$
1,588,127
$
1,774,353
Prior
to
the Teton Transaction, each Trust Security issued by CalEnergy Capital Trust
II
and III with a par value of $50 was convertible at the option of the holder
at
any time into shares of MEHC’s common stock based on a specified conversion
rate. As a result of the Teton Transaction, in lieu of shares of MEHC’s common
stock, upon any conversion, holders of Trust Securities will receive $35.05
for
each share of common stock it would have been entitled to receive on
conversion.
Distributions
on the Trust Securities (and Junior Debentures) are cumulative, accrue from
the
date of initial issuance and are payable quarterly in arrears. The Junior
Debentures are subordinated in right of payment to all senior indebtedness
of
the Company and the Junior Debentures are subject to certain covenants, events
of default and optional and mandatory redemption provisions, all as described
in
the Junior Debenture indentures.
The
indentures relating to the CalEnergy Trusts II and III Trust Securities give
MEHC the option to defer the interest payments due on the respective Junior
Debentures for up to 20 consecutive quarters during which time the corresponding
distributions on the respective Trust Securities are deferred (but continue
to
accumulate and accrue interest). The indentures relating to the MidAmerican
Capital Trust I, II and III Trust Securities give MEHC the option to defer
the
interest payment on the respective Junior Debentures for up to 10 consecutive
semi-annual periods during which time the corresponding 11% distributions on
the
respective Trust Securities are deferred (but continue to accumulate and accrue
interest at the rate of 13% per annum). In addition, each declaration of trust
establishing the MidAmerican Capital Trusts I, II and III Trust Securities
and
each of the related subscription agreements contains a provision prohibiting
Berkshire Hathaway and its affiliates, who are the holders of all of the
respective Trust Securities issued by such Trusts, from transferring such Trust
Securities to a non-affiliated person absent an event of default.
84
11.
Subsidiary
and Project Debt
Each
of
MEHC’s direct and indirect subsidiaries is organized as a legal entity separate
and apart from MEHC and its other subsidiaries. Pursuant to separate project
financing agreements, all or substantially all of the assets of each subsidiary
are or may be pledged or encumbered to support or otherwise provide the security
for their own project or subsidiary debt. It should not be assumed that any
asset of any such subsidiary will be available to satisfy the obligations of
MEHC or any of its other such subsidiaries; provided, however, that unrestricted
cash or other assets which are available for distribution may, subject to
applicable law and the terms of financing arrangements of such parties, be
advanced, loaned, paid as dividends or otherwise distributed or contributed
to
MEHC or affiliates thereof.
The
restrictions on distributions at these separate legal entities include various
covenants including, but not limited to, leverage ratios, interest coverage
ratios and debt service coverage ratios. As of December 31, 2005, the
separate legal entities were in compliance with all applicable covenants.
However, Cordova Energy’s 537 MW gas-fired power plant in the Quad Cities,
Illinois area is currently prohibited from making distributions by the terms
of
its indenture due to its failure to meet its debt service coverage ratio
requirement.
Long-term
debt of subsidiaries and projects consists of the following, including fair
value adjustments and unamortized premiums and discounts, at December 31 (in
thousands):
Par
Value
2005
2004
MidAmerican
Funding
$
700,000
$
648,390
$
645,926
MidAmerican
Energy
1,637,118
1,631,760
1,422,527
CE
Electric UK
2,346,459
2,507,533
2,571,889
Kern
River
1,157,256
1,157,256
1,214,808
Northern
Natural Gas
800,000
799,560
799,614
CE
Casecnan
142,345
140,635
194,660
Leyte
Projects
42,630
42,630
105,664
Cordova
Funding
198,787
196,210
203,995
HomeServices
27,788
26,313
31,438
Total
Subsidiary and Project Debt
$
7,052,383
$
7,150,287
$
7,190,521
MidAmerican
Funding
The
components of MidAmerican Funding’s senior notes and bonds consist of the
following, including fair value adjustments, at December 31 (in
thousands):
Par
Value
2005
2004
6.339%
Senior Notes, due 2009
$
175,000
$
167,903
$
166,053
6.75%
Senior Notes, due 2011
200,000
200,000
200,000
6.927%
Senior Bonds, due 2029
325,000
280,487
279,873
Total
MidAmerican Funding
$
700,000
$
648,390
$
645,926
The
subsidiaries of MidAmerican Funding must make payments on their own indebtedness
before making distributions to MidAmerican Funding. The distributions are also
subject to utility regulatory restrictions agreed to by MidAmerican Energy
in
March 1999, whereby it committed to the IUB to use commercially reasonable
efforts to maintain an investment grade rating on its long-term debt and to
maintain its common equity level above 42% of total capitalization unless
circumstances beyond its control result in the common equity level decreasing
to
below 39% of total capitalization. MidAmerican Energy must seek approval from
the IUB of a reasonable utility capital structure if MidAmerican Energy’s common
equity level decreases below 42% of total capitalization, unless the decrease
is
beyond the control of MidAmerican Energy. MidAmerican Energy is also required
to
seek the approval of the IUB if MidAmerican Energy’s equity level decreases to
below 39%, even if the decrease is due to circumstances beyond the control
of
MidAmerican Energy.
85
MidAmerican
Energy
The
components of MidAmerican Energy’s mortgage bonds, pollution control revenue
obligations and notes consist of the following, including unamortized premiums
and discounts, at December 31 (in thousands):
Par
Value
2005
2004
Mortgage
bonds, 7% Series, due 2005
$
-
$
-
$
90,497
Pollution
control revenue obligations:
6.1%
Series, due 2007
1,000
1,000
1,000
5.95%
Series, due 2023, secured by general mortgage bonds
29,030
29,030
29,030
Variable
rate series:
Due
2016 and 2017, 3.59% and 2.05%
37,600
37,600
37,600
Due
2023, secured by general mortgage bonds, 3.59% and 2.05%
28,295
28,295
28,295
Due
2023, 3.59% and 2.05%
6,850
6,850
6,850
Due
2024, 3.59% and 2.05%
34,900
34,900
34,900
Due
2025, 3.59% and 2.05%
12,750
12,750
12,750
Notes:
6.375%
Series, due 2006
160,000
159,969
159,893
5.125%
Series, due 2013
275,000
274,581
274,521
4.65%
Series, due 2014
350,000
349,721
349,689
6.75%
Series, due 2031
400,000
395,628
395,459
5.75%
Series, due 2035
300,000
299,743
-
Other
1,693
1,693
2,043
Total
MidAmerican Energy
$
1,637,118
$
1,631,760
$
1,422,527
On
November 1, 2005, MidAmerican Energy issued $300.0 million of 5.75%
medium-term notes due in 2035. The proceeds are being used to support
construction of its electric generation projects and for general corporate
purposes.
CE
Electric UK
The
components of CE Electric UK and its subsidiaries’ long-term debt consist of the
following, including fair value adjustments and unamortized premiums and
discounts, at December 31 (in thousands):
Par
Value
2005
2004
Variable
Rate Reset Trust Securities, due 2020, 5.88%
$
-
$
-
$
308,361
8.625%
Bearer Bonds, due 2005
-
-
193,688
6.995%
Senior Notes, due 2007
237,000
232,547
230,572
6.496%
Yankee Bonds, due 2008
281,000
281,061
281,113
8.875%
Bearer Bonds, due 2020(1)
172,110
208,912
230,215
9.25%
Eurobonds, due 2020(1)
344,220
429,501
485,654
7.25%
Sterling Bonds, due 2022(1)
344,220
371,457
411,287
7.25%
Eurobonds, due 2028(1)
319,264
338,370
378,202
5.125%
Bonds, due 2035(1)
344,220
342,528
-
5.125%
Bonds, due 2035(1)
258,165
256,897
-
CE
Gas Credit Facility, 6.86% and 6.36%(1)
46,260
46,260
52,797
Total
CE Electric UK
$
2,346,459
$
2,507,533
$
2,571,889
(1)
The
par values for these debt instruments are denominated in sterling
and have
been converted to U.S. dollars at the applicable exchange
rate.
Pursuant
to a call option exercised in February 2005, at a cost of $17.5 million, a
subsidiary of CE Electric UK purchased, and then cancelled, its variable rate
reset trust securities, due in 2020, at a par value of £155.0 million.
Accordingly, the Company included the entire principal amount of these
securities in its current portion of long-term debt in the accompanying
consolidated balance sheet at December 31, 2004.
86
On
May 5, 2005, Northern Electric Finance plc, an indirect wholly-owned
subsidiary of CE Electric UK, issued £150.0 million of 5.125%
bonds due 2035, guaranteed by Northern Electric and guaranteed as to scheduled
payments of principal and interest by Ambac Assurance UK Limited (“Ambac”).
Additionally, on May 5, 2005, Yorkshire Electricity, an indirect
wholly-owned subsidiary of CE Electric UK, issued £200.0 million of 5.125%
bonds due 2035, guaranteed as to scheduled payments of principal and interest
by
Ambac. The proceeds from the offerings are being invested and used for general
corporate purposes. Investments include a £100.0 million 4.75% fixed rate
guaranteed investment contract maturing December 2007 and a £200.0 million
4.73% fixed rate guaranteed investment contract maturing February
2008.
Kern
River
The
components of Kern River’s term notes consist of the following at
December 31 (in thousands):
Par
Value
2005
2004
6.676%
Senior Notes, due 2016
$
415,167
$
415,167
$
439,000
4.893%
Senior Notes, due 2018
742,089
742,089
775,808
Total
Kern River
$
1,157,256
$
1,157,256
$
1,214,808
Northern
Natural Gas
The
components of Northern Natural Gas’ senior notes consist of the following,
including unamortized premiums and discounts, at December 31 (in
thousands):
Par
Value
2005
2004
6.875%
Senior Notes, due 2005
$
-
$
-
$
99,963
6.75%
Senior Notes, due 2008
150,000
150,000
150,000
7.00%
Senior Notes, due 2011
250,000
250,000
250,000
5.375%
Senior Notes, due 2012
300,000
299,688
299,651
5.125%
Senior Notes, due 2015
100,000
99,872
-
Total
Northern Natural Gas
$
800,000
$
799,560
$
799,614
On
April 14, 2005, Northern Natural Gas issued $100.0 million of 5.125%
senior notes due May 1, 2015. The proceeds were used by Northern Natural
Gas to repay its
outstanding $100.0 million 6.875% senior notes due May 1,2005.
CE
Casecnan
CE
Casecnan Water and Energy Company, Inc.’s (“CE Casecnan”) term notes and bonds
consist of the following, including fair value adjustments, at December 31
(in thousands):
Par
Value
2005
2004
11.45%
Senior Secured Series A Notes, due in 2005
$
-
$
-
$
47,432
11.95%
Senior Secured Series B Bonds, due in 2010
142,345
140,635
147,228
Total
CE Casecnan
$
142,345
$
140,635
$
194,660
Leyte
Projects
The
Leyte
Projects’ term loans consist of the following at December 31 (in
thousands):
Par
Value
2005
2004
Mahanagdong
Project 6.92% Term Loan, due 2007
$
30,922
$
30,922
$
51,537
Mahanagdong
Project 7.60% Term Loan, due 2007
6,857
6,857
11,428
Malitbog
Project 4.99% and 3.67%, due 2005
-
-
11,866
Malitbog
Project 9.176% Term Loan, due 2005
-
-
6,580
Upper
Mahiao Project 5.95% Term Loan, due 2006
4,851
4,851
24,253
Total
Leyte Projects
$
42,630
$
42,630
$
105,664
87
MEHC
provides debt service reserve letters of credit in amounts equal to the next
semi-annual principal and interest payments due on the loans which were equal
to
$18.8 million and $44.6 million at December 31, 2005 and 2004,
respectively.
Cordova
Funding
Cordova
Funding Corporation’s (“Cordova Funding”) senior secured bonds are due in
semi-annual installments and consist of the following, including fair value
adjustments, at December 31 (in thousands):
Par
Value
2005
2004
8.48%
Senior Secured Bonds, due 2019
$
11,269
$
11,269
$
11,716
8.64%
Senior Secured Bonds, due 2019
82,620
80,457
83,655
8.79%
Senior Secured Bonds, due 2019
27,661
27,247
28,328
8.82%
Senior Secured Bonds, due 2019
51,350
51,350
53,384
9.07%
Senior Secured Bonds, due 2019
25,887
25,887
26,912
Total
Cordova Funding
$
198,787
$
196,210
$
203,995
MEHC
has
issued a limited guarantee of a specified portion of the final scheduled
principal payment on December 15, 2019, on the Cordova Funding senior
secured bonds in an amount up to a maximum of $37.0 million. MEHC has also
issued a debt service reserve guarantee, the maximum amount of which is equal
at
any given time to the difference between the next succeeding debt service
payment ($11.0 million as of December 31, 2005) and the amount then on
deposit in the debt service reserve fund ($9.0 million at December 31,2005).
As
of
December 31, 2005, Cordova Funding is currently prohibited from making
distributions by the terms of its indenture due to its failure to meet its
debt
service coverage ratio requirement.
HomeServices
The
components of HomeServices’ long-term debt consist of the following, including
fair value adjustments, at December 31 (in thousands):
Par
Value
2005
2004
7.12%
Senior Notes, due 2010
$
25,000
$
23,525
$
28,475
Other
2,788
2,788
2,963
Total
HomeServices
$
27,788
$
26,313
$
31,438
Annual
Repayments of Long-Term Debt
The
annual repayments of parent company and subsidiary and project debt for the
years beginning January 1, 2006 and thereafter, excluding fair value
adjustments and unamortized premiums and discounts, are as follows (in
thousands):
2006
2007
2008
2009
2010
Thereafter
Total
Parent
company senior debt
$
-
$
550,000
$
1,000,000
$
-
$
-
$
1,225,000
$
2,775,000
Parent
company subordinated debt
234,021
234,021
234,021
234,021
188,543
539,226
1,663,853
MidAmerican
Funding
-
-
-
175,000
-
525,000
700,000
MidAmerican
Energy
160,509
1,651
448
32
32
1,474,446
1,637,118
CE
Electric UK
5,190
251,481
291,326
8,208
5,763
1,784,491
2,346,459
Kern
River
71,360
69,472
72,816
74,906
78,668
790,034
1,157,256
Northern
Natural Gas
-
-
150,000
-
-
650,000
800,000
CE
Casecnan
36,015
37,730
37,730
13,720
17,150
-
142,345
Leyte
Projects
30,037
12,593
-
-
-
-
42,630
Cordova
Funding
4,500
4,163
4,725
6,412
9,000
169,987
198,787
HomeServices
6,050
5,855
5,409
5,156
5,152
166
27,788
Totals
$
547,682
$
1,166,966
$
1,796,475
$
517,455
$
304,308
$
7,158,350
$
11,491,236
88
Fair
Value
At
December 31, 2005, the Company had fixed-rate long-term debt of
$11,348.0 million in principal amount and having a fair value of
$12,066.0 million. In addition, at December 31, 2005, the Company had
floating-rate obligations of $166.7 million that expose the Company to the
risk of increased interest expense in the event of increases in short-term
interest rates. The fair value of the floating-rate obligations and the
short-term debt approximates their carrying amounts.
At
December 31, 2004, the Company had fixed-rate long-term debt of
$11,503.4 million in principal amount and having a fair value of
$12,416.2 million. In addition, at December 31, 2004, the Company had
floating-rate obligations of $493.4 million. The fair value of the
floating-rate obligations and the short-term debt approximates their carrying
amounts.
12.Asset
Retirement Obligations
On
December 31, 2005, the Company adopted FASB Interpretation No. 47,
“Accounting for Conditional Asset Retirement Obligations, an interpretation
of
FASB Statement No. 143” (“FIN 47”). FIN 47 clarifies
that the term conditional
asset retirement obligation
as used
in SFAS 143 refers to a legal obligation to perform an asset retirement activity
in which the timing and/or method of settlement are conditional on a future
event that may or may not be within the control of the entity. Accordingly,
the
Company is required to recognize a liability for the fair value of a conditional
ARO if the fair value of the liability can be reasonably estimated. Uncertainty
about the timing or method of settlement of a conditional ARO should be factored
into the measurement of the liability when sufficient information exists.
In
conjunction with the adoption of FIN 47, the Company recorded $11.4 million
of ARO liabilities; $0.8 million of associated ARO assets, net of
accumulated depreciation; and a $10.6 million reduction of regulatory
liabilities. Adoption of FIN 47 did not impact net income.
The
change in the balance of the ARO liability, which is included in other long-term
accrued liabilities in the accompanying consolidated balance sheets, for the
years ended December 31 is summarized as follows (in
thousands):
2005
2004
Balance,
January 1
$
185,781
$
284,377
Adoption
of FIN 47
11,422
-
Revisions
1,120
(120,098
)
Additions
3,897
5,602
Retirements
(4,331
)
-
Accretion
10,659
15,900
Balance,
December 31
$
208,548
$
185,781
At
December 31, 2005, $163.0 million of the total ARO liability pertained
to the decommissioning of Quad Cities Station. Assets of $228.1 million,
reflected in other investments in the accompanying consolidated balance sheet,
are restricted for satisfying the Quad Cities Station ARO
liability.
Revisions
for the year ended December 31, 2004 include a revision to the nuclear
decommissioning ARO liability as a result of a change in the assumed life of
Quad Cities Station pursuant to a 20-year extension to the operating license
of
the plant by the NRC in October 2004 and its impact on the timing of related
cash flows.
The
total
ARO liability, computed on a pro forma basis as if FIN 47 had been applied
during each of the periods presented in the consolidated financial statements,
would have been as follows (in millions):
In
addition to the ARO liabilities, MidAmerican Energy has accrued for the cost
of
removing other electric and natural gas assets through its depreciation rates,
in accordance with accepted regulatory practices. These accruals, totaling
$448.5 million and $428.7 million at December 31, 2005 and 2004,
respectively, are reflected as regulatory liabilities and included in other
long-term accrued liabilities in the accompanying consolidated balance
sheets.
The
total
outstanding cumulative preferred securities of MidAmerican Energy are not
subject to mandatory redemption requirements and may be redeemed at the option
of MidAmerican Energy at prices which, in the aggregate, total
$31.1 million. The aggregate total the holders of all preferred securities
outstanding at December 31, 2005, are entitled to upon involuntary
bankruptcy is $30.3 million plus accrued dividends. The total annual
dividend requirements for all preferred securities outstanding at
December 31, 2005 were $1.2 million.
The
total
outstanding 8.061% cumulative preferred securities of a subsidiary of CE
Electric UK, which are redeemable in the event of the revocation of the
subsidiary’s electricity distribution license by the Secretary of State, was
$56.0 million as of December 31, 2005 and 2004,
respectively.
14.Risk
Management and Hedging Activities
The
Company is directly exposed to the impact of market fluctuations in the prices
of natural gas and electricity as a result of its ownership of MidAmerican
Energy, Northern Natural Gas and CE Electric UK. Exposure to foreign
currency risk exists from investment in businesses, primarily
CE Electric UK, operated in foreign countries. The Company is exposed
to interest rate risk as a result of the issuance of fixed rate debt. The
Company employs established policies and procedures to manage its risks
associated with these market fluctuations using various commodity and financial
derivative instruments, including forward contracts,
futures,
swaps
and options. The
risk
management process established by each business platform is designed to
identify, assess, monitor, report, manage, and mitigate each of the various
types of risk involved in its business. The Company does not engage in a
material amount of proprietary trading activities.
Some
of
MEHC’s subsidiaries are exposed to market price fluctuations of various
commodities related to their ongoing power generation and natural gas gathering,
distribution, processing and marketing activities. The Company closely monitors
the potential impacts of commodity price changes and, where appropriate, enters
into contracts to lock-in prices for a portion of the future sales, generation
revenue and fuel expenses.
Certain
derivative electric and gas contracts utilized by the regulated operations
of
MidAmerican Energy are recoverable through retail rates. Accordingly, unrealized
changes in fair value of these contracts are deferred as regulatory assets
or
liabilities pursuant to SFAS 71. At December 31, 2005, $32.7 million of
derivative assets and $47.6 million of derivative liabilities were used for
regulated purposes.
Other
MEHC subsidiaries use derivative instruments such as swaps, futures, forwards
and options as cash flow hedges for natural gas and other
transactions.
90
Currency
Exchange Rate Risk
CE
Electric UK has entered into certain currency rate swap agreements for its
senior notes and Yankee bonds with large multi-national financial institutions.
The swap agreements effectively convert the U.S. dollar fixed interest rate
to a
fixed rate in sterling for $237.0 million of 6.995% senior notes and
$281.0 million of 6.496% Yankee bonds outstanding at December 31,2005. The agreements extend until December 30, 2007 and February 25,2008, respectively. The estimated fair value of these swap agreements at
December 31, 2005 and 2004, was $77.5 million and $131.8 million,
respectively, based on quotes from the counterparties to these instruments
and
represents the estimated amount that the Company would expect to pay if these
agreements were terminated.
Interest
Rate Hedges
The
Company may enter into contractual agreements to hedge exposure to interest
rate
risk. Changes in fair value of interest rate “locks” used as cash flow hedges
are reported in accumulated other comprehensive income to the extent the hedge
is effective until the forecasted transaction occurs, at which time they are
recorded as adjustments to interest expense over the term of the related debt
issuance. In May 2005, MEHC entered into a treasury rate lock agreement in
the
notional amount of $1.6 billion to protect against a rise in interest rates
related to the anticipated financing of the PacifiCorp acquisition. For the
year
ended December 31, 2005, the amount of the deferred gain included in other
comprehensive income was $ - million.
Credit
Risk
Domestic
Regulated Operations
MidAmerican
Energy’s utility operations grant unsecured credit to its retail electric and
gas customers, substantially all of whom are local businesses and residents,
which totaled $186.0 million at December 31, 2005. MidAmerican Energy
also extends unsecured credit to other utilities, energy marketers, financial
institutions and certain commercial and industrial end-users in conjunction
with
wholesale energy marketing activities. MidAmerican Energy analyzes the financial
condition of each significant counterparty before entering into any
transactions, establishes limits on the amount of unsecured credit to be
extended to each counterparty, and evaluates the appropriateness of unsecured
credit limits on a daily basis. MidAmerican Energy seeks to negotiate
contractual arrangements with wholesale counterparties to provide for net
settlement of monthly accounts receivable and accounts payable and net
settlement of contracts for future performance in the event of default. At
December 31, 2005, 84.4% of MidAmerican Energy’s credit exposure, net of
collateral, from wholesale operations was with counterparties having “investment
grade” credit ratings from Moody’s or Standard & Poor’s, while an additional
7.4% of MidAmerican Energy’s credit exposure, net of collateral, from wholesale
operations was with counterparties having financial characteristics deemed
equivalent to “investment grade” by MidAmerican Energy based on internal review.
Northern
Natural Gas’ primary customers include regulated local distribution companies in
the upper Midwest. Kern River’s primary customers are electric generating
companies and energy marketing and trading companies in the western United
States. As a general policy, collateral is not required for receivables from
creditworthy customers. Customers’ financial condition and creditworthiness are
regularly evaluated, and historical losses have been minimal. In order to
provide protection against credit risk, and as permitted by the separate terms
of each of Northern Natural Gas’ and Kern River’s tariffs, the companies have
required customers that lack creditworthiness, as defined by the tariffs, to
provide cash deposits, letters of credit or other security until their
creditworthiness improves.
CE
Electric UK
Northern
Electric and Yorkshire Electricity charge fees for the use of their electrical
infrastructure levied on supply companies. The supply companies, which purchase
electricity from generators and traders and sell the electricity to end-use
customers, use Northern Electric’s and Yorkshire Electricity’s distribution
networks pursuant to an industry standard “Distribution Use of System
Agreement,” which Northern Electric and Yorkshire Electricity separately entered
into with the various suppliers of electricity in their respective distribution
service areas. Northern Electric’s and Yorkshire Electricity’s customers are
concentrated in a small number of electricity supply businesses with RWE Npower
PLC accounting for approximately 44% of distribution revenues in 2005. The
Office of Gas and Electricity Markets (“Ofgem”) has determined a framework which
sets credit limits for each supply business and requires them to provide credit
cover if their value at risk (measured as being equivalent to 45 days usage)
exceeds the credit limit. Acceptable credit cover must be provided in the form
of a parent company guarantee, letter of credit or an escrow account. Ofgem
has
indicated that, provided Northern Electric and Yorkshire Electricity have
implemented credit control, billing and collection in line with best practice
guidelines and can demonstrate compliance with the guidelines or are able to
satisfactorily explain departure from the guidelines, any bad debt losses
arising from supplier default will be recovered through an increase in future
allowed income. Losses incurred to date have not been material.
91
CalEnergy
Generation-Foreign
PNOC-EDC’s
and NIA’s obligations under the project agreements are the Leyte Projects’ and
Casecnan Project’s sole source of operating revenue. Because of the dependence
on a single customer, any material failure of the customer to fulfill its
obligations under the project agreements and any material failure of the ROP
to
fulfill its obligation under the performance undertaking would significantly
impair the ability to meet existing and future obligations, including
obligations pertaining to the outstanding project debt. Total operating revenue
for CalEnergy Generation-Foreign was $312.3 million for the year ended
December 31, 2005. The Leyte Projects’ agreements expire in June 2006
and July 2007, respectively, while the Casecnan Project’s agreement expires in
December 2021.
15.
Income
Taxes
Income
tax expense on continuing operations consists of the following (in
thousands):
A
reconciliation of the federal statutory tax rate to the effective tax rate
on
continuing operations applicable to income before income tax expense
follows:
The
net
deferred tax liability consists of the following at December 31 (in
thousands):
2005
2004
Deferred
tax assets:
Minimum
pension liability adjustment
$
145,767
$
163,761
Revenue
sharing accruals
92,040
80,220
Accruals
not currently deductible for tax purposes
80,798
54,402
Deferred
income
20,050
34,458
Nuclear
reserve and decommissioning
14,962
27,112
Net
operating loss (“NOL”) and credit carryforwards
265,408
267,051
Other
4,551
16,569
Total
deferred tax assets
623,576
643,573
Deferred
tax liabilities:
Properties,
plants and equipment, net
1,756,340
1,700,884
Income
taxes recoverable through future rates
176,108
163,108
Employee
benefits
40,632
51,509
Fuel
cost recoveries
9,897
6,028
Reacquired
debt
2,473
3,877
Total
deferred tax liabilities
1,985,450
1,925,406
Net
deferred tax liability
$
1,361,874
$
1,281,833
At
December 31, 2005, the Company has available unused NOL and credit
carryforwards that may be applied against future taxable income and that expire
at various intervals between 2007 and 2026.
16.
Other
Income and Expense
Other
income for the years ending December 31 consists of the following (in
thousands):
2005
2004
2003
Allowance
for equity funds used during construction
$
26,170
$
20,476
$
26,708
Gains
on sales of non-strategic assets and investments
23,298
3,609
4,183
Gains
on Enron note receivable and other claims
6,358
72,210
-
Corporate-owned
life insurance income
5,150
5,447
6,317
Gain
on Mirant bankruptcy claim
-
14,750
-
Gain
on CE Casecnan settlement
-
-
31,889
Gain
on Williams preferred stock
-
-
13,750
Other
13,540
11,713
13,796
Total
other income
$
74,516
$
128,205
$
96,643
Non-Strategic
Assets and Investments
Included
in gains on sales of non-strategic assets and investments for the year ended
December 31, 2005, are gains from sales of certain non-strategic, passive
investments at MidAmerican Funding of $13.4 million and
CE Electric UK of $8.4 million.
Enron
Note Receivable and Other Claims
Northern
Natural Gas had a note receivable of approximately $259.0 million (the
“Enron Note Receivable”) with Enron. As a result of Enron filing for bankruptcy
on December 2, 2001, Northern Natural Gas filed a bankruptcy claim against
Enron seeking to recover payment of the Enron Note Receivable. As of
December 31, 2001, Northern Natural Gas had written-off the note. By
stipulation, Enron and Northern Natural Gas agreed to a value of
$249.0 million for the claim and received approval of the stipulation from
Enron’s Bankruptcy Court on August 26, 2004. On November 23, 2004,
Northern Natural Gas sold its stipulated general, unsecured claim against Enron
of $249.0 million to a third party investor for $72.2 million.
93
Mirant
Americas Energy Marketing (“Mirant”) Claim
Mirant
was one of the shippers that entered into a 15-year, 2003 Expansion Project,
firm gas transportation contract (90,000 Dth per day) with Kern River and
provided a letter of credit equivalent to 12 months of reservation charges
as
security for its obligations thereunder. In July 2003, Mirant filed for Chapter
11 bankruptcy protection and Kern River subsequently drew on the letter of
credit and held the proceeds thereof, $14.8 million, as cash collateral.
The bankruptcy court ultimately determined that Kern River was entitled to
the
$14.8 million cash collateral which resulted in Kern River recognizing such
amount as other income.
CE
Casecnan Arbitration Settlement
On
October 15, 2003, CE Casecnan, an indirect, majority-owned subsidiary of
the Company, closed a transaction settling the arbitration, which arose from
a
Statement of Claim made on August 19, 2002, by CE Casecnan against the
Republic of the Philippines (“ROP”) NIA. As a result of the agreement, CE
Casecnan recorded $31.9 million of other income and $24.4 million of
associated income taxes. In connection with the settlement, the NIA delivered
to
CE Casecnan a $97.0 million 8.375% ROP Note due 2013 (the “ROP Note”),
which contained a put provision granting CE Casecnan the right to put the ROP
Note to the ROP for a price of par plus accrued interest for a 30-day period
commencing on January 14, 2004. On January 14, 2004, CE Casecnan
exercised its right to put the ROP Note to the ROP and, in accordance with
the
terms of the put, CE Casecnan received $99.2 million (representing
$97.0 million par value plus accrued interest) from the ROP on
January 21, 2004.
Williams
Preferred Stock
On
March 27, 2002, the Company invested $275.0 million in Williams in
exchange for shares of 9.875% cumulative convertible preferred stock of
Williams. Dividends on the Williams preferred stock were received quarterly,
commencing July 1, 2002. On June 10, 2003, Williams repurchased, for
$288.8 million, plus accrued dividends, all of the shares of its 9.875%
Cumulative Convertible Preferred Stock originally acquired by the Company in
March 2002 for $275.0 million. The Company recorded a pre-tax gain of
$13.8 million on the transaction.
Other
Expense
The
Company’s other expense totaled $22.1 million, $10.1 million and
$5.9 million, respectively, for the years ended December 31, 2005,
2004 and 2003. MidAmerican Funding has investments in commercial passenger
aircraft leased to major domestic airlines, which are accounted for as leveraged
leases. During 2005, the airline industry continued to deteriorate and two
major
airline carriers filed for bankruptcy. MidAmerican Funding evaluated its
investments in commercial passenger aircraft and recognized losses totaling
$15.6 million for other-than-temporary impairments of those
investments.
17.
Discontinued
Operations - Zinc Recovery Project and Mineral
Assets
Indirect
wholly-owned subsidiaries of MEHC own the rights to commercial quantities of
extractable minerals from elements in solution in the geothermal brine and
fluids utilized at certain geothermal energy generation facilities located
in
the Imperial Valley of California and a zinc recovery plant constructed near
the
geothermal energy generation facilities designed to recover zinc from the
geothermal brine through an ion exchange, solvent extraction, electrowinning
and
casting process (the “Zinc Recovery Project”).
The
Zinc
Recovery Project began limited production during December 2002 and continued
limited production until September 10, 2004. On September 10, 2004,
management made the decision to cease operations of the Zinc Recovery Project.
Based on this decision, a non-cash, after-tax impairment charge of
$340.3 million was recorded to write-off the Zinc Recovery Project, rights
to quantities of extractable minerals, and allocated goodwill (collectively,
the
“Mineral Assets”). The charge and the related activity of the Mineral Assets are
classified separately as discontinued operations in the accompanying
consolidated statements of operations and include the following (in
thousands):
94
Year
Ended December 31.
2005
2004
2003
Operating
revenue
$
-
$
3,401
$
659
Losses
from discontinued operations
$
-
$
(42,695
)
$
(46,423
)
Proceeds
from (costs of) disposal activities, net
7,634
(4,134
)
-
Asset
impairment charges
-
(479,233
)
-
Goodwill
impairment charges
-
(52,776
)
-
Income
tax (expense) benefit
(2,500
)
211,277
19,305
Income
(loss) from discontinued operations, net of tax
$
5,134
$
(367,561
)
$
(27,118
)
In
connection with ceasing operations, the Zinc Recovery Project’s assets have been
dismantled and sold and certain employees of the operator of the Zinc Recovery
Project were paid one-time termination benefits. Implementation of the
decommissioning plan began in September 2004 and, as of December 31, 2005,
the dismantling, decommissioning, and sale of remaining assets of the Zinc
Recovery Project was completed. Proceeds from the sale of the Zinc Recovery
Project’s assets exceeded the cost of disposal activities during the year ended
December 31, 2005. Salvage proceeds were recognized in the period earned.
Costs were recognized in the period in which the related liability was incurred.
Cash expenditures of approximately $4.1 million, consisting of pre-tax
disposal costs, termination benefit costs and property taxes, were made through
December 31, 2004.
18.Stock
Transactions
On
January 6, 2004, the Company purchased a portion of the shares of common
stock owned by Mr. Sokol for an aggregate purchase price of
$20.0 million.
There
were no common stock options granted, forfeited or allowed to expire during
each
of the three years in the period ended December 31, 2005. Common stock
options exercised during each of the three years in the period ended
December 31, 2005 consisted solely of 200,000 in 2005 held by
Mr. Sokol having an exercise price of $29.01 per share. There were
1,848,329 common stock options outstanding and exercisable with a
weighted-average exercise price of $30.75 per share at December 31, 2005.
1,145,000 of the outstanding and exercisable common stock options have exercise
prices ranging from $15.94 to $34.69 per share, a weighted-average exercise
price of $28.11 per share and a remaining contractual life of 2.25 years. The
remaining 703,329 outstanding and exercisable common stock options have an
exercise price of $35.05 per share and a remaining contractual life of 4.25
years. There were 2,048,329 common stock options outstanding and exercisable
with a weighted-average exercise price of $30.58 per share at December 31,2004, 2003 and 2002.
19.
Regulatory
Matters
MidAmerican
Energy
Under
a
series of settlement agreements between MidAmerican Energy, the Iowa Office
of
Consumer Advocate (“OCA”) and other interveners approved by the IUB, MidAmerican
Energy has agreed not to seek a general increase in electric rates to become
effective prior to January 1, 2012 unless its Iowa jurisdictional electric
return on equity for any year falls below 10%. Prior to filing for a general
increase in electric rates, MidAmerican Energy is required to conduct 30 days
of
good faith negotiations with the signatories to the settlement agreements to
attempt to avoid a general increase in such rates. As a party to the settlement
agreements, the OCA has agreed not to seek any decrease in MidAmerican Energy’s
Iowa electric rates prior to January 1, 2012. The settlement agreements
specifically allow the IUB to approve or order electric rate design or
cost-of-service rate changes that could result in changes to rates for specific
customers as long as such changes do not result in an overall increase in
revenues for MidAmerican Energy. The settlement agreements also each provide
that portions of revenues associated with Iowa retail electric returns on equity
within specified ranges will be recorded as a regulatory liability.
95
Under
a
settlement agreement approved by the IUB on December 31, 2001, which was
effective through December 31, 2005, an amount equal to 50% of revenues
associated with returns on equity between 12% and 14%, and 83.33% of revenues
associated with returns on equity above 14%, in each year was recorded as a
regulatory liability. A settlement agreement, which was filed in conjunction
with MidAmerican Energy’s application for ratemaking principles on its 2004/2005
wind power project and approved by the IUB on October 17, 2003, provided
that during the period January 1, 2006 through December 31, 2010, an
amount equal to 40% of revenues associated with returns on equity between 11.75%
and 13%, 50% of revenues associated with returns on equity between 13% and
14%,
and 83.3% of revenues associated with returns on equity above 14%, in each
year
will be recorded as a regulatory liability.
A
settlement agreement approved by the IUB on January 31, 2005, in
conjunction with MidAmerican Energy’s 2005 expansion of its wind power project
extended through 2011 MidAmerican Energy’s commitment not to seek a general
increase in electric rates unless its Iowa jurisdictional electric return on
equity falls below 10%. It also extended the revenue sharing mechanism through
2011, and the OCA agreed not to seek any decrease in Iowa electric base rates
to
become effective before January 1, 2012.
On
December 16, 2005, MidAmerican Energy filed with the IUB a settlement
agreement between MidAmerican Energy and the OCA regarding ratemaking principles
for up to 545 MW of additional wind generation capacity in Iowa, based on
nameplate ratings. The settlement agreement, which is subject to IUB approval,
extends through 2012 MidAmerican Energy’s commitment not to seek a general
increase in electric rates unless its Iowa jurisdictional electric return on
equity for the calendar year 2011 falls below 10%. Additionally, the revenue
sharing mechanism is extended through 2012, and the OCA agrees not to seek
any
decrease in Iowa electric base rates to become effective prior to January 1,2013.
The
regulatory liabilities created by the settlement agreements are recorded as
a
regulatory charge in depreciation and amortization expense when the liability
is
accrued. Additionally, interest expense is accrued on the portion of the
regulatory liability balance recorded in prior years. The regulatory liabilities
created for the years through 2010 are expected to be reduced as they are
credited against plant in service associated with generating plant additions.
As
a result of the credit applied to generating plant balances from the reduction
of the regulatory liabilities, future depreciation will be reduced. The
regulatory liability accrued for 2011 and 2012, if any, will be credited to
customer bills in 2012 and 2013, respectively.
Kern
River
Kern
River’s tariff rates are designed to give it an opportunity to recover all
actually and prudently incurred operations and maintenance costs of its pipeline
system, taxes, interest, depreciation and amortization and a regulated equity
return. Kern River’s rates have historically been set using a “levelized
cost-of-service” methodology so that the rate is constant over the contract
period; however, rate design is the subject of Kern River’s current rate case
before the FERC and may be subject to change as a result of the rate case
outcome. This levelized cost of service has been achieved by using a
FERC-approved depreciation schedule in which depreciation increases as interest
expense decreases. If the Kern River system is converted to a traditional rate
design as a result of the 2004 general rate case, the depreciation of Kern
River’s transmission system would be calculated on a straight-line basis over
the expected economic life of its facilities. Under the traditional methodology,
transportation rates do not remain constant over the lives of the shipper
contracts, but rather are adjusted in each rate case to reflect current
operating costs, updated depreciation rates and the rate base investment then
in
effect.
Kern
River was required to file its 2004 general rate case no later than May 1,2004 pursuant to the terms of its 1998 FERC Docket No. RP99-274 rate case
settlement. Kern River filed its rate case on April 30, 2004, which
supports an annual revenue increase of $40.1 million representing a 13%
increase from its existing cost of service and a proposed overall cost of
service of $347.4 million. The rate increase became effective on
November 1, 2004, subject to refund. Since its previous rate case, Kern
River increased the capacity of its system from 724,500 Dth per day to 1,755,575
Dth per day at a cost of approximately $1.2 billion. The filing employed
the levelized rate methodology.
The
Kern
River 2004 general rate case hearing concluded in August 2005. On March 2,2006,
Kern River received an initial decision on the case from the administrative
law
judge. Briefs on exceptions will be due on April 3, 2006, and briefs opposing
exceptions are due April 26, 2006. The administrative law judge’s initial
decision is non-binding and after briefing, the FERC will issue its initial
decision on the case. The initial FERC decision, which may result in rate
refunds, typically becomes binding on all parties while rehearing requests
on
the FERC decision and/or court appeals are pending. The initial FERC decision
is
not expected until late 2006 or early 2007. The final resolution of the rate
case is dependent on receiving a final, non-appealable decision on the case
from
the FERC, or approval of a settlement of the case by the FERC.
96
Northern
Natural Gas
Northern
Natural Gas continues to use a straight fixed variable rate design which
provides that all fixed costs assignable to firm capacity customers, including
a
return on equity, are to be recovered through fixed monthly demand or capacity
reservation charges which are not a function of throughput volumes.
On
May 1, 2003, Northern Natural Gas filed a general rate case proceeding for
increased rates with the FERC and filed an additional rate case proceeding
on
January 30, 2004 to reflect further cost increases. The FERC consolidated
the 2003 and 2004 rate cases due to the similarity of issues in both cases
and
the updated costs. On March 25, 2005, as modified on April 22, 2005,
Northern Natural Gas filed a stipulation and agreement with the FERC (the
“Settlement”) resolving the consolidated rate cases. On June 20, 2005, the
FERC approved the Settlement without modification. The Settlement represents
the
agreement Northern Natural Gas reached with its customers to settle the base
tariff rates and related tariff issues in the consolidated cases. The Settlement
provided for, among other things, rates designed to generate revenues on an
annual basis above the base rates which were in effect as of October 31,2003, as follows: $48 million for the period November 1, 2003 through
October 31, 2004, $53 million for the period November 1, 2004
through October 31, 2005, $58 million for the period November 1,2005 through October 31, 2006, and $62 million beginning
November 1, 2006. Northern Natural Gas provided refunds including interest
of $71.5 million to its customers in the third quarter of 2005 consistent
with the terms of the Settlement, generally reflecting the difference between
the rate increases implemented on November 1, 2003 and November 1,2004 and the revenue generated using the Settlement rates.
In
April
2004, Northern Natural Gas also filed tariff sheets with the FERC in relation
to
its system levelized account (“SLA”) (an imbalance recovery mechanism) with the
new rates going into effect on June 1, 2004, subject to refund. On
February 14, 2005, Northern Natural Gas received FERC approval of the SLA
settlement. The SLA settlement provides for recovery of the final SLA balance
as
of December 31, 2004, over a forty-eight month period beginning
November 1, 2003. Under the SLA settlement, Northern Natural Gas is
responsible for the financial impacts of managing operational storage
volumes.
CE
Electric UK
Most
of
the revenue of the DLHs in Great Britain is controlled by a distribution price
control formula which is set out in the license of each DLH. It has been the
practice of Ofgem (and its predecessor body, the Office of Electricity
Regulation), to review and reset the formula at five-year intervals, although
the formula has been, and may be, further reviewed at other times at the
discretion of the regulator. Any such resetting of the formula requires the
consent of the DLH. If the DLH does not consent to the formula reset, it is
reviewed by the British competition commission, whose recommendations can then
be given effect by license modifications made by Ofgem.
The
current formula requires that regulated distribution income per unit is
increased or decreased each year by RPI-Xd where RPI means the Retail Prices
Index, reflecting the average of the 12-month inflation rates recorded for
each
month in the previous July to December period. The Xd factor in the formula
was
established by Ofgem at the price control review effective in April 2005 (and
through March 31, 2010, is expected to continue to be set) at 0%. The
formula also takes account of a variety of other factors including the changes
in system electrical losses, the number of customers connected and the voltage
at which customers receive the units of electricity distributed. The
distribution price control formula determines the maximum average price per
unit
of electricity distributed (in pence per kWh) which a DLH is entitled to charge.
The distribution price control formula permits DLHs to receive additional
revenue due to increased distribution of units and the increase in the number
of
end users. The price control does not seek to constrain the profits of a DLH
from year to year. It is a control on revenue that operates independently of
most of the DLH’s costs. During the term of the price control, cost savings or
additional costs have a direct impact on income and cash flow.
97
The
procedure and methodology adopted at a price control review are at the
reasonable discretion of Ofgem. Generally, Ofgem’s judgment of the future
allowed revenue of licensees has been based upon, among other
things:
·
the
actual operating costs of each of the
licensees;
·
the
operating costs which each of the licensees would incur if it were
as
efficient as, in Ofgem’s judgment, the more efficient
licensees;
·
the
taxes that each licensee is expected to
pay;
·
the
regulatory value to be ascribed to each of the licensees’ distribution
network assets;
·
the
allowance for depreciation of the distribution network assets of
each of
the licensees;
·
the
rate of return to be allowed on investment in the distribution network
assets by all licensees; and
·
the
financial ratios of each of the licensees and the license requirement
for
each licensee to maintain an investment grade
status.
As
a
result of the review concluded in 2004, the allowed revenue of Northern
Electric’s distribution business was reduced by 4%, in real terms, and the
allowed revenue of Yorkshire Electricity’s distribution business was reduced by
9%, in real terms, with effect from April 1, 2005. Ofgem indicated that
during the period 2005 to 2010, the retention of the benefits of any
out-performance from the operating cost assumptions made by Ofgem in setting
the
new price control might depend on the successful implementation of revised
cost
reporting guidelines prescribed by Ofgem and to be applied by all
DLHs.
The
triennial process of valuing the UK pension plan’s assets and liabilities, which
valued the plan assets and liabilities as of March 31, 2004, was completed
in 2005. This valuation set a revised level of contributions for the next three
years. The report of the actuaries conducting the valuation showed a funding
deficiency of £190.3 million. Based on this valuation, CE Electric UK will
contribute £23.1 million to the pension plan each year in respect of the
existing funding deficiency. The amount in respect of the funding deficiency
has
been calculated based on eliminating the funding deficiency over 12 years
commencing April 1, 2005. In setting the allowed revenue of Northern
Electric and Yorkshire Electricity (and all other DLHs) with effect from
April 1, 2005, Ofgem made a specific allowance for an amount in respect of
each DLH’s pension costs, which reflects recovery of a significant portion of
the deficiency payments.
With
effect from April 1, 2005, a number of incentive schemes operate to
encourage DLHs to provide an appropriate quality of service. Payments in respect
of each failure to meet a prescribed standard of service are set out in
regulations. The aggregate of payments that may be due is uncapped, although
payments are excused in certain force majeure circumstances. In storm conditions
the obligations relating to the period within which supplies should be restored
are relaxed and the overall, annual exposure under the restoration standard
in
storm conditions is limited to 2% of a DLH’s allowed revenue. There also is a
discretionary reward scheme of up to £1 million per annum, and other
incentive schemes pursuant to which a DLH’s allowed revenue may increase by up
to 3.3% or decrease by up to 3.5% in any year.
20.
Commitments
and Contingencies
MidAmerican
Energy, Kern River, Northern Natural Gas, CE Electric UK, CalEnergy
Generation-Domestic and HomeServices have non-cancelable operating leases
primarily for computer equipment, office space and rail cars. Rental payments
on
non-cancelable operating leases totaled $77.4 million for 2005,
$71.1 million for 2004, and $65.8 million for 2003. The minimum
payments under these leases are $74.8 million, $67.8 million,
$57.0 million, $45.7 million, and $35.3 million for the years
2006 through 2010, respectively, and $96.2 million for the total of the
years thereafter.
MidAmerican
Energy
Fuel
and Energy Commitments
MidAmerican
Energy has coal supply and related transportation contracts for its
fossil-fueled generating stations. As of December 31, 2005, the contracts,
with expiration dates ranging from 2006 to 2010, require minimum payments of
$87.4 million, $70.0 million, $35.6 million, $35.2 million
and $16.1 million for the years 2006 through 2010, respectively.
MidAmerican Energy expects to supplement these coal contracts with additional
contracts and spot market purchases to fulfill its future fossil fuel needs.
Additionally, MidAmerican Energy has a transportation contract for a natural
gas-fired generating plant. The contract, which expires in 2012, requires
minimum annual payments of $6.0 million.
98
MidAmerican
Energy also has contracts to purchase electric capacity. As of December 31,2005, the contracts, with expiration dates ranging from 2006 to 2028, require
minimum payments of $26.2 million, $27.5 million, $35.7 million,
$28.9 million and $9.4 million for the years 2006 through 2010,
respectively, and $165.3 million for the total of the years
thereafter.
MidAmerican
Energy has various natural gas supply and transportation contracts for its
gas
operations. As of December 31, 2005, the contracts, with expiration dates
ranging from 2006 to 2017, require minimum payments of $61.5 million,
$51.0 million, $16.7 million, $10.9 million and $5.7 million
for the years 2006 through 2010, respectively, and $16.9 million for the
total of the years thereafter.
MidAmerican
Energy is the lessee on operating leases for coal railcars that contain
guarantees of the residual value of such equipment throughout the term of the
leases. Events triggering the residual guarantees include termination of the
lease, loss of the equipment or purchase of the equipment. Lease terms are
for
five years with provisions for extensions. As of December 31, 2005, the
maximum amount of such guarantees specified in these leases totaled
$29.4 million. These guarantees are not reflected in the accompanying
consolidated balance sheets.
On
February 12, 2003, MidAmerican Energy executed a contract with Mitsui &
Co. Energy Development, Inc. (“Mitsui”) for engineering, procurement and
construction of a 790 MW (based on expected accreditation) coal-fired generating
plant expected to be completed in the summer of 2007. MidAmerican Energy
currently holds a 60.67% individual ownership interest as a tenant in common
with the other owners of the plant. Under the contract, MidAmerican Energy
is
allowed to defer payments, including the other owners’ shares, for up to
$200.0 million of billed construction costs through the end of the project.
Deferred payments as of December 31, 2005 and 2004, totaled
$200.0 million and $152.3 million, respectively, and are reflected in
other long-term accrued liabilities in the accompanying consolidated balance
sheets.
An
asset
representing the other owners’ share of the deferred payments is reflected in
deferred charges and other assets in the accompanying consolidated balance
sheets and totaled $78.7 million and $59.9 million, respectively, as
of December 31, 2005 and 2004. MidAmerican Energy will bill each of the
other owners for its share of the deferred payments when payment is made to
Mitsui.
Air
Quality
MidAmerican
Energy is subject to applicable provisions of the Clean Air Act and related
air
quality standards promulgated by the United States Environmental Protection
Agency (“EPA”). The Clean Air Act provides the framework for regulation of
certain air emissions and permitting and monitoring associated with those
emissions. MidAmerican Energy believes it is in material compliance with current
air quality requirements.
The
EPA
has in recent years implemented more stringent national ambient air quality
standards for ozone and new standards for fine particulate matter. These
standards set the minimum level of air quality that must be met throughout
the
United States. Areas that achieve the standards, as determined by ambient air
quality monitoring, are characterized as being in attainment of the standard.
Areas that fail to meet the standard are designated as being nonattainment
areas. Generally, once an area has been designated as a nonattainment area,
sources of emissions that contribute to the failure to achieve the ambient
air
quality standards are required to make emissions reductions. The EPA has
concluded that the entire state of Iowa, where MidAmerican Energy’s major
emission sources are located, is in attainment of the ozone standards and the
fine particulate matter standards.
On
December 20, 2005, the EPA proposed strengthening the ambient air quality
standard for fine particulates, suggesting a range of prospective new levels
for
fine particulate matter and suggesting maintaining the annual standard at the
current level while reducing the 24-hour standard. The EPA established a 90-day
public comment period on its plan, which closes on April 17, 2006, and
final rules are anticipated to be issued in September 2006.
Until
the public comment period closes and the EPA takes final action on the proposal,
the impact of the proposed rules on MidAmerican Energy cannot be
determined.
On
March 10, 2005, the EPA released the final Clean Air Interstate Rule
(“CAIR”), calling for reductions of sulfur dioxide (“SO2”)
and
nitrogen oxides (“NOx”)
emissions in the eastern United States through, at each state’s option, a
market-based cap and trade system, emission reductions, or both. The state
of
Iowa is implementing rules that exercise the option of the market-based cap
and
trade system. While the state of Iowa has been determined to be in attainment
of
the ozone and fine particulate standards, Iowa has been found to significantly
contribute to nonattainment of the fine particulate standard in Cook County,
Illinois; Lake County, Indiana; Madison County, Illinois; St. Clair County,
Illinois; and Marion County, Indiana. The EPA has also concluded that emissions
from Iowa significantly contribute to ozone nonattainment in Kenosha and
Sheboygan counties in Wisconsin and Macomb County, Michigan. Under the final
CAIR, the first phase reductions of SO2
emissions are effective on January 1, 2010, with the second phase
reductions effective January 1, 2015. For NOx,
the
first phase emissions reductions are effective January 1, 2009, and the
second phase reductions are effective January 1, 2015. The CAIR calls for
overall reductions of SO2
and
NOx
in Iowa
of 68% and 67%, respectively, by 2015. The CAIR will impact the operation of
MidAmerican Energy’s generating facilities and will require MidAmerican Energy
to either reduce emissions from those facilities through the installation of
emission controls or purchase additional emission allowances, or some
combination thereof.
99
On
March 15, 2005, the EPA released the final Clean Air Mercury Rule (“CAMR”).
The CAMR utilizes a market-based cap and trade mechanism to reduce mercury
emissions from coal-burning power plants from the current nationwide level
of
48 tons to 15 tons at full implementation. The CAMR’s two-phase reduction
program requires initial reductions of mercury emission in 2010 and an overall
reduction in mercury emissions from coal-burning power plants of 70% by 2018.
The CAMR will impact MidAmerican Energy’s coal-burning generating facilities and
will require MidAmerican Energy to either reduce emissions from those facilities
through the installation of emission controls or purchase additional emission
allowances, or some combination thereof.
The
CAIR
or the CAMR could, in whole or in part, be superseded or made more stringent
by
one of a number of multi-pollutant emission reduction proposals currently under
consideration at the federal level, including pending legislative proposals
that
contemplate 70% to 90% reductions of SO2, NOX and mercury, as well as possible
new federal regulation of carbon dioxide and other gases that may affect global
climate change. In addition to any federal legislation that could be enacted
by
Congress to supersede the CAIR and the CAMR, the rules could be changed or
overturned as a result of litigation. The sufficiency of the standards
established by both the CAIR and the CAMR has been legally challenged in the
United States District Court for the District of Columbia. Until the court
makes
a determination regarding the merits of the challenges to the CAIR and the
CAMR,
the full impact of the rules on MidAmerican Energy cannot be
determined.
MidAmerican
Energy has implemented a planning process that forecasts the site-specific
controls and actions that may be required to meet emissions reductions as
promulgated by the EPA. In accordance with an Iowa law passed in 2001,
MidAmerican Energy has on file with the IUB its current multi-year plan and
budget for managing SO2 and NOX from its generating facilities in a
cost-effective manner. The plan, which is required to be updated every two
years, provides specific actions to be taken at each coal-fired generating
facility and the related costs and timing for each action. On July 17,2003, the IUB issued an order that affirmed an administrative law judge’s
approval of the initial plan filed on April 1, 2002, as amended. On
October 4, 2004, the IUB issued an order approving MidAmerican Energy’s
second biennial plan as revised in a settlement MidAmerican Energy entered
into
with the OCA. That plan covers the time period from April 1, 2004 through
December 31, 2006. Neither IUB order resulted in any changes to electric
rates for MidAmerican Energy. The effect of the orders is to approve the
prudence of expenditures made consistent with the plans. Pursuant to an
unrelated rate settlement agreement approved by the IUB on October 17,2003, if, prior to January 1, 2011, capital and operating expenditures to
comply with environmental requirements cumulatively exceed $325 million,
then MidAmerican Energy may seek to recover the additional expenditures from
customers.
Under
the
existing New Source Review (“NSR”) provisions of the Clean Air Act, a utility is
required to obtain a permit from the EPA or a state regulatory agency prior
to
(1) beginning construction of a new major stationary source of an NSR-regulated
pollutant or (2) making a physical or operational change to an existing facility
that potentially increases emissions, unless the changes are exempt under the
regulations (including routine maintenance, repair and replacement of
equipment). In general, projects subject to NSR regulations are subject to
pre-construction review and permitting under the Prevention of Significant
Deterioration (“PSD”) provisions of the Clean Air Act. Under the PSD program, a
project that emits threshold levels of regulated pollutants must undergo a
Best
Available Control Technology analysis and evaluate the most effective emissions
controls. These controls must be installed in order to receive a permit.
Violations of NSR regulations, which may be alleged by the EPA, states and
environmental groups, among others, potentially subject a utility to material
expenses for fines and other sanctions and remedies including requiring
installation of enhanced pollution controls and funding supplemental
environmental projects.
In
recent
years, the EPA has requested from several utilities information and supporting
documentation regarding their capital projects for various generating plants.
The requests were issued as part of an industry-wide investigation to assess
compliance with the NSR and the New Source Performance Standards of the Clean
Air Act. In December 2002 and April 2003, MidAmerican Energy received requests
from the EPA to provide documentation related to its capital projects from
January 1, 1980, to April 2003 for a number of its generating plants.
MidAmerican Energy has submitted information to the EPA in responses to these
requests, and there are currently no outstanding data requests pending from
the
EPA. MidAmerican Energy cannot predict the outcome of these requests at this
time.
100
In
2002
and 2003, the EPA proposed various changes to its NSR rules that clarify
what
constitutes routine repair, maintenance and replacement for purposes of
triggering NSR requirements. These changes have been subject to legal challenge
and, until such time as the legal challenges are resolved and the rules are
effective, MidAmerican Energy will continue to manage projects at its generating
plants in accordance with the rules in effect prior to 2002. On June 24,2005, the Washington D.C. Circuit Court upheld portions of the EPA’s 2002 NSR
rule but invalidated other portions. On October 13, 2005, the EPA proposed
a rule that would change or clarify how emission increases are to be calculated
for purposes of determining the applicability of the NSR permitting program
for
modifications to existing power plants and opened a public comment period,
which
ended on February 17, 2006. The impact of these proposed changes on
MidAmerican Energy cannot be determined until after the rule is finalized
and
implemented.
Nuclear
Decommissioning Costs
Expected
nuclear decommissioning costs for Quad Cities Station have been developed based
on a site-specific decommissioning study that includes decontamination,
dismantling, site restoration, dry fuel storage cost and an assumed shutdown
date. Quad Cities Station nuclear decommissioning costs are included in base
rates in Iowa tariffs.
MidAmerican
Energy’s share of estimated decommissioning costs for Quad Cities Station as of
December 31, 2005, was $163.0 million and is the ARO liability for
Quad Cities Station. MidAmerican Energy has established trusts for the
investment of funds for decommissioning the Quad Cities Station. The fair value
of the assets held in the trusts was $228.1 million at December 31,2005 and is reflected in other investments in the accompanying consolidated
balance sheets.
Nuclear
Insurance
MidAmerican
Energy maintains financial protection against catastrophic loss associated
with
its interest in Quad Cities Station through a combination of insurance purchased
by Exelon Generation Company, LLC (“Exelon Generation”) (the operator and joint
owner of Quad Cities Station), insurance purchased directly by MidAmerican
Energy, and the mandatory industry-wide loss funding mechanism afforded under
the Price-Anderson Amendments Act of 1988, which was amended and extended by
the
Energy Policy Act. The general types of coverage are: nuclear liability,
property coverage and nuclear worker liability.
Exelon
Generation purchases private market nuclear liability insurance for Quad Cities
Station in the maximum available amount of $300.0 million, which includes
coverage for MidAmerican Energy’s ownership. In accordance with the
Price-Anderson Amendments Act of 1988, as amended and extended by the Energy
Policy Act, excess liability protection above that amount is provided by a
mandatory industry-wide Secondary Financial Protection program under which
the
licensees of nuclear generating facilities could be assessed for liability
incurred due to a serious nuclear incident at any commercial nuclear reactor
in
the United States. Currently, MidAmerican Energy’s aggregate maximum potential
share of an assessment for Quad Cities Station is approximately
$50.3 million per incident, payable in installments not to exceed
$7.5 million annually.
The
property insurance covers property damage, stabilization and decontamination
of
the facility, disposal of the decontaminated material and premature
decommissioning arising out of a covered loss. For Quad Cities Station, Exelon
Generation purchases primary and excess property insurance protection for the
combined interests in Quad Cities Station, with coverage limits totaling
$2.1 billion. MidAmerican Energy also directly purchases extra expense
coverage for its share of replacement power and other extra expenses in the
event of a covered accidental outage at Quad Cities Station. The property and
related coverages purchased directly by MidAmerican Energy and by Exelon
Generation, which includes the interests of MidAmerican Energy, are underwritten
by an industry mutual insurance company and contain provisions for retrospective
premium assessments should two or more full policy-limit losses occur in one
policy year. Currently, the maximum retrospective amounts that could be assessed
against MidAmerican Energy from industry mutual policies for its obligations
associated with Quad Cities Station total $9.0 million.
The
master nuclear worker liability coverage, which is purchased by Exelon
Generation for Quad Cities Station, is an industry-wide guaranteed-cost policy
with an aggregate limit of $300 million for the nuclear industry as a
whole, which is in effect to cover tort claims of workers in nuclear-related
industries.
101
Legal
Matters
In
addition to the proceedings described below, the Company is currently party
to
various items of litigation or arbitration in the normal course of business,
none of which are reasonably expected by the Company to have a material adverse
effect on its financial position, results of operations or cash
flows.
CalEnergy
Generation-Foreign
Pursuant
to the share ownership adjustment mechanism in the CE Casecnan stockholder
agreement, which is based upon pro forma financial projections of the Casecnan
project prepared following commencement of commercial operations, in February
2002, MEHC’s indirect wholly-owned subsidiary, CE Casecnan Ltd., advised the
minority stockholder of CE Casecnan, LaPrairie Group Contractors
(International) Ltd. (“LPG”), that MEHC’s indirect ownership interest in
CE Casecnan had increased to 100% effective from commencement of commercial
operations. On July 8, 2002, LPG filed a complaint in the Superior Court of
the State of California, City and County of San Francisco against
CE Casecnan Ltd., KEIL Casecnan Ltd. (“KE”), a former stockholder, and
MEHC. LPG’s complaint, as amended, seeks compensatory and punitive damages
arising out of CE Casecnan Ltd.’s and MEHC’s alleged improper calculation
of the proforma financial projections On January 21, 2004, CE Casecnan
Ltd., LPG and CE Casecnan entered into a status quo agreement pursuant to which
the parties agreed to set aside certain distributions related to the shares
subject to the LPG dispute and CE Casecnan agreed not to take any further
actions with respect to such distributions without at least 15 days prior notice
to LPG. Accordingly, 15% of the CE Casecnan dividend distributions declared
in
2004 and 2005, totaling $17.6 million, was set aside in a separate bank
account in the name of CE Casecnan and is shown as restricted cash and
short-term investments and other current liabilities in the accompanying
consolidated balance sheets.
On
August 4, 2005, the court issued a decision, ruling in favor of LPG on five
of the eight disputed issues in the first phase of the litigation. On
September 12, 2005, LPG filed a motion seeking the release of the funds
which have been set aside pursuant to the status quo agreement referred to
above. MEHC and CE Casecnan Ltd. filed an opposition to the motion on October3,2005, and at the hearing on October 26, 2005, the court denied LPG’s
motion. On January 3, 2006, the court entered a judgment in favor of LPG
against CE Casecnan Ltd. and KE. According to the judgment LPG would retain
its
ownership of 15% of the shares of CE Casecnan and distributions of the amounts
deposited into escrow plus interest at 9% per annum. On February 28, 2006,
CE Casecnan Ltd. and KE filed an appeal of this judgment and the August 4,2005
decision. The appeal is expected to be resolved sometime in 2007. The impact,
if
any, of this litigation on the Company cannot be determined at this
time.
In
February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. (“San
Lorenzo”), an original shareholder substantially all of whose shares in CE
Casecnan were purchased by MEHC in 1998, threatened to initiate legal action
against the Company in the Philippines in connection with certain aspects of
its
option to repurchase such shares. On July 1, 2005, MEHC and
CE Casecnan Ltd. commenced an action against San Lorenzo in the
District Court of Douglas County, Nebraska, seeking a declaratory judgment
as to
MEHC’s and CE Casecnan Ltd.'s rights vis-à-vis San Lorenzo in respect of such
shares. San Lorenzo filed a motion to dismiss on September 19, 2005.
The motion was heard on October 21, 2005, and the court took the matter
under advisement. Subsequently, San Lorenzo purported to exercise its option
to
repurchase such shares. On January 30, 2006, San Lorenzo filed a
counterclaim against MEHC and CE Casecnan Ltd. seeking declaratory relief that
it has effectively exercised its option to purchase 15% of the shares of CE
Casecnan, that it is the rightful owner of such shares, and that it is due
all
dividends paid on such shares. The impact, if any, of San Lorenzo’s purported
exercise of its option and the Nebraska litigation on the Company cannot be
determined at this time. The Company intends to vigorously defend the
counterclaims.
21.
Pension
and Postretirement
Commitments
Domestic
Operations
MidAmerican
Energy sponsors a noncontributory defined benefit pension plan covering
substantially all employees of MEHC and its domestic energy subsidiaries.
Benefit obligations under the plan are based on a cash balance arrangement
for
salaried employees and certain union employees and final average pay formulas
for most union employees. Funding to the established trust is based upon the
actuarially determined costs of the plan and the requirements of the Internal
Revenue Code and the Employee Retirement Income Security Act. The Company also
maintains noncontributory, nonqualified defined benefit supplemental executive
retirement plans for active and retired participants.
102
MidAmerican
Energy also sponsors certain postretirement health care and life insurance
benefits covering substantially all retired employees of MEHC and its domestic
energy subsidiaries. Under the plans, covered employees may become eligible
for
these benefits if they reach retirement age while working for the Company.
On
July 1, 2004, the postretirement benefit plan was amended for non-union
participants. As a result, non-union employees hired July 1, 2004, and
after are no longer eligible for postretirement benefits other than pensions.
The plan, as amended, establishes retiree medical accounts for participants
to
which the Company makes fixed contributions until the employee’s retirement.
Participants will use such accounts to pay a portion of their medical premiums
during retirement. The Company retains the right to change these benefits
anytime, subject to provisions in its collective bargaining
agreements.
For
purposes of calculating the expected return on pension plan assets, a
market-related value is used. Market-related value is equal to fair value except
for gains and losses on equity investments which are amortized into
market-related value on a straight-line basis over five years. Net periodic
pension benefit cost, including supplemental retirement, and postretirement
benefit cost included the following components for MEHC and its domestic energy
subsidiaries for the years ended December 31:
Pension
Cost
Postretirement
Cost
2005
2004
2003
2005
2004
2003
(in
thousands)
Service
cost
$
25,840
$
25,568
$
24,693
$
6,669
$
7,842
$
8,175
Interest
cost
36,518
35,159
34,533
13,455
15,716
16,065
Expected
return on plan assets
(38,188
)
(38,258
)
(38,396
)
(9,611
)
(8,437
)
(6,008
)
Amortization
of net transition obligation
-
(792
)
(2,591
)
2,403
3,283
4,110
Amortization
of prior service cost
2,766
2,758
2,761
-
296
593
Amortization
of prior year (gain) loss
1,271
1,569
1,483
1,554
3,299
3,716
Regulatory
expense
-
-
3,320
-
-
-
Net
periodic benefit cost
$
28,207
$
26,004
$
25,803
$
14,470
$
21,999
$
26,651
Weighted-average
assumptions used to determine benefit obligations at December 31:
2005
2004
2003
2005
2004
2003
Discount
rate
5.75%
5.75%
5.75%
5.75%
5.75%
5.75%
Rate
of compensation increase
5.00%
5.00%
5.00%
Not
applicable
Weighted-average
assumptions used to determine net benefit cost for the years ended December
31:
2005
2004
2003
2005
2004
2003
Discount
rate
5.75%
5.75%
5.75%
5.75%
5.75%
5.75%
Expected
return on plan assets
7.00%
7.00%
7.00%
7.00%
7.00%
7.00%
Rate
of compensation increase
5.00%
5.00%
5.00%
Not
applicable
Assumed
health care cost trend rates at December 31:
2005
2004
Health
care cost trend rate assumed for next year
9.00%
10.00%
Rate
that the cost trend rate gradually declines to
5.00%
5.00%
Year
that the rate reaches the rate it is assumed to remain at
2010
2010
103
Assumed
health care cost trend rates have a significant effect on the amounts reported
for the health care plans. A one-percentage-point change in assumed health
care
cost trend rates would have the following effects (in thousands):
Increase
(Decrease) in Expense
One
Percentage-
One
Percentage-
Point
Increase
Point
Decrease
Effect
on total service and interest cost
$
2,418
$
(1,891
)
Effect
on postretirement benefit obligation
$
26,434
$
(21,350
)
The
following table presents a reconciliation of the beginning and ending balances
of the benefit obligation, fair value of plan assets and the funded status
of
the aforementioned plans to the net amounts measured and recognized in the
accompanying consolidated balance sheets as of December 31 (in
thousands):
Pension
Benefits
Postretirement
Benefits
2005
2004
2005
2004
Reconciliation
of the fair value of plan assets:
Fair
value of plan assets at beginning of year
$
591,628
$
551,568
$
179,375
$
157,849
Employer
contributions
5,786
5,083
16,615
23,782
Participant
contributions
-
-
9,096
7,733
Actual
return on plan assets
46,966
63,151
5,958
9,698
Benefits
paid
(31,551
)
(28,174
)
(20,144
)
(19,687
)
Fair
value of plan assets at end of year
612,829
591,628
190,900
179,375
Reconciliation
of benefit obligation:
Benefit
obligation at beginning of year
657,406
620,048
256,044
297,433
Service
cost
25,840
25,568
6,669
7,841
Interest
cost
36,518
35,159
13,455
15,716
Participant
contributions
-
-
9,096
7,733
Plan
amendments
(3,184
)
-
(421
)
(19,219
)
Actuarial
(gain) loss
(6,917
)
4,805
(15,141
)
(33,773
)
Benefits
paid
(31,551
)
(28,174
)
(20,144
)
(19,687
)
Benefit
obligation at end of year
678,112
657,406
249,558
256,044
Funded
status
(65,283
)
(65,778
)
(58,658
)
(76,669
)
Amounts
not recognized in consolidated balance sheets:
Unrecognized
net (gain) loss
(51,285
)
(34,319
)
29,725
42,768
Unrecognized
prior service cost
9,207
15,157
-
-
Unrecognized
net transition obligation (asset)
-
-
16,820
19,641
Net
amount recognized in the consolidated balance sheets
$
(107,361
)
$
(84,940
)
$
(12,113
)
$
(14,260
)
Net
amount recognized in the consolidated balandce sheets consists
of:
Accrued
benefit liability
$
(135,506
)
$
(117,357
)
$
(12,113
)
$
(14,260
)
Intangible
assets
11,939
14,653
-
-
Regulatory
assets
11,694
17,764
-
-
Accumulated
other comprehensive income
4,512
-
-
-
Net
amount recognized
$
(107,361
)
$
(84,940
)
$
(12,113
)
$
(14,260
)
The
portion of the pension projected benefit obligation, included in the table
above, related to the supplemental executive retirement plan was
$105.7 million and $106.5 million as of December 31, 2005 and
2004, respectively. The supplemental executive retirement plan has no assets,
and accordingly, the fair value of its plan assets was zero as of
December 31, 2005 and 2004. The accumulated benefit obligation for all
defined benefit pension plans was $608.4 million and $585.4 million at
December 31, 2005 and 2004, respectively. Of these amounts, the
supplemental executive retirement plan accumulated benefit obligation totaled
$102.2 million and $102.3 million for 2005 and 2004,
respectively.
104
Although
the supplemental executive retirement plan had no assets as of December 31,2005, the Company has Rabbi trusts that hold corporate-owned life insurance
and
other investments to provide funding for the future cash requirements. Because
this plan is nonqualified, the assets in the Rabbi trusts are not considered
plan assets. The cash surrender value of the policies included in the Rabbi
trusts plus the fair market value of other Rabbi trust investments was
$102.9 million and $98.8 million at December 31, 2005 and 2004,
respectively.
Plan
Assets
The
Company’s investment policy for its domestic pension and postretirement plans is
to balance risk and return through a diversified portfolio of high-quality
equity and fixed income securities. Equity targets for the pension and
postretirement plans are as indicated in the tables below. Maturities for fixed
income securities are managed to targets consistent with prudent risk
tolerances. Sufficient liquidity is maintained to meet near-term benefit payment
obligations. The plans retain outside investment advisors to manage plan
investments within the parameters outlined by the Company’s Pension and Employee
Benefits Plans Administrative Committee. The weighted average return on assets
assumption is based on historical performance for the types of assets in which
the plans invest.
The
Company’s pension plan asset allocations at December 31, 2005 and 2004 are
as follows:
Percentage
of
Plan
Assets
at
December 31
Target
2005
2004
Range
Asset
Category
Equity
securities
66%
71%
65-75%
Debt
securities
26%
22%
20-30%
Real
estate
6%
6%
0-10%
Other
2%
1%
0-5%
Total
100%
100%
The
Company’s postretirement benefit plan asset allocations at December 31,2005 and 2004 are as follows:
Percentage
of
Plan
Assets
at
December 31
Target
2005
2004
Range
Asset
Category
Equity
securities
50%
49%
45-55%
Debt
securities
48%
47%
45-55%
Other
2%
4%
0-10%
Total
100%
100%
Cash
Flows
The
Company’s expected benefit payments to participants for its pension and
postretirement plans for 2006 through 2010 and for the five years thereafter
are
summarized below (in thousands):
Postretirement
Benefits
Pension
Benefits
Gross
Medicare
Subsidy
Net
of Subsidy
2006
$
32,545
$
14,054
$
2,350
$
11,704
2007
34,771
15,336
2,533
12,803
2008
37,347
16,434
2,719
13,715
2009
41,125
17,419
2,888
14,531
2010
45,030
18,525
3,032
15,493
2011-2015
275,118
107,131
17,728
89,403
105
Employer
contributions to the domestic pension and postretirement plans are currently
expected to be $6.7 million and $14.5 million, respectively, for 2006.
The Company’s policy is to contribute the minimum required amount to the pension
plan and the amount expensed to its postretirement plans.
The
Company sponsors defined contribution pension plans (401(k) plans) covering
substantially all domestic employees. The Company’s contributions vary depending
on the plan but are based primarily on each participant’s level of contribution
and cannot exceed the maximum allowable for tax purposes. The Company’s total
contributions were $17.3 million, $17.1 million and $15.5 million
for 2005, 2004 and 2003, respectively.
In
December 2003, the President signed into law the Medicare Prescription Drug,
Improvement and Modernization Act of 2003 (“Medicare Act”). The Medicare Act
introduces a prescription drug benefit under Medicare as well as a subsidy
to
sponsors of retiree health care plans that provide a benefit to participants
that is at least actuarially equivalent to Medicare Part D. Detailed regulations
pertaining to the Medicare Act were promulgated in 2004 resulting in a $23.8
million subsidy to the Company to be used for any valid business purpose. The
subsidy is reflected as an actuarial gain in benefit obligation in 2004 in
the
table above. The impact of the Medicare Act on the net periodic postretirement
benefit expense is reflected in 2005.
United
Kingdom Operations
Certain
wholly-owned subsidiaries of CE Electric UK participate in the Northern Electric
group of the United Kingdom industry-wide Electricity Supply Pension Scheme
(the
“UK Plan”), which provides pension and other related defined benefits, based on
final pensionable pay, to substantially all employees of CE Electric UK’s
certain wholly-owned subsidiaries.
For
purposes of calculating the expected return on pension plan assets, a
market-related value is used. Market-related value is equal to fair value except
for gains and losses on equity investments which are amortized into
market-related value on a straight-line basis over five years. Net periodic
pension benefit cost included the following components for CE Electric UK for
the years ended December 31:
2005
2004
2003
Service
cost
$
15,292
$
12,100
$
9,485
Interest
cost
76,460
73,515
62,632
Expected
return on plan assets
(96,849
)
(98,448
)
(89,124
)
Amortization
of prior service cost
1,890
1,915
1,472
Amortization
of loss
22,761
12,742
537
Net
periodic expense (benefit)
$
19,554
$
1,824
$
(14,998
)
Weighted-average
assumptions used to determine benefit obligations at
December 31:
2005
2004
2003
Discount
rate
4.75%
5.25%
5.50%
Rate
of compensation increase
2.75%
2.75%
2.75%
Weighted-average
assumptions used to determine net benefit cost for years ended
December 31:
2005
2004
2003
Discount
rate
5.25%
5.50%
5.75%
Expected
return on plan assets
7.00%
7.00%
7.00%
Rate
of compensation increase
2.75%
2.75%
2.50%
106
The
following table presents a reconciliation of the beginning and ending balances
of the benefit obligation, fair value of plan assets and the funded status
of
the UK Plan to the net amounts measured and recognized in the accompanying
consolidated balance sheets as of December 31 (in thousands):
2005
2004
Reconciliation
of the fair value of plan assets:
Fair
value of plan assets at beginning of year
$
1,364,722
$
1,206,216
Employer
contributions
55,663
17,600
Participant
contributions
6,190
6,417
Actual
return on plan assets
211,723
106,515
Benefits
paid
(67,176
)
(65,265
)
Foreign
currency exchange rate changes
(151,559
)
93,239
Fair
value of plan assets at end of year
1,419,563
1,364,722
Reconciliation
of benefit obligation:
Benefit
obligation at beginning of year
1,571,579
1,334,587
Service
cost
15,292
12,100
Interest
cost
76,460
73,515
Participant
contributions
6,190
6,417
Benefits
paid
(67,176
)
(65,265
)
Experience
loss and change of assumptions
127,617
104,315
Foreign
currency exchange rate changes
(170,645
)
105,910
Benefit
obligation at end of year
1,559,317
1,571,579
Funded
status
(139,754
)
(206,857
)
Unrecognized
net loss
561,050
614,182
Net
amount recognized in the consolidated balance sheets
$
421,296
$
407,325
Amounts
recognized in the consolidated balance sheets consist of:
Prepaid
benefit cost
$
421,296
$
407,325
Accrued
benefit liability
(492,550
)
(561,988
)
Intangible
assets
12,908
16,119
Accumulated
other comprehensive income
479,642
545,869
Net
amount recognized
$
421,296
$
407,325
The
accumulated benefit obligation for the defined benefit pension plan was
$1.5 billion at December 31, 2005 and 2004, respectively.
The
Company recorded a minimum pension liability as of December 31, 2005 and
2004 in the amount of $479.6 million and $545.9 million, respectively.
The pension liability is primarily due to the decline in market value of the
pension plan assets during 2002 combined with the effects of lower discount
rates and higher rates of compensation increases used to value the plan’s
liabilities in 2005 and 2004, as well as, mortality assumption changes which
increased the liability. As of December 31, 2005 and 2004, the minimum
pension liability is measured as the amount of the plan’s accumulated benefit
obligation that is in excess of the plan’s market value of assets at
December 31, 2005 and 2004 plus the prepaid asset balance. A charge equal
to the excess was recorded to the Company’s stockholders’ equity, net of income
tax benefits, as a component of comprehensive loss in the amount of
$(46.4) million and $46.4 million in 2005 and 2004, respectively. This
adjustment does not impact current year earnings, or the funding requirements
of
the plan.
Plan
Assets
CE
Electric UK’s investment policy for its pension and postretirement plans is to
balance risk and return through a diversified portfolio of high-quality equity
and fixed income securities. Maturities for fixed income securities are managed
such that sufficient liquidity exists to meet near-term benefit payment
obligations. The plans retain outside investment advisors to manage plan
investments within the parameters outlined by the Benefits Committee of
subsidiaries of CE Electric UK. The weighted average return on assets assumption
is based on historical performance for the types of assets in which the plans
invest.
107
CE
Electric UK’s pension plan asset allocation consists of the following at
December 31:
Percentage
of
Plan
Assets
at
December 31,
2005
2004
Target
Asset
Category
Equity
securities
51%
49%
50%
Debt
securities
37%
39%
40%
Real
estate
11%
11%
10%
Other
1%
1%
-%
Total
100%
100%
100%
Cash
Flows
CE
Electric UK's expected benefit payments relative to the UK Plan for 2006 through
2010 and for the five years thereafter are summarized below (in
millions):
2006
$
66.2
2007
67.1
2008
67.7
2009
70.2
2010
70.7
2011-2015
378.9
The
triennial process of valuing the UK Plan's assets and liabilities, which valued
the plan assets and liabilities as of March 31, 2004, was completed in
2005. This valuation set a revised level of contributions for the next three
years. The report of the actuaries conducting the valuation showed a funding
deficiency of £190.3 million. Based on this valuation, CE Electric UK will
contribute £23.1 million to the UK Plan each year in respect of the
existing funding deficiency. The amount in respect of the funding deficiency
has
been calculated based on eliminating the funding deficiency over 12 years
commencing April 1, 2005. Employer contributions to the UK Plan for the
year ended December 31, 2005 totaled $55.7 million and consisted of
$24.6 million to fund ongoing liabilities and $31.1 million in respect
of the existing funding deficiency. Employer contributions to the UK Plan,
including the £23.1 million deficiency funding, are currently expected to
be £35.0 million for 2006.
108
22.
Segment
Information
The
Company has identified seven reportable segments: MidAmerican Energy, Kern
River, Northern Natural Gas, CE Electric UK, CalEnergy Generation-Foreign,
CalEnergy Generation-Domestic and HomeServices. The Company’s determination of
reportable segments considers the strategic units under which the Company is
managed. The Company’s foreign reportable segments include CE Electric UK, whose
business is principally in Great Britain, and CalEnergy Generation-Foreign,
whose business is in the Philippines. The reportable segment financial
information includes all necessary adjustments and eliminations needed to
conform to the Company’s significant accounting policies including the
allocation of goodwill. Additionally, the activity of the Company’s Mineral
Assets, which was previously reported in the CalEnergy Generation-Domestic
reportable segment, is presented as discontinued operations within the
accompanying consolidated financial statements. Information related to the
Company’s reportable segments is shown below (in thousands):
The
remaining differences between the segment amounts and the consolidated
amounts described as “Corporate/other” relate principally to intersegment
eliminations for operating revenue and, for the other items presented,
to
(i) corporate functions, including administrative costs, interest
expense,
corporate cash and related interest income, (ii) intersegment eliminations
and (iii) fair value adjustments relating to
acquisitions.
(2)
The
Company adopted and applied the provisions of FIN 46R, related to
certain
finance subsidiaries, as of October 1, 2003. The adoption required
the deconsolidation of certain finance subsidiaries, which resulted
in
amounts that were previously recorded as minority interest and preferred
dividends of subsidiaries being prospectively recorded as interest
expense
in the accompanying consolidated statements of operations. For the
years
ended December 31, 2005 and 2004, and the three-month period ended
December 31, 2003, the Company has recorded $184.4 million,
$196.9 million and $49.8 million, respectively, of interest
expense related to these securities. In accordance with the requirements
of FIN 46R, no amounts prior to adoption of FIN 46R on October 1,2003 have been reclassified. The amount included in minority interest
and
preferred dividends of subsidiaries related to these securities for
the
nine-month period ended September 30, 2003 was
$170.2 million.
111
The
following table shows the change in the carrying amount of goodwill by
reportable segment for the years ended December 31, 2005 and 2004 (in
thousands):
An
evaluation was performed under the supervision and with the participation of
the
Company’s management, including the chief executive officer and chief financial
officer, regarding the effectiveness of the design and operation of the
Company’s disclosure controls and procedures (as defined in Rule 13a-15(e)
promulgated under the Securities and Exchange Act of 1934, as amended) as of
December 31, 2005. Based on that evaluation, the Company’s management,
including the chief executive officer and chief financial officer, concluded
that the Company’s disclosure controls and procedures were effective. There have
been no changes during the fourth quarter of 2005 in the Company’s internal
control over financial reporting that has materially affected, or is reasonably
likely to materially affect, the Company’s internal control over financial
reporting.
On
March 1, 2006, MEHC and Berkshire Hathaway entered into the Berkshire
Equity Commitment pursuant to which Berkshire Hathaway has agreed to purchase
up
to $3.5 billion of common equity of MEHC upon any requests authorized from
time to time by the Board of Directors of MEHC. The proceeds of any such equity
contribution shall only be used for the purpose of (a) paying when due MEHC’s
debt obligations and (b) funding the general corporate purposes and capital
requirements of the Company’s regulated subsidiaries. Berkshire Hathaway will
have up to 180 days to fund any such request. The Berkshire Equity Commitment
will expire on February 28, 2011, and will not be used for the PacifiCorp
acquisition or for other future acquisitions.
Effective
March 1, 2006, Messrs. W. David Scott, Edgar D. Aronson, John K. Boyer,
Stanley J. Bright and Richard R. Jaros resigned from the Board of Directors
of
MEHC. Mr. Jaros was a member of MEHC’s Audit Committee.
On
November 16, 2005, MEHC issued 200,000 shares of its common stock, no par
value, to Mr. David L. Sokol, its Chairman and Chief Executive Officer, upon
the
exercise by Mr. Sokol of 200,000 of his outstanding common stock options. The
common stock options were exercisable at a price of $29.01 per share and the
aggregate exercise price paid by Mr. Sokol was $5.8 million. The issuance
was pursuant to a private placement and was exempt from the registration
requirements of the Securities Act of 1933, as amended.
113
PART
III
Item
10.Directors
and Executive Officers of the
Registrant.
MEHC’s
management structure is organized functionally and the current executive
officers and directors of MEHC and their positions are as follows:
Name
Position
David
L. Sokol
Chairman
of the Board of Directors and Chief Executive Officer
Gregory
E. Abel
President,
Chief Operating Officer and Director
Patrick
J. Goodman
Senior
Vice President and Chief Financial Officer
Douglas
L. Anderson
Senior
Vice President, General Counsel and Corporate Secretary
Maureen
E. Sammon
Senior
Vice President, Human Resources, Information Technology and
Insurance
Keith
D. Hartje
Senior
Vice President, Communications, General Services and Safety Audit
and
Compliance
Warren
E. Buffett
Director
Walter
Scott Jr.
Director
Marc
D. Hamburg
Director
Officers
are elected annually by the Board of Directors. There are no family
relationships among the executive officers, nor any arrangements or
understanding between any officer and any other person pursuant to which the
officer was appointed.
Set
forth
below is certain information, as of March 1, 2006, with respect to each of
the foregoing officers and directors:
DAVID
L.
SOKOL, 49, Chairman of the Board of Directors and Chief Executive Officer.
Mr. Sokol has been the Chief Executive Officer since April 19, 1993
and served as President of MEHC from April 19, 1993 until January 21,1995. Mr. Sokol has been Chairman of the Board of Directors since May 1994
and a director since March 1991. Formerly, among other positions held in the
independent power industry, Mr. Sokol served as President and Chief Executive
Officer of Kiewit Energy Company, which at that time was a wholly owned
subsidiary of Peter Kiewit & Sons’, Inc., and Ogden Projects,
Inc.
GREGORY
E. ABEL, 43, President, Chief Operating Officer and Director. Mr. Abel joined
MEHC in 1992 and initially served as Vice President and Controller.
Mr. Abel is a Chartered Accountant and from 1984 to 1992 was employed by
PricewaterhouseCoopers. As a Manager in the San Francisco office of
PricewaterhouseCoopers, he was responsible for clients in the energy
industry.
PATRICK
J. GOODMAN, 39, Senior Vice President and Chief Financial Officer.
Mr. Goodman joined MEHC in 1995 and has served in various financial
positions including Chief Accounting Officer. Prior to joining MEHC, Mr. Goodman
was a financial manager for National Indemnity Company and a senior associate
at
PricewaterhouseCoopers.
DOUGLAS
L. ANDERSON, 47, Senior Vice President, General Counsel and Corporate Secretary.
Mr. Anderson joined MEHC in February 1993 and has served in various legal
positions including General Counsel of the Company’s independent power
affiliates. Prior to that, Mr. Anderson was a corporate attorney in private
practice.
MAUREEN
E. SAMMON, 42, Senior Vice President, Human Resources, Information Technology
and Insurance. Ms. Sammon has been with MidAmerican Energy and its predecessor
companies since 1986. In that time, she has held several positions, including
Manager of Benefits and Vice President, Human Resources and
Insurance.
KEITH
D.
HARTJE, 56, Senior Vice President, Communications, General Services and Safety
Audit and Compliance. Mr. Hartje has been with MidAmerican Energy and its
predecessor companies since 1973. In that time, he has held a number of
positions, including General Counsel and Corporate Secretary, District Vice
President for southwest Iowa operations, and Vice President, Corporate
Communications.
WARREN
E.
BUFFETT, 75, Director. Mr. Buffett has been a director of MEHC since March
2000. He is Chairman of the Board and Chief Executive Office of Berkshire
Hathaway. Mr. Buffett is a Director of the Coca Cola Company and The
Washington Post Company.
114
WALTER
SCOTT, JR., 74, Director. Mr. Scott has been a director of MEHC since June
1991. Mr. Scott was the Chairman and Chief Executive Officer of MEHC from
January 8, 1992 until April 19, 1993. For more than five years, he has
been Chairman of the Board of Directors of Level 3 Communications, Inc., a
successor to certain businesses of Peter Kiewit & Sons’, Inc. Mr. Scott
is a director of Peter Kiewit & Sons’, Inc., Berkshire Hathaway, Burlington
Resources, Inc., Valmont Industries, Inc. and Commonwealth Telephone
Enterprises, Inc.
MARC
D.
HAMBURG, 56, Director. Mr. Hamburg has been a director of MEHC since March
2000. He has served as Vice President - Chief Financial Officer of Berkshire
Hathaway since October 1, 1992 and Treasurer since June 1, 1987, his
date of employment with Berkshire Hathaway.
Audit
Committee Members and Financial Experts
The
audit
committee of the Board of Directors is comprised of Mr. Marc D. Hamburg.
The Board of Directors has determined that Mr. Hamburg qualifies as an
“audit committee financial expert,” as defined by SEC Rules, based on his
education, experience and background. Mr. Hamburg is not independent within
the
meaning of Item 7(d)(3)(iv) of Schedule 14A under the Exchange Act.
Code
of Ethics
MEHC
has
adopted a code of ethics that applies to its principal executive officer, its
principal financial officer, its chief accounting officer and certain other
covered officers. The code of ethics is filed as an exhibit to this annual
report on Form 10-K.
The
following table sets forth the compensation of MEHC’s Chief Executive Officer
and its four other most highly compensated executive officers who were employed
as of December 31, 2005, which MEHC refers to as its Named Executive
Officers. Information is provided regarding its Named Executive Officers for
the
last three fiscal years during which they were its executive officers, if
applicable.
Name
and Principal Positions
Year
Ended
Dec.
31
Salary
(1)
Bonus
(1)
Other
Annual
Comp(2)
LTIP
Payouts
All
Other
Comp(3)
David
L. Sokol
2005
$
850,000
$
13,750,000
$
103,929
$
-
$
10,290
Chairman
and Chief
2004
800,000
2,500,000
131,644
-
9,995
Executive
Officer
2003
800,000
2,750,000
141,501
-
9,800
Gregory
E. Abel
2005
740,000
13,450,000
-
-
10,290
President
and
2004
720,000
2,200,000
80,424
-
9,995
Chief
Operating Officer
2003
700,000
2,200,000
87,162
-
9,800
Patrick
J. Goodman
2005
297,500
325,000
-
107,212
67,269
Senior
Vice President and
2004
290,000
295,000
-
257,694
88,391
Chief
Financial Officer
2003
275,000
285,000
-
-
108,631
Douglas
L. Anderson
2005
275,000
265,000
-
87,769
60,456
Senior
Vice President and
2004
270,000
240,000
-
151,585
77,145
General
Counsel
2003
260,000
240,000
-
-
83,703
Maureen
E. Sammon
2005
175,000
110,000
-
-
39,397
Senior
Vice President, Human Resources,
2004
165,000
80,000
-
-
42,236
Information
Technology and Insurance
2003
147,500
65,000
-
-
35,223
115
______________
(1)
Includes
amounts voluntarily deferred by the executive, if applicable. Pursuant
to
MEHC’s Executive Incremental Profit Sharing Plan, Messrs. Sokol and
Abel each received a profit sharing award of $11.25 million based
upon achieving the specified adjusted diluted earnings per share
target
for the year ended December 31, 2005. Messrs. Sokol and Abel are
each eligible to receive additional profit sharing awards of
$7.5 million or $26.25 million based upon achieving specified
adjusted diluted earnings per share targets for any calendar year
2006 and
2007. In 2005, Messrs. Goodman and Anderson and Ms. Sammon each received
a
performance award related to the pending acquisition of
PacifiCorp.
(2)
Consists
of perquisites and other benefits if the aggregate amount of such
benefits
exceeds the lesser of either $50,000 or 10% of the total of salary
and
bonus reported for the Named Executive Officer. The amounts shown
include
the personal use of aircraft for 2005 for Mr. Sokol of
$76,811.
(3)
Consists
of the 2005 earnings on the MEHC Long-Term Incentive Partnership
Plan
(“LTIP”) awards not paid out in 2005 and 401(k) plan contributions. For
2005, LTIP earnings on awards not paid out in 2005 were $56,979 for
Mr. Goodman, $50,166 for Mr. Anderson and $29,457 for Ms.
Sammon. Messrs. Sokol and Abel are not participants in the LTIP.
Additionally, the amounts shown include company 401(k) contributions
for
2005 for Messrs. Sokol, Abel, Goodman and Anderson of $10,290 and for
Ms. Sammon of $9,940.
Option
Grants in Last Fiscal Year
MEHC
did
not grant any options during 2005.
Aggregated
Option Exercises in Last Fiscal Year and Fiscal Year End Option
Values
The
following table sets forth the option exercises and the number of securities
underlying exercisable and unexercisable options held by each of its Named
Executive Officers at December 31, 2005.
Shares
Acquired
Value
Underlying
Unexercised
Value
of Unexercised
On
Exercise
Realized
Options
Held (#)
In-the-money
Options ($) (1)
Name
(#)
($)
Exercisable
Unexercisable
Exercisable
Unexercisable
David
Sokol
200,000
$
16,798,740
1,199,277
-
$
134,652,051
N/A
Gregory
E. Abel
-
-
649,052
-
$
76,518,336
N/A
Patrick
J. Goodman
-
-
-
-
-
-
Douglas
L. Anderson
-
-
-
-
-
-
Maureen
E. Sammon
-
-
-
-
-
-
______________
(1)
On
March 14, 2000, MEHC was acquired by a private investor group and on
February 9, 2006, became a majority-owned subsidiary of Berkshire
Hathaway. As a privately held company, MEHC has no publicly traded
equity
securities. The value shown is based on an assumed fair market value
of
the common stock of $145 per share as of December 31, 2005, as agreed
to by MEHC stockholders.
116
Long-Term
Incentive Plans - Awards in Last Fiscal Year
The
awards shown in the foregoing table are made pursuant to the LTIP.
The
amounts shown are dollar amounts credited to an investment account
for the
benefit of the named executive officers and such amounts vest equally
over
five years (starting with year 2005) with any unvested balances forfeited
upon termination of employment. Vested balances (including any investment
performance profits or losses thereon) are paid to the participant
at the
time of termination. Once an award is fully vested, the participant
may
elect to defer or receive payment of part or the entire award. Awards
are
credited or reduced with annual interest or loss based on a composite
of
funds or indices. Because the amounts to be paid out may increase
or
decrease depending on investment performance, the ultimate benefits
are
undeterminable and the payouts do not have a “target” or “maximum”
amount.
Compensation
of Directors
Directors
are not paid any fees for serving as directors. All directors are reimbursed
for
their expenses incurred in attending Board meetings.
Retirement
Plans
The
MidAmerican Energy Company Supplemental Retirement Plan for Designated Officers
(the “SERP”), provides additional retirement benefits to designated
participants, as determined by the Board of Directors. Messrs. Sokol, Abel
and Goodman are participants in the SERP. The SERP provides annual retirement
benefits up to sixty-five percent of a participant’s Total Cash Compensation in
effect immediately prior to retirement, subject to a $1 million maximum
retirement benefit. “Total Cash Compensation” means the highest amount payable
to a participant as monthly base salary during the five years immediately prior
to retirement multiplied by 12 plus the average of the participant’s last three
years awards under an annual incentive bonus program and special, additional
or
non-recurring bonus awards, if any, that are required to be included in Total
Cash Compensation pursuant to a participant’s employment agreement or approved
for inclusion by the Board. Participants must be credited with five years of
service to be eligible to receive benefits under the SERP. Each of the
Messrs. Sokol, Abel and Goodman has five years of credited service with the
Company and will be eligible to receive benefits under the SERP. A participant
who elects early retirement is entitled to reduced benefits under the SERP,
however, in accordance with their respective employment agreements,
Messrs. Sokol and Abel are eligible to receive the maximum retirement
benefit at age 47. A survivor benefit is payable to a surviving spouse under
the
SERP. Benefits from the SERP will be paid out of general corporate funds;
however, through a Rabbi trust, the Company maintains life insurance on the
participants in amounts expected to be sufficient to fund the after-tax cost
of
the projected benefits. Deferred compensation is considered part of the salary
covered by the SERP. The SERP benefit will be reduced by the amount of the
participant’s regular retirement benefit under the MidAmerican Energy Company
Cash Balance Retirement Plan (the “MidAmerican Retirement Plan”), which became
effective January 1, 1997.
The
MidAmerican Retirement Plan replaced retirement plans of predecessor companies
that were structured as traditional, defined benefit plans. Under the
MidAmerican Retirement Plan, each participant has an account, for record keeping
purposes only, to which credits are allocated annually based upon a percentage
of the participant’s salary paid in the plan year. In addition, all balances in
the accounts of participants earn a fixed rate of interest that is credited
annually. The interest rate for a particular year is based on the one-year
constant maturity Treasury yield plus seven-tenths of one percentage point.
At
retirement, or other termination of employment, an amount equal to the vested
balance then credited to the account is payable to the participant in the form
of a lump sum or a form of annuity for the entire benefit under the MidAmerican
Retirement Plan. The estimated annual benefit payable upon normal retirement
age
(65) for Mr. Anderson is $89,109 and for Ms. Sammon is $141,535. These
estimates assume an interest credit rate of 6.0 percent and conversion to a
life
annuity using plan mortality and 6.0 percent interest. Mr. Anderson and Ms.
Sammon are not participants in the SERP.
117
The
table
below shows the estimated aggregate combined annual benefits payable under
the
SERP and the MidAmerican Retirement Plan. The amounts exclude Social Security
and are based on a straight life annuity and retirement at ages 55, 60 and
65.
Federal law limits the amount of benefits payable to an individual through
the
tax qualified defined benefit and contribution plans, and benefits exceeding
such limitation are payable under the SERP.
Total
Cash
Estimated
Annual Benefit
Compensation
Age
of Retirement
at
Retirement ($)
55
60
65
$
400,000
$
220,000
$
240,000
$
260,000
500,000
275,000
300,000
325,000
600,000
330,000
360,000
390,000
700,000
385,000
420,000
455,000
800,000
440,000
480,000
520,000
900,000
495,000
540,000
585,000
1,000,000
550,000
600,000
650,000
1,250,000
687,500
750,000
812,500
1,500,000
825,000
900,000
975,000
1,750,000
962,500
1,000,000
1,000,000
2,000,000 and greater
1,000,000
1,000,000
1,000,000
Employment
Agreements
Pursuant
to his employment agreement, Mr. Sokol serves as Chairman of MEHC’s Board
of Directors and Chief Executive Officer. The employment agreement provides
that
Mr. Sokol is to receive an annual base salary of not less than $750,000,
senior executive employee benefits and annual bonus awards that shall not be
less than $675,000. The agreement is currently scheduled to expire on
August 21, 2006, but renews automatically from year to year subject to Mr.
Sokol’s election to decline renewal at least 120 days prior to such date or
termination by MEHC.
The
employment agreement provides that MEHC may terminate the employment of
Mr. Sokol with cause, in which case MEHC is to pay to him any accrued but
unpaid salary and a bonus of not less than the minimum annual bonus, or due
to
death, permanent disability or other than for cause, including a change in
control, in which case Mr. Sokol is entitled to receive an amount equal to
three times the sum of his annual salary then in effect and the greater of
his
minimum annual bonus or his average annual bonus for the two preceding years,
as
well as three years of accelerated option vesting plus continuation of his
senior executive employee benefits (or the economic equivalent thereof) for
three years. If Mr. Sokol resigns, MEHC is to pay to him any accrued but
unpaid salary and a bonus of not less than the annual minimum bonus, unless
he
resigns for good reason in which case he will receive the same benefits as
if he
were terminated other than for cause.
In
the
event Mr. Sokol has relinquished his position as Chief Executive Officer
and is subsequently terminated as Chairman of the Board due to death, disability
or other than for cause, he is entitled to (i) any accrued but unpaid salary
plus an amount equal to the aggregate annual salary that would have been paid
to
him through the fifth anniversary of the date he commenced his employment solely
as Chairman of the Board, (ii) the immediate vesting of all of his options,
and
(iii) the continuation of his senior executive employee benefits (or the
economic equivalent thereof) through such fifth anniversary. If Mr. Sokol
relinquishes his position as Chief Executive Officer but offers to remain
employed as the Chairman of the Board, he is to receive a special achievement
bonus equal to two times the sum of his annual salary then in effect and the
greater of his minimum annual bonus or his average annual bonus for the two
preceding years, as well as two years of accelerated option
vesting.
118
Under
the
terms of separate employment agreements with MEHC, each of Messrs. Abel and
Goodman is entitled to receive two years base salary continuation, payments
in
respect of average bonuses for the prior two years and two years continued
option vesting in the event MEHC terminates his employment other than for cause.
If such persons were terminated without cause, Messrs. Sokol, Abel and
Goodman would currently be entitled to be paid approximately $10,050,000,
$5,880,000 and $1,215,000, respectively, without giving effect to any
tax-related provisions.
Compensation
Committee Interlocks and Insider Participation
The
compensation committee of the Board of Directors is comprised of
Messrs. Warren E. Buffett and Walter Scott, Jr. Mr. Walter Scott, Jr.
is a former officer of the Company. See also Item 13. Certain Relationships
and
Related Transactions of this Form 10-K.
Item
12.Security
Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters.
The
following table sets forth certain information regarding beneficial ownership
of
the shares of MEHC’s common stock and certain information with respect to the
beneficial ownership of each director, its Named Executive Officers and all
directors and executive officers as a group as of March 1,2006.
Number
of Shares
Percentage
Name
and Address of Beneficial Owner (1)
Beneficially
Owned (2)
Of
Class (2)
Common
Stock:
Berkshire
Hathaway (3)
42,164,337
83.42%
Walter
Scott, Jr. (4)
4,972,000
9.84%
David
L. Sokol (5)
1,523,482
2.94%
Gregory
E. Abel (6)
704,992
1.38%
Douglas
L. Anderson
-
-
Warren
E. Buffett (7)
-
-
Patrick
J. Goodman
-
-
Marc
D. Hamburg (7)
-
-
Maureen
E. Sammon
-
-
All
directors and executive officers as a group (8 persons)
7,200,474
13.74%
______________
(1)
Unless
otherwise indicated, each address is c/o MEHC at 666 Grand Avenue,
29th
Floor, Des Moines, Iowa50309.
(2)
Includes
shares which the listed beneficial owner is deemed to have the right
to
acquire beneficial ownership under Rule 13d-3(d) under the Securities
Exchange Act, including, among other things, shares which the listed
beneficial owner has the right to acquire within 60
days.
(3)
Such
beneficial owner’s address is 1440 Kiewit Plaza, Omaha, Nebraska68131.
(4)
Excludes
3,000,000 shares held by family members and family controlled trusts
and
corporations (“Scott Family Interests”) as to which Mr. Scott
disclaims beneficial ownership. Such beneficial owner’s address is 1000
Kiewit Plaza, Omaha, Nebraska68131.
(5)
Includes
options to purchase 1,199,277 shares of common stock that are exercisable
within 60 days.
(6)
Includes
options to purchase 649,052 shares of common stock which are exercisable
within 60 days. Excludes 10,041 shares reserved for issuance pursuant
to a
deferred compensation plan.
(7)
Excludes
42,164,337 shares of common stock held by Berkshire Hathaway of which
beneficial ownership of such shares is
disclaimed.
119
Mr. Sokol’s
employment agreement gives him the right during the term of his employment
to
serve as a member of the Board of Directors and to nominate two additional
directors.
Pursuant
to a shareholders agreement, as amended on December 7, 2005, Walter Scott,
Jr. or any of the Scott Family Interests and Messrs. Sokol and Abel are
able to require Berkshire Hathaway to exchange any or all of their respective
shares of MEHC’s common stock for shares of Berkshire Hathaway common
stock.
Item
13.Certain
Relationships and Related
Transactions.
Under
a
subscription agreement with MEHC, which expires in March 2007, Berkshire
Hathaway has agreed to purchase, under certain circumstances, additional 11%
trust issued mandatorily redeemable preferred securities in the event that
certain outstanding trust preferred securities of MEHC which were outstanding
prior to the closing of its acquisition by a private investor group on
March 14, 2000 are tendered for conversion to cash by the current
holders.
In
order
to finance its acquisition of Northern Natural Gas, on August 16, 2002,
MEHC sold to Berkshire Hathaway $950.0 million in aggregate principal
amount of the 11% mandatorily redeemable trust issued preferred securities
Series A, of its subsidiary trust, MidAmerican Capital Trust II, due
August 31, 2012. The transaction was a private placement pursuant to
Section 4(1) of the Securities Act and did not involve any underwriters,
underwriting discounts or commissions. Scheduled principal payments began in
August 2003. Messrs. Warren E. Buffett and Walter Scott, Jr. are members of
the Board of Directors of Berkshire Hathaway. Messrs. Buffett and Marc D.
Hamburg are executive officers of Berkshire Hathaway.
The
Energy Policy Act became law on August 8, 2005 and included the repeal of
PUHCA 1935 effective February 8, 2006. On February 9, 2006, Berkshire
Hathaway converted its 41,263,395 shares of MEHC’s no par, zero-coupon
convertible preferred stock into an equal number of shares of MEHC’s common
stock and, upon conversion, has an 83.4% (80.5% on a diluted basis) voting
interest in MEHC.
Aggregate
fees billed to the Company as a consolidated entity during the fiscal years
ending December 31, 2005 and 2004 by the Company’s principal accounting
firm, Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu,
and their respective affiliates (collectively, the “Deloitte Entities”), are set
forth below. The audit committee has considered whether the provision of the
non-audit services described below is compatible with maintaining the principal
accountant’s independence and concluded that these are not independence
impairing services.
Includes
the aggregate fees billed for each of the last two fiscal years for
professional services rendered by the Deloitte Entities for the audit
of
the Company’s annual financial statements and the review of financial
statements included in the Company’s Form 10-Q or for services that are
normally provided by the Deloitte Entities in connection with statutory
and regulatory filings or engagements for those fiscal
years.
(2)
Includes
the aggregate fees billed in each of the last two fiscal years for
assurance and related services by the Deloitte Entities that are
reasonably related to the performance of the audit or review of the
Company’s financial statements. Services included in this category include
audits of benefit plans, due diligence for possible acquisitions
and
consultation pertaining to new and proposed accounting and regulatory
rules.
120
(3)
Includes
the aggregate fees billed in each of the last two fiscal years for
professional services rendered by the Deloitte Entities for tax
compliance, tax advice, and tax
planning.
(4)
Includes
the aggregate fees billed in each of the last two fiscal years for
products and services provided by the Deloitte Entities, other than
the
services reported as “Audit Fees,”“Audit-Related Fees,” or “Tax
Fees.”
The
audit
committee reviewed the non-audit services rendered by the Deloitte Entities
in
and for fiscal 2005 as set forth in the above table and concluded that such
services were compatible with maintaining the principal accountant’s
independence. Under the Sarbanes-Oxley Act of 2002, all audit and non-audit
services performed by the Company’s principal accountant are approved in advance
by the audit committee to assure that such services do not impair the principal
accountant’s independence from the Company. Accordingly, the audit committee has
an Audit and Non-Audit Services Pre-Approval Policy (the “Policy”) which sets
forth the procedures and the conditions pursuant to which services to be
performed by the principal accountant are to be pre-approved. Pursuant to the
Policy, certain services described in detail in the Policy may be pre-approved
on an annual basis together with pre-approved maximum fee levels for such
services. The services eligible for annual pre-approval consist of services
that
would be included under the categories of Audit Fees, Audit-Related Fees and
Tax
Fees. If not pre-approved on an annual basis, proposed services must otherwise
be separately approved prior to being performed by the principal accountant.
In
addition, any services that receive annual pre-approval but exceed the
pre-approved maximum fee level also will require separate approval by the audit
committee prior to being performed. The audit committee may delegate authority
to pre-approve audit and non-audit services to any member of the audit
committee, but may not delegate such authority to management.
121
PART
IV
Item
15.Exhibits
and Financial Statement
Schedules.
(a)
Financial
Statements and Schedules
(i)
Financial
Statements
Financial
Statements are included in Item 8 of this Form 10-K.
(ii)
Financial
Statement Schedules
See
Schedule I on page 123.
See
Schedule II on page 126.
Schedules
not listed above have been omitted because they are either not applicable,
not required or the information required to be set forth therein
is
included in the consolidated financial statements or notes
thereto.
(b)
Exhibits
The
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).
Reserves
Deducted From Assets To Which They Apply:
Reserve
for uncollectible accounts receivable:
Year
ended 2005
$
26,033
$
13,069
$
(17,672
)
$
21,430
Year
ended 2004
$
26,004
$
15,304
$
(15,275
)
$
26,033
Year
ended 2003
$
39,742
$
13,620
$
(27,358
)
$
26,004
Reserves
Not Deducted From Assets(1):
Year
ended 2005
$
10,848
$
4,019
$
(2,386
)
$
12,481
Year
ended 2004
$
17,417
$
4,048
$
(10,617
)
$
10,848
Year
ended 2003
$
10,981
$
10,527
$
(4,091
)
$
17,417
The
notes
to the consolidated MEHC financial statements are an integral part of this
financial statement schedule.
(1)
Reserves
not deducted from assets relate primarily to estimated liabilities
for
losses retained by MEHC for workers compensation, public liability
and
property damage claims.
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf
by
the undersigned thereunto duly authorized on this 3rd
day of
March 2006.
MIDAMERICAN
ENERGY HOLDINGS COMPANY
/s/
David L. Sokol*
David
L. Sokol
Chairman
of the Board and Chief Executive
Officer
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has
been
signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.
Amended
and Restated Bylaws of MidAmerican Energy Holdings
Company.
4.1
Indenture,
dated as of October 4, 2002, by and between MidAmerican Energy
Holdings Company and The Bank of New York, relating to the 4.625%
Senior
Notes due 2007 and the 5.875% Senior Notes due 2012 (incorporated
by
reference to Exhibit 4.1 of MidAmerican Energy Holdings Company’s
Registration Statement No. 333-101699 dated December 6,2002).
4.2
First
Supplemental Indenture, dated as of October 4, 2002, by and between
MidAmerican Energy Holdings Company and The Bank of New York, relating
to
the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due
2012
(incorporated by reference to Exhibit 4.2 of MidAmerican Energy Holdings
Company’s Registration Statement No. 333-101699 dated December 6,2002).
4.3
Second
Supplemental Indenture, dated as of May 16, 2003, by and between
MidAmerican Energy Holdings Company and The Bank of New York, relating
to
the 3.50% Senior Notes due 2008 (incorporated by reference to Exhibit
4.3
of MidAmerican Energy Holdings Company’s Registration Statement No.
333-105690 dated May 23, 2003).
4.4
Third
Supplemental Indenture, dated as of February 12, 2004, by and between
MidAmerican Energy Holdings Company and The Bank of New York, relating
to
the 5.00% Senior Notes due 2014 (incorporated by reference to Exhibit
4.4
of MidAmerican Energy Holdings Company’s Registration Statement No.
333-113022 dated February 23, 2004).
4.5
Indenture
for the 6 1/4% Convertible Junior Subordinated Debentures due 2012,
dated
as of February 26, 1997, between MidAmerican Energy Holdings Company,
as issuer, and the Bank of New York, as Trustee (incorporated by
reference
to Exhibit 10.129 to MidAmerican Energy Holdings Company’s Annual Report
on Form 10-K for the year ended December 31,1995).
4.6
Indenture,
dated as of October 15, 1997, among MidAmerican Energy Holdings
Company and IBJ Schroder Bank & Trust Company, as Trustee
(incorporated by reference to Exhibit 4.1 to MidAmerican Energy Holdings
Company’s Current Report on Form 8-K dated October 23,1997).
4.7
Form
of First Supplemental Indenture for the 7.63% Senior Notes in the
principal amount of $350,000,000 due 2007, dated as of October 28,1997, among MidAmerican Energy Holdings Company and IBJ Schroder
Bank
& Trust Company, as Trustee (incorporated by reference to Exhibit 4.2
to MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated
October 23, 1997).
4.8
Form
of Second Supplemental Indenture for the 6.96% Senior Notes in the
principal amount of $215,000,000 due 2003, 7.23% Senior Notes in
the
principal amount of $260,000,000 due 2005, 7.52% Senior Notes in
the
principal amount of $450,000,000 due 2008, and 8.48% Senior Notes
in the
principal amount of $475,000,000 due 2028, dated as of September 22,1998 between MidAmerican Energy Holdings Company and IBJ Schroder
Bank
& Trust Company, as Trustee (incorporated by reference to Exhibit 4.1
to MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated
September 17, 1998.)
4.9
Form
of Third Supplemental Indenture for the 7.52% Senior Notes in the
principal amount of $100,000,000 due 2008, dated as of November 13,1998, between MidAmerican Energy Holdings Company and IBJ Schroder
Bank
& Trust Company, as Trustee (incorporated by reference to MidAmerican
Energy Holdings Company’s Current Report on Form 8-K dated
November 10, 1998).
128
Exhibit
No.
4.10
Indenture,
dated as of March 14, 2000, among MidAmerican Energy Holdings Company
and the Bank of New York, as Trustee (incorporated by reference to
Exhibit
4.9 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K/A
for the year ended December 31, 1999).
4.11
Indenture,
dated as of March 12, 2002, between MidAmerican Energy Holdings
Company and the Bank of New York, as Trustee (incorporated by reference
to
Exhibit 4.11 to MidAmerican Energy Holdings Company’s Annual Report on
Form 10-K for the year ended December 31, 2001).
Amendment
No. 1 to Shareholders Agreement, dated December 7,2005.
10.1
Amended
and Restated Employment Agreement between MidAmerican Energy Holdings
Company and David L. Sokol, dated May 10, 1999 (incorporated by
reference to Exhibit 10.1 to MidAmerican Energy Holdings Company’s Annual
Report on Form 10-K/A for the year ended December 31,1999).
10.2
Amendment
No. 1 to the Amended and Restated Employment Agreement between MidAmerican
Energy Holdings Company and David L. Sokol, dated March 14, 2000
(incorporated by reference to Exhibit 10.2 to MidAmerican Energy
Holdings
Company’s Annual Report on Form 10-K/A for the year ended
December 31, 1999).
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).
Employment
Agreement between MidAmerican Energy Holdings Company and Patrick
J.
Goodman, dated April 21, 1999 (incorporated by reference to Exhibit
10.5 to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K/A
for the year ended December 31, 1999).
10.7
125
MW Power Plant-Upper Mahiao Agreement, dated September 6, 1993,
between Philippine National Oil Company-Energy Development Corporation
and
Ormat, Inc. as amended by the First Amendment to 125 MW Power Plant
Upper
Mahiao Agreement, dated as of January 28, 1994, the Letter Agreement
dated February 10, 1994, the Letter Agreement dated February 18,1994 and the Fourth Amendment to 125 MW Power Plant-Upper Mahiao
Agreement, dated as of March 7, 1994 (incorporated by reference to
Exhibit 10.95 to MidAmerican Energy Holdings Company’s Annual Report on
Form 10-K for the year ended December 31, 1993).
10.8
Credit
Agreement, dated as of April 8, 1994, between CE Cebu Geothermal
Power Company, Inc., Export-Import Bank of the United States (incorporated
by reference to Exhibit 10.97 to MidAmerican Energy Holdings Company’s
Annual Report on Form 10-K for the year ended December 31,1993).
10.9
180
MW Power Plant-Mahanagdong Agreement, dated September 18, 1993,
between Philippine National Oil Company-Energy Development Corporation
and
CE Philippines Ltd. and the Company, as amended by the First Amendment
to
Mahanagdong Agreement, dated June 22, 1994, the Letter Agreement
dated July 12, 1994, the Letter Agreement dated July 29, 1994,
and the Fourth Amendment to Mahanagdong Agreement, dated March 3,1995 (incorporated by reference to Exhibit 10.1 00 to MidAmerican
Energy
Holdings Company’s Annual Report on Form 10-K for the year ended
December 31, 1993).
10.10
Credit
Agreement, dated as of June 30, 1994, between CE Luzon Geothermal
Power Company, Inc. and Export-Import Bank of the United States
(incorporated by reference to Exhibit 10.102 to MidAmerican Energy
Holdings Company’s Annual Report on Form 10-K for the year ended
December 31, 1993).
10.11
Finance
Agreement, dated as of June 30, 1994, between CE Luzon Geothermal
Power Company, Inc. and Overseas Private Investment Corporation
(incorporated by reference to Exhibit 10.103 to MidAmerican Energy
Holdings Company’s Annual Report on Form 10-K for the year ended
December 31, 1993).
10.12
Overseas
Private Investment Corporation Contract of Insurance, dated July 29,1994, between Overseas Private Investment Corporation and the Company,
CE
International Ltd., CE Mahanagdong Ltd. and American Pacific Finance
Company and Amendment No. 1, dated August 3, 1994 (incorporated by
reference to Exhibit 10.105 to MidAmerican Energy Holdings Company’s
Annual Report on Form 10-K for the year ended December 31,1993).
10.13
231
MW Power Plant-Malitbog Agreement, dated September 10, 1993, between
Philippine National Oil Company-Energy Development Corporation and
Magma
Power Company and the First and Second Amendments thereto, dated
December 8, 1993 and March 10, 1994, respectively (incorporated
by reference to Exhibit 10.106 to MidAmerican Energy Holdings Company’s
Annual Report on Form 10-K for the year ended December 31,1993).
10.14
Trust
Indenture, dated as of November 27, 1995, between the CE Casecnan
Water and Energy Company, Inc. and Chemical Trust Company of California
(incorporated by reference to Exhibit 4.1 to CE Casecnan Water and
Energy
Company, Inc.’s Registration Statement on Form S-4 dated January 25,1996).
10.15
Amended
and Restated Casecnan Project Agreement, dated June 26, 1995, between
the National Irrigation Administration and CE Casecnan Water and
Energy
Company Inc. (incorporated by reference to Exhibit 10.1 to CE Casecnan
Water and Energy Company, Inc.’s Registration Statement on Form S-4 dated
January 25, 1996).
10.16
Supplemental
Agreement between CE Casecnan Water and Energy Company, Inc. and
the
Philippines National Irrigation Administration dated as of
September 29, 2003 (incorporated by reference to Exhibit 98.1 to
MidAmerican Energy Holdings Company's Current Report on Form 8-K
dated
October 15, 2003).
130
Exhibit
No.
10.17
Indenture
and First Supplemental Indenture, dated March 11, 1999, between
MidAmerican Funding LLC and IBJ Whitehall Bank & Trust Company and the
First Supplement thereto relating to the $700 million Senior Notes
and Bonds (incorporated by reference to MidAmerican Energy Holdings
Company’s Annual Report on Form 10-K for the year ended December 31,1998).
10.18
Second
Supplemental Indenture, dated as of March 1, 2001, by and between
MidAmerican Funding, LLC and The Bank of New York, as Trustee
(incorporated by reference to Exhibit 4.4 to MidAmerican Funding
LLC’s
Registration Statement on Form S-3, Registration No.
333-56624).
10.19
General
Mortgage Indenture and Deed of Trust, dated as of January 1, 1993,
between Midwest Power Systems Inc. and Morgan Guaranty Trust Company
of
New York, Trustee (incorporated by reference to Exhibit 4(b)-1 to
the
Midwest Resources Inc. Annual Report on Form 10-K for the year ended
December 31, 1992, Commission File No. 1-10654).
10.20
First
Supplemental Indenture, dated as of January 1, 1993, between Midwest
Power Systems Inc. and Morgan Guaranty Trust Company of New York,
Trustee
(incorporated by reference to Exhibit 4(b)-2 to the Midwest Resources
Inc.
Annual Report on Form 10-K for the year ended December 31, 1992,
Commission File No. 1-10654).
10.21
Second
Supplemental Indenture, dated as of January 15, 1993, between Midwest
Power Systems Inc. and Morgan Guaranty Trust Company of New York,
Trustee
(incorporated by reference to Exhibit 4(b)-3 to the Midwest Resources
Inc.
Annual Report on Form 10-K for the year ended December 31, 1992,
Commission File No. 1-10654).
10.22
Third
Supplemental Indenture, dated as of May 1, 1993, between Midwest
Power Systems Inc. and Morgan Guaranty Trust Company of New York,
Trustee
(incorporated by reference to Exhibit 4.4 to the Midwest Resources
Inc.
Annual Report on Form 10-K for the year ended December 31, 1993,
Commission File No. 1-10654).
10.23
Fourth
Supplemental Indenture, dated as of October 1, 1994, between Midwest
Power Systems Inc. and Harris Trust and Savings Bank, Trustee
(incorporated by reference to Exhibit 4.5 to the Midwest Resources
Inc.
Annual Report on Form 10-K for the year ended December 31, 1994,
Commission File No. 1-10654).
10.24
Fifth
Supplemental Indenture, dated as of November 1, 1994, between Midwest
Power Systems Inc. and Harris Trust and Savings Bank, Trustee
(incorporated by reference to Exhibit 4.6 to the Midwest Resources
Inc.
Annual Report on Form 10-K for the year ended December 31, 1994,
Commission File No. 1-10654).
10.25
Sixth
Supplemental Indenture, dated as of July 1, 1995, between Midwest
Power Systems Inc. and Harris Trust and Savings Bank, Trustee
(incorporated by reference to Exhibit 4.15 to the MidAmerican Energy
Company Annual Report on Form 10-K for the year ended December 31,1995, Commission File No. 1-11505).
10.26
Indenture
dated as of December 1, 1996, between MidAmerican Energy Company and
the First National Bank of Chicago, as Trustee (incorporated by reference
to Exhibit 4(1) to MidAmerican Energy Company’s Registration Statement on
Form S-3, Registration No. 333-15387).
10.27
First
Supplemental Indenture, dated as of February 8, 2002, by and between
MidAmerican Energy Company and The Bank of New York, as Trustee
(incorporated by reference to Exhibit 4.3 to MidAmerican Energy Company’s
Annual Report on Form 10-K for the year ended December 31, 2004,
Commission File No. 333-15387).
131
Exhibit
No.
10.28
Second
Supplemental Indenture, dated as of January 14, 2003, by and between
MidAmerican Energy Company and The Bank of New York, as Trustee
(incorporated by reference to Exhibit 4.2 to MidAmerican Energy Company’s
Annual Report on Form 10-K for the year ended December 31, 2004,
Commission File No. 333-15387).
10.29
Third
Supplemental Indenture, dated as of October 1, 2004, by and between
MidAmerican Energy Company and The Bank of New York, as Trustee
(incorporated by reference to Exhibit 4.1 to MidAmerican Energy Company’s
Annual Report on Form 10-K for the year ended December 31, 2004,
Commission File No. 333-15387).
10.30
Fourth
Supplemental Indenture, dated November 1, 2005, by and between
MidAmerican Energy Company and the Bank of New York Trust Company,
NA, as
Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican
Energy Company Annual Report on Form 10-K for the year ended
December 31, 2005).
10.31
Sixth
Amendment to 180 MW Power Plant-Mahanagdong Agreement, dated
August 31, 2003, between Philippine National Oil Company-Energy
Development Corporation and CE Luzon Geothermal Power Company, Inc.
(incorporated by reference to Exhibit 10.44 to MidAmerican Energy
Holdings
Company’s Annual Report on Form 10-K for the year ended December 31,2003).
10.32
Third
Amendment to 231 MW Power Plant-Malitbog Agreement, dated August 31,2003, between Philippine National Oil Company-Energy Development
Corporation and Visayas Geothermal Power Company, Inc. (incorporated
by
reference to Exhibit 10.45 to MidAmerican Energy Holdings Company’s Annual
Report on Form 10-K for the year ended December 31,2003).
10.33
Seventh
Amendment to 125 MW Power Plant-Upper Mahiao Agreement, dated
August 31, 2003, between Philippine National Oil Company-Energy
Development Corporation and CE Cebu Geothermal Power Company, Inc.
(incorporated by reference to Exhibit 10.46 to MidAmerican Energy
Holdings
Company’s Annual Report on Form 10-K for the year ended December 31,2003).
10.34
Fiscal
Agency Agreement, dated as of October 15, 2002, between Northern
Natural Gas Company and J.P. Morgan Trust Company, National Association,
Fiscal Agent, relating to the $300,000,000 in principal amount of
the
5.375% Senior Notes due 2012 (incorporated by reference to Exhibit
10.47
to MidAmerican Energy Holdings Company’s Annual Report on Form 10-K for
the year ended December 31, 2003).
10.35
Trust
Indenture, dated as of August 13, 2001, among Kern River Funding
Corporation, Kern River Gas Transmission Company and the JP Morgan
Chase
Bank, as Trustee, relating to the $510,000,000 in principal amount
of the
6.676% Senior Notes due 2016 (incorporated by reference to Exhibit
10.48
to MidAmerican Energy Holdings Company's Annual Report on Form 10-K
for
the year ended December 31, 2003).
10.36
Third
Supplemental Indenture, dated as of May 1, 2003, among Kern River
Funding Corporation, Kern River Gas Transmission Company and JPMorgan
Chase Bank, as Trustee, relating to the $836,000,000 in principal
amount
of the 4.893% Senior Notes due 2018 (incorporated by reference to
Exhibit
10.49 to MidAmerican Energy Holdings Company's Annual Report on Form
10-K
for the year ended December 31, 2003).
10.37
CalEnergy
Company, Inc. Voluntary Deferred Compensation Plan, effective
December 1, 1997, First Amendment, dated as of August 17, 1999,
and Second Amendment effective March 14, 2000 (incorporated by
reference to Exhibit 10.50 of MidAmerican Energy Holdings Company’s
Registration Statement No. 333-101699 dated December 6,2002).
10.38
MidAmerican
Energy Holdings Company Executive Voluntary Deferred Compensation
Plan
(incorporated by reference to Exhibit 10.51 of MidAmerican Energy
Holdings
Company’s Registration Statement No. 333-101699 dated December 6,2002).
132
Exhibit
No.
10.39
MidAmerican
Energy Company First Amended and Restated Supplemental Retirement
Plan for
Designated Officers dated as of May 10, 1999 (incorporated by
reference to Exhibit 10.52 of MidAmerican Energy Holdings Company’s
Registration Statement No. 333-101699 dated December 6,2002).
10.40
MidAmerican
Energy Company Restated Executive Deferred Compensation Plan (incorporated
by reference to Exhibit 10.6 to MidAmerican Energy Holdings Company’s
Annual Report on Form 10-K/A for the year ended December 31,1999).
10.41
MidAmerican
Energy Holdings Company Restated Deferred Compensation Plan-Board
of
Directors (incorporated by reference to Exhibit 10 to MidAmerican
Energy
Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended
June 30, 1999).
10.42
MidAmerican
Energy Company Combined Midwest Resources/Iowa Resources Restated
Deferred
Compensation Plan-Board of Directors (incorporated by reference to
Exhibit
10.63 to MidAmerican Energy Holdings Company’s Annual Report on Form
10-K/A for the year ended December 31, 1999).
10.43
MidAmerican
Energy Holdings Company Executive Incremental Profit Sharing Plan
(incorporated by reference to Exhibit 10.2 of MidAmerican Energy
Holdings
Company’s Quarterly Report on Form 10-Q for the quarter ended
March 31, 2003.)
10.44
Trust
Deed between CE Electric UK Funding Company, AMBAC Insurance UK Limited
and The Law Debenture Trust Corporation, p.l.c. dated December 15,1997 (incorporated by reference to Exhibit 99.1 to MidAmerican Energy
Holdings Company’s Current Report on Form 8-K dated March 30,2004).
10.45
Insurance
and Indemnity Agreement between CE Electric UK Funding Company and
AMBAC
Insurance UK Limited dated December 15, 1997 (incorporated by reference
to
Exhibit 99.2 to MidAmerican Energy Holdings Company’s Current Report on
Form 8-K dated March 30, 2004).
10.46
Supplemental
Agreement to Insurance and Indemnity Agreement between CE Electric
UK
Funding Company and AMBAC Insurance UK Limited dated September 19,2001 (incorporated by reference to Exhibit 99.3 to MidAmerican Energy
Holdings Company’s Current Report on Form 8-K dated March 30,2004).
10.47
Fiscal
Agency Agreement, dated as of September 4, 1998, between Northern
Natural Gas Company and Chase Bank of Texas, National Association,
Fiscal
Agent, relating to the $150,000,000 in principal amount of the 6.75%
Senior Notes due 2008 (incorporated by reference to Exhibit 10.69
to
MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for
the quarter ended March 31, 2004).
10.48
Fiscal
Agency Agreement, dated as of May 24, 1999, between Northern Natural
Gas Company and Chase Bank of Texas, National Association, Fiscal
Agent,
relating to the $250,000,000 in principal amount of the 7.00% Senior
Notes
due 2011 (incorporated by reference to Exhibit 10.70 to MidAmerican
Energy
Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended
March 31, 2004).
10.49
Trust
Indenture, dated as of September 10, 1999, between Cordova Funding
Corporation and Chase Manhattan Bank and Trust Company, National
Association, Trustee, relating to the $225,000,000 in principal amount
of
the 8.75% Senior Secured Bonds due 2019 (incorporated by reference
to
Exhibit 10.71 to MidAmerican Energy Holdings Company’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 2004).
10.50
Indenture,
dated as of December 15, 1997, among CE Electric UK Funding Company,
The
Bank of New York, as Trustee, and Banque Internationale A Luxembourg
S.A.,
as Paying Agent (incorporated by reference to Exhibit 10.72 to MidAmerican
Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter
ended March 31, 2004).
133
Exhibit
No.
10.51
First
Supplemental Indenture, dated as of December 15, 1997, among CE Electric
UK Funding Company, The Bank of New York, Trustee, and Banque
Internationale A Luxembourg S.A., Paying Agent, relating to the
$125,000,000 in principal amount of the 6.853% Senior Notes due 2004
and
to the $237,000,000 in principal amount of the 6.995% Senior Notes
due
2007 (incorporated by reference to Exhibit 10.73 to MidAmerican Energy
Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended
March 31, 2004).
10.52
Trust
Deed, dated as of February 4, 1998 among Yorkshire Power Finance
Limited, Yorkshire Power Group Limited and Bankers Trustee Company
Limited, Trustee, relating to the £200,000,000 in principal amount of the
7.25% Guaranteed Bonds due 2028 (incorporated by reference to Exhibit
10.74 to MidAmerican Energy Holdings Company’s Quarterly Report on Form
10-Q for the quarter ended March 31, 2004).
10.53
First
Supplemental Trust Deed, dated as of October 1, 2001, among Yorkshire
Power Finance Limited, Yorkshire Power Group Limited and Bankers
Trustee
Company Limited, Trustee, relating to the £200,000,000 in principal amount
of the 7.25% Guaranteed Bonds due 2028 (incorporated by reference
to
Exhibit 10.75 to MidAmerican Energy Holdings Company’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 2004).
10.54
Third
Supplemental Trust Deed, dated as of October 1, 2001, among Yorkshire
Electricity Distribution plc, Yorkshire Electricity Group plc and
Bankers
Trustee Company Limited, Trustee, relating to the £200,000,000 in
principal amount of the 9.25% Bonds due 2020 (incorporated by reference
to
Exhibit 10.76 to MidAmerican Energy Holdings Company’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 2004).
10.55
Indenture,
dated as of February 1, 1998, and Second Supplemental Indenture,
dated as of February 25, 1998, each among Yorkshire Power Finance
Limited, Yorkshire Power Group Limited, The Bank of New York, Trustee,
and
Banque Internationale du Luxembourg S.A., Paying Agent, relating
to the
$300,000,000 in principal amount of the 6.496% Notes due 2008
(incorporated by reference to Exhibit 10.77 to MidAmerican Energy
Holdings
Company’s Quarterly Report on Form 10-Q for the quarter ended
March 31, 2004).
10.56
Indenture,
dated as of February 1, 2000, among Yorkshire Power Finance 2
Limited, Yorkshire Power Group Limited and The Bank of New York,
Trustee
(incorporated by reference to Exhibit 10.78 to MidAmerican Energy
Holdings
Company’s Quarterly Report on Form 10-Q for the quarter ended
March 31, 2004).
10.57
First
Supplemental Trust Deed, dated as of September 27, 2001, among
Northern Electric Finance plc, Northern Electric plc, Northern Electric
Distribution Limited and The Law Debenture Trust Corporation p.l.c.,
Trustee, relating to the £100,000,000 in principal amount of the 8.625%
Guaranteed Bonds due 2005 and to the £100,000,000 in principal amount of
the 8.875% Guaranteed Bonds due 2020 (incorporated by reference to
Exhibit
10.81 to MidAmerican Energy Holdings Company’s Quarterly Report on Form
10-Q for the quarter ended March 31, 2004).
10.58
Trust
Deed, dated as of January 17, 1995, between Yorkshire Electricity
Group plc and Bankers Trustee Company Limited, Trustee, relating
to the
£200,000,000 in principal amount of the 9 1/4% Bonds due 2020
(incorporated by reference to Exhibit 10.83 to MidAmerican Energy
Holdings
Company’s Quarterly Report on Form 10-Q for the quarter ended
March 31, 2004).
10.59
Master
Trust Deed, dated as of October 16, 1995, among Northern Electric
Finance plc, Northern Electric plc and The Law Debenture Trust Corporation
p.l.c., Trustee, relating to the £100,000,000 in principal amount of the
8.625% Guaranteed Bonds due 2005 and to the £100,000,000 in principal
amount of the 8.875% Guaranteed Bonds due 2020 (incorporated by reference
to Exhibit 10.70 to MidAmerican Energy Holdings Company’s Annual Report on
Form 10-K for the year ended December 31, 2004).
134
Exhibit
No.
10.60
MidAmerican
Energy Holdings Company Amended and Restated Long-Term Incentive
Partnership Plan dated as of January 1, 2004 (incorporated by
reference to Exhibit 10.71 to MidAmerican Energy Holdings Company’s Annual
Report on Form 10-K for the year ended December 31,2004).
10.61
Fiscal
Agency Agreement, dated April 14, 2005, by and between Northern
Natural Gas Company, as issuer, and J.P. Morgan Trust Company, National
Association, as fiscal agent, relating to the $100,000,000 in principal
amount of the 5.125% Senior Notes due 2015 (incorporated by reference
to
exhibit 99.1 to MidAmerican Energy Holdings Company’s Current Report on
Form 8-K dated April 18, 2005).
10.62
£100,000,000
Facility Agreement dated 4 April 2005 made between CE Electric UK
Funding
Company, the subsidiaries of CE Electric UK Funding Company listed
in Part
1 of Schedule 1, Lloyds TSB Bank plc and The Royal Bank of Scotland
plc
(incorporated by reference to exhibit 99.1 to MidAmerican Energy
Holdings
Company’s Current Report on Form 8-K dated April 20,2005).
10.63
Trust
Deed made on 5 May 2005 between Northern Electric Finance plc,
Northern Electric Distribution Limited, Ambac Assurance UK Limited
and
HSBC Trustee (C.I.) Limited (incorporated by reference to Exhibit
99.1 to
MidAmerican Energy Holdings Company’s Quarterly Report on Form 10-Q for
the quarter ended March 31, 2005).
10.64
Reimbursement
and Indemnity Agreement dated 5 May 2005 between Northern Electric
Finance plc, Northern Electric Distribution Limited and Ambac Assurance
UK
Limited (incorporated by reference to Exhibit 99.2 to MidAmerican
Energy
Holdings Company’s Quarterly Report on Form 10-Q for the quarter ended
March 31, 2005).
10.65
Trust
Deed made on 5 May 2005 between Yorkshire Electricity Distribution
plc, Ambac Assurance UK Limited and HSBC Trustee (C.I.) Limited
(incorporated by reference to Exhibit 99.3 to MidAmerican Energy
Holdings
Company’s Quarterly Report on Form 10-Q for the quarter ended
March 31, 2005).
10.66
Reimbursement
and Indemnity Agreement dated 5 May 2005 between Yorkshire
Electricity Distribution plc and Ambac Assurance UK Limited (incorporated
by reference to Exhibit 99.4 to MidAmerican Energy Holdings Company’s
Quarterly Report on Form 10-Q for the quarter ended March 31,2005).
10.67
Supplemental
Trust Deed made on 5 May 2005 between CE Electric UK Funding Company,
Ambac Assurance UK Limited and The Law Debenture Trust Corporation
plc
(incorporated by reference to Exhibit 99.5 to MidAmerican Energy
Holdings
Company’s Quarterly Report on Form 10-Q for the quarter ended
March 31, 2005).
10.68
Second
Supplemental Agreement to Insurance and Indemnity Agreement made
on
5 May 2005 between CE Electric UK Funding Company and Ambac Assurance
UK Limited (incorporated by reference to Exhibit 99.6 to MidAmerican
Energy Holdings Company’s Quarterly Report on Form 10-Q for the quarter
ended March 31, 2005).
10.69
Stock
Purchase Agreement, dated as of May 23, 2005, by and among Scottish
Power
plc, PacifiCorp Holdings, Inc. and MidAmerican Energy Holdings Company
(incorporated by reference to exhibit 99.1 to MidAmerican Energy
Holdings
Company’s Current Report on Form 8-K dated May 24,2005).
10.70
Credit
Agreement, dated August 26, 2005, by and among MidAmerican Energy
Holdings
Company, as Borrower, The Banks and Other Financial Institutions
Parties
Hereto, as Banks, JPMorgan Chase Bank, N.A., as L/C Issuer, Union
Bank of
California, N.A., as Administrative Agent, The Royal Bank of Scotland
PLC,
as Syndication Agent, and ABN Amro Bank N.V., JPMorgan Chase Bank,
N.A.
and BNP
Paribas
as
Co-Documentation Agents (incorporated by reference to exhibit 99.1
to
MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated
September 1, 2005).
135
Exhibit
No.
10.71
Credit
Agreement among MidAmerican Energy Company, the Lending Institutions
Party
Hereto, as Banks, Union Bank of California, N.A., as Syndication
Agent,
and JPMorgan Chase Bank, N.A. as Administrative Agent, dated as of
November 18, 2004 Union Bank of California, N.A. and J.P.Morgan
Securities, Inc. Co-Lead Arrangers and Co-Book Runners (incorporated
by
reference to Exhibit 10.1 to the MidAmerican Energy Company Annual
Report
on Form 10-K for the year ended December 31,2005).
10.72
Equity
Commitment Agreement, dated as of March 1, 2006, between Berkshire
Hathaway, Inc. and MidAmerican Energy Holdings Company.
14.1
MidAmerican
Energy Holdings Company Code of Ethics for Chief Executive Officer,
Chief
Financial Officer and Other Covered Officers (incorporated by reference
to
Exhibit 14.1 to MidAmerican Energy Holdings Company’s Annual Report on
Form 10-K for the year ended December 31, 2003).
