Document/ExhibitDescriptionPagesSize 1: 10-K Midamerican Energy Holdings Company Form 10-K HTML 2.86M
2: EX-10.1 Amended and Restated Employment Agreement HTML 87K
6: EX-10.10 First Amended and Restated Supplemental Retirement HTML 113K
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7: EX-10.11 Long-Term Incentive Partnership Plan as Amended HTML 130K
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8: EX-10.12 Summary of Key Terms of Compensation Arrangements HTML 13K
3: EX-10.3 Amended and Restated Employment Agreement HTML 82K
4: EX-10.5 Amended and Restated Employment Agreement HTML 73K
5: EX-10.9 Executive Voluntary Deferred Compensation Plan HTML 83K
9: EX-21.1 Subsidiaries of the Registrant HTML 78K
10: EX-23.1 Consent of Deloitte & Touche LLP HTML 9K
11: EX-24.1 Power of Attorney HTML 13K
12: EX-31.1 Section 302 Certification - Principal Executive HTML 19K
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Officer
(Former
name or former address and former fiscal year, if changed since last
report)
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 No
T
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 T No
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of 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, a non-accelerated filer or a smaller reporting company. See
definitions of “large accelerated filer,”“accelerated filer,” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large
accelerated filer
Accelerated
filer
Non-accelerated
filer T
Smaller
reporting company
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 January 31, 2008, 74,859,001
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. Forward looking
statements can typically be identified by the use of forward-looking words, such
as “may,”“could,”“project,”“believe,”“anticipate,”“expect,”“estimate,”“continue,”“intend,”“potential,”“plan,”“forecast,” and similar terms. These
statements are based upon 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;
·
changes
in governmental, legislative or regulatory requirements affecting the
Company or the electric or gas utility, pipeline or power generation
industries;
·
changes
in, and compliance with, environmental laws, regulations, decisions and
policies that could increase operating and capital improvement costs,
reduce plant output and/or delay plant
construction;
·
the
outcome of general rate cases and other proceedings conducted by
regulatory commissions or other governmental and legal
bodies;
·
changes
in economic, industry or weather conditions, as well as demographic
trends, that could affect customer growth and usage or supply of
electricity and gas;
·
changes
in prices and availability for both purchases and sales of wholesale
electricity, coal, natural gas, other fuel sources and fuel transportation
that could have a significant impact on energy
costs;
·
financial
condition and creditworthiness of significant customers and
suppliers;
·
changes
in business strategy or development
plans;
·
availability,
terms and deployment of capital;
·
performance
of generation facilities, including unscheduled outages or
repairs;
·
risks
relating to nuclear generation;
·
the
impact of derivative instruments used to mitigate or manage volume and
price risk and interest rate risk and changes in the commodity prices,
interest rates and other conditions that affect the value of the
derivatives;
·
the
impact of increases in healthcare costs, changes in interest rates,
mortality, morbidity and investment performance on pension and other
postretirement benefits expense, as well as the impact of changes in
legislation on funding
requirements;
·
changes
in MidAmerican Energy Holdings Company’s (“MEHC”) and its subsidiaries’
credit ratings;
·
unanticipated
construction delays, changes in costs, receipt of required permits and
authorizations, ability to fund capital projects and other factors that
could affect future generation plants and infrastructure
additions;
·
the
impact of new accounting pronouncements or changes in current accounting
estimates and assumptions on financial
results;
·
the
Company’s ability to successfully integrate future acquired operations
into the Company’s business;
·
other
risks or unforeseen events, including litigation and wars, the effects of
terrorism, embargos and other catastrophic events;
and
·
other
business or investment considerations that may be disclosed from time to
time in filings with the United States Securities and Exchange Commission
(“SEC”) or in other publicly disseminated written
documents.
Further
details of the potential risks and uncertainties affecting the Company are
described in MEHC’s filings with the SEC, including Item 1A and other
discussions contained in this Form 10-K. The 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”) is a holding company which owns subsidiaries
that are principally engaged in energy businesses. MEHC and its subsidiaries are
referred to as the “Company.” MEHC is a consolidated subsidiary of Berkshire
Hathaway Inc. (“Berkshire Hathaway”). The balance of MEHC’s common stock is
owned by a private investor group comprised of Mr. Walter Scott, Jr.
(along with family members and related entities), who is a member of MEHC’s
Board of Directors, Mr. David L. Sokol, MEHC’s Chairman and Chief
Executive Officer, and Mr. Gregory E. Abel, MEHC’s President and Chief
Operating Officer. As of January 31, 2008, Berkshire Hathaway, Mr. Scott
(along with family members and related entities), Mr. Sokol and
Mr. Abel owned 88.2%, 11.0%, -% and 0.8%, respectively, of MEHC’s voting
common stock and held diluted ownership interests of 87.4%, 10.9%, 0.7% and
1.0%, respectively.
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 MEHC’s
common equity upon any requests authorized from time to time by MEHC’s Board of
Directors. The proceeds of any such equity contribution shall only be used for
the purpose of (a) paying when due MEHC’s debt obligations and (b) funding the
general corporate purposes and capital requirements of MEHC’s regulated
subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such
request in minimum increments of at least $250 million pursuant to one or
more drawings authorized by MEHC’s Board of Directors. The funding of each
drawing will be made by means of a cash equity contribution to us in exchange
for additional shares of MEHC’s common stock. The Berkshire Equity Commitment
will expire on February 28, 2011.
The
Company’s operations are organized and managed as eight distinct platforms:
PacifiCorp, MidAmerican Funding, LLC (“MidAmerican Funding”) (which primarily
includes MidAmerican Energy Company (“MidAmerican Energy”)), Northern Natural
Gas Company (“Northern Natural Gas”), Kern River Gas Transmission Company (“Kern
River”), CE Electric UK Funding Company (“CE Electric UK”) (which primarily
consists of Northern Electric Distribution Limited (“Northern Electric”) and
Yorkshire Electricity Distribution plc (“Yorkshire Electricity”)), CalEnergy
Generation-Foreign (owning a majority interest in the Casecnan project in the
Philippines), CalEnergy Generation-Domestic (owning interests in independent
power projects in the United States), and HomeServices of America, Inc.
(collectively with its subsidiaries, “HomeServices”). Refer to Note 23 of
Notes to Consolidated Financial Statements included in Item 8 of this
Form 10-K for additional segment information regarding the Company’s
platforms. Through these platforms, the Company owns and operates an electric
utility company in the Western United States, a combined electric and natural
gas utility company in the Midwestern United States, two interstate natural gas
pipeline companies in the United States, two electricity distribution companies
in Great Britain, a diversified portfolio of independent power projects and the
second-largest residential real estate brokerage firm in the United
States.
MEHC’s
energy subsidiaries generate, transmit, store, distribute and supply energy.
Approximately 91% of the Company’s operating income in 2007 was generated from
rate-regulated businesses. As of December 31, 2007, MEHC’s electric and
natural gas utility subsidiaries served approximately 6.2 million
electricity customers and end users and approximately 0.7 million natural
gas customers. MEHC’s natural gas pipeline subsidiaries operate interstate
natural gas transmission systems that transported approximately 8% of the total
natural gas consumed in the United States in 2007. These pipeline subsidiaries
have approximately 17,000 miles of pipeline in operation and a design capacity
of 6.9 billion cubic feet of natural gas per day. As of December 31,2007, the Company had interests in approximately 17,000 net owned megawatts
(“MW”) of power generation facilities in operation and under construction,
including approximately 16,000 net owned MW in facilities that are part of the
regulated asset base of its electric utility businesses and approximately 1,000
net owned MW in non-utility power generation facilities. The majority of the
Company’s non-utility power generation facilities have long-term contracts for
the sale of energy and/or capacity from the facilities.
MEHC’s
principal executive offices are located at 666 Grand Avenue, Suite 500, DesMoines, Iowa50309-2580 and its telephone number is (515) 242-4300. MEHC was
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.
PacifiCorp
On
March 21, 2006, a wholly owned subsidiary of MEHC acquired 100% of the
common stock of PacifiCorp, a public utility company, from a wholly owned
subsidiary of Scottish Power plc (“ScottishPower”) for a cash purchase price of
$5.12 billion, which includes direct transaction costs. The results of
PacifiCorp’s operations are included in the Company’s results beginning
March 21, 2006. In connection with the 2006 acquisition of PacifiCorp,
PacifiCorp and MEHC agreed to certain regulatory commitments as discussed in
Item 7 of this Form 10-K.
General
PacifiCorp
serves approximately 1.7 million regulated retail electric customers in its
service territories in portions of the states of Utah, Oregon, Wyoming,
Washington, Idaho and California. The combined service territory’s diverse
regional economy ranges from rural, agricultural and mining areas to urban,
manufacturing and government service centers. No single segment of the economy
dominates the service territory, which helps mitigate PacifiCorp’s exposure to
economic fluctuations. In the eastern portion of the service territory, mainly
consisting of Utah, Wyoming and southeast Idaho, the principal industries are
manufacturing, health services, recreation, agriculture and mining or extraction
of natural resources. In the western portion of the service territory, mainly
consisting of Oregon, southeastern Washington and northern California, the
principal industries are agriculture and manufacturing, with forest products,
food processing, technology and primary metals being the largest industrial
sectors. In addition to retail sales, PacifiCorp sells electric energy to other
utilities, municipalities and marketers. These sales are referred to as
wholesale sales.
PacifiCorp’s
regulated electric operations are conducted under franchise agreements,
certificates, permits and licenses obtained from state and local authorities.
The average term of these franchise agreements is approximately 30 years,
although their terms range from five years to indefinite.
On
May 10, 2006, the PacifiCorp Board of Directors elected to change
PacifiCorp’s fiscal year-end from March 31 to December 31. Therefore,
in the following pages, the nine-month period ended December 31, 2006
information covers the transition period beginning April 1, 2006 and ending
December 31, 2006.
Electric
Operations
Customers
The
percentages of electricity sold (measured in MWh) to retail and wholesale
customers, by class of customer, and the average number of retail customers (in
millions) were as follows:
Customer
demand is typically highest in the summer across PacifiCorp’s service territory
when air-conditioning and irrigation systems are heavily used. Customer demand
also peaks in the winter months in the western portion of PacifiCorp’s service
territory primarily due to heating requirements and in the eastern portion due
to other electricity demands.
For
residential customers, within a given year, weather conditions are the dominant
cause of usage variations from normal seasonal patterns. Strong Utah residential
growth over the last several years and increasing installations of central air
conditioning systems have contributed to increased summer peak load growth.
During the year ended December 31, 2007, PacifiCorp’s peak load was
9,775 MW in the summer and 8,650 MW in the winter. During the year
ended December 31, 2007, PacifiCorp’s average load was 7,185 MW for
the summer and 7,028 MW for the winter.
Power and Fuel
Supply
The
estimated percentages of PacifiCorp’s total energy requirements supplied by its
generation facilities and through long- and short-term contracts or spot market
purchases were as follows:
The
percentage of PacifiCorp’s energy requirements generated by its facilities will
vary from year to year and is determined by factors such as planned and
unplanned outages, the availability and price of coal and natural gas,
precipitation and snowpack levels, other weather-related impacts, environmental
considerations and the market price of electricity. PacifiCorp manages certain
risks relating to its natural gas supply requirements and its wholesale
transactions by entering into various financial derivative instruments,
including forward purchases and sales, swaps and options. Refer to Item 7A
included in this Form 10-K for a discussion of commodity price risk and
derivative instruments.
Mines
owned or leased by PacifiCorp supplied 31% of PacifiCorp’s total coal
requirements during the year ended December 31, 2007 and the nine-month
period ended December 31, 2006, compared to 32% during the year ended
March 31, 2006. The remaining coal requirements are acquired through long-
and short-term third party contracts. PacifiCorp’s mines are located adjacent to
many of its coal-fired generating facilities, which significantly reduces
overall transportation costs included in fuel expense. In an effort to lower
costs and obtain better quality coal, the Jim Bridger mine developed an
underground mine to access 57 million tons of PacifiCorp’s coal reserves.
Sustained operations at the underground mine commenced in March 2007 and
production continues at its surface operations. The life of the underground mine
is expected to be approximately 15 years.
6
Recoverable
coal reserves as of December 31, 2007, based on PacifiCorp’s most recent
engineering studies, were as follows (in millions):
Location
Plant
Served
Mining
Method
Recoverable
Tons
Craig,
CO
Craig
Surface
47
(1)
Huntington
& Castle Dale, UT
Huntington
and Hunter
Underground
45
(2)
Rock
Springs, WY
Jim
Bridger
Surface/Underground
140
(3)
232
(1)
These
coal reserves are leased and mined by Trapper Mining, Inc., a Delaware
non-stock corporation operated on a cooperative basis, in which PacifiCorp
has an ownership interest of 21%.
(2)
These
coal reserves are leased by PacifiCorp and mined by a wholly owned
subsidiary of PacifiCorp.
(3)
These
coal reserves are leased and mined by Bridger Coal Company, a joint
venture between Pacific Minerals, Inc. (“PMI”) and a subsidiary of Idaho
Power Company. PMI, a wholly owned subsidiary of PacifiCorp, has a
two-thirds interest in the joint venture. The amount included above
represents only PacifiCorp’s two-thirds interest in the coal
reserves.
Coal
reserve estimates are subject to adjustment as a result of the development of
additional engineering and geological data, new mining technology and changes in
regulation and economic factors affecting the utilization of such reserves.
PacifiCorp believes that the coal reserves available to the Craig, Huntington,
Hunter and Jim Bridger plants, together with coal available under both long- and
short-term contracts with external suppliers to supply its remaining plants,
will be substantially sufficient to provide these plants with fuel for their
currently expected useful lives. To meet applicable standards, PacifiCorp blends
coal mined from its owned mines with contracted coal, and utilizes electricity
plant technologies for controlling sulfur dioxide and other
emissions.
Recoverability
by surface mining methods typically ranges from 90% to 95%. Recoverability by
underground mining techniques ranges from 50% to 70%. Most of PacifiCorp’s coal
reserves are held pursuant to leases from the federal government through the
Bureau of Land Management and from certain states and private parties. The
leases generally have multi-year terms that may be renewed or extended only with
the consent of the lessor and require payment of rents and
royalties.
PacifiCorp
uses natural gas as fuel for its combined- and simple-cycle natural gas-fired
plants. Oil and natural gas are also used for igniter fuel and to fuel
generation for transmission support and standby purposes. These sources are
presently in adequate supply and available to meet PacifiCorp’s
needs.
PacifiCorp
operates the majority of its hydroelectric generating portfolio under long-term
licenses from the Federal Energy Regulatory Commission (“FERC”) with terms of 30
to 50 years. Several of PacifiCorp’s long-term operating licenses have expired
and they are operating under temporary annual licenses issued by the FERC until
new long-term operating licenses are issued. The amount of electricity
PacifiCorp is able to generate from its hydroelectric plants depends on a number
of factors, including snowpack in the mountains upstream of its hydroelectric
plants, reservoir storage, precipitation in its watersheds, plant availability
and restrictions imposed by oversight bodies due to competing water management
objectives. When these factors are favorable, PacifiCorp can generate more
electricity using its hydroelectric plants. When these factors are unfavorable,
PacifiCorp must increase its reliance on more expensive thermal plants and
purchased electricity.
PacifiCorp
is pursuing renewable resources as a viable, economic and environmentally
prudent means of generating electricity. The benefits of energy from renewable
resources include low to no emissions and typically little or no fossil fuel
requirements. The intermittent nature of some renewable resources, such as wind,
is complemented by PacifiCorp’s other generating resources, which are important
to integrating intermittent wind resources into the electric
system.
7
In
addition to its portfolio of generating plants, PacifiCorp purchases electricity
in the wholesale markets to meet its retail load and long-term wholesale
obligations, for system balancing requirements and to enhance the efficient use
of its generating capacity over the long-term. PacifiCorp enters into wholesale
purchase and sale transactions to balance its electricity supply when generation
and retail loads are higher or lower than expected. Generation can vary with the
levels of outages, hydroelectric and wind conditions, operational factors and
transmission constraints. Retail load can vary with the weather, distribution
system outages, consumer trends and the level of economic activity. In addition,
PacifiCorp purchases electricity in the wholesale markets when it is more
economical than generating it at its own plants. PacifiCorp may also sell into
the wholesale market excess electricity arising from imbalances between
generation and retail load obligations, subject to pricing and transmission
constraints. Many of PacifiCorp’s purchased electricity contracts have
fixed-price components, which provide some protection against price
volatility.
PacifiCorp’s
wholesale transactions are integral to its retail business, providing for a
balanced and economically hedged position and enhancing the efficient use of its
generating capacity over the long term. Historically, PacifiCorp has been able
to purchase electricity from utilities in the Western United States for its own
requirements. Delivery of these purchases is conducted through PacifiCorp and
third-party transmission systems, which connect with market hubs in the Pacific
Northwest to provide access to normally low-cost hydroelectric generation, and
in the Southwestern United States to provide access to normally higher-cost
fossil-fuel generation. The transmission system is available for common use
consistent with open-access regulatory requirements.
8
The
following table sets out certain information concerning PacifiCorp’s power
generating facilities as of December 31, 2007:
Facility
Net
Capacity
Net
MW
Location
Energy
Source
Installed
(MW)
(1)
Owned
(1)
COAL:
Jim
Bridger
Rock
Springs, WY
Coal
1974-1979
2,120
1,414
Huntington
Huntington,
UT
Coal
1974-1977
895
895
Dave
Johnston
Glenrock,
WY
Coal
1959-1972
762
762
Naughton
Kemmerer,
WY
Coal
1963-1971
700
700
Hunter
No. 1
Castle
Dale, UT
Coal
1978
430
403
Hunter
No. 2
Castle
Dale, UT
Coal
1980
430
259
Hunter
No. 3
Castle
Dale, UT
Coal
1983
460
460
Cholla
No. 4
Joseph
City, AZ
Coal
1981
380
380
Wyodak
Gillette,
WY
Coal
1978
335
268
Carbon
Castle
Gate, UT
Coal
1954-1957
172
172
Craig
Nos. 1 and 2
Craig,
CO
Coal
1979-1980
856
165
Colstrip
Nos. 3 and 4
Colstrip,
MT
Coal
1984-1986
1,480
148
Hayden
No. 1
Hayden,
CO
Coal
1965-1976
184
45
Hayden
No. 2
Hayden,
CO
Coal
1965-1976
262
33
9,466
6,104
NATURAL
GAS:
Lake
Side
Vineyard,
UT
Natural
gas/Steam
2007
548
548
Currant
Creek
Mona,
UT
Natural
gas/Steam
2005-2006
540
540
Hermiston
Hermiston,
OR
Natural
gas/Steam
1996
474
237
Gadsby
Steam
Salt
Lake City, UT
Natural
gas
1951-1952
235
235
Gadsby
Peakers
Salt
Lake City, UT
Natural
gas
2002
120
120
Little
Mountain
Ogden,
UT
Natural
gas
1972
14
14
1,931
1,694
HYDROELECTRIC:
Swift
No. 1
Cougar,
WA
Lewis
River
1958
264
264
Merwin
Ariel,
WA
Lewis
River
1931-1958
151
151
Yale
Amboy,
WA
Lewis
River
1953
163
163
Five
North Umpqua Plants
Toketee
Falls, OR
N.
Umpqua River
1950-1956
141
141
John
C. Boyle
Keno,
OR
Klamath
River
1958
83
83
Copco
Nos. 1 and 2
Hornbrook,
CA
Klamath
River
1918-1925
62
62
Clearwater
Nos. 1 and 2
Toketee
Falls, OR
Clearwater
River
1953
49
49
Grace
Grace,
ID
Bear
River
1908-1923
33
33
Prospect
No. 2
Prospect
OR
Rogue
River
1928
36
36
Cutler
Collingston,
UT
Bear
River
1927
29
29
Oneida
Preston,
ID
Bear
River
1915-1920
28
28
Iron
Gate
Hornbrook,
CA
Klamath
River
1962
19
19
Soda
Soda
Springs, ID
Bear
River
1924
14
14
28
minor hydroelectric plants
Various
Various
1895-1990
86
86
1,158
1,158
WIND:
Foote
Creek
Arlington,
WY
Wind
1997
41
33
Leaning
Juniper 1
Arlington,
OR
Wind
2006
101
101
Marengo
Dayton,
WA
Wind
2007
140
140
282
274
OTHER:
Camas
Co-Gen
Camas,
WA
Black
liquor
1996
22
22
Blundell
Milford,
UT
Geothermal
1984,
2007
34
34
56
56
Total
Available Generating Capacity
12,893
9,286
PROJECTS
UNDER CONSTRUCTION/DEVELOPMENT(2):
Various
wind projects
Various
Wind
2008
461
461
13,354
9,747
(1)
Facility
Net Capacity (MW) represents the total capability of a generating unit as
demonstrated by actual operating or test experience, less power generated
and used for auxiliaries and other station uses, and is determined using
average annual temperatures. Net MW Owned indicates current legal
ownership.
9
(2)
Facility
Net Capacity (MW) and Net MW Owned for projects under construction each
represent the estimated nameplate ratings. A generator’s nameplate rating
is its full-load capacity under normal operating conditions as defined by
the manufacturer. The estimated installation date for the
projects is by the end of 2008.
Future
Generation
As
required by certain state regulations, PacifiCorp uses an Integrated Resource
Plan (“IRP”) to develop a long-term view of prudent future actions required to
help ensure that PacifiCorp continues to provide reliable and cost-effective
electric service to its customers. The IRP process identifies the amount and
timing of PacifiCorp’s expected future resource needs and an associated optimal
future resource mix that accounts for planning uncertainty, risks, reliability
impacts and other factors. The IRP is a coordinated effort with stakeholders in
each of the six states where PacifiCorp operates. When the IRP is filed, each
state commission with IRP adequacy rules judges whether the IRP reasonably meets
its standards and guidelines. PacifiCorp requests “acknowledgement” of its IRP
filing from the Utah Public Service Commission (“UPSC”), the Oregon Public
Utility Commission (“OPUC”), Idaho Public Utility Commission (“IPUC”) and the
Washington Utilities and Transportation Commission (“WUTC”) pursuant to those
states’ IRP adequacy rules. The IRP can be used as evidence by parties in
rate-making or other regulatory proceedings. PacifiCorp files its IRP on a
biennial basis. Additionally, PacifiCorp is required to file draft requests for
proposals with the UPSC, the OPUC and the WUTC prior to issuance to the
market.
In
May 2007, PacifiCorp released its 2007 IRP. The 2007 IRP identified a need
for approximately 3,171 MW of additional resources by summer 2016 to
satisfy the difference between projected retail load obligations and available
resources. PacifiCorp plans to meet this need through demand response and energy
efficiency programs; the construction or purchase of additional generation,
including cost-effective renewable energy, combined heat and power, and thermal
generation; and wholesale electricity transactions to make up for the remaining
difference between retail load obligations and available resources. PacifiCorp
is currently seeking acknowledgement of its 2007 IRP from state regulators and
expects the acknowledgement process to be complete in 2008.
Demand-side
Management
PacifiCorp
has provided a comprehensive set of demand-side management programs to its
customers since the 1970s. The programs are designed to reduce growth in peak
load and energy consumption. Current programs offer customers services such as
energy engineering and audits, as well as rebates for high efficiency equipment
such as lighting, heating and cooling equipment, weatherization, motors and
process equipment and systems; new construction; and load management
(curtailment) programs for large commercial and industrial customers and
residential customers whose central air conditioners are controlled during
summer peak load periods. Subject to random prudence reviews, state regulations
allow for contemporaneous recovery of costs incurred for demand-side management
programs and services through the energy efficiency service charges to all
retail electric customers. In 2007, $53 million was expended on the
demand-side management programs in PacifiCorp’s six-state service area,
resulting in an estimated 300,000 MWh of first year energy savings and
170 MW of peak load management.
Transmission and
Distribution
PacifiCorp
operates one balancing authority area in the western portion of its service
territory, and one balancing authority area in the eastern portion of its
service territory. A balancing authority area is a geographic area with electric
systems that control generation to maintain schedules with other balancing
authority areas and ensure reliable operations. In operating the balancing
authority areas, PacifiCorp is responsible for continuously balancing electric
supply and demand by dispatching generating resources and interchange
transactions so that generation internal to the balancing authority area, plus
net imported power, matches customer loads. PacifiCorp also schedules deliveries
over its transmission system in accordance with FERC requirements.
PacifiCorp’s
transmission system is part of the Western Interconnection, the regional grid in
the West. The Western Interconnection includes the interconnected transmission
systems of 14 western states, two Canadian provinces and parts of Mexico that
make up the Western Electric Coordinating Council (“WECC”). PacifiCorp’s
transmission system, together with contractual rights on other transmission
systems, enables PacifiCorp to integrate and access generation resources to meet
its customer load requirements.
10
PacifiCorp’s
wholesale transmission services are regulated by the FERC under cost-based
regulation subject to PacifiCorp’s Open Access Transmission Tariff (“OATT”). In
accordance with the OATT, PacifiCorp offers several transmission services to
wholesale customers:
·
Network
transmission service (guaranteed service that integrates generating
resources to serve retail loads);
·
Long-
and short-term firm point-to-point transmission service (guaranteed
service with fixed delivery and receipt points);
and
·
Non-firm
point-to-point service (“as available” service with fixed delivery and
receipt points).
These
services are offered on a non-discriminatory basis, which means that all
potential customers are provided an equal opportunity to access the transmission
system. PacifiCorp’s transmission business is managed and operated independently
from the generating and marketing business in accordance with the FERC Standards
of Conduct. Transmission costs are not separated from, but rather are “bundled”
with, generation and distribution costs in retail rates approved by state
regulatory commissions.
The
electric transmission system of PacifiCorp as of December 31, 2007 included
approximately 15,700 miles of transmission lines. As of December 31,2007, PacifiCorp owned approximately 900 substations.
In May
2007, PacifiCorp announced plans to build in excess of 1,200 miles of new
high-voltage transmission lines primarily in Wyoming, Utah, Idaho, Oregon and
the desert Southwest. The estimated $4.1 billion investment plan includes
projects that will address customers’ increasing electric energy use, improve
system reliability and deliver wind and other renewable generation resources to
more customers throughout PacifiCorp’s six-state service area and the Western
United States. These transmission lines are expected to be placed into service
beginning 2010 and continuing through 2014. PacifiCorp is also collaborating
with other utilities to address transmission needs, including new development
and system reliability.
MidAmerican
Energy
General
MidAmerican
Energy, an indirect wholly owned subsidiary of MEHC, is a public utility company
headquartered in Iowa, which serves approximately 0.7 million regulated
retail electric customers and approximately 0.7 million regulated retail
and transportation natural gas customers. MidAmerican Energy is principally
engaged in the business of generating, transmitting, distributing and selling
electricity and in distributing, selling and transporting natural gas.
MidAmerican Energy distributes electricity at retail in Council Bluffs, Des
Moines, Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities
(Davenport and Bettendorf, Iowa and Rock Island, Moline and East Moline,
Illinois); and a number of adjacent communities and areas. It also distributes
natural gas at retail in Cedar Rapids, Des Moines, Fort Dodge, Iowa City, Sioux
City and Waterloo, Iowa; the Quad Cities; Sioux Falls, South Dakota; and a
number of adjacent communities and areas. Additionally, MidAmerican Energy
transports natural gas through its distribution system for a number of end-use
customers who have independently secured their supply of natural gas. In
addition to retail sales and natural gas transportation, MidAmerican Energy
sells electric energy and natural gas to other utilities, municipalities and
marketers. These sales are referred to as wholesale sales.
MidAmerican
Energy’s regulated electric and gas operations are conducted under franchise
agreements, certificates, permits and licenses obtained from state and local
authorities. The franchise agreements, with various expiration dates, are
typically for 25-year terms.
MidAmerican
Energy has a diverse customer base consisting of residential, agricultural, and
a variety of commercial and industrial customer groups. Some of the larger
industrial groups served by MidAmerican Energy include the processing and sales
of food products; the manufacturing, processing and fabrication of primary
metals; farm and other non-electrical machinery; real estate; and cement and
gypsum products.
MidAmerican
Energy also conducts a number of nonregulated business activities in addition to
its traditional regulated electric and natural gas services, including
nonregulated electric and natural gas sales and gas income-sharing
arrangements. MidAmerican Energy’s nonregulated retail electric
marketing services provide electric supply services to retail customers
predominantly in Illinois, but also in Michigan and Maryland. During 2007,
MidAmerican Energy’s nonregulated retail electric marketing services expanded
significantly in Illinois as a result of that market becoming fully open to
competition. Effective January 1, 2007, the major electric distribution
companies in Illinois increased their purchases of energy on the open market due
to the expiration of contracts associated with electric industry restructuring
in Illinois. MidAmerican Energy’s nonregulated gas marketing services operate in
Iowa, Illinois, Michigan, South Dakota and Nebraska. MidAmerican Energy
purchases gas from producers and third party marketers and sells it directly to
commercial and industrial end-users. In addition, MidAmerican Energy manages gas
supplies for a number of smaller commercial end-users, which includes the sale
of gas to these customers to meet their supply requirements.
11
MidAmerican
Energy’s operating revenues were derived from the following business activities
during the years ended December 31:
2007
2006
2005
Regulated
electric
45%
52%
48%
Regulated
gas
28
32
42
Nonregulated
27
16
10
100%
100%
100%
Electric
Operations
Customers
The
percentages of electricity sold (measured in MWh) to retail and wholesale
customers, by class of customer, and the average number of retail customers (in
millions) as of and for the years ended December 31 were as
follows:
2007
2006
2005
Residential
18%
18%
21%
Commercial
12
13
15
Industrial
27
28
28
Wholesale
38
36
31
Other
5
5
5
100%
100%
100%
Total
average retail customers
0.7
0.7
0.7
The
percentages of electricity sold (measured in MWh), by jurisdiction, for the
years ended December 31 were as follows:
2007
2006
2005
Iowa
90%
90%
89%
Illinois
9
9
10
South
Dakota
1
1
1
100%
100%
100%
There are
seasonal variations in MidAmerican Energy’s electric business that are
principally related to the use of electricity for air conditioning. In general,
35-40% of MidAmerican Energy’s regulated electric revenues are reported in the
months of June, July, August and September.
The
annual hourly peak demand on MidAmerican Energy’s electric system usually occurs
as a result of air conditioning use during the cooling season. On
August 13, 2007, retail customer usage of electricity caused a new record
hourly peak demand of 4,240 MW on MidAmerican Energy’s electric system, an
increase of 104 MW from the previous record set in 2006.
12
Power and Fuel
Supply
The
estimated percentages of MidAmerican Energy’s total energy requirements supplied
by its generation plants and through long- and short-term contracts or spot
market purchases for the years ended December 31 were as
follows:
Energy
purchased-short-term contracts and spot market
19
21
13
100%
100%
100%
The share
of MidAmerican Energy’s energy requirements generated by its plants will vary
from year to year and is determined by factors such as planned and unplanned
outages, the availability and price of fuels, weather, environmental
considerations and the market price of electricity.
MidAmerican
Energy is exposed to fluctuations in energy costs relating to retail sales in
Iowa and, effective January 1, 2007, in Illinois as it does not have fuel
adjustment clauses in those jurisdictions. In Illinois, base rates were adjusted
to include recoveries at average 2004/2005 energy cost levels beginning
January 1, 2007, and rate case approval is required for any base rate
changes. MidAmerican Energy may not petition for reinstatement of the Illinois
fuel adjustment clause until November 2011.
All of
the coal-fired generating stations operated by MidAmerican Energy are fueled by
low-sulfur, western coal from the Powder River Basin in northeast Wyoming and
southeast Montana. MidAmerican Energy’s coal supply portfolio includes multiple
suppliers and mines under short-term and multi-year agreements of varying terms
and quantities. MidAmerican Energy’s coal supply portfolio has a substantial
majority of its expected 2008 requirements under fixed-price contracts.
MidAmerican Energy regularly monitors the western coal market looking for
opportunities to enhance its coal supply portfolio.
MidAmerican
Energy has a long-term coal transportation agreement with Union Pacific Railroad
Company (“Union Pacific”). Under this agreement, Union Pacific delivers coal
directly to MidAmerican Energy’s George Neal and Walter Scott, Jr. Energy
Centers and to an interchange point with the Iowa, Chicago & Eastern
Railroad Corporation for short-haul delivery to the Louisa and Riverside Energy
Centers. MidAmerican Energy has the ability to use BNSF Railway Company for
delivery of a small amount of coal to the Walter Scott, Jr., Louisa and
Riverside Energy Centers should the need arise.
MidAmerican
Energy is a 25% joint owner of Quad Cities Generating Station Units 1 and 2
(“Quad Cities Station”), a nuclear power plant. Exelon Generation Company, LLC
(“Exelon Generation”), the 75% joint owner and the operator of Quad Cities
Station, is a subsidiary of Exelon Corporation. Approximately one-third of the
nuclear fuel assemblies in each reactor core at the Quad Cities Station is
replaced every 24 months. MidAmerican Energy has been advised by Exelon
Generation that the following requirements for the Quad Cities Station can be
met under existing supplies or commitments: uranium requirements through
2010 and partial requirements through 2015; uranium conversion requirements
through 2010 and partial requirements through 2011; enrichment requirements
through 2010 and partial requirements through 2017; and fuel fabrication
requirements through 2015. MidAmerican Energy has been advised by Exelon
Generation that it does not anticipate that it will have difficulty in
contracting for uranium, uranium conversion, enrichment or fabrication of
nuclear fuel needed to operate Quad Cities Station during this
time.
13
MidAmerican
Energy uses natural gas and oil as fuel for intermediate and peak demand
electric generation, igniter fuel, transmission support and standby purposes.
These sources are presently in adequate supply and available to meet MidAmerican
Energy’s needs. MidAmerican Energy manages a portion of its natural gas supply
requirements by entering into various financial derivative instruments,
including forward purchases and sales, futures, swaps and options. Refer to Item
7A included in this Form 10-K for a discussion of commodity price risk and
derivative instruments.
MidAmerican
Energy is pursuing renewable resources as a viable, economic and environmentally
prudent means of generating electricity. The benefits of energy from renewable
resources include low to no emissions and typically little or no fossil fuel
requirements. The intermittent nature of some renewable resources, such as wind,
is complemented by MidAmerican Energy’s other generating resources, which are
important to integrating intermittent wind resources into the electric
system.
14
The
following table sets out certain information concerning MidAmerican Energy’s
power generating facilities as of December 31, 2007:
Facility
Net
Capacity
Net
MW
Location
Energy
Source
Installed
(MW)(1)
Owned(1)
COAL:
George
Neal Unit No. 1
Sergeant
Bluff, IA
Coal
1964
135
135
George
Neal Unit No. 2
Sergeant
Bluff, IA
Coal
1972
289
289
George
Neal Unit No. 3
Sergeant
Bluff, IA
Coal
1975
515
371
George
Neal Unit No. 4
Salix,
IA
Coal
1979
644
261
Louisa
Muscatine,
IA
Coal
1983
700
616
Ottumwa
Ottumwa,
IA
Coal
1981
672
349
Riverside
Unit No. 3
Bettendorf,
IA
Coal
1925
5
5
Riverside
Unit No. 5
Bettendorf,
IA
Coal
1961
130
130
Walter
Scott, Jr. Unit No. 1
Council
Bluffs, IA
Coal
1954
45
45
Walter
Scott, Jr. Unit No. 2
Council
Bluffs, IA
Coal
1958
88
88
Walter
Scott, Jr. Unit No. 3
Council
Bluffs, IA
Coal
1978
690
546
Walter
Scott, Jr. Unit No. 4
Council
Bluffs, IA
Coal
2007
790
471
4,703
3,306
NATURAL
GAS:
Greater
Des Moines
Pleasant
Hill, IA
Natural
gas
2003-2004
497
497
Coralville
Coralville,
IA
Natural
gas
1970
64
64
Electrifarm
Waterloo,
IA
Natural
gas/Oil
1975-1978
199
199
Moline
Moline,
IL
Natural
gas
1970
64
64
Parr
Charles
City, IA
Natural
gas
1969
32
32
Pleasant
Hill
Pleasant
Hill, IA
Natural
gas/Oil
1990-1994
161
161
River
Hills
Des
Moines, IA
Natural
gas
1966-1967
117
117
Sycamore
Johnston,
IA
Natural
gas/Oil
1974
149
149
28
portable power modules
Various
Oil
2000
56
56
1,339
1,339
NUCLEAR:
Quad
Cities Unit No. 1
Cordova,
IL
Uranium
1972
872
218
Quad
Cities Unit No. 2
Cordova,
IL
Uranium
1972
868
217
1,740
435
WIND:
Century
Blairsburg,
IA
Wind
2005/2007
189
189
Intrepid
Schaller,
IA
Wind
2004-2005
176
176
Pomeroy
Pomeroy,
IA
Wind
2007
197
197
Victory
Westside,
IA
Wind
2006
99
99
661
661
OTHER:
Moline
Unit Nos. 1-4
Moline,
IL
Mississippi
River
1941
3
3
Total
Available Generating Capacity
8,446
5,744
PROJECTS
UNDER CONSTRUCTION/DEVELOPMENT(2):
Various
wind projects
Various
Wind
2008
462
462
8,908
6,206
(1)
Facility
Net Capacity (MW) represents total plant accredited net generating
capacity from the summer 2007 based on MidAmerican Energy’s accreditation
approved by the Mid-Continent Area Power Pool (“MAPP”), except for
wind-powered generation facilities, which are nameplate ratings. The 2007
summer accreditation of the wind-powered generation facilities in service
at that time totaled 67 MW and is considerably less than the
nameplate ratings due to the varying nature of wind. Additionally, the
Pomeroy wind-powered generation facility and 15 MW of the Century
wind-powered generation facility were placed in service in the fourth
quarter of 2007, which was after the 2007 summer accreditation. Net MW
Owned indicates MidAmerican Energy’s ownership of Facility Net
Capacity.
15
(2)
Facility
Net Capacity (MW) and Net MW Owned represent the estimated nameplate
ratings (MW) for wind-powered generation projects under
construction.
Future
Generation
On
April 18, 2006, the Iowa Utilities Board (“IUB”) approved a settlement
agreement between MidAmerican Energy and the Iowa Office of Consumer Advocate
(“OCA”) regarding ratemaking principles for additional wind-powered generation
capacity in Iowa to be installed in 2006 and 2007. A total of 222 MW
(nameplate ratings) of wind-powered generation was placed in service in 2006 and
2007 subject to that agreement, including 123 MW (nameplate ratings) in the
fourth quarter of 2007. On July 27, 2007, the IUB approved a settlement
agreement between MidAmerican Energy and the OCA in conjunction with MidAmerican
Energy’s ratemaking principles application for up to 540 MW (nameplate
ratings) of additional wind-powered capacity in Iowa to be placed in service on
or before December 31, 2013. MidAmerican Energy placed 78 MW (nameplate
ratings) of wind-powered generation into service in the fourth quarter of 2007
subject to the 2007 settlement agreement. Currently, MidAmerican Energy has
462 MW (nameplate ratings) under development or construction that it
expects will be placed in service by December 31, 2008. MidAmerican Energy
continues to pursue additional cost effective wind-powered
generation.
Demand-side
Management
MidAmerican
Energy has provided a comprehensive set of demand-side management programs to
its Iowa electric and gas customers since 1990. The programs are designed to
reduce growth in peak load and energy consumption. Current Iowa programs offer
customers incentives for energy audits and weatherization; rebates or below
market financing for high efficiency equipment such as lighting, heating and
cooling equipment, insulation, motors and process equipment and systems; new
construction; and load management (curtailment) programs for large commercial
and industrial customers and residential customers whose central air
conditioners are controlled during summer peak load periods. Subject to random
prudence reviews, Iowa regulation allows for contemporaneous recovery of costs
incurred for the demand-side management plan through an energy charge to all
retail electric and gas customers. In 2007, $51 million was expended on the
demand-side management programs in Iowa resulting in an estimated 268 MW
and 5,464 Dth/day of electric and gas peak demand reduction, respectively.
MidAmerican Energy Company plans to offer similar or comparable programs to
Illinois customers in 2008.
Transmission and
Distribution
MidAmerican
Energy is interconnected with utilities in Iowa and neighboring states.
MidAmerican Energy is also a party to an electric generation reserve sharing
pool and regional transmission group administered by MAPP. MAPP is a voluntary
association of electric utilities doing business in Minnesota, Nebraska, North
Dakota and the Canadian provinces of Saskatchewan and Manitoba and portions of
Iowa, Montana, South Dakota and Wisconsin. Its membership also includes power
marketers, regulatory agencies and independent power producers. MAPP performs
functions including administration of its short-term regional OATT, coordination
of regional planning and operations, and operation of the generation reserve
sharing pool.
MidAmerican
Energy can transact with a substantial number of parties through its
participation in MAPP and through its direct interconnections to the Midwest
Independent Transmission System Operator, Inc., Southwest Power Pool, Inc. and
PJM Interconnection, L.L.C. regional transmission organizations (“RTOs”) and
several other major transmission-owning utilities in the region. Under normal
operating conditions, MidAmerican Energy’s transmission system has adequate
capacity to deliver energy to MidAmerican Energy’s distribution system and to
export and import energy with other interconnected systems. The electric
transmission system of MidAmerican Energy as of December 31, 2007, included
approximately 2,200 miles of transmission lines. MidAmerican Energy’s
electric distribution system included approximately 400 substations as of
December 31, 2007.
16
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 areas to
MidAmerican Energy’s service territory under contracts with interstate
pipelines, stores it in various storage facilities to manage fluctuations in
system demand and seasonal pricing, and delivers it to customers through
MidAmerican Energy’s distribution system. MidAmerican Energy sells natural gas
and transportation services to end-use customers and natural gas to other
utilities, municipalities and marketers. MidAmerican Energy also transports
through its distribution system natural gas purchased independently by a number
of end-use customers. During 2007, 46% of total natural gas delivered through
MidAmerican Energy’s system for end use customers was under natural gas
transportation service.
The
percentages of regulated natural gas Dth, excluding transportation throughput,
by class of customer, for the years ended December 31 were as
follows:
2007
2006
2005
Residential
40%
37%
38%
Commercial(1)
19
18
18
Industrial(1)
4
4
4
Wholesale(2)
37
41
40
100%
100%
100%
(1)
Small
and large general service customers are classified primarily based on the
nature of their business and natural gas usage. Commercial customers are
business customers whose natural gas usage is principally for heating.
Industrial customers are business customers whose principal natural gas
usage is for their manufacturing processes.
(2)
Wholesale
generally includes other utilities, municipalities and marketers to whom
natural gas is sold at wholesale for eventual resale to ultimate end-use
customers.
The
percentages of regulated natural gas Dth, excluding transportation throughput,
by jurisdiction, for the years ended December 31 were as
follows:
2007
2006
2005
Iowa
77%
77%
77%
South
Dakota
12
12
12
Illinois
10
10
10
Nebraska
1
1
1
100%
100%
100%
MidAmerican
Energy is allowed to recover its cost of natural gas from all of its regulated
natural gas customers through purchased gas adjustment clauses. Accordingly, as
long as MidAmerican Energy is prudent in its procurement practices, MidAmerican
Energy’s regulated natural gas customers retain the risk associated with the
market price of natural gas. MidAmerican Energy uses several strategies designed
to reduce the market price risk for its natural gas customers, including the use
of storage gas and peak-shaving facilities, sharing arrangements to share
savings and costs with customers and short-term and long-term financial and
physical gas purchase agreements.
MidAmerican
Energy purchases natural gas supplies from producers and third-party marketers.
To enhance system reliability, a geographically diverse supply portfolio with
varying terms and contract conditions is utilized for the natural gas supplies.
MidAmerican Energy has rights to firm pipeline capacity to transport natural gas
to its service territory through direct interconnects to the pipeline systems of
several interstate natural gas pipeline systems, including Northern Natural Gas
(an affiliate company).
There are
seasonal variations in MidAmerican Energy’s natural gas business that are
principally due to the use of natural gas for heating. Typically, 45-55% of
MidAmerican Energy’s regulated natural gas revenue is reported in the months of
January, February, March and December.
17
MidAmerican
Energy utilizes leased gas storage to meet peak day requirements and to manage
the daily changes in demand due to changes in weather. The storage gas is
typically replaced during off-peak months when the demand for natural gas is
historically lower than during the heating season. In addition, MidAmerican
Energy also utilizes three liquefied natural gas (“LNG”) plants and two
propane-air plants to meet peak day demands in the winter. The storage and peak
shaving facilities reduce MidAmerican Energy’s dependence on natural gas
purchases during the volatile winter heating season. MidAmerican Energy can
deliver approximately 50% of its design day sales requirements from its storage
and peak shaving supply sources.
On
February 2, 1996, MidAmerican Energy had its highest peak-day delivery of
1,143,026 Dth. This peak-day delivery consisted of 88% traditional sales
service and 12% transportation service of customer-owned gas. As of
January 31, 2008, MidAmerican Energy’s 2007/2008 winter heating season
peak-day delivery of 1,019,111 Dth was reached on January 29, 2008.
This peak-day delivery included 73% traditional sales service and 27%
transportation service.
Natural
gas property consists primarily of natural gas mains and services pipelines,
meters, and related distribution equipment, including feeder lines to
communities served from natural gas pipelines owned by others. The gas
distribution facilities of MidAmerican Energy as of December 31, 2007
included approximately 21,800 miles of gas mains and service pipelines. In
addition, natural gas property includes three liquefied natural gas plants and
two propane-air plants.
Interstate
Pipeline Companies
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 owns and operates approximately 15,700 miles of natural gas
pipelines, consisting of approximately 6,700 miles of mainline transmission
pipelines and approximately 9,000 miles of branch and lateral pipelines,
with a Market Area design capacity of 5.1 Bcf per day. 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 seventh-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 and managed for operational
and system balancing purposes, 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 regulated tariff that is on file with the
FERC. The tariff rates are designed to allow it an opportunity to recover its
costs and generate a regulated return on equity.
Northern
Natural Gas’ pipeline system, which is interconnected with many interstate and
intrastate pipelines in the national grid system, consists of two distinct but
operationally integrated markets. Its traditional end-use and distribution
market area is at the northern part of the system, including delivery points in
Michigan, Illinois, Iowa, Minnesota, Nebraska, Wisconsin and South Dakota, which
Northern Natural Gas refers to as the Market Area. Its natural gas supply and
delivery service area is at the southern part of the system, including Kansas,
Oklahoma, Texas and New Mexico, which Northern Natural Gas refers to as the
Field Area.
Northern
Natural Gas’ pipeline system provides its customers access to natural gas from
key production areas, including the Hugoton, Permian, Anadarko and Rocky
Mountain basins in its Field Area and, through interconnections, the Rocky
Mountain and Canadian basins in its Market Area. In each of these areas,
Northern Natural Gas has numerous interconnecting receipt and delivery
points.
Northern
Natural Gas transports natural gas primarily to end-user and local distribution
markets in the Market Area. In 2007, 66% of Northern Natural Gas’ transportation
and storage revenue was generated from Market Area customer transportation
contracts. Its Market Area customers consist of utilities, other pipeline
companies, gas marketers and end-users. Northern Natural Gas directly serves 76
utilities, with seven large utilities, including MidAmerican Energy, accounting
for the majority of its Market Area transportation revenues in 2007. In turn,
these large utilities serve numerous residential, commercial and industrial
customers. In 2007, 85% of Northern Natural Gas’ transportation and storage
revenue for the Field and Market Areas was generated from reservation charges
under firm transportation and storage contracts and 67% of that revenue was from
utilities.
18
A
majority of Northern Natural Gas’ capacity in the Market Area is dedicated to
Market Area customers under firm transportation contracts. As of
December 31, 2007, 90% of Northern Natural Gas’ contracted firm
transportation capacity in the Market Area is contracted beyond 2009, and 45% is
contracted beyond 2015.
Northern
Natural Gas has commenced the Northern Lights expansion project, which is
expected to add approximately 650,100 Dth per day capacity to its Market Area.
This load is concentrated primarily in the Twin Cities area of Minnesota. The
majority of service for the first phase began in November 2007 with
entitlement consisting of approximately 422,900 Dth per day. Service for
the second phase is expected to begin by November 2008 with entitlement
consisting of approximately 91,200 Dth per day. Service for the next phase
is expected to begin by November 2009 with entitlement consisting of
approximately 136,000 Dth per day. A portion of Northern Lights consists of
service for new ethanol plants in the Market Area. Northern Natural Gas is
geographically well situated to serve the expanding ethanol industry and serves
approximately 31% of the nation’s ethanol manufacturing capacity. All of the
Northern Lights entitlement, except for 24,600 Dth per day in 2007 and
13,000 Dth per day in 2008, is associated with new service. All phases of
Northern Lights are entirely supported by executed precedent agreements and
contracts, the majority of which (91% by volume) have terms ranging from five to
twenty years. In total, the current Northern Lights expansion projects are
expected to require over $336 million in capital expenditures of which
$169 million has been incurred through December 31, 2007.
In the
Field Area, customers holding transportation capacity currently consist
primarily of marketers and producers. The majority of Northern Natural Gas’
Field Area firm transportation was previously conducted under long-term firm
transportation contracts, the majority of which expired on October 31,2007, with such volumes supplemented by volumes transported on a short-term firm
and interruptible basis. The majority of this entitlement has been recontracted
as of November 1, 2007 by marketers and producers, although the contracts
are generally for less than one year. Northern Natural Gas expects recontracting
to continue since Market Area customers need to purchase gas connected to its
Field Area in order to meet their growing demand requirements. Market Area
demand cannot presently be met without the purchase of supplies from the Field
Area. In 2007, 21% of Northern Natural Gas’ transportation and storage revenue
was generated from Field Area customer transportation contracts.
Northern
Natural Gas’ storage services are provided through the operation of one
underground storage field in Iowa, two underground storage facilities in Kansas
and one LNG storage peaking unit each in Garner, Iowa and Wrenshall, Minnesota.
The three underground natural gas storage facilities and two LNG storage peaking
units have a total firm service cycle capacity of approximately 65 Bcf and
over 1.9 Bcf per day of FERC-certificated peak delivery capability. These
storage facilities provide Northern Natural Gas with operational flexibility for
the daily balancing of its system and provide services to customers to meet
their winter peaking and year-round load swing requirements. In 2007, 13% of
Northern Natural Gas’ transportation and storage revenue was generated from
storage services.
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 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, and growing
supply areas, such as the Rocky Mountains, through Trailblazer Pipeline Company,
Kinder Morgan Interstate Gas Transmission, Cheyenne Plains Pipeline, Colorado
Interstate Gas Pipeline Company (“Colorado Interstate”) and, beginning in 2008,
Rockies Express Pipeline as well as from Canadian production areas through
Northern Border Pipeline Company, 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 local distribution companies (“LDCs”) revenue
by capitalizing on opportunities for shippers to reach additional markets, such
as Chicago, Illinois, other parts of the Midwest, and Texas, through
interconnections.
19
Kern
River
Kern
River, an indirect wholly owned subsidiary of MEHC, owns an interstate natural
gas transportation pipeline system consisting of approximately 1,700 miles
of pipeline, with an approximate design capacity of 1,755,575 Dth per day,
extending from supply areas in the Rocky Mountains to consuming markets in Utah,
Nevada and California. On May 1, 2003, Kern River placed into service
approximately 700-miles for an expansion project (the “2003 Expansion Project”),
which increased the design capacity of Kern River’s pipeline system by
885,575 Dth per day to its current capacity. Except for quantities of
natural gas owned for system operations, Kern River does not own the natural gas
that is transported through its system. Kern River’s transportation operations
are subject to a regulated tariff that is on file with the FERC. The tariff
rates are designed to allow it an opportunity to recover its costs and generate
a regulated return on equity.
Kern
River’s pipeline consists of two sections: the mainline section and the common
facilities. Kern River owns the entire mainline section, which extends from the
pipeline’s point of origination near Opal, Wyoming through the Central Rocky
Mountains area into Daggett, California. The mainline section consists of
approximately 700 miles of the original 36-inch diameter pipeline,
approximately 600 miles of 36-inch diameter loop pipeline related to the
2003 Expansion Project and approximately 100 miles of various laterals that
connect to the mainline.
The
common facilities consist of approximately 200-miles of the original pipeline
that extends from the point of interconnection with the mainline in Daggett to
Bakersfield, California and an additional approximately 100 miles related
to the 2003 Expansion Project. The common facilities are jointly owned by Kern
River (approximately 77% as of December 31, 2007) and Mojave Pipeline
Company (“Mojave”), a wholly owned subsidiary of El Paso Corporation,
(approximately 23% as of December 31, 2007), as tenants-in-common. Kern
River’s ownership percentage in the common facilities will increase or decrease
pursuant to the capital contributions made by the respective joint owners. Kern
River has exclusive rights to approximately 1,570,500 Dth per day of the
common facilities’ capacity, and Mojave has exclusive rights to 400,000 Dth
per day of capacity. Operation and maintenance of the common facilities are the
responsibility of Mojave Pipeline Operating Company, an affiliate of
Mojave.
Kern
River has year-round long-term firm natural gas transportation service
agreements for 1,755,575 Dth per day of capacity. Pursuant to these
agreements, the pipeline receives natural gas on behalf of shippers at
designated receipt points, transports the natural gas on a firm basis up to each
shipper’s maximum daily quantity and delivers thermally equivalent quantities of
natural gas at designated delivery points. Each shipper pays Kern River the
aggregate amount specified in its long-term firm natural gas transportation
service agreement and Kern River’s tariff, with such amount consisting primarily
of a fixed monthly reservation fee based on each shipper’s maximum daily
quantity and a commodity charge based on the actual amount of natural gas
transported.
These
year-round long-term firm natural gas transportation service agreements expire
between September 30, 2011 and April 30, 2018, and have a
weighted-average remaining contract term of almost nine years. Shippers on the
pipeline include major oil and gas companies or affiliates of such companies,
electric generating companies, energy marketing and trading companies, financial
institutions and natural gas distribution utilities which provide services in
Utah, Nevada and California. As of December 31, 2007, over 95% of the firm
capacity has primary delivery points in California, with the flexibility to
access secondary delivery points in Nevada and Utah.
Northern
Natural Gas and Kern River 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 and overall customer service. Industrial end-users often have the
ability to choose from alternative fuel sources, such as fuel oil and coal, in
addition to natural gas. Natural gas competes with other forms of energy,
including electricity, coal and fuel oil, primarily on the basis of price.
Legislation and governmental regulations, the weather, the futures market,
production costs and other factors beyond the control of Northern Natural Gas
and Kern River influence the price of natural gas.
Historically,
Northern Natural Gas has been able to provide competitively priced services
because of its access to a variety of relatively low cost supply basins, its
cost control measures and its relatively high load factor throughput, which
lowers the per unit cost of transportation. To date, Northern Natural Gas has
avoided any significant pipeline system bypasses. In recent years, Northern
Natural Gas has retained and signed long-term contracts with customers such as
CenterPoint Energy Minnesota Gas (“CenterPoint”), Xcel Energy Inc. (“Xcel
Energy”) and Metropolitan Utilities District, which in some cases, because of
competition, resulted in lower reservation charges relative to the contracts
being replaced.
20
Northern
Natural Gas’ major competitors in the Market Area include ANR Pipeline Company,
Northern Border Pipeline Company and Natural Gas Pipeline Company of America.
Other competitors of Northern Natural Gas include Great Lakes and Viking. In the
Field Area, Northern Natural Gas competes with a large number of interstate and
intrastate pipeline companies. Particularly in the Field Area, the vast majority
of Northern Natural Gas’ capacity is used for transportation services provided
on a short-term firm basis. Northern Natural Gas’ tariff rates are competitive
with the market alternatives and provide value to the shippers holding the firm
capacity.
Although
it needs to compete aggressively to retain and build load, Northern Natural Gas
believes that current and anticipated changes in its competitive environment
have created opportunities to serve its existing customers more efficiently and
to meet certain growing supply needs. While peak day delivery growth of LDCs is
driven by population growth and alternative fuel replacement, new baseload or
off-peak demand growth is being driven primarily by power and ethanol plant
expansion. This baseload or off-peak demand growth is important to Northern
Natural Gas as this demand provides revenues year round and allows Northern
Natural Gas to utilize facilities on a year-round basis. The additional Market
Area load growth also supports the continued sale of Northern Natural Gas’
storage services and Field Area transportation services. Northern Natural Gas
has been successful in competing for a significant amount of the increased
demand related to the construction of new power and ethanol plants.
Kern
River competes with various interstate pipelines and its shippers in order to
market any unutilized or unsubscribed capacity serving the southern California,
Las Vegas, Nevada and Salt Lake City, Utah market areas. Kern River provides its
customers with supply diversity through pipeline interconnections with Northwest
Pipeline, Colorado Interstate, Overland Trail Pipeline, Questar Pipeline Company
and Questar Overthrust Pipeline Company. These interconnections, in addition to
the direct interconnections to natural gas processing facilities, allow Kern
River to access natural gas reserves in Colorado, northwestern New Mexico,
Wyoming, Utah and the Western Canadian Sedimentary Basin.
Kern
River is the only interstate pipeline that presently delivers natural gas
directly from a gas supply basin to end users in the California market. This
enables direct connect customers to avoid paying a “rate stack” (i.e.,
additional transportation costs attributable to the movement from one or more
interstate pipeline systems to an intrastate system within California). Kern
River believes that its historic levelized rate structure and access to upstream
pipelines/storage facilities and to economic Rocky Mountain gas reserves
increases its competitiveness and attractiveness to end-users. Kern River
believes it has an advantage relative to other competing interstate pipelines
because its relatively new pipeline can be economically expanded and will
require significantly less capital expenditures to comply with the Pipeline
Safety Improvement Act of 2002 (“PSIA”) than other systems. Kern River’s
favorable market position is tied to the availability and relatively favorable
price of gas reserves in the Rocky Mountain area, an area that in recent years
has attracted considerable expansion of pipeline capacity serving markets other
than California and Nevada. In addition, Kern River’s 2003 Expansion Project has
several long-term transportation service agreements with electric generation
companies, whose long-term competition and financial prospects are now improving
as demand for electric generation in Kern River’s market territory increases and
older, less efficient power plants in the region are retired.
In 2007,
Northern Natural Gas had two customers who each accounted for greater than 10%
of its revenue and its seven largest customers accounted for 52% of its
systemwide transportation and storage revenues. Northern Natural Gas has
agreements to retain the vast majority of its two largest customers’ volumes
through at least 2017. Kern River had three customers who each accounted for
greater than 10% of its revenue. The loss of any of these significant customers,
if not replaced, could have a material adverse effect on Northern Natural Gas’
and Kern River’s respective businesses.
CE
Electric UK
General
CE
Electric UK, an indirect wholly owned subsidiary of MEHC, is a holding company
which owns, primarily, two companies that distribute electricity in Great
Britain, Northern Electric and Yorkshire Electricity. Northern Electric and
Yorkshire Electricity operate in the north-east of England from North
Northumberland through Durham, Tyne and Wear, Tees Valley and Yorkshire to North
Lincolnshire, an area covering approximately 10,000 square miles, and serve
approximately 3.8 million end users.
21
The
principal function of Northern Electric and Yorkshire Electricity is to build
and maintain the electricity distribution network to serve the end user. The
service territory geographically features a diverse economy with no dominant
sector. The mix of rural, agricultural, urban and industrial areas covers a
broad customer base ranging from domestic usage through farming and retail to
major industry including automotives, chemicals, mining, steelmaking and
offshore marine construction. The industry within the area is concentrated
around the principal centers of Newcastle, Middlesbrough and Leeds.
The price
controlled revenues of the regulated distribution companies are agreed with the
regulator, Office of Gas and Electricity Markets (“Ofgem”), based around 5-year
price control periods, with the current price control period commencing
April 1, 2005.
In
addition to building and maintaining the electricity distribution network, CE
Electric UK also owns an engineering contracting business and a hydrocarbon
exploration and development business.
Electricity
Distribution
Northern
Electric’s and Yorkshire Electricity’s operations consist primarily of the
distribution of electricity in Great Britain. Northern Electric and Yorkshire
Electricity receive electricity from the national grid transmission system and
distribute it to their customers’ premises using their networks of transformers,
switchgear and distribution lines and cables. Substantially all of the end users
in Northern Electric’s and Yorkshire Electricity’s distribution service areas
are connected to the Northern Electric and Yorkshire Electricity networks and
electricity can only be delivered through their distribution systems, thus
providing Northern Electric and Yorkshire Electricity with distribution volume
that is relatively stable from year to year. Northern Electric and Yorkshire
Electricity each charge fees for the use of their distribution systems to the
suppliers of electricity. The suppliers, which purchase electricity from
generators and sell the electricity to end-user customers, use Northern
Electric’s and Yorkshire Electricity’s distribution networks pursuant to an
industry standard “Distribution Connection and Use of System Agreement,” which
Northern Electric and Yorkshire Electricity separately entered into with the
various suppliers of electricity in their respective distribution service areas.
One such supplier, RWE Npower PLC and certain of its affiliates, represented
approximately 40% of the total combined distribution revenues of Northern
Electric and Yorkshire Electricity in 2007. The fees that may be charged by
Northern Electric and Yorkshire Electricity for use of their distribution
systems are controlled by a formula prescribed by the United Kingdom’s
electricity regulatory body that limits increases (and may require decreases)
based upon the rate of inflation, other factors and other regulatory
action.
Electricity
distributed (in GWh) to end users and the total number of end users (in
millions) as of and for the years ended December 31 were as
follows:
2007
2006
2005
Electricity
distributed:
Northern
Electric
16,977
17,203
17,207
Yorkshire
Electricity
24,281
25,025
24,781
41,258
42,228
41,988
Number
of end users:
Northern
Electric
1.6
1.6
1.5
Yorkshire
Electricity
2.2
2.2
2.2
3.8
3.8
3.7
As of
December 31, 2007, Northern Electric’s and Yorkshire Electricity’s
electricity distribution network on a combined basis included approximately
29,000 kilometers of overhead lines, approximately 63,000 kilometers of
underground cables and approximately 700 major substations.
Utility
Services
Integrated
Utility Services Limited, CE Electric UK’s indirect wholly-owned subsidiary, is
an engineering contracting company providing electrical infrastructure
contracting services to third parties.
22
Hydrocarbon
Exploration and Development
CalEnergy
Gas (Holdings) Limited (“CE Gas”), CE Electric UK’s indirect wholly owned
subsidiary, is a hydrocarbon exploration and development company that is focused
on developing integrated upstream gas projects in Australia, the United Kingdom
and Poland. Its upstream gas business consists of full or partial ownership in
exploration, construction and production projects, which, if successful, result
in the sale of gas and other hydrocarbon products to third parties.
CalEnergy
Generation-Foreign
The
CalEnergy Generation-Foreign platform consists of MEHC’s indirect ownership of
the Casecnan project, which is a combined irrigation and hydroelectric power
generation project located in the central part of the island of Luzon in the
Philippines.
The
following table sets out certain information concerning the Casecnan project as
of December 31, 2007:
The
Republic of the Philippines (“ROP”) has provided a performance undertaking
under which the Philippine National Irrigation Administration’s (“NIA”)
obligations under the Casecnan Project Agreement, which was modified by a
Supplemental Agreement between CE Casecnan Water and Energy Company,
Inc. (“CE Casecnan”) and the NIA effective on October 15, 2003
(the “Project Agreement”), are guaranteed by the full faith and credit of
the ROP. NIA also pays CE Casecnan for the delivery of
water and electricity by CE Casecnan. The Casecnan project
carries political risk insurance.
(2)
Contract
Capacity (MW) represents the contract capacity for the
facility. Net MW Owned indicates legal ownership of Contract
Capacity. The Net MW Owned is subject to a dispute with respect
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 5% of the project. Refer to Item 3 of
this Form 10-K for additional
information.
NIA’s
payment obligation under the project agreement is substantially denominated in
U.S. dollars and is the Casecnan project’s sole source of operating revenue.
Because of the dependence on a single customer, any material failure of the
customer to fulfill its obligation under the project agreement and any material
failure of the ROP to fulfill its obligation under the performance undertaking
would significantly impair the ability to meet existing and future obligations
of the relevant project company, including obligations pertaining to the
outstanding project debt.
CE
Casecnan owns and operates the Casecnan project under the terms of the Project
Agreement. CE Casecnan will own and operate the project for a 20-year
cooperation period which commenced on December 11, 2001, the start of the
Casecnan project’s commercial operations, after which ownership and operation of
the project will be transferred to NIA at no cost on an “as-is” basis. The
Casecnan project is dependent upon sufficient rainfall to generate electricity
and deliver water. Rainfall varies within the year and from year to year, which
is outside the control of CE Casecnan, and will impact the amounts of
electricity generated and water delivered by the Casecnan project. Rainfall has
historically been highest from June through December and lowest from January
through May. The contractual terms for water delivery fees and variable energy
fees can produce variability in revenue between reporting periods.
On
June 25, 2006 the Upper Mahiao project and on July 25, 2007 the
Malitbog and Mahanagdong projects’ separate 10-year cooperation periods ended
and the projects, representing a total of 485 MW of net owned contract
capacity, were transferred to PNOC-Energy Development Corporation (“PNOC-EDC”)
by the Company at no cost on an “as-is” basis.
23
CalEnergy
Generation-Domestic
The
subsidiaries comprising the Company’s CalEnergy Generation-Domestic platform own
interests in 15 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 31,2007:
Facility
Net or Contract Capacity (MW) represents total plant accredited net
generating capacity from the summer 2007 as approved by MAPP for Cordova
and contract capacity for most other projects. Net MW Owned indicates
legal ownership of the Facility Net Capacity or Contract
Capacity.
(2)
Constellation
Energy Commodities Group, Inc. (“Constellation”); Hawaii Electric Company
(“HELCO”); 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
subsidiaries currently operate ten geothermal plants in the Imperial
Valley of California (the “Imperial Valley Projects”) and three natural
gas-fired power generation facilities.
(4)
Approximately
82% of the Company’s interests in the Imperial Valley Projects’ Contract
Capacity (MW) is sold to Southern California Edison Company under
long-term power purchase agreements expiring in 2016 through
2026.
24
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, primarily through joint ventures, title and
closing services, property and casualty insurance, home warranties and other
home-related services. HomeServices’ real estate brokerage business is subject
to seasonal fluctuations because more home sale transactions tend to close
during the second and third quarters of the year. As a result,
HomeServices’ operating results and profitability are typically higher in the
second and third quarters relative to the remainder of the year. HomeServices
currently operates more than 370 broker offices in 19 states with almost
19,000 agents under the following 20 brand names: Carol Jones REALTORS,
CBSHOME Real Estate, Champion Realty, Edina Realty Home Services, EWM REALTORS,
Harry Norman Realtors, HOME Real Estate, Huff Realty, Iowa Realty, Jenny Pruitt
and Associates REALTORS, Long Realty Company, Prudential California Realty,
Prudential Carolinas Realty, Prudential First Realty, RealtySouth, Rector-Hayden
REALTORS, Reece & Nichols, Roberts Brothers, Inc., Semonin REALTORS and
Woods Bros. Realty. HomeServices generally occupies the number one or number two
market share position in each of its major markets based on aggregate closed
transaction sides. HomeServices’ major markets consist of the following
metropolitan areas: Minneapolis and St. Paul, Minnesota; Los Angeles and San
Diego, California; Kansas City, Kansas; Kansas City and Springfield, Missouri;
Des Moines and Cedar Rapids, Iowa; Atlanta, Georgia; Omaha and Lincoln,
Nebraska; Birmingham, Auburn and Mobile, Alabama; Tucson, Arizona;
Winston-Salem, Raleigh-Durham and Charlotte, North Carolina; Louisville and
Lexington, Kentucky; Annapolis, Maryland; Cincinnati, Ohio; and Miami, Florida.
The U.S. residential real estate brokerage business is highly competitive and
consists of numerous local brokers and agents in each market seeking to
represent sellers and buyers in residential real estate
transactions.
Electric
Transmission Joint Ventures
In
December 2007, approval was received from the Public Utility Commission of
Texas (“PUCT”) to establish Electric Transmission Texas, LLC (“ETT”), as a joint
venture company to fund, own and operate electric transmission assets in the
Electric Reliability Council of Texas (“ERCOT”) market. The PUCT order also
approved initial rates based on a 9.96% return on equity and a debt to equity
capital structure of 60:40. In December 2007, AEP Texas Central Company
contributed $70 million of transmission assets to ETT. Through a series of
transactions, a subsidiary of American Electric Power Company, Inc. (“AEP”) then
sold, at net book value, a 50% equity ownership interest in ETT to a
wholly-owned subsidiary of MEHC. ETT intends to invest in additional
transmission projects in ERCOT over the next several years. Future projects will
be evaluated on a case-by-case basis. Two immediate sources of new projects
include (a) the assignment of AEP Texas Central Company and AEP Texas North
Company projects, and (b) potential projects within the ERCOT Competitive
Renewable Energy Zones (“CREZ”).
In
February 2007, ETT filed a proposal with the PUCT that addresses the CREZ
initiative of the Texas Legislature, which outlines opportunities for additional
significant investment in transmission assets in Texas. The PUCT issued an
interim order in August 2007 that directed ERCOT to perform studies by
April 2008 to determine the necessary transmission upgrades to accommodate
between 10,000 and 22,800 MW of wind development from CREZ across the Texas
panhandle and central West Texas. The PUCT also indicated in its interim order
that it plans to select transmission construction designees in the first quarter
of 2008.
In
September 2007, subsidiaries of AEP and MEHC formed Electric Transmission
America, LLC (“ETA”) to pursue transmission opportunities outside of ERCOT. MEHC
also holds a 50% equity ownership in ETA. Neither ETT nor ETA is consolidated
with MEHC for financial reporting purposes.
Employees
As of
December 31, 2007, the Company employed approximately 17,200 people, of
which approximately 7,700 are covered by union contracts. The majority of the
union employees are employed by PacifiCorp and MidAmerican Energy and are
represented by the International Brotherhood of Electrical Workers, the Utility
Workers Union of America, the International Brotherhood of Boilermakers and the
United Mine Workers of America. These collective bargaining agreements have
expiration dates ranging through May 2012. HomeServices’ residential real
estate agents are independent contractors and not employees.
25
General
Regulation
MEHC’s
energy subsidiaries are subject to comprehensive governmental regulation which
significantly influences their operating environment, prices charged to
customers, capital structure, costs and their ability to recover
costs.
MEHC’s
domestic regulated public utility subsidiaries, PacifiCorp and MidAmerican
Energy, are subject to comprehensive regulation by state utility commissions,
federal agencies, and other state and local regulatory agencies. The more
significant aspects of this regulatory framework are described
below.
State
Regulation
Historically,
state utility commissions have established service rates on a cost-of-service
basis, which is designed to allow a utility an opportunity to recover its costs
of providing services and to earn a reasonable return on its investment. A
utility’s cost-of-service generally reflects its allowed operating expenses,
including operation and maintenance expense, depreciation expense and taxes.
Some portion of margins earned on wholesale sales for electricity and capacity
and gas transmission service has historically been included as a component of
retail cost of service upon which retail rates are based. State utility
commissions may adjust rates pursuant to a review of (i) a utility’s revenues
and expenses during a defined test period and (ii) such utility’s level of
investment. State utility commissions typically have the authority to review and
change service rates on their own initiative. Some states may initiate reviews
at the request of a utility customer, a governmental agency or a representative
of a group of customers. The utility and such parties, however, may agree with
one another not to request a review of or changes to rates for a specified
period of time.
The
electric rates of PacifiCorp and MidAmerican Energy are generally based on the
cost of providing traditional bundled service, including generation,
transmission and distribution services. Historically, the state regulatory
framework in the service areas of PacifiCorp’s and MidAmerican Energy’s systems
reflected specified power and fuel costs as part of bundled rates or
incorporated power or fuel adjustment clauses in the utility’s rates and
tariffs. Power and fuel adjustment clauses permit periodic adjustments to cost
recovery from customers and therefore provide protection against exposure to
cost changes.
Except
for Oregon, Washington and Illinois, PacifiCorp and MidAmerican Energy have an
exclusive right to serve electricity customers within their service territories
and, in turn, have the obligation to provide electric service to those
customers. Under Oregon law, certain commercial and industrial customers have
the right to choose alternative electric suppliers. The impact of these programs
on the Company’s financial results has not been material. In Washington, the
state statute does not provide for exclusive service territory allocation.
PacifiCorp’s service territory in Washington is surrounded by other public
utilities with whom PacifiCorp has from time to time entered into service area
agreements under the jurisdiction of the WUTC. In Illinois, all customers are
free to choose their electricity supplier and MidAmerican Energy has an
obligation to serve customers at regulated rates that leave MidAmerican Energy’s
system, but later choose to return. To date, there has been no significant loss
of customers in Illinois.
26
PacifiCorp
The
following table illustrates the current rate case status in each state
jurisdiction in which PacifiCorp operates:
State
Regulator
Base
Rate(1)
Power
Costs(1)
Utah
Public Service Commission (“UPSC”)
December
2006 stipulation resulted in an annual increase of $115 million, or
10% overall, with $85 million effective in December 2006 and the
remaining $30 million effective in June 2007.
In
December 2007, PacifiCorp filed a general rate case requesting an
increase of $161 million, or 11% overall, with an effective date of
August 2008. In February 2008, the UPSC issued an order
determining that the proper test period should end December 2008.
PacifiCorp is currently determining the reduction to the originally
requested amount that will result from the change in the test
period.
No
separate power cost recovery mechanism.
Oregon
Public Utility Commission (“OPUC”)
September 2006
settlement agreement resulted in an annual increase for non-power costs of
$33 million effective in January 2007(2).
Uses
an annual transition adjustment mechanism, resulting in a $10 million
increase in January 2007. In December 2007, the OPUC issued an order
approving an increase of $22 million effective January 1, 2008
related to forecasted power costs.
In
December 2007, the OPUC approved a renewable adjustment clause
(“RAC”) mechanism with an effective date of January 1, 2008 to
recover revenue requirements of new renewable resources between rate
cases. Under the RAC mechanism, PacifiCorp will submit a filing on
April 1 of each year, with rates to become effective January 1
of the following year to recover the revenue requirement of new renewable
resources and associated transmission that are not reflected in general
rates.
Wyoming
Public Service Commission (“WPSC”)
In
June 2007, PacifiCorp filed for a rate increase of $36 million,
or 8% overall, to be effective May 1, 2008. In January 2008,
PacifiCorp reached a settlement with all parties to this case for an
annual increase of $23 million, or 5% overall, subject to final
stipulation and approval by the WPSC.
The
January 2008 rate case settlement allows for a one time forecast
period for the existing power cost mechanism. The power cost adjustment
mechanism terminates in April 2011.
In
February 2008, PacifiCorp filed its annual deferred net power cost
adjustment application with the WPSC for $31 million of costs
incurred during the period December 1, 2006 through November 30,2007.
Washington
Utilities and Transportation Commission (“WUTC”)
In
June 2007, the WUTC approved a rate increase of $14 million, or
6% overall, effective June 27, 2007 and accepted PacifiCorp’s
proposed western balancing authority area cost allocation methodology for
a five-year pilot period.
In
February 2008, PacifiCorp filed a general rate case with the WUTC for
an annual increase of $35 million, or 15% overall, with an effective
date no later than January 2009.
No
separate power cost recovery mechanism.
Idaho
Public Utilities Commission (“IPUC”)
In
December 2007, the IPUC approved a settlement of PacifiCorp’s general rate
case, resulting in a $12 million, or 6% overall, base rate increase
effective January 2008. The settlement also provides for rate
increases effective January 1, 2009 and 2010 for PacifiCorp’s two
special contract industrial customers and no additional rate changes for
those two special contract customers effective prior to January 1,2011. Additional rate increases for the remaining customer classes may be
requested if needed to maintain cost of service coverage.
No
separate power cost recovery mechanism.
California
Public Utilities Commission (“CPUC”)
The
CPUC approved a $1 million, or 1% overall, increase effective
January 1, 2008 to reflect changes to the post test-year adjustment
mechanism, which allows for annual rate adjustments for changes in
operating costs and plant additions outside of the context of a
traditional rate case.
In
December 2007, the CPUC approved a $5 million, or 7% overall,
increase effective January 1, 2008 to reflect the new level of net
power costs.
(1)
Margins
earned on net wholesale sales for energy and capacity have historically
been included as a component of retail cost of service upon which retail
rates are based.
(2)
Refer
to Note 6 of Notes to Consolidated Financial Statements included in Item 8
of this Form 10-K for additional information regarding Oregon Senate Bill
408.
27
MidAmerican
Energy
Iowa
The IUB
has approved over the past several years a series of electric settlement
agreements between MidAmerican Energy, the OCA and other interveners under
which, MidAmerican Energy has agreed not to seek a general increase in electric
base rates to become effective prior to January 1, 2014, unless its Iowa
jurisdictional electric return on equity for any year covered by the applicable
agreement falls below 10%, computed as prescribed in each respective agreement.
Prior to filing for a general increase in electric rates, MidAmerican Energy is
required to conduct 30 days of good faith negotiations with the signatories to
the settlement agreements to attempt to avoid a general increase in rates. As a
party to the settlement agreements, the OCA has agreed not to request or support
any decrease in MidAmerican Energy’s Iowa electric base rates to become
effective prior to January 1, 2014. The settlement agreements specifically
allow the IUB to approve or order electric rate design or cost of service rate
changes that could result in changes to rates for specific customers as long as
such changes do not result in an overall increase in revenues for MidAmerican
Energy. Additionally, the settlement agreements also each provide that revenues
associated with Iowa retail electric returns on equity within specified ranges
will be shared with customers. Refer to Note 6 of Notes to the Consolidated
Financial Statements included in Item 8 of this Form 10-K for
additional discussion regarding these settlements.
On
April 18, 2006, the Iowa Utilities Board (“IUB”) approved a settlement
agreement between MidAmerican Energy and the Iowa Office of Consumer Advocate
(“OCA”) regarding ratemaking principles for additional wind-powered generation
capacity in Iowa to be installed in 2006 and 2007. A total of 222 MW
(nameplate ratings) of wind-powered generation was placed in service in 2006 and
2007 subject to that agreement, including 123 MW (nameplate ratings) in the
fourth quarter of 2007. On July 27, 2007, the IUB approved a settlement
agreement between MidAmerican Energy and the OCA in conjunction with MidAmerican
Energy’s ratemaking principles application for up to 540 MW (nameplate
ratings) of additional wind-powered capacity in Iowa to be placed in service on
or before December 31, 2013. MidAmerican Energy placed 78 MW (nameplate
ratings) of wind-powered generation into service in the fourth quarter of 2007
subject to the 2007 settlement agreement. Currently, MidAmerican Energy has
462 MW (nameplate ratings) under development or construction that it
expects will be placed in service by December 31, 2008. MidAmerican Energy
continues to pursue additional cost effective wind-powered generation. Refer to
Note 6 of Notes to Consolidated Financial Statements included in Item 8 for
additional discussion regarding these settlements.
MidAmerican
Energy does not have an electric fuel and purchased power adjustment clause in
Iowa. A monthly purchased gas cost adjustment clause combined with an Incentive
Gas Supply Procurement Plan provides protection from market changes in gas costs
while offering financial incentives for MidAmerican Energy to minimize the cost
of its gas supply portfolio.
Illinois
In
December 1997, Illinois enacted a law to restructure Illinois’ electric utility
industry. The law changed how and what electric services are regulated by the
Illinois Commerce Commission (“ICC”) and transitioned portions of the
traditional electric services to a competitive environment. Electric base rates
in Illinois were generally frozen until January 1, 2007, and are now
subject to cost-based ratemaking.
Effective
January 2007, MidAmerican Energy and the ICC have eliminated the monthly
adjustment clause for recovery of fuel for electric generation and purchased
power costs in Illinois. Base rates have been adjusted effective January 1,2007 to include recoveries at average 2004/2005 cost levels. The elimination of
the fuel adjustment clause exposes MidAmerican Energy to monthly market price
changes for fuel and purchased power costs in Illinois, with rate case approval
required for any base rate changes. With the elimination of the fuel adjustment
clause, MidAmerican Energy may not petition for its reinstatement until November
2011. A monthly adjustment clause remains in effect for MidAmerican Energy’s
purchased gas costs.
Federal
Regulation
The FERC
is an independent agency with broad authority to implement provisions of the
Federal Power Act and the Energy Policy Act. MidAmerican Energy is also subject
to regulation by the Nuclear Regulatory Commission (“NRC”) pursuant to the
Atomic Energy Act of 1954, as amended (“Atomic Energy Act”), with respect to the
operation of the Quad Cities Station.
28
Federal
Power Act
Under the
Federal Power Act, the FERC regulates rates for interstate sales of electricity
at wholesale, transmission of electric power, accounting, securities issuances
and other matters, including construction and operation of hydroelectric
projects. Margins earned on wholesale sales for electricity and capacity and
transmission service have historically been included as a component of retail
cost of service upon which retail rates are based.
Wholesale Electricity and
Capacity
The FERC
regulates PacifiCorp’s and MidAmerican Energy’s rates charged to wholesale
customers for electricity, capacity and transmission services. Most of
PacifiCorp’s and MidAmerican Energy’s electric wholesale sales and purchases
take place under market-based rate pricing allowed by the FERC and are therefore
subject to market volatility. A December 2006 decision of the Ninth Circuit
changed the interpretation of the relevant standard that the FERC should apply
when reviewing wholesale contracts for electricity or capacity from a stringent
“public policy” standard to a broader “just and reasonable” standard making
contracts more vulnerable to challenge. The decision raises some concerns
regarding the finality of contract prices, particularly from the sellers’ side
of the transactions. The U.S. Supreme Court is reviewing the case on appeal and
the outcome of its ruling cannot be predicted at this time. All sellers subject
to the FERC’s jurisdiction, including PacifiCorp and MidAmerican Energy, are
currently subject to increased risk as a result of this decision.
The FERC
conducts a triennial review of PacifiCorp’s and MidAmerican Energy’s
market-based rate pricing authority. Each utility must demonstrate the lack of
generation market power in order to charge market-based rates for sales of
wholesale electricity and capacity in their respective balancing authority
areas. Under the FERC’s market-based rules, PacifiCorp and MidAmerican Energy
must file a notice of change in status when 100 MW of incremental
generation becomes operational. Following separate filings by PacifiCorp of a
change in status notice relating to new generation, the FERC in February and
November 2007, confirmed that PacifiCorp does not have market power and may
continue to charge market-based rates. In accordance with the filing schedule
established by the FERC in Order No. 697, PacifiCorp’s next triennial
review will occur in 2010. MidAmerican Energy’s most recent review, which began
in October 2004, is complete pending the FERC’s final ruling on certain sales
made within MidAmerican Energy’s balancing authority area for delivery outside
the balancing authority area. MidAmerican Energy has FERC authorization to sell
at market-based rates outside of its balancing authority area. Based on its
estimate of MidAmerican Energy’s potential refund obligation, the Company does
not believe the ultimate resolution of this issue will have a material impact on
MidAmerican Energy’s financial results. Following a change in status notice
relating to new generation filed by MidAmerican Energy in October 2007, the
FERC confirmed that MidAmerican Energy is authorized to sell at market-based
rates outside of its balancing authority area and directed that MidAmerican
submit its next required triennial review in accordance with the schedule
established in Order No. 697. Unless the FERC determines otherwise in
response to a pending request for clarification, MidAmerican Energy’s next
triennial filings will occur in June and December 2008.
Transmission
The FERC
regulates PacifiCorp’s and MidAmerican Energy’s wholesale transmission services.
The regulation requires each to provide open access transmission service at
cost-based rates. The FERC also regulates unbundled transmission service to
retail customers. These services are offered on a non-discriminatory basis,
meaning that all potential customers are provided an equal opportunity to access
the transmission system. The Company’s transmission businesses are managed and
operated independently from its generating and wholesale marketing businesses in
accordance with the FERC Standards of Conduct.
In
January 2007, the FERC approved a settlement with PacifiCorp regarding
PacifiCorp’s use of its transmission system while conducting wholesale power
transactions with third parties. PacifiCorp discovered possible violations of
its FERC-approved tariff during an internal review of its compliance with
certain FERC regulations shortly before MEHC’s acquisition of PacifiCorp. Upon
completion of the acquisition, PacifiCorp self-reported the potential violations
to the FERC. The potential violations primarily related to the way PacifiCorp
used its own transmission system to transmit energy using “network service”
instead of “point-to-point” service as the FERC believes is required by
PacifiCorp’s tariff. This use of transmission service neither enriched
PacifiCorp’s shareholders nor harmed its retail customers. As part of the
settlement, PacifiCorp voluntarily refunded $1 million to other
transmission customers in April 2006 and paid a $10 million fine to the
U.S. Treasury in January 2007.
29
On
February 16, 2007, the FERC adopted a final rule in Order No. 890
designed to strengthen the pro-forma OATT by providing greater specificity and
increasing transparency. The most significant revisions to the pro forma OATT
relate to the development of more consistent methodologies for calculating
available transfer capability, changes to the transmission planning process,
changes to the pricing of certain generator and energy imbalances to encourage
efficient scheduling behavior and to exempt intermittent generators, and changes
regarding long-term point-to-point transmission service, including the addition
of conditional firm long-term point-to-point transmission service, and
generation redispatch. As transmission providers with an OATT on file with the
FERC, PacifiCorp and MidAmerican Energy are required to comply with the
requirements of the new rule. The first compliance filing, which amends the
OATT, was filed on July 13, 2007. Certain details related to the precise
methodology that will be used to calculate available transfer capability were
filed with the FERC on September 11, 2007. A number of parties to the
proceeding, including PacifiCorp and MidAmerican Energy, have requested
rehearing or clarification of various portions of the final rule. In
December 2007, the FERC issued Order No. 890-A generally affirming the
provisions of the final rule as adopted in Order No. 890 with certain
limited clarifications. Although PacifiCorp has requested a limited
clarification of Order No. 890-A, the final rule as revised is not anticipated
to have a significant impact on PacifiCorp’s or MidAmerican Energy’s financial
results, but it will likely have a significant impact on their transmission
operations, planning and wholesale marketing functions.
In
March 2007, the FERC issued Order No. 693, Mandatory Reliability
Standards for the Bulk-Power System, which imposes penalties of up to
$1 million per day per violation for failure to comply with new electric
reliability standards. The FERC approved 83 reliability standards developed
by the North American Electric Reliability Corporation (the “NERC”).
Responsibility for compliance and enforcement of these standards has been given
to the WECC for PacifiCorp and the Midwest Reliability Organization for
MidAmerican Energy. The 83 standards comprise over 600 requirements
and sub-requirements with which PacifiCorp and MidAmerican Energy must comply.
On June 18, 2007, the standards became mandatory and enforceable under
federal law. PacifiCorp and MidAmerican Energy expect that the existing
standards will change as a result of modifications, guidance and clarification
following industry implementation and ongoing audits and enforcement. On
January 18, 2008, the FERC approved eight additional cyber security and
critical infrastructure protection standards proposed by the NERC. The
additional standards will become effective on April 7, 2008. MEHC cannot
predict the effect that these standards will have on its consolidated financial
results, however, they will likely have a significant impact on PacifiCorp’s and
MidAmerican Energy’s transmission operations and resource planning functions.
Also during 2007, the WECC audited PacifiCorp’s compliance with several of the
reliability standards approved by the FERC. PacifiCorp is analyzing the
preliminary results of the audit and, at this time, cannot predict the impact of
potential penalties, if any, on its consolidated financial results.
Neither
PacifiCorp nor MidAmerican Energy is part of a RTO, but MidAmerican Energy has
hired an independent transmission system coordinator to administer various
MidAmerican Energy OATT functions for transmission service and is evaluating
participating in a RTO market. PacifiCorp, along with other private utilities
and public power organizations throughout the Pacific Northwest and Western
United States, is a member of the Northern Tier Transmission Group, which
initially will conduct reliability and economic planning coordination for its
members.
Hydroelectric
Relicensing
PacifiCorp’s
hydroelectric portfolio consists of 47 plants with an aggregate facility net
owned capacity of 1,158 MW. The FERC regulates 98% of the net capacity of
this portfolio through 16 individual licenses. Several of PacifiCorp’s
hydroelectric plants are in some stage of relicensing with the FERC.
Hydroelectric relicensing and the related environmental compliance requirements
and litigation are subject to uncertainties. PacifiCorp expects that future
costs relating to these matters may be significant and will consist primarily of
additional relicensing costs, operations and maintenance expense, and capital
expenditures. Electricity generation reductions may result from the additional
environmental requirements. Refer to Note 18 of Notes to Consolidated
Financial Statements included in Item 8 of this Form 10-K for
additional information regarding hydroelectric relicensing.
Northwest
Power Act
The
Northwest Power Act, through the Residential Exchange Program, provides access
to the benefits of low-cost federal hydroelectricity to the residential and
small-farm customers of the region’s investor-owned utilities. The program is
administered by the Bonneville Power Administration (the “BPA”) in accordance
with federal law. Pursuant to agreements between the BPA and PacifiCorp,
benefits from the BPA are passed through to PacifiCorp’s Oregon, Washington and
Idaho residential and small-farm customers in the form of electricity bill
credits. Several publicly owned utilities, cooperatives and the BPA’s
direct-service industry customers filed lawsuits against the BPA with the United
States Ninth Circuit Court of Appeals (the “Ninth Circuit”) seeking review of
certain aspects of the BPA’s Residential Exchange Program, as well as
challenging the level of benefits previously paid to investor-owned utility
customers under the agreements. In May 2007, the Ninth Circuit issued two
decisions, which resulted in the BPA suspending payment of the benefits under
the agreements. This has resulted in increases to PacifiCorp’s residential and
small-farm customers’ electric bills in Oregon, Washington and Idaho. In
February 2008, the BPA initiated a rate proceeding under section 7(i) of
the Northwest Power Act to reconsider the level of benefits for the years 2002
through 2006 consistent with the Ninth Circuit’s decision to re-establish the
level of benefits for years 2007 and 2008 and to set the level of benefits for
years 2009 and beyond. Because the benefit payments from the BPA are passed
through to PacifiCorp’s customers, the outcome of this matter is not expected to
have a significant effect on the Company’s consolidated financial
results.
30
Energy
Policy Act
On
August 8, 2005, the Energy Policy Act was signed into law and has
significantly impacted the energy industry. In particular, the law expanded the
FERC’s regulatory authority in areas such as electric system reliability,
electric transmission expansion and pricing, regulation of utility holding
companies, and enforcement authority to issue civil penalties of up to
$1 million per day. While the FERC has now issued rules and decisions on
multiple aspects of the Energy Policy Act, the full impact of those decisions
remains uncertain.
The
Energy Policy Act also repealed the Public Utility Holding Company Act of 1935
(“PUHCA 1935”) and enacted the Public Utility Holding Company Act of 2005
(“PUHCA 2005”), effective February 8, 2006. PUHCA 2005 eliminated the
substantive requirements and restrictions previously applicable to holding
companies under PUHCA 1935. Its repeal enabled Berkshire Hathaway to convert its
shares of MEHC’s no par, zero-coupon non-voting convertible preferred stock into
an equal number of shares of MEHC’s voting common stock. As a consequence, MEHC
became a consolidated subsidiary of Berkshire Hathaway. PUHCA 2005 also
increased the FERC’s authority over utility mergers, provides the FERC with
access to books and records and requires holding companies to comply with its
record retention requirements.
The
Energy Policy Act also gives the FERC “backstop” transmission siting authority
and directs the FERC to oversee the establishment of mandatory transmission
reliability standards as discussed above. The Energy Policy Act also extended
the federal production tax credit for new renewable electricity generation
projects through December 31, 2007, with subsequent legislation extending
the credit to December 31, 2008. Partly as a result of that portion of the
law, PacifiCorp and MidAmerican Energy began development efforts to add
additional wind-powered generation facilities.
Nuclear
Regulatory Commission
MidAmerican
Energy is subject to the jurisdiction of the NRC with respect to its license and
25% ownership interest in the Quad Cities Station. Exelon Generation is the
operator of Quad Cities Station and is under contract with MidAmerican Energy to
secure and keep in effect all necessary NRC licenses and
authorizations.
The NRC
regulates the granting of permits and licenses for the construction and
operation of nuclear generating stations and regularly inspects such stations
for compliance with applicable laws, regulations and license terms. Current
licenses for the Quad Cities Station provide for operation until
December 14, 2032. The NRC review and regulatory process covers, among
other things, operations, maintenance, and environmental and radiological
aspects of such stations. The NRC may modify, suspend or revoke licenses and
impose civil penalties for failure to comply with the Atomic Energy Act, the
regulations under such Act or the terms of such licenses.
Federal
regulations provide that any nuclear operating facility may be required to cease
operation if the NRC determines there are deficiencies in state, local or
utility emergency preparedness plans relating to such facility, and the
deficiencies are not corrected. Exelon Generation has advised MidAmerican Energy
that an emergency preparedness plan for Quad Cities Station has been approved by
the NRC. Exelon Generation has also advised MidAmerican Energy that state and
local plans relating to Quad Cities Station have been approved by the Federal
Emergency Management Agency.
MidAmerican
Energy maintains financial protection against catastrophic loss associated with
its interest in the Quad Cities Station through a combination of insurance
purchased by Exelon Generation (the operator and joint owner of the Quad Cities
Station), insurance purchased directly by MidAmerican Energy, and the mandatory
industry-wide loss funding mechanism afforded under the Price-Anderson
Amendments Act of 1988, which was amended and extended by the Energy Policy Act
of 2005. The general types of coverage are: nuclear liability, property coverage
and nuclear worker liability.
The
natural gas pipeline and storage operations of the Company’s U.S. interstate
pipeline subsidiaries are regulated by the FERC, which administers, most
significantly, the Natural Gas Act and the Natural Gas Policy Act of 1978. Under
this authority, the FERC regulates, among other items, (i) rates, charges, terms
and conditions of service, and (ii) the construction and operation of U.S.
pipelines, storage and related facilities, including the extension, expansion or
abandonment of such facilities.
Northern
Natural Gas continues to use a modified straight fixed variable rate design
methodology, whereby substantially all fixed costs assignable to firm
transportation and storage customers, including a return on invested capital and
income taxes, are to be recovered through fixed monthly demand reservation
charges regardless of volumes shipped. Commodity charges, which are paid only
with respect to volumes actually shipped, are designed to recover the remaining,
primarily variable, cost. Kern River’s rates have historically been set using a
“levelized cost-of-service” methodology so that the rate is constant over the
contract period; however, rate design is the subject of Kern River’s current
rate case before the FERC and may be subject to change as a result of the rate
case outcome. This levelized cost of service has been achieved by using a
FERC-approved depreciation schedule in which depreciation increases as interest
expense decreases.
FERC
regulations also restrict each pipeline’s marketing affiliates’ access to U.S.
interstate pipeline natural gas transmission customer data and place certain
conditions on services provided by the U.S interstate pipelines to their
marketing affiliates.
Additional
proposals and proceedings that might affect the interstate natural gas pipeline
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. The Company cannot predict when or if any new
proposals might be implemented or, if so, how Northern Natural Gas and Kern
River might be affected.
U.S.
interstate natural gas pipelines are also subject to the regulations of the
Pipeline & Hazardous Material Safety Administration (“PHMSA”) division of
the Department of Transportation (“DOT”) pursuant to the Natural Gas Pipeline
Safety Act of 1968 (“NGPSA”), which establishes safety requirements in the
design, construction, operation and maintenance of interstate natural gas
transmission facilities, and the PSIA, which implemented additional safety and
pipeline integrity regulations for high consequence areas.
The NGPSA
requires any entity that owns or operates pipeline facilities to comply with
applicable safety standards, to establish and maintain inspection and
maintenance plans and to comply with such plans. 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 PSIA,
as amended by the Pipeline Safety Act of 2002 and the Pipeline Inspection,
Protection, Enforcement, and Safety Act of 2006, established mandatory
inspections for all natural gas pipelines in high-consequence areas. These
regulations require pipeline operators to implement integrity management
programs, including more frequent inspections, and other safety protection in
areas where the consequences of potential pipeline accidents pose the greatest
risk to life and property. The Company believes its pipeline operations comply
in all material respects to this regulation. The regulation also requires
Northern Natural Gas and Kern River to complete certain modifications to their
pipeline systems by December 17, 2012. Each pipeline is scheduled to have
this work completed by December 2011.
In
addition to FERC and PHMSA regulation, certain operations are subject to
oversight by state regulatory commissions.
32
U.S. Mine
Safety
Mining
operations are regulated by the federal Mine Safety and Health Administration
(“MSHA”) which administers federal mine safety and health laws, regulations and
state regulatory agencies. The Mine Improvement and New Emergency Response Act
of 2006 (“MINER Act”), enacted in June 2006, amended previous mine safety
and health laws to improve mine safety and health and accident preparedness. The
MINER Act, portions of which are not yet fully implemented, requires operators
of underground coal mines to develop a written emergency response plan specific
to each mine they operate. These plans must be updated and re-certified by MSHA
every six months. It also requires every mine to have at least two rescue teams
located within one hour, and it limits the legal liability of rescue team
members and the companies that employ them. The MINER Act also increases civil
and criminal penalties for violations of federal mine safety standards and gives
MSHA the ability to institute a civil action for relief, including a temporary
or permanent injunction, restraining order or other appropriate order against a
mine operator who fails to pay the penalties or fines.
U.K. Electricity
Distribution Companies
Northern
Electric and Yorkshire Electricity, as holders of electricity distribution
licenses, are subject to regulation by the Gas and Electricity Markets Authority
(“GEMA”). GEMA discharges certain of its powers through its staff within Ofgem.
Each of fourteen distribution license holders (“DLH”) distributes electricity
from the national grid system to end use customers within their respective
distribution service areas.
Given the
absence of an effective competitive market in the distribution of electricity,
the amount of revenue that can be collected from customers by a DLH is
controlled by a distribution price control formula. This encourages companies to
look for efficiency gains in order to improve profits. The distribution price
control formula also adjusts the revenue received by DLHs to reflect an increase
or decrease in distribution of units and number of end users. Currently, price
controls are established every five years, although the formula has been, and
may be, reviewed at the regulator’s discretion. The procedure and methodology
adopted at a price control review are at the reasonable discretion of Ofgem.
Historically, Ofgem’s judgment of the future allowed revenue of licensees has
been based upon, among other things:
·
actual
operating costs of each of the
licensees;
·
pension
deficiency payments of each of the
licensees;
·
operating
costs which each of the licensees would incur if it were as efficient as,
in Ofgem’s judgment, the more efficient
licensees;
·
taxes
that each licensee is expected to
pay;
·
regulatory
value ascribed to and the allowance for depreciation related to the
distribution network assets;
·
rate
of return to be allowed on investment in the distribution network assets
by all licensees; and
·
financial
ratios of each of the licensees and the license requirement for each
licensee to maintain an investment grade
status.
The
current electricity distribution price control was agreed in December 2004,
became effective April 2005 and is expected to continue through March 2010.
Prices during this 5-year period will be allowed to increase by no more than the
rate of inflation (based upon the retail price index). Ofgem also indicated that
during the current price control period, the retention of any actual reductions
in operating costs from the assumptions used in setting the new price control
might depend on the successful implementation of revised cost reporting
guidelines prescribed by Ofgem and to be applied by all DLHs.
A number
of incentive schemes also operate within the current price control period to
encourage DLHs to provide an appropriate quality of service with specified
payments to be made for failures to meet prescribed standards of service. The
aggregate of these payments is uncapped, but may be excused in certain
prescribed circumstances that are generally beyond the control of the DLH. There
are also incentive schemes pursuant to which allowed revenue may increase by up
to 3.3% or decrease by up to 3.5% in any year.
Ofgem
also monitors DLH compliance with license conditions and enforces the remedies
resulting from any breach of condition. License conditions include the prices
and terms of service, financial strength of the DLH, the provision of
information to Ofgem and the public, as well as maintaining transparency,
non-discrimination and avoidance of cross-subsidy in the provision of such
services. Ofgem also monitors and enforces certain duties of a DLH set out in
the Electricity Act of 1989 including the duty to develop and maintain an
efficient, coordinated and economical system of electricity distribution. Under
the Utilities Act 2000, the regulators are able to impose financial penalties on
DLHs who contravene any of their license duties or certain of their duties under
the Electricity Act 1989, as amended, or who are failing to achieve a
satisfactory performance in relation to the individual standards prescribed by
GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the
licensee’s revenue.
33
Independent Power
Projects
Foreign
The
Philippine Congress has passed the Electric Power Industry Reform Act of 2001
(“EPIRA”), which is aimed at restructuring the Philippine power industry,
privatizing the NPC and introducing a competitive electricity market, among
other initiatives. The implementation of EPIRA may impact the Company’s future
operations in the Philippines and the Philippine power industry as a whole, the
effect of which is not yet known as changes resulting from EPIRA are
ongoing.
Domestic
Both the
Cordova and Power Resources Projects are Exempt Wholesale Generators (“EWG”)
under the Energy Policy Act while the remaining domestic projects are currently
certified as Qualifying Facilities (“QF”) under the Public Utility Regulatory
Policies Act of 1978 (“PURPA”). Both EWGs and QFs are generally exempt from
compliance with extensive federal and state regulations that control the
financial structure of an electric generating plant and the prices and terms at
which electricity may be sold by the facilities.
EWGs are
permitted to sell capacity and electricity only in the wholesale markets, not to
end users. Additionally, utilities are required to purchase electricity produced
by QFs at a price that does not exceed the purchasing utility’s “avoided cost”
and to sell back-up power to the QFs on a non-discriminatory basis. Avoided cost
is defined generally as the price at which the utility could purchase or produce
the same amount of power from sources other than the QF on a long-term basis.
The Energy Policy Act eliminated the purchase requirement for utilities with
respect to new contracts under certain conditions. New QF contracts are also
subject to FERC rate filing requirements, unlike QF contracts entered into prior
to the Energy Policy Act. FERC regulations also permit QFs and utilities to
negotiate agreements for utility purchases of power at rates other than the
utilities’ avoided cost.
Residential Real Estate
Brokerage Company
HomeServices
is regulated by the U.S. Department of Housing and Urban Development (“HUD”),
most significantly under the Real Estate Settlement Procedures Act (“RESPA”),
and by state agencies where it operates. RESPA primarily governs the real estate
settlement process by mandating all parties fully inform borrowers about all
closing costs, lender servicing and escrow account practices, and business
relationships between closing service providers and other parties to the
transaction. In late 2007, HUD initiated the process to revise the RESPA
regulation, however, it is unknown whether a proposed rule will be introduced or
finalized in 2008. Accordingly, the Company is presently unable to quantify the
likely impact of a final rule, if adopted.
Environmental
Regulation
MEHC and
its energy subsidiaries are subject to federal, state, local, and foreign laws
and regulations with regard to air and water quality, renewable portfolio
standards, climate change, hazardous and solid waste disposal and other
environmental matters and are subject to zoning and other regulation by local
authorities. In addition to imposing continuing compliance obligations, these
laws and regulations authorize the imposition of substantial penalties for
noncompliance including fines, injunctive relief and other sanctions. The
Company believes it is in material compliance with all laws and regulations. The
most significant environmental laws and regulations affecting the Company
include:
·
The
federal Clean Air Act, as well as state laws and regulations impacting air
emissions, including State Implementation Plans related to existing and
new national ambient air quality standards. Rules issued by the United
States Environmental Protection Agency (“EPA”) and certain states require
substantial reductions in sulfur dioxide (“SO2”)
and nitrogen oxide (“NOx”)
emissions beginning in 2009 and extending through 2018. The Company has
already installed certain emission control technology and is taking other
measures to comply with required reductions. Refer to the Clean Air
Standards section below for additional discussion regarding this
topic.
34
·
The
federal Water Pollution Control Act (“Clean Water Act”) and individual
state clean water laws regulate cooling water intake structures and
discharges of wastewater, including storm water runoff. The Company
believes that it currently has, or has initiated the process to receive,
all required water quality permits. Refer to the Water Quality Standards
section below for additional discussion regarding this
topic.
·
The
federal Comprehensive Environmental Response, Compensation and Liability
Act and similar state laws, which may require any current or former owners
or operators of a disposal site, as well as transporters or generators of
hazardous substances sent to such disposal site, to share in environmental
remediation costs. Refer to Note 18 of Notes to Consolidated
Financial Statements included in Item 8 of this Form 10-K for
additional information regarding environmental
contingencies.
·
The
Nuclear Waste Policy Act of 1982, under which the U.S. Department of
Energy is responsible for the selection and development of repositories
for, and the permanent disposal of, spent nuclear fuel and high-level
radioactive wastes. The federal Surface Mining Control and Reclamation Act
of 1977 and similar state statutes establish operational, reclamation and
closure standards that must be met during and upon completion of mining
activities. Refer to Note 12 of Notes to Consolidated Financial
Statements included in Item 8 of this Form 10-K for additional
information regarding the nuclear decommissioning and mine reclamation
obligations.
·
The
federal Surface Mining Control and Reclamation Act of 1977 and similar
state statutes establish operational, reclamation and closure standards
that must be met during and upon completion of mining
activities.
·
The
FERC oversees the relicensing of existing hydroelectric projects and is
also responsible for the oversight and issuance of licenses for new
construction of hydroelectric projects, dam safety inspections and
environmental monitoring. Refer to Note 18 of Notes to Consolidated
Financial Statements included in Item 8 of this Form 10-K for
additional information regarding the relicensing of certain of
PacifiCorp’s existing hydroelectric
facilities.
Refer to
the Liquidity and Capital Resources section of Item 7 of this
Form 10-K for additional information regarding planned capital expenditures
related to environmental regulation.
Clean
Air Standards
The Clean
Air Act provides a framework for protecting and improving the nation’s air
quality, and controlling mobile and stationary sources of air emissions. The
major Clean Air Act programs, which most directly affect the Company’s electric
generating facilities, are briefly described below. Many of these programs are
implemented and administered by the states, which can impose additional, more
stringent requirements.
National
Ambient Air Quality Standards
The EPA
implements national ambient air quality standards for ozone and fine particulate
matter, as well as for other criteria pollutants that set the minimum level of
air quality for the United States. Areas that achieve the standards, as
determined by ambient air quality monitoring, are characterized as being in
attainment, while those that fail to meet the standards are designated as being
nonattainment areas. Generally, sources of emissions in a nonattainment area are
required to make emissions reductions. The counties in Washington, Idaho,
Montana, Wyoming, Colorado, Utah and Arizona, where PacifiCorp’s major emission
sources are located, and the entire state of Iowa, where MidAmerican Energy’s
major emission sources are located, are in attainment of the current ambient air
quality standards. A new, more stringent standard for fine particulate matter
became effective on December 18, 2006, but is under legal challenge in the
United States Court of Appeals for the District of Columbia Circuit. Air quality
modeling and preliminary air quality monitoring data indicate that portions of
the states in which PacifiCorp and MidAmerican Energy have major emission
sources may not meet the new standards. Until three years of data are collected
and attainment designations under the new fine particulate standard are made,
the impact of these new standards on PacifiCorp and MidAmerican Energy will not
be known.
In
July 2007, the EPA proposed revisions to the primary and secondary national
ambient air quality standards for ozone, including lowering the current level of
the 8-hour standard from 0.08 parts per million to a range of 0.070 and
0.075 parts per million. The EPA also solicited public comments through
October 9, 2007 on alternative levels between 0.060 parts per million
and the current 8-hour standard. Final action on the standards must be completed
by March 12, 2008. States will then have until June 2009 to
characterize their attainment status, with the EPA’s determinations regarding
non-attainment made by June 2010 and state implementation plans due in
2013. Until the EPA makes its final determination on the revised standards and
attainment designations are made, the impact of any new standards on PacifiCorp
and MidAmerican Energy will not be known.
35
Regulated
Air Pollutants
In
March 2005, the EPA released the final Clean Air Mercury Rule (“CAMR”), a
two-phase program that utilizes a market-based cap and trade mechanism to reduce
mercury emissions from coal-burning power plants from the 1999 nationwide level
of 48 tons to 15 tons. The CAMR required initial reductions of mercury
emission in 2010 and an overall reduction in mercury emissions from coal-burning
power plants of 70% by 2018. The individual states in which PacifiCorp and
MidAmerican Energy operate facilities regulated under the CAMR submitted state
implementation plans reflecting their regulations relating to state mercury
control programs. On February 8, 2008, the United States Court of Appeals
for the District of Columbia Circuit held that the EPA improperly removed
electricity generating units from Section 112 of the Clean Air Act and,
thus, that the CAMR was improperly promulgated under Section 111 of the
Clean Air Act. The court vacated the CAMR’s new source performance standards and
remanded the matter to the EPA for reconsideration. In light of this decision,
it is not known the extent to which future mercury rules may impact PacifiCorp’s
and MidAmerican Energy’s current plans to reduce mercury emissions at their
coal-fired facilities.
In
March 2005, the EPA released the final Clean Air Interstate Rule (“CAIR”),
calling for reductions of SO2 and
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 has adopted rules implementing the market-based cap and trade system. While
the state of Iowa has been determined to be in attainment of the existing ozone
and fine particulate standards, Iowa has been found to significantly contribute
to nonattainment of the fine particulate standard in Cook County, Illinois; Lake
County, Indiana; Madison County, Illinois; St. Clair County, Illinois; and
Marion County, Indiana. The EPA has also concluded that emissions from Iowa
significantly contribute to ozone nonattainment in Kenosha and Sheboygan
counties in Wisconsin and Macomb County, Michigan. Under the CAIR, the first
phase of NOx emissions
reductions are effective January 1, 2009, and the first phase of
SO2
emissions reductions are effective January 1, 2010. For both NOx and
SO2,
the second-phase reductions are effective January 1, 2015. The CAIR
requires overall reductions by 2015 of SO2 and
NOx in
Iowa of 68% and 67%, respectively, from 2003 levels. PacifiCorp’s generation
facilities are not subject to the CAIR.
The CAIR
could, in whole or in part, be superseded or made more stringent by current or
future regulatory and legislative proposals at the federal or state levels that
would result in significant reductions of SO2, NOX and
mercury, as well as carbon dioxide and other gases that may affect global
climate change. In addition to any federal rules or legislation that could be
enacted, the CAIR could be changed or overturned as a result of litigation. The
sufficiency of the standards established by the CAIR has been legally challenged
in the United States Circuit Court of Appeals for the District of
Columbia.
Regional
Haze
The EPA
has initiated a regional haze program intended to improve visibility at specific
federally protected areas. Some of PacifiCorp’s and MidAmerican Energy’s plants
meet the threshold applicability criteria under the Clean Air Visibility Rules.
In accordance with the federal requirements, states were required to submit
state implementation plans by December 2007 to demonstrate reasonable progress
toward achieving natural visibility conditions in certain Class I areas by
requiring emission controls, known as best available retrofit technology, on
sources with emissions that are anticipated to cause or contribute to impairment
of visibility. Iowa submitted its state implementation plan to the EPA by
December 2007 and suggested that the emission reductions already made by
MidAmerican Energy and additional reductions that will be made under the CAIR
place the state in the position that no further reductions should be required.
Wyoming has not yet submitted its state implementation plan and is continuing to
review the results of analyses relating to planned emission reductions at
PacifiCorp’s Wyoming generating plants. Utah has not yet submitted its state
implementation plan, but expects to do so in the near term. PacifiCorp believes
that its planned emission reduction projects will satisfy the regional haze
requirements in Utah and Wyoming; however, it is possible that some additional
controls may be required once the respective state implementation plans have
been submitted.
New
Source Review
Under
existing New Source Review (“NSR”) provisions of the Clean Air Act, any facility
that emits regulated pollutants is required to obtain a permit from the EPA or a
state regulatory agency prior to (1) beginning construction of a new major
stationary source of an NSR-regulated pollutant, or (2) making a physical or
operational change to an existing stationary source of such pollutants that
increases certain levels of emissions, unless the changes are exempt under the
regulations (including routine maintenance, repair and replacement of
equipment). In general, projects subject to NSR regulations are subject to
pre-construction review and permitting under the Prevention of Significant
Deterioration (“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.
36
As part
of an industry-wide investigation to assess compliance with the NSR and PSD
provisions, the EPA has requested from numerous utilities information and
supporting documentation regarding their capital projects for various generating
plants. Between 2001 and 2003, PacifiCorp and MidAmerican Energy responded to
requests for information relating to their capital projects at their generating
plants. PacifiCorp has been engaged in periodic discussions with the EPA over
several years regarding this matter. There are currently no outstanding data
requests at MidAmerican Energy pending from the EPA. An NSR enforcement case
against another utility has been decided by the Supreme Court, holding that an
increase in the annual emissions of a facility, when combined with a
modification (i.e., a physical or operational change), may trigger NSR
permitting. PacifiCorp and MidAmerican Energy cannot predict the outcome of the
EPA’s review of the data they have submitted at this time.
In 2002
and 2003, the EPA proposed various changes to its NSR rules that clarify what
constitutes routine repair, maintenance and replacement for purposes of
triggering NSR requirements. These changes have been subject to legal challenge
and in March 2006, a panel of the United States Court of Appeals for the
District of Columbia Circuit invalidated portions of the EPA’s new NSR rules,
holding that they conflicted with the wording of the statute. However, the EPA
has asked the Supreme Court to review portions of the case. Until such time as
the legal challenges are resolved and the revised rules are effective,
PacifiCorp and MidAmerican Energy will continue to manage projects at their
generating plants in accordance with the rules in effect prior to 2002, except
for pollution-control projects, which are now subject to permitting under the
PSD program. In 2005, the EPA proposed a rule that would change or clarify how
emission increases are to be calculated for purposes of determining the
applicability of the NSR permitting program for existing power plants. The EPA
also proposed additional changes to the NSR rules in September 2006 that are
intended to simplify the permitting process and allow facilities to undertake
activities that improve their safety, reliability and efficiency without
triggering NSR requirements. In April 2007, the EPA issued a supplemental notice
of proposed rulemaking to the October 2005 proposed rulemaking to determine
emissions increases for electric generating units, proposing to use both hourly
and annual emissions tests to determine whether utilities trigger the NSR
permitting program when an existing power plant makes a physical or operational
change. The supplemental proposal was issued three weeks after the U.S. Supreme
Court issued a unanimous opinion in Environmental Defense v. Duke
Energy that the EPA was correct in applying an annual emissions test to
determine NSR compliance.
Refer to
Note 18 of Notes to Consolidated Financial Statements included in
Item 8 of this Form 10-K for additional information regarding
commitments and litigation related to air quality standards.
Renewable
Portfolio Standards
The
renewable portfolio standards (“RPS”) described below could significantly impact
the Company’s financial results. Resources that meet the qualifying electricity
requirements under the RPS vary from state-to-state. Each state’s RPS requires
some form of compliance reporting and the Company can be subject to penalties in
the event of non-compliance.
In
November 2006, Washington voters approved a ballot initiative establishing a RPS
requirement for qualifying electric utilities, including PacifiCorp. The
requirements are 3% of retail sales by January 1, 2012 through 2015, 9% of
retail sales by January 1, 2016 through 2019 and 15% of retail sales by
January 1, 2020. The WUTC has adopted final rules to implement the
initiative. The Company expects to be able to recover its costs of complying
with the RPS, either through rate cases or an adjustment mechanism.
37
In June
2007, the Oregon Renewable Energy Act (the “Act”) was adopted, providing a
comprehensive renewable energy policy for Oregon. Subject to certain exemptions
and cost limitations established in the Act, PacifiCorp and other qualifying
electric utilities must meet minimum qualifying electricity requirements for
electricity sold to retail customers of at least 5% in 2011 through 2014, 15% in
2015 through 2019, 20% in 2020 through 2024, and 25% in 2025 and subsequent
years. As required by the Act, the OPUC has approved an automatic adjustment
clause to allow an electric utility, including PacifiCorp, to recover prudently
incurred costs of its investments in renewable energy facilities and associated
transmission costs. The OPUC and the Oregon Department of Energy have undertaken
additional rulemaking proceedings to further implement the initiative. The
Company expects to be able to recover its costs of complying with the RPS
through the automatic adjustment mechanism.
California
law requires electric utilities to increase their procurement of renewable
resources by at least 1% of their annual retail electricity sales per year so
that 20% of their annual electricity sales are procured from renewable resources
by no later than December 31, 2010. However, PacifiCorp and other small
multi-jurisdictional utilities (“SMJU”) are currently awaiting further guidance
from the CPUC on the treatment of SMJUs in the California RPS program.
PacifiCorp has filed comments requesting SMJU rules for flexible compliance with
annual targets. PacifiCorp expects rules governing the treatment of SMJUs and
any specific flexible compliance mechanisms to be released by CPUC staff for
public review in early 2008. Absent further direction from the CPUC on treatment
of SMJUs, the Company cannot predict the impact of the California RPS on its
financial results.
Climate
Change
As a
result of increased attention to global climate change in the United States,
numerous bills have been introduced in the current session of the United States
Congress that would reduce greenhouse gas emissions in the United States.
Congressional leadership has made climate change legislation a priority, and
many congressional observers expect to see the passage of climate change
legislation within the next several years. The Lieberman-Warner Climate Security
Act of 2007 (S. 2191), was passed by the United States Senate Environment and
Public Works Committee on December 5, 2007. The bill would impose an
economy-wide cap on greenhouse gas emissions to reduce emissions 70% from 2005
levels by 2050. Included within the bill’s definition of a covered facility is
any facility that uses more than 5,000 tons of coal in a calendar year, which
includes all of PacifiCorp’s and MidAmerican Energy’s coal-fired generating
plants. In addition, nongovernmental organizations have become more active in
initiating citizen suits under existing environmental and other laws. In April
2007, a United States Supreme Court decision concluded that the EPA has the
authority under the Clean Air Act to regulate emissions of greenhouse gases from
motor vehicles. Furthermore, pending cases that address the potential public
nuisance from greenhouse gas emissions from electricity generators and the EPA’s
failure to regulate greenhouse gas emissions from new and existing coal-fired
plants are expected to become active. While debate continues at the national
level over the direction of domestic climate policy, several states have
developed state-specific laws or regional legislative initiatives to reduce
greenhouse gas emissions, including:
·
In
February 2007, the governors of California, Arizona, New Mexico, Oregon
and Washington signed the Western Regional Climate Action Initiative (the
“Western Climate Initiative”) that directed their respective states to
develop a regional target for reducing greenhouse gases by August 2007.
Utah joined the Western Climate Initiative in May 2007. The states in the
Western Climate Initiative announced a target of reducing greenhouse gas
emissions by 15% below 2005 levels by 2020, with Utah establishing its
reduction goal by August 2008. By August 2008, they are expected to devise
a market-based program, such as a load-based cap-and-trade program for the
electricity sector, to reach the target. The Western Climate Initiative
participants also have agreed to participate in a multi-state registry to
track and manage greenhouse gas emissions in the
region.
·
An
executive order signed by California’s governor in June 2005 would
reduce greenhouse gas emissions in that state to 2000 levels by 2010, to
1990 levels by 2020 and 80% below 1990 levels by 2050. In addition,
California has adopted legislation that imposes a greenhouse gas emission
performance standard to all electricity generated within the state or
delivered from outside the state that is no higher than the greenhouse gas
emission levels of a state-of-the-art combined-cycle natural gas
generation facility, as well as legislation that adopts an economy-wide
cap on greenhouse gas emissions to 1990 levels by
2020.
38
·
The
Washington and Oregon governors enacted legislation in May 2007 and August
2007, respectively, establishing economy-wide goals for the reduction of
greenhouse gas emissions in their respective states. Washington’s goals
seek to, (i) by 2020, reduce emissions to 1990 levels; (ii) by 2035,
reduce emissions to 25% below 1990 levels; and (iii) by 2050, reduce
emissions to 50% below 1990 levels, or 70% below Washington’s forecasted
emissions in 2050. Oregon’s goals seek to, (i) by 2010, cease the growth
of Oregon greenhouse gas emissions; (ii) by 2020, reduce greenhouse gas
levels to 10% below 1990 levels; and (iii) by 2050, reduce greenhouse gas
levels to at least 75% below 1990 levels. Each state’s legislation also
calls for state government developed policy recommendations in the future
to assist in the monitoring and achievement of these goals. The impact of
the enacted legislation on the Company cannot be determined at this
time.
·
In
Iowa, legislation enacted in 2007 requires the Iowa Climate Change
Advisory Council, a 23-member group appointed by the Iowa governor, to
develop scenarios designed to reduce statewide greenhouse gas emissions,
including one scenario that would reduce emissions by 50% by 2050, and
submit its recommendations to the legislature. The Iowa Climate Change
Advisory Council has determined that it will also develop a second
scenario to reduce greenhouse gas emissions by 90% with reductions in both
scenarios from 2005 emission
levels.
·
On
November 15, 2007, the Iowa governor signed the Midwest Greenhouse
Gas Accord and the Energy Security and Climate Stewardship Platform for
the Midwest. The signatories to the platform were other Midwestern states
that agreed to implement a regional cap and trade system for greenhouse
gas emissions by May 2010 after establishing emissions reduction
targets by July 2008 and adopting a model rule by November 2008.
In addition, the accord calls for the participating states to collectively
meet at least 2% of regional annual retail sales of natural gas and
electricity through energy efficiency improvements by 2015 and continue to
achieve an additional 2% in efficiency improvements every year
thereafter.
PacifiCorp
and MidAmerican Energy continue to add renewable electricity capacity to their
generation portfolios. In addition, PacifiCorp and MidAmerican Energy have
engaged in several voluntary programs designed to either reduce or avoid
greenhouse gas emissions, including the EPA’s sulfur hexafluoride reduction
program, refrigerator recycling programs, and the EPA landfill methane outreach
program. PacifiCorp is a member of the California Climate Action Registry and
The Climate Registry, under which it reports and certifies its greenhouse gas
emissions.
The
impact of any pending judicial proceedings and any pending or enacted federal
and state climate change legislation and regulation cannot be determined at this
time; however, adoption of stringent limits on greenhouse gas emissions could
significantly impact the Company’s current and future fossil-fueled facilities,
and, therefore, its financial results.
Water
Quality Standards
The Clean
Water Act establishes the framework for maintaining and improving water quality
in the United States through a program that regulates, among other things,
discharges to and withdrawals from waterways. The Clean Water Act requires that
cooling water intake structures reflect the “best technology available for
minimizing adverse environmental impact” to aquatic organisms. In July 2004, the
EPA established significant new national technology-based performance standards
for existing electric generating facilities that take in more than
50 million gallons of water a day. These rules are aimed at minimizing the
adverse environmental impacts of cooling water intake structures by reducing the
number of aquatic organisms lost as a result of water withdrawals. In response
to a legal challenge to the rule, in January 2007, the Second Circuit Court of
Appeals remanded almost all aspects of the rule to the EPA, leaving companies
with cooling water intake structures uncertain regarding compliance with these
requirements. Petitions for certiorari are pending before the U.S. Supreme Court
regarding the Second Circuit’s decision. Compliance and the potential costs of
compliance, therefore, cannot be ascertained until such time as further action
is taken by the EPA. Currently, PacifiCorp’s Dave Johnston Plant and all of
MidAmerican Energy’s coal-fired generating facilities, except Louisa, Ottumwa
and Walter Scott, Jr. Unit 4, which have water cooling towers, exceed the
50 million gallons of water per day in-take threshold. In the event that
PacifiCorp’s or MidAmerican Energy’s existing intake structures require
modification or alternative technology is required by new rules, expenditures to
comply with these requirements could be significant.
We are
subject to certain risks in our business operations which are described below.
Careful consideration of these risks, together with all of the other information
included in this annual report and the other public information filed by us,
should be made before making an investment decision. The risks and uncertainties
described below are not the only ones facing us. Additional risks and
uncertainties not presently known or that are currently deemed immaterial may
also impair our business operations.
Our Corporate and Financial
Structure Risks
We
are a holding company and depend on distributions from subsidiaries, including
joint ventures, to meet our obligations.
We are a
holding company with no material assets other than the stock of our subsidiaries
and joint ventures, collectively referred to as our subsidiaries. Accordingly,
cash flows and the ability to meet our obligations are largely dependent upon
the earnings of our subsidiaries and the payment of such earnings to us in the
form of dividends, loans, advances or other distributions. Our subsidiaries are
separate and distinct legal entities and have no obligation, contingent or
otherwise, to make funds available, whether by dividends, loans or other
payments, for payment of our obligations, and do not guarantee the payment of
any of our obligations. Distributions from subsidiaries may also be limited
by:
·
their
respective earnings, capital requirements, and required debt and preferred
stock payments;
·
the
satisfaction of certain terms contained in financing or organizational
documents; and
·
regulatory
restrictions which limit the ability of our regulated utility subsidiaries
to distribute profits.
We
are substantially leveraged, the terms of our senior and subordinated debt do
not restrict the incurrence of additional indebtedness by us or our
subsidiaries, and our senior and subordinated debt is structurally subordinated
to the indebtedness of our subsidiaries, each of which could have an adverse
impact on our financial results.
A
significant portion of our capital structure is debt and we expect to incur
additional indebtedness in the future to fund acquisitions, capital investments
or the development and construction of new or expanded facilities. As of
December 31, 2007, we had the following outstanding
obligations:
·
senior
indebtedness of $5.47 billion;
·
subordinated
indebtedness of $1.13 billion, consisting of $304 million of
trust preferred securities held by third parties and $821 million
held by Berkshire Hathaway and its affiliates;
and
·
guarantees
and letters of credit in respect of subsidiary and equity investment
indebtedness aggregating
$84 million.
Our
consolidated subsidiaries also have outstanding indebtedness, which totaled
$13.10 billion as of December 31, 2007. These amounts exclude (i)
trade debt or preferred stock obligations, (ii) letters of credit in respect of
subsidiary indebtedness, and (iii) our share of the outstanding
indebtedness of our own or our subsidiaries’ equity investments.
Given our
substantial leverage, we may not generate sufficient cash to service our debt
which could limit our ability to finance future acquisitions, develop and
construct additional projects, or operate successfully under adverse economic
conditions. It could also impair our credit quality or the credit quality of our
subsidiaries, making it more difficult to finance operations or issue future
indebtedness on favorable terms, and could result in a downgrade in debt ratings
by credit rating agencies.
40
The terms
of our senior and subordinated debt do not limit our ability or the ability of
our subsidiaries to incur additional debt or issue preferred stock. Accordingly,
we or our subsidiaries could enter into acquisitions, refinancings,
recapitalizations or other highly leveraged transactions that could
significantly increase our or our subsidiaries’ total amount of outstanding
debt. The interest payments needed to service this increased level of
indebtedness could have a material adverse effect on our or our subsidiaries’
financial results. Further, if an event of default accelerates a repayment
obligation and such acceleration results in an event of default under some or
all of our other indebtedness, we may not have sufficient funds to repay all of
the accelerated indebtedness.
Because
we are a holding company, the claims of our senior and subordinated debt holders
are structurally subordinated with respect to the assets and earnings of our
subsidiaries. Therefore, the rights of our creditors to participate in the
assets of any subsidiary in the event of a liquidation or reorganization are
subject to the prior claims of the subsidiary’s creditors and preferred
shareholders. In addition, a significant amount of the stock or assets of our
operating subsidiaries is directly or indirectly pledged to secure their
financings and, therefore, may be unavailable as potential sources of repayment
of our senior and subordinated debt.
A
downgrade in our credit ratings or the credit ratings of our subsidiaries could
negatively affect our or our subsidiaries’ access to capital, increase the cost
of borrowing or raise energy transaction credit support
requirements.
Our
senior unsecured long-term debt is rated investment grade by various rating
agencies. We cannot assure that our senior unsecured long-term debt will
continue to be rated investment grade in the future. Although none of our
outstanding debt has rating-downgrade triggers that would accelerate a repayment
obligation, a credit rating downgrade would increase our borrowing costs and
commitment fees on the revolving credit agreements, perhaps significantly. In
addition, we would likely be required to pay a higher interest rate in future
financings, and the potential pool of investors and funding sources would likely
decrease. Further, access to the commercial paper market, the principal source
of short-term borrowings, could be significantly limited resulting in higher
interest costs.
Similarly,
any downgrade or other event negatively affecting the credit ratings of our
subsidiaries could make their costs of borrowing higher or access to funding
sources more limited, which in turn could cause us to provide liquidity in the
form of capital contributions or loans to such subsidiaries, thus reducing our
and our subsidiaries’ liquidity and borrowing capacity.
Most of
our large customers, suppliers and counterparties require sufficient
creditworthiness in order to enter into transactions, particularly in the
wholesale energy markets. If our credit ratings or the credit ratings of our
subsidiaries were to decline, especially below investment grade, operating costs
would likely increase because counterparties may require a letter of credit,
collateral in the form of cash-related instruments or some other security as a
condition to further transactions with us or our subsidiaries.
Our
majority shareholder, Berkshire Hathaway, could exercise control over us in a
manner that would benefit Berkshire Hathaway to the detriment of our
creditors.
Berkshire
Hathaway is our majority owner and has control over all decisions requiring
shareholder approval, including the election of our directors. In circumstances
involving a conflict of interest between Berkshire Hathaway and our creditors,
Berkshire Hathaway could exercise its control in a manner that would benefit
Berkshire Hathaway to the detriment of our creditors.
41
Our Business
Risks
Much
of our growth has been achieved through acquisitions, and additional
acquisitions may not be successful.
Our
growth has been achieved largely through acquisitions, including, since 2002,
those of Kern River, Northern Natural Gas, PacifiCorp and various residential
real estate brokerage businesses. Future acquisitions may range from buying
individual assets to the purchase of entire businesses. We will continue to
investigate and pursue opportunities for future acquisitions that we believe may
increase shareholder value and expand or complement existing businesses. We may
participate in bidding or other negotiations at any time for such acquisition
opportunities which may or may not be successful. Any transaction that does take
place may involve consideration in the form of cash or debt or equity
securities.
Completion
of any acquisition entails numerous risks, including, among others,
the:
·
failure
to complete the transaction for various reasons, such as the inability to
obtain the required regulatory
approvals;
·
failure
of the combined business to realize the expected benefits or to meet
regulatory commitments; and
·
need
for substantial additional capital and financial
investments.
An
acquisition could cause an interruption of, or loss of momentum in, the
activities of one or more of our businesses. The diversion of management’s
attention and any delays or difficulties encountered in connection with the
approval and integration of the acquired operations could adversely affect our
combined businesses and financial results and could impair our ability to
realize the anticipated benefits of the acquisition.
We cannot
assure that future acquisitions, if any, or any related integration efforts will
be successful, or that our ability to repay our obligations will not be
adversely affected by any future acquisitions.
Our
regulated businesses are subject to extensive regulations that affect their
operations and costs. These regulations are complex, dynamic and subject to
change.
Our
businesses are subject to numerous regulations and laws enforced by regulatory
agencies. In the United States, these regulatory agencies include, among others,
the FERC, the EPA, the NRC, and the DOT. In addition, our domestic utility
subsidiaries are subject to state utility regulation in each state in which they
operate. In the United Kingdom, these regulatory agencies include, among others,
GEMA, which discharges certain of its powers through its staff within
Ofgem.
Regulations
affect almost every aspect of our business and limit our ability to
independently make and implement management decisions regarding, among other
items, business combinations, constructing, acquiring or disposing of operating
assets, setting rates charged to customers, establishing capital structures and
issuing debt or equity securities, engaging in transactions between our domestic
utilities and other subsidiaries and affiliates, and paying dividends.
Regulations are subject to ongoing policy initiatives and we cannot predict the
future course of changes in regulatory laws, regulations and orders, or the
ultimate effect that regulatory changes may have on us. However, such changes
could materially impact our financial results. For example, such changes could
result in, but are not limited to, increased retail competition within our
subsidiaries’ service territories; new environmental requirements, including the
implementation of RPS and greenhouse gas emissions reduction goals; the
acquisition by a municipality or other quasi-governmental body of our
subsidiaries’ distribution facilities (by negotiation, legislation or
condemnation or by a vote in favor of a Public Utility District under Oregon
law); or a negative impact on our subsidiaries’ current transportation and cost
recovery arrangements, including income tax recovery.
42
Federal
and state energy regulation changes are emerging as one of the more challenging
aspects of managing utility operations. New and expanded regulations imposed by
policy makers, court systems, and industry restructuring have imposed changes on
the industry. The following are examples of current or recent changes to our
regulatory environment that may impact us:
·
Energy Policy Act of 2005 -
In the United States, the Energy Policy Act impacts many segments
of the energy industry. The U.S. Congress granted the FERC additional
authority in the Energy Policy Act which expanded its regulatory role from
a regulatory body to an enforcement agency. To implement the law, the FERC
has and will continue to issue new regulations and regulatory decisions
addressing electric system reliability, electric transmission planning,
operation, expansion and pricing, regulation of utility holding companies,
and enforcement authority, including the ability to assess civil penalties
of up to $1 million per day per infraction for non-compliance. The
full impact of those decisions remains uncertain however, the FERC has
vigorously exercised its enforcement authority by imposing significant
civil penalties for violations of its rules and regulations. 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. Since the
adoption of the Energy Policy Act, the FERC has approved numerous electric
reliability, cyber security and critical infrastructure protection
standards developed by the NERC. A transmission owner’s reliability
compliance issues with these and future standards could result in
financial penalties. In Order No. 693, the FERC implemented its
authority to impose penalties of up to $1 million per day per
violation for failure to comply with electric reliability standards. The
adoption of these and future electric reliability standards will impose
more comprehensive and stringent requirements on our public utility
subsidiaries, which could result in increased compliance costs and could
adversely affect our financial
results.
·
FERC Orders – The FERC
has issued a series of orders to encourage competition in natural gas
markets, the expansion of existing pipelines and the construction of new
pipelines and to foster greater competition in wholesale power markets by
reducing barriers to entry in the provision of transmission service. As a
result of Order Nos. 636 and 637, in the natural gas markets, LDCs
and end-use customers have additional choices in this more competitive
environment and may be able to obtain service from more than one pipeline
to fulfill their natural gas delivery requirements. Any new pipelines that
are constructed could compete with our pipeline subsidiaries to service
customer needs. Increased competition could reduce the volumes of gas
transported by our pipeline subsidiaries or, in the absence of long-term
fixed rate contracts, could force our pipeline subsidiaries to lower their
rates to remain competitive. This could adversely affect our pipeline
subsidiaries’ financial results. In Order Nos. 888, 889, 890 and
890-A, the FERC required electric utilities to adopt a proforma OATT by
which transmission service would be provided on a just, reasonable and not
unduly discriminatory or preferential basis. The rules adopted by these
orders promote transparency and consistency in the administration of the
OATT, increase the ability of customers to access new generating resources
and promote efficient utilization of transmission by requiring an open,
transparent and coordinated transmission planning process. Together with
the increased reliability standards required of transmission providers,
the cost of operating the transmission system and providing transmission
service has increased and, to the extent such increased costs are not
recovered in rates charged to customers, it could adversely affect our
financial results.
·
Hydroelectric
Relicensing - Several of PacifiCorp’s hydroelectric projects whose
operating licenses have expired or will expire in the next several years
are in some stage of the FERC relicensing process. Hydroelectric
relicensing is a political and public regulatory process involving
sensitive resource issues and uncertainties. We cannot predict with
certainty the requirements (financial, operational or otherwise) that may
be imposed by relicensing, the economic impact of those requirements, and
whether new licenses will ultimately be issued or whether PacifiCorp will
be willing to meet the relicensing requirements to continue operating its
hydroelectric projects. Loss of hydroelectric resources or additional
commitments arising from relicensing could adversely affect our financial
results.
43
Recovery
of costs by our energy subsidiaries is subject to regulatory review and
approval, and the inability to recover costs may adversely affect their
financial results.
State
Rate Proceedings - Public Utility Subsidiaries
Two of
our regulated subsidiaries, PacifiCorp and MidAmerican Energy, establish rates
for their regulated retail service through state regulatory proceedings. These
proceedings typically involve multiple parties, including government bodies and
officials, consumer advocacy groups and various consumers of energy, who have
differing concerns, but who generally have the common objective of limiting rate
increases. Decisions are subject to appeal, potentially leading to additional
uncertainty associated with the approval proceedings.
Each
state sets retail rates based in part upon the state utility commission’s
acceptance of an allocated share of total utility costs. When states adopt
different methods to calculate interjurisdictional cost allocations, some costs
may not be incorporated into rates of any state. Ratemaking is also generally
done on the basis of estimates of normalized costs, so if a given year’s
realized costs are higher than normal, rates will not be sufficient to cover
those costs. Each state utility commission generally sets rates based on a test
year established in accordance with that commission’s policies. Certain states
use a future test year or allow for escalation of historical costs while other
states use a historical test year. Use of a historical test year may cause
regulatory lag which results in our utilities incurring costs, including
significant new investments, for which recovery through rates is delayed. State
commissions also decide the allowed rate of return we will be permitted to earn
on our equity investment. They also decide the allowed levels of expense and
investment that they deem is just and reasonable in providing service. The state
commissions may disallow recovery in rates for any costs that do not meet such
standard.
In Iowa,
MidAmerican Energy has agreed not to seek a general increase in electric base
rates to become effective prior to January 1, 2014 unless its Iowa
jurisdictional electric return on equity for any year falls below 10%.
MidAmerican Energy expects to continue to make significant capital expenditures
to maintain and improve the reliability of its generation, transmission and
distribution facilities to reduce emissions and to support new business and
customer growth. As a result, MidAmerican Energy’s financial results may be
adversely affected if it is not able to deliver electricity in a cost-efficient
manner and is unable to offset inflation and the cost of infrastructure
investments with costs savings or additional sales.
In
certain states, PacifiCorp and MidAmerican Energy are not permitted to pass
through energy cost increases in their electric rates without a general rate
case. Any significant increase in fuel costs or purchased power costs for
electricity generation could have a negative impact on PacifiCorp or MidAmerican
Energy, despite efforts to minimize this impact through future general rate
cases or the use of hedging instruments. Any of these consequences could
adversely affect our financial results.
While
rate regulation is premised on providing a fair opportunity to obtain a
reasonable rate of return on invested capital, the state regulatory commissions
do not guarantee that we will be able to realize a reasonable rate of
return.
The FERC
establishes cost-based tariffs under which both PacifiCorp and MidAmerican
Energy provide transmission services to wholesale markets and retail markets in
states that allow retail competition. The FERC also has responsibility for
approving both cost- and market-based rates under which both these companies
sell electricity at wholesale and has licensing authority over most of
PacifiCorp’s hydroelectric generation facilities. The FERC may impose price
limitations, bidding rules and other mechanisms to address some of the
volatility of these markets or may (pursuant to pending or future proceedings)
revoke or restrict the ability of our public utility subsidiaries to sell
electricity at market-based rates, which could adversely affect our financial
results. The FERC may also impose substantial civil penalties for any
non-compliance with the Federal Power Act and the FERC’s rules and
orders.
Interstate
Pipelines
The FERC
also has jurisdiction over the construction and operation of pipelines and
related facilities used in the transportation, storage and sale of natural gas
in interstate commerce, including the modification or abandonment of such
facilities and rates, charges and terms and conditions of service for the
transportation of natural gas in interstate commerce.
44
Rates
established for our U.S. interstate gas transmission and storage operations at
Northern Natural Gas and Kern River are subject to the FERC’s regulatory
authority. The rates the FERC authorizes these companies to charge their
customers may not be sufficient to cover the costs incurred to provide services
in any given period. These pipelines, from time to time, have in effect rate
settlements approved by the FERC which prevent them or third parties from
modifying rates, except for allowed adjustments, for certain periods. These
settlements do not preclude the FERC from initiating a separate proceeding under
the Natural Gas Act to modify the rates. It is not possible to determine at this
time whether any such actions would be instituted or what the outcome would be,
but such proceedings could result in rate adjustments.
U.K.
Electricity Distribution
Northern
Electric and Yorkshire Electricity, as holders of electricity distribution
licenses, are subject to regulation by GEMA. Most of the revenue of the
electricity DLH is controlled by a distribution price control formula set out in
the electricity distribution license. The price control formula does not
constrain profits from year to year, but is a control on revenue that operates
independently of most of the electricity distribution license holder’s costs. It
has been the practice of Ofgem, to review and reset the formula at five-year
intervals, although the formula has been, and may be, reviewed at other times at
the discretion of Ofgem. The current five-year cost control period became
effective on April 1, 2005. A resetting of the formula requires the consent
of the electricity distribution license holder; however, license modifications
may be unilaterally imposed by Ofgem without such consent following review by
the British competition commission. GEMA is able to impose financial penalties
on electricity distribution companies who contravene any of their electricity
distribution license duties or certain of their duties under British law, or
fail to achieve satisfactory performance of individual standards prescribed by
GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the
electricity distribution license holder’s revenue. During the term of the price
control, additional costs have a direct impact on the financial results of
Northern Electric and Yorkshire Electricity.
Through
energy subsidiaries, we are actively pursuing, developing and constructing new
or expanded facilities, the completion and expected cost of which is subject to
significant risk, and our electric utility subsidiaries have significant funding
needs related to their planned capital expenditures.
Through
energy subsidiaries, we are continuing to develop and construct new or expanded
facilities. We expect that these subsidiaries will incur substantial annual
capital expenditures over the next several years. Expenditures could include,
among others, amounts for new coal-fired, natural gas, nuclear and wind powered
electric generating facilities, electric transmission or distribution projects,
environmental control and compliance systems, gas storage facilities, new or
expanded pipeline systems, as well as the continued maintenance of the installed
asset base.
Development
and construction of major facilities are subject to substantial risks, including
fluctuations in the price and availability of commodities, manufactured goods,
equipment, labor and other items over a multi-year construction period. These
risks may result in higher than expected costs to complete an asset and place it
into service. Such costs may not be recoverable in the regulated rates or market
prices our subsidiaries are able to charge their customers. It is also possible
that additional generation needs may be obtained through power purchase
agreements, which could increase long-term purchase obligations and force our
subsidiaries to rely on the operating performance of a third party. The
inability to successfully and timely complete a project, avoid unexpected costs
or to recover any such costs may materially affect our financial
results.
Furthermore,
our energy subsidiaries depend upon both internal and external sources of
liquidity to provide working capital and to fund capital requirements. If we do
not provide needed funding to our subsidiaries and the subsidiaries are unable
to obtain funding from external sources, they may need to postpone or cancel
planned capital expenditures. Failure to construct these projects could limit
opportunities for revenue growth, increase operating costs and adversely affect
the reliability of electric service to our customers. For example, if PacifiCorp
is not able to expand its existing generating facilities it may be required to
enter into bilateral long-term electricity procurement contracts or procure
electricity at more volatile and potentially higher prices in the spot markets
to support growing retail loads.
45
Our
subsidiaries are subject to numerous environmental, health, safety and other
laws, regulations and other requirements that may adversely affect our financial
results.
Operational
Standards
Our
subsidiaries are subject to numerous environmental, health, safety, and other
laws, regulations and other requirements affecting many aspects of their present
and future operations, including, among others:
·
the
EPA’s CAIR, which established cap and trade programs to reduce sulfur
dioxide, or SO2, and
nitrous oxide, or NOx,
emissions starting in 2009 to address alleged contributions to downwind
non-attainment with the revised National Ambient Air Quality
Standards;
·
the
DOT regulations, effective in 2004, that establish mandatory inspections
for all natural gas transmission pipelines in high-consequence areas
within 10 years. These regulations require pipeline operators to implement
integrity management programs, including more frequent inspections, and
other safety protections in areas where the consequences of potential
pipeline accidents pose the greatest risk to life and
property;
·
the
provisions of the Mine Improvement and New Emergency Response Act of 2006
to improve underground coal mine safety and emergency
preparedness;
·
the
implementation of federal and state renewable portfolio standards;
and
·
other
laws or regulations that establish or could establish standards for
greenhouse gas emissions, water quality, wastewater discharges, solid
waste and hazardous waste.
These and
related laws, regulations and orders generally require our subsidiaries to
obtain and comply with a wide variety of environmental licenses, permits,
inspections and other approvals.
Compliance
with environmental, health, safety, and other laws, regulations and other
requirements can require significant capital and operating expenditures,
including expenditures for new equipment, inspection, cleanup costs, damages
arising out of contaminated properties, and fines, penalties and injunctive
measures affecting operating assets for failure to comply with environmental
regulations. Compliance activities pursuant to regulations could be
prohibitively expensive. As a result, some facilities may be required to shut
down or alter their operations. Further, our subsidiaries may not be able to
obtain or maintain all required environmental regulatory approvals for their
operating assets or development projects. Delays in or active opposition by
third parties to obtaining any required environmental or regulatory permits,
failure to comply with the terms and conditions of the permits or increased
regulatory or environmental requirements may increase costs or prevent or delay
our subsidiaries from operating their facilities, developing new facilities,
expanding existing facilities or favorably locating new facilities. If our
subsidiaries fail to comply with all applicable environmental requirements, they
may be subject to penalties and fines or other sanctions. The costs of complying
with current or new environmental, health, safety, and other laws, regulations
and other requirements could adversely affect our financial results. Not being
able to operate existing facilities or develop new electric generating
facilities to meet customer energy needs could require our subsidiaries to
increase their purchases of power from the wholesale markets which could
increase market and price risks and adversely affect our financial results.
Proposals for voluntary initiatives and mandatory controls are being discussed
both in the United States and worldwide to reduce so-called ‘‘greenhouse gases’’
such as carbon dioxide, a by-product of burning fossil fuels, methane (the
primary component of natural gas), and methane leaks from pipelines. These
actions could result in increased costs to (i) operate and maintain our
facilities, (ii) install new emission controls on our facilities and (iii)
administer and manage any greenhouse gas emissions program. These actions could
also impact the consumption of natural gas, thereby affecting our
operations.
Further,
the regulatory rate structure or long-term customer contracts may not
necessarily allow our regulated subsidiaries to recover all costs incurred to
comply with new environmental requirements. Although we believe that, in most
cases, our regulated subsidiaries are legally entitled to recover these kinds of
costs, the inability to fully recover such costs in a timely manner could
adversely affect our financial results.
46
Site
Clean-up and Contamination
Environmental,
health, safety, and other laws, regulations and other requirements also impose
obligations to remediate contaminated properties or to pay for the cost of such
remediation, often by parties that did not actually cause the contamination. Our
subsidiaries are generally responsible for on-site liabilities, and in some
cases off-site liabilities, associated with the environmental condition of their
assets, including power generation facilities, and electric and natural gas
transmission and distribution assets which our subsidiaries have acquired or
developed, regardless of when the liabilities arose and whether they are known
or unknown. In connection with acquisitions, we or our subsidiaries may obtain
or require indemnification against some environmental liabilities. If our
subsidiaries incur a material liability, or the other party to a transaction
fails to meet its indemnification obligations, our subsidiaries could suffer
material losses. Our subsidiaries have established reserves to recognize their
estimated obligations for known remediation liabilities, but such estimates may
change materially over time. PacifiCorp is required to fund its portion of the
costs of mine reclamation at its coal mining operations, which include
principally site restoration. Also, MidAmerican Energy is required to fund its
portion of the costs of decommissioning the Quad Cities Station, when it is
retired from service, which may include site remediation or decontamination. In
addition, future events, such as changes in existing laws or policies or their
enforcement, or the discovery of currently unknown contamination, may give rise
to additional remediation liabilities that may be material.
Our
subsidiaries are exposed to credit risk of counterparties with whom they do
business and failure of their significant customers to perform under or to renew
their contracts could reduce our operating revenues materially.
Certain
of our subsidiaries are dependent upon a relatively small number of customers
for a significant portion of their revenues. For example:
·
a
significant portion of our pipeline subsidiaries’ capacity is contracted
under long-term arrangements, and our pipeline subsidiaries are dependent
upon relatively few customers for a substantial portion of their
revenues;
·
PacifiCorp
and MidAmerican Energy rely on their wholesale customers to fulfill their
commitments and pay for energy delivered to them on a timely
basis;
·
our
U.K. utility electricity distribution businesses are dependent upon a
relatively small number of retail suppliers. In particular, one supplier,
RWE Npower PLC and certain of its affiliates represented approximately 40%
of the total distribution revenues of our U.K. distribution companies in
2007; and
·
generally,
a single power purchaser takes energy from our non-utility generating
facilities.
Adverse
economic conditions or other events affecting counterparties with whom our
subsidiaries conduct business could impair the ability of these counterparties
to pay for services or fulfill their contractual obligations, or cause them to
delay or reduce such payments to our subsidiaries. Our subsidiaries depend on
these counterparties to remit payments on a timely basis. Any delay or default
in payment or limitation on the subsidiaries to negotiate alternative
arrangements could adversely affect our financial results.
If our
subsidiaries are unable to renew, remarket, or find replacements for their
long-term arrangements, our sales volume and revenue would be exposed to
increased volatility. For example, without the benefit of long-term
transportation, transmission or power purchase agreements, we cannot assure that
our pipeline subsidiaries will be able to transport gas at efficient capacity
levels, our regulated subsidiaries’ will be able to operate profitably, or our
unregulated power generators will be able to sell the power generated by the
non-utility generating facilities. Failure to secure these long-term
arrangements could adversely affect our financial results.
The
replacement of any existing long-term customer arrangements depends on market
conditions and other factors that are beyond our subsidiaries’
control.
47
Inflation
and changes in commodity prices and fuel transportation costs may adversely
affect our financial results.
Inflation
affects our businesses through increased operating costs and increased capital
costs for plant and equipment. As a result of existing rate agreements and
competitive price pressures, our subsidiaries may not be able to pass the costs
of inflation on to their customers. If our subsidiaries are unable to manage
cost increases or pass them on to their customers, our financial results could
be adversely affected.
We are
also exposed to changes in prices and availability of coal and natural gas and
the transportation of coal and natural gas because a substantial portion of our
generation capacity utilizes these fossil fuels. Each of our electric utilities
currently has contracts of varying durations for the supply and transportation
of coal for much of their existing generation capacity, although PacifiCorp
obtains some of its coal supply from mines owned or leased by it. When these
contracts expire or if they are not honored, we may not be able to purchase or
transport coal on terms as favorable as the current contracts. We have similar
exposures regarding the market price of natural gas. Changes in the cost of coal
or natural gas supply and transportation and changes in the relationship between
such costs and the market price of power will affect our financial results.
Since the sales price we receive for power may not change at the same rate as
our coal or natural gas supply and transportation costs, we may be unable to
pass on the changes in costs to our customers. In addition, the overall prices
we charge our retail customers in some jurisdictions are capped and our fuel
recovery mechanisms in other states are frozen for various periods of time or
have been eliminated.
A
significant decrease in demand for natural gas or electricity in the markets
served by our subsidiaries’ pipeline and gas distribution systems would
significantly decrease our operating revenues and thereby adversely affect our
business and financial results.
A
sustained decrease in demand for natural gas or electricity in the markets
served by our subsidiaries would significantly reduce our operating revenue and
adversely affect our financial results. Factors that could lead to a decrease in
market demand include, among others:
·
a
recession or other adverse economic condition that results in a lower
level of economic activity or reduced spending by consumers on natural gas
or electricity;
·
an
increase in the market price of natural gas or electricity or a decrease
in the price of other competing forms of
energy;
·
efforts
by customers to reduce their consumption of energy through various
conservation and energy efficiency measures and
programs;
·
higher
fuel taxes or other governmental or regulatory actions that increase,
directly or indirectly, the cost of natural gas or the fuel source for
electricity generation or that limit the use of natural gas or the
generation of electricity from fossil fuels;
and
·
a
shift to more energy-efficient or alternative fuel machinery or an
improvement in fuel economy, whether as a result of technological advances
by manufacturers, legislation mandating higher fuel economy or lower
emissions, price differentials, incentives or
otherwise.
Our
public utility subsidiaries’ financial results may be adversely affected if they
are unable to obtain adequate, reliable and affordable access to transmission
service.
Our
public utility subsidiaries depend on transmission facilities owned and operated
by other utilities to transport electricity and natural gas to both wholesale
and retail markets, as well as natural gas purchased to supply some of our
subsidiaries’ electric generation facilities. If adequate transmission is
unavailable, our subsidiaries may be unable to purchase and sell and deliver
products. Such unavailability could also hinder our subsidiaries from providing
adequate or economical electricity or natural gas to their wholesale and retail
electric and gas customers and could adversely affect their financial
results.
The
different regional power markets have varying and dynamic regulatory structures,
which could affect our businesses growth and performance. In addition, the
independent system operators who oversee the transmission systems in regional
power markets have imposed in the past, and may impose in the future, price
limitations and other mechanisms to counter volatility in the power markets.
These types of price limitations and other mechanisms may adversely impact the
financial results of our utilities.
48
Our subsidiaries are subject to
market risk, counterparty performance risk and other risks associated with
wholesale energy markets.
In
general, wholesale market risk is the risk of adverse fluctuations in the market
price of wholesale electricity and fuel, including natural gas and coal, which
is compounded by volumetric changes affecting the availability of or demand for
electricity and fuel. PacifiCorp and MidAmerican Energy purchase electricity and
fuel in the open market or pursuant to short-term or variable-priced contracts
as part of their normal operating businesses. If market prices rise, especially
in a time when larger than expected volumes must be purchased at market or
short-term prices, PacifiCorp or MidAmerican Energy may incur significantly
greater expense than anticipated. Likewise, if electricity market prices decline
in a period when PacifiCorp or MidAmerican Energy is a net seller of electricity
in the wholesale market, PacifiCorp or MidAmerican Energy will earn less
revenue.
Wholesale
electricity prices in PacifiCorp’s service areas are influenced primarily by
factors throughout the Western United States relating to supply and demand.
Those factors include the adequacy of generating capacity, scheduled and
unscheduled outages of generating facilities, hydroelectric generation levels,
prices and availability of fuel sources for generation, disruptions or
constraints to transmission facilities, weather conditions, economic growth and
changes in technology. Volumetric changes are caused by unanticipated changes in
generation availability and/or changes in customer loads due to the weather, the
economy, regulations or customer behavior. Although PacifiCorp plans for
resources to meet its current and expected retail and wholesale load
obligations, PacifiCorp is a net buyer of electricity during peak periods and
therefore, its energy costs may be adversely impacted by market risk. In
addition, PacifiCorp may not be able to timely recover all, if any, of those
increased costs unless the state regulators authorize such
recovery.
MidAmerican
Energy’s total accredited net generating capability exceeds its historical peak
load. As a result, in comparison to PacifiCorp, which relies to a significant
extent on purchased power to satisfy its peak load, MidAmerican Energy has less
exposure to wholesale electricity market price fluctuations. The actual amount
of generation capacity available at any time, however, may be less than the
accredited capacity due to regulatory restrictions, transmission constraints,
fuel restrictions and generating units being temporarily out of service for
inspection, maintenance, refueling, modifications or other reasons. In such
circumstances, MidAmerican Energy may need to purchase energy in the wholesale
markets and it may not recover in rates all of the additional costs that may be
associated with such purchases. Most of MidAmerican Energy’s electric wholesale
sales and purchases take place under market-based pricing allowed by the FERC
and are therefore subject to market volatility, including price
fluctuations.
PacifiCorp
and MidAmerican Energy are also exposed to risks related to performance of
contractual obligations by wholesale suppliers and customers. Each utility
relies on suppliers to deliver commodities, primarily natural gas, coal and
electricity, in accordance with short- and long-term contracts. Failure or delay
by suppliers to provide these commodities pursuant to existing contracts could
disrupt the delivery of electricity and require the utilities to incur
additional expenses to meet customer needs. In addition, when these contracts
terminate, the utilities may be unable to purchase the commodities on terms
equivalent to the terms of current contracts.
PacifiCorp
and MidAmerican Energy rely on wholesale customers to take delivery of the
energy they have committed to purchase and to pay for the energy on a timely
basis. Failure of customers to take delivery may require these subsidiaries to
find other customers to take the energy at lower prices than the original
customers committed to pay. At certain times of the year, prices paid by
PacifiCorp and MidAmerican Energy for energy needed to satisfy their customers’
energy needs may exceed the amounts they receive through rates from these
customers. If the strategy used to minimize these risk exposures is ineffective,
significant losses could result.
Our
operating results may fluctuate on a seasonal and quarterly basis.
The sale
of electric power and natural gas are generally seasonal businesses. In most
parts of the United States and other markets in which our subsidiaries operate,
demand for electricity peaks during the hot summer months when cooling needs are
higher. Market prices for electric supply also generally peak at that time. In
other areas, demand for electricity peaks during the winter. In addition, demand
for gas and other fuels generally peaks during the winter when heating needs are
higher. This is especially true in Northern Natural Gas’ market area and
MidAmerican Energy’s retail gas business. Further, extreme weather conditions
such as heat waves or winter storms could cause these seasonal fluctuations to
be more pronounced. Periods of low rainfall or snow-pack may also impact
electric generation at PacifiCorp’s hydroelectric projects.
49
As a
result, the overall financial results of our energy subsidiaries may fluctuate
substantially on a seasonal and quarterly basis. We have historically sold less
power, and consequently earned less income, when weather conditions are mild.
Unusually mild weather in the future may adversely affect our financial results
through lower revenues or margins. Conversely, unusually extreme weather
conditions could increase our costs to provide power and adversely affect our
financial results. Furthermore, during or following periods of low rainfall or
snowpack, PacifiCorp may obtain substantially less electricity from
hydroelectric projects and must purchase greater amounts of electricity from the
wholesale market or from other sources at market prices. The extent of
fluctuation in financial results may change depending on a number of factors
related to our subsidiaries’ regulatory environment and contractual agreements,
including their ability to recover power costs, the existence of revenue sharing
provisions and terms of the power sale contracts.
Our
subsidiaries are subject to operating uncertainties that may adversely affect
our financial results.
The
operation of complex electric and gas utility (including generation,
transmission and distribution) systems, pipelines or power generating facilities
that are spread over large geographic areas involves many operating
uncertainties and events beyond our control. These potential events include the
breakdown or failure of power generation equipment, compressors, pipelines,
transmission and distribution lines or other equipment or processes, unscheduled
plant outages, work stoppages, shortage of qualified labor, transmission and
distribution system constraints or outages, fuel shortages or interruptions,
unavailability of critical equipment, materials and supplies, low water flows,
performance below expected levels of output, capacity or efficiency, operator
error and catastrophic events such as severe storms, fires, earthquakes,
explosions or mining accidents. A casualty occurrence might result in injury or
loss of life, extensive property damage or environmental damage. Any of these
risks or other operational risks could significantly reduce or eliminate our
subsidiaries’ revenues or significantly increase their expenses, thereby
reducing the availability of distributions to us. For example, if our
subsidiaries cannot operate their electric or natural gas facilities at full
capacity due to damage caused by a catastrophic event, their revenues could
decrease due to decreased sales and their expenses could increase due to the
need to obtain energy from more expensive sources. Further, we self-insure many
risks and current and future insurance coverage may not be sufficient to replace
lost revenues or cover repair and replacement costs. Any reduction of revenues
for such reason, or any other reduction of our subsidiaries’ revenues or
increase in their expenses resulting from the risks described above could
adversely affect our financial results.
Potential
terrorist activities or military or other actions could adversely affect
us.
The
continued threat of terrorism since September 11, 2001 and the impact of
military and other actions by the United States and its allies may lead to
increased political, economic and financial market instability and subject our
subsidiaries’ operations to increased risk of acts of terrorism. The United
States government has issued warnings that energy assets, specifically pipeline,
nuclear generation and other electric utility infrastructure are potential
targets for terrorist organizations. Political, economic or financial market
instability or damage to the operating assets of our subsidiaries, customers or
suppliers may result in business interruptions, lost revenue, higher commodity
prices, disruption in fuel supplies, lower energy consumption and unstable
markets, particularly with respect to natural gas and electric energy, increased
security, repair or other costs that may materially adversely affect us and our
subsidiaries in ways that cannot be predicted at this time. Any of these risks
could materially affect our financial results. Furthermore, instability in the
financial markets as a result of terrorism or war could also materially
adversely affect our ability and the ability of our subsidiaries to raise
capital.
The
insurance industry changed in response to these events. As a result, insurance
covering risks we and our subsidiaries typically insure against may decrease in
scope and availability and we may elect to self-insure against many such risks.
In addition, the available insurance may have higher deductibles, higher
premiums and more restrictive policy terms.
50
MidAmerican
Energy is subject to the unique risks associated with nuclear
generation.
The
ownership and operation of nuclear power plants, such as MidAmerican Energy’s
25% ownership interest in the Quad Cities Station involves certain risks. These
risks include, among other items, mechanical or structural problems, inadequacy
or lapses in maintenance protocols, the impairment of reactor operation and
safety systems due to human error, the costs of storage, handling and disposal
of nuclear materials, limitations on the amounts and types of insurance coverage
commercially available, and uncertainties with respect to the technological and
financial aspects of decommissioning nuclear facilities at the end of their
useful lives. The prolonged unavailability of the Quad Cities Station could
materially affect MidAmerican Energy’s financial results, particularly when the
cost to produce power at the plant is significantly less than market wholesale
power prices. The following are among the more significant of these
risks:
·
Operational
Risk - Operations at any nuclear power plant could degrade to the point
where the plant would have to be shut down. If such degradations were to
occur, the process of identifying and correcting the causes of the
operational downgrade to return the plant to operation could require
significant time and expense, resulting in both lost revenue and increased
fuel and purchased power expense to meet supply commitments. Rather than
incurring substantial costs to restart the plant, the plant could be shut
down. Furthermore, a shut-down or failure at any other nuclear plant could
cause regulators to require a shut-down or reduced availability at the
Quad Cities Station.
·
Regulatory
Risk - The NRC may modify, suspend or revoke licenses and impose civil
penalties for failure to comply with the Atomic Energy Act, applicable
regulations or the terms of the licenses of nuclear facilities. Unless
extended, the NRC operating licenses for the Quad Cities Station will
expire in 2032. Changes in regulations by the NRC could require a
substantial increase in capital expenditures or result in increased
operating or decommissioning costs.
·
Nuclear
Accident Risk - Accidents and other unforeseen problems have occurred at
nuclear facilities other than the Quad Cities Station, both in the United
States and elsewhere. The consequences of an accident can be severe and
include loss of life and property damage. Any resulting liability from a
nuclear accident could exceed MidAmerican Energy’s resources, including
insurance coverage.
We
own investments and projects located in foreign countries that are exposed to
increased economic, regulatory and political risks.
We own
and may acquire significant energy-related investments and projects outside of
the United States. The economic, regulatory and political conditions in some of
the countries where we have operations or are pursuing investment opportunities
may present increased risks related to, among others, inflation, currency
exchange rate fluctuations, currency repatriation restrictions, nationalization,
renegotiation, privatization, availability of financing on suitable terms,
customer creditworthiness, construction delays, business interruption, political
instability, civil unrest, guerilla activity, terrorism, expropriation, trade
sanctions, contract nullification and changes in law, regulations or tax policy.
We may not be capable of either fully insuring against or effectively hedging
these risks.
We
are exposed to risks related to fluctuations in currency rates.
Our
business operations and investments outside the United States increase our risk
related to fluctuations in currency rates, primarily the British pound and the
Philippine peso. Our principal reporting currency is the United States dollar,
and the value of the assets and liabilities, earnings, cash flows and potential
distributions from our foreign operations changes with the fluctuations of the
currency in which they transact. We may selectively reduce some foreign currency
risk by, among other things, requiring contracted amounts to be settled in
United States dollars, indexing contracts to the United States dollar or hedging
through foreign currency derivatives. These efforts, however, may not be
effective and could negatively affect our financial results. We attempt, in many
circumstances, to structure foreign transactions to provide for payments to be
made in, or indexed to, United States dollars or a currency freely convertible
into United States dollars. We may not be able to obtain sufficient dollars or
other hard currency or available dollars may not be allocated to pay such
obligations, which could adversely affect our financial results.
51
Cyclical
fluctuations in the residential real estate brokerage and mortgage businesses
could adversely affect HomeServices.
The
residential real estate brokerage and mortgage industries tend to experience
cycles of greater and lesser activity and profitability and are typically
affected by changes in economic conditions which are beyond HomeServices’
control. Any of the following are examples of items that could have a material
adverse effect on HomeServices’ businesses by causing a general decline in the
number of home sales, sale prices or the number of home financings which, in
turn, would adversely affect its financial results:
·
rising
interest rates or unemployment
rates;
·
periods
of economic slowdown or recession in the markets
served;
·
decreasing
home affordability;
·
lack
of available mortgage credit for potential
homebuyers;
·
declining
demand for residential real estate as an investment;
and
·
nontraditional
sources of new competition.
We
and our subsidiaries are involved in numerous legal proceedings, the outcomes of
which are uncertain and could negatively affect our financial
results.
We and
our subsidiaries are parties to numerous legal proceedings. Litigation is
subject to many uncertainties, and we cannot predict the outcome of individual
matters. It is possible that the final resolution of some of the matters in
which we and our subsidiaries are involved could result in additional payments
in excess of established reserves over an extended period of time and in amounts
that could have a material adverse effect on our financial results. Similarly,
it is also possible that the terms of resolution could require that we or our
subsidiaries change business practices and procedures, which could also have a
material adverse effect on our financial results. Further, litigation could
result in the imposition of financial penalties or injunctions which could limit
our ability to take certain desired actions or the denial of needed permits,
licenses or regulatory authority to conduct our business, including the siting
or permitting of facilities. Any of these outcomes could have a material adverse
effect on our financial results.
Potential
changes in accounting standards might cause us to revise our financial results
and disclosure in the future, which may change the way analysts measure our
business or financial performance.
Accounting
irregularities discovered in the past few years in various industries have
caused regulators and legislators to take a renewed look at accounting
practices, financial disclosures, companies’ relationships with their
independent auditors and retirement plan practices. Because it is still unclear
what laws or regulations will ultimately develop, we cannot predict the ultimate
impact of any future changes in accounting regulations or practices in general
with respect to public companies or the energy industry or in our operations
specifically. In addition, the Financial Accounting Standards Board (“FASB”),
the FERC or the U.S. Securities and Exchange Commission (“SEC”) could enact new
or revised accounting standards or FERC orders that might impact how we are
required to record revenues, expenses, assets and liabilities.
The
Company’s energy properties consist of the physical assets necessary and
appropriate to generate, transmit, store, distribute and supply energy and
consist mainly of electric generation, transmission and distribution facilities
and gas distribution plants, natural gas pipelines, storage facilities,
compressor stations and meter stations, along with the related rights-of-way. It
is the opinion of the Company’s management that the principal depreciable
properties owned by the Company are in good operating condition and are well
maintained. Pursuant to separate financing agreements, substantially all or most
of the properties of each of the Company’s subsidiaries (except CE Electric UK,
all of MidAmerican Energy’s gas and non-Iowa electric utility properties and
Northern Natural Gas) are pledged or encumbered to support or otherwise provide
the security for their own project or subsidiary debt. For additional
information regarding the Company’s energy properties, refer to Item 1 of
this Form 10-K and Notes 4 and 23 of Notes to Consolidated Financial
Statements included in Item 8 of this Form 10-K.
The right
to construct and operate the Company’s electric transmission and distribution
facilities and pipelines across certain property was obtained in most
circumstances through negotiations and, where necessary, through the exercise of
the power of eminent domain. PacifiCorp, MidAmerican Energy, Northern Natural
Gas and Kern River in the United States and Northern Electric and Yorkshire
Electricity in the United Kingdom continue to have the power of eminent domain
in each of the jurisdictions in which they operate their respective facilities,
but the United States utilities do not have the power of eminent domain with
respect to Native American tribal lands. Although the main Kern River pipeline
crosses the Moapa Indian Reservation, all facilities in the Moapa Indian
Reservation are located within a utility corridor that is reserved to the United
States Department of Interior, Bureau of Land Management.
With
respect to real property, each of the electric transmission and distribution
facilities and pipelines fall into two basic categories: (1) parcels that are
owned in fee, such as certain of the generation stations, electric substations,
compressor stations, measurement stations and office sites; and (2) parcels
where the interest derives from leases, easements, rights-of-way, permits or
licenses from landowners or governmental authorities permitting the use of such
land for the construction, operation and maintenance of the electric
transmission and distribution facilities and pipelines. The Company believes
that each of its energy subsidiaries have satisfactory title to all of the real
property making up their respective facilities 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 consolidated financial results.
Regulated
Utility Companies
In May
2004, PacifiCorp was served with a complaint filed in the United States District
Court for the District of Oregon by the Klamath Tribes of Oregon, individual
Klamath Tribal members and the Klamath Claims Committee. The complaint generally
alleges that PacifiCorp and its predecessors affected the Klamath Tribes’
federal treaty rights to fish for salmon in the headwaters of the Klamath River
in southern Oregon by building dams that blocked the passage of salmon upstream
to the headwaters beginning in 1911. In September 2004, the Klamath Tribes filed
their first amended complaint adding claims of damage to their treaty rights to
fish for sucker and steelhead in the headwaters of the Klamath River. The
complaint seeks in excess of $1.0 billion in compensatory and punitive
damages. In July 2005, the District Court dismissed the case and in September
2005 denied the Klamath Tribes’ request to reconsider the dismissal. In October
2005, the Klamath Tribes appealed the District Court’s decision to the United
States Court of Appeals for the Ninth Circuit (the “Ninth Circuit”) and briefing
was completed in March 2006. In February 2008, the Ninth Circuit held oral
argument on the briefs. PacifiCorp believes the outcome of this proceeding will
not have a material impact on its consolidated financial results.
In
May 2007, PacifiCorp was served with a complaint filed in the United States
District Court for the Northern District of California by Leaf Hillman and
Terance J. Supahan (Karuk Tribe Members); Frankie Joe Myers, Howard McConnell
and Robert Attebery (Yurok Tribe Members): Michael T. Hudson
(a commercial fisherman); Blythe Reis (a resort owner); and the
Klamath Riverkeeper (a local environmental group) alleging that toxic algae
“introduced” by PacifiCorp into Klamath hydroelectric project reservoirs is
released by PacifiCorp to the river downstream of the project, and caused or
will cause the plaintiffs physical, property, and economic harm. Plaintiffs
allege seven causes of action based on nuisance, trespass, negligence, and
unlawful business practices, all under California law. Elevated concentrations
of microcystis aeruginosa (blue-green
algae), which can generate a toxin called microcystin, have been identified in
Klamath River hydroelectric project reservoirs, and now farther downstream on
the Klamath River. The algae occur naturally across Oregon, California, and
throughout the world. Elevated concentrations tend to appear in areas of slack
water that is relatively warm. It has been identified for years on Klamath Lake.
Plaintiffs seek unspecified damages and injunctive relief; however, in an order
filed by the court in August 2007, the court dismissed plaintiffs’ claims
for injunctive relief based on federal preemption under the Federal Power Act.
PacifiCorp denies the allegations and is vigorously defending the case, which is
currently in the discovery phase.
In
December 2007, PacifiCorp was served with a complaint filed in the United
States District Court for the Northern District of California by the Klamath
Riverkeeper (a local environmental group), Leaf Hillman (a Karuk Tribe member),
Howard McConnell and Robert Attebery (Yurok Tribe Members) and Blythe Reis (a
resort owner). The complaint alleges that reservoirs behind the hydroelectric
dams that PacifiCorp operates on the Klamath River provide an environment for
the growth of blue-green algae known as microcystis aeruginosa, which
can generate a toxin called microcystin. The complaint alleges that such algae
is a “solid waste” under the federal Resource Conservation and Recovery Act,
that PacifiCorp “generates” and “stores” such algae in its reservoirs, that
PacifiCorp “disposes” of such algae when it passes through the dams, and that
such “generation,”“storage” and “disposal” causes or threatens to cause an
imminent and substantial endangerment to health and the environment. The
complaint seeks a Court order declaring that PacifiCorp is violating the federal
Resource Conservation and Recovery Act, enjoining PacifiCorp from storing or
disposing of the algae, requiring PacifiCorp to “remediate all contamination of
or other damage to health or the environment” from such algae, and requiring
PacifiCorp to pay civil penalties of up to $27,500 per day per violation
from February 2001 to March 2004, and up to $32,500 per day per
violation from March 2004 and thereafter. PacifiCorp believes these claims
to be without merit and filed a motion to dismiss on December 20, 2007. In
February 2008, a court order was issued conditionally allowing the
consolidation of the December 2007 blue-green algae case with the
May 2007 blue-green algae case described above. Subsequently, the
plaintiffs filed a motion seeking clarification of the order. The plaintiffs
have until February 29, 2008 to agree to the conditions of the order, which
are to pay for certain of PacifiCorp’s costs and fees associated with any delay
caused by the consolidation of the two cases. If the plaintiffs do not agree to
pay the delay costs, the December 2007 blue-green algae case will be
dismissed.
In
February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint
against PacifiCorp in the federal district court in Cheyenne, Wyoming, alleging
violations of the Wyoming state opacity standards at PacifiCorp’s Jim Bridger
plant in Wyoming. Under Wyoming state requirements, which are part of the Jim
Bridger plant’s Title V permit and are enforceable by private citizens under the
federal Clean Air Act, a potential source of pollutants such as a coal-fired
generating facility must meet minimum standards of opacity, which is a
measurement of light in the flue of a generating facility. The complaint alleges
thousands of violations of asserted six-minute compliance periods and seeks an
injunction ordering the Jim Bridger plant’s compliance with opacity limits,
civil penalties of $32,500 per day per violation, and the plaintiffs’ costs of
litigation. The court granted a motion to bifurcate the trial into separate
liability and remedy phases. A five-day trial on the liability phase is
scheduled to begin in April 2008. The remedy-phase trial has not yet been
set. The court is considering several summary judgment motions filed by the
parties, but has not yet ruled on any of them. PacifiCorp believes it has a
number of defenses to the claims. PacifiCorp intends to vigorously oppose the
lawsuit but cannot predict its outcome at this time. PacifiCorp has already
committed to invest at least $812 million in pollution control equipment at
its generating facilities, including the Jim Bridger plant. This commitment is
expected to significantly reduce system-wide emissions, including emissions at
the Jim Bridger plant.
54
On
December 28, 2004, an apparent gas explosion and fire resulted in three
fatalities, one serious injury and property damage at a commercial building in
Ramsey, Minnesota. According to the Minnesota Office of Pipeline Safety, an
improper installation of a pipeline connection may have been a cause of the
explosion and fire. A predecessor company to MidAmerican Energy provided gas
service in Ramsey, Minnesota, at the time of the original installation in 1980.
In 1993, a predecessor of CenterPoint Energy, Inc. (“CenterPoint”) acquired all
of the Minnesota gas properties owned by the MidAmerican Energy predecessor
company.
All of
the wrongful death, personal injury and property damage claims arising from this
incident have been settled by CenterPoint. MidAmerican Energy’s exposure, if
any, to these settlements is covered under its liability insurance to which a
$2 million retention applies.
Two
lawsuits naming MidAmerican Energy as a third party defendant have been filed by
CenterPoint Energy Resources Corp. in the U.S. District Court, District of
Minnesota, related to this incident. The complaints seek reimbursement of all
sums associated with CenterPoint’s replacement of all service lines in the
MidAmerican Energy predecessor company’s properties located in Minnesota at a
cost of approximately $39 million according to publicly available reports.
MidAmerican Energy filed a motion for summary judgment in both of these actions
requesting that CenterPoint’s third party claims based upon misrepresentation
and negligent installation and negligent operation and maintenance of the gas
pipeline be barred. On March 5, 2007, the U.S. District Court issued an
order granting MidAmerican Energy’s motion for summary judgment as to
CenterPoint’s misrepresentation and negligent installation claims and denying
MidAmerican Energy’s motion for summary judgment as to CenterPoint’s negligent
operation and maintenance claims. A court-ordered settlement conference was held
September 21, 2007, but the parties did not achieve a settlement.
Subsequently, the court ordered the parties to be ready for trial on or after
February 1, 2008. Trial has not commenced. MidAmerican Energy intends to
vigorously defend its position in these claims and believes their ultimate
outcome will not have a material impact on its financial results.
Interstate
Pipeline Companies
In 1998,
the United States Department of Justice informed the then current owners of
Northern Natural Gas and Kern River that Jack Grynberg, an individual, had filed
claims in the United States District Court for the District of Colorado under
the False Claims Act against such entities and certain of their subsidiaries
including Northern Natural Gas and Kern River. Mr. Grynberg has also filed
claims against numerous other energy companies and alleges that the defendants
violated the False Claims Act in connection with the measurement and purchase of
hydrocarbons. The relief sought is an unspecified amount of royalties allegedly
not paid to the federal government, treble damages, civil penalties, attorneys’
fees and costs. On October 21, 1999, the Panel on Multi-District Litigation
transferred the claims to the United States District Court for the District of
Wyoming for pre-trial purposes. Motions to dismiss based on various
jurisdictional grounds were filed on June 4, 2004. On May 17, 2005,
Northern Natural Gas and Kern River each received a Special Master’s Report and
Recommendations which recommended that the action be dismissed for lack of
subject matter jurisdiction. On October 20, 2006, the United States
District Court for the District of Wyoming affirmed the Special Master’s Report
and Recommendation and dismissed Grynberg’s complaint as to all defendants. On
November 16, 2006, Grynberg filed 74 separate notices of appeal. In
accordance with case management orders issued by the Court of Appeals for the
Tenth Circuit, initial appellate briefs were filed by the parties in the second
half of 2007 with additional briefs to be filed during the first half
of 2008. Oral argument is scheduled for the week of September 22,2008. In connection with the purchase of Kern River from The Williams Companies,
Inc. (“Williams”) in 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 2002. The Company believes that the Grynberg cases filed against Northern
Natural Gas and Kern River are without merit and that Williams, on behalf of
Kern River pursuant to its indemnification, and Northern Natural Gas, intend to
defend these actions vigorously and that the ultimate outcome of the Grynberg
cases will not have a material impact on their financial results.
55
On
June 8, 2001, Northern Natural Gas, Kern River and other pipeline
companies, were named as defendants in a nationwide class action in the 26th
Judicial District, District Court, Stevens County Kansas, Civil Department. The
plaintiffs allege that the defendants have engaged in mismeasurement techniques
that distort the heating content of natural gas, resulting in an alleged
underpayment of royalties to the class of producer plaintiffs. With court
approval, the plaintiffs filed a fourth amended petition alleging a class of gas
royalty owners in Kansas, Colorado and Wyoming on July 28, 2003. Kern River
was not a named defendant in the amended petition and has been dismissed from
the action. Northern Natural Gas filed an answer to the fourth amended petition
on August 22, 2003. After fully briefing the class certification issue, on
November 9, 2006, the plaintiffs filed a request for a new briefing
schedule on class certification in light of a new Kansas Supreme Court case on
class actions which ruled that in that case the trial court failed to engage in
properly rigorous analysis of class certification and choice of law issues and
remanded a denial of class certification for such an analysis. The plaintiffs
hope to use this as grounds for further class certification briefing. On
July 31, 2007, both the plaintiffs and Northern Natural Gas, as one of the
coordinated defendants, filed their proposed findings of fact and conclusions of
law regarding class certification. Northern Natural Gas believes that this claim
is without merit and intends to defend these actions vigorously and believes its
ultimate outcome will not have a material impact on its financial
results.
Similar
to the June 8, 2001 matter referenced above, the plaintiffs in that matter
filed a new companion action on May 12, 2003 against Northern Natural Gas
and other parties, but excluding Kern River, in a Kansas state district court
for damages for mismeasurement of British thermal unit content, resulting in
lower royalties. After fully briefing the class certification issue, on
November 9, 2006, the plaintiffs filed a request for a new briefing
schedule on class certification in light of a new Kansas Supreme Court case on
class actions which ruled that in that case the trial court failed to engage in
properly rigorous analysis of class certification and choice of law issues and
remanded a denial of class certification for such an analysis. The plaintiffs
hope to use this as grounds for further class certification briefing. On
July 31, 2007, both the plaintiff and Northern Natural Gas, as one of the
coordinated defendants, filed their proposed findings of fact and conclusion of
law regarding class certification. Northern Natural Gas believes that this claim
is without merit and intends to defend these actions vigorously and believes its
ultimate outcome will not have a material impact on its financial
results.
Independent
Power Projects
Pursuant
to the share ownership adjustment mechanism in the CE Casecnan shareholder
agreement, which is based upon proforma financial projections of the Casecnan
Project prepared following commencement of commercial operations, in
February 2002, MEHC’s indirect wholly owned subsidiary,
CE Casecnan Ltd., advised the minority shareholder of
CE Casecnan, LaPrairie Group Contractors (International) Ltd. (“LPG”), that
MEHC’s indirect ownership interest in CE Casecnan had increased to 100%
effective from commencement of commercial operations. On July 8, 2002, LPG
filed a complaint in the Superior Court of the State of California, City and
County of San Francisco against CE Casecnan Ltd. and MEHC. LPG’s complaint,
as amended, seeks compensatory and punitive damages arising out of
CE Casecnan Ltd.’s and MEHC’s alleged improper calculation of the proforma
financial projections and alleged improper settlement of the NIA
arbitration.
On
February 21, 2007, the appellate court issued a decision, and as a result
of the decision, CE Casecnan Ltd. determined that LPG would retain ownership of
10% of the shares of CE Casecnan, with the remaining 5% ownership being
transferred to CE Casecnan Ltd. subject to certain buy-up rights under the
shareholder agreement. At a hearing on October 10, 2007, the court
determined that LPG was ready, willing and able to exercise its buy-up rights in
2007. Additional hearings were held on October 23 and 24, 2007, regarding
the issue of the buy-up price calculation and a written decision was issued on
February 4, 2008 specifying the method for determining LPG’s buy-up price.
A final judgment has not been issued on the buy-up right and price and when
issued will be subject to appeal. LPG waived its request for a jury trial for
the breach of fiduciary duty claim and the parties have entered into a
stipulation which provides for a trial of such claim by the court based on the
existing record of the case. The trial date has been set for March 12,2008. The Company intends to vigorously defend and pursue the remaining
claims.
56
In
February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. (“San
Lorenzo”), an original shareholder substantially all of whose shares in
CE Casecnan were purchased by MEHC in 1998, threatened to initiate legal
action against the Company in the Philippines in connection with certain aspects
of its option to repurchase such shares. The Company believes that San Lorenzo
has no valid basis for any claim and, if named as a defendant in any action that
may be commenced by San Lorenzo, the Company will vigorously defend such action.
On July 1, 2005, MEHC and CE Casecnan Ltd. commenced an action against
San Lorenzo in the District Court of Douglas County, Nebraska, seeking a
declaratory judgment as to MEHC’s and CE Casecnan Ltd.’s rights vis-à-vis
San Lorenzo in respect of such shares. San Lorenzo filed a motion to dismiss on
September 19, 2005. Subsequently, San Lorenzo purported to exercise its
option to repurchase such shares. On January 30, 2006, San Lorenzo filed a
counterclaim against MEHC and CE Casecnan Ltd. seeking declaratory relief
that it has effectively exercised its option to purchase 15% of the shares of
CE Cascenan, that it is the rightful owner of such shares and that it is
due all dividends paid on such shares. On March 9, 2006, the court granted
San Lorenzo’s motion to dismiss, but has since permitted MEHC and
CE Casecnan Ltd. to file an amended complaint incorporating the purported
exercise of the option. The complaint has been amended and the action is
proceeding. Currently, the action is in the discovery phase and a one-week trial
has been set to begin on November 3, 2008. The impact, if any, of San
Lorenzo’s purported exercise of its option and the Nebraska litigation on the
Company cannot be determined at this time. The Company intends to vigorously
defend the counterclaims.
Market for Registrant’s Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity
Securities
Since
March 14, 2000, MEHC’s common stock has been owned by Berkshire Hathaway,
Mr. Walter Scott, Jr. and certain of his family members and family
controlled trusts and corporations, Mr. David L. Sokol, its Chairman and Chief
Executive Officer, and Mr. Gregory E. Abel, its President and Chief Operating
Officer, and has 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. MEHC has not declared or paid any cash dividends on its common stock
since March 14, 2000 and does not presently anticipate that it will declare
any dividends on its common stock in the foreseeable future.
In
connection with the 2006 acquisition of PacifiCorp by MEHC, MEHC and PacifiCorp
have made commitments to the state commissions that limit the dividends
PacifiCorp can pay to either MEHC or MEHC’s wholly owned subsidiary, PPW
Holdings LLC. As of December 31, 2007, the most restrictive of these
commitments prohibits PacifiCorp from making any distribution to MEHC or its
affiliates without prior state regulatory approval to the extent that it would
reduce PacifiCorp’s common stock equity below 48.25% of its total
capitalization, excluding short-term debt and current maturities of long-term
debt. After December 31, 2008, this minimum level of common equity declines
annually to 44% after December 31, 2011. As of December 31, 2007,
PacifiCorp’s actual common stock equity percentage, as calculated under this
measure, exceeded the minimum threshold.
These
commitments also restrict PacifiCorp from making any distributions to either
MEHC or MEHC’s wholly owned subsidiary, PPW Holdings LLC, if PacifiCorp’s
unsecured debt rating is BBB- or lower by Standard & Poor’s Rating Services
or Fitch Ratings or Baa3 or lower by Moody’s Investor Service, as indicated by
two of the three rating services. At December 31, 2007, PacifiCorp’s
unsecured debt rating was BBB+ by Standard & Poor’s Rating Services and
Fitch Ratings and Baa1 by Moody’s Investor Service.
In
conjunction with the March 1999 acquisition of MidAmerican Energy by MEHC,
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 a
common equity to total capitalization ratio above 42%, except under
circumstances beyond its control. MidAmerican Energy’s common equity to total
capitalization ratio is not allowed to decline below 39% for any reason. If the
ratio declines below the defined threshold, MidAmerican Energy must seek the
approval of a reasonable utility capital structure from the IUB. MidAmerican
Energy’s ability to issue debt could also be restricted. As of December 31,2007, MidAmerican Energy’s common equity to total capitalization ratio, computed
on a basis consistent with the commitment, exceeded the minimum
threshold.
For
further discussion of contractual and regulatory restrictions that limit certain
of MEHC’s subsidiaries’ ability to pay dividends on their common stock to MEHC,
refer to Note 11 of Notes to Consolidated Financial Statements included in
Item 8 of this Form 10-K.
On
November 12, 2007, MEHC issued 370,000 shares of its common stock, no par
value, to Mr. Abel upon the exercise by Mr. Abel of 370,000 of his outstanding
common stock options. The common stock options were exercisable at a
weighted-average price of $26.99 per share and the aggregate exercise price paid
by Mr. Abel was $10 million. This issuance was pursuant to a private
placement and was exempt from the registration requirements of the Securities
Act of 1933, as amended.
The
following table sets forth the Company’s selected consolidated historical
financial data, which should be read in conjunction with the information
included in Item 7 of this Form 10-K and with the Company’s historical
Consolidated Financial Statements and notes thereto included in Item 8 of
this Form 10-K. The selected consolidated historical financial data has been
derived from the Company’s audited historical Consolidated Financial Statements
and notes thereto (in millions).
Reflects
the acquisition of PacifiCorp on March 21, 2006.
(2)
Reflects
MEHC’s decision to cease operations of the Zinc Recovery Project effective
September 10, 2004, which resulted in a non-cash, after-tax
impairment charge of $340 million being recorded to write-off the
Zinc Recovery Project, rights to quantities of extractable minerals, and
allocated goodwill (collectively, the “Mineral
Assets”).
The
following is management’s discussion and analysis of certain significant factors
that have affected the financial condition and results of operations of the
Company during the periods included herein. Explanations include management’s
best estimate of the impact of weather, customer growth and other factors. This
discussion should be read in conjunction with Item 6 of this Form 10-K
and with the Company’s historical Consolidated Financial Statements and notes
thereto included in Item 8 of this Form 10-K. The Company’s actual
results in the future could differ significantly from the historical
results.
Results
of Operations
Overview
Net
income for 2007 was $1.19 billion, an increase of $273 million, or
30%, compared to 2006. PacifiCorp, which was acquired on March 21, 2006,
contributed an additional $235 million of net income in 2007 compared to
2006. Also contributing to the increase in net income were favorable operating
results at the Company’s other domestic energy businesses, largely as a result
of improved margins from favorable market conditions and additional generation
assets being placed in service, a $58 million deferred income tax benefit
recognized as a result of the reduction in the United Kingdom corporate income
tax rate from 30% to 28% and the favorable impact from the foreign currency
exchange rate. Net income decreased due to lower earnings at the Company’s
foreign energy businesses, which included the planned turnover to the Philippine
government of the Upper Mahiao project in June 2006 and the Malitbog and
Mahanagdong projects in July 2007, lower earnings at HomeServices due to
the general slowdown in the United States housing market, $73 million of
after tax gains on sales of available-for-sale securities in 2006 and higher
interest expense as a result of debt issuances at MEHC and the domestic energy
businesses.
Net
income for 2006 was $916 million, an increase of $353 million, or 63%,
compared to 2005. Net income related to PacifiCorp, which was acquired on
March 21, 2006, was $215 million during 2006. Also contributing to the
increase in net income were favorable comparative results at most of the
Company’s energy businesses and $73 million of after tax gains on sales of
available-for-sale securities. These improvements were partially offset by lower
earnings at HomeServices and higher interest expense on MEHC senior
debt.
Segment
Results
The
Company’s operations are organized and managed as eight distinct platforms:
PacifiCorp, MidAmerican Funding (which primarily includes MidAmerican Energy),
Northern Natural Gas, Kern River, CE Electric UK (which primarily
includes Northern Electric and Yorkshire Electricity), CalEnergy
Generation-Foreign, CalEnergy Generation-Domestic and HomeServices. Through
these platforms, MEHC owns and operates an electric utility company in the
Western United States, a combined electric and natural gas utility company in
the Midwestern United States, two natural gas interstate pipeline companies in
the United States, two electricity distribution companies in Great Britain, a
diversified portfolio of independent power projects and the second largest
residential real estate brokerage firm in the United States.
The
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 and intersegment eliminations.
60
A
comparison of operating revenue and operating income for the Company’s
reportable segments for the years ended December 31 follows
(in millions):
2007
2006
Change
2006
2005
Change
Operating
revenue:
PacifiCorp
$
4,258
$
2,939
$
1,319
45
%
$
2,939
$
-
$
2,939
N/A
MidAmerican
Funding
4,267
3,453
814
24
3,453
3,166
287
9
%
Northern
Natural Gas
664
634
30
5
634
569
65
11
Kern
River
404
325
79
24
325
324
1
-
CE Electric UK
1,079
928
151
16
928
884
44
5
CalEnergy
Generation-Foreign
220
336
(116
)
(35
)
336
312
24
8
CalEnergy
Generation-Domestic
32
32
-
-
32
34
(2
)
(6
)
HomeServices
1,500
1,702
(202
)
(12
)
1,702
1,868
(166
)
(9
)
Corporate/other
(48
)
(48
)
-
-
(48
)
(41
)
(7
)
(17
)
Total
operating revenue
$
12,376
$
10,301
$
2,075
20
$
10,301
$
7,116
$
3,185
45
Operating
income:
PacifiCorp
$
917
$
528
$
389
74
%
$
528
$
-
$
528
N/A
MidAmerican
Funding
514
421
93
22
421
381
40
10
%
Northern
Natural Gas
308
269
39
14
269
209
60
29
Kern
River
277
217
60
28
217
204
13
6
CE Electric UK
555
516
39
8
516
484
32
7
CalEnergy
Generation-Foreign
142
230
(88
)
(38
)
230
185
45
24
CalEnergy
Generation-Domestic
12
14
(2
)
(14
)
14
15
(1
)
(7
)
HomeServices
33
55
(22
)
(40
)
55
125
(70
)
(56
)
Corporate/other
(70
)
(130
)
60
46
(130
)
(74
)
(56
)
(76
)
Total
operating income
$
2,688
$
2,120
$
568
27
$
2,120
$
1,529
$
591
39
PacifiCorp
On
March 21, 2006, MEHC acquired 100% of the common stock of PacifiCorp.
Operating revenue for 2007 and 2006 consisted of retail revenue of
$3.25 billion and $2.33 billion, respectively, and wholesale and
other revenues of $1.01 billion and $610 million, respectively.
PacifiCorp’s operating income was favorably impacted by higher retail
revenues as a result of higher prices approved by regulators as well as
continued growth in the number of customers and usage, higher net margins
on wholesale activities due to higher average prices on sales and lower
purchased electricity volumes and lower employee expense. These
improvements were partially offset by higher fuel costs due to increased
volumes of natural gas consumed in PacifiCorp’s generation plants and
higher prices for coal, natural gas and purchased
electricity.
MidAmerican
Funding
MidAmerican
Funding’s operating revenue and operating income for the years ended
December 31 are summarized as follows (in millions):
2007
2006
Change
2006
2005
Change
Operating
revenue:
Regulated
electric
$
1,934
$
1,779
$
155
9
%
$
1,779
$
1,513
$
266
18
%
Regulated
natural gas
1,174
1,112
62
6
1,112
1,323
(211
)
(16
)
Nonregulated
and other
1,159
562
597
106
562
330
232
70
Total
operating revenue
$
4,267
$
3,453
$
814
24
$
3,453
$
3,166
$
287
9
Operating
income:
Regulated
electric
$
398
$
372
$
26
7
%
$
372
$
334
$
38
11
%
Regulated
natural gas
53
36
17
47
36
39
(3
)
(8
)
Nonregulated
and other
63
13
50
385
13
8
5
63
Total
operating income
$
514
$
421
$
93
22
$
421
$
381
$
40
10
61
Regulated
electric revenue increased $155 million for 2007 compared to 2006 due to
increases in wholesale revenue of $103 million and retail revenue of
$52 million. Wholesale revenue increased due primarily to higher sales
volumes, as a result of new generating assets placed in service during 2007 and
improved market opportunities, and prices. Retail revenue increased due
primarily to growth in retail demand, an increase in the average number of
retail customers and favorable weather conditions in 2007. Regulated natural gas
revenue increased $62 million for 2007 compared to 2006 due primarily to
higher retail sales volumes and an increase in the average per-unit cost of gas
sold, partially offset by lower wholesale sales volumes. Nonregulated and other
revenue increased $597 million for 2007 compared to 2006 due primarily to
increases in electric retail sales volumes and prices driven by improved market
opportunities, partially offset by decreases in gas sales volumes and
prices.
Regulated
electric revenue increased $266 million for 2006 compared to 2005 due to
increases in wholesale revenue of $219 million and retail revenue of
$47 million. Wholesale revenue increased due primarily to higher average
electric energy prices and volumes as a result of additional generation placed
in service and greater market opportunities. Retail revenue increased due
primarily to an increase in retail demand and usage, partially offset by lower
revenue due to mild summer temperatures in 2006. Regulated natural gas revenue
decreased $211 million for 2006 compared to 2005 due primarily to a
decrease in the average per-unit cost of gas sold and lower volumes.
Nonregulated and other revenue increased $232 million for 2006 compared to
2005 due primarily to a change in management strategy related to certain end-use
natural gas contracts that required the related revenues and cost of sales to be
recorded prospectively on a gross, rather than net, basis, partially offset by a
decrease in natural gas sales volumes and lower electric and natural gas prices.
In 2005, cost of sales totaling $289 million were netted in nonregulated
operating revenue for such end-use gas contracts.
Regulated
electric operating income increased $26 million for 2007 compared to 2006
as a result of higher gross margins of $86 million from both retail and
wholesale sales and lower depreciation and amortization of $7 million,
partially offset by higher operating expenses of $67 million. Depreciation
and amortization was lower in 2007 due primarily to a $25 million decrease
in regulatory expense related to a revenue sharing arrangement in Iowa as a
result of lower Iowa electric equity returns, partially offset by higher
depreciation as a result of new generation assets placed in service in 2007.
Operating expenses were higher due primarily to maintenance costs incurred for
restoration of facilities damaged by storms, new generation assets placed in
service during 2007 and the timing of maintenance for natural gas-fueled
generating facilities. Operating income for regulated natural gas and
nonregulated and other increased $17 million and $50 million,
respectively, due primarily to higher gross margins on the aforementioned
operating revenue increases.
Regulated
electric operating income increased $38 million for 2006 compared to 2005
as a result of higher gross margins of $71 million due to the
aforementioned higher sales volumes and prices, partially offset by
$28 million of higher operating expenses and $6 million of higher
depreciation and amortization expense. The increase in operating expenses was
due primarily to higher generating plant operating and maintenance expenses
including additional expense for wind generation.
Northern
Natural Gas
Operating
revenue increased $30 million for 2007 compared to 2006 due to higher
transportation and storage revenues of $47 million on higher rates and
volumes from favorable market conditions, partially offset by a lower volume of
gas and condensate liquids sales of $17 million, which are both utilized in
the operation and balancing of the pipeline system. Operating revenue increased
$65 million for 2006 compared to 2005 due primarily to higher
transportation and storage revenues due to higher rates and volumes from
favorable market conditions.
Operating
income increased $39 million for 2007 compared to 2006 due primarily to the
aforementioned increase in transportation and storage revenues, partially offset
by a $6 million asset impairment charge. Operating income increased
$60 million for 2006 compared to 2005 due to the aforementioned increase in
transportation and storage revenues. Several non-routine events also impacted
operating income in 2005, including a $29 million asset impairment charge
of a non-contiguous portion of the pipeline system, a gain of $20 million
from the sale of an idled section of pipeline in Oklahoma and Texas and the
adjustments from two FERC-approved settlements that increased operating income
by $16 million.
62
Kern
River
Operating
revenue increased $79 million for 2007 compared to 2006. Kern River earned
higher market oriented revenue of $50 million as a result of more favorable
market conditions in 2007. Additionally, Kern River received a FERC order in
2006 that resulted in a $34 million reduction to operating revenue for rate
case estimated refunds. Operating revenue increased $1 million for 2006
compared to 2005 as higher market oriented revenue of $34 million due to
favorable market conditions was offset by the aforementioned adjustment to Kern
River’s provision for estimated refunds.
Operating
income increased $60 million for 2007 compared to 2006 due primarily to the
aforementioned increase in market oriented revenue. The $34 million
decrease in revenue related to the FERC order received in 2006 was largely
offset by a corresponding $28 million adjustment that also lowered
depreciation and amortization expense. Also contributing to the increase in
operating income for 2007 compared to 2006 was $8 million of lower
depreciation and amortization expense due mainly to changes in the expected
depreciation rates in connection with the current rate proceeding and a
$6 million sales and use tax refund received in 2007. Operating income
increased $13 million for 2006 compared to 2005 due primarily to lower
depreciation and amortization due primarily to changes in the expected rates in
connection with the current rate proceeding.
CE Electric UK
Operating
revenue increased $151 million for 2007 compared to 2006 due primarily to a
$79 million favorable impact from the exchange rate, higher distribution
revenue of $33 million at Northern Electric and Yorkshire Electricity, due
primarily to tariff increases, and higher revenue of $32 million at CE Gas,
primarily from higher gas production. Operating revenue increased
$44 million for 2006 compared to 2005 due primarily to higher contracting
revenue of $21 million, higher distribution revenues at Northern Electric
and Yorkshire Electricity of $14 million due to higher units distributed
and the favorable impact of the exchange rate of $12 million.
Operating
income increased $39 million for 2007 compared to 2006 due primarily to
higher gross margins on distribution and gas production revenues totaling
$60 million and the favorable impact from the exchange rate of
$43 million, partially offset by higher costs and expenses of
$62 million. Costs and expenses were higher for 2007 due primarily to
higher depreciation and amortization expense of $37 million primarily
associated with distribution assets, higher distribution costs of
$18 million due mainly to higher maintenance and restoration costs, and the
write-off of an unsuccessful exploration well at CE Gas, partially offset by a
realized gain on the sale of certain CE Gas assets in 2007. Operating income
increased $32 million for 2006 compared to 2005 due primarily to the higher
distribution revenues and the favorable impact of the exchange
rate.
CalEnergy
Generation-Foreign
Operating
revenue decreased $116 million for 2007 compared to 2006 as the Malitbog
and Mahanagdong projects were transferred on July 25, 2007, and the Upper
Mahiao project was transferred on June 25, 2006, to the Philippine
government, which reduced operating revenue by $92 million. Additionally,
operating revenue at the Casecnan project was lower by $24 million as a
result of lower water flows and related energy production. Operating revenue
increased $24 million for 2006 compared to 2005. Higher revenue at the
Casecnan project of $42 million as a result of above normal water flows
throughout 2006 was partially offset by lower operating revenue of
$18 million due primarily to the aforementioned transfer of the Upper
Mahiao project.
Operating
income decreased $88 million for 2007 compared to 2006. Lower revenue was
partially offset by lower depreciation and amortization expense of
$30 million as the projects were transferred. Operating income increased
$45 million for 2006 compared to 2005 due primarily to the higher revenue
as well as lower operating expenses of $15 million due primarily to the
aforementioned transfer of the Upper Mahiao project.
63
HomeServices
Operating
revenue decreased $202 million for 2007 compared to 2006 and
$166 million for 2006 compared to 2005 due to the general slowdown in the
U.S. housing market and the resulting lower number of brokerage
transactions.
Operating
income decreased $22 million for 2007 compared to 2006 due mainly to the
aforementioned decrease in brokerage transactions, partially offset by lower
commissions, operating expenses and depreciation and amortization expense.
Operating income decreased $70 million for 2006 compared to 2005 due mainly
to the aforementioned decrease in brokerage transactions and higher acquisition
related amortization, partially offset by lower operating expenses due primarily
to lower salaries and employee benefits expenses.
Consolidated Other Income
and Expense Items
Interest
Expense
Interest
expense for the years ended December 31 is summarized as follows (in
millions):
2007
2006
Change
2006
2005
Change
Subsidiary
debt
$
899
$
758
$
141
19
%
$
758
$
533
$
225
42
%
MEHC
senior debt and other
285
233
52
22
233
173
60
35
MEHC
subordinated debt-Berkshire
108
134
(26
)
(19
)
134
158
(24
)
(15
)
MEHC
subordinated debt-other
28
27
1
4
27
27
-
-
Total
interest expense
$
1,320
$
1,152
$
168
15
$
1,152
$
891
$
261
29
Interest
expense increased $168 million for 2007 compared to 2006 and
$261 million for 2006 compared to 2005 due to the acquisition of
PacifiCorp, debt issuances at domestic energy businesses and at MEHC, and the
higher exchange rate. Interest expense was higher by $90 million in 2007
and $224 million in 2006 as a result of the acquisition of PacifiCorp. The
increase in interest expense for 2007 and 2006 was partially offset by debt
retirements and scheduled principal repayments.
Other
Income, Net
Other
income, net for the years ended December 31 is summarized as follows
(in millions):
2007
2006
Change
2006
2005
Change
Capitalized
interest
$
54
$
40
$
14
35
%
$
40
$
17
$
23
135
%
Interest
and dividend income
105
73
32
44
73
58
15
26
Other
income
122
239
(117
)
(49
)
239
75
164
219
Other
expense
(10
)
(13
)
3
23
(13
)
(23
)
10
43
Total
other income, net
$
271
$
339
$
(68
)
(20
)
$
339
$
127
$
212
167
Capitalized
interest increased $14 million for 2007 compared to 2006 and
$23 million for 2006 compared to 2005 due primarily to the acquisition of
PacifiCorp and increased levels of capital project expenditures at MidAmerican
Energy.
Interest
and dividend income increased $32 million for 2007 compared to 2006 due
primarily to more favorable cash positions at MEHC and certain subsidiaries as a
result of 2007 debt issuances as well as $9 million resulting from the
acquisition of PacifiCorp. Interest and dividend income increased
$15 million for 2006 compared to 2005 due primarily to the acquisition of
PacifiCorp.
64
Other
income decreased $117 million for 2007 compared to 2006 and increased
$164 million for 2006 compared to 2005. Other income for 2006 included Kern
River’s $89 million of gains from the sale of Mirant stock and
$47 million of gains at MidAmerican Funding from the sales of other
non-strategic investments. Partially offsetting the decrease for 2007 compared
to 2006 was higher equity allowance for funds used during construction (“AFUDC”)
of $28 million due to increased levels of capital project expenditures.
Additionally, other income was higher by $27 million for 2006 compared to
2005 as a result of the acquisition of PacifiCorp.
Other
expense decreased $10 million for 2006 compared to 2005 due primarily to
2005 losses for other-than-temporary impairments of MidAmerican Funding’s
investments in commercial passenger aircraft leased to major domestic
airlines.
Income
Tax Expense
Income
tax expense increased $49 million, or 12%, for 2007 compared to 2006. The
effective tax rates were 28% and 31% for 2007 and 2006, respectively. The
increase in income tax expense is due primarily to higher pretax earnings,
partially offset by the recognition of $58 million of deferred income tax
benefits due to a reduction in the United Kingdom corporate income tax rate from
30% to 28%. Adjusting for the effect of the change in the United Kingdom
corporate income tax rate, the 2007 effective tax rate was 31%.
Income
tax expense increased $162 million, or 66%, for 2006 compared to 2005. The
effective tax rates were 31% and 32% for 2006 and 2005, respectively. The
increase in income tax expense was due to higher pretax earnings.
Minority
Interest and Preferred Dividends of Subsidiaries
Minority
interest and preferred dividends of subsidiaries increased $12 million to
$27 million for 2006 compared to 2005 due mainly to higher earnings at CE
Casecnan and preferred dividends at PacifiCorp.
Equity
Income
Equity
income decreased $7 million to $36 million for 2007 compared to 2006
due primarily to the sale and write-off of an investment in a mortgage joint
venture at HomeServices. Equity income decreased $10 million to
$43 million for 2006 compared to 2005 due primarily to lower earnings at CE
Generation as a result of higher depreciation and maintenance expenses and lower
equity income at HomeServices due to lower refinancing activity at its
residential mortgage loan joint ventures.
Liquidity
and Capital Resources
The
Company has available a variety of sources of liquidity and capital resources,
both internal and external, including the Berkshire Equity Commitment. These
resources provide funds required for current operations, construction
expenditures, debt retirement and other capital requirements. The Company may
from time to time seek to retire its outstanding securities through cash
purchases in the open market, privately negotiated transactions or otherwise.
Such repurchases or exchanges, if any, will depend on prevailing market
conditions, the Company’s liquidity requirements, contractual restrictions and
other factors. The amounts involved may be material.
Each of
MEHC’s direct and indirect subsidiaries is organized as a legal entity separate
and apart from MEHC and its other subsidiaries. Pursuant to separate financing
agreements, the assets of each subsidiary may be pledged or encumbered to
support or otherwise provide the security for its own project or subsidiary
debt. It should not be assumed that any asset of any subsidiary of MEHC’s will
be available to satisfy the obligations of MEHC or any of its other
subsidiaries’ obligations. However, unrestricted cash or other assets which are
available for distribution may, subject to applicable law, regulatory
commitments and the terms of financing and ring-fencing arrangements for such
parties, be advanced, loaned, paid as dividends or otherwise distributed or
contributed to MEHC or affiliates thereof.
The
Company’s cash and cash equivalents were $1.18 billion as of
December 31, 2007, compared to $343 million as of December 31,2006. The Company recorded separately in other current assets, restricted cash
and investments as of December 31, 2007 and 2006 of $73 million and
$132 million, respectively. The restricted cash and investments balance is
mainly composed of current amounts deposited in restricted accounts relating to
(i) the Company’s debt service reserve requirements relating to certain
projects, (ii) trust funds related to mine reclamation costs, (iii)
customer deposits held in escrow, (iv) custody deposits, and (v) unpaid
dividends declared obligations. The debt service funds are restricted by their
respective project debt agreements to be used only for the related project. The
Company had a guaranteed investment contract of $397 million that matured
in February 2008. Additionally, the Company has restricted cash and
investments recorded in deferred charges, investments and other assets as of
December 31, 2007 and 2006 that principally relate to trust funds held for
mine reclamation and nuclear decommissioning costs. As of December 31,2007, MEHC had $554 million of availability under its $600 million
revolving credit facility with no borrowings outstanding and had letters of
credit issued under the credit agreement totaling $46 million.
65
Cash Flows from Operating
Activities
Cash
flows generated from operations for the years ended December 31, 2007 and
2006 were $2.34 billion and $1.92 billion, respectively. The increase
was mainly due to the acquisition of PacifiCorp on March 21, 2006, which
contributed $399 million to the increase in operating cash flows. Higher
cash flows from operations at MidAmerican Energy, Kern River and CE Electric UK
were largely offset by lower cash flows from operations at CalEnergy
Generation-Foreign, as a result of the transfer of the Malitbog and Mahanagdong
projects to the Philippine government in 2007, and HomeServices.
Cash Flows from Investing
Activities
Cash
flows used in investing activities for the years ended December 31, 2007
and 2006 were $3.25 billion and $7.32 billion, respectively. In 2007,
a certain wholly owned subsidiary of CE Electric UK received proceeds of
$201 million from the maturity of a guaranteed investment contract. Capital
expenditures, construction and other development costs increased
$1.09 billion for 2007 compared to 2006. Additionally, net purchases and
sales of available-for-sale securities resulted in higher cash outflows for 2007
of $157 million due primarily to Kern River’s receipt of $89 million
in proceeds from the sale of Mirant stock in 2006 and MidAmerican Funding’s
receipt of $28 million in proceeds from the sale of common shares held in
an electronic energy and metals trading exchange in 2006. In 2006, MEHC acquired
PacifiCorp for $4.93 billion, net of cash acquired.
PacifiCorp
Acquisition
On
March 21, 2006, a wholly owned subsidiary of MEHC acquired 100% of the
common stock of PacifiCorp from a wholly owned subsidiary of ScottishPower for a
cash purchase price of $5.11 billion, which was funded through the issuance
of common stock. MEHC also incurred $10 million of direct transaction costs
associated with the acquisition, which consisted principally of investment
banker commissions and outside legal and accounting fees and expenses, resulting
in a total purchase price of $5.12 billion. The results of PacifiCorp’s
operations are included in the Company’s results beginning March 21,2006.
In the
first quarter of 2006, the state commissions in all six states where PacifiCorp
has retail customers approved the sale of PacifiCorp to MEHC. The approvals were
conditioned on a number of regulatory commitments, including expected financial
benefits in the form of reduced corporate overhead and financing costs, certain
mid- to long-term capital and other expenditures of significant amounts and a
commitment not to seek utility rate increases attributable solely to the change
in ownership. The capital and other expenditures proposed by MEHC and PacifiCorp
include:
·
Approximately
$812 million in investments (generally to be made over several years
following the sale and subject to subsequent regulatory review and
approval) in emissions reduction technology for PacifiCorp’s existing coal
plants, which, when coupled with the use of reduced emissions technology
for anticipated new coal-fueled generation, is expected to result in
significant reductions in emissions rates of SO2,
NOx, and
mercury and to avoid an increase in the carbon dioxide emissions
rate;
·
Approximately
$520 million in investments (to be made over several years following
the sale and subject to subsequent regulatory review and approval) in
PacifiCorp’s transmission and distribution system that would enhance
reliability, facilitate the receipt of renewable resources and enable
further system optimization; and
·
The
addition of 400 MW of cost-effective new renewable resources to
PacifiCorp’s generation portfolio by December 31, 2007, including
100 MW of cost-effective wind resources by March 21,2007.
66
As of
December 31, 2007, PacifiCorp had incurred $205 million in capital
expenditures related to its commitment to invest in emissions reduction
technology for its existing coal plants, and $112 million of capital
expenditures and $16 million of operating expenses related to its
commitment to invest in its transmission and distribution system. PacifiCorp met
the requirements of its commitment to bring 100 MW of cost-effective wind
resources into service by March 21, 2007 with the completion of the 101-MW
Leaning Juniper wind plant, which was placed in service in September 2006.
Additionally, PacifiCorp met its commitment to add 400 MW of cost-effective
renewable resources to its generation portfolio by December 31,2007.
Capital
Expenditure
Capital
expenditures include both those relating to operating projects and to
construction and other development costs. Capital expenditures by reportable
segment for the years ended December 31 are summarized as follows (in
millions):
2007
2006
Capital
expenditures*:
PacifiCorp
$
1,518
$
1,114
MidAmerican
Energy
1,300
758
Northern
Natural Gas
225
122
CE
Electric UK
422
404
Other
reportable segments and corporate/other
47
25
Total
capital expenditures
$
3,512
$
2,423
* -
Excludes amounts for non-cash equity AFUDC.
Capital
expenditures relating to operating projects, mainly for distribution,
transmission, generation, mining and other infrastructure needed to serve
existing and growing demand, totaled $1.69 billion in 2007. Capital
expenditures relating to construction and other development costs totaled
$1.82 billion in 2007 and consisted primarily of the
following:
·
PacifiCorp
completed construction of the Lake Side plant, a 548-MW combined cycle,
natural gas-fired generation plant in September 2007. Total project costs
were $343 million, including $17 million of non-cash equity
AFUDC, and included costs paid in 2007 of $51 million. The Lake Side
plant is 100% owned and operated by
PacifiCorp.
·
PacifiCorp
placed 140 MW of wind-powered generation facilities in service and began
construction of an additional 461 MW of wind-powered generation facilities
in 2007 with costs totaling
$575 million.
·
MidAmerican
Energy completed construction of the Walter Scott, Jr. Energy Center Unit
No. 4, 790-MW supercritical, coal-fired generation plant in June 2007 at a
total cost of $1.2 billion. MidAmerican Energy operates the plant and
holds an undivided ownership interest of approximately 60%, or 471 MW, as
a tenant in common with the other owners of the plant. MidAmerican
Energy’s share of the total project cost was $840 million, including
$64 million of non-cash equity AFUDC, and included costs paid in 2007
of $170 million.
·
MidAmerican
Energy placed 201 MW of wind-powered generation facilities in service and
began construction of an additional 462 MW of wind-powered generation
facilities in 2007 with costs totaling
$565 million.
·
PacifiCorp
and MidAmerican Energy spent $110 million and $167 million,
respectively, on emissions control equipment in
2007.
·
Northern
Natural Gas spent $151 million on its Northern Lights Expansion
project in 2007.
The
Company has significant future capital requirements. Forecasted capital
expenditures for fiscal 2008, which exclude non-cash equity AFUDC, are
approximately $3.9 billion and consist of $2.0 billion for operating
projects mainly for distribution, transmission, generation, mining and other
infrastructure needed to serve existing and growing demand, and
$1.9 billion for construction and other development projects.
67
Capital
expenditure needs are reviewed regularly by management and may change
significantly as a result of such reviews. Estimates may change significantly at
any time as a result of, among other factors, changes in rules and regulations,
including environmental and nuclear, changes in income tax laws, general
business conditions, load projections, the cost and efficiency of construction
labor, equipment, and materials, and the cost of capital. In addition, there can
be no assurance that costs related to capital expenditures will be fully
recovered. The Company expects to meet its capital expenditure requirements with
cash flows from operations and the issuance of debt. To the extent funds are not
available to support capital expenditures, projects may be delayed and operating
income may be reduced.
Projected
2008 construction and other development expenditures include the
following:
·
Combined,
PacifiCorp and MidAmerican Energy anticipate spending $1.26 billion on
wind-powered generation facilities of which 923 MW are expected to be
placed in service in 2008.
·
Combined,
PacifiCorp and MidAmerican Energy are projecting to spend $314 for
emissions control equipment in
2008.
·
In
May 2007, PacifiCorp announced plans to build in excess of 1,200 miles of
new high-voltage transmission lines primarily in Wyoming, Utah, Idaho,
Oregon and the desert Southwest. The estimated $4.1 billion
investment plan includes projects that will address customers’ increasing
electric energy use, improve system reliability and deliver wind and other
renewable generation resources to more customers throughout PacifiCorp’s
six-state service area and the western region. These transmission lines
are expected to be placed into service beginning 2010 and continuing
through 2014. PacifiCorp expects to spend $283 million on new
transmission lines in 2008.
The
Company is subject to federal, state, local and foreign laws and regulations
with regard to air and water quality, renewable portfolio standards, climate
change, hazardous and solid waste disposal and other environmental matters. The
cost of complying with applicable environmental laws, regulations and rules is
expected to be material to the Company. In particular, future mandates may
impact the operation of the Company’s domestic generating facilities and may
require both PacifiCorp and MidAmerican Energy to reduce emissions at their
facilities through the installation of additional emission control equipment or
to purchase additional emission allowances or offsets in the future. The Company
is not aware of any established technology that reduces the carbon dioxide
emissions at coal-fired facilities and the Company is uncertain when, or if,
such technology will be commercially available.
Expenditures
for compliance-related items such as pollution-control technologies, replacement
generation, mine reclamation, nuclear decommissioning, hydroelectric
relicensing, hydroelectric decommissioning and associated operating costs are
generally incorporated into the routine cost structure of MEHC’s energy
subsidiaries. An inability to recover these costs from the Company’s customers,
either through regulated rates, long-term arrangements or market prices could
adversely affect the Company’s future financial results.
Refer to
the Environmental Regulation section of Item 1 of this Form 10-K for a detailed
discussion of the topic.
Cash Flows from Financing
Activities
Cash
flows from financing activities were $1.75 billion for the year ended
December 31, 2007. Sources of cash totaled $3.58 billion and consisted
primarily of $2 billion of proceeds from the issuance of subsidiary and
project debt and $1.54 billion of proceeds from the issuance of MEHC senior
debt. Uses of cash totaled $1.83 billion and consisted primarily of
$784 million for repayments of MEHC senior and subordinated debt,
$599 million for repayments of subsidiary and project debt,
$269 million for net repayments of subsidiary short-term debt and
$152 million for net repayments of MEHC’s revolving credit
facility.
Cash
flows from financing activities were $5.38 billion for the year ended
December 31, 2006. Sources of cash totaled $7.90 billion and consisted
primarily of $5.13 billion of proceeds from the issuance of common stock,
$1.70 billion of proceeds from the issuance of MEHC senior debt and
$718 million of proceeds from the issuance of subsidiary and project debt.
Uses of cash totaled $2.52 billion and consisted primarily of
$1.75 billion of repurchases of common stock, $516 million for
repayments of subsidiary and project debt and $234 million for repayments
of MEHC subordinated debt.
68
Stock
Transactions and Agreements
In 2007,
370,000 common stock options were exercised having a weighted average exercise
price of $26.99 per share and in 2006, 775,000 common stock options were
exercised having a weighted average exercise price of $28.65 per
share.
On
March 1, 2006, 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 MEHC’s common equity upon any requests authorized from
time to time by MEHC’s Board of Directors. The proceeds of any such equity
contribution shall only be used for the purpose of (a) paying when due MEHC’s
debt obligations and (b) funding the general corporate purposes and capital
requirements of the MEHC’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, was not used for the PacifiCorp acquisition
and will not be used for future acquisitions.
On
March 21, 2006, Berkshire Hathaway and certain other of MEHC’s existing
shareholders and related companies invested $5.11 billion, in the
aggregate, in 35,237,931 shares of MEHC’s common stock in order to provide
equity funding for the PacifiCorp acquisition. The per-share value assigned to
the shares of common stock issued, which were effected pursuant to a private
placement and were exempt from the registration requirements of the Securities
Act of 1933, as amended, was based on an assumed fair market value as agreed to
by MEHC’s shareholders.
In March
2006, MEHC repurchased 12,068,412 shares of common stock for an aggregate
purchase price of $1.75 billion.
2007
Debt Transactions and Agreements
In
addition to the debt issuances discussed herein, MEHC and its subsidiaries made
scheduled repayments on MEHC senior and subordinated debt and subsidiary and
project debt totaling approximately $1.38 billion during the year ended
December 31, 2007.
·
On
October 23, 2007, PacifiCorp entered into a new unsecured
revolving credit facility with total bank commitments of
$700 million. The facility will support PacifiCorp’s commercial paper
program and terminates on October 23, 2012. Terms and conditions,
including borrowing rates, are substantially similar to PacifiCorp’s
existing revolving credit facility.
·
On
October 3, 2007, PacifiCorp issued $600 million of 6.25% First
Mortgage Bonds due October 15, 2037. The proceeds were used by
PacifiCorp to repay its short-term debt and for general corporate
purposes.
·
On
August 28, 2007, MEHC issued $1.0 billion of 6.50% Senior Bonds
due September 15, 2037. The proceeds will be used by MEHC to repay at
maturity its 3.50% senior notes due in May 2008 in an aggregate
principal amount of $450 million and its 7.52% senior notes due in
September 2008 in an aggregate principal amount of $550 million.
Pending repayment of this indebtedness, the proceeds are being used to
repay short-term indebtedness, with the balance invested in short-term
securities or used for general corporate
purposes.
·
On
June 29, 2007, MidAmerican Energy issued $400 million of 5.65%
Senior Notes due July 15, 2012, and $250 million of 5.95% Senior
Notes due July 15, 2017. The proceeds were used by MidAmerican Energy
to pay construction costs of its interest in WSEC Unit 4 and its wind
projects in Iowa, to repay short-term indebtedness and for general
corporate purposes.
·
On
May 11, 2007, MEHC issued $550 million of 5.95% Senior Bonds due
May 15, 2037. The proceeds were used by MEHC to repay at maturity its
4.625% senior notes due in October 2007 in an aggregate principal
amount of $200 million and its 7.63% senior notes due in
October 2007 in an aggregate principal amount of
$350 million.
·
On
March 14, 2007, PacifiCorp issued $600 million of 5.75% First
Mortgage Bonds due April 1, 2037. The proceeds were used by
PacifiCorp to repay its short-term debt and for general corporate
purposes.
·
On
February 12, 2007, Northern Natural Gas issued $150 million of
5.8% Senior Bonds due February 15, 2037. The proceeds were used by
Northern Natural Gas to fund capital expenditures and for general
corporate purposes.
69
2006
Debt Transactions and Agreements
In
addition to the debt issuances discussed herein, MEHC and its subsidiaries made
scheduled repayments on MEHC subordinated debt and subsidiary and project debt
totaling approximately $750 million during the year ended December 31,2006.
·
On
March 24, 2006, MEHC completed a $1.70 billion offering of
6.125% unsecured senior bonds due 2036. The proceeds were used to fund
MEHC’s exercise of its right to repurchase shares of its common stock
previously issued to Berkshire
Hathaway.
·
On
July 6, 2006, MEHC entered into a $600 million credit facility
pursuant to the terms and conditions of an amended and restated credit
agreement. The amended and restated credit agreement remains unsecured,
carries a variable interest rate based on LIBOR or a base rate, at MEHC’s
option, plus a margin, and the termination date was extended to
July 6, 2011. The facility is for general corporate purposes and also
continues to support letters of credit for the benefit of certain
subsidiaries and affiliates.
·
On
August 10, 2006, PacifiCorp issued $350 million of 6.1%, 30-year
first mortgage bonds. The proceeds from this offering were used to repay a
portion of PacifiCorp’s short-term debt and for general corporate
purposes.
·
On
October 6, 2006, MidAmerican Energy completed the sale of
$350 million in aggregate principal amount of its 5.8% medium-term
notes due October 15, 2036. The proceeds from this offering were used
to support construction of MidAmerican Energy’s electric generation
projects, to repay a portion of its short-term debt and for general
corporate purposes.
Refer to
Item 5 of this Form 10-K for further discussion regarding the
limitation of distributions from MEHC’s subsidiaries.
Credit
Ratings
As of
January 31, 2008, MEHC’s senior unsecured debt credit ratings were as
follows: Moody’s Investor Service, “Baa1/stable”; Standard and Poor’s,
“BBB+/stable”; and Fitch Ratings, “BBB+/stable.”
Debt and
preferred securities of MEHC and certain of its subsidiaries are rated by
nationally recognized credit rating agencies. Assigned credit ratings are based
on each rating agency’s assessment of the rated company’s ability to, in
general, meet the obligations of its issued debt or preferred securities. The
credit ratings are not a recommendation to buy, sell or hold securities, and
there is no assurance that a particular credit rating will continue for any
given period of time. Other than the agreements discussed below, 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 their risk management activities, PacifiCorp and MidAmerican
Energy must meet credit quality standards as required by counterparties. In
accordance with industry practice, master agreements that govern PacifiCorp’s
and MidAmerican Energy’s energy supply and marketing activities either
specifically require each company to maintain investment grade credit ratings or
provide the right for counterparties to demand “adequate assurances” in the
event of a material adverse change in PacifiCorp’s or MidAmerican Energy’s
creditworthiness. If one or more of PacifiCorp’s or MidAmerican Energy’s credit
ratings decline below investment grade, PacifiCorp or MidAmerican Energy may be
required to post cash collateral, letters of credit or other similar credit
support to facilitate ongoing wholesale energy supply and marketing activities.
As of January 31, 2008, PacifiCorp’s and MidAmerican Energy’s credit
ratings from the three recognized credit rating agencies were investment grade;
however if the ratings fell below investment grade, PacifiCorp’s and MidAmerican
Energy’s estimated potential collateral requirements would total approximately
$265 million and $225 million, respectively. PacifiCorp’s and
MidAmerican Energy’s potential collateral requirements could fluctuate
considerably due to seasonality, market price volatility, and a loss of key
generating facilities or other related factors.
Inflation
Inflation
has not had a significant impact on the Company’s costs.
70
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 MEHC and subsidiary long-term debt and notes payable, operating leases,
purchase obligations and power and fuel purchase contracts. Other obligations
and commitments arise from unused lines of credit and letters of credit.
Material obligations and commitments as of December 31, 2007 are as follows
(in millions):
The
Company has other types of commitments that relate primarily to construction and
other development costs (Liquidity and Capital Resources included within this
Item 7), debt guarantees (Note 11), asset retirement obligations (Note 12)
and uncertain tax positions (Note 15) which have not been included in the above
tables because the amount and timing of the cash payments are not certain.
Refer, where applicable, to the respective referenced note in Notes to
Consolidated Financial Statements included in Item 8 of this Form 10-K for
additional information.
71
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
Consolidated Balance Sheets 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, 2007, the Company’s investments that are accounted for under
the equity method had short- and long-term debt, unused revolving credit
facilities and letters of credit outstanding of $616 million,
$210 million and $82 million, respectively. As of December 31,2007, the Company’s pro-rata share of such short- and long-term debt, unused
revolving credit facilities and outstanding letters of credit was
$306 million, $105 million and $41 million, respectively. The
entire amount of the Company’s pro-rata share of the outstanding short- and
long-term debt and unused revolving credit facilities is non-recourse to the
Company. $34 million of the Company’s pro-rata share of the outstanding
letters of credit is recourse to the Company and is included in the Obligations
and Commitments table. Although the Company is generally not required to support
debt service obligations of its equity investees, default with respect to this
non-recourse short- and long-term debt could result in a loss of invested
equity.
New
Accounting Pronouncements
For a
discussion of new accounting pronouncements affecting the Company, refer to
Note 2 of Notes to Consolidated Financial Statements included in
Item 8 of this Form 10-K.
Critical
Accounting Policies
Certain
accounting policies require management to make estimates and judgments
concerning transactions that will be settled in the future. Amounts recognized
in the Consolidated Financial Statements from such estimates are necessarily
based on numerous assumptions involving varying and potentially significant
degrees of judgment and uncertainty. Accordingly, the amounts currently
reflected in the Consolidated Financial Statements will likely increase or
decrease in the future as additional information becomes available. The
following critical accounting policies are impacted significantly by judgments,
assumptions and estimates used in the preparation of the Consolidated Financial
Statements.
Accounting
for the Effects of Certain Types of Regulation
PacifiCorp,
MidAmerican Energy, Northern Natural Gas and Kern River (the “Domestic Regulated
Businesses”) prepare their financial statements in accordance with the
provisions of Statement of Financial Accounting Standards (“SFAS”) No. 71,
“Accounting for the Effects of Certain Types of Regulation,” (“SFAS No. 71”)
which differs in certain respects from the application of GAAP by non-regulated
businesses. In general, SFAS No. 71 recognizes that accounting for
rate-regulated enterprises should reflect the economic effects of regulation. As
a result, a regulated entity is required to defer the recognition of costs or
income if it is probable that, through the rate-making process, there will be a
corresponding increase or decrease in future rates. Accordingly, the Domestic
Regulated Businesses have deferred certain costs and income that will be
recognized in earnings over various future periods.
Management
continually evaluates the applicability of SFAS No. 71 and assesses
whether its regulatory assets are probable of future recovery by considering
factors such as a change in the regulator’s approach to setting rates from
cost-based rate making to another form of regulation, other regulatory actions
or the impact of competition which could limit the Company’s ability to recover
its costs. Based upon this continual assessment, management believes the
application of SFAS No. 71 continues to be appropriate and its
existing regulatory assets are probable of recovery. The assessment reflects the
current political and regulatory climate at both the state and federal levels
and is subject to change in the future. If it becomes no longer probable that
these costs will be recovered, the regulatory assets and regulatory liabilities
would be written off and recognized in operating income. Total regulatory assets
were $1.50 billion and total regulatory liabilities were $1.63 billion
as of December 31, 2007. Refer to Note 6 of Notes to Consolidated
Financial Statements included in Item 8 of this Form 10-K for
additional information regarding the Company’s regulatory assets and
liabilities.
72
Derivatives
The
Company is exposed to variations in the market prices of electricity and natural
gas, foreign currency and interest rates and uses derivative instruments,
including forward purchases and sales, futures, swaps and options to manage
these inherent market price risks.
Measurement
Principles
Derivative
instruments are recorded in the Consolidated Balance Sheets at fair value as
either assets or liabilities unless they are designated and qualifying for the
normal purchases and normal sales exemption afforded by GAAP. The fair values of
derivative instruments are determined using forward price curves. Forward price
curves represent the Company’s estimates of the prices at which a buyer or
seller could contract today for delivery or settlement at future dates. The
Company bases its forward price curves upon market price quotations when
available and uses internally developed, modeled prices when market quotations
are unavailable. The fair value of these instruments is a function of underlying
forward commodity prices, interest rates, currency rates, related volatility,
counterparty creditworthiness and duration of contracts. The assumptions used in
these models are critical, since any changes in assumptions could have a
significant impact on the fair value of the contracts.
Classification
and Recognition Methodology
Almost
all of the Company’s contracts are probable of recovery in rates, and therefore
recorded as a net regulatory asset or liability, or are accounted for as cash
flow hedges and therefore changes in fair value are recorded as accumulated
other comprehensive income (loss). Accordingly, amounts are generally not
recognized in earnings until the contracts are settled. As of December 31,2007, the Company had $276 million recorded as net regulatory assets and
$91 million recorded as accumulated other comprehensive income (loss),
before tax, related to these contracts in the Consolidated Balance Sheets. If it
becomes no longer probable that a contract will be recovered in rates, the
regulatory asset will be written-off and recognized in earnings. For contracts
designated in hedge relationships (“hedge contracts”), 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, future changes in the value of the derivative are charged to
earnings. Gains and losses related to discontinued hedges that were previously
recorded in accumulated other comprehensive income will remain there until the
hedged item is realized, unless it is probable that the hedged forecasted
transaction will not occur at which time associated deferred amounts in
accumulated other comprehensive income are immediately recognized in
earnings.
Impairment
of Long-Lived Assets and Goodwill
The
Company evaluates long-lived assets for impairment, including property, plant
and equipment, when events or changes in circumstances indicate that the
carrying value of these assets may not be recoverable or the assets meet the
criteria of held for sale. Upon the occurrence of a triggering event, the asset
is reviewed to assess whether the estimated undiscounted cash flows expected
from the use of the asset plus the residual value from the ultimate disposal
exceeds the carrying value of the asset. If the carrying value exceeds the
estimated recoverable amounts, the asset is written down to the estimated
discounted present value of the expected future cash flows from using the asset.
For regulated assets, any impairment charge is offset by the establishment of a
regulatory asset to the extent recovery in rates is probable. Substantially all
of property, plant and equipment was used in regulated businesses as of
December 31, 2007. For all other assets, any resulting impairment loss is
reflected in the Consolidated Statements of Operations.
The
estimate of cash flows arising from the future use of the asset that are used in
the impairment analysis requires judgment regarding what the Company would
expect to recover from the future use of the asset. Changes in judgment that
could significantly alter the calculation of the fair value or the recoverable
amount of the asset may result from, but are not limited to, significant changes
in the regulatory environment, the business climate, management’s plans, legal
factors, market price of the asset, the use of the asset or the physical
condition of the asset. An impairment analysis of generating facilities or
pipelines requires estimates of possible future market prices, load growth,
competition and many other factors over the lives of the facilities. Any
resulting impairment loss is highly dependent on the underlying assumptions and
could significantly affect the Company’s results of operations.
73
The
Company’s Consolidated Balance Sheet as of December 31, 2007 includes
goodwill of acquired businesses of $5.34 billion. Goodwill is allocated to
each reporting unit and is tested for impairment using a variety of methods,
principally discounted projected future net cash flows, at least annually and
impairments, if any, are charged to earnings. The Company completed its annual
review as of October 31. A significant amount of judgment is required in
performing goodwill impairment tests. Key assumptions used in the testing
include, but are not limited to, the use of estimated future cash flows, EBITDA
multiples and an appropriate discount rate. Estimated future cash flows are
impacted by, among other factors, growth rates, changes in regulations and
rates, ability to renew contracts and estimates of future commodity prices. In
estimating cash flows, the Company incorporates current market information as
well as historical factors.
Accrued
Pension and Postretirement Expense
The
Company sponsors defined benefit pension and other postretirement benefit plans
that cover the majority of its employees. The Company recognizes the funded
status of its defined benefit pension and postretirement plans in the balance
sheet. Funded status is the fair value of plan assets minus the benefit
obligation as of the measurement date. As of December 31, 2007, the Company
recognized an asset totaling $162 million for the over-funded status and a
liability totaling $442 million for the under-funded status for the
Company’s defined benefit pension and other postretirement benefit
plans.
The
expense and benefit obligations relating to these pension and other
postretirement benefit plans are based on actuarial valuations. Inherent in
these valuations are key assumptions, including discount rates, expected returns
on plan assets and health care cost trend rates. These actuarial assumptions are
reviewed annually and modified as appropriate. The Company believes that the
assumptions utilized in recording obligations under the plans are reasonable
based on prior experience and market conditions. Refer to Note 19 of Notes
to Consolidated Financial Statements included in Item 8 of this
Form 10-K for disclosures about the Company’s pension and other
postretirement benefit plans, including the key assumptions used to calculate
the funded status and net periodic cost for these plans as of and for the period
ended December 31, 2007.
In
establishing its assumption as to the expected return on assets, the Company
reviews the expected asset allocation and develops return assumptions for each
asset class based on historical performance and forward-looking views of the
financial markets. Pension and other postretirement benefit expenses increase as
the expected rate of return on retirement plan and other postretirement benefit
plan assets decreases. The Company regularly reviews its actual asset
allocations and periodically rebalances its investments to its targeted
allocations when considered appropriate.
The
Company chooses a discount rate based upon high quality fixed-income investment
yields in effect as of the measurement date that corresponds to the expected
benefit period. The pension and other postretirement benefit liabilities, as
well as expenses, increase as the discount rate is reduced.
The
Company chooses a health care cost trend rate which reflects the near and
long-term expectations of increases in medical costs. The health care cost trend
rate gradually declines to 5% in 2010 through 2016 at which point the rate is
assumed to remain constant. Refer to Note 19 of Notes to Consolidated
Financial Statements included in Item 8 of this Form 10-K for health
care cost trend rate sensitivity disclosures.
74
The
actuarial assumptions used may differ materially from period to period due to
changing market and economic conditions. These differences may result in a
significant impact to the amount of pension and postretirement benefit expense
recorded and the funded status. If changes were to occur for the following
assumptions, the approximate effect on the financial statements would be as
follows (in millions):
A variety
of factors, including the plan funding practices of the Company, affect the
funded status of the plans. The Pension Protection Act of 2006 imposed generally
more stringent funding requirements for defined benefit pension plans,
particularly for those significantly under-funded, and allowed for greater tax
deductible contributions to such plans than previous rules permitted under the
Employee Retirement Income Security Act. As a result of the Pension Protection
Act of 2006, the Company does not anticipate any significant changes to the
amount of funding previously anticipated through 2008; however, depending on a
variety of factors which impact the funded status of the plans, including asset
returns, discount rates and plan changes, the Company may be required to
accelerate contributions to its domestic pension plans for periods after 2008
and there may be more volatility in annual contributions than historically
experienced, which could have a material impact on financial
results.
Income
Taxes
In
determining the Company’s tax liabilities, management is required to interpret
complex tax laws and regulations. In preparing tax returns, the Company is
subject to continuous examinations by federal, state, local and foreign tax
authorities that may give rise to different interpretations of these complex
laws and regulations. Due to the nature of the examination process, it generally
takes years before these examinations are completed and these matters are
resolved. The U.S. Internal Revenue Service has closed examination of the
Company’s income tax returns through 2003. In the U.K., each legal entity is
subject to examination by HM Revenue and Customs (“HMRC”), the U.K. equivalent
of the U.S. Internal Revenue Service. HMRC has closed examination of income tax
returns for the separate entities from 2000 to 2005. Most significantly,
Northern Electric’s and Yorkshire Electricity’s examinations are closed through
2001. In addition, open tax years related to a number of state and other foreign
jurisdictions remain subject to examination. Although the ultimate resolution of
the Company’s federal, state and foreign tax examinations is uncertain, the
Company believes it has made adequate provisions for these tax positions and the
aggregate amount of any additional tax liabilities that may result from these
examinations, if any, is not expected to have a material adverse affect on the
Company’s financial results.
Both
PacifiCorp and MidAmerican Energy are required to pass income tax benefits
related to certain accelerated tax depreciation and other property-related basis
differences on to their customers in most state jurisdictions. These amounts
were recognized as a net regulatory asset totaling $606 million as of
December 31, 2007, and will be included in rates when the temporary
differences reverse. Management believes the existing regulatory assets are
probable of recovery. If it becomes no longer probable that these costs will be
recovered, the assets would be written-off and recognized in
earnings.
75
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. The cumulative
earnings related to ongoing operations were approximately $1.5 billion as
of December 31, 2007. Because of the availability of U.S. foreign tax
credits, it is not practicable to determine the U.S. federal income tax
liability that would be payable if such earnings were not reinvested
indefinitely. Deferred taxes are provided for earnings of international
subsidiaries when the Company plans to remit those earnings. 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.
Revenue
Recognition - Unbilled Revenue
Unbilled
revenues were $480 million as of December 31, 2007. Historically, any
differences between the actual and estimated amounts have been immaterial.
Revenue from energy business customers is recognized as electricity or gas is
delivered or services are provided. The determination of sales to individual
customers is based on the reading of meters, fixed reservation charges based on
contractual quantities and rates or, in the case of the U.K. distribution
businesses, when information is received from the national settlement system.
The monthly unbilled revenue is determined by the estimation of unbilled energy
provided during the period. Factors that can impact the estimate of unbilled
energy provided include, but are not limited to, seasonal weather patterns,
historical trends, volumes, line losses, economic impacts and composition of
customer class. Estimates are generally reversed in the following month and
actual revenue is recorded based on subsequent meter readings.
The
Company’s Consolidated Balance Sheets include assets and liabilities whose fair
values are subject to market risks. The Company’s significant market risks are
primarily associated with commodity prices, foreign currency exchange rates and
interest rates. The following sections address the significant market risks
associated with the Company’s business activities. The Company also has
established guidelines for credit risk management. Refer to Notes 2 and 14
of Notes to Consolidated Financial Statements included in Item 8 of this
Form 10-K for additional information regarding the Company’s accounting for
derivative contracts.
Commodity Price
Risk
MEHC is
subject to significant commodity risk, particularly through its ownership of
PacifiCorp and MidAmerican Energy. Exposures include variations in the price of
wholesale electricity that is purchased and sold, fuel costs to generate
electricity, and natural gas supply for regulated retail gas customers.
Electricity and natural gas prices are subject to wide price swings as demand
responds to, among many other items, changing weather, limited storage,
transmission and transportation constraints, and lack of alternative supplies
from other areas. To mitigate a portion of the risk, our subsidiaries use
derivative instruments, including forwards, futures, options, swaps and other
over-the-counter agreements, to effectively secure future supply or sell future
production at fixed prices. The settled cost of these contracts is generally
recovered from customers in regulated rates. Accordingly, the net unrealized
gains and losses associated with interim price movements on contracts that are
accounted for as derivatives, that are probable of recovery in rates, are
recorded as regulatory assets or liabilities. Financial results may be
negatively impacted if the costs of wholesale electricity, fuel and or natural
gas are higher than what is permitted to be recovered in rates.
MidAmerican
Energy also uses futures, options and swap agreements to economically hedge gas
and electric commodity prices for physical delivery to non-regulated customers.
The Company does not engage in a material amount of proprietary trading
activities.
76
The table
that follows summarizes the Company’s commodity risk on energy derivative
contracts as of December 31, 2007 and shows the effects of a hypothetical
10% increase and a 10% decrease in forward market prices by the expected volumes
for these contracts as of that date. The selected hypothetical change does not
reflect what could be considered the best or worst case scenarios (dollars in
millions):
Fair
Value –
Asset
(Liability)
Hypothetical
Price Change
Estimated
Fair Value after Hypothetical Change in Price
MEHC’s
business operations and investments outside the United States increase its risk
related to fluctuations in foreign currency rates primarily in relation to the
British pound. Our principal reporting currency is the United States dollar, and
the value of the assets and liabilities, earnings, cash flows and potential
distributions from our foreign operations changes with the fluctuations of the
currency in which they transact.
CE
Electric UK’s functional currency is the British pound. At December 31,2007, a 10% devaluation in the British pound to the United States dollar would
result in MEHC’s Consolidated Balance Sheet being negatively impacted by a
$212 million cumulative translation adjustment in accumulated other
comprehensive income. A 10% devaluation in the average currency exchange rate
would have resulted in lower reported earnings for CE Electric UK of
$30 million in 2007.
Interest Rate
Risk
As of
December 31, 2007, The Company had fixed-rate long-term debt totaling
$18.96 billion with a total fair value of $19.80 billion. Because of
their fixed interest rates, these instruments do not expose 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 $917 million if
interest rates were to increase by 10% from their levels as of December 31,2007. Comparatively, as of December 31, 2006, the Company had fixed-rate
long-term debt totaling $16.72 billion with a total fair value of
$17.57 billion. The fair value of these instruments would have decreased by
approximately $733 million if interest rates had increased by 10% from
their levels as of December 31, 2006. In general, such a decrease in fair
value would impact earnings and cash flows only if the Company were to reacquire
all or a portion of these instruments prior to their maturity.
As of
December 31, 2007 and 2006, the Company had floating-rate obligations
totaling $729 million and $727 million, respectively, that expose the
Company to the risk of increased interest expense in the event of increases in
short-term interest rates. This market risk is not hedged; however, if floating
interest rates were to increase by 10% from December 31 levels, it would
not have a material effect on the Company’s consolidated annual interest expense
in either year.
Credit
Risk
Domestic
Regulated Operations
PacifiCorp
and MidAmerican Energy extend unsecured credit to other utilities, energy
marketers, financial institutions and certain commercial and industrial
end-users in conjunction with wholesale energy marketing activities. Credit risk
relates to the risk of loss that might occur as a result of non-performance by
counterparties of their contractual obligations to make or take delivery of
electricity, natural gas or other commodities and to make financial settlements
of these obligations. Credit risk may be concentrated to the extent that one or
more groups of counterparties have similar economic, industry or other
characteristics that would cause their ability to meet contractual obligations
to be similarly affected by changes in market or other conditions. In addition,
credit risk includes not only the risk that a counterparty may default due to
circumstances relating directly to it, but also the risk that a counterparty may
default due to circumstances involving other market participants that have a
direct or indirect relationship with such counterparty.
77
PacifiCorp
and MidAmerican Energy analyze the financial condition of each significant
counterparty before entering into any transactions, establish limits on the
amount of unsecured credit to be extended to each counterparty and evaluate the
appropriateness of unsecured credit limits on a daily basis. To mitigate
exposure to the financial risks of wholesale counterparties, PacifiCorp and
MidAmerican Energy enter into netting and collateral arrangements that include
margining and cross-product netting agreements and obtaining third-party
guarantees, letters of credit and cash deposits. Counterparties may be assessed
interest fees for delayed receipts. If required, PacifiCorp and MidAmerican
Energy exercise rights under these arrangements, including calling on the
counterparty’s credit support arrangement.
At
December 31, 2007, 71% of PacifiCorp’s and 91% of MidAmerican Energy’s
credit exposure, net of collateral, from wholesale operations was with
counterparties having externally rated “investment grade” credit ratings, while
an additional 9% of PacifiCorp’s and 8% of MidAmerican Energy’s credit exposure,
net of collateral, from wholesale operations was with counterparties having
financial characteristics deemed equivalent to “investment grade” by PacifiCorp
and MidAmerican Energy based on internal review.
Northern
Natural Gas’ primary customers include regulated local distribution companies in
the upper Midwest. Kern River’s primary customers are major oil and gas
companies or affiliates of such companies, electric generating companies, energy
marketing and trading companies and natural gas distribution utilities which
provide services in Utah, Nevada and California. As a general policy, collateral
is not required for receivables from creditworthy customers. Customers’
financial condition and creditworthiness are regularly evaluated, and historical
losses have been minimal. In order to provide protection against credit risk,
and as permitted by the separate terms of each of Northern Natural Gas’ and Kern
River’s tariffs, the companies have required customers that lack
creditworthiness, as defined by the tariffs, to provide cash deposits, letters
of credit or other security until their creditworthiness improves.
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 the multilateral “Distribution Connection and Use of System
Agreement.” Northern Electric’s and Yorkshire Electricity’s customers are
concentrated in a small number of electricity supply businesses with RWE Npower
PLC accounting for approximately 40% of distribution revenues in 2007. The
Office of Gas and Electricity Markets (“Ofgem”) has determined a framework which
sets credit limits for each supply business based on its credit rating or
payment history and requires them to provide credit cover if their value at risk
(measured as being equivalent to 45 days usage) exceeds the credit limit.
Acceptable credit typically is provided in the form of a parent company
guarantee, letter of credit or an escrow account. Ofgem has indicated that,
provided Northern Electric and Yorkshire Electricity have implemented credit
control, billing and collection in line with best practice guidelines and can
demonstrate compliance with the guidelines or are able to satisfactorily explain
departure from the guidelines, any bad debt losses arising from supplier default
will be recovered through an increase in future allowed income. Losses incurred
to date have not been material.
CalEnergy
Generation-Foreign
NIA’s
obligations under the Casecnan project agreement is CE
Casecnan’s sole source of operating revenue. Because of the
dependence on a single customer, any material failure of the customer to fulfill
its obligations under the project agreement and any material failure of the ROP
to fulfill its obligation under the performance undertaking would significantly
impair the ability to meet existing and future obligations, including
obligations pertaining to the outstanding project debt. Total operating revenue
for the Casecnan project was $125 million for the year ended
December 31, 2007. The Casecnan project agreement expires in
December 2021.
We have
audited the accompanying consolidated balance sheets of MidAmerican Energy
Holdings Company and subsidiaries (the “Company”) as of December 31, 2007
and 2006, and the related consolidated statements of operations, shareholders’
equity, and cash flows for each of the three years in the period ended
December 31, 2007. Our audits also included the financial statement
schedules listed in the Index at Item 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, 2007 and 2006, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2007, in conformity with accounting principles generally
accepted in the United States of America. Also, in our opinion, such financial
statement schedules, when considered in relation to the basic consolidated
financial statements taken as a whole, present fairly in all material respects
the information set forth therein.
As
discussed in Note 2 to the consolidated financial statements, the Company
adopted Statement of Financial Accounting Standards No. 158, “Employers’
Accounting for Defined Benefit Pension and Other Postretirement Plans - an
amendment of FASB Statements No. 87, 88, 106, and 132(R),” as of December 31,2006.
MidAmerican
Energy Holdings Company (“MEHC”) is a holding company which owns subsidiaries
that are principally engaged in energy businesses. MEHC and its subsidiaries are
referred to as the “Company.” MEHC is a consolidated subsidiary of Berkshire
Hathaway Inc. (“Berkshire Hathaway”). The Company is organized and managed as
eight distinct platforms: PacifiCorp (which was acquired on March 21,2006), MidAmerican Funding, LLC (“MidAmerican Funding”) (which primarily
includes MidAmerican Energy Company (“MidAmerican Energy”)), Northern Natural
Gas Company (“Northern Natural Gas”), Kern River Gas Transmission Company (“Kern
River”), CE Electric UK Funding Company (“CE Electric UK”) (which primarily
includes Northern Electric Distribution Limited (“Northern Electric”) and
Yorkshire Electricity Distribution plc (“Yorkshire Electricity”)), CalEnergy
Generation-Foreign (owning a majority interest in the Casecnan project),
CalEnergy Generation-Domestic (owning interests in independent power projects in
the United States), and HomeServices of America, Inc. (collectively with its
subsidiaries, “HomeServices”). Through these platforms, the Company owns and
operates an electric utility company in the Western United States, a combined
electric and natural gas utility company in the Midwestern United States, two
interstate natural gas pipeline companies in the United States, two electricity
distribution companies in Great Britain, a diversified portfolio of independent
power projects and the second largest residential real estate brokerage firm in
the United States.
(2)
Summary
of Significant Accounting Policies
Basis
of Consolidation
The
Consolidated Financial Statements include the accounts of MEHC and its
subsidiaries in which it holds a controlling financial interest. The
Consolidated Statements of Operations include the revenues and expenses of an
acquired entity from the date of acquisition.
Intercompany
accounts and transactions have been eliminated.
Use
of Estimates in Preparation of Financial Statements
The
preparation of the Consolidated Financial Statements in conformity with
accounting principles generally accepted in the United States of America
(“GAAP”) requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the period.
These estimates include, but are not limited to, unbilled receivables, valuation
of energy contracts, the effects of regulation, long-lived asset recovery,
goodwill impairment, the accounting for contingencies, including environmental,
regulatory and income tax matters, and certain assumptions made in accounting
for pension and other postretirement benefits. Actual results may differ from
the estimates used in preparing the Consolidated Financial
Statements.
Cash
Equivalents and Restricted Cash and Investments
Cash
equivalents consist of funds invested in commercial paper, money market
securities and in other investments with a maturity of three months or less when
purchased. Cash and cash equivalents exclude amounts where the availability is
restricted by legal requirements, loan agreements or other contractual
provisions. Restricted amounts are included in other current assets and deferred
charges, investments and other assets in the Consolidated Balance
Sheets.
Investments
The
Company’s management determines the appropriate classifications of investments
in debt and equity securities at the acquisition date and re-evaluates the
classifications at each balance sheet date. The Company’s investments in debt
and equity securities are primarily classified as
available-for-sale.
86
Available-for-sale
securities are stated at fair value with realized gains and losses, as
determined on a specific identification basis, recognized in earnings and
unrealized gains and losses recognized in accumulated other comprehensive income
(“AOCI”), net of tax. Realized and unrealized gains and losses on certain trust
funds related to the decommissioning of nuclear generation assets and the final
reclamation of leased coal mining property are recorded as regulatory assets or
liabilities since the Company expects to recover costs for these activities
through rates.
The
Company utilizes the equity method of accounting with respect to investments
where it exercises significant influence, but not control, over the operating
and financial policies of the investee. The equity method of accounting is
normally applied where the Company has a voting interest of at least 20% and no
greater than 50%. In applying the equity method, investments are recorded at
cost and subsequently increased or decreased by the Company’s proportionate
share of the net earnings or losses of the investee. The Company also records
its proportionate share of other comprehensive income items of the investee as a
component of its comprehensive income. Dividends or other equity distributions
are recorded as a reduction of the investment. Equity investments are required
to be tested for impairment when it is determined that an other-than-temporary
loss in value below the carrying amount has occurred.
Accounting
for the Effects of Certain Types of Regulation
PacifiCorp,
MidAmerican Energy, Northern Natural Gas and Kern River (the “Domestic Regulated
Businesses”) prepare their financial statements in accordance with the
provisions of Statement of Financial Accounting Standards (“SFAS”) No. 71,
“Accounting for the Effects of Certain Types of Regulation,” (“SFAS No. 71”)
which differs in certain respects from the application of GAAP by non-regulated
businesses. In general, SFAS No. 71 recognizes that accounting for
rate-regulated enterprises should reflect the economic effects of regulation. As
a result, a regulated entity is required to defer the recognition of costs or
income if it is probable that, through the rate-making process, there will be a
corresponding increase or decrease in future rates. Accordingly, the Domestic
Regulated Businesses have deferred certain costs and income that will be
recognized in earnings over various future periods.
Management
continually evaluates the applicability of SFAS No. 71 and assesses whether its
regulatory assets are probable of future recovery by considering factors such as
a change in the regulator’s approach to setting rates from cost-based rate
making to another form of regulation, other regulatory actions or the impact of
competition which could limit the Company’s ability to recover its costs. Based
upon this continual assessment, management believes the application of SFAS No.
71 continues to be appropriate and its existing regulatory assets are probable
of recovery. The assessment reflects the current political and regulatory
climate at both the state and federal levels and is subject to change in the
future. If it becomes no longer probable that these costs will be recovered, the
regulatory assets and regulatory liabilities would be written off and recognized
in operating income.
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 ability of customers to pay the amounts owed to the Company and
the outcome of pending disputes and arbitrations. As of December 31, 2007
and 2006, the allowance for doubtful accounts totaled $22 million and
$30 million, respectively.
Derivatives
The
Company employs a number of different derivative instruments in connection with
its electric and natural gas, foreign currency exchange rate and interest rate
risk management activities, including forward purchases and sales, futures,
swaps and options. Derivative instruments are recorded in the Consolidated
Balance Sheets at fair value as either assets or liabilities unless they are
designated and qualify for the normal purchases and normal sales exemption
afforded by GAAP. Contracts that qualify as normal purchases or normal sales are
not marked to market. Derivative contracts for commodities used in normal
business operations that are settled by physical delivery, among other criteria,
are eligible for and may be designated as normal purchases and normal sales
pursuant to the exemption. Recognition of these contracts in operating revenue
or cost of sales in the Consolidated Statements of Operations occurs when the
contracts settle.
87
For
contracts designated in hedge relationships (“hedge contracts”), the Company
maintains formal documentation of the hedge. In addition, at inception and on a
quarterly basis, the Company formally assesses whether the hedge contracts are
highly effective in offsetting changes in cash flows or fair values of the
hedged items. The Company documents hedging activity by transaction type and
risk management strategy.
Changes
in the fair value of a derivative designated and qualified as a cash flow hedge,
to the extent effective, are included in the Consolidated Statements of
Shareholders’ Equity as AOCI, net of tax, until the hedged item is recognized in
earnings. The Company discontinues hedge accounting prospectively when it has
determined that a derivative no longer qualifies as an effective hedge, or when
it is no longer probable that the hedged forecasted transaction will occur. When
hedge accounting is discontinued because the derivative no longer qualifies as
an effective hedge, future changes in the value of the derivative are charged to
earnings. Gains and losses related to discontinued hedges that were previously
recorded in AOCI will remain in AOCI until the hedged item is realized, unless
it is probable that the hedged forecasted transaction will not occur at which
time associated deferred amounts in AOCI are immediately recognized in current
earnings.
Certain
derivative electric and gas contracts utilized by the regulated operations of
PacifiCorp and MidAmerican Energy are recoverable through rates. Accordingly,
unrealized changes in fair value of these contracts are deferred as net
regulatory assets or liabilities pursuant to SFAS No. 71.
When
available, quoted market prices or prices obtained through external sources are
used to measure a contract’s fair value. For contracts without available quoted
market prices, fair value is determined based on internally developed modeled
prices. The fair value of these instruments is a function of underlying forward
commodity prices, interest rates, currency rates, related volatility,
counterparty creditworthiness and duration of the contracts.
Inventories
Inventories
consist mainly of materials and supplies, coal stocks, gas in storage and fuel
oil, which are valued at the lower of cost or market. The cost of materials and
supplies, coal stocks and fuel oil is determined primarily using average cost.
The cost of gas in storage is determined using the last-in-first-out (“LIFO”)
method. With respect to inventories carried at LIFO cost, the cost determined
under the first-in-first-out method would be $73 million and
$77 million higher as of December 31, 2007 and 2006,
respectively.
Property,
Plant and Equipment, Net
General
Property,
plant and equipment is recorded at historical cost. The Company capitalizes all
construction related material, direct labor costs and contract services, as well
as indirect construction costs, which include capitalized interest and equity
allowance for funds used during construction (“AFUDC”). The cost of major
additions and betterments are capitalized, while costs for replacements,
maintenance, and repairs that do not improve or extend the lives of the
respective assets are charged to operating expense. Depreciation and
amortization are generally computed by applying the composite and straight-line
method based on estimated economic lives or regulatorily mandated recovery
periods. Periodic depreciation studies are performed to determine the
appropriate group lives, net salvage and group depreciate rates. The Company
believes the useful lives assigned to the depreciable assets, which range from 3
to 85 years, are reasonable.
Generally
when the Company retires or sells its domestic regulated property, plant and
equipment, it charges the original cost to accumulated depreciation. Any net
cost of removal is charged against the cost of removal regulatory liability that
was established through depreciation rates. Net salvage is recorded in the
related accumulated depreciation and amortization accounts and the residual gain
or loss is deferred and subsequently amortized through future depreciation
expense. Any gain or loss on disposals of all other assets is recorded in income
or expense.
The
Domestic Regulated Businesses record AFUDC, which represents the estimated debt
and equity costs of capital funds necessary to finance the construction of
domestic regulated facilities. AFUDC is capitalized as a component of property,
plant and equipment cost, with offsetting credits to the Consolidated Statements
of Operations. After construction is completed, the Company is permitted to earn
a return on these costs by their inclusion in rate base, as well as recover
these costs through depreciation expense over the useful life of the related
assets.
88
Asset
Retirement Obligations
The
Company recognizes legal asset retirement obligations (“ARO”), mainly related to
the decommissioning of nuclear generation assets and the final reclamation of
leased coal mining property. The fair value of a liability for a legal ARO is
recognized in the period in which it is incurred, if a reasonable estimate of
fair value can be made. The fair value of the liability is added to the carrying
amount of the associated asset, which is then depreciated over the remaining
useful life of the asset. Subsequent to the initial recognition, the liability
is adjusted for any material revisions to the expected value of the retirement
obligation (with corresponding adjustments to property, plant and equipment) and
for accretion of the liability due to the passage of time. The difference
between the ARO liability, the corresponding ARO asset included in property,
plant and equipment and amounts recovered in rates to satisfy such liabilities
is recorded as a regulatory asset or liability. Estimated removal costs that
PacifiCorp and MidAmerican Energy recover through approved depreciation rates,
but that do not meet the requirements of a legal ARO, are accumulated in asset
retirement removal costs within regulatory liabilities in the Consolidated
Balance Sheets.
Impairment
The
Company evaluates long-lived assets for impairment, including property, plant
and equipment, when events or changes in circumstances indicate that the
carrying value of these assets may not be recoverable, or the assets meet the
criteria of held for sale. Upon the occurrence of a triggering event, the asset
is reviewed to assess whether the estimated undiscounted cash flows expected
from the use of the asset plus residual value from the ultimate disposal exceeds
the carrying value of the asset. If the carrying value exceeds the estimated
recoverable amounts, the asset is written down to the estimated discounted
present value of the expected future cash flows from using the asset. For
regulated assets, any impairment charge is offset by the establishment of a
regulatory asset to the extent recovery in rates is probable. For all other
assets, any resulting impairment loss is reflected in the Consolidated
Statements of Operations.
Goodwill
Goodwill
represents the difference between purchase cost and the fair value of net assets
acquired in business acquisitions. Goodwill is allocated to each reporting unit
and is tested for impairment using a variety of methods, principally discounted
projected future net cash flows, at least annually and impairments, if any, are
charged to earnings. The Company completed its annual review as of
October 31. Key assumptions used in the testing include, but are not
limited to, the use of an appropriate discount rate and estimated future cash
flows. In estimating cash flows, the Company incorporates current market
information as well as historical factors. During 2007, 2006 and 2005, the
Company did not record any goodwill impairments.
The
Company records goodwill adjustments for (i) changes in the estimates or the
settlement of tax bases of acquired assets, liabilities and carryforwards and
items relating to acquired entities’ prior income tax returns, (ii) the tax
benefit associated with the excess of tax-deductible goodwill over the reported
amount of goodwill, and (iii) changes to the purchase price allocation prior to
the end of the allocation period, which is generally one year from the
acquisition date.
Revenue
Recognition
Energy
Businesses
Revenue
from electric customers is recognized as electricity is delivered and includes
amounts for services rendered. Revenue from the sale, distribution and
transportation of natural gas is recognized when either the service is provided
or the product is delivered. Revenue recognized includes unbilled as well as
billed amounts.
Rates
charged by the domestic regulated energy businesses are subject to federal and
state regulation. When preliminary rates are permitted to be billed prior to
final approval by the applicable regulator, certain revenue collected may be
subject to refund and a provision for estimated refunds is accrued. Electric
distribution revenues in the U.K. are limited to amounts allowed under their
regulatory formula while under-recoveries are not recognized in revenue. Over-
or under-recoveries of amounts allowed under the regulatory formula are either
refunded to customers or recovered through adjustments in future
rates.
89
Electricity
and water is delivered in the Philippines pursuant to provisions of the
respective project agreements which are accounted for as arrangements that
contain both a lease and a service contract. The leases are classified as
operating due to significant uncertainty regarding the collection of future
amounts mainly due to the existence of political, economic and other
uncertainties in the Philippines. The majority of the revenue under these
arrangements is fixed.
The
Company records sales, franchise and excise taxes, which are collected directly
from customers and remitted directly to the taxing authorities, on a net basis
in the Consolidated Statements of Operations.
Real
Estate 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 closing.
Unamortized
Debt Premiums, Discounts and Financing Costs
Premiums,
discounts and financing costs incurred during the issuance of long-term debt are
amortized over the term of the related financing using the effective interest
method.
Foreign
Currency
The
accounts of foreign-based subsidiaries are measured in most instances using the
local currency as the functional currency. Revenue and expenses of these
businesses are translated into U.S. dollars at the average exchange rate for the
period. Assets and liabilities are translated at the exchange rate as of the end
of the reporting period. Gains or losses from translating the financial
statements of foreign-based operations are included in shareholders’ equity as a
component of AOCI. Gains or losses arising from other transactions denominated
in a foreign currency are included in the Consolidated Statements of
Operations.
Income
Taxes
Berkshire
Hathaway commenced including the Company in its U.S. federal income tax return
in 2006 as a result of converting its convertible preferred stock of MEHC into
shares of MEHC common stock on February 9, 2006. The Company’s provision
for income taxes has been computed on a stand-alone basis. Prior to the
conversion, the Company filed a consolidated U.S. federal income tax
return.
Deferred
tax assets and liabilities are based on differences between the financial
statements and tax bases of assets and liabilities using the estimated tax rates
in effect for the year in which the differences are expected to reverse. Changes
in deferred income tax assets and liabilities that are associated with
components of other comprehensive income are charged or credited directly to
other comprehensive income. Changes in deferred income tax assets and
liabilities that are associated with income tax benefits related to certain
property-related basis differences and other various differences that PacifiCorp
and MidAmerican Energy are required to pass on to their customers in most state
jurisdictions are charged or credited directly to a regulatory asset or
regulatory liability. These amounts were recognized as a net regulatory asset
totaling $606 million and $581 million as of December 31, 2007
and December 31, 2006, respectively, and will be included in rates when the
temporary differences reverse. Other changes in deferred income tax assets and
liabilities are included as a component of income tax expense. Valuation
allowances have been established for certain deferred tax assets where
management has judged that realization is not likely.
Investment
tax credits are generally deferred and amortized over the estimated useful lives
of the related properties or as prescribed by various regulatory
jurisdictions.
The
Company has not provided U.S. federal deferred income taxes on its currency
translation adjustment or the cumulative earnings of international subsidiaries
that have been determined by management to be reinvested indefinitely. The
cumulative earnings related to ongoing operations were approximately
$1.5 billion as of December 31, 2007. Because of the availability of
U.S. foreign tax credits, it is not practicable to determine the U.S. federal
income tax liability that would be payable if such earnings were not reinvested
indefinitely. Deferred taxes are provided for earnings of international
subsidiaries when the Company plans to remit those earnings.
90
In
determining the Company’s tax liabilities, management is required to interpret
complex tax laws and regulations. In preparing tax returns, the Company is
subject to continuous examinations by federal, state, local and foreign tax
authorities that may give rise to different interpretations of these complex
laws and regulations. Due to the nature of the examination process, it generally
takes years before these examinations are completed and these matters are
resolved. The U.S. Internal Revenue Service has closed examination of the
Company’s income tax returns through 2003. In the U.K., each legal entity is
subject to examination by HM Revenue and Customs (“HMRC”), the U.K. equivalent
of the U.S. Internal Revenue Service. HMRC has closed examination of income tax
returns for the separate entities from 2000 to 2005. Most significantly,
Northern Electric’s and Yorkshire Electricity’s examinations are closed through
2001. In addition, open tax years related to a number of state and other foreign
jurisdictions remain subject to examination. Although the ultimate resolution of
the Company’s federal, state and foreign tax examinations is uncertain, the
Company believes it has made adequate provisions for these tax positions and the
aggregate amount of any additional tax liabilities that may result from these
examinations, if any, will not have a material adverse affect on the Company’s
financial results. The Company’s unrecognized tax benefits
are primarily included in other long-term accrued liabilities in the
Consolidated Balance Sheets. The Company recognizes interest and penalties
related to unrecognized tax benefits in income tax expense in the Consolidated
Statements of Operations.
New
Accounting Pronouncements
In July
2006, the Financial Accounting Standards Board (“FASB”) issued FASB
Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an
interpretation of FASB Statement No. 109” (“FIN 48”). The Company adopted the
provisions of FIN 48 effective January 1, 2007. Under FIN 48, tax
benefits are recognized only for tax positions that are more likely than not to
be sustained upon examination by tax authorities. The amount recognized is
measured as the largest amount of benefit that is greater than 50% likely to be
realized upon ultimate settlement. Unrecognized tax benefits are tax benefits
claimed in the Company’s tax returns that do not meet these recognition and
measurement standards. Refer to Note 15 for additional
discussion.
In
December 2007, the FASB issued Statement of Financial Accounting Standards
(“SFAS”) No. 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS
No. 141(R) applies to all transactions or other events in which an entity
obtains control of one or more businesses. SFAS No. 141(R) establishes how
the acquirer of a business should recognize, measure and disclose in its
financial statements the identifiable assets and goodwill acquired, the
liabilities assumed and any noncontrolling interest in the acquired business.
SFAS No. 141(R) is applied prospectively for all business combinations with
an acquisition date on or after the beginning of the first annual reporting
period beginning on or after December 15, 2008, with early application
prohibited. SFAS No. 141(R) will not have an impact on the Company’s
historical Consolidated Financial Statements and will be applied to business
combinations completed, if any, on or after January 1, 2009.
In
December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in
Consolidated Financial Statements – an amendment of ARB No. 51” (“SFAS No.
160”). SFAS No. 160 establishes accounting and reporting standards for the
noncontrolling interest in a subsidiary and for the deconsolidation of a
subsidiary. SFAS No. 160 requires entities to report noncontrolling interests as
a separate component of shareholders’ equity in the consolidated financial
statements. The amount of earnings attributable to the parent and to the
noncontrolling interests should be clearly identified and presented on the face
of the consolidated statements of operations. Additionally, SFAS No. 160
requires any changes in a parent’s ownership interest of its subsidiary, while
retaining its control, to be accounted for as equity transactions. SFAS No. 160
is effective for fiscal years beginning on or after December 15, 2008 and
interim periods within those fiscal years. The Company is currently evaluating
the impact of adopting SFAS No. 160 on its consolidated financial position and
results of operations.
In
February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for
Financial Assets and Financial Liabilities - including an amendment of FASB
Statement No. 115” (“SFAS No. 159”). SFAS No. 159 permits entities to elect to
measure many financial instruments and certain other items at fair value. Upon
adoption of SFAS No. 159, an entity may elect the fair value option for eligible
items that exist at the adoption date. Subsequent to the initial adoption, the
election of the fair value option should only be made at initial recognition of
the asset or liability or upon a remeasurement event that gives rise to
new-basis accounting. The decision about whether to elect the fair value option
is applied on an instrument-by-instrument basis, is irrevocable and is applied
only to an entire instrument and not only to specified risks, cash flows or
portions of that instrument. SFAS No. 159 does not affect any existing
accounting literature that requires certain assets and liabilities to be carried
at fair value nor does it eliminate disclosure requirements included in other
accounting standards. SFAS No. 159 is effective for fiscal years beginning
after November 15, 2007. The Company does not anticipate electing the fair
value option for any existing eligible items. However, the Company will continue
to evaluate items on a case-by-case basis for consideration of the fair value
option.
91
In
September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements”
(“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework
for measuring fair value and expands disclosures about fair value measurements.
SFAS No. 157 does not impose fair value measurements on items not already
accounted for at fair value; rather it applies, with certain exceptions, to
other accounting pronouncements that either require or permit fair value
measurements. Under SFAS No. 157, fair value refers to the price that would
be received to sell an asset or paid to transfer a liability in an orderly
transaction between market participants in the principal or most advantageous
market. The standard clarifies that fair value should be based on the
assumptions market participants would use when pricing the asset or liability.
SFAS No. 157 is effective for fiscal years beginning after
November 15, 2007, and interim periods within those fiscal years. The
Company is currently evaluating the impact of adopting SFAS No. 157 on its
consolidated financial position and results of operations.
In May
2005, MEHC reached a definitive agreement with Scottish Power plc
(“ScottishPower”) and its subsidiary, PacifiCorp Holdings, Inc., to acquire 100%
of the common stock of ScottishPower’s wholly-owned indirect subsidiary,
PacifiCorp. On March 21, 2006, a wholly owned subsidiary of MEHC acquired
100% of the common stock of PacifiCorp from a wholly owned subsidiary of
ScottishPower for a cash purchase price of $5.11 billion, which was funded
through the issuance of common stock (see Note 17). MEHC also incurred
$10 million of direct transaction costs associated with the acquisition,
which consisted principally of investment banker commissions and outside legal
and accounting fees, resulting in a total purchase price of $5.12 billion.
As a result of the acquisition, MEHC controls substantially all of PacifiCorp’s
voting securities, which include both common and preferred stock. The results of
PacifiCorp’s operations are included in the Company’s results beginning
March 21, 2006 (the “acquisition date”).
92
Allocation
of Purchase Price
The total
purchase price was allocated to PacifiCorp’s net tangible and identified
intangible assets acquired and liabilities assumed based on their estimated fair
values at the acquisition date. PacifiCorp’s operations are regulated and are
accounted for pursuant to SFAS No. 71. PacifiCorp has demonstrated a past
history of recovering its costs incurred through its rate making process.
Certain adjustments, which were not significant, related to derivative
contracts, severance costs and income taxes were made to the purchase price
allocation. The following table summarizes the adjusted fair values of the
assets acquired and liabilities assumed as of the acquisition date (in
millions):
Fair
Value
Current
assets, including cash and cash equivalents of $183
$
1,115
Property,
plant and equipment, net
10,047
Goodwill
1,140
Regulatory
assets
1,307
Other
non-current assets
665
Total
assets
14,274
Current
liabilities, including short-term debt of $184 and current portion of
long-term debt of $221
(1,283
)
Regulatory
liabilities
(818
)
Pension
and postretirement obligations
(830
)
Subsidiary
and project debt, less current portion
(3,762
)
Deferred
income taxes
(1,606
)
Other
non-current liabilities
(855
)
Total
liabilities
(9,154
)
Net
assets acquired
$
5,120
Certain
transition activities, pursuant to established plans, were undertaken as
PacifiCorp was integrated into the Company. Costs, relating primarily to
employee termination activities, have been incurred associated with such
transition activities, which were completed as of March 31, 2007. The
finalization of certain integration plans resulted in adjustments to the
purchase price allocation for the acquired assets and assumed liabilities of
PacifiCorp. Qualifying severance costs accrued during the three-month period
ended March 31, 2007, and the period from the acquisition date to
December 31, 2006, totaled $7 million and $41 million,
respectively. Accrued severance costs were $34 million and $31 million
as of March 31, 2007 and December 31, 2006, respectively.
Pro
Forma Financial Information
The
following pro forma condensed consolidated results of operations assume that the
acquisition of PacifiCorp was completed as of January 1, 2005, and provides
information for the years ended December 31 (in millions):
2006
2005
Operating
revenue
$
11,453
$
10,405
Net
income
$
1,060
$
863
The pro
forma financial information represents the historical operating results of the
combined company with adjustments for purchase accounting and is not necessarily
indicative of the results of operations that would have been achieved if the
acquisition had taken place at the beginning of each period
presented.
93
(4)
Property,
Plant and Equipment, Net
Property,
plant and equipment, net consist of the following as of December 31 (in
millions):
Depreciation
Life
2007
2006
Regulated
assets:
Utility
generation, distribution and transmission system
5-85
years
$
30,369
$
27,687
Interstate
pipeline assets
3-67
years
5,484
5,329
35,853
33,016
Accumulated
depreciation and amortization
(12,280
)
(11,872
)
Regulated
assets, net
23,573
21,144
Non-regulated
assets:
Independent
power plants
10-30
years
680
1,184
Other
assets
3-30
years
650
586
1,330
1,770
Accumulated
depreciation and amortization
(427
)
(844
)
Non-regulated
assets, net
903
926
Net
operating assets
24,476
22,070
Construction
in progress
1,745
1,969
Property,
plant and equipment, net
$
26,221
$
24,039
Substantially
all of the construction in progress as of December 31, 2007 and 2006
relates to the construction of regulated assets.
Northern
Natural Gas entered into a purchase and sale agreement for the West Hugoton
non-strategic section of its interstate pipeline system in the fourth quarter of
2005. As a result of entering into the purchase and sale agreement, Northern
Natural Gas recognized a non-cash impairment charge of $29 million
($18 million after-tax) to write down the carrying value of the asset to
its fair value. The fair value was determined based on the agreed sale price.
The impairment charge is recorded in operating expense in the accompanying
Consolidated Statements of Operations for the year ended December 31,2005.
94
(5)
Jointly
Owned Utility Plant
Under
joint plant ownership agreements with other utilities, both PacifiCorp and
MidAmerican Energy, as tenants in common, have undivided interests in jointly
owned generation and transmission facilities. The Company accounts for its
proportional share of each facility, and each joint owner has provided financing
for its share of each generating plant or transmission line. Operating costs of
each facility are assigned to joint owners based on ownership percentage or
energy purchased, depending on the nature of the cost. Operating expenses in the
Consolidated Statements of Operations include the Company’s share of the
expenses of these facilities.
The
amounts shown in the table below represent the Company’s share in each jointly
owned facility as of December 31, 2007 (dollars in millions):
Accumulated
Construction
Company
Plant
in
Depreciation/
Work-in-
Share
Service
Amortization
Progress
PacifiCorp:
Jim
Bridger Nos. 1-4
67
%
$
965
$
482
$
13
Wyodak
80
329
168
1
Hunter
No. 1
94
304
146
1
Colstrip
Nos. 3 and 4
10
243
118
1
Hunter
No. 2
60
192
87
1
Hermiston(1)
50
170
37
2
Craig
Nos. 1 and 2
19
167
77
1
Hayden
No. 1
25
44
20
1
Foote
Creek
79
37
13
-
Hayden
No. 2
13
27
14
-
Other
transmission and distribution plants
Various
80
20
2
Total
PacifiCorp
2,558
1,182
23
MidAmerican
Energy:
Walter
Scott, Jr. Unit No. 4
60
%
634
10
-
Louisa
Unit No. 1
88
750
352
1
Walter
Scott, Jr. Unit No. 3
79
345
227
86
Quad
Cities Unit Nos. 1 and 2
25
320
149
9
Ottumwa
Unit No. 1
52
264
147
3
George
Neal Unit No. 4
41
169
123
-
George
Neal Unit No. 3
72
142
105
2
Transmission
facilities
Various
169
46
-
Total
MidAmerican Energy
2,793
1,159
101
Total
$
5,351
$
2,341
$
124
(1)
PacifiCorp
has contracted to purchase the remaining 50% of the output of the
Hermiston plant.
95
(6) Regulatory
Matters
Regulatory Assets and
Liabilities
Regulatory
assets represent costs that are expected to be recovered in future rates. The
Company’s regulatory assets reflected in the Consolidated Balance Sheets consist
of the following as of December 31 (in millions):
Average
Remaining
Life
2007
2006
Deferred
income taxes(1)
31
years
$
680
$
666
Unrealized
loss on regulated derivatives(2)
8
years
276
266
Employee
benefit plans(3)
11
years
274
625
Asset
retirement obligations
15
years
47
46
Computer
systems development costs
4
years
36
45
Other
Various
190
179
Total
$
1,503
$
1,827
(1)
Amounts
represent income tax benefits related to state accelerated tax
depreciation and certain property-related basis differences that were
previously flowed through to customers and will be included in rates when
the temporary differences reverse.
(2)
Amounts
represent net unrealized losses related to derivative contracts included
in rates.
(3)
Amounts
represent unrecognized components of benefit plans’ funded status that are
recoverable in rates when recognized in net periodic benefit
cost.
The
Company had regulatory assets not earning a return or earning less than the
stipulated return as of December 31, 2007 and 2006 of $1.3 billion and
$1.7 billion, respectively.
Regulatory
liabilities represent income to be recognized or amounts to be returned to
customers in future periods. The Company’s regulatory liabilities reflected in
the Consolidated Balance Sheets consist of the following as of December 31
(in millions):
Average
Remaining
Life
2007
2006
Cost
of removal accrual(1)
(2)
31
years
$
1,198
$
1,164
Employee
benefit plans(3)
14
years
173
141
Asset
retirement obligations(1)
31
years
148
133
Deferred
income taxes
33
years
36
48
Iowa
electric settlement accrual(1)
1
year
17
259
Unrealized
gain on regulated derivatives
1
year
-
22
Other
Various
57
72
Total
$
1,629
$
1,839
(1)
Amounts
are deducted from rate base or otherwise accrue a carrying
cost.
(2)
Amounts
represent the remaining estimated costs, as accrued through depreciation
rates and exclusive of ARO liabilities, of removing electric utility
assets in accordance with accepted regulatory
practices.
(3)
Amounts
represent unrecognized components of benefit plans’ funded status that are
to be returned to customers in future periods when recognized in net
periodic benefit cost.
96
Rate
Matters
Iowa
Electric Revenue Sharing
The Iowa
Utilities Board (“IUB”) has approved a series of settlement agreements between
MidAmerican Energy, the Iowa Office of Consumer Advocate (“OCA”) and other
intervenors, under which MidAmerican Energy has agreed not to seek a general
increase in electric base rates to become effective prior to January 1,2014, unless its Iowa jurisdictional electric return on equity for any year
covered by the applicable agreement falls below 10%, computed as prescribed in
each respective agreement. Prior to filing for a general increase in electric
rates, MidAmerican Energy is required to conduct 30 days of good faith
negotiations with the signatories to the settlement agreements to attempt to
avoid a general increase in such rates. As a party to the settlement agreements,
the OCA has agreed not to request or support any decrease in MidAmerican
Energy’s Iowa electric base rates to become effective prior to January 1,2014. The settlement agreements specifically allow the IUB to approve or order
electric rate design or cost of service rate changes that could result in
changes to rates for specific customers as long as such changes do not result in
an overall increase in revenues for MidAmerican Energy.
The
settlement agreements also each provide that revenues associated with Iowa
retail electric returns on equity within specified ranges will be shared with
customers and that the portion assigned to customers will be recorded as a
regulatory liability. The following table summarizes the ranges of Iowa electric
returns on equity subject to revenue sharing under each settlement agreement,
the percent of revenues within those ranges to be assigned to customers, and the
method by which the liability to customers will be settled.
Credits
against the cost of wind-powered generation projects covered by this
agreement
(1)
If a
rate
case is filed pursuant to the 10% threshold, as discussed above, the
revenue sharing arrangement for 2013 is changed such that the amount to be
shared with customers will be 83.3% of revenues associated with Iowa
operating income in excess of electric returns on equity allowed by the
IUB as a result of the rate case.
97
The
regulatory liabilities created by the settlement agreements have been and are
currently recorded as a regulatory charge in depreciation and amortization
expense when the liability is accrued. As a result of the credits applied to
generating plant balances when the related plant is placed in service,
depreciation expense is reduced over the life of the plant. On June 1,2007, WSEC Unit 4 was placed in service. Accordingly, the January 1,2007 balance of the revenue sharing liability of $264 million, plus the
related interest accrued in 2007, was applied against the cost of WSEC
Unit 4 in utility generation, distribution and transmission
system.
Refund
Matters
Kern
River
Kern
River’s 2004 general rate case hearing concluded in August 2005. On
March 2, 2006, Kern River received an initial decision on the case from the
administrative law judge. On October 19, 2006, the Federal Energy
Regulatory Commission (“FERC”) issued an order that modified certain aspects of
the administrative law judge’s initial decision, including changing the allowed
return on equity from 9.34% to 11.2% and granting Kern River an income tax
allowance. The order also affirmed the rejection of certain issues included in
Kern River’s filed position, including the load factors to be used in
calculating rates for the vintage system. The FERC determined that a 100% load
factor should be used in the rate calculation rather than the 95% load factor
requested by Kern River. The FERC also rejected a 3% inflation factor for
certain operating expenses and a shorter useful life for certain plant. Kern
River and other parties filed their requests for rehearing of the initial order
on November 20, 2006. Kern River submitted its compliance filing, which
sets forth compliance rates in accordance with the initial order, on
December 18, 2006. A final order on the request for rehearing and
compliance filing is not expected until after the FERC finalizes its proposed
policy statement that addresses the inclusion of master limited partnerships in
the proxy group used to determine a pipeline’s allowed return on equity. Rate
refunds will be due within 30 days after a final order on Kern River’s rate case
is issued. Kern River was permitted to bill the requested rate increase prior to
final approval by the FERC, subject to refund, beginning effective
November 1, 2004. Since that time, Kern River has recorded a provision for
estimated refunds. As a result of the October 19, 2006 order, additional
customer billings and the accrual of interest, the liability for rates subject
to refund increased $78 million during 2006 to $107 million as of
December 31, 2006. As of December 31, 2007, the liability for rates
subject to refund was $191 million.
Oregon Senate Bill 408
In
October 2007, PacifiCorp filed its first tax report under Oregon Senate
Bill 408 (“SB 408”), which was enacted in September 2005.
SB 408 requires that PacifiCorp and other large regulated, investor-owned
utilities that provide electric or natural gas service to Oregon customers file
an annual tax report with the Oregon Public Utility Commission (“OPUC”).
PacifiCorp’s filing indicates that in 2006, PacifiCorp paid $33 million
more in federal, state and local taxes than was collected in rates from its
retail customers. PacifiCorp proposes to amortize $27 million of the
surcharge over a one year period, which would result in an average price
increase of 3%. If the OPUC issues an order providing for recovery in excess of
$27 million and allows the deferral of the excess, the portion not yet
recovered will be tracked in a balancing account accruing interest at
PacifiCorp’s weighted cost of capital. The deferred amount, if any, would be
addressed in a subsequent SB 408 filing. The 2006 tax report is currently
being challenged during the 180-day procedural schedule that follows the date of
the filing, with rates potentially effective June 2008. PacifiCorp expects
to file its 2007 tax report under SB 408 during the fourth quarter of 2008.
PacifiCorp has not recorded any amounts related to either the 2006 tax
report or the 2007 expected filing.
98
(7)
Investments
Investments
consist of the following as of December 31 (in millions):
Noncurrent
investments are included in deferred charges, investments and other assets in
the Consolidated Balance Sheets as management does not intend to use them in
current operations. Gross unrealized and realized gains and losses of
investments are not material as of December 31, 2007 and 2006 and for the
three years in the period ended December 31, 2007,
respectively.
In May
2005, certain indirect wholly owned subsidiaries of CE Electric UK
purchased £300 million of fixed rate guaranteed investment contracts
(£100 million at 4.75% and £200 million at 4.73%) with a portion of
the proceeds of the issuance of £350 million of 5.125% bonds due in 2035.
These guaranteed investment contracts matured in December 2007
(£100 million) and February 2008 (£200 million) and the proceeds were
used to repay certain long-term debt of subsidiaries of
CE Electric UK. The guaranteed investment contracts were reported at
cost.
MidAmerican
Energy has established trusts for the investment of funds for decommissioning
the Quad Cities Nuclear Station Units 1 and 2. These investments in debt and
equity securities are classified as available-for-sale and are reported at fair
value. Funds are invested in the trust in accordance with applicable federal
investment guidelines and are restricted for use as reimbursement for costs of
decommissioning the Quad Cities Station. As of December 31, 2007, 54% of
the fair value of the trusts’ funds was invested in domestic common equity
securities, 22% in domestic corporate debt securities and the remainder in
investment grade municipal and U.S. Treasury bonds. As of December 31,2006, 56% of the fair value of the trusts’ funds was invested in domestic common
equity securities, 13% in domestic corporate debt securities and the remainder
in investment grade municipal and U.S. Treasury bonds.
PacifiCorp
has established a trust for the investment of funds for final reclamation of a
leased coal mining property. These investments in debt and equity securities are
classified as available-for-sale and are reported at fair value. Amounts funded
are based on estimated future reclamation costs and estimated future coal
deliveries. As of December 31, 2007 and 2006, 52% and 56%, respectively, of
the fair value of the trust’s funds was invested in equity securities with the
remainder invested in debt securities.
The
Company has invested in AAA-rated interest bearing auction rate securities with
remaining maturities of 9 to 29 years. These auction rate securities normally
provide liquidity via an auction process that resets the applicable interest
rate at predetermined calendar intervals, usually every 28 days or less.
Interest on these securities has been paid on the scheduled auction dates.
During the third and fourth quarters of 2007, auctions for the $73 million
of the Company’s investments in auction rate securities failed. The failures
resulted in the interest rate on these investments resetting at higher levels.
Although there is no current liquid market for the auction rate securities, the
Company believes the underlying creditworthiness of the repayment sources for
these securities’ principal and interest has not materially deteriorated.
Therefore, the fair value of these investments approximates the carrying amount
as of December 31, 2007.
99
(8)
Short-Term
Borrowings
Short-term
borrowings consist of the following as of December 31 (in
millions):
2007
2006
MEHC
$
-
$
152
PacifiCorp
-
397
MidAmerican
Energy
86
-
CE
Electric UK
44
-
HomeServices
-
3
Total
short-term debt
$
130
$
552
MEHC
MEHC has
a $600 million unsecured credit facility expiring in July 2012. The credit
facility has a variable interest rate based on the London Interbank Offered Rate
(“LIBOR”) plus 0.195%, which varies based on MEHC’s credit ratings for its
senior unsecured long-term debt securities, or a base rate, at MEHC’s option.
The credit facility supports letters of credit for the benefit of certain
subsidiaries and affiliates. As of December 31, 2007, MEHC had no
borrowings outstanding under its credit facility and had letters of credit
issued under the credit agreement totaling $46 million. As of
December 31, 2006, the outstanding balance of the credit facility totaled
$152 million, at an interest rate of 5.57%, and letters of credit issued
under the credit agreement totaled $60 million. The related credit
agreement requires that MEHC’s ratio of consolidated debt to total
capitalization, including current maturities, not exceed 0.70 to 1.0 as of the
last day of any quarter.
PacifiCorp
At
December 31, 2007, PacifiCorp had $1.5 billion available under its
unsecured revolving credit facilities. During 2007, PacifiCorp entered into an
unsecured revolving credit facility with total bank commitments of
$700 million available through October 23, 2012. Under PacifiCorp’s
previously existing unsecured revolving credit facility, $800 million is
available through July 6, 2011 and $760 million is available from
July 7, 2011 through July 6, 2012. Each credit facility includes a
variable interest rate borrowing option based on LIBOR plus 0.195% that varies
based on PacifiCorp’s credit ratings for its senior unsecured long-term debt
securities and supports PacifiCorp’s commercial paper program. As of
December 31, 2007, PacifiCorp had no borrowings outstanding under either
credit facility. As of December 31, 2006, PacifiCorp had $397 million
of commercial paper arrangements outstanding at an average interest rate of 5.3%
and no borrowings outstanding under its revolving credit agreement. Each
revolving credit agreement requires that PacifiCorp’s ratio of consolidated debt
to total capitalization, including current maturities, at no time exceed 0.65 to
1.0.
MidAmerican
Energy
MidAmerican
Energy has a $500 million unsecured revolving credit facility expiring in
July 2012. The credit facility has a variable interest rate based on the
LIBOR plus 0.115% that varies based on MidAmerican Energy’s credit ratings for
its senior unsecured long-term debt securities and supports MidAmerican Energy’s
$380 million commercial paper program and its variable rate pollution
control revenue obligations. MidAmerican Energy had $86 million of
commercial paper arrangements outstanding as of December 31, 2007, at an
average rate of 4.46%, and no borrowings outstanding under its revolving credit
agreement as of December 31, 2007 and 2006. The related credit agreement
requires that MidAmerican Energy’s ratio of consolidated debt to total
capitalization, including current maturities, not exceed 0.65 to 1.0 as of the
last day of any quarter.
CE
Electric UK
CE
Electric UK has a £100 million unsecured revolving credit facility expiring
in April 2010. The facility carries a variable interest rate based on
sterling LIBOR plus 0.25% to 0.40% that varies based on its credit ratings. As
of December 31, 2007, the outstanding balance of the credit facility
totaled $44 million, at an interest rate of 5.961%, and there were no
borrowings outstanding under the facility as of December 31, 2006. The
related credit agreement requires that CE Electric UK’s ratio of
consolidated senior net debt to regulated asset value, including current
maturities, not exceed 0.8 to 1.0 at CE Electric UK and 0.65 to 1.0 at Northern
Electric and Yorkshire Electricity as of June 30 and December 31.
Additionally, CE Electric UK’s interest coverage ratio can not exceed 2.5 to
1.0.
100
CE
Electric UK also has a £15 million unsecured, uncommitted line of credit,
which was not drawn on as of December 31, 2007 and 2006. The interest rate
of this uncommitted line of credit as of December 31, 2007 is variable
based on sterling LIBOR plus 0.40%.
HomeServices
HomeServices
has a $125 million unsecured senior revolving credit facility expiring in
December 2010. The facility carries a variable interest rate based on
the prime lending rate or LIBOR, at HomeServices’ option, plus 0.5% to 1.125%,
that varies based on HomeServices’ total debt ratio. The spread was 0.5% as of
December 31, 2007 and 2006. As of December 31, 2007 and 2006 there
were no borrowings outstanding under the facility. The related credit agreement
requires that HomeServices’ ratio of consolidated total debt to earnings before
interest, taxes, depreciation and amortization (“EBITDA”) not exceed 3.0 to 1.0
at the end of any fiscal quarter and its ratio of EBITDA to interest can not be
less than 2.5 to 1.0 at the end of any fiscal quarter.
(9)
MEHC
Senior Debt
MEHC
senior debt represents unsecured senior obligations of MEHC and consists of the
following, including fair value adjustments and unamortized premiums and
discounts, as of December 31 (in millions):
Par
Value
2007
2006
4.625%
Senior Notes, due 2007
$
-
$
-
$
200
7.63%
Senior Notes, due 2007
-
-
350
3.50%
Senior Notes, due 2008
450
450
450
7.52%
Senior Notes, due 2008
550
550
547
5.875%
Senior Notes, due 2012
500
500
500
5.00%
Senior Notes, due 2014
250
250
250
8.48%
Senior Notes, due 2028
475
483
483
6.125%
Senior Notes, due 2036
1,700
1,699
1,699
5.95%
Senior Notes, due 2037
550
547
-
6.50%
Senior Notes, due 2037
1,000
992
-
Total
MEHC Senior Debt
$
5,475
$
5,471
$
4,479
(10)
MEHC
Subordinated Debt
MEHC
subordinated debt consists of the following, including fair value adjustments,
as of December 31 (in millions):
Par
Value
2007
2006
CalEnergy
Capital Trust II-6.25%, due 2012
$
105
$
96
$
94
CalEnergy
Capital Trust III-6.5%, due 2027
270
208
208
MidAmerican
Capital Trust I-11%, due 2010
227
227
318
MidAmerican
Capital Trust II-11%, due 2012
194
194
237
MidAmerican
Capital Trust III-11%, due 2011
400
400
500
Total
MEHC Subordinated Debt
$
1,196
$
1,125
$
1,357
The
Capital Trusts were formed for the purpose of issuing trust preferred securities
to holders and investing the proceeds received in subordinated debt issued by
MEHC. The terms of the MEHC subordinated debt are substantially identical to
those of the trust preferred securities. The MEHC subordinated debt associated
with the CalEnergy Trusts is callable at the option of MEHC at any time at par
value plus accrued interest. The MEHC subordinated debt associated with the
MidAmerican Capital Trusts is not callable by MEHC except upon the limited
occurrence of specified events. Distributions on the MEHC subordinated debt are
payable either quarterly or semi-annually, depending on the issue, in arrears,
and can be deferred at the option of MEHC for up to five years. During the
deferral period, interest continues to accrue on the CalEnergy Capital Trusts at
their stated rates, while interest accrues on the MidAmerican Capital Trusts at
13% per annum. The CalEnergy Capital Trust preferred securities are convertible
any time into cash at the option of the holder for an aggregate amount of
$284 million.
101
The
MidAmerican Capital Trusts preferred securities are held by Berkshire Hathaway
and its affiliates, which are prohibited from transferring the securities absent
an event of default to non-affiliated persons. Interest expense to Berkshire
Hathaway for the years ended December 31, 2007, 2006 and 2005 was
$108 million, $134 million and $157 million, respectively.
Interest expense on the CalEnergy Capital Trusts for the years ended
December 31, 2007, 2006 and 2005 was $28 million, $27 million and
$27 million, respectively.
The MEHC
subordinated debt is subordinated to all senior indebtedness of MEHC and is
subject to certain covenants, events of default and optional and mandatory
redemption provisions, all described in the indenture. Upon involuntary
liquidation, the holder is entitled to par value plus any distributions in
arrears. MEHC has agreed to pay to the holders of the trust preferred
securities, to the extent that the applicable Trust has funds available to make
such payments, quarterly distributions, redemption payments and liquidation
payments on the trust preferred securities.
(11)
Subsidiary
and Project Debt
MEHC’s
direct and indirect subsidiaries are organized as legal entities separate and
apart from MEHC and its other subsidiaries. Pursuant to separate financing
agreements, substantially all or most of the properties of each of the Company’s
subsidiaries (except CE Electric UK, all of MidAmerican Energy’s gas and
non-Iowa electric utility properties and Northern Natural Gas) are pledged or
encumbered to support or otherwise provide the security for their own project or
subsidiary debt. It should not be assumed that the assets of any subsidiary will
be available to satisfy MEHC’s obligations or the obligations of its other
subsidiaries. However, unrestricted cash or other assets which are available for
distribution may, subject to applicable law, regulatory commitments and the
terms of financing and ring-fencing arrangements for such parties, be advanced,
loaned, paid as dividends or otherwise distributed or contributed to MEHC or
affiliates thereof. The long-term debt of subsidiaries and projects may include
provisions that allow MEHC’s subsidiaries to redeem it in whole or in part at
any time. These provisions generally include make-whole premiums.
Distributions
at these separate legal entities are limited by various covenants including,
among others, leverage ratios, interest coverage ratios and debt service
coverage ratios. As of December 31, 2007, all subsidiaries were in
compliance with their covenants. However, Cordova Energy’s 537 MW gas-fired
power plant in the Quad Cities, Illinois area is currently prohibited from
making distributions by the terms of its indenture due to its failure to meet
its debt service coverage ratio requirement.
Long-term
debt of subsidiaries and projects consists of the following, including fair
value adjustments and unamortized premiums and discounts, as of December 31
(in millions):
Par
Value
2007
2006
PacifiCorp
$
5,173
$
5,167
$
4,131
MidAmerican
Funding
700
654
651
MidAmerican
Energy
2,477
2,471
1,821
Northern
Natural Gas
950
950
800
Kern
River
1,016
1,016
1,091
CE
Electric UK
2,403
2,562
2,776
CE
Casecnan
69
68
105
Leyte
Projects
-
-
19
Cordova
Funding
190
188
192
HomeServices
22
21
28
Total
Subsidiary and Project Debt
$
13,000
$
13,097
$
11,614
102
PacifiCorp
The
components of PacifiCorp’s long-term debt consist of the following, including
unamortized premiums and discounts, as of December 31 (dollars in
millions):
Par
Value
2007
2006
First
mortgage bonds:
4.3%
to 9.2%, due through 2012
$
1,169
$
1,169
$
1,294
5.0%
to 8.8%, due 2013 to 2017
442
441
441
8.1%
to 8.5%, due 2018 to 2022
175
175
175
6.7%
to 8.2%, due 2023 to 2026
249
249
249
7.7%
due 2031
300
299
299
5.3%
to 6.3%, due 2034 to 2037
2,050
2,047
847
Pollution-control
revenue obligations:
Variable
rate series (2007-3.5% to 3.8%, 2006-3.9% to 4.0%):
Due
2013, secured by first mortgage bonds(1)
41
41
41
Due
2014 to 2025(1)
325
325
325
Due
2024, secured by first mortgage bonds(1)
176
176
176
3.4%
to 5.7%, due 2014 to 2025, secured by first mortgage bonds
184
183
183
6.2%,
due 2030
13
13
13
Mandatorily
Redeemable Preferred Stock, due 2007
-
-
38
Capital
lease obligations - 10.4% to 14.8%, due through 2036
49
49
50
$
5,173
$
5,167
$
4,131
(1)
Interest
rates fluctuate based on various rates, primarily on certificate of
deposit rates, interbank borrowing rates, prime rates or other short-term
market rates.
As of
December 31, 2007, PacifiCorp had $518 million of standby letters of
credit and standby bond purchase agreements available to provide credit
enhancement and liquidity support for variable-rate pollution-control revenue
bond obligations.
MidAmerican
Funding
The
components of MidAmerican Funding’s senior notes and bonds consist of the
following, including fair value adjustments, as of December 31 (dollars in
millions):
Par
Value
2007
2006
6.339%
Senior Notes, due 2009
$
175
$
172
$
170
6.75%
Senior Notes, due 2011
200
200
200
6.927%
Senior Bonds, due 2029
325
282
281
Total
MidAmerican Funding
$
700
$
654
$
651
MidAmerican
Funding’s subsidiaries must make payments on their own indebtedness before
making distributions to MidAmerican Funding. The distributions are also subject
to utility regulatory restrictions agreed to by MidAmerican Energy in March
1999, whereby it committed to the IUB to use commercially reasonable efforts to
maintain an investment grade rating on its long-term debt and to maintain a
common equity to total capitalization ratio above 42%, except under
circumstances beyond its control. MidAmerican Energy’s common equity to total
capitalization ratio is not allowed to decline below 39% for any reason. If the
ratio declines below the defined threshold, MidAmerican Energy must seek the
approval of a reasonable utility capital structure from the IUB. MidAmerican
Energy’s ability to issue debt could also be restricted. As of December 31,2007, MidAmerican Energy’s common equity to total capitalization ratio, computed
on a basis consistent with the commitment, exceeded the minimum
threshold.
103
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, as of December 31 (dollars in millions):
Par
Value
2007
2006
Pollution
control revenue obligations:
6.10%
Series, due 2007
$
-
$
-
$
1
5.95%
Series, due 2023, secured by general mortgage bonds
29
29
29
Variable
rate series (2007-3.51%, 2006-3.97%):
Due
2016 and 2017
38
38
38
Due
2023, secured by general mortgage bonds
28
28
28
Due
2023
7
7
7
Due
2024
35
35
35
Due
2025
13
13
13
Notes:
5.65%
Series, due 2012
400
400
-
5.125%
Series, due 2013
275
275
274
4.65%
Series, due 2014
350
350
350
5.95%
Series, due 2017
250
249
-
6.75%
Series, due 2031
400
396
396
5.75%
Series, due 2035
300
300
300
5.80%
Series, due 2036
350
349
349
Other
2
2
1
Total
MidAmerican Energy
$
2,477
$
2,471
$
1,821
Northern
Natural Gas
The
components of Northern Natural Gas’ senior notes consist of the following,
including unamortized premiums and discounts, as of December 31 (dollars in
millions):
Par
Value
2007
2006
6.75%
Senior Notes, due 2008
$
150
$
150
$
150
7.00%
Senior Notes, due 2011
250
250
250
5.375%
Senior Notes, due 2012
300
300
300
5.125%
Senior Notes, due 2015
100
100
100
5.80%
Senior Notes, due 2037
150
150
-
Total
Northern Natural Gas
$
950
$
950
$
800
Kern
River
The
components of Kern River’s term notes are due in monthly installments and
consist of the following as of December 31 (dollars in
millions):
Par
Value
2007
2006
6.676%
Senior Notes, due 2016
$
361
$
361
$
389
4.893%
Senior Notes, due 2018
655
655
702
Total
Kern River
$
1,016
$
1,016
$
1,091
Kern
River provides a debt service reserve letter of credit in amounts equal to the
next six months of principal and interest payments due on the loans which were
equal to $64 million as of December 31, 2007 and 2006.
104
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, as of December 31 (dollars in millions):
Par
Value
2007
2006
6.995%
Senior Notes, due 2007
$
-
$
-
$
235
6.496%
Yankee Bonds, due 2008
281
281
281
8.875%
Bearer Bonds, due 2020(1)
198
232
231
9.25%
Eurobonds, due 2020(1)
397
481
482
7.25%
Sterling Bonds, due 2022(1)
397
425
417
7.25%
Eurobonds, due 2028(1)
368
388
384
5.125%
Bonds, due 2035(1)
397
391
389
5.125%
Bonds, due 2035(1)
297
296
292
CE
Gas Credit Facility, 7.94% and 7.62%(1)
68
68
65
Total
CE Electric UK
$
2,403
$
2,562
$
2,776
(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.
CE
Casecnan
CE
Casecnan Water and Energy Company, Inc. (“CE Casecnan”) has 11.95% Senior
Secured Series B Bonds, due in 2010 with a par value of $69 million. The
outstanding balance of these bonds, including fair value adjustments, as of
December 31, 2007 and 2006 was $68 million and $105 million,
respectively.
Cordova
Funding
Cordova
Funding Corporation’s (“Cordova Funding”) senior secured bonds are due in
semi-annual installments and consist of the following, including fair value
adjustments, as of December 31 (dollars in millions):
Par
Value
2007
2006
8.48%
- 9.07% Senior Secured Bonds, due 2019
$
190
$
188
$
192
MEHC has
issued a limited guarantee of a specified portion of the final scheduled
principal payment on December 15, 2019, on the Cordova Funding senior
secured bonds in an amount up to a maximum of $37 million.
HomeServices
The
components of HomeServices’ long-term debt consist of the following, including
fair value adjustments, as of December 31 (dollars in
millions):
Par
Value
2007
2006
7.12%
Senior Notes, due 2010
$
15
$
14
$
19
Other
7
7
9
Total
HomeServices
$
22
$
21
$
28
105
Annual
Repayments of Long-Term Debt
The
annual repayments of MEHC and subsidiary and project debt for the years
beginning January 1, 2008 and thereafter, excluding fair value adjustments
and unamortized premiums and discounts, are as follows (in
millions):
2008
2009
2010
2011
2012
Thereafter
Total
MEHC
senior debt
$
1,000
$
-
$
-
$
-
$
500
$
3,975
$
5,475
MEHC
subordinated debt
234
234
189
143
126
270
1,196
PacifiCorp
414
140
17
589
19
3,994
5,173
MidAmerican
Funding
-
175
-
200
-
325
700
MidAmerican
Energy
1
-
-
-
400
2,076
2,477
Northern
Natural Gas
150
-
-
250
300
250
950
Kern
River
73
75
79
81
81
627
1,016
CE
Electric UK
281
-
13
9
46
2,054
2,403
CE
Casecnan
38
14
17
-
-
-
69
Cordova
Funding
4
6
9
9
10
152
190
HomeServices
5
11
5
-
-
1
22
Totals
$
2,200
$
655
$
329
$
1,281
$
1,482
$
13,724
$
19,671
(12)
Asset
Retirement Obligations
The
Company estimates its ARO liabilities based upon detailed engineering
calculations of the amount and timing of the future cash spending for a third
party to perform the required work. Spending estimates are escalated for
inflation and then discounted at a credit-adjusted, risk-free rate. Changes in
estimates could occur for a number of reasons including plan revisions,
inflation and changes in the amount and timing of expected work. The change in
the balance of the total ARO liability, which is included in other long-term
accrued liabilities in the Consolidated Balance Sheets, is summarized as follows
(in millions):
2007
2006
Balance,
January 1
$
423
$
208
PacifiCorp
acquisition
-
212
Revisions
19
(17
)
Additions
6
4
Retirements
(49
)
(5
)
Accretion
23
21
Balance,
December 31
$
422
$
423
PacifiCorp’s
coal mining operations are subject to the Surface Mining Control and Reclamation
Act of 1977 and similar state statutes that establish operational, reclamation
and closure standards that must be met during and upon completion of mining
activities. These statutes mandate that mine property be restored consistent
with specific standards and the approved reclamation plan. PacifiCorp is
incurring expenditures for both ongoing and final reclamation. The fair value of
PacifiCorp’s estimated mine reclamation costs, principally the Jim Bridger mine,
was $115 million and $141 million as of December 31, 2007 and
2006, respectively, and is the asset retirement obligation for these mines.
PacifiCorp has established trusts for the investment of funds for the Jim
Bridger mine. The fair value of the assets held in trusts was $117 million
and $110 million as of December 31, 2007 and 2006, respectively, and
is reflected in other current assets and deferred charges, investments and other
assets in the Consolidated Balance Sheets.
106
The
Nuclear Regulatory Commission (“NRC”) regulates the decommissioning of nuclear
power plants, which includes the planning and funding for the decommissioning.
In accordance with these regulations, MidAmerican Energy submits a biennial
report to the NRC providing reasonable assurance that funds will be available to
pay for its share of the Quad Cities Station decommissioning. The
decommissioning costs are included in base rates in MidAmerican Energy’s Iowa
tariffs. The fair value of MidAmerican Energy’s share of estimated Quad Cities
Station decommissioning costs was $150 million and $142 million as of
December 31, 2007 and 2006, respectively, and is the asset retirement
obligation for the Quad Cities Station. MidAmerican Energy has established
trusts for the investment of decommissioning funds. The fair value of the assets
held in the trusts was $276 million and $259 million as of
December 31, 2007 and 2006, respectively, and is reflected in deferred
charges, investments and other assets in the Consolidated Balance
Sheets.
In
addition to the ARO liabilities, the Company has accrued for the cost of
removing other electric and gas assets through its depreciation rates, in
accordance with accepted regulatory practices. These accruals are reflected as
regulatory liabilities and total $1.20 billion and $1.16 billion as of
December 31, 2007 and 2006, respectively.
The total
outstanding preferred stock of PacifiCorp, which does not have mandatory
redemption requirements, was $41 million as of December 31, 2007 and
2006. Generally, this preferred stock is redeemable at stipulated prices plus
accrued dividends, subject to certain restrictions. In the event of voluntary
liquidation, all preferred stock is entitled to stated value or a specified
preference amount per share plus accrued dividends. Upon involuntary
liquidation, all preferred stock is entitled to stated value plus accrued
dividends. Dividends on all preferred stock are cumulative. Holders also have
the right to elect members to the PacifiCorp board of directors in the event
dividends payable are in default in an amount equal to four full quarterly
payments.
The total
outstanding cumulative preferred securities of MidAmerican Energy are not
subject to mandatory redemption requirements and may be redeemed at the option
of MidAmerican Energy at prices which, in the aggregate, total $31 million.
The aggregate total the holders of all preferred securities outstanding as of
December 31, 2007 and 2006, are entitled to upon involuntary bankruptcy is
$30 million plus accrued dividends.
The total
outstanding 8.061% cumulative preferred securities of a subsidiary of CE
Electric UK, which are redeemable in the event of the revocation of the
subsidiary’s electricity distribution license by the Secretary of State, was
$56 million as of December 31, 2007 and 2006.
(14)
Risk
Management and Hedging Activities
The
Company is exposed to the impact of market fluctuations in commodity prices,
principally natural gas and electricity, particularly through its ownership of
PacifiCorp and MidAmerican Energy. Interest rate risk exists on variable rate
debt, commercial paper and future debt issuances. The Company is also exposed to
foreign currency risk primarily due to its business operations and investments
in Great Britain. The Company employs established policies and procedures to
manage its risks associated with these market fluctuations using various
commodity and financial derivative instruments, including forward contracts,
futures, options, swaps and other over-the-counter agreements. The risk
management process established by each business platform is designed to
identify, assess, monitor, report, manage, and mitigate each of the various
types of risk involved in its business. The Company does not engage in a
material amount of proprietary trading activities.
107
The
following table summarizes the various derivative mark-to-market positions
included in the Consolidated Balance Sheet as of December 31, 2007 (in
millions):
Accumulated
Regulatory
Other
Derivative
Net Assets (Liabilities)
Net
Assets
Comprehensive
Assets
Liabilities
Total
(Liabilities)
(Income)
Loss(1)
Commodity
$
396
$
(659
)
$
(263
)
$
277
$
(15
)
Foreign
currency
1
(106
)
(105
)
(1
)
106
$
397
$
(765
)
$
(368
)
$
276
$
91
Current
$
170
$
(266
)
$
(96
)
Non-current
227
(499
)
(272
)
Total
$
397
$
(765
)
$
(368
)
(1)
Before
income taxes.
The
following table summarizes the various derivative mark-to-market positions
included in the Consolidated Balance Sheet as of December 31, 2006 (in
millions):
Accumulated
Regulatory
Other
Derivative
Net Assets (Liabilities)
Net
Assets
Comprehensive
Assets
Liabilities
Total
(Liabilities)
(Income)
Loss(1)
Commodity
$
467
$
(740
)
$
(273
)
$
247
$
6
Interest
rate
13
-
13
-
(13
)
Foreign
currency
4
(149
)
(145
)
(3
)
149
$
484
$
(889
)
$
(405
)
$
244
$
142
Current
$
236
$
(271
)
$
(35
)
Non-current
248
(618
)
(370
)
Total
$
484
$
(889
)
$
(405
)
(1)
Before income
taxes.
Commodity
Price Risk
The
Company is subject to significant commodity risk particularly through its
ownership of PacifiCorp and MidAmerican Energy. Exposures include variations in
the price of wholesale electricity that is purchased and sold, fuel costs to
generate electricity, and natural gas supply for regulated retail gas customers.
Electricity and natural gas prices are subject to wide price swings as demand
responds to, among many other items, changing weather, limited storage,
transmission and transportation constraints, and lack of alternative supplies
from other areas. To mitigate a portion of the risk, the Company uses derivative
instruments, including forwards, futures, options, swap and other
over-the-counter agreements, to effectively secure future supply or sell future
production at fixed prices. The settled cost of these contracts is generally
recovered from customers in regulated rates. Accordingly, the net unrealized
gains and losses associated with interim price movements on contracts that are
accounted for as derivatives, that are probable of recovery in rates, are
recorded as regulatory net assets or liabilities.
MidAmerican
Energy also uses futures, options and swap agreements to economically hedge gas
commodity prices for physical delivery to nonregulated customers. MidAmerican
Energy also enters into forward physical supply contracts and swap agreements to
economically hedge electricity commodity prices for physical delivery to
nonregulated customers. Nonregulated retail physical electricity contracts are
considered normal purchases or sales and gains and losses on such contracts are
recognized when settled. All other nonregulated gas and electric contracts are
recorded at fair value.
108
Other
MEHC subsidiaries use derivative instruments such as swaps, future, forwards and
options principally as cash flow hedges for spring operational sales, natural
gas storage and other transactions. During 2006, CE Gas recognized
$14 million of unrealized losses on derivative contracts that became
ineffective due to its inability to effectively forecast the associated hedged
transactions.
Realized
gains and losses on all hedges and hedge ineffectiveness are recognized in
income as operating revenue, cost of sales or operating expenses depending upon
the nature of the item being hedged. Net unrealized gains and losses on hedges
utilized for regulatory purposes are generally recorded as regulatory assets and
liabilities. As of December 31, 2007, the Company had cash flow hedges with
expiration dates through October 2013. For the year ended December 31,2007, hedge ineffectiveness was insignificant. As of December 31, 2007,
$4 million of pre-tax net unrealized gains are forecasted to be
reclassified from AOCI into earnings over the next twelve months as contracts
settle.
Foreign
Currency Risk
MEHC
selectively reduces its foreign currency risk by hedging through foreign
currency derivatives. CE Electric UK has entered into certain currency rate swap
agreements with large multi-national financial institutions for its U.S. dollar
denominated senior notes and Yankee bonds. As of December 31, 2006, the
swap agreements effectively converted the U.S. dollar fixed interest rate to a
fixed rate in sterling for $237 million of 6.995% senior notes and
$281 million of 6.496% Yankee bonds outstanding. The swap agreement for
$237 million of senior notes expired with the maturity of the senior notes
on December 30, 2007, and the swap agreement for $281 million of
Yankee bonds expired with the maturity of the Yankee bonds on February 25,2008. The estimated fair value of these swap agreements as of December 31,2007 and 2006 was a liability of $106 million and $149 million,
respectively, based on quotes from the counterparties to these instruments and
represents the estimated amount that the Company would expect to pay if these
agreements were terminated.
Interest
Rate Risk
The
Company may enter into contractual agreements to hedge exposure to interest rate
risk. In September 2006, MEHC entered into a treasury rate lock agreement in the
notional amount of $1.55 billion to protect against an increase in interest
rates on future long-term debt issuances. As of December 31, 2006, the fair
value of the treasury rate lock agreement was $12 million. The financings
occurred on May 11, 2007 and August 28, 2007, and MEHC received a
total of $32 million, which is being amortized as a reduction to interest
expense over the term of the related financings. In May 2005, MEHC entered into
a treasury rate lock agreement in the notional amount of $1.6 billion to
protect against an increase in interest rates on future long-term debt
issuances. The financing occurred on March 24, 2006 and MEHC received
$53 million, which is being amortized as a reduction to interest expense
over the term of the related financing.
(15)
Income
Taxes
Income
tax expense on continuing operations consists of the following for the years
ended December 31 (in millions):
2007
2006
2005
Current:
Federal
$
147
$
6
$
36
State
38
5
5
Foreign
141
135
74
326
146
115
Deferred:
Federal
188
249
57
State
(6
)
-
10
Foreign
(41
)
21
67
141
270
134
Investment
tax credit, net
(11
)
(9
)
(4
)
Total
$
456
$
407
$
245
109
A
reconciliation of the federal statutory tax rate to the effective tax rate on
continuing operations applicable to income before income tax expense for the
years ended December 31 follows:
2007
2006
2005
Federal
statutory rate
35
%
35
%
35
%
General
business tax credits
(3
)
(3
)
(2
)
State
taxes, net of federal tax effect
2
2
2
Equity
income, net of dividends received deduction
-
-
1
Tax
effect of foreign income
(2
)
(2
)
(2
)
Change
in UK corporate income tax rate
(4
)
-
-
Effects
of ratemaking
-
1
(1
)
Other
items, net
-
(2
)
(1
)
Effective
tax rate
28
%
31
%
32
%
In 2007,
the Company recognized $58 million of deferred income tax benefits upon the
enactment of the reduction in the United Kingdom corporate income tax rate from
30% to 28% to be effective April 1, 2008.
The net
deferred tax liability consists of the following as of December 31 (in
millions):
2007
2006
Deferred
tax assets:
Regulatory
liabilities
$
473
$
452
Employee
benefits
161
362
Accruals
not currently deductible for tax purposes
154
141
Net
operating loss (“NOL”) and credit carryforwards
130
201
Revenue
subject to refund
72
41
Uncertain
tax positions
32
-
Nuclear
reserve and decommissioning
24
23
Revenue
sharing accruals
8
110
Other
223
172
Total
deferred tax assets
1,277
1,502
Valuation
allowance
(12
)
(20
)
Total
deferred tax assets, net
1,265
1,482
Deferred
tax liabilities:
Property,
plant and equipment, net
(3,654
)
(3,562
)
Regulatory
assets
(984
)
(1,095
)
Other
(60
)
(122
)
Total
deferred tax liabilities
(4,698
)
(4,779
)
Net
deferred tax liability
$
(3,433
)
$
(3,297
)
Reflected
as:
Deferred
income taxes-current asset
$
162
$
152
Deferred
income taxes-non-current liability
(3,595
)
(3,449
)
$
(3,433
)
$
(3,297
)
As of
December 31, 2007, the Company has available unused NOL and credit
carryforwards that may be applied against future taxable income and that expire
at various intervals between 2008 and 2027.
The
Company adopted FIN 48 effective January 1, 2007 and had $117 million
of net unrecognized tax benefits. Of this amount, the Company recognized a net
increase in the liability for unrecognized tax benefits of $22 million as a
cumulative effect of adopting FIN 48, which was offset by reductions in
beginning retained earnings of $5 million, deferred income tax liabilities
of $31 million and goodwill of $15 million and an increase in
regulatory assets of $1 million in the Consolidated Balance Sheet. The
remaining $95 million had been previously accrued under SFAS No. 5,
“Accounting for Contingencies,” or SFAS No. 109, “Accounting for Income
Taxes.”
110
As of
December 31, 2007, net unrecognized tax benefits totaled $127 million
which included $104 million of tax positions that, if recognized, would have an
impact on the effective tax rate. The remaining unrecognized tax benefits relate
to positions for which ultimate deductibility is highly certain but for which
there is uncertainty as to the timing of such deductibility and tax positions
related to acquired companies. Recognition of these tax benefits, other than
applicable interest and penalties, would not affect the Company’s effective tax
rate.
(16)
Other
Income and Expense
Other
Income
Other
income, as shown on the Consolidated Statements of Operations, for the years
ending December 31 consists of the following (in millions):
2007
2006
2005
Gain
on Mirant bankruptcy claim
$
3
$
89
$
-
Allowance
for equity funds used during construction
85
57
26
Gains
on sales of non-strategic assets and investments
1
55
23
Corporate-owned
life insurance income
12
13
5
Other
21
25
21
Total
other income
$
122
$
239
$
75
Gain
on Mirant Americas Energy Marketing (“Mirant”) Bankruptcy Claim
Mirant
was one of the shippers that entered into a 15-year, 2003 Expansion Project,
firm gas transportation contract with Kern River (the “Mirant Agreement”) and
provided a letter of credit equivalent to 12 months of reservation charges as
security for its obligations thereunder. In July 2003, Mirant filed for Chapter
11 bankruptcy protection. Kern River claimed $210 million in damages due to
the rejection of the Mirant Agreement. The bankruptcy court ultimately
determined that Kern River was entitled to a general unsecured claim of
$74 million in addition to $15 million of cash collateral. In January
2006, Mirant emerged from bankruptcy. In February 2006, Kern River received
an initial distribution of such shares in payment of the majority of its allowed
claim. Kern River sold all of the shares of new Mirant stock received from its
allowed claim amount plus interest in the first quarter of 2006 and recognized a
gain from those sales of $89 million.
(17)
Shareholders’
Equity
Preferred
Stock
As of
December 31, 2005, Berkshire Hathaway owned 41,263,395 shares of MEHC’s no
par zero-coupon convertible preferred stock. Each share of preferred stock was
convertible at the option of the holder into one share of MEHC’s common stock
subject to certain adjustments as described in MEHC’s Amended and Restated
Articles of Incorporation. The convertible preferred stock was convertible into
common stock only upon the occurrence of specified events, including
modification or elimination of the Public Utility Holding Company Act of 1935
(“PUHCA 1935”) so that holding company registration would not be triggered by
conversion. On February 9, 2006, following the effective date of the repeal
of the Public Utility Holding Company Act of 1935, Berkshire Hathaway converted
its 41,263,395 shares of MEHC’s no par zero-coupon convertible preferred
stock into an equal number of shares of MEHC’s common stock.
Common
Stock
On
March 14, 2000, and as amended on December 7, 2005, MEHC’s
shareholders entered into a Shareholder Agreement that provides specific rights
to certain shareholders. One of these rights allows certain shareholders the
ability to put their common shares back to MEHC at the then current fair value
dependent on certain circumstances controlled by MEHC.
111
On
March 1, 2006, MEHC and Berkshire Hathaway entered into an Equity
Commitment Agreement (the “Berkshire Equity Commitment”) pursuant to which
Berkshire Hathaway has agreed to purchase up to $3.5 billion of common
equity of MEHC upon any requests authorized from time to time by the Board of
Directors of MEHC. The proceeds of any such equity contribution shall only be
used for the purpose of (a) paying when due MEHC’s debt obligations and (b)
funding the general corporate purposes and capital requirements of the Company’s
regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any
such request. The Berkshire Equity Commitment will expire on
February 28, 2011.
On
March 2, 2006, MEHC amended its Articles of Incorporation to (i) increase
the amount of its common stock authorized for issuance to
115,000,000 shares and (ii) no longer provide for the authorization to
issue any preferred stock of MEHC.
In
March 2006, MEHC repurchased 12,068,412 shares of common stock for an
aggregate purchase price of $1.75 billion.
On
March 21, 2006, Berkshire Hathaway and certain other of MEHC’s existing
shareholders and related companies invested $5.11 billion, in the
aggregate, in 35,237,931 shares of MEHC’s common stock in order to provide
equity funding for the PacifiCorp acquisition (see Note 3). The per-share value
assigned to the shares of common stock issued, which were effected pursuant to a
private placement and were exempt from the registration requirements of the
Securities Act of 1933, as amended, was based on an assumed fair market value as
agreed to by MEHC’s shareholders.
Common
Stock Options
There
were no common stock options granted, forfeited or that expired during each of
the three years in the period ended December 31, 2007. There were 370,000
common stock options exercised during the year ended December 31, 2007
having a weighted-average exercise price of $26.99 per share. There were
703,329 common stock options outstanding and exercisable with an exercise
price of $35.05 per share and a remaining contractual life of
2.25 years as of December 31, 2007.
There
were 775,000 common stock options exercised during the year ended
December 31, 2006 having a weighted-average exercise price of $28.65 per
share. There were 1,073,329 common stock options outstanding and exercisable
with a weighted-average exercise price of $32.27 per share as of
December 31, 2006. As of December 31, 2006, 370,000 of the outstanding
and exercisable common stock options had exercise prices ranging from $24.22 to
$34.69 per share, a weighted-average exercise price of $26.99 per share and a
remaining contractual life of 1.25 years. The remaining 703,329 outstanding and
exercisable common stock options had an exercise price of $35.05 per share and a
remaining contractual life of 3.25 years.
There
were 200,000 common stock options exercised during the year ended
December 31, 2005 having an exercise price of $29.01 per share. There were
1,848,329 common stock options outstanding and exercisable with a
weighted-average exercise price of $30.75 per share as of December 31,2005. 1,145,000 of the outstanding and exercisable common stock options had
exercise prices ranging from $15.94 to $34.69 per share, a weighted-average
exercise price of $28.11 per share and a remaining contractual life of 2.25
years. The remaining 703,329 outstanding and exercisable common stock
options had an exercise price of $35.05 per share and a remaining contractual
life of 4.25 years. There were 2,048,329 common stock options outstanding and
exercisable with a weighted-average exercise price of $30.58 per share as of
December 31, 2004.
(18)
Commitments
and Contingencies
Environmental
Matters
The
Company is subject to federal, state, local and foreign laws and regulations
regarding air and water quality, hazardous and solid waste disposal and other
environmental matters and believes it is in material compliance with current
environmental requirements.
112
Air
Quality
Litigation
was filed in the federal district court for the southern district of New York
seeking to require reductions of carbon dioxide emissions from generating
facilities of five large electric utilities. The court dismissed the suit,
ruling that critical issues affecting the United States, like greenhouse gas
emissions reductions, are not the domain of the courts and should be resolved by
the executive branch of the federal government and the U.S. Congress. This
ruling has been appealed to the Second Circuit Court of Appeals. The outcome of
climate change litigation and federal and state climate change initiatives
cannot be determined at this time; however, adoption of stringent limits on
greenhouse gas emissions could significantly impact the Company’s fossil-fueled
facilities and, therefore, its financial results.
The
Environmental Protection Agency’s regulation of certain pollutants under the
Clean Air Act, and its failure to regulate other pollutants, is being challenged
by various lawsuits brought by both individual state attorney generals and
environmental groups. To the extent that these actions may be successful in
imposing additional and/or more stringent regulation of emissions on
fossil-fueled facilities in general and PacifiCorp’s and MidAmerican Energy’s
facilities in particular, such actions could significantly impact the Company’s
fossil-fueled facilities and, therefore, its financial results.
Accrued
Environmental Costs
The
Company is fully or partly responsible for environmental remediation that
results from other than normal operations at various contaminated sites,
including sites that are or were part of the Company’s operations and sites
owned by third parties. The Company accrues environmental remediation expenses
when the expense is believed to be probable and can be reasonably estimated. The
quantification of environmental exposures is based on many factors, including
changing laws and regulations, advancements in environmental technologies, the
quality of available site-specific information, site investigation results,
expected remediation or settlement timelines, the Company’s proportionate
responsibility, contractual indemnities and coverage provided by insurance
policies. The liability recorded as of December 31, 2007 and 2006 was
$38 million and $50 million, respectively, and is included in other
liabilities and other long-term accrued liabilities on the Consolidated Balance
Sheets. Environmental remediation liabilities that result from the normal
operation of a long-lived asset and that are associated with the retirement of
those assets is accounted for as an asset retirement obligation.
Hydroelectric
Relicensing
PacifiCorp’s
hydroelectric portfolio consists of 47 plants with an aggregate facility net
owned capacity of 1,158 MW. The FERC regulates 98% of the net capacity of
this portfolio through 16 individual licenses. Several of PacifiCorp’s
hydroelectric plants are in some stage of relicensing with the FERC.
Hydroelectric relicensing and the related environmental compliance requirements
and litigation are subject to uncertainties. PacifiCorp expects that future
costs relating to these matters may be significant and will consist primarily of
additional relicensing costs, operations and maintenance expense, and capital
expenditures. Electricity generation reductions may result from the additional
environmental requirements. PacifiCorp had incurred $89 million and
$79 million in costs as of December 31, 2007 and 2006, respectively,
for ongoing hydroelectric relicensing, which are included in construction in
progress and reflected in property, plant and equipment, net in the Consolidated
Balance Sheet.
In
February 2004, PacifiCorp filed with the FERC a final application for a new
license to operate the 169 MW (nameplate rating) Klamath hydroelectric
project in anticipation of the March 2006 expiration of the existing license.
PacifiCorp is currently operating under an annual license issued by the FERC and
expects to continue to operate under annual licenses until the new operating
license is issued. As part of the relicensing process, the United States
Departments of Interior and Commerce filed proposed licensing terms and
conditions with the FERC in March 2006, which proposed that PacifiCorp construct
upstream and downstream fish passage facilities at the Klamath hydroelectric
project’s four mainstem dams. In April 2006, PacifiCorp filed alternatives to
the federal agencies’ proposal and requested an administrative hearing to
challenge some of the federal agencies’ factual assumptions supporting their
proposal for the construction of the fish passage facilities. A hearing was held
in August 2006 before an administrative law judge. The administrative law judge
issued a ruling in September 2006 generally supporting the federal agencies’
factual assumptions. In January 2007, the United States Departments of Interior
and Commerce filed modified terms and conditions consistent with March 2006
filings and rejected the alternatives proposed by PacifiCorp. PacifiCorp is
prepared to meet and implement the federal agencies’ terms and conditions as
part of the project’s relicensing. However, PacifiCorp expects to continue in
settlement discussions with various parties in the Klamath Basin area who have
intervened with the FERC licensing proceeding to try to achieve a mutually
acceptable outcome for the project.
113
Also, as
part of the relicensing process, the FERC is required to perform an
environmental review. In September 2006, the FERC issued its draft environmental
impact statement on the Klamath hydroelectric project license. PacifiCorp filed
comments on the draft statement by the close of the public comment period on
December 1, 2006. Subsequently, in November 2007, the FERC issued its
final environmental impact statement. The United States Fish and Wildlife
Service and the National Marine Fisheries Service issued final biological
opinions in December 2007 analyzing the hydroelectric project’s impact on
endangered species under the proposed new FERC license. The United States Fish
and Wildlife Service asserts the hydroelectric project is currently not covered
by previously issued biological opinions, and that consultation under the
Endangered Species Act is required by the issuance of annual license renewals.
PacifiCorp disputes these assertions, and believes federal case law is clear
that consultation on annual FERC licenses is not required. PacifiCorp will need
to obtain water quality certifications from Oregon and California prior to the
FERC issuing a final license. PacifiCorp currently has applications pending
before each state.
In the
relicensing of the Klamath hydroelectric project, PacifiCorp had incurred
$48 million and $42 million in costs as of December 31, 2007 and
2006, respectively, which are included in construction in progress and reflected
in property, plant and equipment, net in the Consolidated Balance Sheets. While
the costs of implementing new license provisions cannot be determined until such
time as a new license is issued, such costs could be material.
Legal
Matters
The
Company is party in a variety of legal actions arising out of the normal course
of business. Plaintiffs occasionally seek punitive or exemplary damages. The
Company does not believe that such normal and routine litigation will have a
material effect on its consolidated financial results. The Company is also
involved in other kinds of legal actions, some of which assert or may assert
claims or seek to impose fines and penalties in substantial amounts and are
described below.
PacifiCorp
In
February 2007, the Sierra Club and the Wyoming Outdoor Council filed a
compliant against PacifiCorp in the federal district court in Cheyenne, Wyoming,
alleging violations of the Wyoming state opacity standards at PacifiCorp’s Jim
Bridger plant in Wyoming. Under Wyoming state requirements, which are part of
the Jim Bridger plant’s Title V permit and are enforceable by private citizens
under the federal Clean Air Act, a potential source of pollutants such as a
coal-fired generating facility must meet minimum standards for opacity, which is
a measurement of light that is obscured in the flue of a generating facility.
The complaint alleges thousands of violations of asserted six-minute compliance
periods and seeks an injunction ordering the Jim Bridger plant’s compliance with
opacity limits, civil penalties of $32,500 per day per violation, and the
plaintiffs’ costs of litigation. The court granted a motion to bifurcate the
trial into separate liability and remedy phases. A five-day trial on the
liability phase is scheduled to begin on April 2008. The remedy-phase trail
has not yet been set. PacifiCorp believes it has a number of defenses to the
claims. PacifiCorp intends to vigorously oppose the lawsuit but cannot predict
its outcome at this time. PacifiCorp has already committed to invest at least
$812 million in pollution control equipment at its generating facilities,
including the Jim Bridger plant. This commitment is expected to significantly
reduce system-wide emissions, including emissions at the Jim Bridger
plant.
CalEnergy
Generation-Foreign
Pursuant
to the share ownership adjustment mechanism in the CE Casecnan shareholder
agreement, which is based upon proforma financial projections of the Casecnan
Project prepared following commencement of commercial operations, in
February 2002, MEHC’s indirect wholly owned subsidiary,
CE Casecnan Ltd., advised the minority shareholder of
CE Casecnan, LaPrairie Group Contractors (International) Ltd. (“LPG”), that
MEHC’s indirect ownership interest in CE Casecnan had increased to 100%
effective from commencement of commercial operations. On July 8, 2002, LPG
filed a complaint in the Superior Court of the State of California, City and
County of San Francisco against CE Casecnan Ltd. and MEHC. LPG’s complaint,
as amended, seeks compensatory and punitive damages arising out of
CE Casecnan Ltd.’s and MEHC’s alleged improper calculation of the proforma
financial projections and alleged improper settlement of the NIA
arbitration.
114
On
February 21, 2007, the appellate court issued a decision, and as a result
of the decision, CE Casecnan Ltd. determined that LPG would retain ownership of
10% of the shares of CE Casecnan, with the remaining 5% ownership being
transferred to CE Casecnan Ltd. subject to certain buy-up rights under the
shareholder agreement. At a hearing on October 10, 2007, the court
determined that LPG was ready, willing and able to exercise its buy-up rights in
2007. Additional hearings were held on October 23 and 24, 2007, regarding
the issue of the buy-up price calculation and a written decision was issued on
February 4, 2008 specifying the method for determining LPG’s buy-up price.
A final judgment has not been issued on the buy-up right and price and when
issued will be subject to appeal. LPG waived its request for a jury trial for
the breach of fiduciary duty claim and the parties have entered into a
stipulation which provides for a trial of such claim by the court based on the
existing record of the case. The trial date has been set for March 12,2008. The Company intends to vigorously defend and pursue the remaining
claims.
In
February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. (“San
Lorenzo”), an original shareholder substantially all of whose shares in
CE Casecnan were purchased by MEHC in 1998, threatened to initiate legal
action against the Company in the Philippines in connection with certain aspects
of its option to repurchase such shares. The Company believes that San Lorenzo
has no valid basis for any claim and, if named as a defendant in any action that
may be commenced by San Lorenzo, the Company will vigorously defend such action.
On July 1, 2005, MEHC and CE Casecnan Ltd. commenced an action against
San Lorenzo in the District Court of Douglas County, Nebraska, seeking a
declaratory judgment as to MEHC’s and CE Casecnan Ltd.’s rights vis-à-vis
San Lorenzo in respect of such shares. San Lorenzo filed a motion to dismiss on
September 19, 2005. Subsequently, San Lorenzo purported to exercise its
option to repurchase such shares. On January 30, 2006, San Lorenzo filed a
counterclaim against MEHC and CE Casecnan Ltd. seeking declaratory relief
that it has effectively exercised its option to purchase 15% of the shares of
CE Cascenan, that it is the rightful owner of such shares and that it is
due all dividends paid on such shares. On March 9, 2006, the court granted
San Lorenzo’s motion to dismiss, but has since permitted MEHC and
CE Casecnan Ltd. to file an amended complaint incorporating the purported
exercise of the option. The complaint has been amended and the action is
proceeding. Currently, the action is in the discovery phase and a one-week trial
has been set to begin on November 3, 2008. The impact, if any, of San
Lorenzo’s purported exercise of its option and the Nebraska litigation on the
Company cannot be determined at this time. The Company intends to vigorously
defend the counterclaims.
Unconditional
Purchase Obligations
The
Company has the following unconditional purchase obligations as of
December 31, 2007 (in millions) which are not reflected in the Consolidated
Balance Sheet:
Coal,
Electricity and Natural Gas Contract Commitments
PacifiCorp
and MidAmerican Energy have fuel supply and related transportation contracts for
their coal-fired and gas generating stations. PacifiCorp and MidAmerican Energy
expect to supplement these contracts with additional contracts and spot market
purchases to fulfill their future fossil fuel needs. PacifiCorp and MidAmerican
Energy acquire a portion of their electricity through long-term purchases and/or
exchange agreements. Included in the purchased electricity payments are any
power purchase agreements that meet the definition of an operating
lease.
115
Purchase
obligations
The
Company has purchase obligations for an ongoing construction program to meet
increased electricity usage, customer growth and system reliability objectives.
Additionally, the Company has various other purchase obligations that are
non-cancelable or cancelable only under certain conditions related to equipment
maintenance and various other service and maintenance agreements.
Owned
Hydroelectric Commitments
As part
of the hydroelectric relicensing process, PacifiCorp entered into settlement
agreements with various interested parties that resulted in commitments for
environmental mitigation and enhancement measures over the life of the
licenses.
Operating
Leases, Easements and Maintenance Contracts
The
Company has non-cancelable operating leases primarily for computer equipment,
office space, certain operating facilities, land and rail cars. These leases
generally require the Company to pay for insurance, taxes and maintenance
applicable to the leased property. Certain leases contain renewal options for
varying periods and escalation clauses for adjusting rent to reflect changes in
price indices. The Company also has non-cancelable easements for land on which
its wind-farm turbines are located, as well as non-cancelable maintenance
contracts for the turbines. Rent expense on non-cancelable operating leases
totaled $122 million for 2007, $117 million for 2006 and
$79 million for 2005.
Guarantees
The
Company has entered into guarantees as part of the normal course of business and
the sale of certain assets. These guarantees are not expected to have a material
impact on the Company’s consolidated financial results. The Company is generally
required to obtain state regulatory commission approval prior to guaranteeing
debt or obligations of other parties. The following represent the material
indemnification obligations of the Company as of December 31,2007.
PacifiCorp
PacifiCorp
has made certain commitments related to the decommissioning or reclamation of
certain jointly owned facilities and mine sites. The decommissioning commitments
require PacifiCorp to pay a proportionate share of the decommissioning costs
based upon percentage of ownership. The mine reclamation commitments require
PacifiCorp to pay the mining entity a proportionate share of the mine’s
reclamation costs based on the amount of coal purchased by PacifiCorp. In the
event of default by any of the other joint participants, PacifiCorp potentially
may be obligated to absorb, directly or by paying additional sums to the entity,
a proportionate share of the defaulting party’s liability. PacifiCorp has
recorded its estimated share of the decommissioning and reclamation
commitments.
(19)
Employee
Benefit Plans
Domestic
Operations
PacifiCorp
sponsors defined benefit pension plans that cover the majority of its employees.
PacifiCorp’s pension plans include a noncontributory defined benefit pension
plan, a supplemental executive retirement plan (“SERP”) and certain
multi-employer and joint trust union plans to which PacifiCorp contributes on
behalf of certain bargaining units. MidAmerican Energy sponsors defined benefit
pension plans that cover substantially all employees of MEHC and its domestic
energy subsidiaries other than PacifiCorp. MidAmerican Energy’s pension plans
included a noncontributory defined benefit pension plan and a SERP. PacifiCorp
and MidAmerican Energy also provide certain postretirement health care and life
insurance benefits through various plans for eligible retirees.
Changes
to the Company’s domestic defined benefit and other postretirement plans include
the following:
·
Effective
June 1, 2007, PacifiCorp switched from a traditional final average
pay formula for its noncontributory defined benefit pension plan to a cash
balance formula for its non-union employees. As a result of the change in
benefits under the traditional final average pay formula were frozen as of
May 31, 2007 for non-union employees, and PacifiCorp’s pension
liability and regulatory assets each decreased by
$111 million.
116
·
Non-union
employees hired on or after January 1, 2008, are not eligible to
participate in the PacifiCorp-sponsored or MidAmerican Energy-sponsored
noncontributory defined benefit pension plans. These non-union employees
will be eligible to receive enhanced benefits under PacifiCorp’s and
MidAmerican Energy’s defined contribution
plans.
·
Effective
December 31, 2007, Local Union No. 659 of the International
Brotherhood of Electrical Workers (“Local 659”) elected to cease
participation in PacifiCorp’s noncontributory defined benefit pension plan
and participate only in PacifiCorp’s defined contribution plan with
enhanced benefits. As a result of this election, the Local 659
participants’ benefits were frozen as of December 31,2007.
·
MidAmerican
Energy’s other postretirement benefit plan was amended for non-union
employees on July 1, 2004, and substantially all union participants
on July 1, 2006. As a result, non-union employees hired after
June 30, 2004, and union employees hired after June 30, 2006,
are not eligible for postretirement benefits other than pensions. The
plan, as amended, provides 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.
Plan
assets and benefit obligations for PacifiCorp-sponsored plans were measured as
of September 30, 2007 and MidAmerican Energy-sponsored plans were measured
as of December 31, 2007. For purposes of calculating the expected return on
pension plan assets, a market-related value is used. Market-related value is
equal to fair value except for gains and losses on equity investments, which are
amortized into market-related value on a straight-line basis over five
years.
Combined
net periodic benefit cost for the pension, including SERP, and other
postretirement benefits plans included the following components for the years
ended December 31 (in millions):
Pension
Other
Postretirement
2007
2006
2005
2007
2006
2005
Service
cost
$
55
$
49
$
26
$
14
$
14
$
7
Interest
cost
111
97
36
47
40
14
Expected
return on plan assets
(112
)
(95
)
(38
)
(40
)
(30
)
(10
)
Net
amortization
28
27
4
21
20
4
Net
periodic benefit cost
$
82
$
78
$
28
$
42
$
44
$
15
The
following table is a reconciliation of the combined fair value of plan assets as
of December 31 (in millions):
Pension
Other
Postretirement
2007
2006
2007
2006
Plan
assets at fair value, beginning of year
$
1,548
$
613
$
532
$
191
PacifiCorp
acquisition
-
829
-
293
Employer
contributions
86
81
58
47
Participant
contributions
-
-
20
16
Actual
return on plan assets
175
137
56
35
Benefits
paid and other
(171
)
(112
)
(63
)
(50
)
Plan
assets at fair value, end of year
$
1,638
$
1,548
$
603
$
532
The SERPs
have no plan assets; however the Company has Rabbi trusts that hold
corporate-owned life insurance and other investments to provide funding for the
future cash requirements of the SERPs. The cash surrender value of all of the
policies included in the Rabbi trusts, net of amounts borrowed against the cash
surrender value, plus the fair market value of other Rabbi trust investments,
was $159 million and $148 million as of December 31, 2007 and
2006, respectively. These assets are not included in the plan assets in the
above table, but are reflected in the Consolidated Balance Sheet. The portion of
the pension projected benefit obligation, included in the table below, related
to the SERPs was $155 million and $161 million as of December 31,2007 and 2006, respectively.
117
The
following table is a reconciliation of the combined benefit obligations as of
December 31 (in millions):
Pension
Other
Postretirement
2007
2006
2007
2006
Benefit
obligation, beginning of year
$
2,038
$
678
$
824
$
250
PacifiCorp
acquisition
-
1,341
-
581
Service
cost
55
49
14
14
Interest
cost
111
97
47
40
Participant
contributions
-
-
20
16
Plan
amendments
(130
)
4
-
(16
)
Actuarial
(gain) loss
(90
)
(19
)
(49
)
(11
)
Benefits
paid and other
(171
)
(112
)
(63
)
(50
)
Benefit
obligation, end of year
$
1,813
$
2,038
$
793
$
824
Accumulated
benefit obligation, end of year
$
1,702
$
1,807
PacifiCorp’s
noncontributory defined benefit pension plan’s accumulated benefit obligation
exceeded the fair value of the plan’s assets by $46 million and
$228 million as of December 31, 2007 and 2006, respectively.
Additionally, the accumulated benefit obligations related to the SERPs totaled
$152 million and $156 million as of December 31, 2007 and 2006,
respectively.
The
combined funded status of the plans and the amounts recognized in the
Consolidated Balance Sheets as of December 31 are as follows
(in millions):
Pension
Other
Postretirement
2007
2006
2007
2006
Plan
assets at fair value, end of year
$
1,638
$
1,548
$
603
$
532
Less
- Benefit obligations, end of year
1,813
2,038
793
824
Funded
status
(175
)
(490
)
(190
)
(292
)
Contributions
after the measurement date but before year-end
-
-
12
27
Amounts
recognized in the Consolidated Balance Sheets
$
(175
)
$
(490
)
$
(178
)
$
(265
)
Amounts
recognized in the Consolidated Balance Sheets:
Deferred
charges, investments and other assets
$
77
$
66
$
-
$
-
Other
current liabilities
(11
)
(11
)
-
(1
)
Other
long-term accrued liabilities
(241
)
(545
)
(178
)
(264
)
Amounts
recognized
$
(175
)
$
(490
)
$
(178
)
$
(265
)
Amounts
not yet recognized as components of net periodic
benefit
cost:
Net
loss
$
108
$
292
$
70
$
144
Prior
service cost (credit)
(109
)
18
13
16
Net
transition obligation
3
5
63
76
Total
$
2
$
315
$
146
$
236
118
A
reconciliation of the amounts not yet recognized as components of net periodic
benefit cost for the year ended December 31, 2007 is as follows (in
millions):
Accumulated
Other
Regulatory
Regulatory
Comprehensive
Asset
Liability
Loss
Total
Pension
Balance,
beginning of year
$
423
$
(122
)
$
14
$
315
Net
gain arising during the year
(123
)
(26
)
(6
)
(155
)
Prior
service cost arising during the year
(129
)
-
(1
)
(130
)
Net
amortization
(25
)
-
(3
)
(28
)
Total
(277
)
(26
)
(10
)
(313
)
Balance,
end of year
$
146
$
(148
)
$
4
$
2
Deferred
Regulatory
Regulatory
Income
Asset
Liability
Taxes
Total
Other
Postretirement
Balance,
beginning of year
$
190
$
(25
)
$
71
$
236
Net
gain arising during the year
(54
)
-
(15
)
(69
)
Net
amortization
(21
)
-
-
(21
)
Total
(75
)
-
(15
)
(90
)
Balance,
end of year
$
115
$
(25
)
$
56
$
146
The net
loss, prior service cost and net transition obligation that will be amortized in
2008 into net periodic benefit cost are estimated to be as follows (in
millions):
Net
Prior
Service
Net
Transition
Loss
Cost
Obligation
Total
Pension
benefits
$
15
$
(10
)
$
2
$
7
Other
postretirement benefits
1
3
13
17
Total
$
16
$
(7
)
$
15
$
24
119
Plan
Assumptions
Assumptions
used to determine benefit obligations as of December 31 and net benefit
cost for the years ended December 31 were as follows:
Pension
Other
Postretirement
2007
2006
2005
2007
2006
2005
%
%
%
%
%
%
Benefit
obligations as of the measurement date:
PacifiCorp-sponsored
plans -
Discount
rate
6.30
5.85
-
6.45
6.00
-
Rate
of compensation increase
4.00
4.00
-
N/A
N/A
N/A
MidAmerican
Energy-sponsored plans -
Discount
rate
6.00
5.75
5.75
6.00
5.75
5.75
Rate
of compensation increase
4.50
4.50
5.00
N/A
N/A
N/A
Net
benefit cost for the years ended December 31:
PacifiCorp-sponsored
plans -
Discount
rate
5.76
5.75
-
6.00
5.75
-
Expected
return on plan assets
8.00
8.50
-
8.00
8.50
-
Rate
of compensation increase
4.00
4.00
-
N/A
N/A
N/A
MidAmerican
Energy-sponsored plans -
Discount
rate
5.75
5.75
5.75
5.75
5.75
5.75
Expected
return on plan assets
7.50
7.00
7.00
7.50
7.00
7.00
Rate
of compensation increase
4.50
5.00
5.00
N/A
N/A
N/A
2007
2006
Assumed
health care cost trend rates as of the measurement date:
PacifiCorp-sponsored
plans -
Health
care cost trend rate assumed for next year – under 65
9.00%
10.00%
Health
care cost trend rate assumed for next year – over 65
7.00%
8.00%
Rate
that the cost trend rate gradually declines to
5.00%
5.00%
Year
that the rate reaches the rate it is assumed to remain at – under
65
2012
2012
Year
that the rate reaches the rate it is assumed to remain at – over
65
2010
2010
MidAmerican
Energy-sponsored plans -
Health
care cost trend rate assumed for next year
9.00%
8.00%
Rate
that the cost trend rate gradually declines to
5.00%
5.00%
Year
that the rate reaches the rate it is assumed to remain at
2016
2010
A
one-percentage-point change in assumed health care cost trend rates would have
the following effects (in millions):
Increase
(Decrease)
One
Percentage-Point
One
Percentage-Point
Increase
Decrease
Effect
on total service and interest cost
$ 5
$
(4)
Effect
on other postretirement benefit obligation
57
(48)
Contributions and Benefit
Payments
Employer
contributions to the pension and other postretirement plans are expected to be
$77 million and $41 million, respectively, for 2008. The Company’s
policy is to contribute the minimum required amount to its pension plans and the
net periodic cost to its other postretirement plans. The Pension Protection Act
of 2006 changes funding rules beginning in 2008 and may have the effect of
making minimum pension funding requirements more volatile than they have been
historically. Accordingly, the Company continually evaluates its funding
strategies.
120
The
Company’s expected benefit payments to participants from its pension and other
postretirement plans for 2008 through 2012 and for the five years thereafter are
summarized below (in millions):
Projected
Benefit Payments
Other
Postretirement
Pension
Gross
Medicare
Subsidy
Net
of Subsidy
2008
$
139
$
54
$
6
$
48
2009
139
57
7
50
2010
133
59
7
52
2011
137
63
7
56
2012
148
64
9
55
2013-17
828
364
53
311
Investment Policy and Asset
Allocation
The
Company’s investment policy for its pension and other postretirement plans is to
balance risk and return through a diversified portfolio of equity securities,
fixed income securities and other alternative investments. Asset allocation for
the pension and other postretirement plans are as indicated in the tables below.
Maturities for fixed income securities are managed to targets consistent with
prudent risk tolerances. Sufficient liquidity is maintained to meet near-term
benefit payment obligations. The plans retain outside investment advisors to
manage plan investments within the parameters outlined by each plan’s Pension
and Employee Benefits Plans Administrative Committee. The weighted-average
return on assets assumption is based on historical performance for the types of
assets in which the plans invest.
PacifiCorp’s
other postretirement plan assets are composed of three different trust accounts.
The 401(h) account is invested in the same manner as the assets of the pension
plan. Each of the two Voluntary Employees’ Beneficiaries Association (“VEBA”)
Trusts has its own investment allocation strategies. PacifiCorp’s asset
allocation as of December 31 was as follows:
Pension
and Other Postretirement
VEBA
Trusts
2007
2006
Target
2007
2006
Target
%
%
%
%
%
%
Equity
securities
56
58
53-57
64
65
63-67
Debt
securities
35
35
35
36
35
33-37
Other
9
7
8-12
-
-
-
Total
100
100
100
100
MidAmerican
Energy’s asset allocation as of December 31 was as follows:
Pension
Other
Postretirement
2007
2006
Target
2007
2006
Target
%
%
%
%
%
%
Equity
securities
69
70
65-75
52
52
60-80
Debt
securities
24
24
20-30
46
47
25-35
Real
estate and other
7
6
0-10
2
1
0-5
Total
100
100
100
100
New
target ranges for MidAmerican Energy’s other postretirement benefit plan assets
were approved by MidAmerican Energy’s Administrative Committee in December 2007.
No rebalancing took place before December 31, 2007.
121
Defined Contribution
Plans
The
Company sponsors defined contribution pension plans (401(k) plans) and an
employee savings plan covering substantially all employees. The Company’s
contributions vary depending on the plan, but are based primarily on each
participant’s level of contribution and cannot exceed the maximum allowable for
tax purposes. Total Company contributions were $36 million,
$34 million and $17 million for 2007, 2006 and 2005,
respectively.
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 the majority of the employees of CE Electric
UK.
Plan
assets and obligations for the UK Plan are measured as of December 31,2007. For purposes of calculating the expected return on pension plan assets, a
market-related value is used. Market-related value is equal to fair value except
for gains and losses on equity investments which are amortized into
market-related value on a straight-line basis over five years. The components of
the net periodic benefit cost for the UK Plan for the years ended
December 31 was as follows (in millions):
2007
2006
2005
Service
cost
$
24
$
18
$
15
Interest
cost
95
78
77
Expected
return on plan assets
(118
)
(101
)
(97
)
Net
amortization
31
34
25
Net
periodic benefit cost
$
32
$
29
$
20
The
following table is a reconciliation of the fair value of plan assets as of
December 31 (in millions):
2007
2006
Plan
assets at fair value, beginning of year
$
1,795
$
1,420
Employer
contributions
71
66
Participant
contributions
7
6
Actual
return on plan assets
87
167
Benefits
paid
(79
)
(70
)
Foreign
currency exchange rate changes
24
206
Plan
assets at fair value, end of year
$
1,905
$
1,795
The
following table is a reconciliation of the benefit obligation as of
December 31 (in millions):
2007
2006
Benefit
obligation, beginning of year
$
1,813
$
1,559
Service
cost
24
18
Interest
cost
95
78
Participant
contributions
7
6
Benefits
paid
(79
)
(70
)
Experience
loss and change of assumptions
(64
)
4
Foreign
currency exchange rate changes
24
218
Benefit
obligation, end of year
$
1,820
$
1,813
Accumulated
benefit obligation, end of year
$
1,725
$
1,724
122
The
funded status of the plan and the amounts recognized in the Consolidated Balance
Sheets as of December 31 is as follows (in millions):
2007
2006
Plan
assets at fair value, end of year
$
1,905
$
1,795
Less
- Benefit obligation, end of year
1,820
1,813
Funded
status
$
85
$
(18
)
Amounts
recognized in the Consolidated Balance Sheets:
Deferred
charges, investments and other assets
$
85
$
-
Other
long-term accrued liabilities
-
(18
)
Amounts
recognized
$
85
$
(18
)
Amounts
not yet recognized as components of net periodic benefit
cost:
Net
loss
$
442
$
500
Prior
service cost
11
13
Total
$
453
$
513
A
reconciliation of the amounts not yet recognized as components of net periodic
benefit cost, which are included in accumulated other comprehensive income
(loss) in the Consolidated Balance Sheets, for the year ended December 31,2007 is as follows (in millions):
Balance,
beginning of year
$
513
Net
gain arising during the year
(34
)
Net
amortization
(31
)
Foreign
currency exchange rate changes
5
Total
(60
)
Balance,
end of year
$
453
The net
loss and prior service cost that will be amortized from accumulated other
comprehensive income (loss) in 2008 into net periodic benefit cost is estimated
to be $19 million and $2 million, respectively.
Plan
Assumptions
Assumptions
used to determine benefit obligations as of December 31 and net periodic
benefit cost for the years ended December 31 are as follows:
2007
2006
2005
%
%
%
Benefit
obligations as of December 31:
Discount
rate
5.90
5.20
4.75
Rate
of compensation increase
3.45
3.25
2.75
Net
benefit cost for the years ended December 31:
Discount
rate
5.20
4.75
5.25
Expected
return on plan assets
7.00
7.00
7.00
Rate
of compensation increase
3.25
2.75
2.75
123
Contributions and Benefit
Payments
The
expected benefit payments to participants in the UK Plan for 2008 through 2012
and for the five years thereafter are summarized below (in
millions):
2008
$
80
2009
83
2010
85
2011
87
2012
89
2013-2017
486
Employer
contributions to the UK Plan, including £23 million for the funding
deficiency, are currently expected to be £48 million for 2008.
Investment Policy and Asset
Allocation
CE
Electric UK’s investment policy for its pension plan is to balance risk and
return through a diversified portfolio of equity securities, fixed income
securities and real estate. Maturities for fixed income securities are managed
such that sufficient liquidity exists to meet near-term benefit payment
obligations. The plan retains outside investment advisors to manage plan
investments within the parameters set by the trustees of the UK Plan in
consultation with CE Electric UK. The return on assets assumption is based on a
weighted average of the expected historical performance for the types of assets
in which the plans invest.
CE
Electric UK’s pension plan asset allocation as of December 31 was as
follows:
Percentage
of Plan Assets
2007
2006
Target
%
%
%
Equity
securities
41
52
40
Debt
securities
46
37
50
Real
estate and other
13
11
10
Total
100
100
(20)
Fair
Value of Financial Instruments
The
carrying amounts of cash and cash equivalents, short-term investments,
receivables, payables, accrued liabilities and short-term borrowings
approximates fair value because of the short-term maturity or frequent
remarketing of these instruments. Derivative instruments are recorded at their
fair values, which are based upon published market indexes as adjusted for other
market factors such as location pricing differences or internally developed
models. Substantially all investments are carried at their fair values, which
are based on quoted market prices.
The fair
value of the Company’s long-term debt has been estimated based upon quoted
market prices, where available, or at the present value of future cash flows
discounted at rates consistent with comparable maturities with similar credit
risks. The carrying amount of variable-rate long-term debt approximates fair
value because of the frequent repricing of these instruments at market rates.
The following table presents the carrying amount and estimated fair value of the
Company’s long-term debt, including the current portion, as of December 31
(in millions):
2007
2006
Carrying
Amount
Fair
Value
Carrying
Amount
Fair
Value
Long-term
debt
$
19,693
$
20,525
$
17,449
$
18,293
124
(21)
Supplemental
Cash Flow Information
The
summary of supplemental cash flow information for the years ending
December 31 follows (in millions):
2007
2006
2005
Interest
paid
$
1,230
$
1,076
$
861
Income
taxes paid(1)
$
287
$
132
$
61
(1)
2007
includes $133 million of income taxes paid to Berkshire Hathaway and
2006 is net of $20 million of income taxes received from Berkshire
Hathaway.
(22)
Components
of Accumulated Other Comprehensive Income (Loss),
Net
Accumulated
other comprehensive income (loss), net is included in the Consolidated Balance
Sheets in the common shareholders’ equity section, and consists of the following
components, net of tax, as of December 31 (in millions):
2007
2006
Unrecognized
amounts on retirement benefits, net of tax of $(128) and
$(160)
$
(329
)
$
(367
)
Foreign
currency translation adjustment
356
326
Fair
value adjustment on cash flow hedges, net of tax of $38 and
$21
57
29
Unrealized
gains on marketable securities, net of tax of $4 and $3
6
5
Total
accumulated other comprehensive income (loss), net
$
90
$
(7
)
125
(23)
Segment
Information
MEHC’s
reportable segments were determined based on how the Company’s strategic units
are managed. The Company’s foreign reportable segments include CE Electric UK,
whose business is principally in Great Britain, and CalEnergy
Generation-Foreign, whose business is in the Philippines. Intersegment
eliminations and adjustments, including the allocation of goodwill, have been
made. Information related to the Company’s reportable segments is shown below
(in millions):
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 and (ii) intersegment
eliminations.
The
following table shows the change in the carrying amount of goodwill by
reportable segment for the years ended December 31, 2007 and 2006 (in
millions):
During
2006, the Company reclassified $45 million of identifiable intangible
assets from goodwill that principally related to trade names at
HomeServices that were determined to have finite lives.
(2)
Other
goodwill adjustments relate primarily to income tax
adjustments.
(3)
The
$22 million adjustment to PacifiCorp’s goodwill was due to the
completion of the purchase price allocation in the first quarter of
2007.
At the
end of the period covered by this Annual Report on Form 10-K, the Company
carried out an evaluation, under the supervision and with the participation of
the Company’s management, including the Chief Executive Officer (principal
executive officer) and the Chief Financial Officer (principal financial
officer), of 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). Based upon that
evaluation, the Company’s management, including the Chief Executive Officer
(principal executive officer) and the Chief Financial Officer (principal
financial officer), concluded that the Company’s disclosure controls and
procedures are effective in timely alerting them to material information
relating to the Company required to be included in the Company’s periodic SEC
filings. There has been no change in the Company’s internal control over
financial reporting during the quarter ended December 31, 2007 that has
materially affected, or is reasonably likely to materially affect, the Company’s
internal control over financial reporting.
Management’s
Report on Internal Control over Financial Reporting
Management
of the Company is responsible for establishing and maintaining adequate internal
control over financial reporting, as such term is defined in the Securities
Exchange Act of 1934 Rule 13a-15(f). Under the supervision and with the
participation of the Company’s management, including the Chief Executive Officer
(principal executive officer) and the Chief Financial Officer (principal
financial officer), the Company’s management conducted an evaluation of the
effectiveness of the Company’s internal control over financial reporting as of
December 31, 2007 as required by the Securities Exchange Act of 1934
Rule 13a-15(c). In making this assessment, the Company’s management used
the criteria set forth in the framework in “Internal Control - Integrated
Framework” issued by the Committee of Sponsoring Organizations of the Treadway
Commission. Based on the evaluation conducted under the framework in “Internal
Control - Integrated Framework,”the Company’s management concluded that the
Company’s internal control over financial reporting was effective as of
December 31, 2007.
This
report does not include an attestation report of the Company’s registered public
accounting firm regarding internal control over financial reporting.
Management’s report was not subject to attestation by the Company’s registered
public accounting firm pursuant to temporary rules of the SEC that permit the
Company to provide only management's report in this Annual Report on Form
10-K.
On
February 25, 2008, David L. Sokol, Chairman and Chief Executive Officer of MEHC,
Gregory E. Abel, President and Chief Operating Officer of MEHC, and Patrick J.
Goodman, Senior Vice President and Chief Financial Officer of MEHC, each
executed an amended and restated employment agreement effective as of January 1,2008. Each employment agreement is filed as an exhibit to this Annual Report on
Form 10-K.
The Board
of Directors appoints executive officers annually. There are no family
relationships among the executive officers, nor, except as set forth in
employment agreements, any arrangements or understandings between any executive
officer and any other person pursuant to which the executive officer was
appointed. Set forth below is certain information, as of January 31, 2008,
with respect to the current directors and executive officers of
MEHC:
DAVID L.
SOKOL, 51, Chairman of the Board of Directors and Chief Executive Officer.
Mr. Sokol has been the Chief Executive Officer since 1993, the Chairman of
the Board of Directors since 1994 and a director since 1991. Mr. Sokol joined
MEHC in 1991.
GREGORY
E. ABEL, 45, President and Director. Mr. Abel has been the President and Chief
Operating Officer since 1998 and a director since 2000. Mr. Abel joined
MEHC in 1992. Mr. Abel is also a director of PacifiCorp.
PATRICK
J. GOODMAN, 41, Senior Vice President and Chief Financial Officer since 1999.
Mr. Goodman joined MEHC in 1995. Mr. Goodman is also a director of
PacifiCorp.
DOUGLAS
L. ANDERSON, 49, Senior Vice President, General Counsel and Corporate Secretary
since 2001. Mr. Anderson joined MEHC in 1993. Mr. Anderson is also a director of
PacifiCorp.
MAUREEN
E. SAMMON, 44, Senior Vice President and Chief Administrative Officer since
2007. Ms. Sammon has been employed by MidAmerican Energy and its
predecessor companies since 1986 and has held several positions, including
Manager of Benefits and Vice President, Human Resources and
Insurance.
WARREN E.
BUFFETT, 77, Director. Mr. Buffett has been a director of MEHC since 2000
and has been Chairman of the Board of Directors and Chief Executive Officer of
Berkshire Hathaway for more than five years. Mr. Buffett is also a director
of The Washington Post Company.
WALTER
SCOTT, JR., 76, Director. Mr. Scott has been a director of MEHC since 1991
and has been Chairman of the Board of Directors of Level 3 Communications, Inc.,
a successor to certain businesses of Peter Kiewit & Sons’, Inc., for more
than five years. Mr. Scott is also a director of Peter Kiewit & Sons’,
Inc., Berkshire Hathaway and Valmont Industries, Inc.
MARC D.
HAMBURG, 58, Director. Mr. Hamburg has been a director of MEHC since 2000
and has been Vice President-Chief Financial Officer and Treasurer of Berkshire
Hathaway for more than five years.
Audit
Committee and Audit Committee Financial Expert
The audit
committee of the Board of Directors is comprised of Mr. Marc D. Hamburg.
The Board of Directors has determined that Mr. Hamburg qualifies as an
“audit committee financial expert,” as defined by SEC rules, based on his
education, experience and background. Based on the standards of the New York
Stock Exchange Inc., on which the common stock of MEHC’s majority owner,
Berkshire Hathaway, is listed, MEHC’s Board of Directors has determined that
Mr. Hamburg is not independent because of his employment by Berkshire
Hathaway.
Code
of Ethics
MEHC has
adopted a code of ethics that applies to its principal executive officer, its
principal financial and accounting officer, or persons acting in such
capacities, and certain other covered officers. The code of ethics is
incorporated by reference in the exhibits to this Annual Report on
Form 10-K.
We
believe that the compensation paid to each of our Chairman and Chief Executive
Officer, or CEO, our Chief Financial Officer, or CFO, and our three other most
highly compensated executive officers, to whom we refer collectively as our
Named Executive Officers, or NEOs, should be closely aligned with our overall
performance, and each NEO’s contribution to that performance, on both a short-
and long-term basis, and that such compensation should be sufficient to attract
and retain highly qualified leaders who can create significant value for our
organization. Our compensation programs are designed to provide our NEOs with
meaningful incentives for superior corporate and individual performance.
Performance is evaluated on a subjective basis within the context of both
financial and non-financial objectives that we believe contribute to our
long-term success, among which are financial strength, customer service,
operational excellence, employee commitment and safety, environmental respect
and regulatory integrity.
How
is Compensation Determined
Our
Compensation Committee is comprised of Messrs. Warren E. Buffett and Walter
Scott, Jr. The Compensation Committee is responsible for the establishment and
oversight of our compensation policy. Approval of compensation decisions for our
NEOs is made by the Compensation Committee, unless specifically delegated.
Although the Compensation Committee reviews each NEO’s complete compensation
package at least annually, it has delegated to the CEO and President and Chief
Operating Officer, or President, authority to approve off-cycle pay changes,
performance awards and participation in other employee benefit plans and
programs.
Our
criteria for assessing executive performance and determining compensation in any
year is inherently subjective and is not based upon specific formulas or
weighting of factors. Given the uniqueness of each NEO’s duties, we do not
specifically use other companies as benchmarks when establishing our NEOs’
initial compensation. Subsequently, the Compensation Committee reviews peer
company data when making annual base salary and incentive recommendations for
the CEO and the President. The peer companies for 2007 were American Electric
Power Company, Inc., Consolidated Edison, Inc., Dominion Resources, Inc., Duke
Energy Corporation, Edison International, Energy Future Holdings Corp. (formerly
TXU Corp.), Entergy Corporation, Exelon Corporation, FirstEnergy Corp., FPL
Group, Inc., PG&E Corporation, Progress Energy, Inc., Public Service
Enterprise Group Incorporated, Sempra Energy, The Southern Company and Xcel
Energy Inc.
Discussion
and Analysis of Specific Compensation Elements
Base
Salary
We
determine base salaries for all our NEOs by reviewing our overall performance
and each NEO’s performance, the value each NEO brings to us and general labor
market conditions. While base salary provides a base level of compensation
intended to be competitive with the external market, the annual base salary
adjustment for each NEO is determined on a subjective basis after consideration
of these factors and is not based on target percentiles or other formal
criteria. The CEO makes recommendations regarding the President’s base salary,
the CEO and President together make recommendations regarding the other NEOs’
base salaries, and the Compensation Committee must approve all annual merit
increases, which take effect on January 1 of each year. The Compensation
Committee alone sets our CEO’s base salary. Base salaries for all NEOs increased
on average by 2.5% effective January 1, 2007. An increase or decrease in base
pay may also result from a promotion or other significant change in a NEO’s
responsibilities during the year. Ms. Sammon received a base pay increase in May
2007 when she was appointed our Chief Administrative Officer. There were no
other base salary changes for our NEOs during the year after the January 1,2007 merit increase.
Short-Term
Incentive Compensation
The
objective of short-term incentive compensation is to reward the achievement of
significant annual corporate goals while also providing NEOs with competitive
total cash compensation.
131
Performance
Incentive Plan
Under our
Performance Incentive Plan, or PIP, all NEOs are eligible to earn an annual
discretionary cash incentive award, which is determined on a subjective basis
and is not based on a specific formula or cap. Awards paid to a NEO under the
PIP are based on a variety of measures linked to our overall performance and
each NEO’s contribution to that performance. An individual NEO’s performance is
measured against defined objectives that commonly include financial measures
(e.g., net income and cash flow) and non-financial measures (e.g., customer
service, operational excellence, employee commitment and safety, environmental
respect and regulatory integrity), as well as the NEO’s response to issues and
opportunities that arise during the year. The CEO and President recommend annual
incentive awards for the other NEOs to the Compensation Committee prior to the
last committee meeting of each year, traditionally held in the fourth quarter.
The CEO recommends the annual incentive award for the President, and the
Compensation Committee determines the CEO’s award. If approved by the
Compensation Committee, awards are paid prior to year-end.
Performance
Awards
In
addition to the annual awards under the PIP, we may grant cash performance
awards periodically during the year to one or more NEOs to reward the
accomplishment of significant non-recurring tasks or projects. These awards are
discretionary and approved by the President, as delegated by the CEO and the
Compensation Committee. In 2007, awards were granted to Mr. Anderson and
Ms. Sammon in recognition of support provided relative to certain non-routine
projects. Although both Messrs. Sokol and Abel are eligible for performance
awards, neither has been granted an award in the past five years.
Long-Term
Incentive Compensation
The
objective of long-term incentive compensation is to retain NEOs, reward their
exceptional performance and motivate them to create long-term, sustainable
value. Our current long-term incentive compensation program is cash-based. We
have not issued stock options or other forms of equity-based awards since March
2000. All stock options held by Messrs. Sokol and Abel are fully
vested.
Long-Term
Incentive Partnership Plan
The
MidAmerican Energy Holdings Company Long-Term Incentive Partnership Plan, or
LTIP, is designed to retain key employees and to align our interests and the
interests of the participating employees. Messrs. Goodman and Anderson and Ms.
Sammon, as well as 76 other employees, participate in this plan, while our CEO
and President do not. Our LTIP provides for annual awards based upon significant
accomplishments by the individual participants and the achievement of the
financial and non-financial objectives previously described. The goals are
developed with the objective of being attainable with a sustained, focused and
concerted effort and are determined and communicated in January of each plan
year. Participation is discretionary and is determined by the CEO and President
who recommend awards to the Compensation Committee annually in the fourth
quarter. Except for limited situations of extraordinary performance, awards are
capped at 1.5 times base salary. The value is finalized in the first quarter of
the following year. These cash-based awards are subject to mandatory deferral
and equal annual vesting over a five-year period starting in the performance
year. Participants allocate the value of their deferral accounts among various
investment alternatives, which are determined by a vote of all participants.
Gains or losses may be incurred based on the investment performance.
Participating NEOs may elect to defer all or a part of the award or receive
payment in cash after the five-year mandatory deferral and vesting period.
Vested balances (including any investment profits or losses thereon) of
terminating participants are paid at the time of termination.
Other
Employee Benefits
Supplemental
Executive Retirement Plan
The
MidAmerican Energy Company Supplemental Retirement Plan for Designated Officers,
or SERP, provides additional retirement benefits to participants. We include the
SERP as part of the participating NEO’s overall compensation in order to provide
a comprehensive, competitive package and as a key retention tool. Messrs. Sokol,
Abel and Goodman participate, and the plan is currently closed to any new
participants. The SERP provides annual retirement benefits of up to 65% of a
participant’s total cash compensation in effect immediately prior to retirement,
subject to an annual $1 million maximum retirement benefit. Total cash
compensation means (i) the highest amount payable to a participant as monthly
base salary during the five years immediately prior to retirement multiplied by
12, plus (ii) the average of the participant’s annual awards under an annual
incentive bonus program during the three years immediately prior to the year of
retirement and (iii) special, additional or non-recurring bonus awards, if any,
that are required to be included in total cash compensation pursuant to a
participant’s employment agreement or approved for inclusion by the Board of
Directors. All participating NEOs have met the five-year service requirement
under the plan. Mr. Goodman’s SERP benefit will be reduced by the amount of his
regular retirement benefit under the MidAmerican Energy Company Retirement Plan
and ratably for retirement between ages 55 and 65.
132
Deferred
Compensation Plan
The
MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation
Plan, or DCP, provides a means for all NEOs to make voluntary deferrals of up to
50% of base salary and 100% of short-term incentive compensation awards. The
deferrals and any investment returns grow on a tax-deferred basis. Amounts
deferred under the DCP receive a rate of return based on the returns of any
combination of eight investment options offered under the DCP and selected by
the participant, and the plan allows participants to choose from three forms of
distribution. While the plan allows us to make discretionary contributions, we
have not made contributions to date. We include the DCP as part of the
participating NEO’s overall compensation in order to provide a comprehensive,
competitive package.
Financial
Planning and Tax Preparation
This
benefit provides NEOs with financial planning and tax preparation services. The
value of the benefit is included in the NEO’s taxable income. It is offered both
as a competitive benefit itself and also to help ensure our NEOs best utilize
the other forms of compensation we provide to them.
Executive
Life Insurance
We
provide universal life insurance to Messrs. Sokol, Abel and Goodman, having a
death benefit of two times annual base salary during employment, reducing to one
times annual base salary in retirement. The value of the benefit is included in
the NEO’s taxable income. We include the executive life insurance as part of the
participating NEO’s overall compensation in order to provide a comprehensive,
competitive package.
Impact
of Accounting and Tax
Compensation
paid under our executive compensation plans has been reported as an expense in
our historical Consolidated Financial Statements. We are entitled to a statutory
exemption from the deductibility limitations of executive compensation under
Section 162(m) of the Internal Revenue Code as we are a non-publicly held
affiliate of a consolidated taxpayer, Berkshire Hathaway.
Potential
Payments Upon Termination
Certain
NEOs are entitled to post-termination payments in the event their employment is
terminated under certain circumstances. We believe these post-termination
payments are an important component of the competitive compensation package we
offer to these NEOs.
Compensation Committee
Report
The
Compensation Committee, consisting of Messrs. Buffett and Scott, has reviewed
and discussed the Compensation Discussion and Analysis with management and,
based on this review and discussion, has recommended to the Board of Directors
that the Compensation Discussion and Analysis be included in this Annual Report
on Form 10-K.
133
Summary Compensation
Table
The
following table sets forth information regarding compensation earned by each of
our NEOs during the years indicated:
Change
in
Pension
Value
and
Non-Equity
Nonqualified
Incentive
Deferred
All
Name
and
Base
Plan
Compensation
Other
Principal
Salary
Bonus(1)
Compensation(2)
Earnings(3)
Compensation(4)
Total(5)(6)
Position
Year
($)
($)
($)
($)
($)
($)
David L. Sokol,
Chairman and
2007
$
850,000
$
4,000,000
$
-
$
-
$
213,038
$
5,063,038
Chief
Executive Officer
2006
850,000
2,500,000
26,250,000
344,000
281,735
30,225,735
Gregory
E. Abel, President
2007
775,000
4,000,000
-
-
370,624
5,145,624
2006
760,000
2,200,000
26,250,000
234,000
265,386
29,709,386
Patrick J. Goodman,
Senior Vice
2007
320,000
889,306
-
51,000
47,868
1,308,174
President
and Chief Financial
2006
307,500
1,025,453
-
89,000
51,248
1,473,201
Officer
Douglas L. Anderson,
Senior Vice
2007
291,500
788,705
-
20,000
29,372
1,129,577
President
and General Counsel
2006
283,000
802,560
-
28,000
45,101
1,158,661
Maureen E. Sammon,
Senior Vice
2007
196,659
452,903
-
17,000
20,291
686,853
President
and Chief
2006
185,000
434,035
-
29,000
20,207
668,242
Administrative
Officer
______________
(1)
Consists
of annual cash incentive awards earned pursuant to the PIP for our NEOs,
as well as performance awards earned related to non-routine projects and
the vesting of LTIP awards and associated earnings for Messrs. Goodman and
Anderson and Ms. Sammon. The breakout for 2007 is as
follows:
PIP
Performance
Awards
LTIP
David
L. Sokol
$
4,000,000
$
-
$
-
Gregory
E. Abel
4,000,000
-
-
Patrick
J. Goodman
340,000
-
549,306
($101,306
in investment profits)
Douglas
L. Anderson
325,000
25,000
438,705
($89,474
in investment profits)
Maureen
E. Sammon
155,000
25,000
272,903
($55,353
in investment profits)
134
LTIP
awards are subject to mandatory deferral and equal annual vesting over a
five–year period starting in the performance year. Participants allocate
the value of their deferral accounts among various investment
alternatives, which are determined by a vote of all participants. Gains or
losses may be incurred based on the investment performance. Participating
NEOs may elect to defer all or a part of the award or receive payment in
cash after the five-year mandatory deferral and vesting period. Vested
balances (including any investment profits or losses thereon) of
terminating participants are paid at the time of termination. Because the
amounts to be paid out may increase or decrease depending on investment
performance, the ultimate payouts are undeterminable.
Net
income, the net income target goal and the matrix below were used in
determining the gross amount of the LTIP award available to the group. Net
income is subject to discretionary adjustment by the CEO, President and
Compensation Committee. In 2007, the gross award and per-point value were
adjusted to eliminate the earnings benefit of a reduction in the United
Kingdom corporate income tax rate from 30% to 28% and for failing to
achieve certain non-financial performance
factors.
Net
Income
Award
Less
than or equal to net income target goal
None
Exceeds
net income target goal by 0.01% - 3.25%
15%
of excess
Exceeds
net income target goal by 3.251% - 6.50%
15%
of the first 3.25% excess;
25%
of excess over 3.25%
Exceeds
net income target goal by more than 6.50%
15%
of the first 3.25% excess;
25%
of the next 3.25% excess;
35%
of excess over 6.50%
A
pool of up to 100,000 points in aggregate is allocated between plan
participants either as initial points or year-end performance points. A
nominating committee recommends the point allocation, subject to approval
by the CEO and President, based upon a discretionary evaluation of
individual achievement of financial and non-financial goals previously
described herein. A participant’s award equals his or her allocated points
multiplied by the final per-point value, capped at 1.5 times base salary
except in extraordinary
circumstances.
(2)
Amounts
consist of cash awards earned pursuant to the Incremental Profit Sharing
Plan, or IPSP, for Messrs. Sokol and Abel. While the initial IPSP
performance period ended in 2007, the adjusted diluted earnings per share
target of $12.37 was achieved in 2006 and Messrs. Sokol and Abel
received the remaining full awards under the plan in
2006.
(3)
Amounts
are based upon the aggregate increase in the actuarial present value of
all qualified and nonqualified defined benefit plans, which include our
cash balance and SERP, as applicable. Amounts are computed using
assumptions consistent with those used in preparing the related pension
disclosures included in our Notes to Consolidated Financial Statements
included in Item 8 of this Form 10-K and are as of the pension plans’
measurement dates. No participant in our DCP earned “above-market” or
“preferential” earnings on amounts deferred.
(4)
Amounts
consist of vacation payouts, life insurance premiums and defined
contribution plan matching and profit-sharing contributions we paid on
behalf of the NEOs, as well as perquisites and other personal benefits
related to the personal use of corporate aircraft and financial planning
and tax preparation that we paid on behalf of Messrs. Sokol, Abel, Goodman
and Anderson. The personal use of corporate aircraft represents our
incremental cost of providing this personal benefit determined by applying
the percentage of flight hours used for personal use to our variable
expenses incurred from operating our corporate aircraft. All other
compensation is based upon amounts paid by us.
Items
required to be reported and quantified are as follows: Mr. Sokol - life
insurance premiums of $51,935, personal use of corporate aircraft of
$114,981 and vacation payouts of $29,422; Mr. Abel - life insurance
premiums of $36,218 and personal use of corporate aircraft of $318,241;
Mr. Goodman - life insurance premiums of $19,149 and vacation payouts of
$12,384; and Mr. Anderson - vacation payouts of
$17,938.
(5)
Any
amounts voluntarily deferred by the NEO, if applicable, are included in
the appropriate column in the summary compensation
table.
135
Outstanding Equity Awards at
Fiscal Year-End
The
following table sets forth information regarding outstanding equity awards held
by each of our NEOs at December 31, 2007:
We
have not issued stock options or other forms of equity-based awards since
March 2000. All outstanding stock options relate to previously granted
options held by Messrs. Sokol and Abel and were fully vested prior to
2007. Accordingly, we have omitted the Stock Awards columns from the
Outstanding Equity Awards at Fiscal Year-End
Table.
Option Exercises and Stock
Vested
The
following table sets forth information regarding stock options exercised by Mr.
Abel during the year ended December 31, 2007:
Option
Awards(1)
Number
of
shares
acquired
Value
realized
on
exercise
on
exercise
Name
(#)
($)
Gregory E. Abel
370,000
54,765,332
______________
(1)
We
have not issued stock options or other forms of equity-based awards since
March 2000. All stock options relate to previously granted options held by
Mr. Abel and were fully vested prior to 2007. Accordingly, we have omitted
the Stock Awards columns from the Option Exercises and Stock Vested
Table.
136
Pension
Benefits
The
following table sets forth certain information regarding the defined benefit
pension plan accounts held by each of our NEOs at December 31,2007:
Number
of
years
Present
value
Payments
credited
of
accumulated
during
last
service(1)
benefit(2)
fiscal
year
Name
Plan
name
(#)
($)
($)
David L. Sokol
SERP
n/a
$
5,692,000
$
-
MidAmerican
Energy Company Retirement Plan
n/a
186,000
-
Gregory E. Abel
SERP
n/a
3,727,000
-
MidAmerican
Energy Company Retirement Plan
n/a
176,000
-
Patrick J. Goodman
SERP
13
years
432,000
-
MidAmerican
Energy Company Retirement Plan
9
years
169,000
-
Douglas L. Anderson
MidAmerican
Energy Company Retirement Plan
9
years
176,000
-
Maureen
E. Sammon
MidAmerican
Energy Company Retirement Plan
21
years
199,000
-
______________
(1)
The
pension benefits for Messrs. Sokol and Abel do not depend on their years
of service, as both have already reached their maximum benefit levels
based on their respective ages and previous triggering events described in
their employment agreements. Mr. Goodman’s credited years of service
includes nine years of service with us and, for purposes of the SERP only,
four additional years of imputed service from a predecessor
company.
(2)
Amounts
are computed using assumptions consistent with those used in preparing the
related pension disclosures included in our Notes to Consolidated
Financial Statements included in Item 8 of this Form 10-K and
are as of December 31, 2007, the plans’ measurement date. The present
value of accumulated benefits for the SERP was calculated using the
following assumptions: (1) Mr. Sokol – a 100% joint and survivor
annuity; (2) Mr. Abel – a 15-year certain and life annuity; and (3)
Mr. Goodman – a 66 2/3% joint and survivor annuity. The present value
of accumulated benefits for the MidAmerican Energy Company Retirement Plan
was calculated using a lump sum payment assumption. The present value
assumptions used in calculating the present value of accumulated benefits
for both the SERP and the MidAmerican Energy Company Retirement Plan were
as follows: a cash balance interest crediting rate of 5.71% in 2007, 4.20%
in 2008 and 5.00% thereafter; cash balance conversion rates (not
applicable in 2007) of 4.75% in 2008, 5.00% in 2009, 5.25% in 2010, 5.50%
in 2011 and 5.75% in 2012 and thereafter; a discount rate of 6.00%; an
expected retirement age of 65; and postretirement mortality using the
RP-2000 M/F tables.
The SERP
provides additional retirement benefits to participants. The SERP provides
annual retirement benefits up to 65% of a participant’s total cash compensation
in effect immediately prior to retirement, subject to an annual $1 million
maximum retirement benefit. Total cash compensation means (i) the highest amount
payable to a participant as monthly base salary during the five years
immediately prior to retirement multiplied by 12, plus (ii) the average of the
participant’s awards under an annual incentive bonus program during the three
years immediately prior to the year of retirement and (iii) special, additional
or non-recurring bonus awards, if any, that are required to be included in total
cash compensation pursuant to a participant’s employment agreement or approved
for inclusion by the Board of Directors. Mr. Goodman’s SERP benefit will be
reduced by the amount of his regular retirement benefit under the MidAmerican
Energy Company Retirement Plan and ratably for retirement between ages 55 and
65. A survivor benefit is payable to a surviving spouse under the SERP. Benefits
from the SERP will be paid out of general corporate funds; however, through a
Rabbi trust, we maintain life insurance on the participants in amounts expected
to be sufficient to fund the after-tax cost of the projected benefits. Deferred
compensation is considered part of the salary covered by the SERP.
137
Under the
MidAmerican Energy Company Retirement Plan, each NEO has an account, for
record-keeping purposes only, to which credits are allocated annually based upon
a percentage of the NEO’s base salary and incentive paid in the plan year. In
addition, all balances in the accounts of NEOs earn a fixed rate of interest
that is credited annually. The interest rate for a particular year is based on
the one-year constant maturity Treasury yield plus seven-tenths of one
percentage point. Each NEO is vested in the MidAmerican Energy Company
Retirement Plan. At retirement, or other termination of employment, an amount
equal to the vested balance then credited to the account is payable to the NEO
in the form of a lump sum or an annuity.
Nonqualified Deferred
Compensation
The
following table sets forth certain information regarding the nonqualified
deferred compensation plan accounts held by each of our NEOs at
December 31, 2007:
Aggregate
Executive
Registrant
Aggregate
Aggregate
balance
as of
contributions
contributions
earnings
withdrawals/
December 31,
in 2007(1)
in 2007
in 2007
distributions
2007(2)
Name
($)
($)
($)
($)
($)
David
L. Sokol
$
-
$
-
$
-
$
-
$
-
Gregory
E. Abel
-
-
56,424
329,285
1,005,654
Patrick J. Goodman
140,000
-
59,959
59,457
1,261,200
Douglas L. Anderson
469,024
-
33,886
-
1,434,116
Maureen
E. Sammon
162,765
-
3,977
-
606,467
______________
(1)
The
contribution amount shown for Mr. Goodman is included in the 2007 total
compensation reported for him in the Summary Compensation Table and is not
additional earned compensation. The contribution amounts shown for
Mr. Anderson and Ms. Sammon include $200,208 and $113,579,
respectively, earned towards their 2003 LTIP awards prior to 2007 and
thus not included in the 2007 total compensation reported for them in the
Summary Compensation Table.
(2)
Excludes
the value of 10,041 shares of our common stock reserved for issuance to
Mr. Abel. Mr. Abel deferred the right to receive the value of these shares
pursuant to a legacy nonqualified deferred compensation
plan.
Eligibility
for our DCP is restricted to select management and highly compensated employees.
The plan provides tax benefits to eligible participants by allowing them to
defer compensation on a pretax basis, thus reducing their current taxable
income. Deferrals and any investment returns grow on a tax-deferred basis, thus
participants pay no income tax until they receive distributions. The DCP permits
participants to make a voluntary deferral of up to 50% of base salary and 100%
of short-term incentive compensation awards. All deferrals are net of social
security taxes due on that bonus or award. Amounts deferred under the DCP
receive a rate of return based on the returns of any combination of eight
investment options offered by the plan and selected by the participant. Gains or
losses are calculated monthly, and returns are posted to accounts based on
participants’ fund allocation elections. Participants can change their fund
allocations as of the end of any calendar month.
The DCP
allows participants to maintain three accounts based upon when they want to
receive payments: retirement distribution, in-service distribution and education
distribution. Both the retirement and in-service accounts can be distributed as
lump sums or in up to 10 annual installments. The education account is
distributed in four annual installments. If a participant leaves employment
prior to retirement (age 55) all amounts in the participant’s account will be
paid out in a lump sum as soon as administratively practicable. Participants are
100% vested in their deferrals and any investment gains or losses recorded in
their accounts.
Participants
in our LTIP also have the option of deferring all or a part of those awards
after the five-year mandatory deferral and vesting period. The provisions
governing the deferral of LTIP awards are similar to those described for the DCP
above.
138
Potential Payments Upon
Termination
We have
entered into employment agreements with Messrs. Sokol, Abel and Goodman that
provide for payments following termination of employment under various
circumstances, which do not include change-in-control provisions.
Mr.
Sokol’s employment will terminate upon his resignation, permanent disability,
death, termination by us with or without cause, or our failure to provide Mr.
Sokol with the compensation or to maintain the job responsibilities set forth in
his employment agreement. A termination of employment of either Messrs. Abel or
Goodman will occur upon his resignation (with or without good reason), permanent
disability, death, or termination by us with or without cause. The employment
agreements for Messrs. Sokol and Abel also include provisions specific to the
calculation of their respective SERP benefits.
Neither
Mr. Anderson nor Ms. Sammon has an employment agreement. Where a NEO does not
have an employment agreement, or in the event that the agreements for Messrs.
Sokol, Abel and Goodman do not address an issue, payments upon termination are
determined by the applicable plan documents and our general employment policies
and practices as discussed below.
The
following discussion provides further detail on post-termination
payments.
David
L. Sokol
Mr.
Sokol’s employment agreement provides that we may terminate his employment with
cause, in which case we must pay him any accrued but unpaid base salary and a
bonus of not less than the minimum annual bonus as defined in his employment
agreement. If termination is due to death, permanent disability or other than
for cause, Mr. Sokol is entitled to receive an amount equal to three times the
sum of his annual base salary then in effect and the greater of his minimum
annual bonus or his average annual bonus for the two preceding years, plus
continuation of his senior executive employee benefits (or the economic
equivalent thereof) for three years. If Mr. Sokol resigns, we must pay him any
accrued but unpaid base salary and a bonus of not less than the annual minimum
bonus, unless he resigns for good reason, in which case he will receive the same
benefits as if he were terminated other than for cause.
If Mr.
Sokol relinquishes his position as Chief Executive Officer but offers to remain
employed as the Chairman of the Board, he is to receive a special achievement
bonus equal to two times the sum of his annual base salary then in effect and
the greater of his minimum annual bonus or his average annual bonus for the two
preceding years. This total payment as of December 31, 2007 is estimated at
$8,200,000 (and is not included in the termination scenarios table below). He
will also receive an annual salary of $750,000 and will be eligible for an
annual bonus.
In the
event Mr. Sokol has relinquished his position as Chief Executive Officer and is
subsequently terminated as Chairman of the Board due to death, disability or
other than for cause, he is entitled to (i) any accrued but unpaid base salary
plus an amount equal to the aggregate annual base salary that would have been
paid to him through the fifth anniversary of the date he commenced his
employment solely as Chairman of the Board and (ii) the continuation of his
senior executive employee benefits (or the economic equivalent thereof) through
such fifth anniversary.
Payments
made in accordance with the employment agreement are contingent on Mr. Sokol
complying with the confidentiality and post-employment restrictions described
therein. The term of the agreement expires on August 21, 2009, but is extended
automatically for additional one year terms thereafter subject to Mr. Sokol’s
election to decline renewal at least 120 days prior to the then current
expiration date or termination.
139
The
following table sets forth the estimated enhancements to payments pursuant to
the termination scenarios described above. Payments or benefits that are not
enhanced in form or amount upon the occurrence of a particular termination
scenario, which include 401(k) account balances and those portions of life
insurance benefits and cash balance pension amounts that would have otherwise
been paid, are not included herein. All estimated payments reflected in the
table below assume termination on December 31, 2007, and are payable as lump
sums unless otherwise noted.
Cash
Life
Benefits
Termination
Scenario
Severance(2)
Incentive
Insurance(3)
Pension(4)
Continuation(5)
Excise
Tax(6)
Retirement
$
-
$
-
$
-
$
9,390,000
$
-
$
-
Voluntary and
Involuntary With Cause
4,000,000
-
-
9,390,000
-
-
Involuntary
Without Cause, Company
Breach
and Disability
12,300,000
-
-
9,390,000
110,252
-
Death
12,300,000
-
1,667,786
8,673,000
110,252
-
Following
Change in Position(1)
3,750,000
-
-
9,390,000
183,753
-
______________
(1)
The
amounts shown in the Following Change in Position termination scenario are
only applicable if the termination is due to death, disability or other
than for cause.
(2)
The
cash severance payments are determined in accordance with Mr. Sokol’s
employment agreement.
(3)
Life
insurance benefits are equal to two times base salary, as of the preceding
June 1, less the benefits otherwise payable in all other termination
scenarios, which are equal to the total cash value of the policies less
cumulative premiums paid by us.
(4)
Pension
values represent the excess of the present value of benefits payable under
each termination scenario over the amount already reflected in the Pension
Benefits Table. Mr. Sokol’s death scenario is based on a 100% joint
and survivor with 15-year certain annuity commencing immediately.
Mr. Sokol’s other termination scenarios are based on a 100% joint and
survivor annuity commencing immediately.
(5)
Includes
health and welfare, life insurance and financial planning and tax
preparation benefits for three years (five years in the case of
termination following a change in position). The health and welfare
benefit amounts are estimated using the rates we currently charge
employees terminating employment but electing to continue their medical,
dental and vision insurance after termination. These amounts are
grossed-up for taxes and then reduced by the amount Mr. Sokol would have
paid if he had continued his employment. The life insurance benefit
amounts are based on the cost of individual policies offering benefits
equivalent to our group coverage and are grossed-up for taxes. These
amounts also assume benefit continuation for the entire three year period
(five year period in the case of termination following a change in
position), with no offset by another employer. We will also continue to
provide financial planning and tax preparation reimbursement, or the
economic equivalent thereof, for three years or pay a lump sum cash amount
to keep Mr. Sokol in the same economic position on an after-tax basis. The
amount included is based on an annual estimated cost using the most recent
three-year average annual reimbursement. If it is determined that benefits
paid with respect to the extension of medical and dental benefits to Mr.
Sokol would not be exempt from taxation under the Internal Revenue Code,
the Company shall pay to Mr. Sokol a lump sum cash payment following
separation from service to allow him to obtain equivalent medical and
dental benefits and which would put him in the same after-tax economic
position.
(6)
As
provided in Mr. Sokol’s employment agreement, should it be deemed under
Section 280G of the Internal Revenue Code that termination payments
constitute excess parachute payments subject to an excise tax, we will
gross up such payments to cover the excise tax and any additional taxes
associated with such gross-up. Based on computations prescribed under
Section 280G and related regulations, we do not believe that any of the
termination scenarios are subject to an excise
tax.
140
Gregory
E. Abel
Mr.
Abel’s employment agreement entitles him to receive two years base salary
continuation and payments in respect of average bonuses for the prior two years
in the event we terminate his employment other than for cause. The payments are
to be paid as a lump sum with no discount for present valuation.
In
addition, if Mr. Abel’s employment is terminated due to death, permanent
disability or other than for cause, he is entitled to continuation of his senior
executive employee benefits (or the economic equivalent thereof) for two years.
If Mr. Abel resigns, we must pay him any accrued but unpaid base salary, unless
he resigns for good reason, in which case he will receive the same benefits as
if he were terminated other than for cause.
Payments
made in accordance with the employment agreement are contingent on Mr. Abel
complying with the confidentiality and post-employment restrictions described
therein. The term of the agreement effectively expires on August 6, 2012,
and is extended automatically for additional one year terms thereafter subject
to Mr. Abel’s election to decline renewal at least 365 days prior to the
August 6 that is four years prior to the current expiration date (or by
August 6, 2008 for the agreement not to extend to August 6,2013).
The
following table sets forth the estimated enhancements to payments pursuant to
the termination scenarios indicated. Payments or benefits that are not enhanced
in form or amount upon the occurrence of a particular termination scenario,
which include 401(k) and nonqualified deferred compensation account balances and
those portions of life insurance benefits and cash balance pension amounts that
would have otherwise been paid, are not included herein. All estimated payments
reflected in the table below assume termination on December 31, 2007, and are
payable as lump sums unless otherwise noted.
Cash
Life
Benefits
Termination
Scenario
Severance(1)
Incentive
Insurance(2)
Pension(3)
Continuation(4)
Excise
Tax(5)
Retirement,
Voluntary and Involuntary
With
Cause
$
-
$
-
$
-
$
9,550,000
$
-
$
-
Involuntary
Without Cause, Disability and
Voluntary
With Good Reason
7,750,000
-
-
9,550,000
38,596
-
Death
7,750,000
-
1,529,784
10,519,000
38,596
-
______________
(1)
The
cash severance payments are determined in accordance with Mr. Abel’s
employment agreement.
(2)
Life
insurance benefits are equal to two times base salary, as of the preceding
June 1, less the benefits otherwise payable in all other termination
scenarios, which are equal to the total cash value of the policies less
cumulative premiums paid by us.
(3)
Pension
values represent the excess of the present value of benefits payable under
each termination scenario over the amount already reflected in the Pension
Benefits Table. Mr. Abel’s death scenario is based on a 100% joint
and survivor with 30-year certain annuity commencing immediately.
Mr. Abel’s other termination scenarios are based on a 100% joint and
survivor with 15-year certain annuity commencing at age
47.
(4)
Includes
health and welfare, life insurance and financial planning and tax
preparation benefits for two years. The health and welfare benefit amounts
are estimated using the rates we currently charge employees terminating
employment but electing to continue their medical, dental and vision
insurance after termination. These amounts are grossed-up for taxes and
then reduced by the amount Mr. Abel would have paid if he had continued
his employment. The life insurance benefit amounts are based on the cost
of individual policies offering benefits equivalent to our group coverage
and are grossed-up for taxes. These amounts also assume benefit
continuation for the entire two year period, with no offset by another
employer. We will also continue to provide financial planning and tax
preparation reimbursement, or the economic equivalent thereof, for two
years or pay a lump sum cash amount to keep Mr. Abel in the same economic
position on an after-tax basis. The amount included is based on an annual
estimated cost using the most recent three-year average annual
reimbursement. If it is determined that benefits paid with respect to the
extension of medical and dental benefits to Mr. Abel would not be exempt
from taxation under the Internal Revenue Code, the Company shall pay to
Mr. Abel a lump sum cash payment following separation from service to
allow him to obtain equivalent medical and dental benefits and which would
put him in the same after-tax economic position.
(5)
As
provided in Mr. Abel’s employment agreement, should it be deemed under
Section 280G of the Internal Revenue Code that termination payments
constitute excess parachute payments subject to an excise tax, we will
gross up such payments to cover the excise tax and any additional taxes
associated with such gross-up. Based on computations prescribed under
Section 280G and related regulations, we believe that none of the
termination scenarios are subject to any excise
tax.
141
Patrick
J. Goodman
Mr.
Goodman’s employment agreement entitles him to receive two years base salary
continuation and payments in respect of average bonuses for the prior two years
in the event we terminate his employment other than for cause. The payments are
to be paid as a lump sum with no discount for present valuation.
In
addition, if Mr. Goodman’s employment is terminated due to death, permanent
disability or other than for cause, he is entitled to continuation of his senior
executive employee benefits (or the economic equivalent thereof) for one year.
If Mr. Goodman resigns, we must pay him any accrued but unpaid base salary,
unless he resigns for good reason, in which case he will receive the same
benefits as if he were terminated other than for cause.
Payments
made in accordance with the employment agreement are contingent on Mr. Goodman
complying with the confidentiality and post-employment restrictions described
therein. The term of the agreement expires on April 21, 2009, but is extended
automatically for additional one year terms thereafter subject to Mr. Goodman’s
election to decline renewal at least 365 days prior to the then current
expiration date or termination.
142
The
following table sets forth the estimated enhancements to payments pursuant to
the termination scenarios indicated. Payments or benefits that are not enhanced
in form or amount upon the occurrence of a particular termination scenario,
which include 401(k) and nonqualified deferred compensation account balances and
those portions of long-term incentive payments, life insurance benefits and cash
balance pension amounts that would have otherwise been paid, are not included
herein. All estimated payments reflected in the table below assume termination
on December 31, 2007, and are payable as lump sums unless otherwise
noted.
Cash
Life
Benefits
Termination
Scenario
Severance(1)
Incentive(2)
Insurance(3)
Pension(4)
Continuation(5)
Excise
Tax(6)
Retirement
and Voluntary
$
-
$
-
$
-
$
462,000
$
-
$
-
Involuntary
With Cause
-
-
-
-
-
-
Involuntary
Without Cause and Voluntary
With
Good Reason
2,771,546
-
-
462,000
14,030
1,099,888
Death
2,771,546
1,174,487
635,155
3,762,000
14,030
-
Disability
2,771,546
1,174,487
-
1,616,000
14,030
-
______________
(1)
The
cash severance payments are determined in accordance with Mr. Goodman’s
employment agreement.
(2)
Amounts
represent the unvested portion of Mr. Goodman’s LTIP account, which
becomes 100% vested upon his death or disability.
(3)
Life
insurance benefits are equal to two times base salary, as of the preceding
June 1, less the benefits otherwise payable in all other termination
scenarios, which are equal to the total cash value of the policies less
cumulative premiums paid by us.
(4)
Pension
values represent the excess of the present value of benefits payable under
each termination scenario over the amount already reflected in the Pension
Benefits Table. Mr. Goodman’s voluntary termination, retirement,
involuntary without cause, and change in control termination scenarios are
based on a 66 2/3% joint and survivor annuity commencing at age 55
(reductions for termination prior to age 55 and commencement prior to age
65). Mr. Goodman’s disability scenario is based on a 66 2/3% joint
and survivor annuity commencing at age 55 (no reduction for termination
prior to age 55, reduced for commencement prior to age 65). Mr. Goodman’s
death scenario is based on a 100% joint and survivor with 15-year certain
annuity commencing immediately (no reduction for termination prior to age
55 and commencement prior to age 65).
(5)
Includes
health and welfare, life insurance and financial planning and tax
preparation benefits for one year. The health and welfare benefit amounts
are estimated using the rates we currently charge employees terminating
employment but electing to continue their medical, dental and vision
insurance after termination. These amounts are grossed-up for taxes and
then reduced by the amount Mr. Goodman would have paid if he had continued
his employment. The life insurance benefit amounts are based on the cost
of individual policies offering benefits equivalent to our group coverage
and are grossed-up for taxes. These amounts also assume benefit
continuation for the entire one year period, with no offset by another
employer. We will also continue to provide financial planning and tax
preparation reimbursement, or the economic equivalent thereof, for one
year or pay a lump sum cash amount to keep Mr. Goodman in the same
economic position on an after-tax basis. The amount included is based on
an annual estimated cost using the most recent three-year average annual
reimbursement.
(6)
As
provided in Mr. Goodman’s employment agreement, should it be deemed under
Section 280G of the Internal Revenue Code that termination payments
constitute excess parachute payments subject to an excise tax, we will
gross up such payments to cover the excise tax and any additional taxes
associated with such gross-up. Based on computations prescribed under
Section 280G and related regulations, we believe that only the Involuntary
Without Cause and Voluntary With Good Reason termination scenarios are
subject to any excise tax.
143
Douglas
L. Anderson
The
following table sets forth the estimated enhancements to payments pursuant to
the termination scenarios indicated. Payments or benefits that are not enhanced
in form or amount upon the occurrence of a particular termination scenario,
which include 401(k) and nonqualified deferred compensation account balances and
those portions of long-term incentive payments and cash balance pension amounts
that would have otherwise been paid, are not included herein. All estimated
payments reflected in the table below assume termination on December 31, 2007,
and are payable as lump sums unless otherwise noted.
Cash
Life
Benefits
Termination
Scenario
Severance
Incentive(1)
Insurance
Pension(2)
Continuation
Excise
Tax
Retirement,
Voluntary and Involuntary With or
Without
Cause
$
-
$
-
$
-
$
29,000
$
-
$
-
Death
and Disability
-
859,086
-
29,000
-
-
______________
(1)
Amounts
represent the unvested portion of Mr. Anderson’s LTIP account, which
becomes 100% vested upon his death or disability.
(2)
Pension
values represent the excess of the present value of benefits payable under
each termination scenario over the amount already reflected in the Pension
Benefits Table.
Maureen
E. Sammon
The
following table sets forth the estimated enhancements to payments pursuant to
the termination scenarios indicated. Payments or benefits that are not enhanced
in form or amount upon the occurrence of a particular termination scenario,
which include 401(k) and nonqualified deferred compensation account balances and
those portions of long-term incentive payments and cash balance pension amounts
that would have otherwise been paid, are not included herein. All estimated
payments reflected in the table below assume termination on December 31, 2007,
and are payable as lump sums unless otherwise noted.
Cash
Life
Benefits
Termination
Scenario
Severance
Incentive(1)
Insurance
Pension(2)
Continuation
Excise
Tax
Retirement,
Voluntary and Involuntary With or
Without
Cause
$
-
$
-
$
-
$
45,000
$
-
$
-
Death
and Disability
-
538,689
-
45,000
-
-
______________
(1)
Amounts
represent the unvested portion of Ms. Sammon’s LTIP account, which becomes
100% vested upon her death or disability.
(2)
Pension
values represent the excess of the present value of benefits payable under
each termination scenario over the amount already reflected in the Pension
Benefits Table.
Director
Compensation
Our
directors are not paid any fees for serving as directors. All directors are
reimbursed for their expenses incurred in attending Board of Directors
meetings.
144
Compensation Committee
Interlocks and Insider Participation
Mr.
Buffett is the Chairman of the Board of Directors and Chief Executive Officer of
Berkshire Hathaway, our majority owner. Mr. Scott is a former officer of ours.
Based on the standards of the New York Stock Exchange, Inc. on which the common
stock of our majority owner, Berkshire Hathaway, is listed, our Board of
Directors has determined that Messrs. Buffett and Scott are not independent
because of their ownership of our common stock. None of our executive officers
serves as a member of the compensation committee of any company that has an
executive officer serving as a member of our Board of Directors. None of our
executive officers serves as a member of the board of directors of any company
that has an executive officer serving as a member of our Compensation Committee.
See also Item 13 of this Form 10-K.
Item
12.
Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder
Matters
Beneficial
Ownership
We are a
consolidated subsidiary of Berkshire Hathaway. The remainder of our common stock
is owned by a private investor group comprised of Messrs. Scott, Sokol and Abel.
The following table sets forth certain information regarding beneficial
ownership of our shares of common stock held by each of our directors, executive
officers and all of our directors and executive officers as a group as of
January 31, 2008:
Number
of Shares
Percentage
Name
and Address of Beneficial Owner (1)
Beneficially
Owned (2)
Of
Class (2)
Berkshire
Hathaway(3)
66,063,061
88.25
%
Walter
Scott, Jr.(4)
4,972,000
6.64
%
David
L. Sokol(5)
549,277
0.73
%
Gregory
E. Abel(6)
749,992
1.00
%
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)
6,271,269
8.30
%
(1)
Unless
otherwise indicated, each address is c/o MidAmerican Energy Holdings
Company at 666 Grand Avenue, 29th Floor, Des Moines, Iowa50309.
(2)
Includes
shares of 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
3,228,000 shares held by family members and family controlled trusts and
corporations, or Scott Family Interests, as to which Mr. Scott
disclaims beneficial ownership. Mr. Scott’s address is 1000 Kiewit Plaza,
Omaha, Nebraska68131.
(5)
Includes
options to purchase 549,277 shares of common stock that are presently
exercisable or become exercisable within 60 days.
(6)
Includes
options to purchase 154,052 shares of common stock that are presently
exercisable or become exercisable within 60 days.
(7)
Excludes
66,063,061 shares of common stock held by Berkshire Hathaway as to which
Messrs. Buffett and Hamburg disclaim beneficial
ownership.
145
The
following table sets forth certain information regarding beneficial ownership of
Class A and Class B shares of Berkshire Hathaway’s common stock held by each of
our directors, executive officers and all of our directors and executive
officers as a group as of January 31, 2008:
Name
and Address of Beneficial Owner (1)
Number
of Shares Beneficially Owned (2)
Percentage
Of Class (2)
Walter
Scott, Jr. (3)
(4)
Class
A
100
*
Class
B
-
-
David
L. Sokol (4)
Class
A
1,162
*
Class
B
103
*
Gregory
E. Abel (4)
Class
A
-
-
Class
B
6
*
Douglas
L. Anderson
Class
A
3
*
Class
B
-
-
Warren
E. Buffett (5)
Class
A
350,000
32.36
%
Class
B
2,564,355
18.30
%
Patrick
J. Goodman
Class
A
2
*
Class
B
3
*
Marc
D. Hamburg
Class
A
-
-
Class
B
-
-
Maureen
E. Sammon
Class
A
-
-
Class
B
21
*
All
directors and executive officers as a group (8 persons)
Class
A
351,267
32.48
%
Class
B
2,564,488
18.30
%
*
Less than 1%
(1)
Unless
otherwise indicated, each address is c/o MidAmerican Energy Holdings
Company 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)
Does
not include 10 Class A shares owned by Mr. Scott’s wife. Mr. Scott’s
address is 1000 Kiewit Plaza, Omaha, Nebraska68131.
(4)
In
accordance with a shareholders agreement, as amended on December 7, 2005,
based on an assumed value for our common stock and the closing price of
Berkshire Hathaway common stock on January 31, 2008, Mr. Scott and the
Scott Family Interests and Messrs. Sokol and Abel would be entitled to
exchange their shares of our common stock and their shares acquired by
exercise of options to purchase our common stock for either 12,661, 848
and 1,158, respectively, shares of Berkshire Hathaway Class A stock or
378,461, 25,351 and 34,615, respectively, shares of Berkshire Hathaway
Class B stock. Assuming an exchange of all available MEHC shares into
either Berkshire Hathaway Class A shares or Berkshire Hathaway Class B
shares, Mr. Scott and the Scott Family Interests would beneficially own
1.17% of the outstanding shares of Berkshire Hathaway Class A stock or
2.63% of the outstanding shares of Berkshire Hathaway Class B stock, and
each of Messrs. Sokol and Abel would beneficially own less than 1% of
the outstanding shares of either class of stock. On January 24, 2008,
Mr. Sokol exchanged 629,931 shares of our common stock for 955 Berkshire
Hathaway Class A shares and three Berkshire Hathaway Class B
shares.
Mr. Sokol’s
employment agreement gives him the right during the term of his employment to
serve as a member of the Board of Directors and to nominate two additional
directors.
Pursuant
to a shareholders agreement, as amended on December 7, 2005, Mr. Scott or
any of the Scott Family Interests and Messrs. Sokol and Abel are able to
require Berkshire Hathaway to exchange any or all of their respective shares of
our common stock for shares of Berkshire Hathaway common stock. The number of
shares of Berkshire Hathaway stock to be exchanged is based on the fair market
value of our common stock divided by the closing price of the Berkshire Hathaway
stock on the day prior to the date of exchange.
The
Berkshire Hathaway Inc. Code of Business Conduct and Ethics and the MEHC Code of
Business Conduct, or the Codes, which apply to all of our directors, officers
and employees and those of our subsidiaries, generally govern the review,
approval or ratification of any related-person transaction. A related-person
transaction is one in which we or any of our subsidiaries participate and in
which one or more of our directors, executive officers, holders of more than
five percent of our voting securities or any of such persons’ immediate family
members have a direct or indirect material interest.
Under the
Codes, all of our directors and executive officers (including those of our
subsidiaries) must disclose to our legal department any material transaction or
relationship that reasonably could be expected to give rise to a conflict with
our interests. No action may be taken with respect to such transaction or
relationship until approved by the legal department. For our chief executive
officer and chief financial officer, prior approval for any such transaction or
relationship must be given by Berkshire Hathaway’s audit committee. In addition,
prior legal department approval must be obtained before a director or executive
officer can accept employment, offices or board positions in other for-profit
businesses, or engage in his or her own business that raises a potential
conflict or appearance of conflict with our interests. Transactions with
Berkshire Hathaway require the approval of our Board of Directors.
Under a
subscription agreement with us, which expired in March 2007, Berkshire Hathaway
had agreed to purchase, under certain circumstances, additional shares of 11%
trust issued mandatorily redeemable preferred securities to be issued by our
wholly owned subsidiary trust in the event that certain of our other outstanding
trust preferred securities, which were outstanding prior to the closing of our
acquisition by a private investor group on March 14, 2000, were tendered
for conversion to cash by the current holders.
At
December 31, 2007 and 2006, Berkshire Hathaway and its affiliates held 11%
mandatorily redeemable preferred securities due from certain of our wholly owned
subsidiary trusts with liquidation preferences of $821 million and
$1.06 billion, respectively. Principal repayments and interest expense on
these securities totaled $234 million and $108 million, respectively,
during 2007.
On
November 12, 2007, we issued 370,000 shares of our common stock, no par
value, to Mr. Abel upon the exercise by Mr. Abel of 370,000 of his
outstanding common stock options. The common stock options were exercisable at a
weighted-average price of $26.99 per share and the aggregate exercise price paid
by Mr. Abel was $10 million. This issuance was pursuant to a private
placement and was exempt from the registration requirements of the Securities
Act of 1933, as amended.
Director
Independence
Based on
the standards of the New York Stock Exchange, Inc., on which the common stock of
our majority owner, Berkshire Hathaway, is listed, our Board of Directors has
determined that none of our directors are considered independent because of
their employment by Berkshire Hathaway or MEHC or their ownership of our common
stock.
The
following table shows the Company’s fees paid or accrued for audit and
audit-related services and fees paid for tax and all other services rendered by
Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and
their respective affiliates (collectively, the “Deloitte Entities”) for each of
the last two years (in millions):
2007
2006
Audit
Fees(1)
$
5.3
$
4.8
Audit-Related
Fees(2)
0.5
0.8
Tax
Fees(3)
0.3
0.3
All
Other Fees
-
-
Total
aggregate fees billed
$
6.1
$
5.9
(1)
Audit
fees include fees for the audit of the Company’s consolidated financial
statements and interim reviews of the Company’s quarterly financial
statements, audit services provided in connection with required statutory
audits of certain of MEHC’s subsidiaries and comfort letters, consents and
other services related to SEC matters.
(2)
Audit-related
fees primarily include fees for assurance and related services for any
other statutory or regulatory requirements, audits of certain subsidiary
employee benefit plans and consultations on various accounting and
reporting matters.
(3)
Tax
fees include fees for services relating to tax compliance, tax planning
and tax advice. These services include assistance regarding federal, state
and international tax compliance, tax return preparation and tax
audits.
The audit
committee reviewed and approved the services rendered by the Deloitte Entities
in and for fiscal 2007 as set forth in the above table and concluded that the
non-audit 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 require the approval in
advance by the audit committee in order 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 Policy
does not delegate the audit committee’s responsibilities to pre-approve services
performed by the principal accountant to management.
Reserves
Deducted From Assets To Which They Apply:
Reserve
for uncollectible accounts receivable:
Year
ended 2007
$
30
$
24
$
-
$
(32
)
$
22
Year
ended 2006
21
19
11
(21
)
30
Year
ended 2005
26
13
-
(18
)
21
Reserves
Not Deducted From Assets(2):
Year
ended 2007
$
12
$
3
$
-
$
(3
)
$
12
Year
ended 2006
12
3
-
(3
)
12
Year
ended 2005
11
4
-
(3
)
12
The notes
to the consolidated MEHC financial statements are an integral part of this
financial statement schedule.
(1)
Acquisition
reserves represent the reserves recorded at PacifiCorp at the date of
acquisition.
(2)
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 29th day of
February 2008.
MIDAMERICAN
ENERGY HOLDINGS COMPANY
/s/ David
L. Sokol*
David
L. Sokol
Chairman
of the Board and Chief Executive Officer
(principal
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.
SUPPLEMENTAL
INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF
THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION
12 OF THE ACT
No annual
report to security holders covering MidAmerican Energy Holdings Company’s last
fiscal year or proxy material has been sent to security holders.
Amended
and Restated Bylaws of MidAmerican Energy Holdings Company (incorporated
by reference to Exhibit 3.2 to the MidAmerican Energy Holdings Company
Annual Report on Form 10-K for the year ended December 31,2005).
4.1
Indenture,
dated as of October 4, 2002, by and between MidAmerican Energy
Holdings Company and The Bank of New York, Trustee, relating to the 5.875%
Senior Notes due 2012 (incorporated by reference to Exhibit 4.1 to the
MidAmerican Energy Holdings Company Registration Statement No. 333-101699
dated December 6, 2002).
4.2
First
Supplemental Indenture, dated as of October 4, 2002, by and between
MidAmerican Energy Holdings Company and The Bank of New York, Trustee,
relating to the 5.875% Senior Notes due 2012 (incorporated by reference to
Exhibit 4.2 to the MidAmerican Energy Holdings Company Registration
Statement No. 333-101699 dated December 6, 2002).
4.3
Second
Supplemental Indenture, dated as of May 16, 2003, by and between
MidAmerican Energy Holdings Company and The Bank of New York, Trustee,
relating to the 3.50% Senior Notes due 2008 (incorporated by reference to
Exhibit 4.3 to the MidAmerican Energy Holdings Company’s Registration
Statement No. 333-105690 dated May 23, 2003).
4.4
Third
Supplemental Indenture, dated as of February 12, 2004, by and between
MidAmerican Energy Holdings Company and The Bank of New York, Trustee,
relating to the 5.00% Senior Notes due 2014 (incorporated by reference to
Exhibit 4.4 to the MidAmerican Energy Holdings Company Registration
Statement No. 333-113022 dated February 23, 2004).
4.5
Fourth
Supplemental Indenture, dated as of March 24, 2006, by and between
MidAmerican Energy Holdings Company and The Bank of New York Trust
Company, N.A., Trustee, relating to the 6.125% Senior Bonds due 2036
(incorporated by reference to Exhibit 4.1 to the MidAmerican Energy
Holdings Company Current Report on Form 8-K dated March 28,2006).
4.6
Fifth
Supplemental Indenture, dated as of May 11, 2007, by and between
MidAmerican Energy Holdings Company and The Bank of New York Trust
Company, N.A., Trustee, relating to the 5.95% Senior Bonds due 2037
(incorporated by reference to Exhibit 4.1 to the MidAmerican Energy
Holdings Company Current Report on Form 8-K dated May 11,2007).
4.7
Sixth
Supplemental Indenture, dated as of August 28, 2007, by and between
MidAmerican Energy Holdings Company and The Bank of New York Trust
Company, N.A., Trustee, relating to the 6.50% Senior Bonds due 2037
(incorporated by reference to Exhibit 4.1 to the MidAmerican Energy
Holdings Company Current Report on Form 8-K dated August 28,2007).
4.8
Indenture
dated as of February 26, 1997, by and between MidAmerican Energy
Holdings Company and the Bank of New York, Trustee relating to the 6¼%
Convertible Junior Subordinated Debentures due 2012 (incorporated by
reference to Exhibit 10.129 to the MidAmerican Energy Holdings Company
Annual Report on Form 10-K for the year ended December 31,1995).
4.9
Indenture,
dated as of October 15, 1997, by and between MidAmerican Energy
Holdings Company and IBJ Schroder Bank & Trust Company, Trustee
(incorporated by reference to Exhibit 4.1 to the MidAmerican Energy
Holdings Company Current Report on Form 8-K dated October 23,1997).
156
Exhibit
No.
4.10
Form
of Second Supplemental Indenture, dated as of September 22, 1998 by
and between MidAmerican Energy Holdings Company and IBJ Schroder Bank
& Trust Company, Trustee, relating to the 7.52% Senior Notes in the
principal amount of $450,000,000 due 2008, and the 8.48% Senior Notes in
the principal amount of $475,000,000 due 2028 (incorporated by reference
to Exhibit 4.1 to the MidAmerican Energy Holdings Company Current Report
on Form 8-K dated September 17, 1998).
4.11
Form
of Third Supplemental Indenture, dated as of November 13, 1998, by
and between MidAmerican Energy Holdings Company and IBJ Schroder Bank
& Trust Company, Trustee, relating to the 7.52% Senior Notes in the
principal amount of $100,000,000 due 2008 (incorporated by reference to
the MidAmerican Energy Holdings Company Current Report on Form 8-K dated
November 10, 1998).
4.12
Indenture,
dated as of March 14, 2000, by and between MidAmerican Energy
Holdings Company and the Bank of New York, Trustee (incorporated by
reference to Exhibit 4.9 to the MidAmerican Energy Holdings Company Annual
Report on Form 10-K/A for the year ended December 31,1999).
4.13
Indenture,
dated as of March 12, 2002, by and between MidAmerican Energy
Holdings Company and the Bank of New York, Trustee (incorporated by
reference to Exhibit 4.11 to the MidAmerican Energy Holdings Company
Annual Report on Form 10-K for the year ended December 31,2001).
Indenture,
dated as of August 16, 2002, by and between MidAmerican Energy
Holdings Company and the Bank of New York, Trustee (incorporated by
reference to Exhibit 4.17 to the MidAmerican Energy Holdings Company
Registration Statement No. 333-101699 dated December 6,2002).
4.18
Amended
and Restated Credit Agreement, dated as of July 6, 2006, by and among
MidAmerican Energy Holdings Company, as Borrower, The Banks and Other
Financial Institutions Parties Hereto, as Banks, JPMorgan Chase Bank,
N.A., as L/C Issuer, Union Bank of California, N.A., as Administrative
Agent, The Royal Bank of Scotland PLC, as Syndication Agent, and ABN Amro
Bank N.V., JPMorgan Chase Bank, N.A. and BNP Paribas as Co-Documentation
Agents (incorporated by reference to Exhibit 99.1 to the MidAmerican
Energy Holdings Company Quarterly Report on Form 10-Q for the quarter
ended June 30, 2006).
4.19
Trust
Indenture, dated as of November 27, 1995, by and between CE Casecnan
Water and Energy Company, Inc. and Chemical Trust Company of California,
Trustee (incorporated by reference to Exhibit 4.1 to the CE Casecnan Water
and Energy Company, Inc. Registration Statement on Form S-4 dated
January 25, 1996).
4.20
Indenture
and First Supplemental Indenture, dated March 11, 1999, by and
between MidAmerican Funding, LLC and IBJ Whitehall Bank & Trust
Company, Trustee, relating to the $700 million Senior Notes and Bonds
(incorporated by reference to the MidAmerican Energy Holdings Company
Annual Report on Form 10-K for the year ended December 31,1998).
4.21
Second
Supplemental Indenture, dated as of March 1, 2001, by and between
MidAmerican Funding, LLC and The Bank of New York, Trustee (incorporated
by reference to Exhibit 4.4 to the MidAmerican Funding, LLC Registration
Statement on Form S-3, Registration No. 333-56624).
157
Exhibit
No.
4.22
General
Mortgage Indenture and Deed of Trust, dated as of January 1, 1993, by
and between Midwest Power Systems Inc. and Morgan Guaranty Trust Company
of New York, Trustee (incorporated by reference to Exhibit 4(b)-1 to the
Midwest Resources Inc. Annual Report on Form 10-K for the year ended
December 31, 1992, Commission File No. 1-10654).
4.23
First
Supplemental Indenture, dated as of January 1, 1993, by and between
Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York,
Trustee (incorporated by reference to Exhibit 4(b)-2 to the Midwest
Resources Inc. Annual Report on Form 10-K for the year ended
December 31, 1992, Commission File No. 1-10654).
4.24
Second
Supplemental Indenture, dated as of January 15, 1993, by and between
Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York,
Trustee (incorporated by reference to Exhibit 4(b)-3 to the Midwest
Resources Inc. Annual Report on Form 10-K for the year ended
December 31, 1992, Commission File No. 1-10654).
4.25
Third
Supplemental Indenture, dated as of May 1, 1993, by and between
Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York,
Trustee (incorporated by reference to Exhibit 4.4 to the Midwest Resources
Inc. Annual Report on Form 10-K for the year ended December 31, 1993,
Commission File No. 1-10654).
4.26
Fourth
Supplemental Indenture, dated as of October 1, 1994, by and between
Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee
(incorporated by reference to Exhibit 4.5 to the Midwest Resources Inc.
Annual Report on Form 10-K for the year ended December 31, 1994,
Commission File No. 1-10654).
4.27
Fifth
Supplemental Indenture, dated as of November 1, 1994, by and between
Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee
(incorporated by reference to Exhibit 4.6 to the Midwest Resources Inc.
Annual Report on Form 10-K for the year ended December 31, 1994,
Commission File No. 1-10654).
4.28
Sixth
Supplemental Indenture, dated as of July 1, 1995, by and between
Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee
(incorporated by reference to Exhibit 4.15 to the MidAmerican Energy
Company Annual Report on Form 10-K for the year ended December 31,1995, Commission File No. 1-11505).
4.29
Indenture
dated as of December 1, 1996, by and between MidAmerican Energy
Company and the First National Bank of Chicago, Trustee (incorporated by
reference to Exhibit 4(1) to the MidAmerican Energy Company Registration
Statement on Form S-3, Registration No. 333-15387).
4.30
First
Supplemental Indenture, dated as of February 8, 2002, by and between
MidAmerican Energy Company and The Bank of New York, Trustee (incorporated
by reference to Exhibit 4.3 to the MidAmerican Energy Company Annual
Report on Form 10-K for the year ended December 31, 2004, Commission
File No. 333-15387).
4.31
Second
Supplemental Indenture, dated as of January 14, 2003, by and between
MidAmerican Energy Company and The Bank of New York, Trustee (incorporated
by reference to Exhibit 4.2 to the MidAmerican Energy Company Annual
Report on Form 10-K for the year ended December 31, 2004, Commission
File No. 333-15387).
4.32
Third
Supplemental Indenture, dated as of October 1, 2004, by and between
MidAmerican Energy Company and The Bank of New York, Trustee (incorporated
by reference to Exhibit 4.1 to the MidAmerican Energy Company Annual
Report on Form 10-K for the year ended December 31, 2004, Commission
File No. 333-15387).
158
Exhibit
No.
4.33
Fourth
Supplemental Indenture, dated November 1, 2005, by and between
MidAmerican Energy Company and the Bank of New York Trust Company, NA,
Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican
Energy Company Annual Report on Form 10-K for the year ended
December 31, 2005).
4.34
Fiscal
Agency Agreement, dated as of October 15, 2002, by and between
Northern Natural Gas Company and J.P. Morgan Trust Company, National
Association, Fiscal Agent, relating to the $300,000,000 in principal
amount of the 5.375% Senior Notes due 2012 (incorporated by reference to
Exhibit 10.47 to the MidAmerican Energy Holdings Company Annual Report on
Form 10-K for the year ended December 31, 2003).
4.35
Trust
Indenture, dated as of August 13, 2001, among Kern River Funding
Corporation, Kern River Gas Transmission Company and JP Morgan Chase Bank,
Trustee, relating to the $510,000,000 in principal amount of the 6.676%
Senior Notes due 2016 (incorporated by reference to Exhibit 10.48 to the
MidAmerican Energy Holdings Company Annual Report on Form 10-K for the
year ended December 31, 2003).
4.36
Third
Supplemental Indenture, dated as of May 1, 2003, among Kern River
Funding Corporation, Kern River Gas Transmission Company and JPMorgan
Chase Bank, Trustee, relating to the $836,000,000 in principal amount of
the 4.893% Senior Notes due 2018 (incorporated by reference to Exhibit
10.49 to the MidAmerican Energy Holdings Company Annual Report on Form
10-K for the year ended December 31, 2003).
4.37
Trust
Deed, dated December 15, 1997 among CE Electric UK Funding Company,
AMBAC Insurance UK Limited and The Law Debenture Trust Corporation,
p.l.c., Trustee (incorporated by reference to Exhibit 99.1 to the
MidAmerican Energy Holdings Company Current Report on Form 8-K dated
March 30, 2004).
4.38
Insurance
and Indemnity Agreement, dated December 15, 1997 by and between CE
Electric UK Funding Company and AMBAC Insurance UK Limited (incorporated
by reference to Exhibit 99.2 to the MidAmerican Energy Holdings Company
Current Report on Form 8-K dated March 30, 2004).
4.39
Supplemental
Agreement to Insurance and Indemnity Agreement, dated September 19,2001, by and between CE Electric UK Funding Company and AMBAC Insurance UK
Limited (incorporated by reference to Exhibit 99.3 to the MidAmerican
Energy Holdings Company Current Report on Form 8-K dated March 30,2004).
4.40
Fiscal
Agency Agreement, dated as of September 4, 1998, by and between
Northern Natural Gas Company and Chase Bank of Texas, National
Association, Fiscal Agent, relating to the $150,000,000 in principal
amount of the 6.75% Senior Notes due 2008 (incorporated by reference to
Exhibit 10.69 to the MidAmerican Energy Holdings Company Quarterly Report
on Form 10-Q for the quarter ended March 31, 2004).
4.41
Fiscal
Agency Agreement, dated as of May 24, 1999, by and between Northern
Natural Gas Company and Chase Bank of Texas, National Association, Fiscal
Agent, relating to the $250,000,000 in principal amount of the 7.00%
Senior Notes due 2011 (incorporated by reference to Exhibit 10.70 to the
MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the
quarter ended March 31, 2004).
4.42
Trust
Indenture, dated as of September 10, 1999, by and between Cordova
Funding Corporation and Chase Manhattan Bank and Trust Company, National
Association, Trustee, relating to the $225,000,000 in principal amount of
the 8.75% Senior Secured Bonds due 2019 (incorporated by reference to
Exhibit 10.71 to the MidAmerican Energy Holdings Company Quarterly Report
on Form 10-Q for the quarter ended March 31, 2004).
4.43
Trust
Deed, dated as of February 4, 1998 among Yorkshire Power Finance
Limited, Yorkshire Power Group Limited and Bankers Trustee Company
Limited, Trustee, relating to the £200,000,000 in principal amount of the
7.25% Guaranteed Bonds due 2028 (incorporated by reference to Exhibit
10.74 to the MidAmerican Energy Holdings Company Quarterly Report on Form
10-Q for the quarter ended March 31, 2004).
159
Exhibit
No.
4.44
First
Supplemental Trust Deed, dated as of October 1, 2001, among Yorkshire
Power Finance Limited, Yorkshire Power Group Limited and Bankers Trustee
Company Limited, Trustee, relating to the £200,000,000 in principal amount
of the 7.25% Guaranteed Bonds due 2028 (incorporated by reference to
Exhibit 10.75 to the MidAmerican Energy Holdings Company Quarterly Report
on Form 10-Q for the quarter ended March 31, 2004).
4.45
Third
Supplemental Trust Deed, dated as of October 1, 2001, among Yorkshire
Electricity Distribution plc, Yorkshire Electricity Group plc and Bankers
Trustee Company Limited, Trustee, relating to the £200,000,000 in
principal amount of the 9.25% Bonds due 2020 (incorporated by reference to
Exhibit 10.76 to the MidAmerican Energy Holdings Company Quarterly Report
on Form 10-Q for the quarter ended March 31, 2004).
4.46
Indenture,
dated as of February 1, 2000, among Yorkshire Power Finance 2
Limited, Yorkshire Power Group Limited and The Bank of New York, Trustee
(incorporated by reference to Exhibit 10.78 to the MidAmerican Energy
Holdings Company Quarterly Report on Form 10-Q for the quarter ended
March 31, 2004).
4.47
First
Supplemental Trust Deed, dated as of September 27, 2001, among
Northern Electric Finance plc, Northern Electric plc, Northern Electric
Distribution Limited and The Law Debenture Trust Corporation p.l.c.,
Trustee, relating to the £100,000,000 in principal amount of the 8.875%
Guaranteed Bonds due 2020 (incorporated by reference to Exhibit 10.81 to
the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for
the quarter ended March 31, 2004).
4.48
Trust
Deed, dated as of January 17, 1995, by and between Yorkshire
Electricity Group plc and Bankers Trustee Company Limited, Trustee,
relating to the £200,000,000 in principal amount of the 9 1/4% Bonds due
2020 (incorporated by reference to Exhibit 10.83 to the MidAmerican Energy
Holdings Company Quarterly Report on Form 10-Q for the quarter ended
March 31, 2004).
4.49
Master
Trust Deed, dated as of October 16, 1995, by and between Northern
Electric Finance plc, Northern Electric plc and The Law Debenture Trust
Corporation p.l.c., Trustee, relating to the £100,000,000 in principal
amount of the 8.875% Guaranteed Bonds due 2020 (incorporated by reference
to Exhibit 10.70 to the MidAmerican Energy Holdings Company Annual Report
on Form 10-K for the year ended December 31, 2004).
4.50
Fiscal
Agency Agreement, dated April 14, 2005, by and between Northern
Natural Gas Company and J.P. Morgan Trust Company, National Association,
Fiscal Agent, relating to the $100,000,000 in principal amount of the
5.125% Senior Notes due 2015 (incorporated by reference to Exhibit 99.1 to
the MidAmerican Energy Holdings Company Current Report on Form 8-K dated
April 18, 2005).
4.51
£100,000,000
Facility Agreement, dated April 4, 2005 among CE Electric UK Funding
Company, the subsidiaries of CE Electric UK Funding Company listed in Part
1 of Schedule 1, Lloyds TSB Bank plc and The Royal Bank of Scotland plc
(incorporated by reference to Exhibit 99.1 to the MidAmerican Energy
Holdings Company Current Report on Form 8-K dated April 20,2005).
4.52
Trust
Deed dated May 5, 2005 among Northern Electric Finance plc, Northern
Electric Distribution Limited, Ambac Assurance UK Limited and HSBC Trustee
(C.I.) Limited (incorporated by reference to Exhibit 99.1 to the
MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the
quarter ended March 31, 2005).
4.53
Reimbursement
and Indemnity Agreement dated May 5, 2005 among Northern Electric
Finance plc, Northern Electric Distribution Limited and Ambac Assurance UK
Limited (incorporated by reference to Exhibit 99.2 to the MidAmerican
Energy Holdings Company Quarterly Report on Form 10-Q for the quarter
ended March 31, 2005).
160
Exhibit
No.
4.54
Trust
Deed, dated May 5, 2005 among Yorkshire Electricity Distribution plc,
Ambac Assurance UK Limited and HSBC Trustee (C.I.) Limited (incorporated
by reference to Exhibit 99.3 to the MidAmerican Energy Holdings Company
Quarterly Report on Form 10-Q for the quarter ended March 31,2005).
4.55
Reimbursement
and Indemnity Agreement, dated May 5, 2005 between Yorkshire
Electricity Distribution plc and Ambac Assurance UK Limited (incorporated
by reference to Exhibit 99.4 to the MidAmerican Energy Holdings Company
Quarterly Report on Form 10-Q for the quarter ended March 31,2005).
4.56
Supplemental
Trust Deed, dated May 5, 2005 among CE Electric UK Funding Company,
Ambac Assurance UK Limited and The Law Debenture Trust Corporation plc
(incorporated by reference to Exhibit 99.5 to the MidAmerican Energy
Holdings Company Quarterly Report on Form 10-Q for the quarter ended
March 31, 2005).
4.57
Second
Supplemental Agreement to Insurance and Indemnity Agreement, dated
May 5, 2005 by and between CE Electric UK Funding Company and Ambac
Assurance UK Limited (incorporated by reference to Exhibit 99.6 to the
MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the
quarter ended March 31, 2005).
4.58
Amended
and Restated Credit Agreement, dated as of July 6, 2006, among
MidAmerican Energy Company, the Lending Institutions Party Hereto, as
Banks, Union Bank of California, N.A., as Syndication Agent, JPMorgan
Chase Bank, N.A.., as Administrative Agent, and The Royal Bank of Scotland
plc, ABN AMRO Bank N.V. and BNP Paribas as Co-Documentation Agents
(incorporated by reference to Exhibit 10.1 to the MidAmerican Energy
Company Quarterly Report on Form 10-Q for the quarter ended June 30,2006).
Amendment
No. 1 to Shareholders Agreement, dated December 7, 2005 (incorporated
by reference to Exhibit 4.17 to the MidAmerican Energy Holdings Company
Annual Report on Form 10-K for the year ended December 31,2005).
4.61
Equity
Commitment Agreement, dated as of March 1, 2006, by and between Berkshire
Hathaway Inc. and MidAmerican Energy Holdings Company (incorporated by
reference to Exhibit 10.72 to the MidAmerican Energy Holdings Company
Annual Report on Form 10-K for the year ended December 31,2005).
4.62
Fiscal
Agency Agreement, dated February 12, 2007, by and between Northern Natural
Gas Company and Bank of New York Trust Company, N.A., Fiscal Agent,
relating to the $150,000,000 in principal amount of the 5.80% Senior Bonds
due 2037 (incorporated by reference to Exhibit 99.1 to the MidAmerican
Energy Holdings Company Current Report on Form 8-K dated February 12,2007).
4.63
Indenture,
dated as of October 1, 2006, by and between MidAmerican Energy
Company and the Bank of New York Trust Company, N.A., Trustee
(incorporated by reference to Exhibit 4.1 to the MidAmerican Energy
Company Quarterly Report on Form 10-Q for the quarter ended
September 30, 2006).
4.64
First
Supplemental Indenture, dated as of October 6, 2006, by and between
MidAmerican Energy Company and the Bank of New York Trust Company, N.A.,
Trustee (incorporated by reference to Exhibit 4.2 to the MidAmerican
Energy Company Quarterly Report on Form 10-Q for the quarter ended
September 30, 2006).
4.65
Second
Supplemental Indenture, dated June 29, 2007, by and between
MidAmerican Energy Company and The Bank of New York Trust Company, N.A.,
Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican
Energy Company Current Report on Form 8-K dated June 29,2007).
161
Exhibit
No.
4.66
Mortgage
and Deed of Trust dated as of January 9, 1989, between PacifiCorp and
JP Morgan Chase Bank (formerly known as The Chase Manhattan Bank),
Trustee, incorporated by reference to Exhibit 4-E to PacifiCorp’s Form
8-B, File No. 1-5152, as supplemented and modified by 21 Supplemental
Indentures, each incorporated by reference, as follows:
$700,000,000
Credit Agreement dated as of October 23, 2007 among PacifiCorp, The
Banks Party thereto, The Royal Bank of Scotland plc, as Syndication Agent,
and Union Bank of California, N.A., as Administrative Agent (incorporated
by reference to Exhibit 99 to the PacifiCorp Quarterly Report on
Form 10-Q for the quarter ended September 30,2007).
10.1
Amended
and Restated Employment Agreement, dated February 25, 2008, by and
between MidAmerican Energy Holdings Company and David L.
Sokol.
Amended
and Restated Employment Agreement, dated February 25, 2008, by and
between MidAmerican Energy Holdings Company and Patrick J.
Goodman.
10.6
Amended
and Restated Casecnan Project Agreement, dated June 26, 1995, between
the National Irrigation Administration and CE Casecnan Water and Energy
Company Inc. (incorporated by reference to Exhibit 10.1 to the CE Casecnan
Water and Energy Company, Inc. Registration Statement on Form S-4 dated
January 25, 1996).
10.7
Supplemental
Agreement, dated as of September 29, 2003, by and between CE Casecnan
Water and Energy Company, Inc. and the Philippines National Irrigation
Administration (incorporated by reference to Exhibit 98.1 to the
MidAmerican Energy Holdings Company Current Report on Form 8-K dated
October 15, 2003).
10.8
CalEnergy
Company, Inc. Voluntary Deferred Compensation Plan, effective
December 1, 1997, First Amendment, dated as of August 17, 1999,
and Second Amendment effective March 14, 2000 (incorporated by
reference to Exhibit 10.50 to the MidAmerican Energy Holdings Company
Registration Statement No. 333-101699 dated December 6,2002).
10.9
MidAmerican
Energy Holdings Company Executive Voluntary Deferred Compensation Plan
restated effective as of January 1, 2007.
10.10
MidAmerican
Energy Company First Amended and Restated Supplemental Retirement Plan for
Designated Officers dated as of May 10, 1999 amended on
February 25, 2008 to be effective as of January 1,2005.
10.11
MidAmerican
Energy Holdings Company Long-Term Incentive Partnership Plan as Amended
and Restated January 1, 2007.
10.12
Summary
of Key Terms of Compensation Arrangements with MidAmerican Energy Holdings
Company Named Executive Officers and Directors.
14.1
MidAmerican
Energy Holdings Company Code of Ethics for Chief Executive Officer, Chief
Financial Officer and Other Covered Officers (incorporated by reference to
Exhibit 14.1 to the MidAmerican Energy Holdings Company Annual Report on
Form 10-K for the year ended December 31, 2003).
No
T