UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
Annual Report Pursuant to Section 13 or 15 (d) of
the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2002
MIDAMERICAN ENERGY HOLDINGS COMPANY
(Exact name of registrant as specified in its charter)
Iowa 94-2213782
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
666 Grand Avenue, Des Moines, IA 50309
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (515) 242-4300
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Securities registered pursuant to Section 12(b) of the Act: N/A
Securities registered pursuant to Section 12(g) of the Act: N/A
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein and will not be contained, to the best
of each of the registrants' knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Act). Yes [ ] No [X]
All of the shares of MidAmerican Energy Holdings Company are held by a limited
group of private investors. As of March 31, 2003, 9,281,087 shares of common
stock were outstanding.
TABLE OF CONTENTS
PART I
Item 1. Business.......................................................... 3
Item 2. Properties........................................................ 30
Item 3. Legal Proceedings................................................. 32
Item 4. Submission of Matters to a Vote of Security Holders............... 34
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters............................................. 35
Item 6. Selected Financial Data........................................... 36
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations....................................... 37
Item 7A. Quantitative and Qualitative Disclosures About Market Risk........ 49
Item 8. Financial Statements and Supplementary Data....................... 50
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure........................................ 96
PART III
Item 10. Directors and Executive Officers of the Registrant................ 97
Item 11. Executive Compensation............................................ 99
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters......................103
Item 13. Certain Relationships and Related Transactions....................104
Item 14. Controls and Procedures...........................................105
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K...106
SIGNATURES ..................................................................111
CERTIFICATIONS...............................................................113
Exhibit Index................................................................115
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PART I
ITEM 1. BUSINESS.
GENERAL
MidAmerican Energy Holdings Company and its subsidiaries (the "Company" or
"MEHC") is a United States-based privately owned global energy company. The
Company's subsidiaries' principal businesses are regulated electric and natural
gas utilities, regulated interstate natural gas transmission and electric power
generation. Its operations are organized and managed on seven distinct
platforms: MidAmerican Energy Company ("MidAmerican Energy"), Kern River Gas
Transmission Company ("Kern River"), Northern Natural Gas Company ("Northern
Natural Gas"), CE Electric UK Funding ("CE Electric UK") (which includes
Northern Electric plc ("Northern Electric") and Yorkshire Power Group Ltd.
("Yorkshire")), CalEnergy Generation - Domestic, CalEnergy Generation-Foreign
(the Upper Mahiao, Malitbog and Mahanagdong Projects (collectively the "Leyte
Projects") and the Casecnan Project) and HomeServices of America, Inc.
("HomeServices"). Through six of these platforms, the Company owns and operates
a combined electric and natural gas utility company in the United States, two
natural gas pipeline companies in the United States, two electricity
distribution companies in the United Kingdom, and a diversified portfolio of
domestic and international independent power projects. The Company also owns the
second largest residential real estate brokerage firm in the United States.
The Company's principal subsidiaries generate, transmit, store, distribute and
supply energy. The Company's electric and natural gas utility subsidiaries
currently serve approximately 4.3 million electricity customers and
approximately 660,000 natural gas customers. Its natural gas pipeline
subsidiaries operate interstate natural gas transmission systems with
approximately 17,500 miles of pipeline in operation and peak delivery capacity
of 5.3 Bcf of natural gas per day. The Company has interests in 6,191 net owned
MW of power generation facilities in operation and construction, including 4,618
net owned MW in facilities that are part of the regulated return asset base of
its electric utility business (as further described in "Business--MidAmerican
Energy--Electric Operations") and 1,573 net owned MW in non-utility power
generation facilities. Substantially all of the non-utility power generation
facilities have long-term contracts for the sale of energy and/or capacity from
the facilities.
On March 14, 2000, the Company and an investor group comprised of Berkshire
Hathaway Inc., Walter Scott, Jr., a Director of the Company, David L. Sokol,
Chairman and Chief Executive Officer of the Company, and Gregory E. Abel,
President and Chief Operating Officer of the Company, closed on a definitive
agreement and plan of merger whereby the investor group acquired all of the
outstanding common stock of the Company (the "Teton Transaction"). As a result
of the Teton Transaction, Berkshire Hathaway, Mr. Scott, Mr. Sokol and Mr. Abel
own approximately 9.7%, 86%, 3% and 1% of the voting stock respectively.
The principal executive offices of the Company are located at 666 Grand Avenue,
Des Moines, Iowa 50309 and its telephone number is (515) 242-4300. The Company
initially incorporated in 1971 under the laws of the State of Delaware and was
reincorporated in 1999 in Iowa, at which time it changed its name from CalEnergy
Company, Inc. to MidAmerican Energy Holdings Company.
In this Annual Report, references to "U.S. dollars," "dollars," "$" or "cents"
are to the currency of the United States, references to "pounds sterling,"
"(pound)," "sterling," "pence" or "p" are to the currency of the United Kingdom
and references to "pesos" are to the currency of the Philippines. References to
MW means megawatts, MWh means megawatt hours, Bcf means billion cubic feet, mmcf
means million cubic feet, GWh means gigawatts per hour, kV means 1000 volts, Tcf
means trillion cubic feet, kWh means kilowatt hours and MMBtus means million
British thermal units.
MIDAMERICAN ENERGY
MidAmerican Energy is the largest energy company headquartered in Iowa, with
$3.8 billion of assets as of December 31, 2002, and revenue for 2002 totaling
$2.2 billion. MidAmerican Energy is principally engaged in the business of
generating, transmitting, distributing and selling electric energy and in
distributing, selling and transporting natural gas. MidAmerican Energy
distributes electricity at retail in Council Bluffs, Des Moines, Fort Dodge,
Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities (Davenport and
Bettendorf, Iowa and Rock Island, Moline and East Moline, Illinois); and a
number of adjacent communities and areas. It also distributes natural gas at
retail in Cedar Rapids, Des Moines, Fort Dodge, Iowa City, Sioux City and
Waterloo, Iowa; the Quad Cities; Sioux Falls, South Dakota; and a number of
adjacent communities and areas. As of December 31, 2002, MidAmerican Energy had
approximately 681,000 retail electric customers and 660,000 retail natural gas
customers.
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In addition to retail sales, MidAmerican Energy sells electric energy and
natural gas to other utilities, marketers and municipalities outside of
MidAmerican Energy's delivery system. These sales are referred to as wholesale
sales. It also transports natural gas through its distribution system for a
number of end-use customers who have independently secured their supply of
natural gas.
MidAmerican Energy's regulated electric and gas operations are conducted under
franchises, certificates, permits and licenses obtained from state and local
authorities. The franchises, with various expiration dates, are typically for
25-year terms.
MidAmerican Energy has a diverse customer base consisting of residential,
agricultural and a variety of commercial and industrial customer groups. Among
the primary industries served by MidAmerican Energy are those that are concerned
with food products, the manufacturing, processing and fabrication of primary
metals, real estate, farm and other non-electrical machinery, and cement and
gypsum products.
For the year ended December 31, 2002, MidAmerican Energy derived approximately
61% of its gross operating revenues from its electric utility business, 31% from
its gas utility business and 8% from its non-regulated business activities. For
2001 and 2000, the corresponding percentages were 56% electric, 37% gas and 7%
non-regulated and 53% electric, 41% gas and 6% non-regulated, respectively. The
change in revenue mix is principally driven by changes in natural gas prices and
seasonality.
There are seasonal variations in MidAmerican Energy's electric and gas
businesses, which are principally related to the use of energy for air
conditioning and heating. In 2002, 41% of MidAmerican Energy's electric utility
revenues were reported in the months of June, July, August and September, and
47% of MidAmerican Energy's gas utility revenues were reported in the months of
January, February, March and December.
Electric Operations
The electric utility industry continues to undergo regulatory change.
Traditionally, prices charged by electric utility companies have been regulated
by federal and state commissions and have been based on cost of service. In
recent years, changes have been occurring that move the electric utility
industry toward a more competitive, market-based pricing environment. These
changes may have a significant impact on the way MidAmerican Energy does
business.
MidAmerican Energy manages its operations as four separate business units:
generation, energy delivery, transmission, and marketing and sales. The
generation segment derives most of its revenue from the sale of regulated
wholesale electricity and non-regulated wholesale and retail natural gas. The
energy delivery segment derives its revenue principally from the delivery of
regulated electricity and natural gas, while the transmission segment obtains
most of its revenue from the sale of transmission capacity. The marketing and
sales segment receives its revenue principally from non-regulated sales of
natural gas and electricity.
For the year ended December 31, 2002, regulated electric sales by MidAmerican
Energy by customer class were as follows: 19.8% were to residential customers,
14.2% were to small general service customers, 24.5% were to large general
service customers, 9.1% were to other customers, and 32.4% were wholesale sales.
For the year ended December 31, 2002, regulated electric sales by MidAmerican
Energy by jurisdiction were as follows: 88.5% to Iowa, 10.7% to Illinois and
0.8% to South Dakota.
The annual hourly peak demand on MidAmerican Energy's electric system occurs
principally as a result of air conditioning use during the cooling season. In
July 2002, MidAmerican Energy recorded an hourly peak demand of 3,889 MW, which
was 56 MW greater than MidAmerican Energy's previous record hourly peak of 3,833
MW set in 1999.
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The following table sets out certain information concerning MidAmerican Energy's
power generation facilities based upon summer 2002 accreditation:
FACILITY NET
CAPACITY NET MW COMMERCIAL
OPERATING PROJECT (1) (MW)(2) OWNED(2) FUEL LOCATION OPERATION
- ------------------------------------------ ------------ ------- -------- -------- ----------
COAL FACILITIES:
Council Bluffs Energy Center Units 1 & 2 133 133 Coal Iowa 1954, 1958
Council Bluffs Energy Center Unit 3 .... 690 546 Coal Iowa 1978
Louisa Generation Station .............. 700 616 Coal Iowa 1983
Neal Generation Station Units 1 & 2 .... 435 435 Coal Iowa 1964, 1972
Neal Generation Station Unit 3 ......... 515 371 Coal Iowa 1975
Neal Generation Station Unit 4 ......... 644 261 Coal Iowa 1979
Ottumwa Generation Station ............. 708 368 Coal Iowa 1981
Riverside Generation Station ........... 135 135 Coal Iowa 1925-61
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Total coal facilities ................ 3,960 2,865
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OTHER FACILITIES:
Combustion Turbines .................... 785 785 Gas/Oil Iowa 1969-95
Moline Water Power ..................... 3 3 Hydro Illinois 1970
Quad Cities Generating Station ......... 1,636 409 Nuclear Illinois 1974
Portable Power Modules ................. 56 56 Oil Iowa 2000
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Total other facilities ............... 2,480 1,253
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ACCREDITED GENERATING CAPACITY ........... 6,440 4,118
Projects Under Construction -
Greater Des Moines Energy Center ....... 500 500 Gas Iowa 2003-05
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TOTAL POWER GENERATION CAPACITY .......... 6,940 4,618
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(1) MidAmerican Energy operates all such power generation facilities other than
Quad Cities Generating Station and Ottumwa Generation Station.
(2) Represents accredited net generating capability. Actual MW may vary
depending on operating conditions and plant design for operating projects.
Net MW owned indicates ownership of accredited capacity for the summer of
2002 as approved by the Mid- Continent Area Power Pool ("MAPP").
MidAmerican Energy's accredited net generating capability in the summer of 2002
was 4,724 MW. Accredited net generating capability represents the amount of
generation available to meet the requirements on MidAmerican Energy's system and
consists of MidAmerican Energy-owned generation of 4,118 MW, generation under
power purchase contracts of 630 MW and the net amount of capacity purchases and
sales of (24) MW. The net generating capability at any time may be less than it
would otherwise be due to regulatory restrictions, fuel restrictions and
generating units being temporarily out of service for inspection, maintenance,
refueling or modifications.
MidAmerican Energy plans to develop and construct three electric generating
projects in Iowa. The projects would provide service to regulated retail
electricity customers and be included in regulated rate base in Iowa, Illinois
and South Dakota. Wholesale sales may also be made from the projects to the
extent the power is not needed for regulated retail service.
The first project will be a 500-MW (based on expected accreditation) natural
gas-fired, combined cycle plant with an estimated cost of $415 million.
MidAmerican Energy will own 100% of the plant and operate it. The plant will be
operated in simple cycle mode during 2003 and 2004, resulting in 310 MW of
accredited capacity. The combined cycle operation will commence in 2005.
MidAmerican Energy has received a certificate from the Iowa Utilities Board
"(IUB") allowing it to construct the plant. In May 2002, the IUB issued an order
that specified the Iowa ratemaking principles that will apply to the plant over
its life. As a result of that order, MidAmerican Energy is proceeding with the
construction of the plant.
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The second project is currently under development and is expected to be a 790-MW
(based on expected accreditation) super-critical-temperature, coal-fired plant
fueled with low-sulfur coal. If constructed, MidAmerican Energy will operate the
plant and expects to own approximately 475 MW of the plant. Municipal,
cooperative and public power utilities will own the remainder, which is a
typical ownership arrangement for large base-load plants in Iowa. On January 23,
2003, MidAmerican Energy received an order approving the issuance of a
certificate from the IUB allowing it to construct the plant. MidAmerican Energy
has made a filing with the IUB for approval of Iowa ratemaking principles for
this second plant. The development of this plant is subject to obtaining
environmental and other required permits, as well as to receiving orders from
the IUB approving construction of the associated transmission facilities and
establishing ratemaking principles which are satisfactory to MidAmerican Energy.
The third project is currently under development and is expected to be wind
power facilities totaling 310 MW (nameplate rating). If constructed, MidAmerican
Energy will own and operate these facilities, which are expected to cost
approximately $323 million, plus associated transmission facilities. MidAmerican
Energy's plan to construct the wind project is in conjunction with a settlement
proposal to extend through December 31, 2010, a rate freeze that is currently
scheduled to expire at the end of 2005. The proposed settlement requires
enactment of Iowa legislation and is subject to approval by the IUB.
MidAmerican Energy is interconnected with Iowa utilities and utilities in
neighboring states and is involved in an electric power pooling agreement known
as 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 facilitates operation of the transmission system and is
responsible for the safety and reliability of the bulk electric system.
In November 2001, MAPPCOR, the contractor to MAPP, sold its transmission-related
assets to the Midwest Independent Transmission System Operator, Inc. ("Midwest
ISO"). The Midwest ISO now has responsibility for administration of MAPP's
Open-Access Transmission Tariff.
Each MAPP participant is required to maintain for emergency purposes a net
generating capability reserve of at least 15% above its system peak demand. If a
participant's capability reserve falls below the 15% minimum, significant
penalties could be contractually imposed by MAPP. MidAmerican Energy's reserve
margin at peak demand for 2002 was approximately 21%.
MidAmerican Energy's transmission system connects its generating facilities with
distribution substations and interconnects with 14 other transmission providers
in Iowa and five adjacent states. Under normal operating conditions, MidAmerican
Energy's transmission system is unconstrained and has adequate capacity to
deliver energy to MidAmerican Energy's distribution system and to export and
import energy with other interconnected systems.
In December 1999, the Federal Energy Regulatory Commission ("FERC") issued Order
No. 2000 establishing, among other things, minimum characteristics and functions
for regional transmission organizations. Public utilities that were not a member
of an independent system operator at the time of the order were required to
submit a plan by which its transmission facilities would be transferred to a
regional transmission organization. On September 28, 2001, MidAmerican Energy
and five other electric utilities filed with the FERC a plan to create TRANSLink
Transmission Company LLC ("TRANSLink") and to integrate their electric
transmission systems into a single, coordinated system operating as a for-profit
independent transmission company in conjunction with a FERC-approved regional
transmission organization. On April 25, 2002, the FERC issued an order approving
the transfer of control of MidAmerican Energy and other utilities' transmission
assets to TRANSLink in conjunction with TRANSLink's participation in the Midwest
ISO regional transmission organization. MidAmerican Energy has filed
applications for state regulatory approval from states in which TRANSLink will
be operating but does not anticipate rulings until late in 2003. Transferring
the operations and control of MidAmerican Energy's transmission assets to other
entities could increase costs for MidAmerican Energy; however, the actual impact
of TRANSLink on MidAmerican Energy's future transmission costs is not yet known.
On July 31, 2002, the FERC issued a notice of proposed rulemaking with respect
to Standard Market Design. The FERC has characterized the proposal as portending
"sweeping changes" to the use and expansion of the interstate transmission and
wholesale bulk power systems in the United States. The proposal includes
numerous proposed changes in the current regulation of transmission and
generation facilities designed "to promote economic efficiency" and replace the
"obsolete patchwork we have today," according to the FERC's chairman. The final
rule, if adopted as currently proposed, would require all public utilities
operating transmission facilities subject to the FERC jurisdiction to file
revised open access transmission tariffs that would require changes to the basic
services these public utilities currently provide. The
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proposed rule may impact the pricing of MidAmerican Energy's electricity and
transmission products. The FERC does not envision that a final rule will be
fully implemented until 2004. MidAmerican Energy is still evaluating the
proposed rule and recognizes the final rule could vary considerably from the
initial proposal. Accordingly, the likely impact of the proposed rule on
MidAmerican Energy's transmission and generation businesses is unknown.
Gas Operations
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For the year ended December 31, 2002, regulated gas sales by MidAmerican Energy,
excluding transportation throughput, by customer class were as follows: 39.0%
were to residential customers, 19.7% were to small general service customers,
1.5% were to large general service customers, 1.2% were to other customers, and
38.6% were wholesale sales. For the year ended December 31, 2002, regulated gas
sales by MidAmerican Energy, excluding transportation throughput, by
jurisdiction were as follows: 78.0% to Iowa, 11.2% to South Dakota, 10.0% to
Illinois, and 0.8% to Nebraska.
MidAmerican Energy purchases gas supplies from producers and third party
marketers. To ensure system reliability, a geographically diverse supply
portfolio with varying terms and contract conditions is utilized for the gas
supplies.
MidAmerican Energy has rights to firm pipeline capacity to transport gas to its
service territory through direct interconnects to the pipeline systems of
Northern Natural Gas, Natural Gas Pipeline Company of America, Northern Border
Pipeline Company and ANR Pipeline Company. Firm capacity in excess of
MidAmerican Energy's system needs, resulting from differences between the
capacity portfolio and seasonal system demand, can be resold to other companies
to achieve optimum use of the available capacity. Past IUB and South Dakota
Public Utilities Commission rulings have allowed MidAmerican Energy to retain
30% of Iowa and South Dakota margins, respectively, earned on the resold
capacity, with the remaining 70% being returned to customers through a purchased
gas adjustment clause as described below.
MidAmerican Energy's cost of gas is recovered from customers through purchased
gas adjustment clauses. In 1995, the IUB gave initial approval of MidAmerican
Energy's Incentive Gas Supply Procurement Program. Under the program, as
amended, MidAmerican Energy is required to file with the IUB every six months a
comparison of its gas procurement costs to an index-based and historical
reference price. If MidAmerican Energy's costs of gas for the period are less or
greater than an established tolerance band around the reference price, then
MidAmerican Energy shares a portion of the savings or costs with customers. In
October 2002, the IUB approved a one-year extension of the program through
October 31, 2003. A similar program is currently in effect in South Dakota
through October 31, 2005. Since the implementation of the program, MidAmerican
Energy has successfully achieved and shared savings with its natural gas
customers.
MidAmerican Energy utilizes leased gas storage to meet peak day requirements and
to manage the daily changes in demand due to changes in weather. The storage gas
is typically replaced during the summer months. In addition, MidAmerican Energy
also utilizes three liquefied natural gas plants and two propane-air plants to
meet peak day demands.
MidAmerican Energy has strategically built multiple pipeline interconnections
into several of its larger communities. Multiple pipeline interconnects create
competition among pipeline suppliers for transportation capacity to serve those
communities, thus reducing costs. In addition, multiple pipeline interconnects
give MidAmerican Energy the ability to optimize delivery of the lowest cost
supply from the various pipeline supply basins into these communities and
increase delivery reliability. Benefits to MidAmerican Energy's system customers
are shared with all jurisdictions through a consolidated purchased gas
adjustment clause.
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KERN RIVER
Kern River's principal asset is a 926-mile interstate natural gas transmission
pipeline system, with an original approximate capacity of 700 mmcf per day,
extending from supply areas in the Rocky Mountains to consuming markets in Utah,
Nevada and California. Following the completion of recent expansion projects,
including the 2002 expansion project and the California Action Project, the
design capacity of the pipeline is currently 845.5 mmcf per day. Construction of
the original pipeline began on January 2, 1991 and was completed in early 1992.
Kern River's pipeline is comprised of two distinguishable sections: the mainline
and the common facilities. The 707-mile mainline section extends from the
pipeline's point of origination in Opal, Wyoming through the Central Rocky
Mountains area to Daggett, California and is owned entirely by Kern River. The
common facilities consist of the 219-mile section of pipeline that extends from
Daggett to Bakersfield, California. The common facilities are jointly owned by
Kern River (currently approximately 67.9%) and Mojave Pipeline Company
(currently approximately 32.1%), as tenants-in-common. Kern River's ownership
percentage in the common facilities will increase or decrease pursuant to each
completed expansion by the respective joint owners.
Kern River's 2003 Expansion Project
- -----------------------------------
The 2003 Expansion Project is a new parallel 717-mile loop pipeline that will
begin in Lincoln County, Wyoming and terminate in Kern County, California. The
2003 Expansion Project began construction on August 6, 2002 and is expected to
be completed and operational May 1, 2003 at a total cost of approximately $1.2
billion. The pipeline will include 36- and 42-inch diameter pipe, most of which
will be laid in the existing Kern River rights-of-way at a 25-foot offset from
the existing pipeline, and new above ground facilities. Three segments along the
rights-of-way, approximately 205 miles in Utah, Nevada and California, will not
require additional pipeline but will instead be areas where the gas will be
compressed and transported through the existing pipeline. The existing pipeline
rights-of-way, compressor facilities and receipt/delivery facilities will all be
utilized by the 2003 Expansion Project, streamlining the permitting, acquisition
of rights-of-way and ultimately the construction and operations of the 2003
Expansion Project.
The 2003 Expansion Project includes the construction of three new compressor
stations and the installation of additional compression and other modifications
at six existing facilities. When completed, the Kern River system will have a
summer day design capacity of approximately 1.73 Bcf per day, an increase of
approximately 886 mmcf per day.
Kern River has 18 long-term firm transportation service agreements with 17
shippers for 100% of the 2003 Expansion Project's capacity. The term for all
these service agreements is either 10 or 15 years from the date on which
transportation services on the 2003 Expansion Project commence.
The 2003 Expansion Project is being financed with approximately 70% debt and 30%
equity, consistent with Kern River's original capital structure, the application
for FERC approval of the 2003 Expansion Project and the limitations contained in
the indenture for Kern River's existing secured senior notes. On June 21, 2002,
Kern River entered into an $875 million credit facility to fund a portion of the
costs of the 2003 Expansion Project and the Company issued a completion
guarantee in favor of the lenders under that credit facility.
NORTHERN NATURAL GAS
Northern Natural Gas is one of the largest interstate natural gas pipeline
systems in the United States. It reaches from Texas to Michigan's Upper
Peninsula and is engaged in the transmission and storage of natural gas for
utilities, municipalities, other pipeline companies, gas marketers, industrial
and commercial users and other end users. Northern Natural Gas operates
approximately 16,600 miles of natural gas pipelines with a design capacity of
4.4 Bcf per day that deliver approximately 5.0% of the total natural gas
consumed in the United States. The Northern Natural Gas system is believed to be
the largest in the United States as measured by pipeline miles and the eighth
largest as measured by throughput. The pipeline system is powered by 92
transmission compressor stations with an aggregate of approximately 840,000
horsepower. Northern Natural Gas' storage services are provided through the
operation of three underground storage fields (one in Iowa and two in Kansas)
and two LNG storage peaking units. The three underground natural gas storage
facilities and Northern Natural Gas' two LNG storage peaking units have a total
storage capacity of approximately 59 Bcf and over 1.3 Bcf per day of peak day
deliverability. These storage facilities provide Northern Natural Gas with
operational flexibility for daily balancing of its system and providing services
to customers for meeting their year-round loadswing requirements. In 2002,
approximately 11% of Northern Natural Gas' revenue was generated from storage
services.
Northern Natural Gas' system is comprised of two distinct areas, its traditional
end-use and distribution market area at the
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northern end of the system, including delivery points in Michigan, Illinois,
Iowa, Minnesota, Nebraska, Wisconsin and South Dakota, which the Company refers
to as the Market Area, and the natural gas supply and market area at the
southern end of the system, including Kansas, Oklahoma, Texas and New Mexico,
which the Company refers to as the Field Area. Northern Natural Gas' Field Area
is interconnected with many interstate and intrastate pipelines in the national
grid system. A majority of Northern Natural Gas' capacity in both the Market
Area and the Field Area is dedicated to Market Area customers under long-term
firm transportation contracts. Approximately 49% of Northern Natural Gas'
capacity subject to firm transportation contracts is under contracts that extend
beyond 2005.
The northern portion of Northern Natural Gas' pipeline system transports natural
gas primarily to end-user and local distributor markets in the Market Area.
Customers consist of LDCs, municipalities, other pipeline companies, gas
marketers and end-users. While approximately ten large LDCs account for the
majority of Market Area volumes, Northern Natural Gas also serves numerous small
communities through these large LDCs as well as municipalities or smaller LDCs
and directly serves several large end-users. In 2002, approximately 85% of
Northern Natural Gas' revenue was from capacity charges under firm
transportation and storage contracts and approximately 82% of that revenue was
from LDCs. In 2002, approximately 68% of Northern Natural Gas' revenue was
generated from Market Area customer contracts.
As noted above, the Field Area of Northern Natural Gas' system provides access
to natural gas supply from key production areas such as the Hugoton, Permian and
Anadarko Basins. In each of these areas, Northern Natural Gas has numerous
interconnecting receipt and delivery points, with volumes received in the Field
Area consisting of both directly connected supply and volumes from
interconnections with other pipeline systems. In addition, Northern Natural Gas
has the ability to aggregate processable natural gas for deliveries to various
gas processing facilities.
In the Field Area, customers holding transportation capacity consist of LDCs,
marketers, producers, and end-users. The majority of Northern Natural Gas' Field
Area firm transportation is provided to Northern Natural Gas' Market Area firm
customers under long-term firm transportation contracts with such volumes
supplemented by volumes transported on an interruptible basis or pursuant to
short-term firm contracts. In 2002, approximately 21% of Northern Natural Gas'
revenue was generated from Field Area customer transportation contracts.
Northern Natural Gas' system is characterized by significant seasonal swings in
demand, which provide opportunities to deliver high value-added services.
Because of its location and multiple interconnections with other interstate and
intrastate pipelines, Northern Natural Gas is able to access natural gas both
from traditional production areas, such as the Hugoton, Permian and Anadarko
Basins, as well as growing supply areas such as the Rocky Mountains through
Trailblazer Pipeline Company, Pony Express Pipeline and Colorado Interstate Gas
Company, and from Canadian production areas through Northern Border Pipeline
Company, Great Lakes Gas Transmission Limited Partnership and Viking Gas
Transmission Company. As a result of Northern Natural Gas' geographic location
in the middle of the United States and its many interconnections with other
pipelines, Northern Natural Gas augments its steady end-user and LDC revenue by
taking advantage of opportunities to provide intermediate transportation through
pipeline interconnections for customers in other markets including Chicago,
other parts of the Midwest and Texas.
Northern Natural Gas' revenue is derived from the interstate transportation and
storage of natural gas for third parties. Except for small quantities of natural
gas owned for system operations, Northern Natural Gas does not own the natural
gas that is transported through its system. Northern Natural Gas' transportation
and storage operations are subject to a FERC-regulated tariff that is designed
to allow it an opportunity to recover its costs together with a regulated return
on equity.
Northern Natural Gas' strategic plan is focused on taking advantage of the
system's bi-directional and relatively flexible natural gas transportation
capabilities and its storage assets to maximize economic returns. A key
component of this strategic plan is to build upon Northern Natural Gas' asset
base located in the center of the North American natural gas grid by increasing
flexibility through additional pipeline interconnects. Through existing
interconnections, Northern Natural Gas' shippers have supply access to Canadian,
Rocky Mountain, Hugoton, Anadarko and Permian supplies. Northern Natural Gas
also expects to pursue selective pipeline expansions, storage service
enhancement and improved utilization of existing systems. In addition, Northern
Natural Gas is focused on utilizing its ability to transport both dry natural
gas and processable natural gas to take advantage of opportunities presented by
natural gas processing facility consolidations in the Mid-continent area.
Northern Natural Gas expects to be able to meet the expected demand growth in
its Market Area with only modest investment in new facilities as a result of the
flexibility in Northern Natural Gas' system. Furthermore, Northern Natural Gas'
access to supply diversity is expected to provide it with a significant
competitive advantage because of the ability of the system to provide shippers
access to many sources of low cost natural gas.
-9-
KERN RIVER AND NORTHERN NATURAL GAS COMPETITION
Natural gas competes with other forms of energy, including electricity, coal and
fuel oil, primarily on the basis of price. Legislation and governmental
regulations, the weather, the futures market, production costs, and other
factors beyond the control of Kern River and Northern Natural Gas influence the
price of natural gas. Industrial end-users often have the ability to choose from
alternative fuel sources in addition to natural gas, such as fuel oil and coal.
Pipelines compete on the basis of cost, flexibility, reliability of service and
overall customer service. More specifically, Kern River competes with various
interstate pipelines and its shippers in serving the southern California, Las
Vegas and Salt Lake City market areas, in order to market any unsubscribed
capacity and expansion capacity. Kern River provides its customers with supply
diversity through pipeline interconnects with Northwest Pipeline, Colorado
Interstate Gas Pipeline, Overland Trail Pipeline, and Questar Pipeline. These
interconnects allow Kern River to access natural gas reserves in Colorado,
northwestern New Mexico, Wyoming, Utah and the Western Canadian Sedimentary
Basin.
Approximately 100% of Kern River's original pipeline capacity is contractually
committed with 14 extended term rate shippers until September 30, 2011. Beyond
that, approximately 86% of the original pipeline capacity is contractually
committed, with 11 shippers, until September 30, 2016. Nearly 100% of the
additional permanent capacity constructed in connection with the 2002 expansion
and to be constructed for the 2003 Expansion Project is contractually committed
under 10- and 15-year agreements.
Even though Kern River does not market natural gas supply, in each market area
the purchaser evaluates the total cost of natural gas supply, including
transportation rates, from each alternative supplier/transporter. Based on
published rates and fuel percentages, the Company believes Kern River currently
has the lowest transportation costs from well-head to burner tip of any
interstate pipeline serving its direct markets in Nevada and southern
California, with gas transportation costs of approximately $0.45 per MMBtu
compared to approximately $0.84-$1.29 per MMBtu on competing pipelines. There
can be no assurance that its competitors do not or will not charge rates that
are discounted to these published rates, particularly on a short-term basis. The
2003 Expansion Project shippers' initial tariff rates in the original FERC
filing were $0.57-$0.70 per MMBtu. These rates are expected to be reduced
slightly in a FERC compliance filing Kern River is required to make 60 days
prior to placing the 2003 Expansion Project in service.
Kern River is the only interstate pipeline that presently delivers natural gas
directly from a gas supply basin into the intrastate California market, which
enables its customers to avoid paying a "rate stack" (i.e., additional
transportation costs attributable to the movement from one or more interstate
pipeline systems to an intrastate system within California). The Company
believes that Kern River's rate structure and access to upstream
pipelines/storage facilities and to low-cost Rocky Mountain gas reserves
increases its competitiveness and attractiveness to end-users. Kern River
believes it is advantaged relative to other competing interstate pipelines
because its relatively new pipeline can be expanded at lower costs than those
that apply to other systems and it directly links the market along its system to
low cost Rocky Mountain gas supplies. Kern River's strategic advantages were the
main reasons the electric generation market purposely selected sites next to the
Kern River pipeline to build their new power plants. Kern River expects to
directly serve over 7,000 MW's of new electric generation load, which is
currently under construction or recently placed in commercial operation. Close
to 90% of the 2003 Expansion Project contract demand is with shippers who either
own or intend to serve power generation facilities.
Historically, Northern Natural Gas has been able to provide competitive cost
service because of its access to a variety of low cost supply basins, its cost
control measures and its relatively high load factor through-put, which lowers
the cost per unit of transportation. Although Northern Natural Gas has
experienced pipeline system bypass affecting a small percentage of its market,
to date Northern Natural Gas has been able to more than offset any load lost to
bypass in the Market Area through expansion projects such as the Peak Day 2000
project.
Major competitors in the Market Area include ANR Pipeline Company and Natural
Gas Pipeline Company of America. Other competitors include Northern Border
Pipeline Company, Great Lakes Gas Transmission Limited Partnership and Viking
Gas Transmission Company. In the Field Area, Northern Natural Gas competes with
a large number of other competitors. Particularly in the Field Area, a
significant amount of Northern Natural Gas' capacity is used on an interruptible
or short-term basis. In summer months, Northern Natural Gas' Market Area
customers often release significant amounts of their unused firm capacity to
other shippers, which competes with Northern Natural Gas' short-term or
interruptible services.
Northern Natural Gas believes that current and anticipated changes in its
competitive environment have created
-10-
opportunities to serve existing customers more efficiently and to meet certain
growing supply needs. While LDCs provide peak day delivery growth driven by
population growth and alternative fuel replacement, new off-peak demand growth
is being driven primarily by power and ethanol plant expansion. Off-peak demand
growth is important to Northern Natural Gas as this demand can generally be
satisfied with little or no requirement for the construction of new facilities.
Approximately 3,800 MW of natural gas-fired electric power plants in development
have been announced in close proximity to Northern Natural Gas' system. Northern
Natural Gas has been successful in competing for a significant amount of the
increased demand related to the construction of new power and ethanol plants.
Over the last five years, Northern Natural Gas has contracted approximately 430
mmcf per day of volume on its system from such new facilities, of which
approximately 258 mmcf per day is currently in service and approximately 172
mmcf per day is scheduled to begin service between 2003 and 2005.
CE ELECTRIC UK
The business of CE Electric UK consists primarily of the distribution of
electricity in the United Kingdom by Northern Electric and Yorkshire.
In December 1996, CE Electric UK Ltd., an indirect wholly owned subsidiary of CE
Electric UK, acquired Northern Electric. Northern Electric was one of the twelve
original United Kingdom regional electric companies that came into existence in
1990 as a result of the restructuring and subsequent privatization of the
electricity industry that occurred in the United Kingdom. On September 21, 2001,
CE Electric UK Ltd. acquired 94.75% of Yorkshire from Innogy Holdings plc
("Innogy"), and simultaneously sold Northern Electric's electricity and gas
supply and metering businesses to Innogy. The Company sometimes refers to these
transactions as the "Yorkshire Swap". In August 2002, CE Electric UK acquired
the remaining 5.25% of Yorkshire that it did not already own from Xcel Energy
International ("Xcel Energy"), an affiliate of Xcel Energy Inc.
With the acquisition of Yorkshire and the disposition of the electricity and gas
supply and metering businesses of Northern Electric and certain other recent
strategic dispositions, CE Electric UK is positioned to continue to bring
together the skills and resources of two neighboring distribution businesses to
create one of the largest distribution companies in the United Kingdom, serving
more than 3.6 million customers in an area of approximately 10,000 square miles.
CE Electric UK has also implemented a number of initiatives that have produced
savings in ongoing operating and capital costs at its businesses.
Descriptions of the functional business units of each of Northern Electric's and
Yorkshire's distribution businesses are set forth below.
Electricity Distribution
- ------------------------
Northern Electric's and Yorkshire's operations consist primarily of the
distribution of electricity and other auxiliary businesses in the United
Kingdom. Northern Electric's and Yorkshire's distribution licensee companies,
Northern Electric Distribution Limited ("NEDL"), and Yorkshire Electricity
Distribution plc ("YEDL"), respectively, receive electricity from the national
grid transmission system and distribute it to their customers' premises using
their network of transformers, switchgear and cables. Substantially all of the
customers in NEDL's and YEDL's distribution service areas are connected to the
NEDL and YEDL networks and electricity can only be delivered through their
distribution system, thus providing NEDL and YEDL with distribution volume that
is relatively stable from year to year. NEDL and YEDL charge fees for the use of
the distribution system to the suppliers of electricity. The suppliers, which
purchase electricity from generators and sell the electricity to end-user
customers, use NEDL's and YEDL's distribution networks pursuant to an industry
standard "Use of System Agreement" which NEDL and YEDL separately entered into
with the various suppliers of electricity in their respective distribution
areas. The fees that may be charged by NEDL and YEDL for use of their
distribution systems are controlled by a prescribed formula that limits
increases (and may require decreases) based upon the rate of inflation in the
United Kingdom and other regulatory action.
At December 31, 2002, NEDL's and YEDL's electricity distribution network
(excluding service connections to consumers) on a combined basis included
approximately 31,000 kilometers of overhead lines and approximately 65,000
kilometers of underground cables. In addition to the circuits referred to above,
at December 31, 2002, NEDL's and YEDL's distribution facilities also included
approximately 57,000 transformers and approximately 58,000 substations.
Substantially all substations are owned in freehold, and most of the balance are
held on leases that will not expire within 10 years.
-11-
Utility Services
- ----------------
Integrated Utility Services Limited ("IUS"), a subsidiary of Northern Electric,
is an engineering contracting company whose main business is providing
electrical connection services on behalf of NEDL's and YEDL's distribution
businesses and providing electrical infrastructure contracting services to third
parties.
Gas Exploration and Production
- ------------------------------
CE Gas is a gas exploration and production company that is focused on developing
integrated upstream gas projects. Its upstream gas business consists of the
exploration, development and production, including transportation and storage,
of gas for delivery to a point of sale into either a gas supply market or a
power generation facility.
In May 2002, CE Gas, an indirect wholly owned subsidiary of the Company,
executed the sale of several of its U.K. natural gas assets to Gaz de France for
(pound)137.0 million (approximately $200.0 million). CE Gas sold four natural
gas-producing fields located in the southern basin of the U.K. North Sea,
including Anglia, Johnston, Schooner and Windermere. The transaction also
included the sale of rights in four gas fields (in development/construction) and
three exploration blocks owned by CE Gas.
In addition to retaining its interest in the Victor Field and the ETS pipeline,
CE Gas retained certain development interests in Poland (Polish Trough) and
Australia (Perth, Bass and Otway Basins).
-12-
CALENERGY GENERATION - DOMESTIC
Business
Through CalEnergy Generation - Domestic, the Company owns interests in 15
operating non-utility power projects in the United States. The following table
sets out certain information concerning CalEnergy Generation-Domestic's
non-utility power projects in operation as of December 31, 2002:
FACILITY NET PURCHASE
CAPACITY NET MW AGREEMENT
OPERATING PROJECT (MW) (1) OWNED (1) FUEL LOCATION EXPIRATION POWER PURCHASER (2)
- ---------------------- ------------- --------- ---- ---------- ----------- -------------------
Cordova ...................... 537 537 Gas Illinois 2017 El Paso/MidAmerican Energy
Salton Sea I ................. 10 5 Geo California 2017 Edison
Salton Sea II ................ 20 10 Geo California 2020 Edison
Salton Sea III ............... 50 25 Geo California 2019 Edison
Salton Sea IV ................ 40 20 Geo California 2026 Edison
Salton Sea V ................. 49 25 Geo California Year-to-year El Paso/Minerals(3)
Vulcan ....................... 34 17 Geo California 2016 Edison
Elmore ....................... 38 19 Geo California 2018 Edison
Leathers ..................... 38 19 Geo California 2019 Edison
Del Ranch .................... 38 19 Geo California 2019 Edison
CE Turbo ..................... 10 5 Geo California Year-to-year El Paso/Minerals(3)
Saranac ...................... 240 90 Gas New York 2009 NYSE&G
Power Resources .............. 200 100 Gas Texas 2003 TXU
Yuma ......................... 50 25 Gas Arizona 2024 SDG&E
Roosevelt Hot Springs (4) .... 23 17 Geo California Year-to-year UP&L
----- ---
DOMESTIC OPERATING PROJECTS .. 1,377 933
===== ===
(1) Represents accredited net generating capability. Actual MW may vary
depending on operating conditions and plant design. Net MW owned indicates
current legal ownership, but, in some cases, does not reflect the current
allocation of partnership distributions.
(2) El Paso Corporation ("El Paso"); Southern California Edison Company
("Edison"); CalEnergy Minerals LLC ("Minerals"), a zinc facility owned by a
subsidiary of the Company; New York State Electric & Gas Corporation
("NYSE&G"), TXU Generation Company LP ("TXU"); San Diego Gas & Electric
Company ("SDG&E"), and Utah Power & Light Company ("UP&L").
(3) Each contract governing power purchases by Minerals will expire 33 years
from the date of the initial power delivery under such contract. Pursuant
to a Transaction Agreement dated January 29, 2003, Salton Sea Power LLC
("Salton Sea Power") and CE Turbo LLC ("CE Turbo") began selling available
power to a subsidiary of TransAlta Corporation ("TransAlta") on February
12, 2003 based on percentages of the Dow Jones SP-15 Index. Such agreement
will expire on October 31, 2003.
(4) The Company's subsidiary owns an approximately 70% indirect interest in
this project which supplies geothermal steam to a power plant owned by
UP&L. The Company obtained a cash prepayment under a pre-sale agreement
with UP&L whereby UP&L paid in advance for the steam produced by this steam
field.
Cordova Energy owns a 537 MW gas-fired power plant in the Quad Cities, Illinois
area that the Company refers to as the Cordova Project. CalEnergy Generation
Operating Company, its indirect wholly owned subsidiary, operates the Cordova
Project. The Cordova Project commenced commercial operations in June 2001.
Cordova Energy entered into a power purchase agreement with a unit of El Paso,
under which El Paso will purchase all of the capacity and energy from the
project until December 31, 2019. Cordova Energy has exercised an option to
recall from El Paso 50% of the output through May 14, 2004, reducing El Paso's
purchase obligation to 50% of the output during such period. The recalled output
is being sold to MidAmerican Energy. The Company is aware there have been public
announcements that El Paso's financial condition has deteriorated as a result
of, among other things, reduced liquidity. The Company will continue to monitor
the situation.
-13-
MEHC has a 50% ownership interest in CE Generation, whose affiliates currently
operate ten geothermal plants (the "Imperial Valley Projects") in the Imperial
Valley in California. The "Salton Sea Projects" consist of the Salton Sea I,
Salton Sea II, Salton Sea III, Salton Sea IV and Salton Sea V Projects (the
"Salton Sea I Project", the "Salton Sea II Project", the "Salton Sea III
Project," the "Salton Sea IV Project," and the "Salton Sea V Project"
respectively). The "Partnership Projects" consist of the Vulcan, Elmore,
Leathers, Del Ranch and CE Turbo projects (the "Vulcan Project," the "Elmore
Project", the "Leathers Project", the "Del Ranch Project," and the "CE Turbo
Project" respectively). The CE Turbo Project and the Salton Sea V Project
commenced commercial operations in 2000.
Each of the Imperial Valley Projects, excluding the Salton Sea V and CE Turbo
Projects, sells electricity to Edison pursuant to a separate Standard Offer No.
4 Agreement ("SO4 Agreement") or a negotiated power purchase agreement. Each
power purchase agreement is independent of the others, and the performance
requirements specified within one such agreement apply only to the project,
which is subject to the agreement. The power purchase agreements provide for
energy payments, capacity payments and capacity bonus payments. Edison makes
fixed annual capacity payments and capacity bonus payments to the applicable
projects to the extent that capacity factors exceed certain benchmarks. The
price for capacity was fixed for the life of the SO4 Agreements and is
significantly higher in the months of June through September.
Energy payments for the SO4 Agreements were at increasing fixed rates for the
first ten years after firm operation and thereafter at a rate based on the cost
that Edison avoids by purchasing energy from the project instead of obtaining
the energy from other sources ("Avoided Cost of Energy"). In June and November
2001, the Imperial Valley Projects, which receive Edison's Avoided Cost of
Energy, entered into agreements that provide for amended energy payments under
the SO4 Agreements. The amendments provide for fixed energy payments per kWh in
lieu of Edison's Avoided Cost of Energy. The fixed energy payment was 3.25 cents
per kWh from December 1, 2001 through April 30, 2002 and is 5.37 cents per kWh
commencing May 1, 2002 for a five-year period. Following the five-year period,
the energy payments revert back to Edison's Avoided Cost of Energy.
For the years ended December 31, 2002, 2001 and 2000, respectively, Edison's
Average Avoided Cost of Energy was 3.5 cents per kWh, 7.4 cents per kWh and 5.8
cents per kWh, respectively. Estimates of Edison's future Avoided Cost of Energy
vary substantially from year to year.
The Salton Sea V and CE Turbo projects began operations in 2000 and, when the
Zinc Recovery Project (defined below) achieves 100% production, the Salton Sea V
Project and the CE Turbo Project would expect to sell approximately 22 MW to the
Zinc Recovery Project at a price based on market transactions. The remainder is
being sold through other market transactions.
The Saranac Project is a 240 net MW natural gas-fired cogeneration facility
located in Plattsburgh, New York. The Saranac Project has entered into a 15-year
power purchase agreement with NYSE&G expiring in 2009. The Saranac Project is a
qualifying facility ("QF") and has entered into 15-year steam purchase
agreements with Georgia-Pacific Corporation and Pactiv Corporation. The Saranac
Project has a 15-year natural gas supply agreement with Shell Canada Limited, to
supply 100% of the Saranac Project's fuel requirements. Each of the Saranac
power purchase agreement, the Saranac steam purchase agreements and the Saranac
gas supply agreement contains rates that are fixed for their respective contract
terms. Revenues escalate at a higher rate than fuel costs. The Saranac
partnership is indirectly owned by subsidiaries of CE Generation, ArcLight
Capital Partners LLC and General Electric Capital Corporation.
The Power Resources Project is a 200 net MW natural gas-fired cogeneration
project located near Big Spring, Texas, which has a 15-year power purchase
agreement with TXU Generation Company LP, formerly known as Texas Utilities
Electric Company expiring in 2003. The Power Resources Project is a QF and has a
steam purchase agreement with Alon USA, L.P. On December 30, 2002, Power
Resources obtained an exempt wholesale generator order from the FERC. The status
as an exempt wholesale generator would facilitate the Power Resources Project
sale of energy in market transactions.
The Yuma Project is a 50 net MW natural gas-fired cogeneration project in Yuma,
Arizona providing 50 MW of electricity to SDG&E under an existing 30-year power
purchase agreement which expires in 2024. The Yuma project is a QF and has
executed steam sales contracts with an adjacent industrial entity to act as its
thermal host.
The Roosevelt Hot Springs Project is a geothermal steam field which supplies
geothermal steam to a 23 net MW power plant owned by UP&L located on the
Roosevelt Hot Springs property under a 30-year steam sales contract expiring in
2020. The Company obtained a cash prepayment under a pre-sale agreement with
UP&L
-14-
whereby UP&L paid in advance for the steam produced by the steam field. The
Company guarantees the performance of this subsidiary. The Company must make
certain penalty payments to UP&L if the steam produced does not meet certain
quantity and quality requirements.
Zinc Recovery Project
- ---------------------
Minerals developed and owns the rights to proprietary processes for the
extraction of zinc from elements in solution in the geothermal brine and fluids
utilized at the Imperial Valley Projects. A plant has successfully produced
commercial quality zinc at the projects. The affiliates of Minerals may develop
facilities for the extraction of manganese, silica and other products as they
further develop the extraction technology.
Minerals constructed the Zinc Recovery Project, which is recovering zinc from
the geothermal brine (the "Zinc Recovery Project"). Facilities have been
installed near the Imperial Valley Projects sites to extract a zinc chloride
solution from the geothermal brine through an ion exchange process. This
solution is being transported to a central processing plant where zinc ingots
are being produced through solvent extraction, electrowinning and casting
processes. The Zinc Recovery Project is designed to have a capacity of
approximately 30,000 metric tons per year. Limited production began during
December 2002 and full production is expected by late-2003. In September 1999,
Minerals entered into a sales agreement whereby all high-grade zinc produced by
the Zinc Recovery Project will be sold to Cominco, Ltd. The initial term of the
agreement expires in December 2005.
Development Projects
- --------------------
The Company's subsidiary, Fox Energy Company LLC ("Fox"), is evaluating the
development of a 635 net MW gas fired power generating facility in Kaukanna,
Outagamie County, Wisconsin. A subsidiary of TransAlta has agreed to participate
in the development of this project at a level of 50% and has an option to own
50% of the project. The Public Service Commission of Wisconsin issued a
Certificate of Public Convenience and Necessity on November 8, 2002. An air
permit for construction and initial operations was issued by the Wisconsin
Department of Natural Resources on November 4, 2000 and such application was
deemed complete on April 25, 2002. A final environmental impact statement was
issued by the Wisconsin Department of Natural Resources on August 19, 2002.
Electrical and natural gas interconnection agreements and a water supply
agreement have also been executed for this project.
The Company's subsidiary, CE Obsidian Energy LLC ("Obsidian"), is evaluating the
development of a 185 net MW geothermal facility in Imperial Valley, California.
Substantially all the output of the facility will be sold to the Imperial
Irrigation Disctrict pursuant to a power purchase agreement. An affiliate of
TransAlta has elected to participate in the ownership and development of this
project at a level of 50%. On July 29, 2002, Obsidian filed an application for
certification seeking approval from the California Energy Commission to
construct and operate the facility.
CALENERGY GENERATION - FOREIGN
Business
- --------
The Company indirectly owns the Upper Mahiao, Malitbog and Mahanagdong projects,
which are geothermal power plants located on the island of Leyte in the
Philippines, and the Casecnan Project, a combined irrigation and hydroelectric
power generation project, which is located in the central part of Island of
Luzon in the Philippines. Each plant possesses an operating margin that allows
for production in excess of the amount listed below. Utilization of this
operating margin is based upon a variety of factors and can be expected to vary
between calendar quarters under normal operating conditions.
-15-
Operating Projects
- ------------------
The following table sets out certain information concerning CalEnergy
Generation-Foreign's non-utility power projects in operation as of December 31,
2002:
FACILITY NET POWER
CAPACITY NET MW COMMERCIAL PURCHASER/
OPERATING PROJECT (1) (MW) (2) OWNED (2) FUEL OPERATION GUARANTOR (3)
- -------------------------------- ------------ --------- ------ ------------ -------------
Upper Mahiao ................... 119 119 Geo 1996 PNOC-EDC/ROP
Mahanagdong .................... 165 155 Geo 1997 PNOC-EDC/ROP
Malitbog ....................... 216 216 Geo 1996-97 PNOC-EDC/ROP
Casecnan (4) ................... 150 150 Hydro 2001 NIA/ROP
--- ---
INTERNATIONAL OPERATING PROJECTS 650 640
=== ===
(1) All operating projects are located in the Philippines; all operating
projects are governed by contracts which are payable in U.S. dollars; and
all operating projects carry political risk insurance.
(2) Actual MW may vary depending on operating and reservoir conditions and
plant design. Facility Net Capacity (MW) represents the contract capacity
for the facility. Net MW owned indicates current legal ownership, but, in
some cases, does not reflect the current allocation of distributions.
(3) PNOC-Energy Development Corporation ("PNOC-EDC"), Republic of the
Philippines ("ROP"), and National Irrigation Administration ("NIA") (NIA
also purchases water from this facility). The government of the Philippines
undertaking supports PNOC-EDC's and NIA's respective obligations.
(4) Net MW Owned is subject to repurchase rights of up to 15% of the project by
an initial minority shareholder and a dispute with the other initial
minority shareholder regarding an additional 15% of the project. Also see
"Legal Proceedings-Philippines."
The Upper Mahiao project is a 119 net MW geothermal power project owned and
operated by CE Cebu Geothermal Power Company, Inc. ("CE Cebu"), a Philippine
corporation that is 100% indirectly owned by the Company. The Upper Mahiao
facility has been in commercial operation since June 17, 1996.
Under the terms of the Upper Mahiao energy conversion agreement, CE Cebu owns
and operates the Upper Mahiao Project during the ten-year cooperation period,
which commenced in June 1996, after which ownership will be transferred to
PNOC-Energy Development Corporation at no cost.
The Upper Mahiao Project is located on land provided by PNOC-EDC at no cost. The
project takes geothermal steam and fluid, also provided by PNOC-EDC at no cost,
and converts its thermal energy into electrical energy which is sold to PNOC-EDC
on a "take-or-pay" basis, which in turn sells the power to the National Power
Corporation (`NPC"), for distribution on the island of Cebu. PNOC-EDC pays to CE
Cebu a fee based on the plant capacity nominated to PNOC-EDC in any year (which,
at the plant's design capacity, is approximately 95% of total contract revenue)
and a fee based on the electricity actually delivered to PNOC-EDC (approximately
5% of total contract revenue). Payments under the Upper Mahiao agreement are
denominated in U.S. dollars, or computed in U.S. dollars and paid in pesos at
the then-current exchange rate, except for the energy fee. PNOC-EDC's payment
requirements, and its other obligations under the Upper Mahiao agreement, are
supported by the ROP through a performance undertaking.
The Mahanagdong Project is a 165 net MW geothermal power project owned and
operated by CE Luzon Geothermal Power Company, Inc. ("CE Luzon"), a Philippine
corporation of which the Company indirectly owns 100% of the common stock.
Another industrial company owns an approximate 6% preferred equity interest in
the Mahanagdong Project. The Mahanagdong Project has been in commercial
operation since July 25, 1997. The Mahanagdong Project sells 100% of its
capacity on a similar basis as described above for the Upper Mahiao Project to
PNOC-EDC, which in turn sells the power to the NPC for distribution on the
island of Luzon.
The terms of the Mahanagdong energy conversion agreement are substantially
similar to those of the Upper Mahiao agreement. The Mahanagdong agreement
provides for a ten-year cooperation period. At the end of the cooperation
period, the facility will be transferred to PNOC-EDC at no cost. All of
PNOC-EDC's obligations under the Mahanagdong agreement are supported by the ROP
through a performance undertaking. The capacity fees are approximately 97% of
total revenue at the design capacity levels and the energy fees are
approximately 3% of such total revenue. PNOC-EDC's payment requirements, and its
other obligations under the Mahanagdong agreement, are supported by the ROP
through
-16-
a performance undertaking.
The Malitbog Project is a 216 net MW geothermal project owned and operated by
Visayas Geothermal Power Company ("VGPC"), a Philippine general partnership that
is wholly owned, indirectly, by the Company. The three units of the Malitbog
facility were put into commercial operation on July 25, 1996 (for Unit I) and
July 25, 1997 (for Units II and III). VGPC sells 100% of its capacity on
substantially the same basis as described above for the Upper Mahiao Project to
PNOC-EDC, which sells the power to the NPC for distribution on the islands of
Cebu and Luzon.
The electrical energy produced by the facility is sold to PNOC-EDC on a
take-or-pay basis. These capacity payments equal approximately 100% of total
revenue. A substantial majority of the capacity payments are required to be made
by PNOC-EDC in dollars. The portion of capacity payments payable to PNOC-EDC in
pesos is expected to vary over the term of the Malitbog energy conversion
agreement from 10% of VGPC's revenue in the early years of the 10-year
cooperation period to 23% of VGPC's revenue at the end of the cooperation
period. Payments made in pesos will generally be made to a peso-dominated
account and will be used to pay peso-denominated operation and maintenance
expenses with respect to the Malitbog Project and Philippine withholding taxes,
if any, on the Malitbog Project's debt service. The government of the
Philippines has entered into a performance undertaking, which provides that all
of PNOC-EDC's obligations pursuant to the Malitbog energy conversion agreement
carry the full faith and credit of, and are affirmed and guaranteed by, the ROP.
The Malitbog energy conversion agreement cooperation period expires ten years
after the date of commencement of commercial operation of Unit III. At the end
of this cooperation period, the facility will be transferred to PNOC-EDC at no
cost, on an "as is" basis. See "Legal Proceedings - Philippines" for a
description of legal proceedings related to the Malitbog Project.
CE Casecnan Ltd. ("CE Casecnan"), the Company's indirectly majority owned
subsidiary, operates the Casecnan Project, a combined irrigation and 150 Net MW
hydroelectric power generation project. The Casecnan Project consists generally
of diversion structures in the Casecnan and Taan rivers that capture and divert
excess water in the Casecnan watershed by means of concrete, in-stream diversion
weirs and transfer that water through a transbasin tunnel of approximately 23
kilometers (including the intake adit from the Taan to the Casecnan river), with
a diameter of approximately 6.5 meters to an existing underutilized water
storage reservoir at Pantabangan. During the water transfer, the elevation
differences between the two watersheds allows electrical energy to be generated
at a 150 MW rated capacity power plant, which is located in an underground
powerhouse cavern at the end of the water tunnel. A tailrace discharge tunnel of
approximately three kilometers delivers water from the water tunnel and the new
powerhouse to the Pantabangan reservoir, providing additional water for
irrigation and increasing the potential electrical generation at two downstream
existing hydroelectric facilities of the Philippine National Power Corporation
("NPC"), the government-owned and controlled corporation that is the primary
supplier of electricity in the Philippines. Since the water has been determined
to remain suitable for irrigation throughout the Casecnan Project operations of
capturing, diverting and transferring the water, other than removing sediments
at the diversion structures, no treatment is required. Once in the reservoir at
Pantabangan, the water is under the control of, and for the use of the NIA.
CE Casecnan constructed and operates the Casecnan Project under the terms of the
Project Agreement between CE Casecnan and NIA. Under the Project Agreement, CE
Casecnan developed, financed and constructed the Casecnan Project during the
construction period and will own and operate the Project during the 20-year
Cooperation Period. During the Cooperation Period, NIA is obligated to accept
all deliveries of water and energy, and so long as the Casecnan Project is
physically capable of operating and delivering in accordance with agreed levels
set forth in the Project Agreement, NIA will pay CE Casecnan a fixed fee for the
delivery of water and a fixed fee for the delivery of a threshold amount of
electricity. In addition, NIA will pay a fee for all electricity delivered in
excess of the threshold amount up to a specified amount. The water delivery fee
is a fixed monthly amount, to be received in US dollars at the end of each
month, based on 801.9 million cubic meters of water flow past the water delivery
point per year, pro-rated to 66.8 million cubic meters per month. The unit price
for water is established at $0.029 per cubic meter (subject to adjustment as set
forth in the Project Agreement) as of January 1, 1994 and escalated at seven and
one-half percent (7.5%) per annum, pro-rated on a monthly basis, through the end
of the fifth year of the Cooperation Period and then kept flat at that level for
the last fifteen years of the Cooperation Period. The unit price for water is to
be adjusted by $.00043 for each $1.0 million of certain taxes and fees paid by
the Company as specified in the Project Agreement. The unit price of water as of
December 31 2002 is $0.1017. Actual deliveries of water greater than or less
than 66.8 million cubic meters in any month will not result in any adjustment of
the water delivery fee. The guaranteed energy fee is a fixed monthly amount, to
be received in US dollars at the end of each month, based on energy deliveries
of 228.0 million kWh per year, pro-rated to 19.0 million kWh per month. Actual
deliveries of energy less than 19.0 million kWh per month will not result in any
reduction of the guaranteed energy fee but will result in an adjustment to the
excess energy fee. The unit price for
-17-
guaranteed energy is $0.1596 per kWh. The excess energy fee is a variable
amount, to be received in US dollars at the end of each month, for electrical
energy delivered in that month in excess of 19.0 million kWh. No excess energy
delivery fee will be due until all cumulative electrical energy shortfalls below
19.0 million kWh in previous months have been made up. The unit price of excess
energy is $0.1509 per kWh. NIA will sell the electricity it purchases to NPC,
although NIA's obligations to CE Casecnan under the Project Agreement are not
dependent on NPC's purchase of the electricity from NIA. All fees to be paid by
NIA to CE Casecnan are payable in US dollars. The fixed fees paid for the
delivery of water and energy, regardless of the amount of electricity or water
actually delivered, are expected to provide approximately 78% of CE Casecnan's
revenues. At the end of the Cooperation Period, the Casecnan Project will be
transferred to NIA at no additional consideration on an "as is" basis.
The ROP has provided a Performance Undertaking under which NIA's obligations
under the Project Agreement are guaranteed by the full faith and credit of the
ROP. The Project Agreement and the Performance Undertaking provide for the
resolution of disputes by binding arbitration in Singapore under international
arbitration rules.
HOMESERVICES
Business
- --------
HomeServices is the second largest full-service independent 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, title and closing
services and other related services. HomeServices currently operates in 15
states under the following brand names: Carol Jones Realty, CBSHOME Real Estate,
Champion Realty, Edina Realty HomeServices, First Realty/GMAC, Home Real Estate,
Iowa Realty, Jenny Pruitt and Associates REALTORS, Long Realty, Prudential
California Realty, RealtySouth, Reece & Nichols, Semonin REALTORS and Woods
Bros. Realty. HomeServices generally occupies the number one or number two
market share position in each of its major markets based on aggregate closed
transaction sides. HomeServices' major markets consist of the following
metropolitan areas: Minneapolis and St. Paul, Minnesota; Los Angeles and San
Diego, California; Kansas City, Kansas; Des Moines, Iowa; Omaha and Lincoln,
Nebraska; Birmingham, Alabama; Tucson, Arizona; Louisville, Kentucky; Annapolis,
Maryland; Atlanta, Georgia and Springfield, Missouri.
HomeServices' 2002 Acquisitions
- -------------------------------
In 2002, HomeServices separately acquired three real estate companies. For the
year ended December 31, 2001, these real estate companies had combined revenue
of approximately $356.0 million on 42,000 closed sides representing $13.7
billion of sales volume.
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REGULATORY MATTERS
The Company's operating platforms are subject to a number of federal, state,
local and international regulations.
MIDAMERICAN ENERGY
MidAmerican Energy is subject to comprehensive regulation by the FERC as well as
utility regulatory agencies in Iowa, Illinois and South Dakota that
significantly influences the operating environment and the recoverability of
costs from utility customers. Except for Illinois, that regulatory environment
has to date, in general, given MidAmerican Energy an exclusive right to serve
electricity customers within its service territory and, in turn, the obligation
to provide electric service to those customers. In Illinois all customers are
free to choose their electricity provider. MidAmerican Energy has an obligation
to serve customers at regulated rates that leave MidAmerican Energy's system,
but later choose to return. To date, there has been no significant loss of
customers from MidAmerican Energy's existing regulated Illinois rates.
In connection with the March 1999 approval by the IUB of the MidAmerican Energy
acquisition and March 2000 affirmation as part of the Company's acquisition by a
private investor group, MidAmerican Energy agreed, among other things, to use
all commercially reasonable efforts to maintain an investment grade credit
rating for MidAmerican Energy's utility operations and its long-term debt and to
seek the approval of the IUB of a reasonable utility capital structure if
MidAmerican Energy's utility operations' common equity level decreases below
42%, excluding circumstances beyond its control, or below 39%, under any
circumstances. MidAmerican Energy's utility operations' common equity level at
December 31, 2002 and 2001, was above these levels.
With the elimination of its energy adjustment clause in Iowa in 1997,
MidAmerican Energy is financially exposed to movements in energy prices.
Although MidAmerican Energy has sufficient low cost generation under typical
operating conditions for its retail electric needs, a loss of adequate
generation by MidAmerican Energy requiring the purchase of replacement power at
a time of high market prices could subject MidAmerican Energy to losses on its
energy sales.
In December 1999, the FERC issued Order No. 2000 establishing, among other
things, minimum characteristics and functions for regional transmission
organizations. Public utilities that were not a member of an independent system
operator at the time of the order were required to submit a plan by which their
transmission facilities would be transferred to a regional transmission
organization. On September 28, 2001, MidAmerican Energy and five other electric
utilities filed with the FERC a plan to create TRANSLink Transmission Company
LLC ("TRANSLink") and to integrate their electric transmission systems into a
single, coordinated system operating as a for-profit independent transmission
company in conjunction with a FERC approved regional transmission organization.
On April 25, 2002, the FERC issued an order approving the transfer of control of
MidAmerican Energy's and other utilities' transmission assets to TRANSLink in
conjunction with TRANSLink's participation in the Midwest ISO. Additionally,
state regulatory approval is required from states in which TRANSLink will be
operating, MidAmerican Energy does not anticipate rulings in the state
proceedings until some time in late 2003. Transferring operation and control of
MidAmerican Energy's transmission assets to other entities could increase costs
for MidAmerican Energy; however, the actual impact of TRANSLink on MidAmerican
Energy's future transmission costs is not yet known.
On July 31, 2002, the FERC issued a notice of proposed rulemaking with respect
to Standard Market Design for the electric industry. The FERC has characterized
the proposal as portending "sweeping changes" to the use and expansion of the
interstate transmission and the wholesale bulk power systems in the United
States. The proposal includes numerous proposed changes to the current
regulation of transmission and generation facilities designed "to promote
economic efficiency" and replace the "obsolete patchwork we have today,"
according to the FERC's chairman. The final rule, if adopted as currently
proposed, would require all public utilities operating transmission facilities
subject to the FERC jurisdiction to file revised open access transmission
tariffs that would require changes to the basic services these public utilities
currently provide. The proposed rule may impact the costs and/or pricing of
MidAmerican Energy's electricity and transmission products. The FERC does not
envision that a final rule will be fully implemented until September 30, 2004.
MidAmerican Energy is still evaluating the proposed rule, and believes that the
final rule could vary considerably from the initial proposal. Accordingly,
MidAmerican Energy is presently unable to quantify the likely impact of the
proposed rule.
The structure of such federal and state energy regulations have in the past, and
may in the future, be the subject of various challenges and restructuring
proposals by utilities and other industry participants. The implementation of
regulatory changes in response to such changes or restructuring proposals, or
otherwise imposing more comprehensive or stringent requirements on MidAmerican
Energy which would result in increased compliance costs, could have a material
adverse effect on its results of operations.
Under a settlement agreement approved by the IUB on December 21, 2001,
MidAmerican Energy's Iowa retail rates in effect
-19-
on December 31, 2000 are frozen through December 31, 2005. In approving that
settlement, the IUB specifically allows the filing of the electric rate design
and/or cost of service rate changes that are intended to keep overall company
revenue unchanged but could result in changes to individual tariffs. Under the
2001 settlement agreement further provides that an amount equal to 50% of
revenues associated with Iowa retail electric returns on equity between 12% and
14%, and 83.33% of revenues associated with Iowa retail electric returns on
equity above 14%, in each year is recorded as a regulatory liability to be used
to offset a portion of the cost to Iowa customers of future generating plant
investment. An amount equal to the regulatory liability is recorded as a
regulatory charge in depreciation and amortization expense when the liability is
accrued. Interest expense is accrued on the portion of the regulatory liability
related to prior years. Beginning in 2002, the liability is being reduced as it
is credited against allowance for funds used during construction or capitalized
financing costs associated with generating plant additions. As of December 31,
2002, the related regulatory liability was $102.9 million.
On March 20, 2003, MidAmerican Energy and the Iowa Office of Consumer Advocate
agreed upon a settlement proposal in which the rate freeze described above would
be extended through December 31, 2010. Under the settlement proposal, for
calendar years 2006 through 2010, an amount equal to 40% of revenues associated
with Iowa retail electric returns on equity between 11.75% and 13.0%; 50% of
revenues associated with Iowa retail electric returns on equity between 13.0%
and 14.0%; and 83.3% of revenues associated with Iowa retail electric returns on
equity greater than 14.0% will be applied as a reduction to offset some of the
capital costs on the Iowa portion of three generation projects. If Iowa retail
electric returns on equity fall below 10% in any 12-month period after January
1, 2006, MidAmerican Energy has the ability to file for a general increase in
rates under the proposed settlement. The proposed settlement is subject to
approval by the IUB and requires enactment of Iowa legislation. The IUB is
expected to rule on the proposal during the second half of 2003.
Under an Illinois restructuring law enacted in 1997, as amended in 2002, a
sharing mechanism is in place for MidAmerican Energy's Illinois regulated retail
electric operations whereby earnings above a computed level of return on common
equity will be shared equally between customers and MidAmerican Energy.
MidAmerican Energy's computed level of return on common equity is based on a
rolling two-year average of the Monthly Treasury Long-Term Average Rate, as
published by the Federal Reserve System, plus a premium of 8.5% for 2000 through
2004 and a premium of 12.5% for 2005 and 2006. The two-year average above which
sharing must occur for 2002 was 14.03%. The law allows MidAmerican Energy to
mitigate the sharing of earnings above the threshold return on common equity
through accelerated recovery of regulatory assets.
On March 15, 2002, MidAmerican Energy made a filing with the IUB requesting an
increase in rates. On June 12, 2002, the IUB issued an order granting
MidAmerican Energy an interim increase of approximately $13.8 million annually,
effective. On July 15, 2002 MidAmerican Energy and the Iowa Office of Consumer
Advocate filed a proposed settlement agreement with the IUB. The settlement
agreement, which was approved by the IUB on November 8, 2002, provides for an
increase in rates of $17.7 million annually for MidAmerican Energy's Iowa retail
natural gas customers and freezes such rates for two years after the date the
IUB approves tariffs implementing the settlement agreement. MidAmerican Energy
implemented the new rates effective November 25, 2002.
KERN RIVER AND NORTHERN NATURAL GAS
Kern River and Northern Natural Gas are subject to regulation by various federal
and state agencies as discussed below.
As owners of interstate natural gas pipelines, Northern Natural Gas' and Kern
River's rates, services and operations are subject to regulation by the FERC.
The FERC administers, among other things, the Natural Gas Act and the Natural
Gas Policy Act of 1978. Additionally, interstate pipeline companies are subject
to regulation by the Department of Transportation pursuant to the Natural Gas
Pipeline Safety Act, which establishes safety requirements in the design,
construction, operations and maintenance of interstate natural gas transmission
facilities.
The FERC has jurisdiction over, among other things, the construction and
operation of pipelines and related facilities used in the transportation,
storage and sale of natural gas in interstate commerce, including the extension,
enlargement or abandonment of such facilities. The FERC also has jurisdiction
over the rates and charges and terms and conditions of service for the
transportation of natural gas in interstate commerce. Its pipeline subsidiaries
also are required to file with the FERC an annual report on Form 2, which is
publicly available, disclosing general corporate information and financial
statements regarding its pipeline subsidiaries.
Kern River's tariff rates were designed to recover a cost of service that
reflects a 13.25% return on equity. Kern River's rates are set using a
"levelized cost-of-service" methodology so that the rate is constant over the
contract period. This is achieved by using a FERC-approved depreciation schedule
in which depreciation increases as interest expense decreases.
-20-
Northern Natural Gas has implemented a straight fixed variable rate design which
provides that all fixed costs assignable to firm capacity customers, including a
return on equity, are to be recovered through fixed monthly demand or capacity
reservation charges which are not a function of throughput volumes.
Northern Natural Gas' current tariff structure provides for:
o seasonality in demand rates;
o extension of the majority of firm storage and transport contracts
through May 31, 2003 and October 31, 2003, respectively;
o a rate moratorium through October 31, 2003, with limited re-openers
based on the FERC's rulemaking changes; and
o the right of Northern Natural Gas to file for term-differentiated
rates, if allowed.
Northern Natural Gas' tariff rates were designed to recover a cost of service
that would reflect a 12.3% return on equity based upon the settlement reached in
FERC Docket No. RP 98-203. Northern Natural Gas' last rate case was filed on May
1, 1998, and its next rate case may be filed no earlier than May 2003 and no
later than May 2004. Northern Natural Gas' most likely next rate case filing
date is May 1, 2003 with filed rates to be effective November 1, 2003.
In 2000, the FERC issued new rules with respect to terms and conditions of
interstate pipeline transportation service pursuant to Order No. 637. In Order
No. 637, the FERC made changes to its regulatory model to enhance the
effectiveness and efficiency of gas markets as they evolved since the series of
FERC orders commonly referred to as Order No. 436, No. 500 and No. 636 which
were adopted beginning in the mid-1980s to the early 1990s and which provided
for the restructuring of interstate pipeline sales and services. Specifically,
in Order No. 637 the FERC:
o addressed alternatives to traditional pipeline pricing by permitting
peak/off-peak and term differentiated rate structures;
o revised certain reporting requirements; and
o made changes in regulations related to (1) scheduling equality for
released capacity, (2) capacity segmentations, and (3) pipeline
imbalance services, operational flow orders and penalties.
On July 17, 2000, Northern Natural Gas made its initial compliance filing in
accordance with Order No. 637. Northern Natural Gas made a revised Order No. 637
compliance filing on March 4, 2002 and a supplemental filing on May 10, 2002. On
November 21, 2002, the FERC issued an Order on Compliance with Order Nos. 637,
587-G and 587-L. In the November 21, 2002 Order, the FERC found that Northern
Natural Gas generally complied with Order Nos. 637, 587-G and 587-L, subject to
certain modifications, and ordered Northern Natural Gas to file compliance
tariffs within 30 days. Northern filed in compliance with the November 21, 2002
order on December 21, 2002. At this time, an order on Compliance has not been
issued. In addition, numerous parties filed for rehearing of the November 21,
2002 order, which are also pending.
As a result of the FERC's policies favoring competition in gas markets and the
expansion of existing pipelines and construction of new pipelines, the
interstate pipeline industry has begun to experience some turnback of firm
capacity as existing transportation service agreements expire and are
terminated. LDCs and end-use customers have more choices in the new, more
competitive environment and may be able to shift load from one pipeline to
another. If a pipeline experiences capacity turnback and is unable to remarket
the capacity, the pipeline or its other customers may have to bear the costs
associated with the capacity that is turned back. These issues will be resolved
in a pipeline's general rate case proceedings.
The FERC also has authority over gas pipelines' accounting practices. The FERC
recently issued a notice of proposed rulemaking regarding gas accounting issues
which would limit the ability of gas pipelines to enter into cash management
agreements with their parent companies. The Company is in the process of
reviewing such proposed rule, but the Company does not believe the rule will
have a material adverse impact on it and its pipeline subsidiaries.
On August 1, 2002, the FERC issued an Order to respond to Northern Natural Gas
related to Northern Natural Gas'
-21-
existing $450.0 million revolving credit facility and to cash management record
keeping by Northern Natural Gas. Pursuant to a Stipulation and Consent Agreement
dated August 8, 2002, Northern Natural Gas agreed to comply with the FERC's cash
management practices and to not include the costs associated with its existing
$450.0 million revolving credit facility in any future rate proceeding.
Additional proposals and proceedings that might affect the interstate pipeline
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. In some states various forms of restructuring
legislation have been passed and in many states local utility regulatory
agencies are overseeing the restructuring. As a result of restructuring, LDCs
could unbundle their services and withdraw from all or part of their merchant
function, and electric utilities could divest their generating function. This
restructuring would result in the interstate pipelines having different customer
profiles, including independent gas marketers and independent power generators
and end-users. The Company cannot predict when or if any new proposals might be
implemented or, if so, how Kern River and Northern Natural Gas might be
affected.
OTHER UNITED STATES REGULATION
The Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"), and
the Public Utility Holding Company Act of 1935, as amended ("PUHCA"), are two of
the laws (including the regulations thereunder) that affect the Company and
certain of its subsidiaries' operations. PURPA provides to QFs certain
exemptions from federal and state laws and regulations, including
organizational, rate and financial regulation. PUHCA extensively regulates and
restricts the activities of registered public utility holding companies and
their subsidiaries. Congress is currently considering major changes to both
PUHCA and PURPA. Any such legislation, if adopted, could vary considerably from
the terms contained in either or both of the House and Senate versions which are
presently under consideration. The Company believes that if the current proposed
legislation is passed, it would apply to new projects only and thus, although
potentially impacting its ability to develop new domestic projects, it would not
affect the Company's existing qualifying facilities. The Company cannot provide
assurance, however, that legislation, if passed, or any other similar
legislation proposed in the future, would not adversely impact its existing
domestic projects.
The Company is currently exempt from regulation under all provisions of PUHCA,
except the provisions that regulate the acquisition of securities of public
utility companies, based on the intrastate exemption in Section 3(a)(1) of
PUHCA. In order to maintain this exemption, the Company and each of its public
utility subsidiaries from which it derives a material part of its income
(currently only MidAmerican Energy) must be predominantly intrastate in
character and organized in and carry on the Company's and MidAmerican Energy's
respective utility operations substantially in the Company's state of
organization (currently Iowa). Except for MidAmerican Energy's generating plant
assets, the majority of the Company's domestic power plants and all of its
foreign utility operations are not public utilities within the meaning of PUHCA
as a result of their status as QFs under PURPA (with the Company's ownership
interest therein limited to 50%), exempt wholesale generators or foreign utility
companies, or are otherwise exempted from the definition of "public utility"
under PUHCA. Although the Company believes that it will continue to qualify for
exemption from additional regulation under PUHCA, it is possible that as a
result of the expansion of its public utility operations, loss of exempt status
by one or more of its domestic power plants or foreign utilities, or amendments
to PUHCA or the interpretation of PUHCA, the Company could become subject to
additional regulation under PUHCA in the future. There can be no assurances that
such regulation would not have a material adverse effect on the Company.
In the event the Company was unable to avoid the loss of QF status for one or
more of its affiliate's facilities, such an event could result in termination of
a given project's power sales agreement and a default under the project
subsidiary's project financing agreements, which, in the event of the loss of QF
status for one or more facilities, could have a material adverse effect on the
Company.
Regulatory requirements applicable in the future to nuclear generating
facilities could adversely affect the results of operations of the Company and
MidAmerican Energy, in particular. The Company is subject to certain generic
risks associated with utility nuclear generation, including risks arising from
the operation of nuclear facilities and the storage, handling and disposal of
high-level and low-level radioactive materials; risks of a serious nuclear
incident; limitations on the amounts and types of insurance commercially
available in respect of losses that might arise in connection with nuclear
operations; and uncertainties with respect to the technological and financial
aspects of decommissioning nuclear plants at the end of their licensed lives.
The Nuclear Regulatory Commission ("NRC") has broad authority under federal law
to impose licensing and safety-related requirements for the operation of nuclear
generating facilities. Revised safety requirements promulgated by the NRC have,
in the past, necessitated substantial capital expenditures at nuclear plants,
including those in which MidAmerican Energy has an ownership interest, such as
the Quad Cities units, and additional such expenditures could be required in the
future.
-22-
CE ELECTRIC UK
Since 1990, the electricity generation, supply and distribution industries in
Great Britain have been privatized, and competition has been introduced in
generation and supply. Electricity is produced by generators, transmitted
through the national grid transmission system and distributed to customers by
the fourteen Distribution License Holders, which the Company refers to as DLHs,
in their respective distribution service areas. During the fourth quarter of
1998, the market for supplying electricity began to be opened to competition
through a phased-in program. This program, which proceeded by geographic areas,
was completed in 1999.
Under the Utilities Act 2000, the public electricity supply license created
pursuant to the Electricity Act 1989 was replaced by two separate licenses-the
electricity distribution license and the electricity supply license. When the
relevant provision of the Utilities Act 2000 became effective on October 1,
2001, the public electricity supply licenses formerly held by Northern Electric
and Yorkshire were split so that separate subsidiaries held licenses for
electricity distribution and electricity supply. In order to comply with the
Utilities Act 2000 and to facilitate this license splitting, Northern Electric
and Yorkshire (and each of the other holders of the former public electricity
supply licenses) each made a statutory transfer scheme that was approved by the
Secretary of State for Trade and Industry. These schemes provided for the
transfer of certain assets and liabilities to the licensed subsidiaries. This
occurred on October 1, 2001, a date set by the Secretary of State for Trade and
Industry. As a consequence of these schemes, the electricity distribution
businesses of Northern Electric and Yorkshire were transferred to NEDL and YEDL,
respectively. NEDL and YEDL are each holders of an electricity distribution
license. The residual elements of the Electricity Supply licenses were
transferred to Innogy in connection with the sale of Northern Electric's
electricity and gas supply business to Innogy and the retention by Innogy of the
electricity and gas supply business of Yorkshire, all as a part of the Yorkshire
Swap on September 21, 2001.
Each of the DLHs is required to offer terms for connection to its distribution
system and for use of its distribution system to any person. In providing the
use of its distribution system, a DLH must not discriminate between users, nor
may its charges differ except where justified by differences in cost.
Most revenue of the DLHs is controlled by a distribution price control formula
which is set out in the license of each DLH. It has been the practice of the
Office of Gas and Electric Markets ("Ofgem") (and its predecessor body, the
Office of Electricity Regulation), to review the formula periodically and to
reset it at intervals of five year duration. The formula may be varied with the
consent of the DLH, or if the DLH does not consent, following a review by the
U.K.'s competition authority.
The periodic review during which the formula is reset is the process by which
Ofgem determines its view of the future allowed revenue of DLHs. The procedure
and methodology adopted at a price control review is at the reasonable
discretion of Ofgem. At the last such review, concluded in 1999 and effective
April 2000, Ofgem's judgment of the future allowed revenue of licensees was
based upon, among other things:
o the actual operating costs of each of the licensees;
o the operating costs which each of the licensees would incur if it were
as efficient as, in Ofgem's judgment, the most efficient licensee;
o the regulatory value to be ascribed to each of the licensees'
distribution network assets;
o the allowance for depreciation of the distribution network assets of
each of the licensees;
o the rate of return to be allowed on investment in the distribution
network assets by all licensees; and
o the financial ratios of each of the licensees and the license
requirement for each licensee to maintain an investment grade status.
As a result of the most recent review, the allowed revenue of Northern
Electric's distribution business was reduced by 24%, in real terms, and the
allowed revenue of Yorkshire's distribution business was reduced by 23%, in real
terms, with effect from April 1, 2000. The range of reductions for all licensees
in Great Britain was between 4% and 33%.
For the duration of the current regulatory period, the 1999 review also requires
that regulated distribution revenue per unit
-23-
be increased or decreased each year by RPI-Xd, where the factor "RPI" is the
United Kingdom retail price index reflecting the average of the 12-month
inflation rates recorded for each month in the previous July to December period
and "Xd" is an adjustment factor which was established by Ofgem at the 1999
review (and continues to be set) at 3%. The formula also takes account of the
changes in system electrical losses, the number of customers connected and the
voltage at which customers receive the units of electricity distributed. This
formula determines the maximum average price per unit of electricity distributed
(in pence per kWh) which a DLH is entitled to charge. The distribution price
control formula permits DLHs to receive additional revenue due to increased
distribution of units and a predetermined increase in customer numbers. Once
set, the price control formula does not, during its duration, seek to constrain
the profits of a DLH from year to year. It is a control on revenue that operates
independently of most of the DLH's costs. During the duration of the price
control, additional cost savings or costs, if any, therefore directly impact
profit.
The distribution prices allowable under the current distribution price control
formula are expected to be reviewed by Ofgem in time for a revised formula to
take effect from April 1, 2005. The formula may be further reviewed at other
times in the discretion of the regulator. Ofgem has recently modified the
licenses of all DLHs to implement an "Information and Incentives Project" under
which up to 2% of a DLH's regulated income depends upon the performance of the
DLH's distribution system as measured by the number and duration of customer
interruptions and upon the level of customer satisfaction monitored by Ofgem.
Under the Utilities Act 2000, the Gas and Electricity Markets Authority ("GEMA")
is able to impose financial penalties on license holders who contravene (or have
in the past contravened) any of their license duties or certain of their duties
under the Electricity Act 1989 or who are failing (or have in the past failed)
to achieve a satisfactory performance in relation to the individual standards of
performance prescribed by GEMA. Any penalty imposed must be reasonable and may
not exceed 10% of the licensee's revenue.
CALENERGY GENERATION - DOMESTIC
Each of the operating domestic power facilities owned through CE Generation
meets the requirements promulgated under PURPA to be qualifying facilities. QF
status under PURPA provides two primary benefits. First, regulations under PURPA
exempt QFs from PUHCA, the FERC rate regulation under the Federal Power Act and
the state laws concerning rates of electric utilities and financial and
organization regulations of electric utilities. Second, the FERC's regulations
promulgated under PURPA require that (1) electric utilities purchase electricity
generated by QFs, the construction of which commenced on or after November 9,
1978, at a price based on the purchasing utility's Avoided Cost of Energy, (2)
electric utilities sell back-up, interruptible, maintenance and supplemental
power to QFs on a non-discriminatory basis, and (3) electric utilities
interconnect with QFs in their service territories. There can be no assurance
that the QF status of such CalEnergy Generation-Domestic facilities will be
maintained.
CORDOVA ENERGY AND POWER RESOURCES
Cordova Energy and Power Resources are exempt from regulation under PUHCA
because they are exempt wholesale generators. Power Resources is also a QF.
PUHCA provides that an exempt wholesale generator is not considered to be an
electric utility company. An exempt wholesale generator is permitted to sell
capacity and electricity in the wholesale markets, but not in the retail
markets.
If an exempt wholesale generator is subject to a "material change" in facts that
might affect its continued eligibility for exempt wholesale generator status,
within 60 days of such material change, the exempt wholesale generator must (1)
file a written explanation of why the material change does not affect its exempt
wholesale generator status, (2) file a new application for exempt wholesale
generator status, or (3) notify the FERC that it no longer wishes to maintain
exempt wholesale generator status.
CALENERGY GENERATION - FOREIGN
The Philippine Congress has passed the Electric Power Industry Reform Act of
2001, which is aimed at restructuring the Philippine power industry,
privatization of the NPC and introduction of a competitive electricity market,
among other initiatives. The implementation of the bill may have an impact on
the Philippines power industry as a whole and the Company's future operations in
the Philippines, the effect of which is not yet determinable and estimable.
In connection with an interagency review of approximately 40 independent power
project contracts in the Philippines, the Casecnan Project (along with four
other unrelated projects) has reportedly been identified as raising legal and
financial questions and, with those projects, has been prioritized for
renegotiation. The Company's subsidiaries' Upper Mahiao, Malitbog, and
Mahanagdong projects, which, together with the Casecnan Project, collectively
referred to as the Philippine
-24-
Projects, have also reportedly been identified as raising financial questions.
No written report has yet been issued with respect to the interagency review,
and the timing and nature of steps, if any that the Philippine Government may
take in this regard are not known. Accordingly, it is not known what, if any,
impact the government's review will have on the operations of the Company's
Philippines Projects. CE Casecnan representatives, together with certain current
and former government officials, were requested to appear and did appear during
2002 before a Philippine Senate committee which has raised questions and made
allegations with respect to the Casecnan Project's tariff structure and
implementation. No further Senate hearings are scheduled at this time although
hearings before a Philippine House committee were scheduled for the first
quarter of 2003.
HOMESERVICES
The Department of Housing and Urban Development and the Federal Home
Administration ("FHA"), lender guidelines prohibit the collection of a
broker-fee from FHA financed buyers where the FHA lender is affiliated with the
real estate broker or where there is no buyer-broker agreement. The majority of
HomeServices' subsidiaries have been charging a broker fee to their buyers and
sellers, except in circumstances where the FHA guidelines prohibit it.
Nonetheless, HomeServices is working with the FHA to change the lenders'
guidelines to permit collection of these fees.
PIPELINE SAFETY REGULATION
The Company's pipeline operations are subject to regulation by the United States
Department of Transportation under the Natural Gas Pipeline Safety Act of 1969,
as amended, relating to design, installation, testing, construction, operation
and management of its pipeline system. The Natural Gas Pipeline Safety Act
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 conducts internal
audits of its facilities every four years, with more frequent reviews of those
it deems higher risk. The Department of Transportation also routinely audits the
Company's pipeline facilities. Compliance issues that arise during these audits
or during the normal course of business are addressed on a timely basis.
The aging pipeline infrastructure in the United States has led to heightened
regulatory and legislative scrutiny of pipeline safety and integrity practices.
The Natural Gas Pipeline Safety Act was amended by the Pipeline Safety Act of
1992 to require the Department of Transportation's Office of Pipeline Safety to
consider protection of the environment when developing minimum pipeline safety
regulations. In addition, the amendments require that the Department of
Transportation issue pipeline regulations concerning, among other things, the
circumstances under which emergency flow restriction devices should be required,
training and qualification standards for personnel involved in maintenance and
operation, and requirements for periodic integrity inspections, as well as
periodic inspection of facilities in navigable waters which could pose a hazard
to navigation or public safety. In addition, the amendments narrowed the scope
of its gas pipeline exemption pertaining to underground storage tanks under the
Resource Conservation and Recovery Act. While the effect of new legislation,
which has been passed by Congress but not yet signed by the President, on the
Company is still being determined, the Company expects to spend the capital or
make the operational changes necessary to comply with all pipeline integrity
legislation.
MEHC believes its subsidiaries' pipeline operations comply in all material
respects with the Natural Gas Pipeline Safety Act, but the industry, including
its subsidiaries, could be required to incur additional capital expenditures and
increased costs depending upon final regulations issued by the Department of
Transportation under the Natural Gas Pipeline Safety Act.
ENVIRONMENTAL REGULATION
Domestic
- --------
The Company is subject to a number of federal, state and local environmental and
environmentally related laws and regulations affecting many aspects of its
present and future operations in the United States. Such laws and regulations
generally require the Company to obtain and comply with a wide variety of
licenses, permits and other approvals. The Company believes that its operating
power facilities and gas pipeline operations are currently in material
compliance with all applicable federal, state and local laws and regulations.
However, no guarantee can be given that in the future the Company will be 100%
compliant with all applicable environmental statutes and regulations or that all
necessary permits will be obtained or approved. In addition, the construction of
new power facilities and gas pipeline operations is a costly and time-consuming
process requiring a multitude of complex environmental permits and approvals
prior to the start of construction that may create the risk of expensive delays
or material impairment of project value if projects cannot function as planned
due to changing regulatory requirements or local opposition.
-25-
The Company cannot assure you that existing regulations will not be revised or
that new regulations will not be adopted or become applicable to it which could
have an adverse impact on its operating costs and operations.
In accordance with the requirements of Section 112 of the Clean Air Act
Amendments of 1990, the EPA has performed a study of the hazards to public
health reasonably anticipated to occur as a result of emissions of hazardous air
pollutants by electric utility steam generating units. In December 2000, after
research and monitoring of mercury emissions, the EPA concluded that it is
appropriate and necessary to regulate mercury emissions from coal-fired
generating units. It is anticipated that rules will be developed to regulate
these emissions in 2003 or 2004 with reductions of mercury emissions effective
in 2007. The cost to MidAmerican Energy of reducing its mercury emissions would
depend on available technology at the time, but could be material.
In July 1997, the EPA adopted revisions to the National Ambient Air Quality
Standards for ozone and a new standard for fine particulate matter. Based on
data to be obtained from monitors located throughout each state, the EPA will
determine which states have areas that do not meet the air quality standards
(i.e., areas that are classified as nonattainment). The standards were subjected
to legal proceedings, and in February 2001, United States Supreme Court upheld
the constitutionality of the standards, though remanding the issue of
implementation of the ozone standard to the EPA. As a result of a decision
rendered by the United States Circuit Court of Appeals for the District of
Columbia, the EPA is moving forward in implementation of the ozone and fine
particulate standards and is analyzing existing monitoring data to determine
attainment status.
The impact of the new standards on the Company is currently unknown. MidAmerican
Energy's generating stations may be subject to emission reductions if the
stations are located in nonattainment areas or contribute to nonattainment areas
in other states. As part of state implementation plans to achieve attainment of
the standards, MidAmerican Energy could be required to install control equipment
on its generating stations or decrease the number of hours during which these
stations operate.
The ozone and fine particulate matter standards could also, in whole or in part,
be superceded by one of a number of multi-pollutant emission reduction proposals
currently under consideration at the federal level. In July 2002, legislation
was introduced in Congress to implement the Administration's "Clear Skies
Initiative," calling for the reduction in emissions of sulfur dioxide, nitrogen
oxides and mercury through a cap-and-trade system. Reductions would begin in
2008 with additional emission reductions being phased in through 2018. While
legislative action is necessary for this or other multi-pollutant emission
reduction initiatives to become effective, MidAmerican Energy has implemented a
planning process that forecasts the site-specific controls and actions required
to meet emissions reductions of this nature.
Since the adoption of the United Nations Framework on Climate Change in 1992,
there has been a worldwide effort to reduce greenhouse gas ("GHG"), emissions to
1990 levels or below. In December 1997, the U.S. participated in the Kyoto,
Japan negotiations, where the basis of a Climate Change treaty was formulated.
Under the treaty, known as the Kyoto Protocol, the United States would have an
overall reduction target of 7% in GHG emissions from 1990 levels by 2012. To
date, the Senate has not ratified the Kyoto Protocol. In addition, President
Bush has indicated his opposition to the Kyoto Protocols. However, given the
widespread international and public support for the reduction of GHG emissions,
the clear possibility exists that GHG reduction regulations will come to pass,
even if not related to the Kyoto Protocol. At this time, the Company cannot
estimate the potential impact of such regulations on it or its' subsidiaries.
In 2001, the state of Iowa passed legislation that, in part, requires
rate-regulated utilities to develop a multi-year plan and budget for managing
regulated emissions from their generating facilities in a cost-effective manner.
MidAmerican Energy's proposed plan and associated budget was filed with the IUB
on April 1, 2002, in accordance with state law. MidAmerican Energy expects the
IUB to rule on the prudence of such plan during the second quarter of 2003.
MidAmerican Energy is required to file updates to such plan at least every two
years.
MidAmerican Energy's plan provides its projected air emission reductions
considering current proposals being debated at the federal level and describes a
coordinated long-range plan to achieve these air emission reductions.
MidAmerican Energy's plan also provides specific actions to be taken at each
coal-fired generating facility and related costs and timing for each action.
MidAmerican Energy's plan outlines $732.0 million in environmental investments
to existing coal-fired generating units, some of which are jointly owned, over a
nine-year period from 2002 through 2010. MidAmerican Energy's share of these
investments is $546.6 million, $67.9 million of which is projected to be
incurred during the current 2002-2005 rate freeze period. Such plan also
identifies expenses that will be incurred at the generating facilities to
operate and maintain the
-26-
environmental equipment installed as a result of such plan.
Federal, state and local environmental laws and regulations currently have, and
future modifications may have, the effect of increasing the lead time for the
construction of new facilities, significantly increasing the total cost of new
facilities, requiring modification of the Company's existing facilities,
increasing the risk of delay on construction projects, increasing its cost of
waste disposal and possibly reducing the reliability of service the Company
provides and the amount of energy available from its facilities. Any of such
items could have a substantial impact on amounts required to be expended by the
Company in the future.
Under various federal, state and local environmental laws and regulations, a
current or previous owner or operator of any facility, including an electric
generating facility, may be required to investigate and remediate past releases
or threatened releases of hazardous or toxic substances or petroleum products
located at the facility, and may be held liable to a governmental entity or to
third parties for property damage, personal injury and investigation and
remediation costs incurred by a party in connection with any releases or
threatened releases. These laws, including the Comprehensive Environmental
Response, Compensation and Liability Act of 1980, as amended by the Superfund
Amendments and Reauthorization Act of 1986, impose liability without regard to
whether the owner knew of or caused the presence of the hazardous substances,
and courts have interpreted liability under such laws to be strict and joint and
several. The cost of investigation, remediation or removal of substances may be
substantial. In connection with the ownership and operation of facilities, the
Company and its subsidiaries may be liable for such costs. Even at those sites
where the Company is not presently aware of any contamination that currently
requires remediation, given the use of hazardous substances at each facility and
their locations, often within areas that have a long history of industrial use,
it is possible that the Company will discover currently unknown contamination or
that future spills or other causes of contamination will occur. As a result, it
is possible that the Company may become liable for remediation.
The EPA and state environmental agencies have determined that contaminated
wastes remaining at certain decommissioned manufactured gas plant facilities may
pose a threat to the public health or the environment if such contaminants are
in sufficient quantities and at such concentrations as to warrant remedial
action.
MidAmerican Energy has evaluated or is evaluating 27 properties that were, at
one time, sites of gas manufacturing plants in which MidAmerican Energy may be a
potentially responsible party. MidAmerican Energy estimates the range of
possible costs for investigation, remediation and monitoring for these sites to
be $16 million to $54 million. As of December 31, 2002, MidAmerican Energy has
recorded a liability of $17 million for these sites. MidAmerican Energy's
present rates in Iowa provide for a fixed annual recovery of manufactured gas
plant costs.
Pursuant to the Toxic Substances Control Act, a federal law administered by the
EPA, MidAmerican Energy developed a comprehensive program for the use, handling,
control and disposal of all polychlorinated biphenyls, or PCBs, contained in
electrical equipment. The future use of equipment containing PCBs will be
minimized. Capacitors, transformers and other miscellaneous equipment are being
purchased with a non-PCB dielectric fluid. MidAmerican Energy's exposure to PCB
liability has been reduced through the orderly replacement of a number of such
electrical devices with similar non-PCB electrical devices.
Accruals for probable remediation costs are established based on site-specific
estimates and are evaluated and revised quarterly as appropriate based on
additional information obtained during investigation and remedial activities.
The estimated recorded liability could change materially based on facts and
circumstances derived from site investigations, changes in required remedial
action and changes in technology relating to remedial alternatives. Insurance
recoveries have been received for some of the sites under investigation. Those
recoveries are intended to be used principally for accelerated remediation, as
specified by the IUB, and are recorded as a regulatory liability. Additionally,
as viable potentially responsible parties are identified, those parties are
evaluated for potential contributions, and cost recovery is pursued when
appropriate.
Although the timing of potential incurred costs and recovery of costs in
MidAmerican Energy's rates may affect the results of operations in individual
periods, management believes that the outcome of issues related to the
remediation of former manufactured gas plant facilities will not have a material
adverse effect on its financial position, results of operations or cash flows.
-27-
United Kingdom
- --------------
CE Electric UK's businesses are subject to extensive regulatory requirements
with respect to the protection of the environment.
The United Kingdom government introduced new contaminated land legislation in
April 2000 that requires local authorities to put in place a program for
investigating land in their area in order to identify contamination.
o Local authorities can leave remediation notices where contamination
poses a threat to the greater environment.
o If the "person" who contaminated the land cannot be found, the land
owner is responsible.
CE Electric UK is in the process of completing the evaluation work on the three
sites that may be subject to the legislation. Exploratory work with an
environmental remediation company is in progress on these sites.
The Environmental Protection Act (Disposal of PCB's and other Dangerous
Substances) Regulations 2001 were introduced on May 5, 2000. The regulations
required that transformers containing over 50 parts per million of PCB's and
other dangerous substances be registered with the Environment Agency by July 31,
2000. Transformers containing 500 parts per million had to be de-contaminated by
December 31, 2000. CE Electric UK has registered 380 items above 50 parts per
million, decontaminated 120 items and informed the Environment Agency that it is
continuing with its sampling, labeling and registration program. These
regulations are not expected to have a significant material impact on the
Company.
The 1998 Groundwater Regulations seek to prevent listed hazardous substances
from entering groundwater and strengthens the United Kingdom Environment
Agency's powers to require additional protective measures, especially in areas
of important groundwater supplies. Mineral oils and hydrocarbons are included in
the list of more tightly controlled substances ("List I substances"). This
affects the high voltage fluid filled electricity cable network incorporating an
insulating fluid that is currently in List I. The existing voluntary Operating
Code of Practice, as agreed between the Environment Agency and the Electricity
Supply Industries, is undergoing revision through the services of the
Electricity Association to address the regulatory changes. The existing
voluntary Operating Code of Practice is, and any revised Operating Code of
Practice will be, incorporated into the operating practices of NEDL and YEDL.
Any revisions which are made are not expected to have a significant material
impact on the Company.
The Oil Storage Regulations became effective in 2002 and require the phased
introduction of secondary containment measures (bunding) for all above ground
oil storage locations where the capacity is more than 200 liters. The primary
containers must be in sound condition, leak free, and positioned away from
vehicle traffic routes. The secondary containment must be impermeable to water
and oil (without drainage valve) and be subject to routine maintenance. The
capacity of the bund must be sufficient to hold up to 110% of the largest stored
vessel or 25% of the maximum stored capacity, whichever is the greater. The full
impact of the regulations is being phased in over the next three years. On March
1, 2002, these regulations came into effect for all new oil storage facilities.
On September 1, 2003, the regulations become effective for existing storage
facilities at "significant risk" (i.e. within 10 meters of a water course), and
on September 1, 2005 the regulations come into effect for all remaining storage
facilities. A detailed study of the impacts has been carried out and a plan of
action prepared to ensure compliance. The Company expects that the cost of
compliance with such regulations will not have a material impact.
The Electricity Act 1989 obligates either the United Kingdom Secretary of State
or the Director General of Electric Supply to take into account the effect of
electricity generation, transmission and supply activities on the physical
environment when approving applications for the construction of overhead power
lines. The Electricity Act requires CE Electric UK to consider the desirability
of preserving natural beauty and the conservation of natural and man-made
features of particular interest when it formulates proposals for development in
connection with certain of its activities. CE Electric UK mitigates the effects
its proposals have on natural and man-made features and administers an
environmental assessment when it intends to lay cables, construct overhead lines
or carry out any other development in connection with its licensed activities.
The Company expects that the cost of compliance with these obligations and the
mitigation thereof will not have a material impact.
CE Electric UK's policy is to carry out its activities in such a manner as to
minimize the impact of its works and operations on the environment, and in
accordance with environmental legislation and good practice. There have not been
any significant regulatory environmental compliance issues and there are no
material legal or administrative proceedings
-28-
pending against CE Electric UK with respect to any environmental matter.
Environmental laws and regulations in the United Kingdom currently have, and
future modifications may increasingly have, the effect of requiring modification
of CE Electric UK's facilities and increasing its operating costs.
PHILIPPINES
On June 23, 1999, the Philippine Congress enacted the Philippine Clean Air Act
of 1999. The related implementing rules and regulations were adopted in November
2000. The law as written would require the Leyte Projects to comply with a
maximum discharge of 200 grams of hydrogen sulfide per gross MWh of output by
June 2004. On November 13, 2002, the Secretary of the Philippine Department of
Environmental and Natural Resources issued Memorandum Circular ("MC")
designating geothermal areas as "special airsheds." PNOC-EDC has advised the
Company that the MC exempts the Mahanagdong and Malitbog plants from the need to
comply with the point-source emission standards of the Clean Air Act. The Leyte
Projects intend to seek confirmation of the impact of the MC from PNOC-EDC and
from the Philippine Department of Environmental and Natural Resources.
NUCLEAR REGULATION
Under the Nuclear Waste Policy Act of 1982, the United States 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.
Exelon Generation, as required by the Nuclear Waste Act, signed a contract with
the Department of Energy to provide for the disposal of spent nuclear fuel and
high-level radioactive waste beginning not later than January 1998. The
Department of Energy did not begin receiving spent nuclear fuel on the scheduled
date, and it is expected that the schedule will be significantly delayed. The
costs incurred by the Department of Energy for disposal activities are being
financed by fees charged to owners and generators of the waste. Exelon
Generation has informed MidAmerican Energy that existing on-site storage
capability at Quad Cities Station is sufficient to permit interim storage into
2005. For Quad Cities Station, Exelon Generation has informed MidAmerican Energy
that it plans to develop interim spent fuel storage installation at Quad Cities
Station to store additional spent nuclear fuel in dry casks. Exelon Generation
expects the bulk of the construction work will be done in 2004.
MidAmerican Energy is subject to the jurisdiction of the NRC with respect to its
license and 25% ownership interest in Quad Cities Station Units 1 and 2. Exelon
Generation 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 regulations control the granting of permits and licenses for the
construction and operation of nuclear generating stations and subject such
stations to continuing review and regulation. The NRC review and regulatory
process covers, among other things, operations, maintenance, and environmental
and radiological aspects of such stations. The NRC may modify, suspend or revoke
licenses and impose civil penalties for failure to comply with the Atomic Energy
Act, the regulations under such Act or the terms of such licenses.
Federal regulations provide that any nuclear operating facility may be required
to cease operation if the NRC determines there are deficiencies in state, local
or utility emergency preparedness plans relating to such facility, and the
deficiencies are not corrected. Exelon Generation has advised MidAmerican Energy
that an emergency preparedness plan for Quad Cities Station has been approved by
the NRC. Exelon Generation has also advised MidAmerican Energy that state and
local plans relating to Quad Cities Station have been approved by the Federal
Emergency Management Agency.
The NRC also regulates the decommissioning of nuclear power plants including the
planning and funding for the eventual decommissioning of the plants. In
accordance with these regulations, MidAmerican Energy submits a report to the
NRC every two years providing "reasonable assurance" that funds will be
available to pay the costs of decommissioning its share of Quad Cities Station.
MidAmerican Energy has established external trusts for the investment of funds
collected for nuclear decommissioning associated with Quad Cities Station.
Electric tariffs currently in effect include provisions for annualized
collection of estimated decommissioning costs at Quad Cities Station. In Iowa,
Quad Cities Station decommissioning costs are reflected in base rates.
MidAmerican Energy's cost related to decommissioning funding in 2002 was $8.3
million.
-29-
EMPLOYEES
As of December 31, 2002, the Company and its subsidiaries employed approximately
10,985 people. Approximately 4,205 of which are represented by labor unions.
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This report contains statements that do not directly or exclusively relate to
historical facts. These statements are "forward-looking statements" within the
meaning of the Private Securities Litigation Reform Act of 1995. You can
typically identify forward-looking statements by the use of forward-looking
words, such as "may", "will", "could", "project", "believe", "anticipate",
"expect", "estimate", "continue", "potential", "plan", "forecast" and similar
terms. These statements represent the Company's intentions, plans, expectations
and beliefs and are subject to risks, uncertainties and other factors. Many of
these factors are outside the Company's control and could cause actual results
to differ materially from such forward-looking statements. These factors
include, among others:
o general economic and business conditions in the jurisdictions in which
its facilities are located;
o governmental, statutory, regulatory or administrative initiatives or
ratemaking actions affecting the Company or the electric or gas
utility, pipeline or power generation industries;
o weather effects on sales and revenue;
o general industry trends;
o increased competition in the power generation, electric utility or
pipeline industries;
o fuel and power costs and availability;
o continued availability of accessible gas reserves;
o changes in business strategy, development plans or customer or vendor
relationships;
o availability, term and deployment of capital;
o availability of qualified personnel;
o risks relating to nuclear generation;
o financial or regulatory accounting principles or policies imposed by
the Public Company Accounting Oversight Board, the Financial
Accounting Standards Board ("FASB"), the Securities and Exchange
Commission ("SEC") and similar entities with regulatory oversight; and
o other business or investment considerations that may be disclosed from
time to time in SEC filings or in other publicly disseminated written
documents.
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.
ITEM 2. PROPERTIES.
The Company's utility properties consist of physical assets necessary and
appropriate to render electric and gas service in its service territories.
Electric property consists primarily of generation, transmission and
distribution facilities. Gas property consists primarily of distribution plants,
natural gas pipelines, related rights-of-way, compressor stations and meter
stations. It is the opinion of management that the principal depreciable
properties owned by the Company are in good operating condition and well
maintained.
-30-
MIDAMERICAN ENERGY
MidAmerican Energy's most significant properties are its electric generation
facilities. For a discussion of these generation facilities, please see
"Business-MidAmerican Energy." MidAmerican Energy's utility properties consist
of physical assets necessary and appropriate to render electric and gas service
in its service territories. Electric property consists primarily of generation,
transmission and distribution facilities. 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. It is the opinion of management that the principal
depreciable properties owned by MidAmerican Energy are in good operating
condition and well maintained.
The electric transmission system of MidAmerican Energy at December 31, 2002,
included 290 miles of 345-kV lines and 1,111 miles of 161-kV lines. MidAmerican
Energy's electric distribution system included approximately 218,500
transformers and 377 substations at December 31, 2002.
The gas distribution facilities of MidAmerican Energy at December 31, 2002,
included 20,835 miles of gas mains and services.
Substantially all the former Iowa-Illinois Gas and Electric Company utility
property and franchises, and substantially all of the former Midwest Power
Systems electric utility property located in Iowa, or approximately 80% of gross
utility plant, is pledged to secure mortgage bonds.
CE ELECTRIC UK
At December 31, 2002, Northern Electric's and Yorkshire's electricity
distribution networks (excluding service connection to consumers) on a combined
basis included approximately 31,000 kilometers of overhead lines and
approximately 65,000 kilometers of underground cables. In addition to the
circuits referred to above, at December 31, 2002, Northern Electric's and
Yorkshire's distribution facilities also included approximately 57,000
transformers and approximately 58,000 substations.
KERN RIVER AND NORTHERN NATURAL GAS
At December 31, 2002, Kern River's pipeline was comprised of two distinguishable
sections: the mainline and the common facilities. The 707-mile mainline section
extends from the pipeline's point of origination in Opal, Wyoming through the
Central Rocky Mountains area to Daggett, California and is owned entirely by
Kern River. The common facilities consist of the 219-mile section of pipeline
that extends from Daggett to Bakersfield, California. The common facilities are
jointly owned by Kern River (currently approximately 67.9%) and Mojave Pipeline
Company (currently approximately 32.1%) as tenants-in-common.
At December 31, 2002, Northern Natural Gas' system was comprised of
approximately 7,300 miles of mainline transmission pipes and approximately 9,300
miles of smaller diameter branch lines and laterals. Northern Natural Gas'
storage services are provided through the operation of three underground storage
fields, in Redfield, Iowa, and Lyons and Cunningham, Kansas. The three
underground natural gas storage facilities and Northern Natural Gas' two
liquefied natural gas storage peaking units have a total storage capacity of
approximately 59 Bcf. Northern Natural Gas' two LNG liquefaction/vaporization
facilities are located near Garner, Iowa and Wrenshall, Minnesota with storage
capacity of 2 Bcf each.
The right to construct and operate the pipelines across certain property was
obtained through negotiations and through the exercise of the power of eminent
domain, where necessary. Kern River and Northern Natural Gas continue to have
the power of eminent domain in each of the states in which they operate their
respective pipelines, but they do not have the power of eminent domain with
respect to Native American tribal lands. Although the main Kern River pipeline
crosses the Moapa Indian Reservation, all facilities are located within a
utility corridor that is reserved to the United States Department of Interior,
Bureau of Land Management.
With respect to real property, each of the pipelines falls into two basic
categories: (1) parcels that are owned in fee, such as certain of the compressor
stations, measurement stations and district office sites; and (2) parcels where
the interest derives from leases, easements, rights-of-way, permits or licenses
from landowners or governmental authorities permitting the use of such land for
the construction, operation and maintenance of the pipelines.
The Company believes that Kern River and Northern Natural Gas each have
satisfactory title to all of the real property
-31-
making up their respective pipelines in all material respects.
OTHER PROPERTIES
At December 31, 2002, the Company's most significant physical
properties, other than those owned by MidAmerican Energy, CE Electric UK, Kern
River and Northern Natural Gas, are its current interests in operating power
facilities and its plants under construction and related real property
interests, as well as leases of office space for its residential real estate
brokerage operations. See "Business" for further detail.
ITEM 3. LEGAL PROCEEDINGS.
In addition to the proceedings described below, the Company and its subsidiaries
are currently parties to various items of litigation or arbitration, none of
which are reasonably expected by the Company to have a material adverse effect
on it.
Pipeline Litigation
- -------------------
In 1998, the United States Department of Justice informed the then current
owners of Kern River and Northern Natural Gas that Jack Grynberg, an individual,
had filed claims in the United States District Court for the District of
Colorado under the False Claims Act against such entities and certain of their
subsidiaries including Kern River and Northern Natural Gas. Mr. Grynberg has
also filed claims against numerous other energy companies and alleges that the
defendants violated the False Claims Act in connection with the measurement and
purchase of hydrocarbons. The relief sought is an unspecified amount of
royalties allegedly not paid to the federal government, treble damages, civil
penalties, attorneys' fees and costs. On April 9, 1999, the United States
Department of Justice announced that it declined to intervene in any of the
Grynberg qui tam cases, including the actions filed against Kern River and
Northern Natural Gas in the United States District Court for the District of
Colorado. On October 21, 1999, the Panel on Multi-District Litigation
transferred the Grynberg qui tam cases, including the ones filed against Kern
River and Northern Natural Gas, to the United States District Court for the
District of Wyoming for pre-trial purposes. Motions to dismiss the complaint,
filed by various defendants including Northern Natural Gas and Williams, which
was the former owner of Kern River, were denied on May 18, 2001. On October 9,
2002, the United States District Court for the District of Wyoming dismissed
Grynberg's Royalty Valuation Claims. Grynberg has appealed this dismissal to the
United States Court of Appeals for the Tenth Circuit. In connection with the
purchase of Kern River from Williams in March 2002, Williams agreed to indemnify
the Company against any liability for this claim; however, no assurance can be
given as to the ability of Williams to perform on this indemnity should it
become necessary. No such indemnification was obtained in connection with the
purchase of Northern Natural Gas in August 2002. The Company believes that the
Grynberg cases filed against Kern River and Northern Natural Gas are without
merit and Williams, on behalf of Kern River pursuant to its indemnification, and
Northern Natural Gas, intend to defend these actions vigorously.
On June 8, 2001, a number of interstate pipeline companies, including Kern River
and Northern Natural Gas, were named as defendants in a nationwide class action
lawsuit which had been pending in the 26th Judicial District, District Court,
Stevens County Kansas, Civil Department against other defendants, generally
pipeline and gathering companies, since May 20, 1999. The plaintiffs allege that
the defendants have engaged in mismeasurement techniques that distort the
heating content of natural gas, resulting in an alleged underpayment of
royalties to the class of producer plaintiffs. In November 2001, Kern River and
Northern Natural Gas, along with the coordinating defendants, filed a motion to
dismiss under Rules 9B and 12B of the Kansas Rules of Civil Procedure. In
January 2002, Kern River and most of the coordinating defendants filed a motion
to dismiss for lack of personal jurisdiction. The court has yet to rule on these
motions. The plaintiffs filed for certification of the plaintiff class on
September 16, 2002. On January 13, 2003, oral arguments were heard on
coordinating defendants' opposition to class certification. Williams has agreed
to indemnify the Company against any liability associated with Kern River for
this claim; however, no assurance can be given as to the ability of Williams to
perform on this indemnity should it become necessary. Williams, on behalf of
Kern River and other entities, anticipates joining with Northern Natural Gas and
other defendants in contesting certification of the plaintiff class. Kern River
and Northern Natural Gas believe that this claim is without merit and that Kern
River's and Northern Natural Gas' gas measurement techniques have been in
accordance with industry standards and its tariff.
-32-
Philippines
- -----------
Casecnan Construction Arbitration
On February 12, 2001, the contractor filed a Request for Arbitration with the
International Chamber of Commerce seeking schedule relief of up to 153 days
through August 31, 2001 resulting from various alleged force majeure events. In
its March 20, 2001 Supplement to Request for Arbitration, the contractor
requested compensation for alleged additional costs of approximately $4 million
it incurred from the claimed force majeure events to the extent it is unable to
recover from its insurer. On April 20, 2001, the contractor filed a further
supplement seeking an additional compensation for damages of approximately $62
million for the alleged force majeure event (and geologic conditions) related to
the collapse of the surge shaft. The contractor also has alleged that the
circumstances in which CE Casecnan assumed control of the Casecnan Project and
placed it into commercial operation on December 11, 2001 amounted to a
repudiation of the construction contract and has filed a claim for unspecified
quantum meruit damages, and has further alleged that the delay liquidated
damages clause which provides for payments of $125,000 per day for each day of
delay in completion of the Project for which the contractor is responsible is
unenforceable. The arbitration is being conducted applying New York law and in
accordance with the rules of the International Chamber of Commerce.
Hearings have been held in connection with this arbitration in July 2001,
September 2001, January 2002, March 2002, November 2002 and January 2003. As
part of those hearings, on June 25, 2001, the arbitration tribunal temporarily
enjoined CE Casecnan from making calls on the demand guaranty posted by Banca di
Roma in support of the contractor's obligations to CE Casecnan for delay
liquidated damages. As a result of the continuing nature of that injunction, on
April 26, 2002, CE Casecnan and the contractor mutually agreed that no demands
would be made on the Banca di Roma demand guaranty except pursuant to an
arbitration award. As of December 31, 2002, however, CE Casecnan has received
approximately $6.0 million of liquidated damages from demands made on the demand
guarantees posted by a separate financial institution on behalf of the
contractor. On November 7, 2002, the International Chamber of Commerce issued
the arbitration tribunal's partial award with respect to the contractor's force
majeure and geologic conditions claims. The arbitration panel awarded the
contractor 18 days of schedule relief in the aggregate for all of the force
majeure events and awarded the contractor $3.8 million with respect to the cost
of the collapsed surge shaft. All of the contractor's other claims with respect
to force majeure and geologic conditions were denied.
Further hearings on the contractor's repudiation and quantum meruit claims, the
alleged unenforceability of the delay liquidated damages clause and certain
other matters had been scheduled for March 24 through March 28, 2003, but were
postponed as a result of the commencement of military action in Iraq. The
arbitral tribunal has requested the parties to indicate the earliest possible
date on which they are available and will then reschedule the hearings.
If the contractor were to prevail on its claim that the delay liquidated damages
clause is unenforceable, CE Casecnan would not be entitled to collect such delay
damages for the period from March 31, 2001 through December 11, 2001. If the
contractor were to prevail in its repudiation claim and prove quantum meruit
damages in excess of amounts already paid to the contractor, CE Casecnan could
be liable to make additional payments to the contractor. CE Casecnan believes
all such allegations and claims are without merit and is vigorously contesting
the contractor's claims.
Casecnan NIA Arbitration
Under the terms of the Project Agreement, NIA has the option of timely
reimbursing CE Casecnan directly for certain taxes CE Casecnan has paid. If NIA
does not so reimburse CE Casecnan, the taxes paid by CE Casecnan result in an
increase in the Water Delivery Fee. The payment of certain other taxes by CE
Casecnan results automatically in an increase in the Water Delivery Fee. As of
December 31, 2002, CE Casecnan has paid approximately $56.7 million in taxes
which as a result of the foregoing provisions has resulted in an increase in the
Water Delivery Fee. NIA has failed to pay the portion of the Water Delivery Fee
each month which relates to the payment of these taxes by CE Casecnan. As a
result of this non-payment, on August 19, 2002, CE Casecnan filed a Request for
Arbitration against NIA, seeking payment of such portion of the Water Delivery
Fee and enforcement of the relevant provision of the Project Agreement going
forward. The arbitration will be conducted in accordance with the rules of the
International Chamber of Commerce. NIA is expected to file its answer late in
the first quarter or early in the second quarter, 2003. The three member
arbitration panel has been confirmed by the International Chamber of Commerce
and an initial organizational hearing is scheduled for the second quarter, 2003.
Casecnan Stockholder Litigation
Pursuant to the share ownership adjustment mechanism in the CE Casecnan
stockholder agreement, which is based
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upon pro forma financial projections of the Casecnan Project prepared following
commencement of commercial operations, in February 2002, MidAmerican, through
its indirect wholly owned subsidiary CE Casecnan Ltd., advised the minority
stockholder LaPrairie Group Contractors (International) Ltd., ("LPG"), that
MidAmerican'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, inter alia, CE Casecnan Ltd. and MidAmerican. In the
complaint, LPG seeks compensatory and punitive damages for alleged breaches of
the stockholder agreement and alleged breaches of fiduciary duties allegedly
owed by CE Casecnan Ltd. and MidAmerican to LPG. The complaint also seeks
injunctive relief against all defendants and a declaratory judgment that LPG is
entitled to maintain its 15% interest in CE Casecnan. The impact, if any, of
this litigation on the Company cannot be determined at this time.
In February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. ("San
Lorenzo"), an original shareholder substantially all of whose shares in CE
Casecnan a subsidiary of the Company purchased in 1998, threatened to initiate
legal action in the Philippines in connection with certain aspects of its option
to repurchase such shares on or prior to commercial operation of the Project. CE
Casecnan 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, will
vigorously defend any such action.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
-34-
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Since March 14, 2000, the Company's equity securities have been owned by a
limited group of private investors and have not been registered with the SEC
pursuant to the Securities Act of 1933, as amended, listed on a stock exchange
or otherwise publicly held or traded.
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ITEM 6. SELECTED FINANCIAL DATA.
SELECTED CONSOLIDATED FINANCIAL DATA
(Amounts in thousands)
The following table sets forth selected historical consolidated financial data,
which should be read in conjunction with the Company's financial statements and
the related notes to those statements included in this annual report and with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" appearing elsewhere in this annual report. The selected consolidated
data as of and for the years ended December 31, 2002 and 2001, as of December
31, 2000 and for the periods from March 14, 2000 through December 31, 2000, and
from January 1, 2000 through March 13, 2000 and as of and for the years ended
December 31, 1999 and 1998 have been derived from the Company's audited
historical consolidated financial statements.
MEHC (PREDECESSOR)
------------------------------------
MARCH 14, 2000 YEAR ENDED
YEAR ENDED DECEMBER 31, THROUGH JANUARY 1, 2000 DECEMBER 31,
----------------------- DECEMBER 31, THROUGH -------------------
2002(1) 2001(2) 2000(3) MARCH 13, 2000 1999 (4) 1998 (5)
--------- --------- ------------ --------------- -------------------
Statement of Operations Data:
Operating revenue .................. $ 4,794.0 $ 4,696.8 $ 3,918.1 $1,056.4 $ 4,086.6 $2,475.2
Total revenue ...................... 4,968.1 4,973.0 4,013.0 1,075.8 4,368.5 2,602.7
Total costs and expenses ........... 4,325.0 4,469.1 3,793.8 984.7 4,011.5 2,330.7
Income before provision
for income taxes ................... 643.1 503.9 219.2 91.2 357.1 272.1
Minority interest .................. 163.5 106.5 84.7 8.9 46.9 41.3
Income before extraordinary item
and change in accounting
principle .......................... 380.0 147.3 81.3 51.3 216.7 --
Extraordinary item,
net of tax ......................... -- -- -- -- (49.4) (7.1)
Cumulative effect of
change in accounting
principle, net of tax .............. -- (4.6) -- -- -- (3.4)
Net income ......................... 380.0 142.7 81.3 51.3 167.2 127.0
BALANCE SHEET DATA:
Total assets ....................... $18,016.5 $12,626.7 $11,610.9 N/A $10,766.4 $9,103.5
Total liabilities .................. 13,478.0 9,778.8 8,911.3 N/A 8,987.9 7,598.0
Company-obligated mandatory
redeemable preferred securities of
subsidiary trusts .................. 2,063.4 788.2 786.5 N/A 450.0 553.9
Subsidiary-obligated mandatorily
redeemable preferred securities
of subsidiary trusts ............... -- 100.0 100.0 N/A 101.6 --
Preferred securities of subsidiaries 93.3 121.2 145.7 N/A 146.6 66.0
Total stockholders' equity ......... 2,294.3 1,708.2 1,576.4 N/A 994.6 827.1
(1) Reflects the acquisitions of Kern River on March 27, 2002 and Northern
Natural Gas on August 16, 2002.
(2) Reflects the Yorkshire Swap on September 21, 2001.
(3) Reflects the Teton Transaction on March 14, 2000.
(4) Reflects the MidAmerican Energy acquisition on March 12, 1999, the
disposition of Coso Joint Ventures on February 26, 1999, the disposition of
50% ownership interest in CE Generation on March 3, 1999, $81.5 million for
non-recurring Indonesia gain on settlement, gains on sales of McLeodUSA
Class A common stock and qualified facilities, CE Electric UK restructuring
charges and Teton Transaction costs.
(5) Reflects the acquisition of Kiewit Diversified Group on January 2, 1998.
-36-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
The following is management's discussion and analysis of certain significant
factors which have affected the Company's financial condition and results of
operations during the periods included in the accompanying statements of
operations. This discussion should be read in conjunction with "Selected
Consolidated Financial Data" and the Company's historical financial statements
and the notes to those statements included elsewhere in this annual report.
GENERAL
The Company is a United States-based privately owned global energy company with
publicly held fixed income securities that generates, distributes and supplies
energy to utilities, government entities, retail customers and other customers
located throughout the world. Through its subsidiaries, its operations are
organized and managed on seven distinct platforms: MidAmerican Energy, Kern
River, Northern Natural Gas, CE Electric UK (which includes Northern Electric
and Yorkshire), CalEnergy Generation-Domestic, CalEnergy Generation-Foreign and
HomeServices.
As a result of the recent acquisitions of Kern River and Northern Natural Gas,
the Yorkshire Swap, and the acquisition by a private investor group on March 14,
2000, the Company's future results will differ from its historical results.
2002 ACQUISITIONS
Kern River
- ----------
In March 2002, the Company acquired Kern River for $419.7 million, net of cash
acquired of $7.7 million and a working capital adjustment. Kern River owns a
926-mile interstate natural gas pipeline extending from Wyoming to markets in
California, Nevada and Utah and accesses natural gas supplies from large
producing regions in the Rocky Mountains and Canada. In connection with the
acquisition of Kern River, the Company issued $323.0 million of 11%
Company-obligated mandatorily redeemable preferred securities of subsidiary
trust due March 12, 2012 with scheduled principal payments beginning in 2005 and
$127.0 million of no par, zero coupon convertible preferred stock to Berkshire
Hathaway Inc.("Berkshire Hathaway").
Northern Natural Gas
- --------------------
In August 2002, the Company acquired Northern Natural Gas for $882.7 million,
net of cash acquired of $1.4 million and a working capital adjustment. Northern
Natural Gas owns a 16,600-mile interstate natural gas pipeline extending from
southwest Texas to the upper Midwest region of the United States with a design
capacity of 4.4 Bcf of natural gas per day. Northern Natural Gas also operates
three natural gas storage facilities and two liquefied natural gas peaking units
with a total storage capacity of 59 Bcf and peak delivery capability of over 1.3
Bcf of natural gas per day. Northern Natural Gas accesses natural gas supply
from many of the larger producing regions in North America, including the Rocky
Mountains, Hugoton, Permian, Anadarko and Western Canadian basins. The pipeline
system provides transportation and storage services to utilities,
municipalities, other pipeline companies, gas marketers and industrial and
commercial users. The Company used the proceeds from a $950.0 million investment
in its subsidiary trust's preferred securities by Berkshire Hathaway to finance
the acquisition.
HomeServices' 2002 Acquisitions
- -------------------------------
In 2002, HomeServices separately acquired three real estate companies for an
aggregate purchase price of approximately $106.1 million, net of cash acquired,
plus working capital and certain other adjustments. For the year ended December
31, 2001, these real estate companies had combined revenue of approximately
$356.0 million on 42,000 closed sides representing $13.7 billion of sales
volume. Additionally, HomeServices is obligated to pay a maximum earnout of
$18.5 million based on 2002 financial performance measures. These purchases were
financed using HomeServices' internally generated cash flows, revolving credit
facility and $40.0 million from the Company, which was contributed to
HomeServices as equity.
-37-
CRITICAL ACCOUNTING POLICIES
The preparation of financial statements and related documents in conformity with
accounting principles generally accepted in the United States of America
requires management to make judgments, assumptions and estimates that affect the
amounts reported in the consolidated financial statements and accompanying
notes. Note 2 to the consolidated financial statements for the year ended
December 31, 2002 included in this annual report describes the significant
accounting policies and methods used in the preparation of the consolidated
financial statements. Estimates are used for, but not limited to, the accounting
for revenue, the effects of certain types of regulation, impairment of
long-lived assets, and contingent liabilities. Actual results could differ from
these estimates. The following critical accounting policies are impacted
significantly by judgments, assumptions and estimates used in the preparation of
the consolidated financial statements.
Accounting for the Effects of Certain Types of Regulation
- ---------------------------------------------------------
MidAmerican Energy, Kern River and Northern Natural Gas prepare their financial
statements in accordance with the provisions of Statement of Financial
Accounting Standards ("SFAS") No. 71 ("SFAS 71"), which differs in certain
respects from the application of generally accepted accounting principles by
non-regulated businesses. In general, SFAS 71 recognizes that accounting for
rate-regulated enterprises should reflect the economic effects of regulation. As
a result, a regulated utility is required to defer the recognition of costs (a
regulatory asset) or the recognition of obligations (a regulatory liability) if
it is probable that, through the rate-making process, there will be a
corresponding increase or decrease in future rates. Accordingly, MidAmerican
Energy, Kern River and Northern Natural Gas have deferred certain costs, which
will be amortized over various future periods. To the extent that collection of
such costs or payment of such obligations is no longer probable as a result of
changes in regulation, the associated regulatory asset or liability is charged
or credited to income.
A possible consequence of deregulation of the regulated energy industry is that
SFAS 71 may no longer apply. If portions of the Company's subsidiaries'
regulated energy operations no longer meet the criteria of SFAS 71, the Company
could be required to write off the related regulatory assets and liabilities
from its balance sheet, and thus a material adjustment to earnings in that
period could result if regulatory assets or liabilities are not recovered in
transition provisions of any deregulation legislation.
The Company continues to evaluate the applicability of SFAS 71 to its regulated
energy operations and the recoverability of these assets and liabilities through
rates as there are on-going changes in the regulatory and economic environment.
Impairment of Long-Lived Assets
- -------------------------------
The Company's long-lived assets consist primarily of properties, plants and
equipment. Depreciation is computed using the straight-line method based on
economic lives or regulatory mandated recovery periods. The Company believes the
useful lives assigned to the depreciable assets, which generally range from 3 to
87 years, are reasonable.
The Company periodically evaluates long-lived assets, including properties,
plants and equipment, when events or changes in circumstances indicate that the
carrying value of these assets may not be recoverable. Upon the occurrence of a
triggering event, the carrying amount of a long-lived asset is reviewed to
assess whether the recoverable amount has declined below its carrying amount.
The recoverable amount is the estimated net future cash flows that the Company
expects to recover from the future use of the asset, undiscounted and without
interest, plus the asset's residual value on disposal. Where the recoverable
amount of the long-lived asset is less than the carrying value, an impairment
loss would be recognized to write down the asset to its fair value that is based
on discounted estimated cash flows from the future use of the asset.
The estimate of cash flows arising from future use of the asset that are used in
the impairment analysis requires judgment regarding what the Company would
expect to recover from future use of the asset. Any changes in the estimates of
cash flows arising from future use of the asset or the residual value of the
asset on disposal based on changes in the market conditions, changes in the use
of the asset, management's plans, the determination of the useful life of the
asset and technology changes in the industry could significantly change the
calculation of the fair value or recoverable amount of the asset and the
resulting impairment loss, which could significantly affect the results of
operations. The determination of whether impairment has occurred is based on an
estimate of undiscounted cash flows attributable to the assets, as compared to
the carrying value of the assets. An impairment analysis of generating
facilities requires estimates of possible future market prices, load growth,
competition and many other factors over the lives of the facilities. A resulting
impairment loss is highly dependent on these underlying assumptions.
-38-
Contingent Liabilities
- ----------------------
The Company establishes reserves for estimated loss contingencies when it is
management's assessment that a loss is probable and the amount of the loss can
be reasonably estimated. Revisions to contingent liabilities are reflected in
operations in the period in which different facts or information become known or
circumstances change that affect the previous assumptions with respect to the
likelihood or amount of loss. Reserves for contingent liabilities are based upon
management's assumptions and estimates, and advice of legal counsel or other
third parties regarding the probable outcomes of any matters. Should the
outcomes differ from the assumptions and estimates, revisions to the estimated
reserves for contingent liabilities would be required.
Revenue Recognition
- -------------------
Revenue is recorded based upon services rendered and electricity, gas and steam
delivered, distributed or supplied to the end of the period. The Company records
unbilled revenue representing the estimated amounts customers will be billed for
services rendered between the meter reading dates in a particular month and the
end of that month. The unbilled revenue estimate is reversed in the following
month. To the extent the estimated amount differs from the actual amount
subsequently billed, revenue will be affected.
Where there is an over recovery of United Kingdom distribution business revenue
against the maximum regulated amount, revenue is deferred in an amount
equivalent to the over recovered amount. The deferred amount is deducted from
revenue and included in other liabilities. Where there is an under recovery, no
anticipation of any potential future recovery is made.
Revenue from the transportation and storage of gas are recognized based on
contractual terms and the related volumes. Kern River and Northern Natural Gas
are subject to the FERC's regulations and, accordingly, certain revenue
collected may be subject to possible refunds upon final orders in pending rate
cases. Kern River and Northern Natural Gas record rate refund liabilities
considering their regulatory proceedings and other third party regulatory
proceedings, advice of counsel and estimated total exposure, as discounted and
risk weighted, as well as collection and other risks.
Commission revenue from real estate brokerage transactions and related amounts
due to agents are recognized when title has transferred from seller to buyer.
Title fee revenue from real estate transactions and related amounts due to the
title insurer are recognized at the closing, which is when consideration is
received. Fees related to loan originations are recognized at the closing, which
is when services have been provided and consideration is received.
RESULTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2002 AND THE YEAR ENDED
DECEMBER 31, 2001
Operating revenue for the year ended December 31, 2002 increased $97.2 million
or 2.1% to $4,794.0 million from $4,696.8 million for the same period in 2001.
CE Electric UK operating revenue for the year ended December 31, 2002 decreased
$648.6 million or 44.9% to $795.4 million from $1,444.0 million for the same
period in 2001, primarily due to the sale of the supply business in 2001
partially offset by the acquisition of Yorkshire Electric in September 2001 and
changes in the exchange rate. CE Electric UK distributed 41,157 GWh of
electricity in the year ended December 31, 2002, compared with 23,770 GWh of
electricity in the same period in 2001. The increase in electricity distributed
is primarily due to the acquisition of Yorkshire distribution.
MidAmerican Energy operating revenue for the year ended December 31, 2002
decreased $147.8 million or 6.2% to $2,240.9 million from $2,388.7 million for
the same period in 2001. MidAmerican Energy electric retail sales increased for
the year ended December 31, 2002 from the same period in 2001 due primarily to
higher temperatures in 2002, primarily in the third quarter of 2002. Regulated
and non-regulated gas revenue decreased due to lower prices for gas purchased
passed directly to the customer.
Kern River operating revenue, from its date of acquisition, was $127.3 million.
Kern River transported 285,848,285 MMBtus during the period since the Company
acquired Kern River on March 27, 2002 through December 31, 2002.
Northern Natural Gas operating revenue, from its date of acquisition, was $176.9
million. Northern Natural Gas transported 416,272,813 MMBtus since the Company
acquired Northern Natural Gas on August 16, 2002 through December 31, 2002.
-39-
CalEnergy Generation - Domestic operating revenue for the year ended December
31, 2002 increased $1.2 million or 3.2% to $38.5 million from $37.3 million for
the same period in 2001.
CalEnergy Generation - Foreign operating revenue for the year ended December 31,
2002 increased $122.8 million or 60.3% to $326.3 million from $203.5 million for
the same period in 2001, primarily due to commencement of commercial operation
of the Casecnan Project in December 2001.
HomeServices operating revenue for the year ended December 31, 2002 increased
$496.4 million or 77.3% to $1,138.3 million from $641.9 million for the same
period in 2001, primarily due to current year acquisitions' contributions of
$431.5 million. The remainder of HomeServices' increase was due to growth of
existing companies of $105.3 million partially offset by a decrease of $40.4
million from a joint venture that was consolidated in 2001 and is accounted for
under the equity method in 2002.
Income on equity investments for the year ended December 31, 2002 increased $0.9
million or 2.3% to $40.5 million from $39.6 million for the same period in 2001.
The increase was primarily due to $8.8 million income from a HomeServices' joint
venture which was fully consolidated in 2001 partially offset by $7.9 million
lower earnings at CE Generation as a result of higher earnings from higher
energy prices in 2001.
Interest and dividend income for the year ended December 31, 2002 increased
$31.7 million or 128.9% to $56.3 million from $24.6 million for the same period
in 2001. The increase was primarily due to increased interest income at CE
Electric UK of $15.1 million due to the increased cash balance following the
Yorkshire acquisition and increased corporate interest and dividends of $13.4
million primarily due to dividends received on the investment in Williams
preferred securities.
Other income for the year ended December 31, 2002 decreased $134.7 million or
63.5% to $77.4 million from $212.1 million for the same period in 2001. Other
income in 2002 resulted primarily from the non-recurring gain on the sale of CE
Gas of $54.3 million and equity AFUDC at Kern River of $10.6 million. These
items were offset, in 2002, by losses from the write-down of investments at
MidAmerican Energy of $21.9 million. Other income in 2001 resulted from the
non-recurring gains from the sales of Northern Electric's supply business,
Telephone Flat and Western States Geothermal of $196.7 million, $20.7 million
and $9.8 million, respectively, and a non-recurring gain from the transfer of
Bali shares of $10.4 million. These items were partially offset, in 2001, by a
charge related to the impairment of the Company's interest in Teeside Power
Limited ("TPL") of $58.8 million.
Cost of sales for the year ended December 31, 2002 decreased $497.2 million or
21.2% to $1,844.0 million from $2,341.2 million for the same period in 2001.
CE Electric UK cost of sales for the year ended December 31, 2002 decreased
$713.2 million or 84.6% to $129.5 million from $842.7 million for the same
period in 2001. The decrease was primarily due to the sale of the supply
business in 2001.
MidAmerican Energy cost of sales for the year ended December 31, 2002 decreased
$132.4 million or 11.8% to $988.9 million from $1,121.3 million for the same
period in 2001, primarily due to decreases in regulated and non-regulated gas
costs, caused by lower volumes and prices, partially offset by an increase in
regulated electric costs caused by higher volumes, partially offset by the
restructuring of the Cooper Nuclear Station contract.
Northern Natural Gas had cost of sales of $1.1 million since its acquisition on
August 16, 2002.
HomeServices cost of sales for the year ended December 31, 2002 increased $371.9
million or 94.0% to $767.6 million from $395.7 million for the same period in
2001. The increase was primarily due to acquisitions during 2002 of $315.6
million, and higher commission expense resulting from increased sales at
existing HomeServices divisions, partially offset by $9.0 million of cost of
sales from a joint venture which had been consolidated in 2001 and is accounted
for under the equity method in 2002.
Operating expenses for the year ended December 31, 2002 increased $168.8 million
or 14.3% to $1,345.2 million from $1,176.4 million for the same period in 2001.
The increase was primarily due to higher costs at HomeServices of $99.1 million
as a result of acquisitions, operating expenses due to the acquisitions of
Northern Natural Gas of $95.0 million and Kern River of $27.2 million and plant
operating expenses at the Zinc project and Casecnan of $33.9 million, partially
offset by lower costs at MidAmerican Energy of $57.5 million primarily due to
the restructuring of the Cooper Nuclear Station contract and lower energy
efficiency expenses and lower costs at CE Electric UK of $28.5 million due to
the sale of the supply business.
-40-
Depreciation and amortization for the year ended December 31, 2002 decreased
$12.8 million or 2.4% to $525.9 million from $538.7 million for the same period
in 2001. The decrease was primarily due to discontinuance of amortizing goodwill
beginning January 1, 2002 of $96.4 million, partially offset by a full year of
operations at CE Casecnan of $22.0 million, higher depreciation at MidAmerican
Energy of $17.2 million primarily due to higher Iowa revenue sharing accruals
and a change in the estimated useful lives of electric general plant,
depreciation expense due to the acquisitions of Kern River of $17.2 million and
Northern Natural Gas of $18.2 million and increased amortization at HomeServices
of $9.5 million primarily due to the amortization of the gross margin of pending
sales contracts related to acquisitions.
Interest expense, less amounts capitalized, for the year ended December 31, 2002
increased $197.1 million or 47.7% to $609.9 million from $412.8 million for the
same period in 2001. The increase was primarily due to the increase of interest
expense at CE Electric UK of $71.3 million predominantly due to the debt related
to the Yorkshire acquisition, interest expense due to debt related to the
acquisitions of Kern River and Northern Natural Gas of $33.0 million and $23.0
million, respectively and the discontinuance of capitalizing interest related to
the Casecnan Project, the Cordova Project and the Zinc Recovery Project of $50.9
million, $9.4 million and $5.3 million, respectively, all partially offset by
capitalized interest at Kern River of $14.0 million.
Tax expense for the year ended December 31, 2002 decreased $150.5 million or
60.2% to $99.6 million from $250.1 million for the same period in 2001. The
decrease is due primarily to the tax expense related to the sale of the Northern
Electric supply business in September 2001, the release of the tax obligation of
$35.7 million in connection with the execution of the TPL restructuring
agreement at CE Electric UK in 2002, and the recognition of a tax benefit in
connection with the sale of the CE Gas assets in 2002.
Minority interest and preferred dividends for the year ended December 31, 2002
increased $57.0 million or 53.5% to $163.5 million from $106.5 million for the
same period in 2001. Minority interest and preferred dividends includes the
dividends on the Company-obligated mandatorily redeemable preferred securities
of subsidiary trusts. The increase in minority interest and preferred dividends
is primarily due to the issuance of Company-obligated mandatorily redeemable
preferred securities of subsidiary trusts relating to the Kern River and
Northern Natural Gas acquisitions.
Effective January 1, 2001, the Company changed its accounting policy regarding
major maintenance and repairs for non-regulated gas projects, non-regulated
plant overhaul costs and geothermal well rework costs to the direct expense
method from the former policy of monthly accruals based on long-term scheduled
maintenance plans for the gas projects and deferral and amortization of plant
overhaul costs and geothermal well rework costs over the estimated useful lives.
The cumulative effect of the change in accounting principle for 2001 was $4.6
million, net of taxes.
RESULTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2001 AND THE PERIODS MARCH
14, 2000 THROUGH DECEMBER 31, 2000, AND JANUARY 1, 2000 THROUGH MARCH 13, 2000
The following is a discussion of the historical results of the Company for the
year ended December 31, 2001 and the period March 14, 2000 through December 31,
2000, and of its predecessor (referred to as "MEHC (Predecessor)") for the
period January 1, 2000 through March 13, 2000. Results for the Company include
the impact of the Teton Transaction beginning March 14, 2000 which are
predominately the minority interest costs on issuance of Company-obligated
mandatorily redeemable preferred securities of a subsidiary trust and the
effects of purchase accounting, including goodwill amortization and fair value
adjustments to the carrying value of assets and liabilities.
Operating revenue for the year ended December 31, 2001 decreased $277.7 million
or 5.6% to $4,696.8 million from $4,974.5 million for the same period in 2000.
MidAmerican Energy operating revenue for the year ended December 31, 2001
increased $72.4 million or 3.1% to $2,388.7 million from $2,316.3 million for
the same period in 2000. MidAmerican Energy electric retail sales increased for
the year ended December 31, 2001 from the same period in 2000 due to the warmer
temperatures during the cooling season and an increase in non-weather related
sales. Electric sales for resale increased for the year ended December 31, 2001
from the same period in 2000 due to higher production at the Cooper and Neal
power plants and favorable market conditions. Regulated and non-regulated gas
supplied increased due principally to growth in the non-regulated markets for
the year ended December 31, 2001 compared to the same period in 2000.
CE Electric UK operating revenue for the year ended December 31, 2001 decreased
$553.9 million or 27.7% to $1,444.0 million from $1,997.9 million for the same
period in 2000, primarily due to the sale of the supply business in 2001 and
changes in foreign exchange rates. The decrease in electricity supplied for the
year ended December 31, 2001 is due to
-41-
the sale of the Northern Electric supply business in September 2001. The
increase in electricity distributed for the year ended December 31, 2001 is due
to the addition of Yorkshire and changes in demand in the distribution area. The
decrease in gas supplied in 2001 from 2000 reflects the sale of the Northern
Electric supply business.
The remaining increase primarily relates to the increase of revenue at
HomeServices due to acquisitions and the inclusion of a joint venture which was
previously accounted for as an equity investment and the commencement of
operations of the Cordova Project in June 2001.
Income on equity investments for the year ended December 31, 2001 decreased $3.9
million or 9.0% to $39.6 million from $43.5 million for the same period in 2000.
The decrease was primarily due to a joint venture at HomeServices previously
accounted for as an equity investment that was fully consolidated in 2001.
Interest and dividend income for the year ended December 31, 2001 decreased $8.8
million or 26.3% to $24.6 million from $33.4 million for the same period in
2000. The decrease was due primarily to decreased interest income at Casecnan as
funds previously invested were used for capital expenditures.
Other income for the year ended December 31, 2001 increased $174.6 million to
$212.1 million from $37.5 million for the same period in 2000. The increase was
primarily due to non-recurring gains from the sales of Northern Electric's
supply business, Telephone Flat and Western States Geothermal recorded in 2001,
of $196.7 million, $20.7 million and $9.8 million, respectively, and a
non-recurring gain from the transfer of Bali shares of $10.4 million in 2001.
These items were partially offset by a write down of the investment in TPL
during 2001 of $58.8 million.
Cost of sales for the year ended December 31, 2001 decreased $428.0 million or
15.5% to $2,341.2 million from $2,769.2 million for the same period in 2000. The
decrease relates primarily to decreased cost of sales at CE Electric UK due to
the sale of the Northern Electric supply business, lower foreign exchange rate
and lower electricity volumes and prices, partially offset by increased volumes
and prices for both regulated and non-regulated gas at MidAmerican Energy, and
acquisitions at HomeServices.
Operating expenses for the year ended December 31, 2001 increased $45.0 million
or 4.0% to $1,176.4 million from $1,131.4 million for the same period in 2000.
The increase was primarily due to higher costs at HomeServices due to
acquisitions and the inclusion of a joint venture which was previously accounted
for as an equity investment and higher costs at MidAmerican Energy due to costs
related to Cooper, accounts receivable discounts and bad debts, partially offset
by lower costs at CE Electric UK due to the sale of the supply business, lower
pension costs and a lower exchange rate, partially offset by the addition of
Yorkshire. In addition, the Company recorded $7.6 million in the period from
January 1, 2000 through March 13, 2000 which represents the costs incurred
related to the Teton Transaction.
Depreciation and amortization for the year ended December 31, 2001 increased
$58.1 million or 12.1% to $538.7 million from $480.6 million for the same period
in 2000. This increase was due to higher depreciation at MidAmerican Energy due
to inclusion of Iowa revenue sharing accrual and an increase in depreciation
rates implemented in 2001 and amortization of the gross margin of pending sales
contracts related to the HomeServices acquisitions, partially offset by lower
depreciation at CE Electric UK due to lower amortization of operational assets
and lower exchange rate, partially offset by the addition of Yorkshire.
Interest expense, less amounts capitalized, for the year ended December 31, 2001
increased $15.6 million or 3.9% to $412.8 million from $397.2 million for the
same period in 2000. This increase is due to increased interest expense
associated with the debt acquired with Yorkshire and lower capitalized interest
on the mineral extraction process, partially offset by lower average outstanding
debt balances and lower foreign exchange rates at CE Electric UK.
Tax expense for the year ended December 31, 2001 increased $165.8 million or
196.7% to $250.1 million from $84.3 million for the same period in 2000. The
increase is due primarily to the tax on the gain related to the sale of Northern
Electric supply business and higher pre-tax income.
Minority interest and preferred dividends for the year ended December 31, 2001
increased $13.0 million or 13.9% to $106.5 million from $93.5 million for the
same period in 2000. The increase is primarily due to the issuance of
Company-obligated mandatorily redeemable preferred securities of subsidiary
trusts relating to the Teton Transaction and increased minority interest at
HomeServices related to certain mortgage and title joint ventures.
The cumulative effect of change in accounting principle of $4.6 million in 2001
represents the change in accounting for major maintenance and overhauls.
-42-
LIQUIDITY AND CAPITAL RESOURCES
The Company has available a variety of sources of liquidity and capital
resources, both internal and external. These resources provide funds required
for current operations, construction expenditures, debt retirement and other
capital requirements. The Company may from time to time seek to retire its
outstanding debt 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.
The Company's cash and cash equivalents were $844.4 million at December 31,
2002, compared $386.7 million at December 31, 2001. Each of the Company's direct
or indirect subsidiaries is organized as a legal entity separate and apart from
the Company and its other subsidiaries. Pursuant to separate financing
agreements at each subsidiary, the assets of each subsidiary may be pledged or
encumbered to support or otherwise provide the security for their own project or
subsidiary debt. It should not be assumed that any asset of any subsidiary of
the Company will be available to satisfy the obligations of the Company or any
of its other subsidiaries; provided, however, that unrestricted cash or other
assets which are available for distribution may, subject to applicable law and
the terms of financing arrangements for such parties, be advanced, loaned, paid
as dividends or otherwise distributed or contributed to the Company or
affiliates thereof.
The Company generated cash flows from operations of $757.7 million for the year
ended December 31, 2002, compared with $847.0 million for the same period in
2001. The decrease was primarily due to timing of changes in working capital
activities, partially offset by positive impacts of the Kern River, Northern
Natural Gas and real estate companies acquisitions.
The remaining increase to cash and cash equivalents is primarily due to the
issuances of convertible preferred stock, trust preferred securities and
subsidiary and project debt and cash proceeds from sale of assets, partially
offset by the Kern River and Northern Natural Gas acquisitions, purchase of
convertible preferred securities, repayment of subsidiary and project debt and
capital expenditures for operating and construction projects.
In addition, the Company recorded separately restricted cash and investments of
$58.7 million and $54.8 million at December 31, 2002, and December 31, 2001,
respectively. The restricted cash balance as of December 31, 2002, is comprised
primarily of amounts deposited in restricted accounts which are reserved for the
service of debt obligations.
Kern River
- ----------
The Company paid $419.7 million, net of cash acquired of $7.7 million and a
working capital adjustment, for Kern River's gas pipeline business. The
acquisition has been accounted for as a purchase business combination. The
Company is in the process of completing the allocation of the purchase price to
the assets and liabilities acquired. The results of operations for Kern River
are included in the Company's results beginning March 27, 2002.
In connection with the acquisition of Kern River, the Company issued $323.0
million of 11% Company-obligated mandatorily redeemable preferred securities of
subsidiary trust due March 12, 2012 with scheduled principal payments beginning
in 2005 and $127.0 million of no par, zero coupon convertible preferred stock to
Berkshire Hathaway. Each share of preferred stock is convertible at the option
of the holder into one share of the Company's common stock subject to certain
adjustments as described in the Company's Amended and Restated Articles of
Incorporation.
Northern Natural Gas
- --------------------
The Company paid $882.7 million for Northern Natural Gas, net of cash acquired
of $1.4 million and a working capital adjustment. At the time of the
acquisition, Northern Natural Gas had $950.0 million of debt outstanding. The
acquisition has been accounted for as a purchase business combination. The
Company is in the process of completing the allocation of the purchase price to
the assets and liabilities acquired. The results of operations for Northern
Natural Gas are included in the Company's results beginning August 16, 2002.
In connection with the acquisition of Northern Natural Gas, the Company issued
$950.0 million of 11% Company-obligated mandatorily redeemable preferred
securities of subsidiary trust due August 31, 2011, with scheduled principal
payments beginning in 2003, to Berkshire Hathaway.
-43-
HomeServices' 2002 Acquisitions
- ---------------------------------------
In 2002, HomeServices separately acquired three real estate companies for an
aggregate purchase price of approximately $106.1 million, net of cash acquired,
plus working capital and certain other adjustments. For the year ended December
31, 2001, these real estate companies had combined revenue of approximately
$356.0 million on 42,000 closed sides representing $13.7 billion of sales
volume. Additionally, HomeServices is obligated to pay a maximum earnout of
$18.5 million based on 2002 financial performance measures. These purchases were
financed using HomeServices' internally generated cash flows, revolving credit
facility and $40.0 million from the Company, which was contributed to
HomeServices as equity.
Williams' Company Preferred Stock
- ---------------------------------
On March 27, 2002, a newly formed subsidiary of the Company, MEHC Investments
Inc., invested $275.0 million in Williams in exchange for shares of 9 7/8%
cumulative convertible preferred stock of Williams. In connection with this
investment, the Company issued $275.0 million of no par, zero coupon convertible
preferred stock to Berkshire Hathaway. Dividends on the Williams' preferred
stock are scheduled to be received quarterly, which commenced July 1, 2002. This
investment is accounted for under the cost method. Since the date of this
investment, there have been public announcements that Williams' financial
condition has deteriorated as a result of, among other factors, reduced
liquidity. The Company had not recorded an impairment on this investment as of
December 31, 2002, and is monitoring the situation.
Yorkshire
- ---------
In August 2002, CE Electric UK acquired the remaining 5.25% of Yorkshire that it
did not already own from Xcel Energy for $33.3 million.
CE Gas Disposal
- ---------------
In May 2002, CE Gas, an indirect wholly owned subsidiary of the Company,
completed the sale of several of its U.K. natural gas assets to Gaz de France
for (pound) 137.0 million (approximately $200.0 million). CE Gas sold four
natural gas-producing fields located in the southern basin of the U.K. North Sea
including Anglia, Johnston, Schooner and Windermere. The transaction also
included the sale of rights in four gas fields in development and construction
and three exploration blocks owned by CE Gas.
Kern River's 2003 Expansion Project
- -----------------------------------
The 2003 Expansion Project is a new parallel 717-mile loop pipeline that will
begin in Lincoln County, Wyoming and terminate in Kern County, California. The
2003 Expansion Project began construction on August 6, 2002 and is expected to
be completed and operational May 1, 2003 at a total cost of approximately $1.2
billion. The pipeline will include 36- and 42-inch diameter pipe, most of which
will be laid in the existing Kern River rights-of-way at a 25-foot offset from
the existing pipeline, and new above ground facilities. Three segments along the
rights-of-way, approximately 205 miles in Utah, Nevada and California, will not
require additional pipeline but will instead be areas where the gas will be
compressed and transported through the existing pipeline. The existing pipeline
rights-of-way, compressor facilities and receipt/delivery facilities will all be
utilized by the 2003 Expansion Project, streamlining the permitting, acquisition
of rights-of-way and ultimately the construction and operations of the 2003
Expansion Project.
The 2003 Expansion Project includes the construction of three new compressor
stations and the installation of additional compression and other modifications
at six existing facilities. When completed, the Kern River system will have a
summer day design capacity of approximately 1.73 Bcf per day, an increase of
approximately 886 mmcf per day.
Kern River has 18 long-term firm transportation service agreements with 17
shippers for 100% of the 2003 Expansion Project's capacity. The term for all
these service agreements is either 10 or 15 years from the date on which
transportation services on the 2003 Expansion Project commences.
The 2003 Expansion Project is being financed with approximately 70% debt and 30%
equity, consistent with Kern River's original capital structure, the application
for FERC approval of the 2003 Expansion Project and the limitations contained in
the indenture for Kern River's existing secured senior notes. On June 21, 2002,
Kern River entered into an $875 million
-44-
credit facility to fund a portion of the costs of the 2003 Expansion Project and
the Company issued a completion guarantee in favor of the lenders under that
credit facility.
Construction is being initially funded with the proceeds of the $875.0 million
credit facility. The remaining approximately 30% of the capitalized costs of the
2003 Expansion Project is being funded with equity from the Company. The credit
facility is structured as a two-year construction facility followed by a term
loan with a final maturity 15 years after completion of the 2003 Expansion
Project. However, Kern River presently intends to refinance the construction
financing facility through a bond offering or other capital markets transaction
following completion of the 2003 Expansion Project. Prior to completion of the
2003 Expansion Project, the holders of the construction financing facility will
have limited recourse to Kern River and its assets and cash flow, and will have
recourse to the Company's completion guarantee described below. Following
completion of the 2003 Expansion Project, until such time as the Kern River
construction financing facility is refinanced, the lenders under the
construction financing facility will share equally and ratably with the existing
holders of Kern River's senior Notes in all of the collateral pledged to such
Senior Note holders.
Pursuant to MEHC's completion guarantee, the Company has guaranteed that
"completion" of the 2003 Expansion Project will occur on or prior to the
earliest of any abandonment by Kern River of the project, the occurrence of
certain other acceleration events and June 30, 2004. The potential acceleration
events include any downgrading of the Company's public debt rating to below
investment grade by either Standard & Poor's ("S&P") or Moody's Investors
Service Inc. unless a satisfactory substitute guarantor assumes the Company's
obligations under the completion guarantee within 60 days after any such
downgrade; Berkshire Hathaway ceasing to own at least a majority of the
outstanding capital stock of the Company; and certain other customary events of
default by the Company. In the completion guarantee, the Company has also agreed
to cause capital contributions to be made to Kern River in a minimum aggregate
amount of at least $375.0 million by June 30, 2004 or upon any earlier event of
abandonment of the project. For purposes of the Company's completion guarantee,
the term "completion" is defined in the Kern River construction financing
agreement to mean satisfaction of a number of conditions, the most significant
of which include the requirements that the 2003 Expansion Project be
substantially complete and operable and able to permit Kern River to perform its
obligations under all of the long-term firm gas transportation service
agreements entered into in connection with the 2003 Expansion Project; that the
shippers under such agreements shall have begun to incur the obligation to pay
reservation fees thereunder; and that the FERC shall have authorized Kern River
to begin collecting rates under its tariff and its shipper agreements; provided
that the 2003 Expansion Project shall still be deemed to have been completed if
it is less than substantially complete but it demonstrates at least 80% design
capacity and Kern River's debt service coverage ratios as defined in its Senior
Notes indenture are not less than 1:55 to 1:0. There are a number of other
conditions to completion, including requirements that all conditions to
completion of the expansion contained in Kern River's Senior Notes indenture be
satisfied and all of Kern River's obligations under its construction financing
agreement then share pari passu in all collateral available to Kern River's
senior secured noteholders. The Company's completion guarantee shall terminate
upon the earlier of completion of the 2003 Expansion Project or repayment in
full of all obligations under the Kern River credit facility.
MidAmerican Energy Operating Projects and Construction and Development Costs
- ----------------------------------------------------------------------------
MidAmerican Energy's primary need for capital is utility construction
expenditures. For the year ended December 31, 2002, utility construction
expenditures totaled $357 million, including allowance for funds used during
construction, or capitalized financing costs, and Quad Cities Station nuclear
fuel purchases.
Forecasted utility construction expenditures, including allowance for funds used
during construction, are $368 million for 2003. Capital expenditure needs are
reviewed regularly by management and may change significantly as a result of
such reviews.
Through 2010, MidAmerican Energy plans to develop and construct three electric
generating projects in Iowa. The projects would provide service to regulated
retail electricity customers and, subject to regulatory approvals, be included
in regulated rate base in Iowa, Illinois and South Dakota. Wholesale sales may
also be made from the plants to the extent the power is not needed for regulated
retail service. MidAmerican Energy expects to invest approximately $1.6 billion
in the three projects, including the cost of related transmission facilities and
allowance for funds used during construction. The three projects may provide
approximately 1,285 MW of generating capacity for MidAmerican Energy depending
on management's on-going assessment of energy needs and related factors.
The first project is a 500-MW (based on expected accreditation) natural
gas-fired combined cycle unit with an estimated cost of $415 million.
MidAmerican Energy will own 100% of the plant and operate it. MidAmerican Energy
has received a certificate from the IUB allowing it to construct the plant.
Also, on May 29, 2002, the IUB issued an order that provides the
-45-
ratemaking principles for the gas-fired plant. As a result of that order,
MidAmerican Energy is proceeding with the construction of the plant. The plant
will be operated in simple cycle mode during 2003 and 2004, resulting in 310 MW
of accredited capacity. The combined cycle operation is expected to commence in
2005.
The second project is currently under development and is expected to be a 790-MW
(based on expected accreditation) super-critical-temperature, coal-fired plant
fueled with low-sulfur coal. If constructed, MidAmerican Energy will operate the
plant and expects to own approximately 475 MW of the plant. Municipal,
cooperative and public power utilities will own the remainder, which is a
typical ownership arrangement for large base-load plants in Iowa. On January 23,
2003, MidAmerican Energy received an order approving the issuance of a
certificate from the IUB allowing it to construct the plant. MidAmerican Energy
has made a filing with the IUB for approval of ratemaking principles pertaining
to this second plant. Continued development of this plant is subject to
obtaining environmental and other required permits, as well as receiving orders
from the IUB approving construction of the associated transmission facilities
and establishing ratemaking principles which are satisfactory to MidAmerican
Energy.
The third project is currently under development and is expected to be wind
power facilities totaling 310 MW (nameplate rating). If constructed, MidAmerican
Energy will own and operate these facilities, which are expected to cost
approximately $323 million, plus associated transmission facilities. MidAmerican
Energy's plan to construct the wind project is in conjunction with a settlement
proposal to extend through December 31, 2010, a rate freeze that is currently
scheduled to expire at the end of 2005. The proposed settlement requires
enactment of Iowa legislation and is subject to approval by the IUB.
Development Activity
- --------------------
Fox is exploring the development of a 635 net MW gas fired power generating
facility in Kaukanna, Outagamie County, Wisconsin. A subsidiary of TransAlta has
agreed to participate in the development of this project at a level of 50% and
has an option to own 50% of the project. Obsidian is developing a 185 net MW
geothermal facility in Imperial Valley, California, known as Salton Sea VI.
TransAlta has elected to participate in the ownership and development of this
project at a level of 50%.
Development can require the Company to expend significant sums for preliminary
engineering, permitting, fuel supply, resource exploration, legal and other
expenses in preparation for competitive bids which the Company may not win or
before it can be determined whether a project is feasible, economically
attractive or capable of being financed. Successful development and construction
is contingent upon, among other things, negotiation on terms satisfactory to the
Company of engineering, construction, fuel supply, sales contracts and, if the
Company intends to own less than 100% of the project, joint venture or similar
agreements, with other project participants, receipt of required governmental
permits and consents and timely implementation of construction. There can be no
assurance that development efforts on any particular project or the Company's
development efforts generally, will be successful.
Debt Issuances and Redemptions
- ------------------------------
On February 8, 2002, MidAmerican Energy issued $400.0 million of 6.75%
medium-term notes due in 2031. The proceeds were used to refinance existing debt
and preferred securities and for other corporate purposes. On March 11, 2002,
MidAmerican Energy redeemed all $100.0 million of its 7.98% MidAmerican
Energy-obligated preferred securities of a subsidiary trust at 100% of the
principal amount plus accrued interest.
On May 1, 2002, MidAmerican Energy reacquired all $26.7 million of its $7.80
series of preferred securities. Of this amount, $13.3 million of preferred
securities were redeemed at 100% of the principal amount plus accrued dividends,
and the remaining $13.4 million was redeemed at 103.9% of the principal amount
plus accrued dividends.
On June 21, 2002, Kern River closed on a bank loan facility providing for
aggregate loans of up to $875.0 million to be used for the construction of the
Kern River 2003 Expansion Project. The facility, which matures 15 years after
the 2003 Expansion Project commences operation, has a variable interest rate
which increases over the term of the facility from 1.375% to 4.5% over LIBOR.
Kern River had drawn $789.9 million on this facility as of December 31, 2002. In
connection with this facility, the Company guaranteed the completion of the 2003
Expansion Project as previously discussed.
On October 4, 2002, the Company issued $200.0 million of 4.625% Senior Notes due
in 2007 and $500.0 million of 5.875% Senior Notes due in 2012. The proceeds are
being used for general corporate purposes including reducing short-term
obligations, to make a $150.0 million equity contribution to Northern Natural
Gas, and to make funds available to Kern River for its 2003 Expansion Project.
-46-
On October 15, 2002, Northern Natural Gas issued $300.0 million of 5.375% Senior
Notes due in 2012. The proceeds, along with the $150.0 million equity
contribution from the Company, were used to refinance a $450.0 million
short-term debt obligation.
On March 1, 2001, MidAmerican Funding, LLC ("MidAmerican Funding"), a wholly
owned subsidiary of the Company and MidAmerican Energy's parent company, retired
$200.0 million of 5.85% senior secured notes due 2001. On March 19, 2001,
MidAmerican Funding issued $200.0 million of 6.75% senior secured notes due
March 1, 2011.
On January 14, 2003, MidAmerican Energy issued $275.0 million of 5.125%
medium-term notes due in 2013. The proceeds will be used to refinance existing
debt, support utility construction expenditures and other corporate purposes.
OBLIGATIONS AND COMMITMENTS
The Company has contractual obligations and commercial commitments that may
affect its financial condition. Contractual obligations to make future payments
arise from parent company and subsidiary long-term debt and notes payable,
preferred equity securities, operating leases and power and fuel purchase
contracts. Other obligations arise from unused lines of credit and letters of
credit. Material obligations as of December 31, 2002 are as follows (in
thousands):
PAYMENTS DUE BY PERIOD
-------------------------------------------------------
LESS THAN 2-3 4-5 AFTER 5
Contractual Cash Obligations: TOTAL 1 YEAR YEARS YEARS YEARS
--------- -------- -------- -------- --------
Parent company long-term debt (1) ................. $ 2,539.5 $215.0 $ 260.0 $ 550.0 $1,514.5
Subsidiary and project debt (1) ................... 7,332.3 255.2 847.2 587.2 5,642.7
Company-obligated mandatorily redeemable
Preferred securities of subsidiary trusts ....... 2,063.4 150.0 288.5 468.0 1,156.9
Mandatorily redeemable preferred securities
of subsidiaries ................................. 93.3 93.3 -- -- --
Coal, electricity and natural gas contract
commitments (2) ................................. 493.1 168.5 229.5 32.9 62.2
Operating leases (2) .............................. 293.2 60.8 85.4 60.3 86.7
--------- ------ -------- -------- --------
Total contractual cash obligations .............. $12,814.8 $942.8 $1,710.6 $1,698.4 $8,463.0
========= ====== ======== ======== ========
COMMITMENT EXPIRATION PER PERIOD
---------------------------------------------
LESS THAN 2-3 4-5 AFTER 5
Other Commercial Commitments: TOTAL 1 YEAR YEARS YEARS YEARS
--------- -------- -------- -------- --------
Unused parent company revolving lines of credit ... $ 352.3 $352.3 $ -- $ -- $ --
Parent company letters of credit .................. 47.7 -- 47.7 -- --
Unused subsidiaries lines of credit ............... 350.0 249.7 100.3 -- --
Parent company guarantee of subsidiary debt ....... 174.8 1.4 3.6 2.9 166.9
Subsidiary lines of credit from parent company .... 10.0 -- -- -- 10.0
--------- ------ -------- -------- --------
Total other commercial commitments ............. $ 934.8 $603.4 $ 151.6 $ 2.9 $ 176.9
========= ====== ======== ======== ========
(1) Excludes certain unamortized debt premiums and discounts
(2) The fuel and energy commitments and operating leases are not reflected
on the consolidated balance sheets
In addition to amounts in the table above, the unused portion of the Kern River
Construction Financing Facility is $85.1 million.
As of December 31, 2002, Northern Natural Gas had $52.0 million of obligations
to deliver 12.2 Bcf of natural gas in 2003. The obligations are revalued based
on market prices for natural gas, with changes in value included in the
statement of operations. In 2002, Northern Natural Gas entered into natural gas
commodity price swaps and index basis swaps to effectively fix the deferred
obligation balance. These swaps have a net receivable balance of $3.4 million at
December 31, 2002. The swaps are revalued based on market prices for natural
gas, with changes in value included in the statement of operations. Therefore,
any further changes in the market value of the deferred obligations are expected
to be offset by a corresponding change in the opposite direction in the market
value of the swaps. However, at December 31, 2002, Northern Natural Gas had a
$10.4 million receivable position with a third party energy marketer relating to
these swaps. Since the date of entering into these swaps, there have been public
announcements that this third party's financial condition has deteriorated as a
result of, among
-47-
other factors, reduced liquidity. This receivable would increase by
approximately $12.2 million if the price curve of natural gas were to increase
by $1/MMBtu from levels at December 31, 2002. The Company has not recorded an
allowance on this receivable as of December 31, 2002, and is monitoring the
situation.
OFF-BALANCE SHEET ARRANGEMENTS
The Company has certain investments that are accounted for under the equity
method in accordance with GAAP. Accordingly, an amount is recorded on the
Company's balance sheet as an equity investment and is increased or decreased
for the Company's pro-rata share of earnings or losses, respectively, less any
dividend distribution from such investments.
As of December 31, 2002, the Company's investments which are accounted for under
the equity method had an aggregate $1,023.6 million of debt and $43.7 million in
outstanding letters of credit. As of December 31, 2002, the Company's pro-rata
share of the debt was $507.6 million and was non-recourse to the Company, except
for $137.8 million of such debt which the Company has guaranteed on the Salton
Sea Funding Series F Bonds and which was included in the Company's consolidated
balance sheet at December 31, 2002. The Company's pro-rata share of the
outstanding letters of credit was $21.9 million as of December 31, 2002. The
Company is generally not required to support the debt service obligations of
these investments. However, default with respect to this non-recourse debt could
result in a loss of invested equity.
NEW ACCOUNTING PRONOUNCEMENTS
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" ("SFAS 143"). This statement provides accounting and disclosure
requirements for retirement obligations associated with long-lived assets and is
effective January 1, 2003. This statement requires that the present value of
retirement costs for which the Company has a legal obligation be recorded as
liabilities with an equivalent amount added to the asset cost and depreciated
over an appropriate period. The liability is then accreted over time by applying
an interest method of allocation to the liability. Cumulative accretion and
accumulated depreciation will be recognized for the time period from the date
the liability would have been recognized had the provisions of this statement
been in effect, to the date of adoption of this statement. The cumulative effect
of initially applying this statement is recognized as a change in accounting
principle. The Company and its unconsolidated subsidiary used an expected cash
flow approach to measure the obligations and adopted the statement as of January
1, 2003.
The Company's initial review of its regulated entities identified legal
retirement obligations for nuclear decommissioning, wet and dry ash landfills
and offshore and minor lateral pipeline facilities. The Company expects to
record approximately $290.0 million of asset retirement obligation liabilities,
approximately $265.0 million of which pertains to obligations associated with
the decommissioning of the Quad Cities nuclear station. The adoption of this
statement is not expected to have a material impact on the operations of the
regulated entities, as the effects are expected to be offset by the
establishment of regulatory assets, totaling approximately $115.0 million,
pursuant to SFAS 71.
In addition, one of the Company's unconsolidated subsidiaries has identified
legal retirement obligations for landfill and plant abandonment costs. The
Company's share of this adoption is expected to total $1.1 million, net of tax.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 144 provides new guidance on
the recognition of impairment losses on long-lived assets to be held and used or
to be disposed of and also broadens the definition of what constitutes a
discontinued operation and how the results of a discontinued operation are to be
measured and presented. SFAS 144 supercedes SFAS No. 121 and APB Opinion No. 30,
while retaining many of the requirements of these two statements. Under SFAS
144, assets held for sale that are a component of an entity will be included in
discontinued operations if the operations and cash flows will be or have been
eliminated from the ongoing operations of the entity and the entity will not
have any significant continuing involvement in the operations prospectively.
SFAS 144 did not materially change the methods used by the Company to measure
impairment losses on long-lived assets but may result in more future
dispositions being reported as discontinued operations than would previously
have been permitted. The Company adopted SFAS 144 on January 1, 2002.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No.
4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections"
("SFAS 145"). SFAS 145 eliminates extraordinary accounting treatment for
reporting gains or losses on debt extinguishment, and amends other existing
authoritative pronouncements to make various technical corrections, clarify
meanings, or describe their applicability under changed conditions. The
provisions of SFAS 145 related to the rescission of FASB Statement No. 4 are
applicable in fiscal years beginning after
-48-
May 15, 2002, the provisions related to FASB Statement No. 13 are effective for
transactions occurring after May 15, 2002, and all other provisions are
effective for financial statements issued on or after May 15, 2002; however,
early application is encouraged. Debt extinguishments reported as extraordinary
items prior to scheduled or early adoption of SFAS 145 would be reclassified in
most cases following adoption. The Company does not expect the adoption of SFAS
145 to have a material effect on its financial position, results of operations,
or cash flows.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities" ("SFAS 146"). SFAS 146 nullifies EITF Issue
No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and
Other Costs to Exit an Activity (including Certain Costs Incurred in a
Restructuring)" ("EITF 94-3"). The principal difference between SFAS 146 and
EITF 94-3 relates to the requirements for recognition of a liability for costs
associated with an exit or disposal activity. SFAS 146 requires that a liability
be recognized for a cost associated with an exit or disposal activity when it is
incurred. A liability is incurred when a transaction or event occurs that leaves
an entity little or no discretion to avoid the future transfer or use of assets
to settle the liability. Under EITF 94-3, a liability for an exit cost was
recognized at the date of an entity's commitment to an exit plan. In addition,
SFAS 146 also requires that a liability for a cost associated with an exit or
disposal activity be recognized at its fair value when it is incurred. SFAS 146
is effective for exit or disposal activities that are initiated after December
31, 2002 with early application encouraged. The Company will apply the
provisions of SFAS 146 to all exit or disposal activities initiated after
December 31, 2002.
In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" ("FIN 45"). FIN 45 requires that a
liability be recorded in the guarantor's balance sheet upon issuance of certain
guarantees. In addition, FIN 45 requires disclosures about the guarantees that
an entity has issued. The provision for initial recognition and measurement of
the liability will be applied on a prospective basis to guarantees issued or
modified after December 31, 2002. The disclosure provisions of FIN 45 are
effective for financial statements of interim or annual periods ending after
December 15, 2002. The Company does not expect the adoption of FIN 45 to have a
material effect on its financial position, results of operations, or cash flows.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Company is exposed to market risk, including changes in the market price of
certain commodities and interest rates. To manage the price volatility relating
to these exposures, the Company enters into various financial derivative
instruments. Senior management provides the overall direction, structure,
conduct and control of the Company's risk management activities, including the
use of financial derivative instruments, authorization and communication of risk
management policies and procedures, strategic hedging program guidelines,
appropriate market and credit risk limits, and appropriate systems for
recording, monitoring and reporting the results of transactional and risk
management activities.
At December 31, 2002, the Company had fixed-rate long-term debt,
Company-obligated mandatorily redeemable preferred securities of subsidiary
trusts, and subsidiary-obligated mandatorily redeemable preferred securities of
subsidiary trusts of $11,683.2 million in principal amount and having a fair
value of $12,188.8 million. These instruments are fixed-rate and therefore do
not expose the Company to the risk of earnings loss due to changes in market
interest rates. However, the fair value of these instruments would decrease by
approximately $397.1 million if interest rates were to increase by 10% from
their levels at December 31, 2002. In general, such a decrease in fair value
would impact earnings and cash flows only if the Company were to reacquire all
or a portion of these instruments prior to their maturity.
At December 31, 2002, the Company had floating-rate obligations of $425.1
million that expose the Company to the risk of increased interest expense in the
event of increases in short-term interest rates. These obligations are not
hedged. If the floating rates were to increase by 1% the Company's consolidated
interest expense for unhedged floating-rate obligations would increase by
approximately $0.4 million each month in which such increase continued based
upon December 31, 2002 principal balances.
-49-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Independent Auditors' Report.........................................51
Consolidated Balance Sheets as of December 31, 2002 and 2001.........52
Consolidated Statements of Operations
for the Years Ended December 31, 2002 and 2001 and for the
periods from March 14, 2000 through December 31, 2000 and
January 1, 2000 through March13, 2000..............................53
Consolidated Statements of Stockholders' Equity
for the Three Years Ended December 31, 2002, 2001 and 2000.........54
Consolidated Statements of Cash Flows
for the Years Ended December 31, 2002 and 2001 and for the
periods from March 14, 2000 through December 31, 2000 and
January 1, 2000 through March13, 2000..............................55
Notes to Consolidated Financial Statements...........................56
-50-
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholders
MidAmerican Energy Holdings Company
Des Moines, Iowa
We have audited the accompanying consolidated balance sheets of MidAmerican
Energy Holdings Company (successor to MidAmerican Energy Holdings Company
(Predecessor), referred to as "MEHC (Predecessor)") and subsidiaries (the
"Company") as of December 31, 2002 and 2001 for the Company, and the related
consolidated statements of operations, stockholders' equity, and cash flows for
the years ended December 31, 2002 and 2001 for the Company, for the period
January 1, 2000 to March 13, 2000 for MEHC (Predecessor), and for the period
March 14, 2000 to December 31, 2000 for the Company. 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 these
financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes 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, 2002 and 2001, and the results of their
operations and their cash flows for the above stated periods 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, in 2002 the
Company changed its accounting policy for goodwill and other intangible assets
and in 2001 the Company changed is accounting policy for major maintenance,
overhaul and well workover costs.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Des Moines, Iowa
January 24, 2003
-51-
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands)
AS OF DECEMBER 31,
----------------------------
2002 2001
------------ ------------
ASSETS
Current assets:
Cash and cash equivalents ......................................................... $ 844,430 $ 386,745
Restricted cash and short-term investments ........................................ 50,808 30,565
Accounts receivable, net of allowance for doubtful accounts of $39,742 and $7,319 . 707,731 310,030
Inventories ....................................................................... 126,938 135,822
Other current assets .............................................................. 212,888 106,124
------------ ------------
Total current assets ................................................................ 1,942,795 969,286
------------ ------------
Properties, plants and equipment, net ............................................... 9,810,087 6,537,371
Excess of cost over fair value of net assets acquired ............................... 4,258,132 3,638,546
Regulatory assets ................................................................... 504,513 221,120
Other investments ................................................................... 446,732 174,185
Equity investments .................................................................. 273,707 261,432
Deferred charges and other assets ................................................... 780,489 824,712
------------ ------------
TOTAL ASSETS ........................................................................ $ 18,016,455 $ 12,626,652
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable .................................................................. $ 462,960 $ 266,027
Accrued interest .................................................................. 192,015 130,569
Accrued taxes ..................................................................... 75,097 88,973
Other accrued liabilities ......................................................... 457,058 308,924
Short-term debt ................................................................... 79,782 256,012
Current portion of long-term debt ................................................. 470,213 317,180
------------ ------------
Total current liabilities ....................................................... 1,737,125 1,367,685
------------ ------------
Other long-term accrued liabilities ................................................. 1,100,917 537,495
Parent company debt ................................................................. 2,324,456 1,834,498
Subsidiary and project debt ......................................................... 7,077,087 4,754,811
Deferred income taxes ............................................................... 1,238,421 1,284,268
------------ ------------
Total liabilities ................................................................. 13,478,006 9,778,757
------------ ------------
Deferred income ..................................................................... 80,078 85,917
Minority interest ................................................................... 7,351 44,477
Company-obligated mandatorily redeemable preferred securities of subsidiary trusts .. 2,063,412 788,151
Subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts -- 100,000
Preferred securities of subsidiaries ................................................ 93,325 121,183
Commitments and contingencies (Note 20)
Stockholders' equity:
Zero coupon convertible preferred stock - authorized 50,000 shares, no par value,
41,263 and 34,563 shares outstanding at December 31, 2002 and 2001, respectively .. -- --
Common stock - authorized 60,000 no par value; 9,281 shares issued
and outstanding at December 31, 2002 and 2001 ..................................... -- --
Additional paid-in capital .......................................................... 1,956,509 1,553,073
Retained earnings ................................................................... 584,009 223,926
Accumulated other comprehensive loss, net ........................................... (246,235) (68,832)
------------ ------------
Total stockholders' equity ........................................................ 2,294,283 1,708,167
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY .......................................... $ 18,016,455 $ 12,626,652
============ ============
The accompanying notes are an integral part of these financial statements.
-52
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands)
MEHC
(PREDECESSOR)
YEAR ENDED DECEMBER 31, MARCH 14, 2000 JANUARY 1, 2000
---------------------------- THROUGH THROUGH
2002 2001 DECEMBER 31, 2000 MARCH 13, 2000
----------- ----------- ----------------- --------------
REVENUE:
Operating revenue ....................... $ 4,794,010 $ 4,696,781 $ 3,918,100 $ 1,056,365
Income on equity investments ............ 40,520 39,565 40,019 3,497
Interest and dividend income ............ 56,250 24,552 25,320 8,080
Other income ............................ 77,359 212,082 29,543 7,907
----------- ----------- ----------- -----------
Total revenue ......................... 4,968,139 4,972,980 4,012,982 1,075,849
----------- ----------- ----------- -----------
COSTS AND EXPENSES:
Cost of sales ........................... 1,844,024 2,341,178 2,194,512 574,679
Operating expense ....................... 1,345,205 1,176,422 904,511 226,908
Depreciation and amortization ........... 525,902 538,702 383,351 97,278
Interest expense ........................ 647,379 499,263 396,773 101,330
Less interest capitalized ............... (37,469) (86,469) (85,369) (15,516)
----------- ----------- ----------- -----------
Total costs and expenses .............. 4,325,041 4,469,096 3,793,778 984,679
----------- ----------- ----------- -----------
INCOME BEFORE PROVISION FOR INCOME TAXES .. 643,098 503,884 219,204 91,170
Provision for income taxes .............. 99,588 250,064 53,277 31,008
----------- ----------- ----------- -----------
INCOME BEFORE MINORITY INTEREST AND
PREFERRED DIVIDENDS ..................... 543,510 253,820 165,927 60,162
Minority interest and preferred dividends 163,467 106,547 84,670 8,850
----------- ----------- ----------- -----------
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE .......... 380,043 147,273 81,257 51,312
Cumulative effect of change in accounting
principle, net of tax (Note 2) .......... -- (4,604) -- --
----------- ----------- ----------- -----------
NET INCOME AVAILABLE TO COMMON
AND PREFERRED STOCKHOLDERS .............. $ 380,043 $ 142,669 $ 81,257 $ 51,312
=========== =========== =========== ===========
The accompanying notes are an integral part of these financial statements.
-53-
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Amounts in thousands)
ACCUMULATED
OUTSTANDING ADDITIONAL OTHER
COMMON COMMON PAID-IN RETAINED COMPREHENSIVE TREASURY
SHARES STOCK CAPITAL EARNINGS INCOME(LOSS) STOCK TOTAL
----------- ------ ------------ --------- ------------ -------- -----------
Balance, January 1, 2000 ............. 59,944 $ -- $ 1,249,079 $ 507,726 $ (12,029) $(750,188) $ 994,588
Net income January 1, 2000
through March 13, 2000 ............. -- -- -- 51,312 -- -- 51,312
Net income March 14, 2000
through December 31, 2000 .......... -- -- -- 81,257 -- -- 81,257
Other comprehensive income:
Foreign currency translation
adjustment ...................... -- -- -- -- (82,996) -- (82,996)
Minimum pension liability adjustment,
net of tax of $1,699 ............... -- -- -- -- (2,388) -- (2,388)
Unrealized gains on securities,
net of tax of $1,164................ -- -- -- -- 2,160 -- 2,160
-----------
Total other comprehensive income ..... 49,345
Exercise of stock options and
other equity transactions .......... 13 -- (138) -- -- 418 280
Teton Transaction .................... (50,676) -- 304,132 (559,038) 37,324 749,770 532,188
- -----------------------------------------------------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 2000 ........... 9,281 -- 1,553,073 81,257 (57,929) -- 1,576,401
Net income ........................... -- -- -- 142,669 -- -- 142,669
Other comprehensive income:
Foreign currency translation
adjustment ....................... -- -- -- -- (22,103) -- (22,103)
Fair value adjustment on cash
flow hedges, net of tax of $8,143 .. -- -- -- -- 18,490 -- 18,490
Minimum pension liability adjustment,
net of tax of $3,448 ............... -- -- -- -- (4,847) -- (4,847)
Unrealized losses on securities,
net of tax of $1,315 ............... -- -- -- -- (2,443) -- (2,443)
-----------
Total other comprehensive income ..... 131,766
- -----------------------------------------------------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 2001 ........... 9,281 -- 1,553,073 223,926 (68,832) -- 1,708,167
Net income ........................... -- -- -- 380,043 -- -- 380,043
Other comprehensive income:
Foreign currency translation
adjustment ....................... -- -- -- -- 166,880 -- 166,880
Fair value adjustment on cash
flow hedges, net of tax of $10,106 . -- -- -- -- (27,623) -- (27,623)
Minimum pension liability adjustment,
net of tax of $135,707 ............. -- -- -- -- (313,456) -- (313,456)
Unrealized losses on securities,
net of tax of $1,813 ............... -- -- -- -- (3,204) -- (3,204)
-----------
Total other comprehensive income ..... 202,640
Issuance of zero-coupon convertible
preferred stock .................... -- -- 402,000 -- -- -- 402,000
Retirement of stock options .......... -- -- 815 (19,960) -- -- (19,145)
Other equity transactions ............ -- -- 621 -- -- -- 621
- -----------------------------------------------------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 2002 ........... 9,281 $ -- $ 1,956,509 $ 584,009 $(246,235) $ -- $ 2,294,283
===================================================================================================================================
The accompanying notes are an integral part of these financial statements
-54-
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
MEHC
(PREDECESSOR)
YEAR ENDED DECEMBER 31, MARCH 14, 2000 JANUARY 1, 2002
------------------------- THROUGH THROUGH
2002 2001 DECEMBER 31, 2000 MARCH 13, 2000
----------- --------- ----------------- --------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .............................................. $ 380,043 $ 142,669 $ 81,257 $ 51,312
Adjustments to reconcile net cash flows from
operating activities:
Income in excess of distributions on equity investments (11,383) (28,515) (26,607) (3,459)
Gains on non-recurring items .......................... (25,329) (179,493) -- --
Depreciation and amortization ......................... 525,902 442,284 303,354 83,097
Amortization of excess of cost over fair value of net
assets acquired .................................... -- 96,418 79,997 14,181
Amortization of deferred financing and other costs .... 46,132 20,529 18,310 4,075
Provision for deferred income taxes ................... (16,228) 152,920 (15,460) 7,735
Cumulative effect of change in accounting principle,
net of tax .......................................... -- 4,604 -- --
Changes in other items:
Accounts receivable, net ............................ (244,829) 639,868 (333,277) (11,769)
Other current assets ................................ 42,552 (20,041) 16,990 12,209
Accounts payable and other accrued liabilities ...... 36,083 (424,374) 124,030 (21,242)
Accrued interest .................................... 68,924 (1,683) (19,892) 35,701
Accrued taxes ....................................... (39,302) (4,616) 7,238 (4,270)
Deferred income ..................................... (4,839) 6,428 10,467 3,513
----------- --------- ----------- ---------
Net cash flows from operating activities ............ 757,726 846,998 246,407 171,083
----------- --------- ----------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions, net of cash acquired .................... (1,416,937) (81,934) (2,048,266) --
Purchase of convertible preferred securities .......... (275,000) -- -- --
Capital expenditures relating to operating projects ... (542,615) (398,165) (301,948) (44,355)
Construction and other development costs .............. (965,470) (178,587) (236,781) (79,186)
Proceeds from sale of assets .......................... 214,070 377,396 -- --
Decrease in restricted cash and investments ........... 16,351 24,540 157,905 48,788
Other ................................................. 61,790 18,206 39,930 19,879
----------- --------- ----------- ---------
Net cash flows from investing activities ........... (2,907,811) (238,544) (2,389,160) (54,874)
----------- --------- ----------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from subsidiary and project debt ............. 1,485,349 200,000 262,176 6,043
Proceeds from parent company debt ..................... 700,000 -- -- --
Repayments of subsidiary and project debt ............. (395,370) (437,372) (234,776) (3,135)
Net proceeds from (repayment of) corporate revolver ... (153,500) 68,500 85,000 --
Repayment of other obligations ........................ (94,297) -- (4,225) --
Net repayment of subsidiary short-term debt ........... (472,835) (74,144) (88,106) (124,761)
Proceeds from issuance of trust preferred securities .. 1,273,000 -- 454,772 --
Proceeds from issuance of common and preferred stock .. 402,000 -- 1,428,024 --
Redemption of preferred securities of subsidiaries .... (127,908) (24,910) (20,409) --
Other ................................................. (61,205) 9,459 (3,607) (6,648)
----------- --------- ----------- ---------
Net cash flows from financing activities ............ 2,555,234 (258,467) 1,878,849 (128,501)
----------- --------- ----------- ---------
Effect of exchange rate changes ....................... 52,536 (1,394) (1,555) (424)
----------- --------- ----------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS .... 457,685 348,593 (265,459) (12,716)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ........ 386,745 38,152 303,611 316,327
----------- --------- ----------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD .............. $ 844,430 $ 386,745 $ 38,152 $ 303,611
=========== ========= =========== =========
SUPPLEMENTAL DISCLOSURE:
Interest paid, net of interest capitalized .............. $ 588,972 $ 389,953 $ 351,532 $ 35,057
=========== ========= =========== =========
Income taxes paid ....................................... $ 101,225 $ 133,139 $ 94,405 $ --
=========== ========= =========== =========
The accompanying notes are an integral part of these financial statements.
-55-
MIDAMERICAN ENERGY HOLDINGS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND OPERATIONS
MidAmerican Energy Holdings Company and its subsidiaries (the "Company" or
"MEHC") is a United States-based privately owned global energy company. The
Company's subsidiaries' principal businesses are regulated electric and natural
gas utilities, regulated interstate natural gas transmission and electric power
generation. Its operations are organized and managed on seven distinct
platforms: MidAmerican Energy Company ("MidAmerican Energy"), Kern River Gas
Transmission Company ("Kern River"), Northern Natural Gas Company ("Northern
Natural Gas"), CE Electric UK Funding ("CE Electric UK") (which includes
Northern Electric plc ("Northern Electric") and Yorkshire Power Group Ltd.
("Yorkshire")), CalEnergy Generation - Domestic, CalEnergy Generation-Foreign
(the Upper Mahiao, Malitbog and Mahanagdong Projects (collectively the "Leyte
Projects") and the Casecnan Project) and HomeServices of America, Inc.
("HomeServices"). Through six of these platforms, the Company owns and operates
a combined electric and natural gas utility company in the United States, two
natural gas pipeline companies in the United States, two electricity
distribution companies in the United Kingdom, and a diversified portfolio of
domestic and international independent power projects. The Company also owns the
second largest residential real estate brokerage firm in the United States.
On March 14, 2000, the Company and an investor group comprised of Berkshire
Hathaway Inc., Walter Scott, Jr., a director of the Company, David L. Sokol,
Chairman and Chief Executive Officer of the Company, and Gregory E. Abel,
President and Chief Operating Officer of the Company, closed on a definitive
agreement and plan of merger whereby the investor group acquired all of the
outstanding common stock of the Company (the "Teton Transaction"). As a result
of the Teton Transaction, Berkshire Hathaway, Mr. Scott, Mr. Sokol and Mr. Abel
own approximately 9.7%, 86%, 3% and 1% of the voting stock respectively.
The Company initially incorporated in 1971 under the laws of the State of
Delaware and was reincorporated in 1999 in Iowa, at which time it changed its
name from CalEnergy Company, Inc. to MidAmerican Energy Holdings Company.
In these notes to consolidated financial statements, references to "U.S.
dollars," "dollars," "US $," "$" or "cents" are to the currency of the United
States and references to "pounds sterling," "pounds," "sterling," "pence" or "p"
are to the currency of the United Kingdom. References to MW means megawatts, MWh
means megawatt hours, Bcf means billion cubic feet, mmcf means million cubic
feet, GWh means gigawatts per hour, kV means 1000 volts, Tcf means trillion
cubic feet, kWh means kilowatt hours and MMBtus means million British thermal
units.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
- ---------------------------
The consolidated financial statements include the accounts of the Company and
its wholly-owned subsidiaries. Subsidiaries which are less than 100% owned but
greater than 50% owned are consolidated with a minority interest. Subsidiaries
that are 50% owned or less, but where the Company has the ability to exercise
significant influence, are accounted for under the equity method of accounting.
Investments where the Company's ability to influence is limited are accounted
for under the cost method of accounting. All significant inter-enterprise
transactions and accounts have been eliminated. The results of operations of the
Company include the Company's proportionate share of results of operations of
entities acquired from the date of each acquisition for purchase business
combinations.
For the Company's foreign operations whose functional currency is not the U.S.
dollar, the assets and liabilities are translated into U.S. dollars at current
exchange rates. Resulting translation adjustments are reflected as accumulated
other comprehensive income (loss) in stockholders' equity. Revenue and expenses
are translated at average exchange rates for the period. Transaction gains and
losses that arise from exchange rate fluctuations on transactions denominated in
a currency other than the functional currency, except those transactions which
operate as a hedge of an identifiable foreign currency commitment or as a hedge
of a foreign currency investment position, are included in the results of
operations as incurred.
-56-
Reclassifications
- -----------------
Certain amounts in the fiscal 2001 and 2000 consolidated financial statements
and supporting note disclosures have been reclassified to conform to the fiscal
2002 presentation. Such reclassification did not impact previously reported net
income or retained earnings.
Use of Estimates
- ----------------
The preparation of consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the consolidated financial statements and the
reported amounts of revenue and expenses during the reporting period. Actual
results could differ from those estimates.
Accounting for the Effects of Certain Types of Regulation
- ---------------------------------------------------------
MidAmerican Energy, Kern River and Northern Natural Gas prepare their financial
statements in accordance with the provisions of Statement of Financial
Accounting Standards ("SFAS") No. 71 ("SFAS 71"), which differs in certain
respects from the application of generally accepted accounting principles by
non-regulated businesses. In general, SFAS 71 recognizes that accounting for
rate-regulated enterprises should reflect the economic effects of regulation. As
a result, a regulated utility is required to defer the recognition of costs (a
regulatory asset) or the recognition of obligations (a regulatory liability) if
it is probable that, through the rate-making process, there will be a
corresponding increase or decrease in future rates. Accordingly, MidAmerican
Energy, Kern River and Northern Natural Gas have deferred certain costs, which
will be amortized over various future periods. To the extent that collection of
such costs or payment of such obligations is no longer probable as a result of
changes in regulation, the associated regulatory asset or liability is charged
or credited to income.
A possible consequence of deregulation of the regulated energy industry is that
SFAS 71 may no longer apply. If portions of the Company's subsidiaries'
regulated energy operations no longer meet the criteria of SFAS 71, the Company
could be required to write off the related regulatory assets and liabilities
from its balance sheet, and thus a material adjustment to earnings in that
period could result if regulatory assets or liabilities are not recovered in
transition provisions of any deregulation legislation.
The Company continues to evaluate the applicability of SFAS 71 to its regulated
energy operations and the recoverability of these assets and liabilities through
rates as there are on-going changes in the regulatory and economic environment.
Cash and Cash Equivalents
- --------------------------
The Company considers all investment instruments purchased with an original
maturity of three months or less to be cash equivalents. Investments other than
restricted cash are primarily commercial paper and money market securities.
Restricted cash is not considered a cash equivalent.
Restricted Cash and Investments
- -------------------------------
The current restricted cash and short-term investments balance includes
commercial paper and money market securities, and is mainly composed of amounts
deposited in restricted accounts from which the Company will source its debt
service reserve requirements relating to the projects. These funds are
restricted by their respective project debt agreements to be used only for the
related project.
The Company's nuclear decommissioning trust funds and other marketable
securities are classified as available for sale and are accounted for at fair
value.
-57-
Allowance for Doubtful Accounts
- -------------------------------
The allowance for doubtful accounts is based on the Company's assessment of the
collectibility of payments from its customers. This assessment requires judgment
regarding the outcome of pending disputes, arbitrations and the ability of
customers to pay the amounts owed to the Company. Any change in the Company's
assessment of the collectibility of accounts receivable that was not previously
provided is recorded in the current period.
Fair Value of Financial Instruments
- -----------------------------------
The fair value of a financial instrument is the amount at which the instrument
could be exchanged in a current transaction between willing parties, other than
in a forced sale or liquidation. Although management uses its best judgment in
estimating the fair value of these financial instruments, there are inherent
limitations in any estimation technique. Therefore, the fair value estimates
presented herein are not necessarily indicative of the amounts that the Company
could realize in a current transaction.
The methods and assumptions used to estimate fair value are as follows:
Short-term debt - Due to the short-term nature of the short-term debt, the fair
value approximates the carrying value.
Debt instruments - The fair value of all debt issues listed on exchanges has
been estimated based on the quoted market prices. The Company is unable to
estimate a fair value for the Philippine term loans as there are no quoted
market prices available.
Other financial instruments - All other financial instruments of a material
nature are short-term and the fair value approximates the carrying amount.
Properties, Plants and Equipment, Net
- -------------------------------------
Properties, plants and equipment are recorded at historical cost. The cost of
major additions and betterments are capitalized, while replacements,
maintenance, and repairs that do not improve or extend the lives of the
respective assets are expensed.
Capitalized costs for gas reserves, other than costs of unevaluated exploration
projects and projects awaiting development consent, are depleted using the units
of production method. Depletion is calculated based on hydrocarbon reserves of
properties in the evaluated pool estimated to be commercially recoverable and
include anticipated future development costs in respect of those reserves.
Impairment of Long-Lived Assets
- -------------------------------
The Company's long-lived assets consist primarily of properties, plants and
equipment. Depreciation is computed using the straight-line method based on
economic lives or regulatory mandated recovery periods. The Company believes the
useful lives assigned to the depreciable assets, which generally range from 3 to
87 years, are reasonable.
The Company periodically evaluates long-lived assets, including properties,
plants and equipment, when events or changes in circumstances indicate that the
carrying value of these assets may not be recoverable. Upon the occurrence of a
triggering event, the carrying amount of a long-lived asset is reviewed to
assess whether the recoverable amount has declined below its carrying amount.
The recoverable amount is the estimated net future cash flows that the Company
expects to recover from the future use of the asset, undiscounted and without
interest, plus the asset's residual value on disposal. Where the recoverable
amount of the long-lived asset is less than the carrying value, an impairment
loss would be recognized to write down the asset to its fair value that is based
on discounted estimated cash flows from the future use of the asset.
The estimate of cash flows arising from future use of the asset that are used in
the impairment analysis requires judgment regarding what the Company would
expect to recover from future use of the asset. Any changes in the estimates of
cash flows arising from future use of the asset or the residual value of the
asset on disposal based on changes in the market conditions, changes in the use
of the asset, management's plans, the determination of the useful life of the
asset and technology changes in the industry could significantly change the
calculation of the fair value or recoverable amount of the asset and the
resulting impairment loss, which could significantly affect the results of
operations. The determination of whether impairment has occurred is based on an
estimate of undiscounted cash flows attributable to the assets, as
-58-
compared to the carrying value of the assets. An impairment analysis of
generating facilities requires estimates of possible future market prices, load
growth, competition and many other factors over the lives of the facilities. A
resulting impairment loss is highly dependent on these underlying assumptions.
Excess of Cost over Fair Value of Net Assets Acquired
- -----------------------------------------------------
On January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other
Intangible Assets" ("SFAS 142"), which establishes the accounting for acquired
goodwill and other intangible assets, and provides that goodwill and
indefinite-lived intangible assets will not be amortized, but will be tested for
impairment on an annual basis. The Company's related amortization consisted
primarily of goodwill amortization. Following is a reconciliation of net income
available to common and preferred stockholders as originally reported for the
years ended December 31, 2002 and 2001 and for the periods from March 14, 2000
through December 31, 2000 and January 1, 2000 through March13, 2000, to adjusted
net income available to common and preferred stockholders (in thousands):
MEHC (PREDECESSOR)
YEAR ENDED DECEMBER 31, MARCH 14, 2000 JANUARY 1, 2002
----------------------- THROUGH THROUGH
2002 2001 DECEMBER 31, 2000 MARCH 13, 2000
-------- --------- ----------------- -----------------
Reported net income available to common
and preferred stockholders ........................ $380,043 $ 142,669 $ 81,257 $ 51,312
Amortization of excess of cost over fair value of net
assets acquired ................................... -- 96,418 79,997 14,181
Tax effect of amortization .......................... -- (2,018) (1,413) (372)
-------- --------- --------- --------
Adjusted net income available to common
and preferred stockholders .......................... $380,043 $ 237,069 $ 159,841 $ 65,121
======== ========= ========= ========
The Company completed its initial review pursuant to SFAS No. 142 for its
reporting units during the second quarter of 2002 and its annual review during
the fourth quarter of 2002. No impairment was indicated as a result of these
assessments.
Capitalization of Interest and Allowance for Funds Used During Construction
- ---------------------------------------------------------------------------
Allowance for funds used during construction ("AFUDC") represents the
approximate net composite interest cost of borrowed funds and a reasonable
return on the equity funds used for construction. Although AFUDC increases both
utility plant and earnings, it is realized in cash through depreciation
provisions included in rates for subsidiaries that apply SFAS 71. Interest and
AFUDC for subsidiaries that apply SFAS 71 are capitalized as a component of
projects under construction and will be amortized over the assets' estimated
useful lives.
Deferred Financing Costs
- ------------------------
The Company capitalizes costs associated with financings, as deferred financing
costs, and amortizes the amounts over the term of the related financing using
the effective interest method.
Contingent Liabilities
- ----------------------
The Company establishes reserves for estimated loss contingencies when it is
management's assessment that a loss is probable and the amount of the loss can
be reasonably estimated. Revisions to contingent liabilities are reflected in
operations in the period in which different facts or information become known or
circumstances change that affect the previous assumptions with respect to the
likelihood or amount of loss. Reserves for contingent liabilities are based upon
management's assumptions and estimates, and advice of legal counsel or other
third parties regarding the probable outcomes of any matters. Should the
outcomes differ from the assumptions and estimates, revisions to the estimated
reserves for contingent liabilities would be required.
-59-
Deferred Income Taxes
- ---------------------
The Company recognizes deferred tax assets and liabilities based on the
difference between the financial statement and tax basis of assets and
liabilities using estimated tax rates in effect for the year in which the
differences are expected to reverse. The Company does not intend to repatriate
earnings of foreign subsidiaries in the foreseeable future. As a result,
deferred United States income taxes are not provided for retained earnings of
international subsidiaries and corporate joint ventures unless the earnings are
intended to be remitted.
Revenue Recognition
- -------------------
Revenue is recorded based upon services rendered and electricity, gas and steam
delivered, distributed or supplied to the end of the period. The Company records
unbilled revenue representing the estimated amounts customers will be billed for
services rendered between the meter reading dates in a particular month and the
end of that month. The unbilled revenue estimate is reversed in the following
month. To the extent the estimated amount differs from the actual amount
subsequently billed, revenue will be affected.
Where there is an over recovery of United Kingdom distribution business revenue
against the maximum regulated amount, revenue is deferred in an amount
equivalent to the over recovered amount. The deferred amount is deducted from
revenue and included in other liabilities. Where there is an under recovery, no
anticipation of any potential future recovery is made.
Revenue from the transportation and storage of gas are recognized based on
contractual terms and the related volumes. Kern River and Northern Natural Gas
are subject to the FERC's regulations and, accordingly, certain revenue
collected may be subject to possible refunds upon final orders in pending rate
cases. Kern River and Northern Natural Gas record rate refund liabilities
considering their regulatory proceedings and other third party regulatory
proceedings, advice of counsel and estimated total exposure, as discounted and
risk weighted, as well as collection and other risks.
Commission revenue from real estate brokerage transactions and related amounts
due to agents are recognized when title has transferred from seller to buyer.
Title fee revenue from real estate transactions and related amounts due to the
title insurer are recognized at the closing, which is when consideration is
received. Fees related to loan originations are recognized at the closing, which
is when services have been provided and consideration is received.
Financial Instruments
- ---------------------
The Company currently utilizes swap agreements and forward purchase agreements
to manage market risks and reduce its exposure resulting from fluctuation in
interest rates, foreign currency exchange rates and electric and gas prices. For
interest rate swap agreements, the net cash amounts paid or received on the
agreements are accrued and recognized as an adjustment to interest expense.
Gains and losses related to gas forward contracts are deferred and included in
the measurement of the related gas purchases. These instruments are either
exchange traded or with counterparties of high credit quality; therefore, the
risk of nonperformance by the counterparties is considered to be negligible.
Accounting Principle Change
- ---------------------------
Effective January 1, 2001, the Company has changed its accounting policy
regarding major maintenance and repairs for non-regulated gas projects,
non-regulated plant overhaul costs and geothermal well rework costs to the
direct expense method from the former policy of monthly accruals based on
long-term scheduled maintenance plans for the gas projects and deferral and
amortization of plant overhaul costs and geothermal well rework costs over the
estimated useful lives. The cumulative effect of the change in accounting
principle was $4.6 million, net of taxes of $0.7 million. If the Company had
adopted the policy as of January 1, 2000, income before extraordinary item and
cumulative effect of change in accounting principle would have been $6.3 million
lower in 2000 on a pro forma basis.
NEW ACCOUNTING PRONOUNCEMENTS
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" ("SFAS 143"). This statement provides accounting and disclosure
requirements for retirement obligations associated with long-lived assets and is
effective January 1, 2003. This statement requires that the present value of
retirement costs for which the Company has a legal obligation be recorded as
liabilities with an equivalent amount added to the asset cost and depreciated
over an appropriate period. The liability is then accreted over time by applying
an interest method of allocation to the liability. Cumulative accretion and
accumulated depreciation will be recognized for the time period from
-60-
the date the liability would have been recognized had the provisions of this
statement been in effect, to the date of adoption of this statement. The
cumulative effect of initially applying this statement is recognized as a change
in accounting principle. The Company and its unconsolidated subsidiary used an
expected cash flow approach to measure the obligations and adopted the statement
as of January 1, 2003.
The Company's initial review of its regulated entities identified legal
retirement obligations for nuclear decommissioning, wet and dry ash landfills
and offshore and minor lateral pipeline facilities. The Company expects to
record approximately $290.0 million of asset retirement obligation liabilities,
approximately $265.0 million of which pertains to obligations associated with
the decommissioning of the Quad Cities nuclear station. The adoption of this
statement is not expected to have a material impact on the operations of the
regulated entities, as the effects are expected to be offset by the
establishment of regulatory assets, totaling approximately $115.0 million,
pursuant to SFAS 71.
In addition, one of the Company's unconsolidated subsidiaries has identified
legal retirement obligations for landfill and plant abandonment costs. The
Company's share of this adoption is expected to total $1.1 million, net of tax.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 144 provides new guidance on
the recognition of impairment losses on long-lived assets to be held and used or
to be disposed of and also broadens the definition of what constitutes a
discontinued operation and how the results of a discontinued operation are to be
measured and presented. SFAS 144 supercedes SFAS No. 121 and APB Opinion No. 30,
while retaining many of the requirements of these two statements. Under SFAS
144, assets held for sale that are a component of an entity will be included in
discontinued operations if the operations and cash flows will be or have been
eliminated from the ongoing operations of the entity and the entity will not
have any significant continuing involvement in the operations prospectively.
SFAS 144 did not materially change the methods used by the Company to measure
impairment losses on long-lived assets but may result in more future
dispositions being reported as discontinued operations than would previously
have been permitted. The Company adopted SFAS 144 on January 1, 2002.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No.
4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections"
("SFAS 145"). SFAS 145 eliminates extraordinary accounting treatment for
reporting gains or losses on debt extinguishment, and amends other existing
authoritative pronouncements to make various technical corrections, clarify
meanings, or describe their applicability under changed conditions. The
provisions of SFAS 145 related to the rescission of FASB Statement No. 4 are
applicable in fiscal years beginning after May 15, 2002, the provisions related
to FASB Statement No. 13 are effective for transactions occurring after May 15,
2002, and all other provisions are effective for financial statements issued on
or after May 15, 2002; however, early application is encouraged. Debt
extinguishments reported as extraordinary items prior to scheduled or early
adoption of SFAS 145 would be reclassified in most cases following adoption. The
Company does not expect the adoption of SFAS 145 to have a material effect on
its financial position, results of operations, or cash flows.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities" ("SFAS 146"). SFAS 146 nullifies EITF Issue
No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and
Other Costs to Exit an Activity (including Certain Costs Incurred in a
Restructuring)" ("EITF 94-3"). The principal difference between SFAS 146 and
EITF 94-3 relates to the requirements for recognition of a liability for costs
associated with an exit or disposal activity. SFAS 146 requires that a liability
be recognized for a cost associated with an exit or disposal activity when it is
incurred. A liability is incurred when a transaction or event occurs that leaves
an entity little or no discretion to avoid the future transfer or use of assets
to settle the liability. Under EITF 94-3, a liability for an exit cost was
recognized at the date of an entity's commitment to an exit plan. In addition,
SFAS 146 also requires that a liability for a cost associated with an exit or
disposal activity be recognized at its fair value when it is incurred. SFAS 146
is effective for exit or disposal activities that are initiated after December
31, 2002 with early application encouraged. The Company will apply the
provisions of SFAS 146 to all exit or disposal activities initiated after
December 31, 2002.
In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" ("FIN 45"). FIN 45 requires that a
liability be recorded in the guarantor's balance sheet upon issuance of certain
guarantees. In addition, FIN 45 requires disclosures about the guarantees that
an entity has issued. The provision for initial recognition and measurement of
the liability will be applied on a prospective basis to guarantees issued or
modified after December 31, 2002. The disclosure provisions of FIN 45 are
effective for financial statements of interim or annual periods ending after
December 15, 2002. The Company does not expect the adoption of FIN 45 to have a
material effect on its financial position, results of operations, or cash flows.
-61-
3. ACQUISITIONS
Kern River
- ----------
On March 27, 2002, the Company acquired Kern River, a 926-mile interstate
pipeline transporting Rocky Mountain and Canadian natural gas to markets in
California, Nevada and Utah.
The Company paid $419.7 million, net of cash acquired of $7.7 million and a
working capital adjustment, for Kern River's gas pipeline business. The
acquisition has been accounted for as a purchase business combination. The
Company is in the process of completing the allocation of the purchase price to
the assets and liabilities acquired. The results of operations for Kern River
are included in the Company's results beginning March 27, 2002.
The recognition of excess of cost over fair value of net assets acquired
resulted from various attributes of Kern River's operations and business in
general. These attributes include, but are not limited to:
o Opportunities for expansion;
o High credit quality shippers contracting with Kern River; o Kern
River's strong competitive position; o Exceptional operating track
record and state-of-the-art technology; o Strong demand for gas in the
Western markets; and
o An ample supply of low-cost gas.
In connection with the acquisition of Kern River, the Company issued $323.0
million of 11% Company-obligated mandatorily redeemable preferred securities of
subsidiary trust due March 12, 2012 with scheduled principal payments beginning
in 2005 and $127.0 million of no par, zero coupon convertible preferred stock to
Berkshire Hathaway. Each share of preferred stock is convertible at the option
of the holder into one share of the Company's common stock subject to certain
adjustments as described in the Company's Amended and Restated Articles of
Incorporation.
The following table summarizes the estimated fair values of the assets acquired
and liabilities assumed at the date of acquisition (in millions):
Cash ................................................. $ 7.7
Properties, plants and equipment ..................... 797.2
Excess of cost over fair value of net assets acquired 32.5
Other assets ......................................... 173.2
--------
Total assets acquired .............................. 1,010.6
--------
Current liabilities .................................. (105.4)
Long-term debt ....................................... (482.0)
Other liabilities .................................... (0.9)
--------
Total liabilities assumed .......................... (588.3)
--------
Net assets acquired .................................. $ 422.3
========
Northern Natural Gas Company
- ----------------------------
On August 16, 2002, the Company acquired Northern Natural Gas from Dynegy Inc.
("Dynegy"). Northern Natural Gas is a 16,600-mile interstate pipeline extending
from southwest Texas to the upper Midwest region of the United States.
The Company paid $882.7 million for Northern Natural Gas, net of cash acquired
of $1.4 million and net of a working capital adjustment. The acquisition has
been accounted for as a purchase business combination. The Company is in the
process of completing the allocation of the purchase price to the assets and
liabilities acquired. The results of operations for Northern Natural Gas are
included in the Company's results beginning August 16, 2002.
-62-
The recognition of excess of cost over fair value of net assets acquired
resulted from various attributes of Northern Natural Gas' operations and
business in general. These attributes include, but are not limited to:
o High credit quality shippers contracting with Northern Natural Gas; o
Northern Natural Gas' strong competitive position;
o Strategic location in the high demand Upper Midwest markets;
o Flexible access to an ample supply of low-cost gas;
o Exceptional operating track record; and
o Opportunities for expansion.
In connection with the acquisition of Northern Natural Gas, the Company issued
$950.0 million of 11% Company-obligated mandatorily redeemable preferred
securities of subsidiary trust due August 31, 2011, with scheduled principal
payments beginning in 2003, to Berkshire Hathaway.
The following table summarizes the preliminary estimated fair values of the
assets acquired and liabilities assumed at the date of acquisition (in
millions):
Cash ................................................. $ 1.4
Properties, plants and equipment ..................... 1,346.7
Excess of cost over fair value of net assets acquired 414.7
Other assets ......................................... 309.9
--------
Total assets acquired .............................. 2,072.7
--------
Current portion of long-term debt .................... (450.0)
Other current liabilities ............................ (216.1)
Long-term debt ....................................... (499.8)
Other liabilities .................................... (27.7)
--------
Total liabilities assumed .......................... (1,193.6)
--------
Net assets acquired .................................. $ 879.1
========
The following pro forma financial information of the Company represents the
unaudited pro forma results of operations as if the Kern River and Northern
Natural Gas acquisitions, and the related financings, had occurred at the
beginning of each period. These pro forma results have been prepared for
comparative purposes only and do not profess to be indicative of the results of
operations which would have been achieved had these transactions been completed
at the beginning of each year, nor are the results indicative of the Company's
future results of operations (in millions).
YEAR ENDED
DECEMBER 31,
-------------------
2002 2001
-------- --------
Revenue ......................... $5,299.4 $5,688.5
Income before cumulative effect
of change in accounting principle 285.5 36.9
Net income available to common
and preferred shareholders ..... 285.5 32.3
HomeServices' 2002 Acquisitions
- -------------------------------
In 2002, HomeServices separately acquired three real estate companies for an
aggregate purchase price of approximately $106.1 million, net of cash acquired,
plus working capital and certain other adjustments. For the year ended December
31, 2001, these real estate companies had combined revenue of approximately
$356.0 million on 42,000 closed sides representing $13.7 billion of sales
volume. Additionally, HomeServices is obligated to pay a maximum earnout of
$18.5 million based on 2002 financial performance measures. These purchases were
financed using HomeServices' internally generated cash flows, revolving credit
facility and $40.0 million from the Company, which was contributed to
HomeServices as equity.
-63-
The acquisitions have been accounted for as a purchase business combination. The
purchase price has been allocated to assets acquired and liabilities assumed.
The Company recorded goodwill of approximately $108.9 million.
Yorkshire Swap
- --------------
On September 21, 2001, CE Electric UK Ltd, an indirect wholly owned subsidiary
of the Company, and Innogy Holdings, plc ("Innogy") executed an agreement to
exchange Northern' Electrics electricity and gas supply and metering assets for
Innogy's 94.75% interest in Yorkshire's electricity distribution business.
Northern Electric's supply business was valued at approximately $391.0 million
((pound)268.0 million), including working capital of approximately $14.0 million
((pound)10.0 million). 94.75% of Yorkshire's distribution business was valued at
approximately $405.0 million ((pound)278.0 million), including working capital
of approximately $58.0 million ((pound)40.0 million). The net cash paid by
Northern Electric for the exchange was approximately $14.0 million ((pound)10.0
million).
The disposition of Northern Electric's supply business created a pre-tax
non-recurring gain of $196.7 million and an after-tax gain of $10.8 million.
Included in the carrying value of the Northern Electric supply business was
$504.4 million of goodwill allocated based on the relative fair values of the
Northern Electric supply business.
The Company paid $57.4 million, net of cash acquired of $353.8 million and
transaction costs, for 94.75% of the Yorkshire electricity distribution business
and related indebtedness. The acquisition has been accounted for as a purchase
business combination. The results of operations for Yorkshire are included in
the Company's results beginning September 21, 2001.
Teton Transaction
- -----------------
On October 24, 1999, the Company and an investor group comprised of Berkshire
Hathaway, Walter Scott, Jr., and David L. Sokol, executed a definitive agreement
and plan of merger whereby the investor group would acquire all of the
outstanding common stock of the Company for $35.05 per share in cash,
representing a total purchase price of approximately $2.2 billion, including
transaction costs. The Teton Transaction closed on March 14, 2000 and Berkshire
Hathaway invested approximately $1.24 billion in common stock and convertible
preferred stock and approximately $455 million in 11% nontransferable trust
preferred securities due March 14, 2010. Mr. Scott, Mr. Sokol and Gregory E.
Abel contributed cash and current securities of the Company having a value of
approximately $310 million. The remaining purchase price was funded with the
Company's cash. Berkshire Hathaway owns approximately 9.7% of the voting stock,
Mr. Scott owns approximately 86% of the voting stock, Mr. Sokol owns
approximately 3% of the voting stock and Mr. Abel owns approximately 1% of the
voting stock.
The merger has been accounted for as a purchase business combination. The
purchase price has been allocated to assets acquired and liabilities assumed.
The Company recorded goodwill of approximately $1.2 billion.
4. DISPOSITIONS AND OTHER NON-RECURRING ITEMS
CE Gas Asset Sale
- -----------------
In May 2002, CE Gas, an indirect wholly owned subsidiary of the Company,
executed the sale of several of its U.K. natural gas assets to Gaz de France for
(pound)137.0 million (approximately $200.0 million). CE Gas sold four natural
gas-producing fields located in the southern basin of the U.K. North Sea,
including Anglia, Johnston, Schooner and Windermere. The transaction also
included the sale of rights in four gas fields (in development/construction) and
three exploration blocks owned by CE Gas. The Company recorded pre-tax and
after-tax income of $54.3 million and $41.3 million, respectively, which
includes a write off of non-deductible goodwill of $49.6 million.
Telephone Flat Sale
- -------------------
On October 16, 2001, the Company closed on a transaction that transferred all
properties and rights of the Telephone Flat Project, a geothermal development
project in northern California to Calpine Corp. The Company recorded a pre-tax
gain of $20.7 million and an after-tax gain of $12.2 million on the sale of the
Telephone Flat Project.
-64-
Western States Sale
- -------------------
On June 30, 2001, the Company closed on a transaction in which the Company sold
Western States Geothermal, an indirect wholly owned subsidiary of the Company,
to Ormat. The Company recorded a pre-tax gain of $9.8 million and an after-tax
gain of $6.4 million on the sale of Western States Geothermal.
Tesside Power Limited ("TPL")
- -----------------------------
In December 2001, the Company recorded a non-recurring charge of $20.7 million,
net of tax, representing an asset valuation impairment charge under SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets" ("SFAS 121") relating
to the Company's 15.4% interest in TPL. TPL owns and operates a 1,875 MW
combined cycle gas-fired power plant. Enron Corp. ("Enron"), through its
subsidiaries, owned a 42.5% interest, operated the plant, and purchased 668 MW
of capacity. Enron's subsidiary, which owns and operates TPL, is now in
administration and administrators have been appointed to run its business and
are attempting to find a buyer.
Shareholders in TPL had previously utilized TPL's taxable losses with an
obligation to reimburse TPL later in the project's life. In May 2002, TPL
executed a restructuring and stabilization agreement with its lenders. The
contract included an agreement between TPL and its shareholders with respect to
the waiver of these repayment obligations. In May 2002, TPL released $35.7
million due to the repayment obligation being waived which is reflected as a tax
benefit in the provision for income taxes.
5. PROPERTIES, PLANTS AND EQUIPMENT, NET
Properties, plants and equipment, net comprise the following at December 31 (in
thousands):
ESTIMATED DECEMBER 31,
USEFUL LIVES -------------------------
(Years) 2002 2001
------------ ----------- -----------
Properties, plants and equipment, net:
Utility generation and distribution system .... 10-50 $ 8,165,140 $ 7,574,339
Interstate pipelines' assets .................. 3-87 2,171,436 --
Independent power plants ...................... 10-30 1,410,170 1,402,102
Mineral and gas reserves and exploration assets 5-30 495,423 387,697
Utility non-operational assets ................ 3-30 370,811 354,366
Other assets .................................. 3-10 130,755 153,211
----------- -----------
Total operating assets ...................... 12,743,735 9,871,715
----------- -----------
Accumulated depreciation and amortization ..... (4,104,133) (3,650,875)
----------- -----------
Net operating assets .......................... 8,639,602 6,220,840
Construction in progress ...................... 1,170,485 316,531
----------- -----------
Properties, plants and equipment, net ....... $ 9,810,087 $ 6,537,371
=========== ===========
Construction in Progress
- ------------------------
MidAmerican Energy is constructing a 500-MW (based on expected accreditation)
natural gas-fired, combined cycle plant with an estimated cost of $415 million.
MidAmerican Energy will own 100% of the plant and operate it. The plant will be
operated in simple cycle mode during 2003 and 2004, resulting in 310 MW of
accredited capacity. The combined cycle operation will commence in 2005.
MidAmerican Energy has received a certificate from the Iowa Utilities Board,
"(IUB"), allowing it to construct the plant. In May 2002, the IUB issued an
order that specified the Iowa ratemaking principles that will apply to the plant
over its life. As a result of that order, MidAmerican Energy is proceeding with
the construction of the plant.
The 2003 Expansion Project is a new parallel 717-mile loop pipeline that will
begin in Lincoln County, Wyoming and terminate in Kern County, California. The
2003 Expansion Project began construction on August 6, 2002 and is expected to
be completed and operational by May 1, 2003 at a total cost of approximately
$1.2 billion. The pipeline will include 36- and 42-inch diameter pipe, most of
which will be laid in the existing Kern River rights-of-way at a 25-foot offset
from the
-65-
existing pipeline, and new above ground facilities. Three segments
along the rights-of-way, approximately 205 miles in Utah, Nevada and California,
will not require additional pipeline but will instead be areas where the gas
will be compressed and transported through the existing pipeline. The existing
pipeline rights-of-way, compressor facilities and receipt/delivery facilities
will all be utilized by the 2003 Expansion Project, streamlining the permitting,
acquisition of rights-of-way and ultimately the construction and operations of
the 2003 Expansion Project.
The 2003 Expansion Project includes the construction of three new compressor
stations and the installation of additional compression and other modifications
at six existing facilities. When completed, the Kern River system will have a
summer day design capacity of approximately 1.73 Bcf per day, an increase of
approximately 886 mmcf per day.
6. INVESTMENT IN CE GENERATION
Since the sale of 50% of its interests in CE Generation on March 3, 1999, the
Company has accounted for CE Generation as an equity investment. The equity
investment in CE Generation at December 31, 2002 and 2001 was approximately
$244.9 million and $233.6 million, respectively. The following is summarized
financial information for CE Generation as of and for the years ended December
31 (in thousands):
2002 2001 2000
---------- ---------- --------
Revenue .................................... $ 510,082 $ 565,838 $510,796
Income before cumulative effect of change in
accounting principle ..................... 58,314 74,194 73,535
Net income ................................. 58,314 58,808 73,535
Current assets ............................. 202,490 211,635
Total assets ............................... 1,865,036 1,932,119
Current liabilities ........................ 150,165 155,808
Long-term debt, including current portion .. 1,011,220 1,096,256
7. OTHER INVESTMENTS
Williams' Company Preferred Stock
- ---------------------------------
On March 27, 2002, a newly formed subsidiary of the Company, MEHC Investments
Inc., invested $275.0 million in Williams in exchange for shares of 9 7/8%
cumulative convertible preferred stock of Williams. Dividends on the Williams'
preferred stock are scheduled to be received quarterly, which commenced July 1,
2002. This investment is accounted for under the cost method. Since the date of
this investment, there have been public announcements that Williams' financial
condition has deteriorated as a result of, among other factors, reduced
liquidity. The Company has not recorded an impairment on this investment as of
December 31, 2002, and is monitoring the situation.
-66-
Investments in Debt and Equity Securities
- -----------------------------------------
Substantially all of the Company's investments in debt and equity securities
relate to its Quad Cities Station decommissioning trust. The amortized cost,
gross unrealized gain and losses and estimated fair value of investments in debt
and equity securities comprise the following at December 31 (in thousands):
2002
--------------------------------------------
AMORTIZED UNREALIZED UNREALIZED FAIR
COST GAINS LOSSES VALUE
--------- ---------- ---------- --------
Available-for-sale:
Equity securities ............. $ 56,265 $16,373 $(1,313) $ 71,325
Municipal bonds ............... 30,915 918 (263) 31,570
U. S. Government securities ... 18,511 183 (119) 18,575
Corporate securities .......... 25,258 1,152 (80) 26,330
Cash equivalents .............. 12,718 -- -- 12,718
-------- ------- ------- --------
Total available-for-sale .... $143,667 $18,626 $(1,775) $160,518
======== ======= ======= ========
HELD-TO-MATURITY:
Debt securities ............... $ 2,070 $ -- $ -- $ 2,070
U.S. Treasury Strips .......... 1,485 208 -- 1,693
Agency obligations ............ 216 111 -- 327
-------- ------- ------- --------
Total held-to-maturity ...... $ 3,771 $ 319 $ -- $ 4,090
======== ======= ======= ========
2001
---------------------------------------------
AMORTIZED UNREALIZED UNREALIZED FAIR
COST GAINS LOSSES VALUE
---------- ---------- ---------- ---------
Available-for-sale:
Equity securities ............. $ 53,663 $24,444 $(3,144) $ 74,963
Municipal bonds ............... 27,842 1,315 (92) 29,065
U. S. Government securities ... 26,725 1,910 (19) 28,616
Corporate securities .......... 18,682 812 (23) 19,471
Cash equivalents .............. 7,120 -- -- 7,120
-------- ------- ------- --------
Total available-for-sale .... $134,032 $28,481 $(3,278) $159,235
======== ======= ======= ========
HELD-TO-MATURITY:
Debt securities ............... $ 2,074 $ -- $ -- $ 2,074
U.S. Treasury Strips .......... 1,090 85 -- 1,175
Agency obligations ............ 611 -- (22) 589
-------- ------- ------- --------
Total held-to-maturity ...... $ 3,775 $ 85 $ (22) $ 3,838
======== ======= ======= ========
At December 31, 2002, the debt securities held by the Company had the following
maturities (in thousands):
AVAILABLE FOR SALE HELD TO MATURITY
------------------- ------------------
AMORTIZED FAIR AMORTIZED FAIR
COST VALUE COST VALUE
--------- ------- --------- -------
Within 1 year ...... $ 7,224 $ 7,384 $2,070 $2,070
1 through 5 years .. 25,143 25,994 479 664
5 through 10 years . 14,190 14,574 1,222 1,356
Over 10 years ...... 27,621 28,020 -- --
-67-
The proceeds and gross realized gains and losses on the disposition of
available-for-sale and held-to-maturity investments are shown in the following
table (in thousands). Realized gains and losses are determined by specific
identification.
MEHC
(PREDECESSOR)
YEAR ENDED MARCH 14, 2000 JANUARY 1, 2000
DECEMBER 31, THROUGH THROUGH
2002 2001 DECEMBER 31, 2000 MARCH 13, 2000
-------- ------- ----------------- ---------------
Proceeds from sales $151,394 $68,333 $93,531 $ 22,588
Gross realized gains 7,099 2,676 6,464 1,560
Gross realized losses (7,792) (7,314) (10,585) (2,556)
8. SHORT-TERM DEBT
Short-term debt comprises the following at December 31 (in thousands):
2002 2001
------- --------
Short-term debt:
Corporate revolving credit facility .... $ -- $153,500
MidAmerican Energy short-term debt ..... 55,000 91,780
HomeServices revolving credit facilities 24,750 9,000
Other .................................. 32 1,732
------- --------
Total short-term debt .................. $79,782 $256,012
======= ========
Corporate Revolving Credit Facilities
- -------------------------------------
The Company has a $400.0 million revolving credit facility which expires in June
2003. The facility is unsecured and available to fund working capital
requirements and other corporate requirements. The facility carries a variable
interest rate based on LIBOR and ranged from 2.625% to 2.8625% in 2002. No
borrowings were outstanding at December 31, 2002. The Company plans to renew the
facility in June 2003.
MidAmerican Energy Short-Term Debt
- ----------------------------------
As of December 31, 2002, MidAmerican Energy had in place a $370.4 million
revolving credit facility that supports its $250.0 million commercial paper
program and its variable rate pollution control revenue obligations. In
addition, MidAmerican Energy has a $5.0 million line of credit. As of December
31, 2002, commercial paper and bank notes totaled $55.0 million for MidAmerican
Energy. MHC Inc., an indirect wholly owned subsidiary of the Company, has a $4.0
million line of credit under which no borrowings were outstanding at December
31, 2002. The commercial paper, bank notes and outstanding line of credit have a
weighted average interest rate of 1.29% at December 31, 2002.
HomeServices Revolving Credit Facilities
- ----------------------------------------
Upon the expiration of its $65.0 million senior secured revolving credit
facility in November 2002, HomeServices entered into a new $125.0 million senior
secured revolving credit agreement. The new revolving credit agreement has a
term of three years and is secured by a pledge of the capital stock of all of
the existing and future subsidiaries of HomeServices. Amounts outstanding under
this revolving credit facility bear interest, at HomeServices' option, at either
the prime lending rate or LIBOR plus a fixed spread of 1.25% to 2.25%, which
varies based on HomeServices' cash flow leverage ratio (1.25% at December 31,
2002). As of December 31, 2002, the outstanding balance of $24.8 million had a
weighted average interest rate of 2.6661%.
-68-
9. PARENT COMPANY DEBT
Parent company debt is unsecured senior obligations of the Company and comprises
the following at December 31 (in thousands):
2002 2001
----------- -----------
Parent company debt:
6.96% Senior Notes, due 2003 ............ $ 215,000 $ 215,000
7.23% Senior Notes, due 2005 ............ 260,000 260,000
4.625% Senior Notes, due 2007 ........... 200,000 --
7.63% Senior Notes, due 2007 ............ 350,000 350,000
7.52% Senior Notes, due 2008 ............ 450,000 450,000
7.52% Senior Notes, due 2008 (Series B) . 101,481 101,680
5.875% Senior Notes, due 2012 ........... 500,000 --
8.48% Senior Notes, due 2028 ............ 475,000 475,000
Fair value adjustments and other ........ (12,025) (17,182)
----------- -----------
Total parent company debt ............. 2,539,456 1,834,498
Less current portion ................ (215,000) --
----------- -----------
Total long-term parent company debt ... $ 2,324,456 $ 1,834,498
=========== ===========
Interest on the 7.63% Senior Notes is payable semiannually on April 15 and
October 15 of each year. Interest on the 4.625% Senior Notes and the 5.875%
Senior Notes is payable semiannually on January 31 and July 31 of each year.
Interest on the remaining parent company debt is payable semiannually on March
15 and September 15 of each year.
10. SUBSIDIARY AND PROJECT LOANS
Each of the Company's direct and indirect subsidiaries is organized as a legal
entity separate and apart from the Company and its other subsidiaries. Pursuant
to separate project financing agreements, the assets of each subsidiary are
pledged or encumbered to support or otherwise provide the security for their own
project or subsidiary debt. It should not be assumed that any asset of any such
subsidiary will be available to satisfy the obligations of the Company or any of
its other such subsidiaries; provided, however, that unrestricted cash or other
assets which are available for distribution may, subject to applicable law and
the terms of financing arrangements of such parties, be advanced, loaned, paid
as dividends or otherwise distributed or contributed to the Company or
affiliates thereof.
-69-
Project loans held by subsidiaries and projects comprise the following at
December 31 (in thousands):
2002 2001
----------- -----------
Subsidiary and project loans:
MidAmerican Funding Senior Notes and Bonds ..... $ 700,000 $ 700,000
MidAmerican Energy Mortgage Bonds .............. 340,570 340,570
MidAmerican Energy Pollution Control Bonds ..... 155,745 157,185
MidAmerican Energy Notes ....................... 560,000 322,240
MidAmerican Capital Notes ...................... -- 23,333
Northern Electric Eurobonds .................... 322,811 291,643
CE Electric UK Senior Notes and Sterling Bonds . 677,642 646,500
Yorkshire ...................................... 1,573,136 1,491,597
CE Gas Loan .................................... -- 70,180
Kern River Senior Notes ........................ 488,000 --
Kern River Construction Financing Facility ..... 789,916 --
Northern Natural Gas Senior Notes .............. 799,406 --
Cordova Funding Senior Secured Bonds ........... 223,763 225,000
Salton Sea Funding Corporation Series F Bonds .. 137,789 139,896
Casecnan Notes and Bonds ....................... 287,925 320,138
Philippine Term Loans .......................... 244,961 313,221
HomeServices Senior Notes and Other ............ 39,031 36,780
Other, including fair value adjustments ........ (8,395) (6,292)
----------- -----------
Total subsidiary and project loans ........... 7,332,300 5,071,991
Less current portion ....................... (255,213) (317,180)
----------- -----------
Total long-term subsidiary and project loans . $ 7,077,087 $ 4,754,811
=========== ===========
MidAmerican Funding Senior Notes and Bonds
- ------------------------------------------
On March 11, 1999, MidAmerican Funding, a wholly owned subsidiary of the
Company, issued $200.0 million of 5.85% Senior Secured Notes due in 2001, $175.0
million of 6.339% Senior Secured Notes due in 2009, and $325.0 million of 6.927%
Senior Secured Bonds due in 2029. The proceeds from the offering were used to
complete the MidAmerican acquisition in 1999.
On March 1, 2001 MidAmerican Funding retired $200.0 million of 5.85% Senior
Secured Notes due 2001. On March 19, 2001 MidAmerican Funding issued $200
million of 6.75% Senior Secured Notes due March 1, 2011.
MidAmerican Funding uses distributions that it receives from its subsidiaries to
make payments on the Senior Notes and Bonds. These 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 its common equity level above 42% of total
capitalization unless circumstances beyond its control result in the common
equity level decreasing to below 39% of total capitalization. MidAmerican
Funding must seek the approval of the IUB of a reasonable utility capital
structure if MidAmerican Energy's common equity level decreases below 42% of
total capitalization, unless the decrease is beyond the control of MidAmerican
Funding. MidAmerican Funding is also required to seek the approval of the IUB if
MidAmerican Energy's equity level decreases to below 39%, even if the decrease
is due to circumstances beyond the control of MidAmerican Funding.
-70-
MidAmerican Energy Mortgage Bonds, Pollution Control Bonds and Notes
- --------------------------------------------------------------------
The components of MidAmerican Energy's Mortgage Bonds, Pollution Control Bonds
and Notes comprise the following at December 31 (in thousands):
2002 2001
-------- --------
Mortgage bonds:
7.125% Series, due 2003 .......................... $100,000 $100,000
7.70% Series, due 2004 ........................... 55,630 55,630
7% Series, due 2005 .............................. 90,500 90,500
7.375% Series, due 2008 .......................... 75,000 75,000
7.45% Series, due 2023 ........................... 6,940 6,940
6.95% Series, due 2025 ........................... 12,500 12,500
-------- --------
Total mortgage bonds ............................. $340,570 $340,570
======== ========
Pollution control revenue obligations:
5.75% Series, due periodically through 2003 ...... $ 4,320 $ 5,760
5.95% Series, due 2023 ........................... 29,030 29,030
6.7% Series, due 2003 ............................ 1,000 1,000
6.1% Series, due 2007 ............................ 1,000 1,000
Variable rate series:
Due 2016 and 2017, 1.64% and 1.77% respectively .. 37,600 37,600
Due 2023 (secured by general mortgage bond, 1.64%
and 1.77%, respectively .......................... 28,295 28,295
Due 2023, 1.64% and 1.77%, respectively .......... 6,850 6,850
Due 2024, 1.64% and 1.77%, respectively .......... 34,900 34,900
Due 2025, 1.64% and 1.77%, respectively .......... 12,750 12,750
-------- --------
Total pollution control revenue obligations ...... $155,745 $157,185
======== ========
Notes:
8.75% Series, due 2002 ........................... $ -- $ 240
7.375% Series, due 2002 .......................... -- 162,000
6.75% Series, due 2031 ........................... 400,000 --
6.375% Series, due 2006 .......................... 160,000 160,000
-------- --------
Total notes ...................................... $560,000 $322,240
======== ========
On February 8, 2002, MidAmerican Energy issued $400 million of 6.75% notes due
in 2031. The proceeds were used to refinance existing debt and preferred
securities and for other corporate purposes. On March 11, 2002, MidAmerican
Energy redeemed its MidAmerican Energy-obligated mandatorily redeemable
preferred securities of subsidiary trust at 100% of the principal amount plus
accrued interest.
-71-
CE Electric UK, Northern Electric and Yorkshire Electric Eurobonds, Senior Notes
- --------------------------------------------------------------------------------
and Sterling Bonds
- ------------------
2002 2001
---------- ----------
Eurobonds:
8.625% Bearer bonds, due 2005 ................ $ 161,469 $ 145,879
8.875% Bearer bonds, due 2020 ................ 161,342 145,764
---------- ----------
Total eurobonds .............................. $ 322,811 $ 291,643
========== ==========
Senior Notes and Sterling Bonds:
6.853% Senior Notes, due 2004 ................ $ 124,590 $ 124,613
6.995% Senior Notes, due 2007 ................ 236,223 235,937
7.25% Sterling Bonds, due 2022 ............... 316,829 285,950
---------- ----------
Total senior notes and sterling bonds ........ $ 677,642 $ 646,500
========== ==========
Yorkshire:
9.25% Eurobonds, due 2020 .................... $ 421,896 $ 383,576
7.25% Eurobonds, due 2028 .................... 342,539 311,427
Variable Rate Reset Trust Securities, due 2020
(5.04% at December 31, 2002) ............... 258,821 235,313
8.08% Trust Securities, due 2038 ............. 249,695 261,082
6.496% Yankee Bonds, due 2008 ................ 300,185 300,199
---------- ----------
Total Yorkshire Electric debt ................ $1,573,136 $1,491,597
========== ==========
The CE Electric UK Senior Notes and Sterling Bonds prohibit distributions to any
of its stockholders unless certain financial ratios are met by CE Electric UK or
the long-term debt rating is above a prescribed level.
The Yorkshire Electric Debt prohibits distributions to any of its stockholders
unless certain financial ratios are met by Yorkshire or the long-term debt
rating is above a prescribed level.
On February 15, 2005, the Yorkshire Variable Rate Reset Trust Securities may be
remarketed by the underwriter at a fixed rate of interest through the maturity
date or, at a floating rate of interest for up to one year and then at fixed
rate of interest through 2020, or redeemed by Yorkshire.
Kern River Senior Notes and Construction Financing Facility
- -----------------------------------------------------------
On August 13, 2001, Kern River issued $510.0 million in debt securities. The
offering was in the form of $510.0 million of 15-year amortizing Senior Notes
bearing a fixed rate of interest of 6.676%. For the Senior Notes, $405.0 million
will be amortized through June 2016, with a final payment of $105.0 million to
be made on July 31, 2016. As of December 31, 2002, the balance of the Kern River
Senior Notes was $488.0.
On July 17, 2002, Kern River received approval from the FERC to construct, own
and operate the 2003 Expansion Project. The estimated cost of the expansion is
approximately $1.2 billion and is being be financed with approximately 70% debt
and 30% equity, consistent with Kern River's original capital structure, the
application for the FERC approval described above and the limitations contained
in the indenture for Kern River`s existing senior notes.
Construction is being initially funded with the proceeds of the $875.0 million
credit facility entered into by Kern River on June 21, 2002, for approximately
70% of the projected capitalized costs of the 2003 Expansion Project. The
remaining approximately 30% of the capitalized costs of the 2003 Expansion
Project is being funded with equity from the Company. As of December 31, 2002,
the balance of the Kern River construction financing facility was $789.9
million.
-72-
Northern Natural Gas Senior Notes
- ---------------------------------
The components of Northern Natural Gas' Senior Notes comprise the following at
December 31 (in thousands):
2002
---------
6.875% Senior Notes, due 2005 .......... $ 100,000
6.75% Senior Notes, due 2008 ........... 150,000
7.00% Senior Notes, due 2011 ........... 250,000
5.375% Senior Notes, due 2012 .......... 300,000
Unamortized debt discount .............. (594)
---------
Total Senior Notes ..................... $ 799,406
=========
Cordova Funding Senior Secured Bonds
- ------------------------------------
On September 10, 1999, Cordova Funding Corporation ("Cordova Funding"),
a wholly owned subsidiary of the Company, closed the $225.0 million aggregate
principal amount financing for the construction of the Cordova Project. The
proceeds were loaned to Cordova Energy and comprise the following at December 31
(in thousands):
2002 2001
-------- --------
8.64% Senior Secured Bonds, due 2019 .. $ 93,001 $ 93,515
8.79% Senior Secured Bonds, due 2019 .. 31,137 31,309
9.07% Senior Secured Bonds, due 2019 .. 29,139 29,300
8.48% Senior Secured Bonds, due 2019 .. 12,685 12,755
8.82% Senior Secured Bonds, due 2019 .. 57,801 58,121
-------- --------
Total Senior Secured Bonds ............ $223,763 $225,000
======== ========
MEHC has guaranteed a specified portion of the final scheduled principal payment
on December 15, 2019 on the Cordova Funding Senior Secured Bonds in an amount up
to a maximum of $37.0 million. MEHC also provides a debt service reserve
guarantee in an amount equal to the principal, premium, if any, and interest
payment due on the bonds on the next scheduled payment date which was equal to
$14.3 million at December 31, 2002.
Salton Sea Funding Corporation Series F Bonds
- ---------------------------------------------
Salton Sea Funding Corporation, an indirect wholly owned subsidiary of CE
Generation, had a debt balance of $491.7 million at December 31, 2002. Minerals
is one of several guarantors of the Salton Sea Funding Corporation's debt. As a
result of a note allocation agreement, Minerals is primarily responsible for
$137.8 million of the 7.475% Senior Secured Series F Bonds due November 30,
2018. MEHC has guaranteed a specified portion of the scheduled debt service on
the Series F Bonds equal to this current principal amount of $137.8 million and
associated interest.
Casecnan Notes and Bonds
- ------------------------
On November 27, 1995, CE Casecnan Ltd. ("CE Casecnan") issued $371.5 million of
notes and bonds to finance the construction of the Casecnan Project. The
Casecnan notes and bonds comprise the following at December 31 (in thousands):
2002 2001
-------- --------
Casecnan notes and bonds:
Senior Secured Floating Rate Notes (FRNs), due in 2002 ... $ -- $ 23,638
11.45% Senior Secured Series A Notes, due in 2005 ........ 125,000 125,000
11.95% Senior Secured Series B Bonds, due in 2010 ........ 162,925 171,500
-------- --------
Total Casecnan notes and bonds ........................... $287,925 $320,138
======== ========
The Casecnan Notes and Bonds are subject to redemption at the Company's option
as provided in the Trust Indenture. The Casecnan Notes and Bonds are also
subject to mandatory redemption based on certain conditions.
-73-
Philippine Term Loans
- ---------------------
The Export-Import Bank of the United States ("Ex-Im Bank") provided term loan
financing for the Company's Mahanagdong geothermal power project of $92.8
million at a fixed rate of 6.92%. The Overseas Private Investment Corporation
("OPIC") is providing term loan financing of $20.6 million at a fixed interest
rate of 7.6%. The loans have scheduled repayments through June 2007.
OPIC provided term loan financing for the Company's Malitbog geothermal power
project of $22.7 million that was fixed at an interest rate of 9.176%. A
syndicate of international commercial banks is providing term loan financing of
$40.9 million at a variable interest rate based on LIBOR (3.84% at December 31,
2002). The loans have scheduled repayments through June 2005.
Ex-Im provided term loan financing for the Company's Upper Mahiao geothermal
power project of $63.1 million at a fixed interest rate of 5.95%. United Coconut
Planters Bank of the Philippines is providing term loan financing of $5.0
million at a variable interest rate based on LIBOR (4.42% at December 31, 2002).
The loans have scheduled repayments through June 2006.
The Philippine term loans comprise the following at December 31 (in thousands):
2002 2001
-------- --------
Philippine term loans:
Mahanagdong Project 7.60% Term Loan, due 2007 .......... $ 20,571 $ 25,143
Mahanagdong Project 6.92% Term Loan, due 2007 .......... 92,766 113,381
Malitbog Project Variable Rate Term Loan, due 2005
3.84% and 4.295%, respectively ......................... 40,890 55,402
Malitbog Project 9.176% Term Loan, due 2006 ............ 22,677 30,725
Upper Mahiao Project Variable Rate Term Loan, due 2003
4.42% and 5.130%, respectively ......................... 5,000 6,111
Upper Mahiao Project 5.95% Term Loan, due 2006 ......... 63,057 82,459
-------- --------
Total Philippine term loans ............................ $244,961 $313,221
======== ========
HomeServices Senior Notes and Other
- -----------------------------------
In November 1998, HomeServices issued $35.0 million of 7.12% fixed-rate private
placement senior notes due in annual increments of $5.0 million beginning in
2004. As of December 31, 2002, the balance of the HomeServices Senior Notes was
$35.0 million.
In addition to the senior notes, HomeServices' has outstanding notes, with
varying interest rates, totaling $4.0 million at December 31, 2002.
-74-
Annual Repayments of Debt
- -------------------------
The annual repayments of debt for the years beginning January 1, 2003 and
thereafter are as follows (in thousands):
2003 2004 2005 2006 2007 THEREAFTER TOTAL
-------- -------- -------- -------- -------- ----------- -----------
Parent, Subsidiary and Project loans:
Parent Company Debt ............................ $215,000 $ -- $260,000 $ -- $550,000 $ 1,514,456 $ 2,539,456
MidAmerican Funding Senior Notes and Bonds ..... -- -- -- -- -- 700,000 700,000
MidAmerican Energy Mortgage Bonds .............. 100,000 55,630 90,500 -- -- 94,440 340,570
MidAmerican Energy Pollution Control Bonds ..... 5,727 -- -- -- 1,000 149,018 155,745
MidAmerican Energy Notes ....................... -- -- -- 160,000 -- 400,000 560,000
Northern Electric Eurobonds ................... -- -- 161,469 -- -- 161,342 322,811
CE Electric UK Senior Notes and Sterling Bonds . -- 124,590 -- -- 236,223 316,829 677,642
Yorkshire ...................................... -- -- -- -- -- 1,573,136 1,573,136
Kern River Senior Notes ........................ 24,000 25,000 26,000 26,000 26,000 361,000 488,000
Kern River Construction Financing Facility ..... -- -- -- -- -- 789,916 789,916
Northern Natural Gas Senior Notes .............. -- -- 100,000 -- -- 699,406 799,406
Cordova Funding Senior Secured Bonds ........... 9,000 8,100 7,875 4,500 4,162 190,126 223,763
Salton Sea Funding Corporation Series F Bonds .. 1,405 1,757 1,756 1,827 1,055 129,989 137,789
Casecnan Notes and Bonds ....................... 41,468 49,360 54,752 36,015 37,730 68,600 287,925
Philippine Term Loans .......................... 72,148 67,148 63,034 30,037 12,594 -- 244,961
HomeServices Senior Notes and Other ............ 1,465 5,133 5,048 5,036 5,024 17,325 39,031
Other, including fair value adjustments ........ -- -- -- -- -- (8,395) (8,395)
-------- -------- -------- -------- -------- ----------- -----------
Total parent, subsidiary and project loans ... $470,213 $336,718 $770,434 $263,415 $873,788 $ 7,157,188 $ 9,871,756
======== ======== ======== ======== ======== =========== ===========
Fair Value
- ----------
At December 31, 2002, the Company had fixed-rate long-term debt,
Company-obligated mandatorily redeemable preferred securities of subsidiary
trusts, and subsidiary-obligated mandatorily redeemable preferred securities of
subsidiary trusts of $11,683.2 million in principal amount and having a fair
value of $12,188.8 million. In addition, at December 31, 2002, the Company had
floating-rate obligations of $425.1 million that expose the Company to the risk
of increased interest expense in the event of increases in short-term interest
rates.
11. INCOME TAXES
Provision for income taxes was comprised of the following (in thousands):
MEHC
YEAR ENDED (PREDECESSOR)
DECEMBER 31, MARCH 14, 2000 JANUARY 1, 2000
----------------------- THROUGH THROUGH
2002 2001 DECEMBER 31, 2000 MARCH 13, 2000
--------- --------- ----------------- ---------------
Current:
Federal .. $ 46,714 $ 51,025 $ 17,387 $ 9,147
State .... 14,516 2,669 10,527 (1,886)
Foreign .. 54,586 43,450 40,823 16,012
--------- --------- -------- --------
115,816 97,144 68,737 23,273
--------- --------- -------- --------
Deferred:
Federal .. $ (7,073) $ (14,004) $(32,469) $ 1,854
State .... (9,675) (342) (1,933) 834
Foreign .. 520 167,266 18,942 5,047
--------- --------- -------- --------
(16,228) 152,920 (15,460) 7,735
--------- --------- -------- --------
Total .. $ 99,588 $ 250,064 $ 53,277 $ 31,008
========= ========= ======== ========
-75-
A reconciliation of the federal statutory tax rate to the effective tax rate
applicable to income before provision for income taxes follows:
MEHC
YEAR ENDED (PREDECESSOR)
DECEMBER 31, MARCH 14, 2000 JANUARY 1, 2000
-------------- THROUGH THROUGH
2002 2001 DECEMBER 31, 2000 MARCH 13, 2000
---- ---- ----------------- ----------------
Federal statutory rate ................. 35.0% 35.0% 35.0% 35.0%
Investment and energy tax credits ...... (0.7) (1.0) (2.3) (0.7)
State taxes, net of federal tax effect . 1.2 3.2 2.6 (0.8)
Goodwill amortization .................. -- 5.9 12.1 5.9
Dividends on preferred
securities of subsidiary trusts ...... (8.1) (6.1) (11.1) (2.8)
Tax effect of foreign income ........... (4.8) (2.5) (5.8) (5.0)
Non-recurring items on CE Electric UK,
net of tax effect of foreign income .. (8.1) 19.2 -- --
Dividends received deduction ........... (1.8) (2.6) (6.8) (1.0)
Other items, net ....................... 2.8 (1.5) 0.6 3.4
---- ---- ---- ----
Effective tax rate ..................... 15.5% 49.6% 24.3% 34.0%
==== ==== ==== ====
Deferred tax liabilities (assets) comprise the following at December 31 (in
thousands):
2002 2001
----------- -----------
Properties, plants and equipment, net ............ $ 1,325,228 $ 1,133,286
Income taxes recoverable through future rates .... 159,411 185,222
Employee benefits ................................ 65,537 68,514
Reacquired debt .................................. 4,914 7,544
Fuel cost recoveries ............................. -- 20,272
Other ............................................ 121 --
----------- -----------
1,555,211 1,414,838
----------- -----------
Minimum pension liability adjustment ............. (140,854) (5,147)
Revenue sharing accruals ......................... (48,861) (24,769)
Accruals not currently deductible for tax purposes (59,083) (47,287)
Nuclear reserve and decommissioning .............. (28,411) (17,898)
Deferred income .................................. (21,733) (24,732)
Fuel cost recoveries ............................. (9,558) --
NOL and credit carryforwards ..................... (8,290) (5,567)
Other ............................................ -- (5,170)
----------- -----------
(316,790) (130,570)
----------- -----------
Net deferred income taxes ...................... $ 1,238,421 $ 1,284,268
=========== ===========
-76-
12. COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY
TRUSTS
The Company has organized special purpose Delaware business trusts
(collectively, the "Trusts") pursuant to their respective amended and restated
declarations of trusts (collectively, the "Declarations"). The Company, through
these Trusts, issued Company-obligated mandatorily redeemable preferred
securities (collectively, the "Trust Securities") as follows (in thousands):
2002 2001
----------- ---------
CalEnergy Capital Trust II - 6.25% preferred securities, due 2012 .. $ 155,538 $ 155,584
CalEnergy Capital Trust III - 6.5% preferred securities, due 2027 .. 269,980 269,984
MidAmerican Capital Trust I - 11% preferred securities, due 2010 ... 454,772 454,772
MidAmerican Capital Trust II - 11% preferred securities, due 2012 .. 323,000 --
MidAmerican Capital Trust III - 11% preferred securities, due 2012 . 950,000 --
Fair value adjustment .............................................. (89,878) (92,189)
----------- ---------
Total Company-Obligated Mandatorily Redeemable Preferred Securities
of Subsidiary Trusts ............................................. $ 2,063,412 $ 788,151
=========== =========
The Company owns all of the common securities of the Trusts. The Trust
Securities have a liquidation preference of $50 each and represent undivided
beneficial ownership interests in each of the Trusts. The assets of the Trusts
consist solely of the Company's Subordinated Debentures (collectively, the
"Junior Debentures") issued pursuant to their respective indentures. The
indentures include agreements by the Company to pay expenses and obligations
incurred by the Trusts.
Prior to the Teton Transaction, each Trust Security issued by CalEnergy Capital
Trust II and III with a par value of $50 was convertible at the option of the
holder at any time into shares of the Company's common stock based on the
conversion rate. As a result of the Teton Transaction, in lieu of shares of the
Company's common stock, holders of Trust Securities will receive $35.05 for each
share of common stock it would have been entitled to receive on conversion.
Distributions on the Trust Securities (and Junior Debentures) are cumulative,
accrue from the date of initial issuance and are payable quarterly in arrears.
The Junior Debentures are subordinated in right of payment to all senior
indebtedness of the Company and the Junior Debentures are subject to certain
covenants, events of default and optional and mandatory redemption provisions,
all as described in the Junior Debenture indentures.
Pursuant to Preferred Securities Guarantee Agreements (collectively, the
"Guarantees"), between the Company and a preferred guarantee trustee, the
Company has agreed irrevocably to pay to the holders of the Trust Securities, to
the extent that the Trustee has funds available to make such payments, quarterly
distributions, redemption payments and liquidation payments on the Trust
Securities. Considered together, the undertakings contained in the Declarations,
Junior Debentures, Indentures and Guarantees constitute full and unconditional
guarantees by the Company of the Trusts' obligations under the Trust Securities.
13. SUBSIDIARY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
SUBSIDIARY TRUST
On March 11, 2002, MidAmerican Energy redeemed all $100.0 million of its 7.98%
MidAmerican-obligated preferred securities of subsidiary trust at 100% of the
principal amount plus accrued interest.
14. PREFERRED SECURITIES OF SUBSIDIARIES
During 2002, MidAmerican Energy redeemed all $26.7 million of its $7.80 Series
Preferred Shares.
The total outstanding cumulative preferred securities of MidAmerican Energy not
subject to mandatory redemption requirements may be redeemed at the option of
MidAmerican Energy at prices which, in the aggregate, total $32.6 million. The
aggregate total the holders of all preferred securities outstanding at December
31, 2002, are entitled to upon involuntary bankruptcy is $31.8 million plus
accrued dividends. Annual dividend requirements for all preferred securities
outstanding at December 31, 2002, total $1.3 million.
The total outstanding 8.061% cumulative preferred securities of CE Electric UK,
which are redeemable in the event of the revocation by the Secretary of State of
the Company's Public Electricity Supply License, was $56.0 million as of
December 31, 2002 and 2001.
-77-
15. CONVERTIBLE PREFERRED STOCK
In connection with the Kern River acquisition and the purchase of $275.0 million
of Williams' preferred stock, the Company issued 6.7 million shares of no par,
zero-coupon convertible preferred stock valued at $402.0 million. In connection
with the Teton Transaction, the Company issued 34.6 million shares of no par,
zero coupon convertible preferred stock valued at $1,211.4 million. Each share
of preferred stock is convertible at the option of the holder into one share of
the Company's common stock subject to certain adjustments as described in the
Company's Amended and Restated Articles of Incorporation.
16. STOCK OPTIONS
The Company had various stock option plans under which shares were reserved for
grant as incentive or non-qualified stock options, as determined by the Board of
Directors. The plans allowed options to be granted at 85% of their fair market
value of the common stock at the date of grant. Generally, options were issued
at 100% of fair market value of the common stock at the date of grant. Options
remaining subsequent to the Teton Transaction became exercisable over a period
of two to five years and expired if not exercised within ten years from the date
of grant or, in some instances, a lesser term.
As a result of the Teton Transaction, the majority of the options were cashed
out at $35.05 per share. The remaining options of 2,145,000 were reissued under
the new MEHC and an additional 703,329 options were issued. The old options are
fully vested and the additional options vest monthly over three years. The
options are exercisable until the end of the term on March 14, 2008 at exercise
prices ranging from $15.94 to $35.05 per share.
On March 6, 2002, the Company purchased stock options from Mr. David L. Sokol,
its Chairman and Chief Executive Officer. The options purchased had exercise
prices ranging from $18.50 to $29.01. The Company paid Mr. Sokol an aggregate
amount of $27.1 million, which is equal to the difference between the option
exercise prices and an agreed upon per share value.
17. ACCOUNTING FOR DERIVATIVES
MidAmerican Energy
- ------------------
Commodity Price Risk
Under the current regulatory framework, MidAmerican Energy is allowed to recover
in revenue the cost of gas sold from all of its regulated gas customers through
a purchased gas adjustment clause. Because the majority of MidAmerican Energy's
firm natural gas supply contracts contain pricing provisions based on a daily or
monthly market index, MidAmerican Energy's regulated gas customers, although
ensured of the availability of gas supplies, retain the risk associated with
market price volatility.
MidAmerican Energy uses natural gas futures, options and over-the-counter
agreements to mitigate a portion of the market risk retained by its regulated
gas customers through the purchased gas adjustment clause. These financial
derivative instruments are identified and recorded as hedge transactions. The
net amounts exchanged or accrued under swap agreements and the realized gains or
losses on futures and options contracts are included in cost of sales and
recovered in revenue from regulated gas customers.
MidAmerican Energy also derives revenue from nonregulated sales of natural gas.
Pricing provisions are individually negotiated with these customers and may
include fixed prices, prices based on a daily or monthly market index or prices
based on MidAmerican Energy's actual costs. MidAmerican Energy enters into
natural gas futures, options and swap agreements to offset the financial impact
of variations in natural gas commodity prices for physical delivery to
nonregulated customers. These financial derivative activities are also recorded
as hedge accounting transactions.
MidAmerican Energy is exposed to variations in the price of fuel for generation
and the price of purchased power in its Iowa jurisdiction, which comprises
approximately 89% of 2002 electric operating revenues. Fuel price risk is
mitigated through forward contracts. Under typical operating conditions,
MidAmerican Energy has sufficient generation to supply its regulated retail
electric needs. A loss of such generation at a time of high market prices could
subject MidAmerican Energy to losses on its energy sales. MidAmerican Energy
uses electricity forward contracts to hedge anticipated sales of excess
wholesale electric power.
-78-
Derivative instruments are used for two types of hedges. Hedges that offset the
variability in earnings and cash flows related to firm commitments are referred
to as fair value hedges. Gains and losses on fair value hedges are recognized in
income as either operating revenues or cost of sales, depending upon the nature
of the item being hedged. Purchase and sales commitments hedged by fair value
hedges are recorded at fair value, with changes in their fair values recognized
in income and substantially offsetting the impact of the hedges on earnings. For
2002, net pre-tax unrealized gains (losses), representing the ineffectiveness of
fair value hedges, were immaterial.
Hedges that offset the variability in earnings and cash flows related to
forecasted transactions are referred to as cash flow hedges. The effective
portion of unrealized gains and losses on cash flow hedges is recorded in other
comprehensive income, net of associated deferred income taxes. Any ineffective
portion of unrealized gains and losses on cash flow hedges is recognized in
income as operating revenues or a cost of sales, depending upon the nature of
the item being hedged. Only hedges that are highly effective in offsetting the
risk of variability in future cash flows are accounted for in this manner.
Forecasted transactions include purchases of gas for resale to regulated and
nonregulated customers, purchases of gas for storage, and purchases and sales of
wholesale electric energy. When the associated hedged forecasted transaction
occurs or if a hedging relationship is no longer appropriate, the unrealized
gains and losses are reversed from other comprehensive income and recognized in
net income. Realized gains on cash flow hedges are recognized in income as
either operating revenues or cost of sales, depending upon the nature of the
physical transaction being hedged.
For 2002, net pre-tax unrealized gains (losses) of $13,000 and $502,000,
representing the ineffectiveness of cash flow hedges, are reflected in operating
revenues and cost of sales, respectively, on the consolidated statements of
operations. During the twelve months beginning January 1, 2003, it is
anticipated that all of the after-tax, net unrealized gains on cash flow hedges
presently recorded as accumulated other comprehensive income will be realized
and recorded in earnings. MidAmerican Energy has hedged a portion of its
exposure to the variability of cash flows for forecasted transactions through
December 2003.
At December 31, 2002, MidAmerican Energy held derivative instruments used for
the following hedging purposes with the following fair values (in thousands):
Maturity Maturity in
Type in 2003 2004-06 Total
---- -------- ----------- ------
Regulated electric $1,018 $ 112 $1,130
Regulated gas .... 1,150 -- 1,150
Nonregulated gas . 2,027 (41) 1,986
------ ----- ------
Total ....... $4,195 $ 71 $4,266
====== ===== ======
A $5.00 per MWh increase in the price of electricity would decrease the fair
value of electric hedge instruments by $316,000. A $1.00 per MMBtu increase in
the price of natural gas would increase the fair value of gas hedge instruments
by $2.3 million.
Trading Risk
MidAmerican Energy uses natural gas and electricity derivative instruments and
forward contracts for proprietary trading purposes under strict guidelines
outlined by senior management. Derivative instruments held for trading purposes
are recorded at fair value and any unrealized gains or losses are reported in
earnings.
-79-
MidAmerican Energy uses value at risk, or VaR calculations to measure and
control its exposure to market risk sensitive instruments. VaR is an estimate of
the potential loss on a portfolio over a specified holding period, based on
normal market conditions and within a given statistical confidence interval.
MidAmerican Energy calculates VaR separately for its electric and gas
proprietary trading activities based on a variance-covariance method using
historical prices to estimate volatilities and correlations, a one-day holding
period and a 95% level of confidence. MidAmerican Energy initiated its
nonregulated proprietary electric trading activities in early 2002. Accordingly,
the following summary of MidAmerican Energy's trading VaR profile for 2001
includes only gas trading data.
VaR (in $millions)
2002 2001
---- ----
At December 31...................... $0.3 $0.2
High during year.................... 0.5 0.3
Low during year..................... 0.1 -
Average during year................. 0.2 0.1
The fair value of MidAmerican Energy's proprietary trading activities at
December 31, 2002 and the periods in which unrealized gains and losses are
expected to be realized are as follows (in thousands):
Maturity in Maturity in
Type 2003 2004-06 Total
---- ----------- ----------- -------
Exchange prices ....... $ 4,683 $ 71 $ 4,754
Prices actively quoted. (4,259) (159) (4,418)
Prices based on models. 207 (14) 193
------- ----- -------
Total ............ $ 631 $(102) $ 529
======= ===== =======
CE Electric UK
- --------------
Currency Exchange Rate Risk
CE Electric UK entered into certain currency rate swap agreements for the CE
Electric UK Company Senior Notes with two large multi-national financial
institutions. The swap agreements effectively convert the U.S. dollar fixed
interest rate to a fixed rate in Sterling. For the $125.0 million of 6.853%
Senior Notes, the agreements extend until maturity on December 30, 2004 and
convert the U.S. dollar interest rate to a fixed Sterling rate of 7.744%. For
the $237.0 million of 6.995% Senior Notes, the agreements extend until maturity
on December 30, 2007 and convert the U.S. dollar interest rate to a fixed
Sterling rate of 7.737%. The estimated fair value of these swap agreements at
December 31, 2002 is approximately $24.5 million based on quotes from the
counterparty to these instruments and represents the estimated amount that the
Company would expect to receive if these agreements were terminated.
Yorkshire entered into certain currency rate swap agreements for the Trust
Securities and the Yankee Bonds with five large multi-national financial
institutions. The swap agreements effectively convert the U.S. dollar fixed
interest rate to a fixed rate in Sterling. For the 8.08% Trust Securities, the
agreements extend until June 30, 2008 and convert the U.S. dollar interest rate
to a fixed Sterling rate ranging from 9.4758% to 9.715%. For the $300.0 million
of 6.496% Yankee Bonds, the agreements extend until February 25, 2008 and
convert the U.S. dollar interest rate to a fixed Sterling rate ranging from
7.3175% to 7.345%. The estimated fair value of these swap agreements at December
31, 2002 is approximately $(22.8) million based on quotes from the counterparty
to these instruments and represents the estimated amount that the Company would
expect to pay if these agreements were terminated.
A decrease of 10% in the December 31, 2002 rate of exchange of Sterling to
dollars would increase the amount paid to the Company if these swap agreements
were terminated by approximately $120.9 million.
-80-
Northern Natural Gas
- --------------------
Commodity Price Risk
As of December 31, 2002, Northern Natural Gas had $52.0 million of obligations
to deliver 12.2 Bcf of natural gas in 2003. The obligations are revalued based
on market prices for natural gas, with changes in value included in the
statement of operations. In 2002, Northern Natural Gas entered into natural gas
commodity price swaps and index basis swaps to effectively fix the deferred
obligation balance. These swaps have a net receivable balance of $3.4 million at
December 31, 2002. The swaps are revalued based on market prices for natural
gas, with changes in value included in the statement of operations. Therefore,
any further changes in the market value of the deferred obligations are expected
to be offset by a corresponding change in the opposite direction in the market
value of the swaps. However, at December 31, 2002, Northern Natural Gas had a
$10.4 million receivable position with a third party energy marketer relating to
these swaps. Since the date of entering into these swaps, there have been public
announcements that this third party's financial condition has deteriorated as a
result of, among other factors, reduced liquidity. This receivable would
increase by approximately $12.2 million if the price curve of natural gas were
to increase by $1.00 per MMBtu from levels at December 31, 2002. The Company has
not recorded an allowance on this receivable as of December 31, 2002, and is
monitoring the situation.
18. REGULATORY MATTERS
MidAmerican Energy
- ------------------
Under a settlement agreement approved by the IUB on December 21, 2001,
MidAmerican Energy's Iowa retail electric rates in effect on December 31, 2000,
are effectively frozen through December 31, 2005. In approving that settlement,
the IUB specifically allows the filing of electric rate design and/or cost of
service rate changes that are intended to keep overall company revenues
unchanged but could result in changes to individual tariffs. Under the 2001
settlement agreement, an amount equal to 50% of revenues associated with Iowa
retail electric returns on equity between 12% and 14%, and 83.33% of revenues
associated with Iowa retail electric returns on equity above 14%, in each year
is recorded as a regulatory liability to be used to offset a portion of the cost
to Iowa customers of future generating plant investments. An amount equal to the
regulatory liability is recorded as a regulatory charge in depreciation and
amortization expense when the liability is accrued. Interest expense is accrued
on the portion of the regulatory liability related to prior years. Beginning in
2002, the liability is being relieved as it is credited against allowance for
funds used during construction, or capitalized financing costs, associated with
generating plant additions. As of December 31, 2002, the related liability
reflected on the consolidated balance sheet totaled $102.9 million.
On March 20, 2003, MidAmerican Energy and the Iowa Office of Consumer Advocate
agreed upon a settlement proposal in which the rate freeze described above would
be extended through December 31, 2010. Under the settlement proposal, for
calendar years 2006 through 2010, an amount equal to 40% of revenues associated
with Iowa retail electric returns on equity between 11.75% and 13.0%; 50% of
revenues associated with Iowa retail electric returns on equity between 13.0%
and 14.0%; and 83.3% of revenues associated with Iowa retail electric returns on
equity greater than 14.0% will be applied as a reduction to offset some of the
capital costs on the Iowa portion of three generation projects. If Iowa retail
electric returns on equity fall below 10% in any 12-month period after January
1, 2006, MidAmerican Energy has the ability to file for a general increase in
rates under the proposed settlement. The proposed settlement requires enactment
of Iowa legislation and is subject to approval by the IUB. The IUB is expected
to rule on the proposal during the second half of 2003.
On March 15, 2002, MidAmerican Energy made a filing with the IUB requesting an
increase in rates for its Iowa retail natural gas customers. On June 12, 2002,
the IUB issued an order granting an interim rate increase of approximately $13.8
million annually, effective immediately and subject to refund with interest. On
November 8, 2002, the IUB approved the proposed settlement agreement previously
filed with it by MidAmerican Energy and the Iowa Office of Consumer Advocate.
The settlement agreement provides for an increase in rates of $17.7 million
annually for MidAmerican Energy's Iowa retail natural gas customers and
effectively freezes such rates through November 2004. MidAmerican Energy
implemented the new rates for usage beginning November 25, 2002.
CE Electric UK
- --------------
Most revenue of each Distribution License Holder ("DLH") is controlled by a
distribution price control formula. The current formula requires that regulated
distribution income per unit is increased or decreased each year by RPI-Xd where
the Retail Price Index ("RPI") reflects the average of the 12-month inflation
rates recorded for each month in the previous July to December period. The
distribution price control formula also reflects an adjustment factor ("Xd")
which was established
-81-
by the regulatory body, the Office of Gas and Electricity Markets ("Ofgem"), at
the last price control review (and continues to be set) at 3%. The formula also
takes account of the changes in system electrical losses, the number of
customers connected and the voltage at which customers receive the units of
electricity distributed. This formula determines the maximum average price per
unit of electricity distributed (in pence per kWh) which a DLH is entitled to
charge. The distribution price control formula permits DLHs to receive
additional revenue due to increased distribution of units and a predetermined
increase in customer numbers. The price control does not seek to constrain the
profits of a DLH from year to year. It is a control on revenue that operates
independently of most of the DLH's costs. During the lifetime of the price
control, cost savings or additional costs have a direct impact on profit.
19. PENSION COMMITMENTS
Domestic Operations
- -------------------
The Company has primarily noncontributory defined benefit pension plans covering
substantially all domestic employees. Benefit obligations under the plans are
based on participants' compensation, years of service and age at retirement.
Funding is based upon the actuarially determined costs of the plans and the
requirements of the Internal Revenue Code and the Employee Retirement Income
Security Act.
The Company currently provides certain postretirement health care and life
insurance benefits for retired employees. Under the plans, substantially all of
the Company's employees may become eligible for these benefits if they reach
retirement age while working for the Company. However, the Company retains the
right to change these benefits anytime at its discretion.
The Company also maintains noncontributory, nonqualified supplemental executive
retirement plans for active and retired participants.
-82-
Net periodic pension, supplemental retirement and postretirement benefit costs
for domestic employees included the following components for the Company:
MEHC
YEAR ENDED (PREDECESSOR)
DECEMBER 31, MARCH 14, 2000 JANUARY 1, 2000
---------------------- THROUGH THROUGH
2002 2001 DECEMBER 31, 2000 MARCH 13, 2000
-------- -------- ----------------- ---------------
Pension Cost:
Service cost ............................ $ 20,235 $ 18,114 $ 13,014 $ 3,242
Interest cost ........................... 34,177 33,027 28,329 7,058
Expected return on plan assets .......... (38,213) (36,326) (38,532) (9,600)
Amortization of net transition obligation (2,591) (2,591) (2,074) (517)
Amortization of prior service cost ...... 2,729 2,729 2,310 575
Amortization of prior year gain ......... (2,482) (3,894) (3,297) (822)
Regulatory expense ...................... 6,639 -- -- --
-------- -------- -------- -------
Net periodic pension cost (benefit) ... $ 20,494 $ 11,059 $ (250) $ (64)
======== ======== ======== =======
MEHC
YEAR ENDED (PREDECESSOR)
DECEMBER 31, MARCH 14, 2000 JANUARY 1, 2000
---------------------- THROUGH THROUGH
2002 2001 DECEMBER 31, 2000 MARCH 13, 2000
-------- -------- ----------------- ---------------
Postretirement Cost:
Service cost ............................ $ 6,028 $ 4,357 $ 2,089 $ 520
Interest cost ........................... 13,928 10,418 6,688 1,666
Expected return on plan assets .......... (4,880) (4,032) (3,947) (984)
Amortization of net transition obligation 4,110 4,110 3,290 820
Amortization of prior service cost ...... 425 425 340 85
Amortization of prior year (gain) loss .. 2,385 332 (699) (174)
-------- -------- -------- -------
Net periodic pension cost ............. $ 21,996 $ 15,610 $ 7,761 $ 1,933
======== ======== ======== =======
The pension plan assets are in external trusts and are comprised of corporate
equity securities, United States government debt, corporate bonds and insurance
contracts. The postretirement benefit plans assets are in external trusts and
are comprised primarily of corporate equity securities, corporate bonds, money
market investment accounts and municipal bonds.
Although the supplemental executive retirement plans had no plan assets as of
December 31, 2002, MidAmerican Energy has Rabbi trusts which hold
corporate-owned life insurance and other investments to provide funding for the
future cash requirements. Because these plans are nonqualified, the fair value
of these assets is not included in the following table. The fair value of the
Rabbi trust investments was $52.8 million and $50.4 million at December 31, 2002
and 2001, respectively.
-83-
The following table presents a reconciliation of the beginning and ending
balances of the benefit obligation, fair value of plan assets and the funded
status of the Company's plans to the net amounts recognized in the consolidated
balance sheet as of December 31 (dollars in thousands):
PENSION POSTRETIREMENT
BENEFITS BENEFITS
---------------------- ----------------------
2002 2001 2002 2001
--------- --------- --------- ---------
Reconciliation of benefit obligation:
Benefit obligation at beginning of year ................. $ 518,208 $ 472,349 $ 194,917 $ 131,822
Service cost ............................................ 20,235 18,114 6,028 4,357
Interest cost ........................................... 34,177 33,027 13,928 10,418
Participant contributions ............................... -- -- 4,505 3,059
Plan amendments ......................................... -- 652 -- --
Actuarial (gain) loss ................................... 45,461 17,333 31,743 57,101
Acquisition ............................................. 520 -- 55,305 --
Benefits paid ........................................... (25,422) (23,267) (14,985) (11,840)
--------- --------- --------- ---------
Benefit obligation at end of year ..................... 593,179 518,208 291,441 194,917
--------- --------- --------- ---------
Reconciliation of the fair value of plan assets:
Fair value of plan assets at beginning of year .......... 515,890 555,208 81,129 75,090
Employer contributions .................................. 4,681 4,576 24,034 16,022
Participant contributions ............................... -- -- 4,505 3,059
Actual return on plan assets ............................ (27,376) (20,627) (4,528) (1,202)
Acquisition ............................................. -- -- 32,500 --
Benefits paid ........................................... (25,422) (23,267) (14,985) (11,840)
--------- --------- --------- ---------
Fair value of plan assets at end of year .............. 467,773 515,890 122,655 81,129
--------- --------- --------- ---------
Funded status ........................................... (125,406) (2,318) (168,786) (113,788)
Unrecognized net (gain) loss ............................ 61,289 (52,244) 102,095 63,328
Unrecognized prior service cost ......................... 20,156 22,885 3,838 4,264
Unrecognized net transition obligation (asset) .......... (3,383) (5,974) 41,102 45,212
--------- --------- --------- ---------
Net amount recognized in the consolidated balance sheet $ (47,344) $ (37,651) $ (21,751) $ (984)
========= ========= ========= =========
Amounts recognized in the consolidated balance sheet
consist of:
Prepaid benefit cost .................................... $ 11,305 $ 15,381 $ 1,494 $ 1,493
Accrued benefit liability ............................... (99,392) (88,210) (23,245) (2,477)
Intangible asset ........................................ 20,082 22,796 -- --
Accumulated other comprehensive income .................. 20,661 12,382 -- --
--------- --------- --------- ---------
Net amount recognized ................................... $ (47,344) $ (37,651) $ (21,751) $ (984)
========= ========= ========= =========
-84-
Pension and Postretirement Assumptions are as follows for the years ended
December 31:
2002 2001 2000
---- ---- ----
Assumptions used were:
Discount rate ................................. 5.75% 6.50% 7.00%
Rate of increase in compensation levels ....... 5.00% 5.00% 5.00%
Weighted average expected long-term rate
of return on assets ......................... 7.00% 7.00% 9.00%
For purposes of calculating the postretirement benefit obligation, it is assumed
health care costs for all covered individuals will increase by 9.75% in 2003 and
that the rate of increase thereafter will decrease to an ultimate rate of 5.25%
by the year 2007.
If the assumed health care trend rates used to measure the expected cost of
benefits covered by the plans were increased by 1.0%, the total service and
interest cost for 2002 would increase by $4.1 million, and the postretirement
benefit obligation at December 31, 2002, would increase by $47.5 million. If the
assumed health care trend rates were to decrease by 1.0%, the total service and
interest cost for 2002 would decrease by $3.1 million and the postretirement
benefit obligation at December 31, 2002, would decrease by $37.0 million.
United Kingdom Operations
- -------------------------
CE Electric UK participates in the Electricity Supply Pension Scheme, which
provides pension and other related defined benefits, based on final pensionable
pay, to substantially all employees throughout the Electricity Supply Industry
in the United Kingdom.
The actuarial computation for December 31, 2002, 2001 and 2000 assumed interest
rates of 5.75%, 5.75% and 6.0% respectively, an expected return on plan assets
of 7.0%, 7.0% and 6.5%, respectively, and annual compensation increases of 2.5%,
2.5% and 3.0%, respectively, over the remaining service lives of employees
covered under the plan. Amounts funded to the pension are primarily invested in
equity and fixed income securities.
Net periodic pension cost (benefit) for CE Electric UK's plan for 2002, 2001 and
2000 included the following components (in thousands):
MEHC
YEAR ENDED (PREDECESSOR)
DECEMBER 31, MARCH 14, 2000 JANUARY 1, 2000
---------------------- THROUGH THROUGH
2002 2001 DECEMBER 31, 2000 MARCH 13, 2000
-------- -------- ----------------- ---------------
Service cost - benefits earned during the period $ 8,718 $ 7,781 $ 6,933 $ 1,727
Interest cost on projected benefit obligation .. 56,817 51,440 40,640 10,125
Expected return on plan assets ................. (85,927) (78,354) (50,800) (12,657)
Amortization of prior service cost ............. 1,202 -- -- --
Curtailment loss ............................... 6,463 7,061 5,260 1,310
-------- -------- -------- --------
Net periodic pension (benefit) cost ............ $(12,727) $(12,072) $ 2,033 $ 505
======== ======== ======== ========
As a result of the distribution price reviews in 1999, CE Electric UK
implemented a review of staffing requirements primarily in its distribution
business. Following discussions with the trade unions, CE Electric UK put in
place a workforce reduction program. The pension curtailment related to this
workforce reduction program was $6.9 million, $7.1 million and $6.6 million in
2002, 2001 and 2000, respectively.
-85-
The following table details the funded status and the amount recognized in the
Company's consolidated balance sheets for CE Electric UK's plan as of December
31, 2002 and 2001 (in thousands):
2002 2001
----------- -----------
Change in benefit obligation:
Benefit obligation at beginning of year ........................ $ 974,079 $ 951,553
Service cost ................................................... 8,718 7,781
Interest cost .................................................. 56,817 51,440
Participant contributions ...................................... 3,006 5,187
Benefits paid .................................................. (57,719) (48,991)
FAS 88 curtailment ............................................. 5,712 7,060
Northern Supply/Yorkshire swap net effect ...................... -- 43,803
Prior service cost ............................................. 17,286 --
Experience gain and change of assumptions ...................... (11,574) (19,596)
Foreign currency exchange rate changes ......................... 106,405 (24,158)
----------- -----------
Benefit obligation at end of the year .......................... 1,102,730 974,079
----------- -----------
Change in plan assets:
Fair value of plan assets at beginning of the year ............. 1,070,657 1,166,111
Actual return on plan assets ................................... (144,298) (68,010)
Net asset transfer resulting from Northern Supply/Yorkshire
Swap ....................................................... -- 46,541
Employer contributions ......................................... 3,607 576
Participant contributions ...................................... 3,006 5,187
Benefits paid .................................................. (57,719) (48,991)
Foreign currency exchange rate changes ......................... 101,174 (30,757)
----------- -----------
Fair value of plan assets at end of the year ................... 976,427 1,070,657
----------- -----------
Funded status .................................................. (126,303) 96,578
Unrecognized net loss .......................................... 465,211 196,649
----------- -----------
Net amount recognized in the consolidated balance sheet ........ $ 338,908 $ 293,227
=========== ===========
Amounts recognized in the consolidated balance sheet consist of:
Prepaid benefit cost ........................................... $ 338,908 $ 293,227
Accrued benefit liability ...................................... (457,317) --
Intangible asset ............................................... 16,433 --
Accumulated other comprehensive income ......................... 440,884 --
----------- -----------
Net amount recognized .......................................... $ 338,908 $ 293,227
=========== ===========
-86-
20. COMMITMENTS AND CONTINGENCIES
Manufactured Gas Plants
- -----------------------
The United States Environmental Protection Agency ("EPA"), and the state
environmental agencies have determined that contaminated wastes remaining at
decommissioned manufactured gas plant facilities may pose a threat to the public
health or the environment if such contaminants are in sufficient quantities and
at such concentrations as to warrant remedial action.
MidAmerican Energy has evaluated or is evaluating 27 properties that were, at
one time, sites of gas manufacturing plants in which it may be a potentially
responsible party. The purpose of these evaluations is to determine whether
waste materials are present, whether the materials constitute an environmental
or health risk, and whether MidAmerican Energy has any responsibility for
remedial action. As of December 31, 2002, MidAmerican Energy has recorded a $17
million liability for these sites and a corresponding regulatory asset for
future recovery through the regulatory process.
Although the timing of potential incurred costs and recovery of costs in rates
may affect the results of operations in individual periods, management believes
that the outcome of these issues will not have a material adverse effect on
MidAmerican Energy's financial position or results of operations.
Air Quality
- -----------
In July 1997, the EPA adopted revisions to the National Ambient Air Quality
Standards for ozone and a new standard for fine particulate matter. In February
2001, the United States Supreme Court upheld the constitutionality of the
standards, though remanding the issue of implementation of the ozone standard to
the EPA. The impact of the new standards on MidAmerican Energy is currently
unknown. These standards could be superceded, in whole or in part, by a variety
of multi-pollutant emission reduction initiatives.
In 2001, the state of Iowa passed legislation that, in part, requires
rate-regulated utilities to develop a multi-year plan and budget for managing
regulated emissions from their generating facilities in a cost-effective manner.
MidAmerican Energy's proposed plan and associated budget (the "Plan") was filed
with the IUB on April 1, 2002, in accordance with state law. MidAmerican Energy
expects the IUB to rule on the prudence of the Plan in 2003. MidAmerican Energy
is required to file Plan updates at least every two years.
The Plan provides MidAmerican Energy's projected air emission reductions
considering the current proposals that are being debated at the federal level
and describes a coordinated long-range plan to achieve these air emission
reductions. The Plan also provides specific actions to be taken at each
coal-fired generating facility and the related costs and timing for each action.
The Plan outlines $732.0 million in environmental investments to existing
coal-fired generating units, some of which are jointly owned, over a nine-year
period from 2002 through 2010. MidAmerican Energy's share of these investments
is $546.6 million, $67.9 million of which was projected to be incurred in the
years 2002 through 2005, when MidAmerican Energy's Iowa retail electric rates
are effectively frozen. The Plan also identifies expenses that will be incurred
at the generating facilities to operate and maintain the environmental equipment
installed as a result of the Plan.
Following the expiration of MidAmerican Energy's 2001 settlement agreement on
December 31, 2005, the Plan proposes the use of an adjustment mechanism for
recovery of Plan costs, similar to the tracking mechanisms for cost recovery of
renewable energy and energy efficiency expenditures that are presently part of
MidAmerican Energy's regulated electric rates.
Under the New Source Review ("NSR"), provisions of the Clean Air Act ("CAA"), a
utility is required to obtain a permit from the EPA prior to (1) beginning
construction of a new major stationary source of a NSR-regulated pollutant or
(2) making a physical or operational change (a "major modification") to an
existing facility that potentially increases emissions, unless the changes are
exempt under the regulations. 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 CAA. 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. Routine maintenance, repair and replacement are not subject to the NSR
provisions; however, these types of activities have historically been subject to
changing interpretations under the NSR program. The EPA recently proposed a
change to the NSR provisions relating to routine maintenance, repair and
-87-
replacement. Violation of NSR regulations potentially subjects a utility to
fines and/or other sanctions. The impact on MidAmerican Energy of any final
rules is not currently known.
In recent years, the EPA has requested from several utilities information and
support regarding their capital projects for various generating plants. The
requests were issued as part of an industry-wide investigation to assess
compliance with the NSR and the New Source Performance Standards of the CAA. In
December 2002, MidAmerican Energy received a request from the EPA to provide
documentation related to its capital projects from January 1, 1980, to the
present for its Neal, Council Bluffs, Louisa and Riverside Energy Centers.
MidAmerican Energy has responded to this request and at this time cannot predict
the outcome of request.
Decommissioning Costs
- ---------------------
Expected decommissioning costs for Quad Cities Station have been developed based
on a site-specific decommissioning study that includes decontamination,
dismantling, site restoration, dry fuel storage cost and an assumed shutdown
date. Quad Cities Station decommissioning costs are included in as base rates in
Iowa tariffs.
MidAmerican Energy's share of expected decommissioning costs for Quad Cities
Station, in 2002 dollars, is $266 million. MidAmerican Energy has established
external trusts for the investment of funds for decommissioning the Quad Cities
Station. The total accrued balance as of December 31, 2002, was $159.8 million
and is included in other liabilities. A like amount is reflected in properties,
plants and equipment and represents the fair value of the assets held in the
trusts.
MidAmerican Energy's depreciation expense included costs for Quad Cities Station
nuclear decommissioning of $8.3 million for each of the years 2002, 2001 and
2000. The provision charged to depreciation expense is equal to the funding that
is being collected in Iowa rates. The decommissioning funding component of
MidAmerican Energy's Iowa tariff assumes decommissioning costs, related to the
Quad Cities Station, will escalate at an annual rate of 5.0% and the assumed
annual return on funds in the trust is 6.9%. Income (loss), net of investment
fees, on the assets in the trust fund increase/(decrease) by a comparable amount
MidAmerican Energy's decommissioning liability. Actual amounts were $(6.9)
million, $(3.1) million and $3.2 million for 2002, 2001 and 2000, respectively.
Nuclear Insurance
- -----------------
MidAmerican Energy maintains financial protection against catastrophic loss
associated with its interest in Quad Cities Station through a combination of
insurance purchased by Exelon Generation Company, LLC ("Exelon Generation"), the
operator and joint owner of Quad Cities Station, insurance purchased directly by
MidAmerican Energy, and the mandatory industry-wide loss funding mechanism
afforded under the Price-Anderson Amendments Act of 1988. The general types of
coverage are: nuclear liability, property coverage and nuclear worker liability.
Exelon Generation purchases nuclear liability insurance for Quad Cities Station
in the maximum available amount of $200 million. In accordance with the
Price-Anderson Amendments Act of 1988, excess liability protection above that
amount is provided by a mandatory industry-wide Secondary Financial Protection
program under which the licensees of nuclear generating facilities could be
assessed for liability incurred due to a serious nuclear incident at any
commercial nuclear reactor in the United States. Currently, MidAmerican Energy's
aggregate maximum potential share of an assessment for Quad Cities Station is
approximately $44 million per incident, payable in installments not to exceed $5
million annually.
The property insurance covers for property damage, stabilization and
decontamination of the facility, disposal of the decontaminated material and
premature decommissioning arising out of a covered loss. For Quad Cities
Station, Exelon Generation purchased primary and excess property insurance
protection for the combined interests in Quad Cities Station, with coverage
limits totaling $2.1 billion. MidAmerican Energy also directly purchased extra
expense/business interruption coverage for its share of replacement power and/or
other extra expenses in the event of a covered accidental outage at Quad Cities
Station. The property and related coverages purchased directly by MidAmerican
Energy and by Exelon Generation, which includes the interests of MidAmerican
Energy, are underwritten by an industry mutual insurance company and contain
provisions for retrospective premium assessments should two or more full
policy-limit losses occur in one policy year. Currently, the maximum
retrospective amounts that could be assessed against MidAmerican Energy from
industry mutual policies for its obligations associated with Quad Cities Station
total $6.3 million.
The master nuclear worker liability coverage, which is purchased by Exelon
Generation for Quad Cities Station, is an industry-wide guaranteed-cost policy
with an aggregate limit of $200 million for the nuclear industry as a whole,
which is in effect to cover tort claims in nuclear-related industries.
-88-
Fuel, Energy and Operating Lease Commitments
- --------------------------------------------
MidAmerican Energy has supply and related transportation contracts for its
fossil fueled generating stations. The contracts, with expiration dates ranging
from 2003 to 2007, require minimum payments of $76.4 million, $61.2 million,
$43.6 million, $2.6 million and $2.6 million for the years 2003 through 2007,
respectively. MidAmerican Energy expects to supplement these coal contracts with
additional contracts and spot market purchases to fulfill its future fossil fuel
needs.
MidAmerican Energy also has contracts with non-affiliated companies to purchase
electric capacity. The contracts, with expiration dates ranging from 2003 to
2028, require minimum payments of $40.2 million, $37.8 million, $2.9 million,
$2.2 million and $2.2 million for the years 2003 through 2007, respectively, and
$45.6 million for the total of the years thereafter.
MidAmerican Energy has various natural gas supply and transportation contracts
for its gas operations. The minimum commitments under these contracts are $51.9
million, $46.8 million, $37.2 million, $13.1 million and $10.2 million for the
years 2003 through 2007, respectively, and $16.6 million for the total of the
years thereafter.
HomeServices is the lessee on operating leases primarily for office space for
its various brokerage offices. The minimum payments under these leases are $36.0
million, $30.1 million, $25.7 million, $22.4 million and $17.9 million for the
years 2003 through 2007, respectively, and $40.7 million for the total of the
years thereafter.
MidAmerican Energy, Kern River, Northern Natural Gas and CE Electric UK have
various non-cancellable operating leases primarily for office space and rail
cars. The minimum payments under these leases are $24.8 million, $16.9 million,
$12.7 million, $10.6 million and $9.4 million for the years 2003 through 2007,
respectively, and $46.0 million for the total of the years thereafter.
MidAmerican Energy is the lessee on operating leases for coal railcars that
contain guarantees of the residual value of such equipment throughout the term
of the leases. Events triggering the residual guarantees include termination of
the lease, loss of the equipment or purchase of the equipment. Lease terms are
for five years with provisions for extensions. At December 31, 2002, the maximum
amount of such guarantees specified in these leases totals $31.5 million.
Pipeline Litigation
- -------------------
In 1998, the United States Department of Justice informed the then current
owners of Kern River and Northern Natural Gas that Jack Grynberg, an individual,
had filed claims in the United States District Court for the District of
Colorado under the False Claims Act against such entities and certain of their
subsidiaries including Kern River and Northern Natural Gas. Mr. Grynberg has
also filed claims against numerous other energy companies and alleges that the
defendants violated the False Claims Act in connection with the measurement and
purchase of hydrocarbons. The relief sought is an unspecified amount of
royalties allegedly not paid to the federal government, treble damages, civil
penalties, attorneys' fees and costs. On April 9, 1999, the United States
Department of Justice announced that it declined to intervene in any of the
Grynberg qui tam cases, including the actions filed against Kern River and
Northern Natural Gas in the United States District Court for the District of
Colorado. On October 21, 1999, the Panel on Multi-District Litigation
transferred the Grynberg qui tam cases, including the ones filed against Kern
River and Northern Natural Gas, to the United States District Court for the
District of Wyoming for pre-trial purposes. Motions to dismiss the complaint,
filed by various defendants including Northern Natural Gas and Williams, which
was the former owner of Kern River, were denied on May 18, 2001. On October 9,
2002, the United States District Court for the District of Wyoming dismissed
Grynberg's Royalty Valuation Claims. Grynberg has appealed this dismissal to the
United States Court of Appeals for the Tenth Circuit. In connection with the
purchase of Kern River from Williams in March 2002, Williams agreed to indemnify
the Company against any liability for this claim; however, no assurance can be
given as to the ability of Williams to perform on this indemnity should it
become necessary. No such indemnification was obtained in connection with the
purchase of Northern Natural Gas in August 2002. The Company believes that the
Grynberg cases filed against Kern River and Northern Natural Gas are without
merit and Williams, on behalf of Kern River pursuant to its indemnification, and
Northern Natural Gas, intend to defend these actions vigorously.
On June 8, 2001, a number of interstate pipeline companies, including Kern River
and Northern Natural Gas, were named as defendants in a nationwide class action
lawsuit which had been pending in the 26th Judicial District, District Court,
-89-
Stevens County Kansas, Civil Department against other defendants, generally
pipeline and gathering companies, since May 20, 1999. The plaintiffs allege that
the defendants have engaged in mismeasurement techniques that distort the
heating content of natural gas, resulting in an alleged underpayment of
royalties to the class of producer plaintiffs. In November 2001, Kern River and
Northern Natural Gas, along with the coordinating defendants, filed a motion to
dismiss under Rules 9B and 12B of the Kansas Rules of Civil Procedure. In
January 2002, Kern River and most of the coordinating defendants filed a motion
to dismiss for lack of personal jurisdiction. The court has yet to rule on these
motions. The plaintiffs filed for certification of the plaintiff class on
September 16, 2002. On January 13, 2003, oral arguments were heard on
coordinating defendants' opposition to class certification. Williams has agreed
to indemnify the Company against any liability associated with Kern River for
this claim; however, no assurance can be given as to the ability of Williams to
perform on this indemnity should it become necessary. Williams, on behalf of
Kern River and other entities, anticipates joining with Northern Natural Gas and
other defendants in contesting certification of the plaintiff class. Kern River
and Northern Natural Gas believe that this claim is without merit and that Kern
River's and Northern Natural Gas' gas measurement techniques have been in
accordance with industry standards and its tariff.
Kern River's 2003 Expansion Project
- -----------------------------------
The 2003 Expansion Project is a new parallel 717-mile loop pipeline that will
begin in Lincoln County, Wyoming and terminate in Kern County, California. The
2003 Expansion Project began construction on August 6, 2002 and is expected to
be completed and operational by May 1, 2003 at a total cost of approximately
$1.2 billion. The 2003 Expansion Project is being financed with approximately
70% debt and 30% equity, consistent with Kern River's original capital
structure, the application for the FERC approval described above and the
limitations contained in the indenture for Kern River's existing secured senior
notes.
Construction is being initially funded with the proceeds of an $875.0 million
facility entered into by Kern River on June 21, 2002, for approximately 70% of
the projected capitalized costs of the 2003 Expansion Project. The remaining
approximately 30% of the capitalized costs of the 2003 Expansion Project is
being funded with equity from the Company. The credit facility is structured as
a two-year construction facility followed by a term loan with a final maturity
15 years after completion of the 2003 Expansion Project. However, Kern River
presently intends to refinance the construction financing facility through a
bond offering or other capital markets transaction following completion of the
2003 Expansion Project. Prior to completion of the 2003 Expansion Project, the
holders of the construction financing facility will have limited recourse to
Kern River and its assets and cash flow, and will have recourse to the Company's
completion guarantee described below. Following completion of the 2003 Expansion
Project, until such time as the Kern River construction financing facility is
refinanced, the lenders under the construction financing facility will share
equally and ratably with the existing holders of Kern River's senior Notes in
all of the collateral pledged to such Senior Note holders.
Pursuant to the Company's completion guarantee, it has guaranteed that
"completion" of the 2003 Expansion Project will occur on or prior to the
earliest of any abandonment by Kern River of the project, the occurrence of
certain other acceleration events and June 30, 2004. The potential acceleration
events include any downgrading of the Company's public debt rating to below
investment grade by either S&P or Moody's unless a satisfactory substitute
guarantor assumes the Company's obligations under the completion guarantee
within 60 days after any such downgrade; Berkshire Hathaway ceasing to own at
least a majority of the outstanding capital stock of the Company; and certain
other customary events of default by the Company. In the completion guarantee,
the Company has also agreed to cause capital contributions to be made to Kern
River in a minimum aggregate amount of at least $375 million by June 30, 2004 or
upon any earlier event of abandonment of the project. For purposes of the
Company's completion guarantee, the term "completion" is defined in the Kern
River construction financing agreement to mean satisfaction of a number of
conditions, the most significant of which include the requirements that the 2003
Expansion Project be substantially complete and operable and able to permit Kern
River to perform its obligations under all of the long-term firm gas
transportation service agreements entered into in connection with the 2003
Expansion Project; that the shippers under such agreements shall have begun to
incur the obligation to pay reservation fees thereunder; and that the FERC shall
have authorized Kern River to begin collecting rates under its tariff and its
shipper agreements; provided that the 2003 Expansion Project shall still be
deemed to have been completed if it is less than substantially complete but it
demonstrates at least 80% design capacity and Kern River's debt service coverage
ratios as defined in its Senior Notes indenture are not less than 1:55 to 1:0.
There are a number of other conditions to completion, including requirements
that all conditions to completion of the expansion contained in Kern River's
Senior Notes indenture be satisfied and all of Kern River's obligations under
its construction financing agreement then share pari passu in all collateral
available to Kern River's senior secured noteholders. The Company's completion
guarantee shall terminate upon the earlier of completion of the 2003 Expansion
Project or repayment in full of all obligations under the Kern River credit
facility.
-90-
Philippines
- -----------
Casecnan Construction Arbitration
On February 12, 2001, the contractor filed a Request for Arbitration with the
International Chamber of Commerce seeking schedule relief of up to 153 days
through August 31, 2001 resulting from various alleged force majeure events. In
its March 20, 2001 Supplement to Request for Arbitration, the contractor
requested compensation for alleged additional costs of approximately $4 million
it incurred from the claimed force majeure events to the extent it is unable to
recover from its insurer. On April 20, 2001, the contractor filed a further
supplement seeking an additional compensation for damages of approximately $62
million for the alleged force majeure event (and geologic conditions) related to
the collapse of the surge shaft. The contractor also has alleged that the
circumstances in which CE Casecnan assumed control of the Casecnan Project and
placed it into commercial operation on December 11, 2001 amounted to a
repudiation of the construction contract and has filed a claim for unspecified
quantum meruit damages, and has further alleged that the delay liquidated
damages clause which provides for payments of $125,000 per day for each day of
delay in completion of the Project for which the contractor is responsible is
unenforceable. The arbitration is being conducted applying New York law and in
accordance with the rules of the International Chamber of Commerce.
Hearings have been held in connection with this arbitration in July 2001,
September 2001, January 2002, March 2002, November 2002 and January 2003. As
part of those hearings, on June 25, 2001, the arbitration tribunal temporarily
enjoined CE Casecnan from making calls on the demand guaranty posted by Banca di
Roma in support of the contractor's obligations to CE Casecnan for delay
liquidated damages. As a result of the continuing nature of that injunction, on
April 26, 2002, CE Casecnan and the contractor mutually agreed that no demands
would be made on the Banca di Roma demand guaranty except pursuant to an
arbitration award. As of December 31, 2002, however, CE Casecnan has received
approximately $6.0 million of liquidated damages from demands made on the demand
guarantees posted by a separate financial institution on behalf of the
contractor. On November 7, 2002, the International Chamber of Commerce issued
the arbitration tribunal's partial award with respect to the contractor's force
majeure and geologic conditions claims. The arbitration panel awarded the
contractor 18 days of schedule relief in the aggregate for all of the force
majeure events and awarded the contractor $3.8 million with respect to the cost
of the collapsed surge shaft. The $3.8 million is shown as part of the accounts
payable and accrued expenses balance at the end of December 31, 2002. All of the
contractor's other claims with respect to force majeure and geologic conditions
were denied.
Further hearings on the contractor's repudiation and quantum meruit claims, the
alleged unenforceability of the delay liquidated damages clause and certain
other matters had been scheduled for March 24 through March 28, 2003, but were
postponed as a result of the commencement of military action in Iraq. The
arbitral tribunal has requested the parties to indicate the earliest possible
date on which they are available and will then reschedule the hearings.
If the contractor were to prevail on its claim that the delay liquidated damages
clause is unenforceable, CE Casecnan would not be entitled to collect such delay
damages for the period from March 31, 2001 through December 11, 2001. If the
contractor were to prevail in its repudiation claim and prove quantum meruit
damages in excess of amounts already paid to the contractor, CE Casecnan could
be liable to make additional payments to the contractor. CE Casecnan believes
all such allegations and claims are without merit and is vigorously contesting
the contractor's claims.
Casecnan NIA Arbitration
Under the terms of the Project Agreement, NIA has the option of timely
reimbursing CE Casecnan directly for certain taxes CE Casecnan has paid. If NIA
does not so reimburse CE Casecnan, the taxes paid by CE Casecnan result in an
increase in the Water Delivery Fee. The payment of certain other taxes by CE
Casecnan results automatically in an increase in the Water Delivery Fee. As of
December 31, 2002, CE Casecnan has paid approximately $56.7 million in taxes
which as a result of the foregoing provisions has resulted in an increase in the
Water Delivery Fee. NIA has failed to pay the portion of the Water Delivery Fee
each month which relates to the payment of these taxes by CE Casecnan. As a
result of this non-payment, on August 19, 2002, CE Casecnan filed a Request for
Arbitration against NIA, seeking payment of such portion of the Water Delivery
Fee and enforcement of the relevant provision of the Project Agreement going
forward. The arbitration will be conducted in accordance with the rules of the
International Chamber of Commerce. NIA is expected to file its answer late in
the first quarter or early in the second quarter, 2003. The three member
arbitration panel has been confirmed by the International Chamber of Commerce
and an initial organizational hearing is scheduled for the second quarter, 2003.
-91-
Casecnan Stockholder Litigation
Pursuant to the share ownership adjustment mechanism in the CE Casecnan
stockholder agreement, which is based upon pro forma financial projections of
the Casecnan Project prepared following commencement of commercial operations,
in February 2002, MidAmerican, through its indirect wholly owned subsidiary CE
Casecnan Ltd., advised the minority stockholder LaPrairie Group Contractors
(International) Ltd., ("LPG"), that MidAmerican'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, inter alia, CE
Casecnan Ltd. and MidAmerican. In the complaint, LPG seeks compensatory and
punitive damages for alleged breaches of the stockholder agreement and alleged
breaches of fiduciary duties allegedly owed by CE Casecnan Ltd. and MidAmerican
to LPG. The complaint also seeks injunctive relief against all defendants and a
declaratory judgment that LPG is entitled to maintain its 15% interest in CE
Casecnan. The impact, if any, of this litigation on the Company cannot be
determined at this time.
In February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. ("San
Lorenzo"), an original shareholder substantially all of whose shares in CE
Casecnan a subsidiary of the Company purchased in 1998, threatened to initiate
legal action in the Philippines in connection with certain aspects of its option
to repurchase such shares on or prior to commercial operation of the Project. CE
Casecnan 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, will
vigorously defend any such action.
-92-
21. SEGMENT INFORMATION:
With its 2002 acquisitions of Kern River and Northern Natural Gas, the Company
has identified seven reportable operating segments principally based on
management structure: MidAmerican Energy, Kern River, Northern Natural Gas, CE
Electric UK, CalEnergy Generation-Domestic, CalEnergy Generation-Foreign, and
HomeServices. Information related to the Company's reportable operating segments
is shown below (in thousands).
MEHC
(PREDECESSOR)
YEAR ENDED DECEMBER 31, MARCH 14, 2000 JANUARY 1, 2000
---------------------------- THROUGH THROUGH
2002 2001 DECEMBER 31, 2000 MARCH 13, 2000
----------- ----------- ----------------- --------------
OPERATING REVENUE:
MidAmerican Energy .................. $ 2,240,879 $ 2,388,650 $ 1,860,499 $ 455,844
Kern River .......................... 127,254 -- -- --
Northern Natural Gas ................ 176,880 -- -- --
CE Electric UK ...................... 795,366 1,443,997 1,499,768 498,142
CalEnergy Generation-Domestic ....... 38,546 37,299 2,757 438
CalEnergy Generation-Foreign ........ 326,316 203,482 146,798 40,124
HomeServices ........................ 1,138,332 641,934 408,492 60,603
----------- ----------- ----------- ----------
Segment operating revenue ........... 4,843,573 4,715,362 3,918,314 1,055,151
Corporate/other ..................... (49,563) (18,581) (214) 1,214
----------- ----------- ----------- ----------
Total operating revenue ............. $ 4,794,010 $ 4,696,781 $ 3,918,100 $1,056,365
=========== =========== =========== ==========
DEPRECIATION AND AMORTIZATION:
MidAmerican Energy .................. $ 269,412 $ 286,590 $ 184,955 $ 45,184
Kern River .......................... 17,165 -- -- --
Northern Natural Gas ................ 18,151 -- -- --
CE Electric UK ...................... 116,792 133,865 108,637 31,964
CalEnergy Generation-Domestic ....... 8,714 5,439 2,183 250
CalEnergy Generation-Foreign ........ 88,036 66,315 52,685 13,514
HomeServices ........................ 22,072 17,201 8,695 2,891
----------- ----------- ----------- ----------
Segment depreciation and amortization 540,342 509,410 357,155 93,803
Corporate/other ..................... (14,440) 29,292 26,196 3,475
----------- ----------- ----------- ----------
Total depreciation and amortization . $ 525,902 $ 538,702 $ 383,351 $ 97,278
=========== =========== =========== ==========
INTEREST EXPENSE, NET:
MidAmerican Energy .................. $ 119,225 $ 113,980 $ 94,425 $ 24,579
Kern River .......................... 33,036 -- -- --
Northern Natural Gas ................ 22,987 -- -- --
CE Electric UK ...................... 183,472 112,308 74,335 21,189
CalEnergy Generation-Domestic ....... 20,913 10,835 1,829 793
CalEnergy Generation-Foreign ........ 68,338 30,875 34,458 9,713
HomeServices ........................ 4,256 3,884 2,328 785
----------- ----------- ----------- ----------
Segment interest expense, net ....... 452,227 271,882 207,375 57,059
Corporate/other ..................... 157,683 140,912 104,029 28,755
----------- ----------- ----------- ----------
Total interest expense, net ......... $ 609,910 $ 412,794 $ 311,404 $ 85,814
=========== =========== =========== ==========
-93-
MEHC
YEAR ENDED DECEMBER 31, (PREDECESSOR)
-------------------------- MARCH 14, 2000 JANUARY 1, 2000
THROUGH THROUGH
2002 2001 DECEMBER 31, 2000 MARCH 13, 2000
----------- --------- ----------------- --------------
INCOME BEFORE PROVISIONS FOR INCOME TAXES:
MidAmerican Energy ............................. $ 241,005 $ 211,300 $ 181,797 $ 63,315
Kern River ..................................... 60,700 -- -- --
Northern Natural Gas ........................... 42,882 -- -- --
CE Electric UK ................................. 266,755 173,816 83,108 58,673
CalEnergy Generation-Domestic .................. (4,963) 46,765 30,697 2,877
CalEnergy Generation-Foreign ................... 149,915 94,542 49,787 15,976
HomeServices ................................... 69,979 42,945 31,015 (4,929)
----------- --------- --------- ---------
Segment income before provision for income taxes 826,273 569,368 376,404 135,912
Corporate/other ................................ (183,175) (65,484) (157,200) (44,742)
----------- --------- --------- ---------
Total income before provision for income taxes $ 643,098 $ 503,884 $ 219,204 $ 91,170
=========== ========= ========= =========
PROVISION FOR INCOME TAXES:
MidAmerican Energy ............................. $ 99,782 $ 95,688 $ 77,450 $ 27,943
Kern River ..................................... 23,014 -- -- --
Northern Natural Gas ........................... 16,947 -- -- --
CE Electric UK ................................. 25,245 163,253 30,065 18,761
CalEnergy Generation-Domestic .................. (15,203) 2,706 (1,929) (8)
CalEnergy Generation-Foreign ................... 37,577 29,712 29,194 373
HomeServices ................................... 28,207 15,953 12,300 (1,992)
----------- --------- --------- ---------
Segment provision for income taxes ............. 215,569 307,312 147,080 45,077
Corporate/other ................................ (115,981) (57,248) (93,803) (14,069)
----------- --------- --------- ---------
Total provision for income taxes ............. $ 99,588 $ 250,064 $ 53,277 $ 31,008
=========== ========= ========= =========
CAPITAL EXPENDITURES:
MidAmerican Energy ............................. $ 358,194 $ 252,615 $ 194,045 $ 23,977
Kern River ..................................... 769,464 -- -- --
Northern Natural Gas ........................... 62,409 -- -- --
CE Electric UK ................................. 222,622 176,464 95,806 22,210
CalEnergy Generation-Domestic .................. 61,920 52,940 151,289 53,011
CalEnergy Generation-Foreign ................... 7,830 83,954 87,781 22,263
HomeServices ................................... 18,273 9,878 6,996 2,052
----------- --------- --------- ---------
Segment capital expenditures ................... 1,500,712 575,851 535,917 123,513
Corporate/other ................................ 7,373 901 2,812 28
----------- --------- --------- ---------
Total capital expenditures ................... $ 1,508,085 $ 576,752 $ 538,729 $ 123,541
=========== ========= ========= =========
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AS OF DECEMBER 31,
--------------------------
2002 2001
----------- -----------
Identifiable assets:
MidAmerican Energy .......... $ 6,034,742 $ 5,848,035
Kern River .................. 1,797,850 --
Northern Natural Gas ........ 2,162,367 --
CE Electric UK .............. 4,717,524 4,340,147
CalEnergy Generation-Domestic 909,832 870,664
CalEnergy Generation-Foreign 974,852 950,035
HomeServices ................ 488,270 322,552
----------- -----------
Segment identifiable assets . 17,085,437 12,331,433
Corporate/other ............. 931,018 295,219
----------- -----------
Total identifiable assets ... $18,016,455 $12,626,652
=========== ===========
LONG-LIVED ASSETS:
MidAmerican Energy .......... $ 4,999,637 $ 4,879,884
Kern River .................. 1,594,225 --
Northern Natural Gas ........ 1,818,469 --
CE Electric UK .............. 3,936,598 3,650,385
CalEnergy Generation-Domestic 594,282 571,404
CalEnergy Generation-Foreign 724,908 805,050
HomeServices ................ 384,899 262,175
----------- -----------
Segment long-lived assets ... 14,053,018 10,168,898
Corporate/other ............. 15,201 7,019
----------- -----------
Total long-lived assets ..... $14,068,219 $10,175,917
=========== ===========
The remaining differences from the segment amounts to the consolidated amounts
described as "Corporate/Other" relate principally to the corporate functions
including administrative costs, corporate cash and related interest income,
intersegment eliminations, and fair value adjustments relating to acquisitions.
Excess of cost over fair value as of December 31, 2001 and changes from the
period from January 1, 2002 through December 31, 2002 by segment is as follows:
MIDAMERICAN KERN NORTHERN CE ELECTRIC GENERATION HOME-
ENERGY RIVER NATURAL GAS UK DOMESTIC SERVICES TOTAL
----------- ------- ----------- ----------- ---------- --------- -----------
Goodwill at December 31, 2001 ... $ 2,160,004 $ -- $ -- $ 1,104,262 $ 142,726 $ 231,554 $ 3,638,546
Acquisitions/purchase
price accounting adjustments .... -- 32,547 414,721 56,626 -- 108,914 612,808
Goodwill written off related to
sale of business unit ........... -- -- -- (49,587) -- -- (49,587)
Translation adjustment .......... -- -- -- 86,296 -- -- 86,296
Other adjustments
Deferred tax adjustments ........ (8,946) -- -- (1,675) (15,962) (477) (27,060)
Stock option adjustments ........ (1,776) -- -- (601) (324) (170) (2,871)
----------- ------- -------- ----------- --------- --------- -----------
Goodwill at December 31, 2002 ... $ 2,149,282 $32,547 $414,721 $ 1,195,321 $ 126,440 $ 339,821 $ 4,258,132
=========== ======= ======== =========== ========= ========= ===========
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
Not applicable.
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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The Company's management structure is organized functionally and the current
executive officers and directors of the Company and their positions are as
follows:
Name Position
- ---- --------
David L. Sokol Chairman of the Board, Chief Executive Officer
and Director
Gregory E. Abel President, Chief Operating Officer and Director
Patrick J. Goodman Senior Vice President and Chief Financial Officer
Douglas L. Anderson Senior Vice President, General Counsel and
Corporate Secretary
Keith D. Hartje Senior Vice President and Chief Administrative
Officer
Warren E. Buffett Director
Walter Scott Jr. Director
Marc D. Hamburg Director
W. David Scott Director
Edgar D. Aronson Director
John K. Boyer Director
Stanley J. Bright Director
Richard R. Jaros Director
Officers are elected annually by the Board of Directors. There are no family
relationships among the executive officers, nor any arrangements or
understanding between any officer and any other person pursuant to which the
officer was selected.
Set forth below is certain information with respect to each of the foregoing
officers:
DAVID L. SOKOL, 46, Chairman of the Board of Directors and Chief Executive
Officer. Mr. Sokol has been CEO since April 19, 1993 and served as President of
MEHC from April 19, 1993 until January 21, 1995. Mr. Sokol has been Chairman of
the Board of Directors since May 1994 and a director since March 1991. Formerly,
among other positions held in the independent power industry, Mr. Sokol served
as President and Chief Executive Officer of Kiewit Energy Company, which at that
time was a wholly owned subsidiary of Peter Kiewit & Sons Inc., and Ogden
Projects, Inc.
GREGORY E. ABEL, 40, President, Chief Operating Officer and Director. Mr. Abel
joined the Company in 1992 and initially served as Vice President and
Controller. Mr. Abel is a Chartered Accountant and from 1984 to 1992 he was
employed by Price Waterhouse. As a Manager in the San Francisco office of Price
Waterhouse, he was responsible for clients in the energy industry.
PATRICK J. GOODMAN, 36, Senior Vice President and Chief Financial Officer. Mr.
Goodman joined the Company in 1995, and served in various accounting positions
including Senior Vice President and Chief Accounting Officer. Prior to joining
the Company, Mr. Goodman was a financial manager for National Indemnity Company
and a senior associate at Coopers & Lybrand.
DOUGLAS L. ANDERSON, 45, Senior Vice President and General Counsel. Mr. Anderson
joined the Company in February 1993 and has served in various legal positions
including General Counsel of the Company's independent power affiliates. From
1990 to 1993 Mr. Anderson was a corporate attorney with Fraser, Stryker in
Omaha, NE. Prior to that Mr. Anderson was a principal in the firm Anderson and
Anderson.
KEITH D. HARTJE, 53, Senior Vice President and Chief Administrative Officer. Mr.
Hartje has been with MidAmerican Energy and its predecessor companies since
1973. In that time, he has held a number of positions, including General Counsel
and Corporate Secretary, District Vice President for southwest Iowa operations,
and Vice President, Corporate Communications.
WARREN E. BUFFETT, 72, Director. Mr. Buffett has been a director of the Company
since March 2000. He is Chairman of the Board and Chief Executive Office of
Berkshire Hathaway Inc. Mr. Buffett is a Director of the Coca-Cola Company, the
Gillette Company and The Washington Post Company.
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WALTER SCOTT, JR., 72, Director. Mr. Scott has been a director of the Company
since June 1991. Mr. Scott was the Chairman and Chief Executive Officer of the
Company from January 8, 1992 until April 19, 1993. For more than the past five
years, he has been Chairman of the Board of Directors of Level 3 Communications,
Inc., a successor to certain businesses of Peter Kiewit & Sons Inc. Mr. Scott is
a director of Peter Kiewit & Sons Inc., Berkshire Hathaway Inc., Burlington
Resources, Inc., ConAgra, Inc., Valmont Industries, Inc., Kiewit Materials Co.,
Commonwealth Telephone Enterprises, Inc. and RCN Corporation.
MARC D. HAMBURG, 53, Director. Mr. Hamburg has been a director of the Company
since March 2000. He has served as Vice President - Chief Financial Officer of
Berkshire Hathaway Inc. since October 1, 1992 and Treasurer since June 1, 1987,
his date of employment with Berkshire Hathaway Inc.
W. DAVID SCOTT, 41, Director. Mr. Scott has been a director of the Company since
March 2000. Mr. Scott formed Magnum Resources, Inc., a commercial real estate
investment and management company, in October 1994 and has served as its
President and Chief Executive Officer since its inception. Before forming Magnum
Resources, Mr. Scott worked for America First Companies, Cornerstone Banking
Group and Peter Kiewit & Sons Inc. Mr. Scott has been a director of America
First Mortgage Investments, Inc., a mortgage REIT, since 1998.
EDGAR D. ARONSON, 68, Director. Mr. Aronson has been a director of the Company
since 1983. Mr. Aronson founded EDACO, Inc., a private venture capital company,
in 1981, and has been President of EDACO, Inc. since that time. Prior to that,
Mr. Aronson was Chairman of Dillon, Read International from 1979 to 1981 and a
General Partner in charge of the International Department of Salomon Brothers
Inc. from 1973 to 1979. Mr. Aronson served during 1962-1968 as Vice President
consecutively in the International Departments of First National Bank of Chicago
and Republic National Bank of New York. He founded the International Department
of Salomon Brothers and Hutzler in 1968.
JOHN K. BOYER, 59, Director. Mr. Boyer has been a director of the Company since
March 2000. He is a partner with Fraser, Stryker, Meusey, Olson, Boyer & Bloch,
P.C. from 1973 to present with emphasis on corporate, commercial, federal,
state, and local taxation.
STANLEY J. BRIGHT, 63, Director. Mr. Bright is Vice Chairman of the Company and
was Chairman and Chief Executive Officer of MidAmerican Energy from July 1, 1995
until March 1999. Mr. Bright joined Iowa-Illinois Gas and Electric Company (a
predecessor of MidAmerican Energy) as Vice President and Chief Financial Officer
in 1986, became a director in 1987, President and Chief Operating Officer in
1990, and Chairman and Chief Executive Officer in 1991.
RICHARD R. JAROS, 51, Director. Mr. Jaros has been a director since March 1991.
Mr. Jaros served as President and Chief Operating Officer of the Company from
January 8, 1992 to April 19, 1993 and as Chairman of the Board from April 19,
1993 to May 1994. Until July 1997, Mr. Jaros was Executive Vice President and
Chief Financial Officer of Peter Kiewit & Sons Inc. and President of Kiewit
Diversified Group, Inc., which is now Level 3 Communications, Inc. Mr. Jaros
serves as director of Commonwealth Telephone Enterprises, Inc., RCN Corporation
and Level 3 Communications, Inc.
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ITEM 11. EXECUTIVE COMPENSATION.
The following table sets forth the compensation of its Chief Executive Officer
and its four other most highly compensated executive officers who were employed
as of December 31, 2002, which the Company refers to as its Named Executive
Officers. Information is provided regarding its Named Executive Officers for the
last three fiscal years during which they were its executive officers, if
applicable.
RESTRICTED SECURITITIES
NAME AND PRINCIPAL YEAR ENDED OTHER ANNUAL STOCK UNDERLYING LTIP ALL OTHER
POSITIONS DEC. 31 SALARY(1) BONUS (1) COMP AWARDS OPTIONS PAYOUTS COMP(2)
- ---------------------------- ---------- --------- ---------- ------------ ---------- ------------ ------- ---------
David L. Sokol ................ 2002 $800,000 $2,750,000 $27,122,550(3) $ -- $ -- $ -- $ 7,960
Chairman and .................. 2001 750,000 2,400,000 -- -- -- -- 33,033
Chief Executive Officer ....... 2000 750,000 4,250,000 -- -- 2,199,277 -- 40,430
Gregory E. Abel ............... 2002 540,000 2,200,000 -- -- -- -- 7,636
President and ................. 2001 520,000 1,150,000 -- -- -- -- 23,657
Chief Operating Officer ....... 2000 500,000 1,100,000 -- -- 649,052 -- 27,530
Patrick J. Goodman ............ 2002 248,000 365,000 209,560(4) -- -- -- 7,353
Senior Vice President and ..... 2001 240,000 260,000 -- -- -- -- 13,527
Chief Financial Officer ....... 2000 230,000 1,183,071 -- -- -- -- 14,891
Douglas L. Anderson ........... 2002 200,000 325,000 -- -- -- -- 7,150
Senior Vice President and ..... 2001 154,427 200,000 -- -- -- -- 6,630
General Counsel ............... 2000 120,000 591,806 -- -- -- -- 6,630
Keith D. Hartje ............... 2002 180,000 65,000 -- -- -- -- 7,796
Senior Vice President and ..... 2001 180,000 60,000 -- -- -- -- 6,630
Chief Administrative Officer .. 2000 178,173 138,647 -- -- -- -- 6,630
(1) Includes amounts voluntarily deferred by the executive, if applicable.
(2) Consists of 401(k) Plan contributions for 2002 for Mr. Sokol of
$7,150, Mr. Abel of $7,150, Mr. Goodman of $7,150, Mr. Anderson of
$7,150 and Mr. Hartje of $7,796. To offset its obligations under the
Company's Executive Split Dollar Plan for executives whose retirement
benefit cannot be fully funded through the Company's Base Retirement
Plan for Salaried Employees, the Company has agreed to pay the
premiums for policies of split dollar life insurance on the lives of
such executives. No premiums were paid in 2002 for Mr. Sokol, Mr.
Abel, or Mr. Goodman. Included are the insurance premiums in the
following amounts paid by the Company with respect to the term life
insurance portion of premiums paid in 2002 for Mr. Sokol of $810, for
Mr. Abel of $486 and for Mr. Goodman of $203.
(3) Cash amount paid to Mr. Sokol in connection with the Company's
purchase of options to purchase the Company's common stock held by Mr.
Sokol. The amount paid is equal to the difference between the option
exercise prices and the agreed upon value per share.
(4) Includes the cash amount paid to Mr. Goodman in connection with a
subsidiary's purchase of options to purchase the subsidiary's common
stock held by Mr. Goodman. The amount paid is equal to the difference
between the option exercise prices and the agreed upon value per
share.
OPTION GRANTS IN LAST FISCAL YEAR
The Company did not grant any options during 2002.
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR END OPTION
VALUES
The following table sets forth the option exercises and the number of securities
underlying exercisable and unexercisable options held by each of its Named
Executive Officers at December 31, 2002.
-99-
UNDERLYING UNEXERCISED VALUE OF UNEXERCISED
SHARES ACQUIRED VALUE OPTIONS HELD (#) IN-THE-MONEY OPTIONS ($) (1)
--------------------------- ----------------------------
NAME ON EXERCISE(#) REALIZED $ EXERCISEABLE UNEXERCISEABLE EXERCISEABLE UNEXERCISEABLE
- ------------------- --------------- ---------- ------------ -------------- ------------ --------------
David L. Sokol - - 1,353,504 45,773 N/A N/A
Gregory E. Abel - - 636,214 12,838 N/A N/A
Patrick J. Goodman - - - - - -
Douglas L. Anderson - - - - - -
Keith D. Hartje - - - - - -
(1) On March 14, 2000 the Company was acquired by a private investor
group. As a privately held company, the Company has no publicly traded
equity securities and, consequently, its management does not believe
there is a reliable method of computing the present value of the stock
options granted to Messrs. Sokol and Abel as shown on the foregoing
table.
LONG-TERM INCENTIVE PLANS - AWARDS IN LAST FISCAL YEAR
NUMBER OF SHARES, PERFORMANCE OR OTHER
UNITS OR OTHER PERIOD UNTIL MATURATION TARGET ($) MAXIMUM
NAME RIGHTS (#) (1) OR PAYOUT THRESHOLD($) (2) (#)
- ------------------- ----------------- ----------------------- ------------ ---------- -------
Patrick J. Goodman N/A December 31,2006 372,000 N/A 372,000
Douglas L. Anderson N/A December 31,2006 300,000 N/A 300,000
Keith D. Hartje N/A December 31,2006 270,000 N/A 270,000
(1) The awards shown in the foregoing table are made pursuant to the
Long-Term Incentive Partnership Plan ("LTIP"), which provides that
awards vest equally over five years with any unvested balances
forfeited upon termination of employment unless the participant
retires at or above age 55 with at least 5 years of service in which
case the participant will receive any unvested portion of the award.
Vested balances are paid to the participant at the time of
termination. Once an award is fully vested, the participant may elect
to defer or receive payment of part or all of the award. Messrs. Sokol
and Abel are not participants in the LTIP. Awards are credited or
reduced with annual interest or loss based on a composite of funds or
indices.
(2) "Target" and "Threshold" payouts are equivalent with the LTIP.
COMPENSATION OF DIRECTORS
All directors, excluding Messrs. Sokol, Abel, Warren Buffett and Walter Scott,
are paid an annual retainer fee of $20,000 and a fee of $500 per day for
attendance at Board and Committee meetings. Directors who are employees are not
entitled to receive such fees. All directors are reimbursed for their expenses
incurred in attending Board meetings.
RETIREMENT PLANS
The Company maintains a Supplemental Retirement Plan for Designated Officers,
which the Company refers to as the Supplemental Plan, to provide additional
retirement benefits to designated participants, as determined by the Board of
Directors. Messrs. Sokol, Abel, Goodman and Hartje are participants in the
Supplemental Plan. The Supplemental Plan provides annual retirement benefits up
to sixty-five percent of a participant's Total Cash Compensation in effect
immediately prior to retirement, subject to a $1 million maximum retirement
benefit. "Total Cash Compensation" means the highest amount payable to a
participant as monthly base salary during the five years immediately prior to
retirement multiplied by 12 plus the average of the participant's last three
years awards under an annual incentive bonus program and special, additional or
non-recurring bonus awards, if any, that are required to be included in Total
Cash Compensation pursuant to a participant's employment agreement or approved
for inclusion by the Board. Participants must be credited with five years
service in order to be eligible to receive benefits under the Supplemental Plan.
Each of the Company's Named Executive Officers has or will have five years of
credited service with the Company as of their respective normal retirement age
and will be eligible to receive benefits under the Supplemental Plan. A
participant who
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elects early retirement is entitled to reduced benefits under the Supplemental
Plan, however, in accordance with their respective employment agreements,
Messrs. Sokol and Abel are eligible to receive the maximum retirement benefit at
age 47. A survivor benefit is payable to a surviving spouse under the
Supplemental Plan. Benefits from the Supplemental Plan will be paid out of
general corporate funds; however, through a rabbi trust, the Company maintains
life insurance on the participants in amounts expected to be sufficient to fund
the after-tax cost of the projected benefits. Deferred compensation is
considered part of the salary covered by the Supplemental Plan.
The supplemental retirement benefit will be reduced by the amount of the
participant's regular retirement benefit under the MidAmerican Energy Cash
Balance Retirement Plan, which the Company refers to as the MidAmerican
Retirement Plan, that became effective January 1, 1997 and by benefits under the
Iowa Resources Inc. and Subsidiaries Supplemental Retirement Income Plan ("IOR
Supplemental Plan"), as applicable.
The MidAmerican Retirement Plan replaced retirement plans of predecessor
companies that were structured as traditional, defined benefit plans. Under the
MidAmerican Retirement Plan, each participant has an account, for record keeping
purposes only, to which credits are allocated each payroll period based upon a
percentage of the participant's salary paid in the current pay period. In
addition, all balances in the accounts of participants earn a fixed rate of
interest that is credited annually. The interest rate for a particular year is
based on the constant maturity Treasury yield plus seven-tenths of one
percentage point. At retirement or other termination of employment, an amount
equal to the vested balance then credited to the account is payable to the
participant in the form of a lump sum or a form of annuity for the entire
benefit under the MidAmerican Retirement Plan.
Part A of the IOR Supplemental Plan provides retirement benefits up to
sixty-five percent of a participant's highest annual salary during the five
years prior to retirement reduced by the participant's MidAmerican Retirement
Plan benefit. The percentage applied is based on years of accredited service. A
participant who elects early retirement is entitled to reduced benefits under
the plan. A survivor benefit is payable to a surviving spouse. Benefits are
adjusted annually for inflation. Part B of the IOR Supplemental Plan provides
that an additional one hundred-fifty percent of annual salary is to be paid out
to participants at the rate of ten percent per year over fifteen years, except
in the event of a participant's death, in which event the unpaid balance would
be paid to the participant's beneficiary or estate. Deferred compensation is
considered part of the salary covered by the IOR Supplemental Plan.
The table below shows the estimated aggregate annual benefits payable under the
Supplemental Plan and the MidAmerican Retirement Plan. The amounts exclude
Social Security and are based on a straight life annuity and retirement at ages
55, 60 and 65. Federal law limits the amount of benefits payable to an
individual through the tax qualified defined benefit and contribution plans, and
benefits exceeding such limitation are payable under the Supplemental Plan.
ESTIMATED ANNUAL BENEFIT
TOTAL CASH ------------------------------------------
COMPENSATION AGE AT RETIREMENT
AT RETIREMENT ($) 55 60 65
----------------- ---------- ---------- ----------
$ 400,000 $ 220,000 $ 240,000 $ 260,000
500,000 275,000 300,000 325,000
600,000 330,000 360,000 390,000
700,000 385,000 420,000 455,000
800,000 440,000 480,000 520,000
900,000 495,000 540,000 585,000
1,000,000 550,000 600,000 650,000
1,250,000 687,500 750,000 812,500
1,500,000 825,000 900,000 975,000
1,750,000 962,500 1,000,000 1,000,000
2,000,000
and greater 1,000,000 1,000,000 1,000,000
-101-
EMPLOYMENT AGREEMENTS
Pursuant to his employment agreement Mr. Sokol serves as Chairman of its Board
of Directors and Chief Executive Officer. The employment agreement provides that
Mr. Sokol is to receive an annual base salary of not less than $750,000, senior
executive employee benefits and annual bonus awards that shall not be less than
$675,000. Subject to an annual renewal provision, such agreement is scheduled to
expire on August 21, 2003.
The employment agreement provides that the Company may terminate the employment
of Mr. Sokol with cause, in which case the Company is to pay to him any accrued
but unpaid salary and a bonus of not less than the minimum annual bonus, or due
to death, permanent disability or other than for cause, including a change in
control, in which case Mr. Sokol is entitled to receive an amount equal to three
times the sum of his annual salary then in effect and the greater of his minimum
annual bonus or his average annual bonus for the two preceding years, as well as
three years of accelerated option vesting plus continuation of his senior
executive employee benefits (or the economic equivalent thereof) for three
years. If Mr. Sokol resigns, the Company is to pay to him any accrued but unpaid
salary and a bonus of not less than the annual minimum bonus, unless he resigns
for good reason in which case he will receive the same benefits as if he were
terminated other than for cause.
In the event Mr. Sokol has relinquished his position as Chief Executive Officer
and is subsequently terminated as Chairman of the Board due to death, disability
or other than for cause, he is entitled to any accrued but unpaid salary plus an
amount equal to the aggregate annual salary that would have been paid to him
through the fifth anniversary of the date he commenced his employment solely as
Chairman of the Board, the immediate vesting of all of his options and the
continuation of his senior executive employee benefits (or the economic
equivalent thereof) through this fifth anniversary. If Mr. Sokol relinquishes
his position as Chief Executive Officer but offers to remain employed as the
Chairman of the Board, he is to receive a special achievement bonus equal to two
times the sum of his annual salary then in effect and the greater of his minimum
annual bonus or his average annual bonus for the two preceding years, as well as
two years of accelerated option vesting.
Under the terms of separate employment agreements between the Company and each
of Messrs. Abel and Goodman, each of such executives is entitled to receive two
years base salary continuation, payments in respect of average bonuses for the
prior two years and two years continued option vesting in the event the Company
terminate his employment other than for cause. If such persons were terminated
without cause, Messrs. Sokol, Abel and Goodman would currently be entitled to be
paid approximately $10,125,000, $4,750,000 and $1,175,000, respectively, without
giving effect to any tax related provisions.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS.
The following table sets forth certain information regarding beneficial
ownership of the shares of its common stock and certain information with respect
to the beneficial ownership of each director, its Named Executive Officers and
all directors and executive officers as a group as of December 31, 2002.
NUMBER OF SHARES
BENEFICIALLY PERCENTAGE OF
NAME AND ADDRESS OF BENEFICIAL OWNER (1) OWNED(2) CLASS (2)
---------------------------------------- ---------------- -------------
Common Stock:
Walter Scott, Jr. (3) .............. 5,000,000 53.87%
David L. Sokol (4) ................. 1,708,224 15.10%
Berkshire Hathaway Inc. (5) ........ 900,942 9.71%
Gregory E. Abel (6) ................ 700,713 6.20%
W. David Scott (7) ................. 624,350 6.73%
Douglas L. Anderson ................ - -
Edgar D. Aronson ................... - -
Stanley J. Bright .................. - -
John K. Boyer ...................... - -
Warren E. Buffett (8) .............. - -
Patrick J. Goodman ................. - -
Marc D. Hamburg (8) ................ - -
Richard R. Jaros ................... - -
Keith D. Hartje .................... - -
All directors and executive officers 8,934,229 78.99%
as a group (14 persons)
(1) Unless otherwise indicated, each address is c/o the Company at 666 Grand
Avenue, 29th Floor, Des Moines, Iowa 50309.
(2) Includes shares which the listed beneficial owner is deemed to have the
right to acquire beneficial ownership under Rule 13d-3(d) under the
Securities Exchange Act, including, among other things, shares which the
listed beneficial owner has the right to acquire within 60 days.
(3) Excludes 3 million shares held by family members and family controlled
trusts and corporations ("Scott Family Interests") as to which Mr. Scott
disclaims beneficial ownership. Such beneficial owner's address is 1000
Kiewit Plaza, Omaha, Nebraska 68131.
(4) Includes options to purchase 1,384,019 shares of common stock that are
exercisable within 60 days.
(5) Such beneficial owner's address is 1440 Kiewit Plaza, Omaha, Nebraska
68131.
(6) Includes options to purchase 644,773 shares of common stock which are
exercisable within 60 days.
(7) Includes shares held by trusts for the benefit of or controlled by W. David
Scott. Such beneficial owner's address is 11422 Miracle Hills Drive, Suite
400, Omaha, Nebraska 68154.
(8) Excludes 900,942 shares of common stock held by Berkshire Hathaway Inc. of
which beneficial ownership of such shares is disclaimed.
The terms of its Zero Coupon Convertible Preferred Stock held by Berkshire
Hathaway entitle the holder thereof to elect two members of its Board of
Directors. The Zero Coupon Convertible Preferred Stock does not vote as to the
election of any other members of its Board of Directors. Mr. Sokol's employment
agreement gives him the right during the term of his employment to serve as a
member of the Board of Directors and to designate two additional directors.
Pursuant to a shareholders agreement, following March 14, 2003, Walter Scott,
Jr. or any of the Scott Family Interests would be able to require Berkshire
Hathaway to purchase, for an agreed value or an appraised value, any or all of
Walter Scott, Jr.'s and the Scott Family Interests' shares of its common stock,
provided that Berkshire Hathaway is then a purchaser of a type which is able to
consummate such a purchase without causing it or any of its affiliates or the
Company or any of its subsidiaries to become subject to regulation as a
registered holding company or a subsidiary of a
-103-
registered holding company under PUHCA. Berkshire Hathaway is not currently such
a purchaser. The consummation of such a transaction could result in a change in
control with respect to the Company.
MEHC's Amended and Restated Articles of Incorporation provide that each share of
the Zero Coupon Convertible Preferred Stock is convertible at the option of the
holder thereof into one conversion unit, which is one share of its common stock
subject to certain adjustments as described in its articles, upon the occurrence
of a Conversion Event. A "Conversion Event" includes (1) any conversion of Zero
Coupon Convertible Preferred Stock that would not cause the holder of the shares
of common stock issued upon conversion (or any affiliate of such holder) or the
Company to become subject to regulation as a registered holding company or as a
subsidiary of a registered holding company under PUHCA either as a result of the
repeal or amendment of PUHCA, the number of shares involved or the identity of
the holder of such shares and (2) a Company Sale. A "Company Sale" includes its
involuntary or voluntary liquidation, dissolution, recapitalization, winding-up
or termination and any merger, consolidation or sale of all or substantially all
of its assets. The conversion by Berkshire Hathaway of its shares of Zero Coupon
Convertible Preferred Stock into its common stock could result in a change in
control with respect to beneficial ownership of its voting securities as
calculated pursuant to Rule 13d-3(d) under the Securities Exchange Act.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Under a subscription agreement with the Company, Berkshire Hathaway has agreed
to purchase, under certain circumstances, additional 11% trust issued
mandatorily redeemable preferred securities in the event preferred securities
outstanding prior to the closing of its acquisition by a private investor group
on March 14, 2000 are tendered for conversion to cash by the current holders.
The Company provided a guarantee in favor of a third party lender in connection
with a $1,663,998.75 loan from such lender to its President, Gregory E. Abel, in
March of 2000. The loan matures on April 1, 2010. The proceeds of this loan were
used by Mr. Abel to purchase 47,475 shares of the Company's common stock. Such
common stock (together with 8,465 additional shares of common stock owned by Mr.
Abel) also secures the loan. The entire original principal amount of the loan
and the guarantee remain presently outstanding.
In order to finance its $275 million preferred stock investment in Williams, on
March 7, 2002, the Company sold to Berkshire Hathaway shares of its zero coupon
convertible preferred stock. In order to finance its acquisition of Kern River,
on March 12, 2002, the Company sold to Berkshire Hathaway and/or its
consolidated subsidiaries shares of its no par, zero coupon convertible
preferred stock for $127 million and $323 million of 11% mandatorily redeemable
preferred securities of its subsidiary trust due March 12, 2012 with scheduled
principal payments beginning in 2005. In order to finance its acquisition of
Northern Natural Gas, on August 16, 2002, the Company sold to Berkshire Hathaway
and/or its consolidated subsidiaries $950.0 million of 11% mandatorily
redeemable preferred securities of its subsidiary trust due August 31, 2012 with
scheduled principal payments beginning in 2003. Messrs. Warren E. Buffett and
Walter Scott, Jr. are members of the Board of Directors of Berkshire Hathaway.
Messrs. Buffett and Marc D. Hamburg are executive officers of Berkshire
Hathaway. Each of Messrs. Buffett, Hamburg and Walter Scott serves on its Board
of Directors and participates in deliberations regarding executive officer
compensation.
On March 6, 2002, the Company purchased options to purchase shares of its common
stock from Mr. David L. Sokol, its Chairman and Chief Executive Officer. The
options purchased had exercise prices ranging from $18.50 to $29.01. The Company
paid Mr. Sokol an aggregate amount of $27,122,550, which is equal to the
difference between his option exercise prices and an agreed upon per share
value. Mr. Sokol serves on its Board of Directors and participates in
deliberations regarding executive officer compensation.
In July 2002, the Company purchased 557,686 options to purchase shares of
HomeServices common stock from directors, officers and employees of
HomeServices. The options purchased had exercise prices ranging from $11.3125 to
$15.00. The Company paid an aggregate of $4,268,392, which is equal to the
difference between the option exercise prices and an agreed upon per share
value.
The Company has not purchased any other options or securities from its
stockholders, directors or executive officers since January 1, 2002.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
There is no compensation committee of the Board of Directors. All members of the
Board of Directors participate in deliberations regarding executive officer
compensation. Messrs. Sokol and Abel are current officers and employees. Mr.
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Walter Scott is a former officer. Mr. Jaros is a former officer and employee.
See "Certain Relationships and Related Transactions."
ITEM 14. CONTROLS AND PROCEDURES.
a) Evaluation of disclosure controls and procedures: Based on the Company's
evaluation as of a date within 90 days of the filing date of this Annual
Report on Form 10-K, the principal executive officer and principal
financial officer have concluded that the Company's disclosure controls and
procedures (as defined in Rules 13a-14(c) and 15d-14(c) under the
Securities Exchange Act of 1934 (the Exchange Act)) are effective to ensure
that information required to be disclosed by the Company in reports that it
files or submits under the Exchange Act are recorded, processed, summarized
and reported within the time periods specified in Securities and Exchange
Commission rules and forms. It should be noted that the design of any
system of controls is based in part upon certain assumptions about the
likelihood of future events, and there can be no assurance that any design
will succeed in achieving its stated goals under all potential future
conditions, regardless of how remote.
b) Changes in internal controls. There were no significant changes in the
Company's internal controls or in other factors that could significantly
affect these controls subsequent to the date of their evaluation. There
were no significant deficiencies or material weaknesses, and therefore
there were no corrective actions taken.
-105-
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) Financial Statements and Schedules
(i) Financial Statements
Financial Statements are included in Part II of this Form 10-K
(ii) Financial Statement Schedules
See Schedule I on Page 107.
See Schedule II on Page 110.
(b) Reports on Form 8-K
The Company filed the following Current Reports on Form 8-K during the
fourth quarter of 2002:
o The Company filed a Current Report on Form 8-K on October 2,
2002.
o The Company filed a Current Report on Form 8-K on October 4,
2002.
o The Company filed a Current Report on Form 8-K on November 13,
2002.
o The Company filed a Current Report on Form 8-K on November 14,
2002.
(c) Exhibits
The exhibits listed on the accompanying Exhibit Index are filed as part of
this Annual Report.
(d) Financial statements required by Regulation S-X, which are excluded
from the Annual Report by Rule 14a-3(b).
Not applicable.
-106-
MIDAMERICAN ENERGY HOLDINGS COMPANY SCHEDULE I
PARENT COMPANY ONLY
CONDENSED BALANCE SHEETS
As of December 31, 2002 and 2001
(Amounts in thousands)
2002 2001
----------- -----------
ASSETS
Current assets -
Cash and cash equivalents .................................. $ 320,629 $ 2,524
Investments in and advances to subsidiaries and joint ventures 5,459,832 3,432,528
Equipment, net ............................................... 15,984 17,605
Excess of cost over fair value of net assets acquired ........ 1,185,963 1,211,814
Deferred charges and other assets ............................ 151,126 129,501
----------- -----------
TOTAL ASSETS ................................................. $ 7,133,534 $ 4,793,972
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and other accrued liabilities ............. $ 94,389 $ 68,445
Current portion of long-term debt .......................... 215,000 --
Short-term debt ............................................ -- 153,500
----------- -----------
Total current liabilities ................................ 309,389 221,945
----------- -----------
Non-current liabilities ...................................... 11,885 6,480
Notes payable - affiliate .................................... 94,795 197,153
Parent company debt .......................................... 2,324,457 1,834,498
----------- -----------
Total liabilities .......................................... 2,740,526 2,260,076
----------- -----------
Deferred income .............................................. 35,313 37,578
Company-obligated mandatorily redeemable
preferred securities of subsidiary trusts .................. 2,063,412 788,151
Stockholders' equity:
Zero coupon convertible preferred stock -
authorized 50,000 shares, no par value,
41,263 and 34,563 shares issued and
outstanding at December 31, 2002 and 2001 .................. -- --
Common stock -authorized 60,000 shares, no par value; 9,281
shares issued and outstanding at December 31, 2002 and 2001 -- --
Additional paid in capital ................................... 1,956,509 1,553,073
Retained earnings ............................................ 584,009 223,926
Accumulated other comprehensive loss, net .................... (246,235) (68,832)
----------- -----------
Total stockholders' equity ................................... 2,294,283 1,708,167
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ................... $ 7,133,534 $ 4,793,972
=========== ===========
The notes to the consolidated MEHC financial statements are an integral part of
this financial statement schedule.
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MIDAMERICAN ENERGY HOLDINGS COMPANY SCHEDULE I
PARENT COMPANY ONLY (CONTINUED)
CONDENSED STATEMENTS OF OPERATIONS
For the three years ended December 31, 2002
(Amounts in thousands)
2002 2001 2000
-------- --------- --------
Revenue:
Equity in undistributed earnings of subsidiary companies
and joint ventures ............................................ $460,631 $ 608,896 $390,194
Cash dividends and distributions from subsidiary
companies and joint ventures .................................. 351,847 87,625 96,342
Interest and other income ..................................... 18,243 2,248 13,818
-------- --------- --------
Total revenue ................................................. 830,721 698,769 500,354
-------- --------- --------
COSTS AND EXPENSES:
General and administration .................................... 29,368 41,078 45,089
Depreciation and amortization ................................. 815 31,537 25,716
Interest, net of capitalized interest ......................... 173,240 148,680 141,891
-------- --------- --------
Total costs and expenses ...................................... 203,423 221,295 212,696
-------- --------- --------
INCOME BEFORE PROVISION FOR INCOME TAXES ...................... 627,298 477,474 287,658
Provision for income taxes .................................... 99,588 250,064 84,285
-------- --------- --------
INCOME BEFORE MINORITY INTEREST ............................... 527,710 227,410 203,373
Minority interest ............................................. 147,667 80,137 70,804
-------- --------- --------
INCOME BEFORE AND CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE ................................ 380,043 147,273 132,569
Cumulative effect of change in accounting principle, net of tax -- (4,604) --
-------- --------- --------
NET INCOME AVAILABLE TO COMMON STOCKHOLDERS ................... $380,043 $ 142,669 $132,569
======== ========= ========
The notes to the consolidated MEHC financial statements are an integral part of
this financial statement schedule.
-108-
MIDAMERICAN ENERGY HOLDINGS COMPANY SCHEDULE I
PARENT COMPANY ONLY (CONTINUED)
CONDENSED STATEMENTS OF CASH FLOWS
For the three years ended December 31, 2002
(Amounts in thousands)
2002 2001 2000
----------- --------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES ................ $ (188,300) $(272,906) $ (299,862)
CASH FLOWS FROM INVESTING ACTIVITIES:
Decrease (increase) in advances to and investments in
subsidiaries and joint ventures ..................... (1,692,742) 204,118 143,052
Acquisition of MEHC (Predecessor) ................... -- -- (2,048,266)
Other, net .......................................... 10,307 (5,297) 28,458
----------- --------- -----------
Net cash flows from investing activities ............ (1,682,435) 198,821 (1,876,756)
----------- --------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common and preferred stock 402,000 -- 1,428,024
Proceeds from issuance of trust preferred securities 1,273,000 -- 454,772
Proceeds from issuances of parent company debt ...... 700,000 -- --
Repayments of parent company debt ................... -- (32) --
Net (repayment of) proceeds from revolver ........... (153,500) 68,500 85,000
Other ............................................... (32,660) (82) (23,893)
----------- --------- -----------
Net cash flows from financing activities ............ 2,188,840 68,386 1,943,903
----------- --------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 318,105 (5,699) (232,715)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR ...... 2,524 8,223 240,938
----------- --------- -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR ............ $ 320,629 $ 2,524 $ 8,223
=========== ========= ===========
SUPPLEMENTAL DISCLOSURES:
Interest paid, net of interest capitalized .......... $ 164,267 $ 148,999 $ 144,147
=========== ========= ===========
Income taxes paid ................................... $ 101,225 $ 133,139 $ 94,405
=========== ========= ===========
The notes to the consolidated MEHC financial statements are an integral part
of this financial statement schedule.
-109-
SCHEDULE II
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2002
(Amounts in thousands)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------- ---------- --------------------------------- -------- ----------
BALANCE AT ADDITIONS
--------------------------------- BALANCE AT
BEGINNING CHARGED OTHER ACQUISITION END
Description OF YEAR TO INCOME ACCOUNTS RESERVES (2) DEDUCTIONS OF YEAR
----------- --------- --------- -------- ------------ ---------- ----------
Reserves Deducted From Assets
To Which They Apply:
Reserve for uncollectible accounts receivable:
Year ended 2002 .............................. $ 7,319 $27,782 $-- $10,142 $ (5,501) $39,742
Year ended 2001 .............................. $32,685 $17,061 $-- $ -- $(42,427) $ 7,319
Year ended 2000 .............................. $18,666 $40,024 $-- $ -- $(26,005) $32,685
Reserves Not Deducted From Assets (1):
Year ended 2002 .............................. $13,631 $ 2,798 $247 $ -- $ (5,695) $10,981
Year ended 2001 .............................. $25,063 $ 5,046 $-- $ -- $(16,478) $13,631
Year ended 2000 .............................. $17,696 $10,832 $-- $ -- $ (3,465) $25,063
The notes to the consolidated MEHC financial statements
are an integral part of this financial statement schedule.
(1) Reserves not deducted from assets include estimated liabilities for losses
retained by MEHC for workers compensation, public liability and property
damage claims
(2) Acquisition reserves represent the reserves recorded at Kern River and
Northern Natural Gas at the date of acquisition.
-110-
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized, in the City of Des
Moines, State of Iowa, on this 31st day of March 2003.
MIDAMERICAN ENERGY HOLDINGS COMPANY
/s/ David L. Sokol*
--------------------
David L. Sokol
Chairman of the Board and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Signature Date
--------- ----
/s/ David L. Sokol* March 31, 2003
- -------------------
David L. Sokol
Chairman of the Board,
Chief Executive Officer, and
Director
/s/ Gregory E. Abel* March 31, 2003
- ---------------------
Gregory E. Abel
President, Chief Operating Officer and Director
/s/ Patrick J. Goodman* March 31, 2003
- ------------------------
Patrick J. Goodman
Senior Vice President and
Chief Financial Officer
/s/ Edgar D. Aronson* March 31, 2003
- ---------------------
Edgar D. Aronson
Director
/s/ Stanley J. Bright* March 31, 2003
- -----------------------
Stanley J. Bright
Director
/s/ Walter Scott, Jr.* March 31, 2003
- -----------------------
Walter Scott, Jr.
Director
-111-
/s/ Marc D. Hamburg* March 31, 2003
- --------------------
Marc D. Hamburg
Director
/s/ Warren E. Buffett* March 31, 2003
- ----------------------
Warren E. Buffett
Director
/s/ John K. Boyer* March 31, 2003
- ------------------
John K. Boyer
Director
/s/ W. David Scott* March 31, 2003
- -------------------
W. David Scott
Director
/s/ Richard R. Jaros* March 31, 2003
- ---------------------
Richard R. Jaros
Director
*By:/s/ Douglas L. Anderson March 31, 2003
- ----------------------------
Douglas L. Anderson
Attorney-in-Fact
-112-
SECTION 302 CERTIFICATION FOR FORM 10-K
CERTIFICATIONS
- --------------
I, David L. Sokol, certify that:
1. I have reviewed this annual report on Form 10-K of MidAmerican Energy
Holdings Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and the Company has:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to the Company by others within those entities, particularly
during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report its conclusions about the effectiveness of
the disclosure controls and procedures based on its evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on its
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of its most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 31, 2003
/s/ David L. Sokol
-----------------------
David L. Sokol
Chief Executive Officer
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SECTION 302 CERTIFICATION FOR FORM 10-K
CERTIFICATIONS
- --------------
I, Patrick J. Goodman, certify that:
1. I have reviewed this annual report on Form 10-K of MidAmerican Energy
Holdings Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and the Company has:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to the Company by others within those entities, particularly
during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report its conclusions about the effectiveness of
the disclosure controls and procedures based on its evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on its
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of its most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 31, 2003
/s/ Patrick J. Goodman
-------------------------
Patrick J. Goodman
Senior Vice President and
Chief Financial Officer
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EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
----------- -----------
3.1 Amended and Restated Articles of Incorporation of the Company
effective March 6, 2002 (incorporated by reference to Exhibit 3.3 to
the Company's Annual Report on Form 10-K for the year ended December
31, 2001).
3.2 Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the
Company's Annual Report on Form 10-K/A for the year ended December 31,
1999).
4.1 Indenture, dated as of October 4, 2002, by and between the Company and
The Bank of New York, relating to the 4.625% Senior Notes due 2007 and
the 5.875% Senior Notes due 2012 (incorporated by reference to Exhibit
4.1 of the Company's Registration Statement No. 333-101699 dated
December 6, 2002).
4.2 First Supplemental Indenture, dated as of October 4, 2002, by and
between the Company and The Bank of New York, relating to the 4.625%
Senior Notes due 2007 and the 5.875% Senior Notes due 2012
(incorporated by reference to Exhibit 4.2 of the Company's
Registration Statement No. 333-101699 dated December 6, 2002).
4.3 Registration Rights Agreement, dated as of October 1, 2002, by and
between the Company and Credit Suisse First Boston (as Representative
for the Initial Purchasers) (incorporated by reference to Exhibit 4.3
of the Company's Registration Statement No. 333-101699 dated December
6, 2002).
4.4 Indenture for the 6 1/4% Convertible Junior Subordinated Debentures
due 2012, dated as of February 26, 1997, between the Company, as
issuer, and the Bank of New York, as Trustee (incorporated by
reference to Exhibit 10.129 to the Company's Annual Report on Form
10-K for the year ended December 31, 1995).
4.5 Indenture, dated as of October 15, 1997, among the Company and IBJ
Schroder Bank & Trust Company, as Trustee (incorporated by reference
to Exhibit 4.1 to the Company's Current Report on Form 8-K dated
October 23, 1997).
4.6 Form of First Supplemental Indenture for the 7.63% Senior Notes in the
principal amount of $350,000,000 due 2007, dated as of October 28,
1997, among the Company and IBJ Schroder Bank & Trust Company, as
Trustee (incorporated by reference to Exhibit 4.2 to the Company's
Current Report on Form 8-K dated October 23, 1997).
4.7 Form of Second Supplemental Indenture for the 6.96% Senior Notes in
the principal amount of $215,000,000 due 2003, 7.23% Senior Notes in
the principal amount of $260,000,000 due 2005, 7.52% Senior Notes in
the principal amount of $450,000,000 due 2008, and 8.48% Senior Notes
in the principal amount of $475,000,000 due 2028, dated as of
September 22, 1998 between the Company and IBJ Schroder Bank & Trust
Company, as Trustee (incorporated by reference to Exhibit 4.1 to the
Company's Current Report on Form 8-K dated September 17, 1998.)
-115-
4.8 Form of Third Supplemental Indenture for the 7.52% Senior Notes in the
principal amount of $100,000,000 due 2008, dated as of November 13,
1998, between the Company and IBJ Schroder Bank & Trust Company, as
Trustee (incorporated by reference to the Company's Current Report on
Form 8-K dated November 10, 1998).
4.9 Indenture, dated as of March 14, 2000, among the Company and the Bank
of New York, as Trustee (incorporated by reference to Exhibit 4.9 to
the Company's Annual Report on Form 10-K/A for the year ended December
31, 1999).
4.10 Subscription Agreement, dated as of March 14, 2000, executed by
Berkshire Hathaway Inc. (incorporated by reference to Exhibit 4.10 to
the Company's Annual Report on Form 10-K/A for the year ended December
31, 1999).
4.11 Indenture, dated as of March 12, 2002, between the Company and the
Bank of New York, as Trustee (incorporated by reference to Exhibit
4.11 to the Company's Annual Report on Form 10-K for the year ended
December 31, 2001).
4.12 Subscription Agreement, dated as of March 7, 2002, executed by
Berkshire Hathaway Inc. (incorporated by reference to Exhibit 4.12 to
the Company's Annual Report on Form 10-K for the year ended December
31, 2001).
4.13 Subscription Agreement, dated as of March 12, 2002, executed by
Berkshire Hathaway Inc. (incorporated by reference to Exhibit 4.13 to
the Company's Annual Report on Form 10-K for the year ended December
31, 2001).
4.14 Amended and Restated Declaration of Trust of MidAmerican Capital Trust
III, dated as of August 16, 2002 (incorporated by reference to Exhibit
4.14 of the Company's Registration Statement No. 333-101699 dated
December 6, 2002).
4.15 Amended and Restated Declaration of Trust of MidAmerican Capital Trust
II, dated as of March 12, 2002 (incorporated by reference to Exhibit
4.15 of the Company's Registration Statement No. 333-101699 dated
December 6, 2002).
4.16 Amended and Restated Declaration of Trust of MidAmerican Capital Trust
I, dated as of March 14, 2000 (incorporated by reference to Exhibit
4.16 of the Company's Registration Statement No. 333-101699 dated
December 6, 2002).
4.17 Indenture, dated as of August 16, 2002, between the Company and the
Bank of New York, as Trustee (incorporated by reference to Exhibit
4.17 of the Company's Registration Statement No. 333-101699 dated
December 6, 2002).
4.18 Subscription Agreement, dated as of August 16, 2002, executed by
Berkshire Hathaway Inc. (incorporated by reference to Exhibit 4.18 of
the Company's Registration Statement No. 333-101699 dated December 6,
2002).
4.19 Shareholders Agreement, dated as of March 14, 2000 (incorporated by
reference to Exhibit 4.19 of the Company's Registration Statement No.
333-101699 dated December 6, 2002).
10.1 Employment Agreement between the Company and David L. Sokol, dated May
10, 1999 (incorporated by reference to Exhibit 10.1 to the Company's
Annual Report on Form 10-K/A for the year ended December 31, 1999).
-116-
10.2 Amendment No. 1 to the Amended and Restated Employment Agreement
between the Company and David L. Sokol, dated March 14, 2000
(incorporated by reference to Exhibit 10.2 to the Company's Annual
Report on Form 10-K/A for the year ended December 31, 1999).
10.3 Non-Qualified Stock Options Agreements of David L. Sokol, dated March
14, 2000 (incorporated by reference to Exhibit 10.3 of the Company's
Registration Statement No. 333-101699 dated December 6, 2002).
10.4 Amended and Restated Employment Agreement between the Company and
Gregory E. Abel, dated May 10, 1999 (incorporated by reference to
Exhibit 10.3 to the Company's Annual Report on Form 10-K/A for the
year ended December 31, 1999).
10.5 Non-Qualified Stock Options Agreements of Gregory E. Abel, dated March
14, 2000 (incorporated by reference to Exhibit 10.5 of the Company's
Registration Statement No. 333-101699 dated December 6, 2002).
10.6 Employment Agreement between the Company and Patrick J. Goodman, dated
April 21, 1999 (incorporated by reference to Exhibit 10.5 to the
Company's Annual Report on Form 10-K/A for the year ended December 31,
1999).
10.7 MidAmerican Energy Holdings Company Long Term Incentive Partnership
Plan (incorporated by reference to Exhibit 10.7 of the Company's
Registration Statement No. 333-101699 dated December 6, 2002).
10.8 125 MW Power Plant-Upper Mahiao Agreement, dated September 6, 1993,
between PNOC-Energy Development Corporation and Ormat, Inc. as amended
by the First Amendment to 125 MW Power Plant Upper Mahiao Agreement,
dated as of January 28, 1994, the Letter Agreement dated February 10,
1994, the Letter Agreement dated February 18, 1994 and the Fourth
Amendment to 125 MW Power Plant-Upper Mahiao Agreement, dated as of
March 7, 1994 (incorporated by reference to Exhibit 10.95 to the
Company's Annual Report on Form 10-K for the year ended December 31,
1993).
10.9 Credit Agreement, dated April 8, 1994, among CE Cebu Geothermal Power
Company, Inc., the Banks thereto, Credit Suisse as Agent (incorporated
by reference to Exhibit 10.96 to the Company's Annual Report on Form
10-K for the year ended December 31, 1993).
10.10 Credit Agreement, dated as of April 8, 1994, between CE Cebu
Geothermal Power Company, Inc., Export-Import Bank of the United
States (incorporated by reference to Exhibit 10.97 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1993).
10.11 Pledge Agreement, dated as of April 8, 1994, among CE Philippines
Ltd, Ormat-Cebu Ltd., Credit Suisse as Collateral Agent and CE Cebu
Geothermal Power Company, Inc. (incorporated by reference to Exhibit
10.98 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1993).
10.12 Overseas Private Investment Corporation Contract of Insurance, dated
April 8, 1994, between the Overseas Private Investment Corporation and
the Company through its subsidiaries CE International Ltd., CE
Philippines Ltd., and Ormat-Cebu Ltd. (incorporated by reference to
Exhibit 10.99 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1993).
-117
10.13 180 MW Power Plant-Mahanagdong Agreement, dated September 18, 1993,
between PNOC-Energy Development Corporation and CE Philippines Ltd.
and the Company, as amended by the First Amendment to Mahanagdong
Agreement, dated June 22, 1994, the Letter Agreement dated July 12,
1994, the Letter Agreement dated July 29, 1994, and the Fourth
Amendment to Mahanagdong Agreement, dated March 3, 1995 (incorporated
by reference to Exhibit 10.100 to the Company's Annual Report on Form
10-K for the year ended December 31, 1993).
10.14 Credit Agreement, dated as of June 30, 1994, among CE Luzon
Geothermal Power Company, Inc., American Pacific Finance Company, the
Lenders party thereto, and Bank of America National Trust and Savings
Association as Administrative Agent (incorporated by reference to
Exhibit 10.101 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1993).
10.15 Credit Agreement, dated as of June 30, 1994, between CE Luzon
Geothermal Power Company, Inc. and Export-Import Bank of the United
States (incorporated by reference to Exhibit 10.102 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1993).
10.16 Finance Agreement, dated as of June 30, 1994, between CE Luzon
Geothermal Power Company, Inc. and Overseas Private Investment
Corporation (incorporated by reference to Exhibit 10.103 to the
Company's Annual Report on Form 10-K for the year ended December 31,
1993).
10.17 Pledge Agreement, dated as of June 30, 1994, among CE Mahanagdong
Ltd., Kiewit Energy International (Bermuda) Ltd., Bank of America
National Trust and Savings Association as Collateral Agent and CE
Luzon Geothermal Power Company, Inc. (incorporated by reference to
Exhibit 10.104 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1993).
10.18 Overseas Private Investment Corporation Contract of Insurance, dated
July 29, 1994, between Overseas Private Investment Corporation and the
Company, CE International Ltd., CE Mahanagdong Ltd. and American
Pacific Finance Company and Amendment No. 1, dated August 3, 1994
(incorporated by reference to Exhibit 10.105 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1993).
10.19 231 MW Power Plant-Malitbog Agreement, dated September 10, 1993,
between PNOC- Energy Development Corporation and Magma Power Company
and the First and Second Amendments thereto, dated December 8, 1993
and March 10, 1994, respectively (incorporated by reference to Exhibit
10.106 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1993).
10.20 Credit Agreement, dated as of November 10, 1994, among Visayas Power
Capital Corporation, the Banks parties thereto and Credit Suisse, as
Bank Agent (incorporated by reference to Exhibit 10.107 to the
Company's Annual Report on Form 10-K for the year ended December 31,
1993).
10.21 Finance Agreement, dated as of November 10, 1994, between Visayas
Geothermal Power Company and Overseas Private Investment Corporation
(incorporated by reference to Exhibit 10.108 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1993).
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10.22 Pledge and Security Agreement, dated as of November 10, 1994, among
Broad Street Contract Services, Inc., Magma Power Company, Magma
Netherlands B.V. and Credit Suisse, as Bank Agent (incorporated by
reference to Exhibit 10.109 to the Company's Annual Report on Form
10-K for the year ended December 31, 1993).
10.23 Overseas Private Investment Corporation Contract of Insurance, dated
December 21, 1994, between Overseas Private Investment Corporation and
Magma Netherlands, B.V. (incorporated by reference to Exhibit 10.110
to the Company's Annual Report on Form 10-K for the year ended
December 31, 1993).
10.24 Agreement as to Certain Common Representations, Warranties, Covenants
and Other Terms, dated November 10, 1994, between Visayas Geothermal
Power Company, Visayas Power Capital Corporation, Credit Suisse, as
Bank Agent, Overseas Private Investment Corporation and the Banks
named therein (incorporated by reference to Exhibit 10.111 to the
Company's 1994 Annual Report on Form 10-K for the year ended December
31, 1993).
10.25 Trust Indenture, dated as of November 27, 1995, between the CE
Casecnan Water and Energy Company, Inc. and Chemical Trust Company of
California (incorporated by reference to Exhibit 4.1 to CE Casecnan
Water and Energy Company, Inc.'s Registration Statement on Form S-4
dated January 25, 1996).
10.26 Amended and Restated Casecnan Project Agreement, dated June 26, 1995,
between the National Irrigation Administration and CE Casecnan Water
and Energy Company Inc. (incorporated by reference to Exhibit 10.1 to
CE Casecnan Water and Energy Company, Inc.'s Registration Statement on
Form S-4 dated January 25, 1996).
10.27 Term Loan and Revolving Facility Agreement, dated as of October 28,
1996, among CE Electric UK Holdings, CE Electric UK plc and Credit
Suisse (incorporated by reference to Exhibit 10.130 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1995).
10.28 Indenture and First Supplemental Indenture, dated March 11, 1999,
between MidAmerican Funding LLC and IBJ Whitehall Bank & Trust Company
and the First Supplement thereto relating to the $700 million Senior
Notes and Bonds (incorporated by reference to the Company's Annual
Report on Form 10-K for the year ended December 31, 1998).
10.29 General Mortgage Indenture and Deed of Trust, dated as of January 1,
1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust
Company of New York, Trustee (incorporated by reference to Exhibit
4(b)-1 to the Midwest Resources Inc. Annual Report on Form 10-K for
the year ended December 31, 1992, Commission File No. 1-10654).
10.30 First Supplemental Indenture, dated as of January 1, 1993, between
Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New
York, Trustee (incorporated by reference to Exhibit 4(b)-2 to the
Midwest Resources Inc. Annual Report on Form 10-K for the year ended
December 31, 1992, Commission File No. 1-10654).
10.31 Second Supplemental Indenture, dated as of January 15, 1993, between
Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New
York, Trustee (incorporated by reference to Exhibit 4(b)-3 to the
Midwest Resources Inc. Annual Report on Form 10-K for the year ended
December 31, 1992, Commission File No. 1-10654).
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10.32 Third Supplemental Indenture, dated as of May 1, 1993, between
Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New
York, Trustee (incorporated by reference to Exhibit 4.4 to the Midwest
Resources Inc. Annual Report on Form 10-K for the year ended December
31, 1993, Commission File No. 1-10654).
10.33 Fourth Supplemental Indenture, dated as of October 1, 1994, between
Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee
(incorporated by reference to Exhibit 4.5 to the Midwest Resources
Inc. Annual Report on Form 10-K for the year ended December 31, 1994,
Commission File No. 1-10654).
10.34 Fifth Supplemental Indenture, dated as of November 1, 1994, between
Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee
(incorporated by reference to Exhibit 4.6 to the Midwest Resources
Inc. Annual Report on Form 10-K for the year ended December 31, 1994,
Commission File No. 1-10654).
10.35 Sixth Supplemental Indenture, dated as of July 1, 1995, between
Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee
(incorporated by reference to Exhibit 4.15 to the MidAmerican Energy
Company Annual Report on Form 10-K for the year ended December 31,
1995, Commission File No. 1-11505).
10.36 Indenture of Mortgage and Deed of Trust, dated as of March 1, 1947
(incorporated by reference to Exhibit 7B filed by Iowa-Illinois Gas
and Electric Company as part of Commission File No. 2-6922).
10.37 Sixth Supplemental Indenture, dated as of July 1, 1967 (incorporated
by reference to Exhibit 2.08 filed by Iowa-Illinois Gas and Electric
Company as part of Commission File No. 2-28806).
10.38 Twentieth Supplemental Indenture, dated as of May 1, 1982
(incorporated by reference to Exhibit 4.B.23 to the Iowa-Illinois Gas
and Electric Company Quarterly Report on Form 10-Q for the period
ended June 30, 1982, Commission File No. 1-3573).
10.39 Resignation and Appointment of successor Individual Trustee
(incorporated by reference to Exhibit 4.B.30 filed by Iowa-Illinois
Gas and Electric Company as part of Commission File No. 33-39211).
10.40 Twenty-Eighth Supplemental Indenture, dated as of May 15, 1992
(incorporated by reference to Exhibit 4.31.B to the Iowa-Illinois Gas
and Electric Company Current Report on Form 8-K dated May 21, 1992,
Commission File No. 1-3573).
10.41 Intentionally left blank.
10.42 Thirtieth Supplemental Indenture, dated as of October 1, 1993
(incorporated by reference to Exhibit 4.34.A to the Iowa-Illinois Gas
and Electric Company Current Report on Form 8-K, dated October 7,
1993, Commission File No. 1-3573).
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10.43 Thirty-First Supplemental Indenture, dated as of July 1, 1995,
between Iowa-Illinois Gas and Electric Company and Harris Trust and
Savings Bank, Trustee (incorporated by reference to Exhibit 4.16 to
the MidAmerican Energy Company Annual Report on Form 10-K for the year
ended dated December 31, 1995, Commission File No. 1-11505).
10.44 Power Sales Contract, dated September 22, 1967, between Iowa Power
Inc. and Nebraska Public Power District (incorporated by reference to
Exhibit 4-C-2 filed by Iowa Power Inc. as part of Registration
Statement No. 2-27681).
10.45 Amendments Nos. 1 and 2 to Power Sales Contract between Iowa Power
Inc. and Nebraska Public Power District, dated September 22, 1967
(incorporated by reference to Exhibit 4-C-2a filed by Iowa Power Inc.
as part of Registration Statement No. 2-35624).
10.46 Amendment No. 3, dated August 31, 1970, to the Power Sales Contract
between Iowa Power Inc. and Nebraska Public Power District, dated
September 22, 1967 (incorporated by reference to Exhibit 5-C-2-b filed
by Iowa Power Inc. as part of Registration Statement No. 2-42191).
10.47 Amendment No. 4, dated March 28, 1974, to the Power Sales Contract
between Iowa Power Inc. and Nebraska Public Power District, dated
September 22, 1967 (incorporated by reference to Exhibit 5-C-2-c filed
by Iowa Power Inc. as part of Registration Statement No. 2-51540).
10.48 Amendment No. 5, dated September 2, 1997, to the Power Sales Contract
between MidAmerican Energy Company and Nebraska Public Power District,
dated September 22, 1967 (incorporated by reference to Exhibit 10.2 to
the former MidAmerican Energy Holdings Company and MidAmerican Energy
Company respective Quarterly Reports on the combined Form 10-Q for the
quarter ended September 30, 1997, Commission File Nos. 333-90553 and
1-11505, respectively).
10.49 Amendment No. 6, dated July 31, 2002, to the Power Sales Contract
between MidAmerican Energy Company and Nebraska Public Power District,
dated September 22, 1967 (incorporated by reference to Exhibit 10.1 to
the MidAmerican Funding, LLC and MidAmerican Energy Company respective
Quarterly Reports on the combined Form 10-Q for the quarter ended June
20, 2002, Commission File Nos. 1-12459 and 1-11505, respectively).
10.50 CalEnergy Company, Inc. Voluntary Deferred Compensation Plan,
effective December 1, 1997, First Amendment, dated as of August 17,
1999, and Second Amendment effective March 2000 (incorporated by
reference to Exhibit 10.50 of the Company's Registration Statement No.
333-101699 dated December 6, 2002).
10.51 MidAmerican Energy Holdings Company Executive Voluntary Deferred
Compensation Plan (incorporated by reference to Exhibit 10.51 of the
Company's Registration Statement No. 333-101699 dated December 6,
2002).
10.52 MidAmerican Energy Company First Amended and Restated Supplemental
Retirement Plan for Designated Officers dated as of May 10, 1999
(incorporated by reference to Exhibit 10.52 of the Company's
Registration Statement No. 333-101699 dated December 6, 2002).
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10.53 MidAmerican Energy Company Restated Executive Deferred Compensation
Plan (incorporated by reference to Exhibit 10.6 to the Company's
Annual Report on Form 10-K/A for the year ended December 31, 1999).
10.54 MidAmerican Energy Holdings Company Restated Deferred Compensation
Plan-Board of Directors (incorporated by reference to Exhibit 10 to
the Company's Quarterly Report on Form 10-Q for the quarter ended June
30, 1999).
10.55 MidAmerican Energy Company Combined Midwest Resources/Iowa Resources
Restated Deferred Compensation Plan-Board of Directors (incorporated
by reference to Exhibit 10.63 to the Company's Annual Report on Form
10-K/A for the year ended December 31, 1999).
10.56 Midwest Resources Inc. Supplemental Retirement Plan (formerly the
Midwest Energy Company Supplemental Retirement Plan (incorporated by
reference to Exhibit 10.10 to the Midwest Resources Inc. Annual Report
on Form 10-K for the year ended December 31, 1993, Commission File No.
1-10654).
10.57 Amendment No. 1 to the Midwest Resources Inc. Supplemental Retirement
Plan (incorporated by reference to Exhibit 10.24 to the Midwest
Resources Inc. Annual Report on Form 10-K for the year ended December
31, 1994, Commission File No. 1-10654).
10.58 Iowa-Illinois Gas and Electric Company Supplemental Retirement Plan
for Designated Officers, as amended as of July 28, 1994 (incorporated
by reference to the Iowa-Illinois Gas and Electric Company Annual
Report on Form 10-K for the year ended December 31, 1994, Commission
File No. 1-3573).
10.59 Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for
Designated Officers, as amended as of July 1, 1993 (incorporated by
reference to Exhibit 10.K.2 to the Iowa-Illinois Gas and Electric
Company Annual Report on Form 10-K for the year ended December 31,
1993, Commission File No. 1-3573).
10.60 Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for
Key Employees, dated as of April 26, 1991 (incorporated by reference
to the Iowa-Illinois Gas and Electric Company Annual Report on Form
10-K for the year ended December 31, 1991, Commission File No.
1-3573).
10.61 Iowa-Illinois Gas and Electric Company Board of Directors'
Compensation Deferral Plan (incorporated by reference to Exhibit
10.K.4 to the Iowa-Illinois Gas and Electric Company Annual Report on
Form 10-K for the year ended December 31, 1992, Commission File No.
1-3573).
10.62 Iowa Utilities Board Settlement Agreement among MidAmerican Energy
Company, Office of Consumer Advocate, Iowa Energy Consumers, Aluminum
Company of America, Deere & Company, Cargill Inc., U.S. Gypsum
Company, Interstate Power Company and IES Utilities, Inc.
(incorporated by reference to Exhibit 10.16 to the MidAmerican
Funding, LLC and MidAmerican Energy Company respective Annual Reports
on the combined Form 10-K for the year ended December 31, 2000,
Commission File Nos. 333-90553 and 1-11505, respectively).
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10.63 Share Sale Agreement, dated as of August 6, 2001, among NPower
Yorkshire Limited, Innogy Holdings plc, CE Electric UK plc and
Northern Electric plc (incorporated by reference to Exhibit 10.63 of
the Company's Registration Statement No. 333-101699 dated December 6,
2002).
10.64 Purchase Agreement, dated as of March 7, 2002, among The Williams
Companies, Inc., Williams Gas Pipeline Company, LLC, Williams Western
Pipeline Company LLC, Kern River Acquisition, LLC and the Company, KR
Holding, LLC, KR Acquisition 1, LLC and KR Acquisition 2, LLC
(incorporated by reference to Exhibit 99.2 to the Company's Current
Report on Form 8-K dated March 28, 2002).
10.65 Stock Purchase Agreement, dated as of March 7, 2002, among The
Williams Companies, Inc., MEHC Investment, Inc. and the Company
(incorporated by reference to Exhibit 99.3 to the Company's Current
Report on Form 8-K dated March 28, 2002).
10.66 Completion Guarantee, dated as of June 21, 2002, given by the Company
to Union Bank of California, Administrative Agent (incorporated by
reference to Exhibit 99.2 to the Company's Current Report on Form 8-K
dated June 27, 2002).
10.67 Purchase and Sale Agreement, dated as of July 28, 2002, between
Dynegy Inc., NNGC Holding Company, Inc. and the Company (incorporated
by reference to Exhibit 99.2 to the Company's Current Report on Form
8-K dated July 30, 2002).
21.1 Subsidiaries of the Registrant.
24.1 Power of Attorney.
99.1 Chief Executive Officer's Certificate Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
99.2 Chief Financial Officer's Certificate Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
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