UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[ X ] Annual Report Pursuant to Section 13 or 15 (d) of
the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2001
[ ] Transition Report Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
For the transition period from _____ to _____
Commission File No. 0-25551
MIDAMERICAN ENERGY HOLDINGS COMPANY
(Exact name of registrant as specified in its charter)
Iowa 94-2213782
---- ----------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
666 Grand Avenue, Des Moines, IA 50309
-------------------------------- -----
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (515) 242-4300
--------------
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 Registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. [X]
All of the shares of MidAmerican Energy Holdings Company are held by a
limited group of private investors. As of March 28, 2002, 9,281,087 shares of
common stock were outstanding.
TABLE OF CONTENTS
PART I........................................................................3
Item 1. Business.............................................................3
General.......................................................................3
Teton Transaction.............................................................3
Business Strategy.............................................................3
Business of MEHC..............................................................4
MidAmerican Energy.....................................................4
CE Electric UK Funding.................................................8
CalEnergy Generation - Domestic.......................................12
CalEnergy Generation - Foreign....................................15
HomeServices......................................................17
Regulatory Matters...........................................................18
United States.........................................................18
United Kingdom........................................................19
Philippines...........................................................20
Environmental Regulation.....................................................20
United States.........................................................20
United Kingdom........................................................21
Employees....................................................................21
Item 2. Properties..........................................................22
Item 3. Legal Proceedings...................................................22
Item 4. Submission of Matters to a Vote of Security Holders.................26
PART II......................................................................27
Item 5. Market for Registrant's Common Equity and Related Stockholder's
Matters.............................................................27
Item 6. Selected Financial Data..............................................27
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations...............................................27
Item 7A. Qualitative and Quantitative Disclosures About Market Risk..........27
Item 8. Financial Statements and Supplementary Data..........................27
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure................................................27
PART III.....................................................................28
Item 10. Directors, Executive and Other Officers of the Company and
Significant Subsidiaries............................................28
Item 11. Executive Compensation..............................................30
Item 12. Security Ownership of Certain Beneficial Owners and Management......34
Item 13. Certain Relationships and Related Transactions......................35
PART IV......................................................................36
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K....36
SIGNATURES...................................................................99
EXHIBIT INDEX...............................................................101
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 with
publicly traded fixed income securities. Through its subsidiaries, MidAmerican
Energy Company ("MidAmerican Energy") and CE Electric UK Funding, the Company
currently serves approximately 4.3 million electricity customers and 652,000
natural gas customers worldwide. In addition, through its subsidiaries, the
Company owns interests in over 10,000 megawatts ("MW") of diversified power
generation facilities in operation, construction and development. The Company's
Senior unsecured obligations have received investment grade ratings of Baa3,
BBB- and BBB from Moody's Investor Services Inc. ("Moody's"), Standard & Poors
Ratings Services ("S&P") and Fitch ("Fitch"). The Company's utility subsidiaries
are also investment grade rated by Moody's, S&P and Fitch: MidAmerican Energy
(A3, A- and AA-), Northern Electric, plc (A3, A- and A-) and Yorkshire
Electricity Group, plc (A3, A- and A-).
In this Annual Report, 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.
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 was initially incorporated in 1971 under the laws of the State of
Delaware. The Company was reincorporated in 1999 in Iowa.
Teton Transaction
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,
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 became the
sole shareholders of the Company in a "going private" transaction.
Business Strategy
The opportunity for independent power generation and energy distribution and
supply is a global competitive market as many countries have initiated
restructuring and privatization policies that encourage the development of
independent power generation and independent distribution and supply of energy.
The movement toward privatization in some developing countries has created new
markets. The need for economic expansion has caused many countries to select
private power development as their only practical alternative and to restructure
their legislative and regulatory systems to facilitate such development. The
Company intends to evaluate opportunities in these markets and to develop,
construct and acquire power generation, distribution and supply and related
energy projects meeting its strategic criteria both inside and outside the
United States. In addition, as privatization, deregulation and restructuring
initiatives are enacted in various countries and states, the Company will
evaluate opportunities to acquire power generation, distribution and supply
assets, as well as other energy related infrastructure assets.
In pursuing its strategy, the Company presently intends to focus upon
development and acquisition opportunities in countries possessing
characteristics that meet the Company's general investment criteria. At the
present time, the Company is active in the United States, the Philippines and
the United Kingdom.
Business of MEHC
The Company is a United States-based privately owned global energy
company with publicly traded 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, the
Company is organized and managed on five separate platforms: MidAmerican Energy,
CE Electric UK Funding, CalEnergy Generation-Domestic, CalEnergy
Generation-Foreign, and HomeServices.
MidAmerican Energy
MidAmerican Energy is the largest energy company headquartered in Iowa,
with assets at December 31, 2001 and 2001 revenues totaling $3.6 billion and
$2.7 billion, respectively. 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 Iowa, Illinois and South Dakota. It also
distributes natural gas at retail in Iowa, Illinois, South Dakota and Nebraska.
As of December 31, 2001, MidAmerican Energy had 673,000 retail electric
customers and 652,000 retail natural gas customers.
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 residential, agricultural, commercial and
diversified industrial customer group, in which no single industry or customer
accounted for more than 4% of its total 2001 electric operating revenues or 4%
of its total 2001 gas operating margin. Among the primary industries served by
MidAmerican Energy are those which 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, 2001, MidAmerican Energy derived
approximately 48% of its gross operating revenues from its regulated electric
business, 32% from its regulated gas business and 20% from its nonregulated
business activities. For 2000 and 1999, the corresponding percentages were 48%
electric, 37% gas and 15% nonregulated; and 63% electric, 30% gas and 7%
nonregulated, respectively. The change in revenue mix is principally driven by
an increase in natural gas prices and in nonregulated natural gas sales
activity.
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 2001, 38% of MidAmerican Energy's regulated
electric revenues were reported in the months of June, July, August and
September, and 59% of MidAmerican Energy's regulated gas 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 nonregulated wholesale and retail natural gas. The
energy delivery segment derives its revenue principally from the delivery of
retail 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 nonregulated sales of natural gas
and electricity.
The following tables present historical regulated electric sales data
related to customer class and jurisdictions.
Total Regulated Electric Sales of MidAmerican Energy By Customer Class
2001 2000 1999
Residential 20.6% 20.7% 21.0%
Small General Service 15.3 15.9 16.7
Large General Service 25.8 28.6 26.9
Other 7.3 5.4 4.5
Sales for Resale 31.0 29.4 30.9
----- ----- -----
Total 100.0% 100.0% 100.0%
====== ====== ======
Regulated Retail Electric Sales of MidAmerican Energy By State
2001 2000 1999
Iowa 88.6% 89.3% 88.9%
Illinois 10.6 10.0 10.4
South Dakota 0.8 0.7 0.7
------ ------ ------
Total 100.0% 100.0% 100.0%
====== ====== ======
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 August 2001, MidAmerican Energy recorded an hourly peak demand of
3,758 MW, which is 75 MW less than MidAmerican Energy's previous record hourly
peak of 3,833 MW set in 1999.
The following table sets out certain information concerning various MidAmerican
Energy power generation facilities:
- ------------------------- -------- ------- ------- ---------- ------------
Operating Project(1) Facility Net MW Fuel Location Commercial
Net MW Owned(2) Operation
- ------------------------- -------- ------- ------- ---------- ------------
Council Bluffs Energy
Center units 1 & 2 131 131 Coal Iowa 1954, 1958
- ------------------------- -------- ------- ------- ---------- ------------
Council Bluffs Energy
Center unit 3 675 534 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 4 624 261 Coal Iowa 1979
- ------------------------- -------- ------- ------- ---------- ------------
Ottumwa Generation
Station 708 368 Coal Iowa 1981
- ------------------------- -------- ------- ------- ---------- ------------
Quad Cities
Generating Station 1,529 383 Nuclear Illinois 1972
- ------------------------- -------- ------- ------- ---------- ------------
Riverside Generation
Station 135 135 Coal Iowa 1925-61
- ------------------------- -------- ------- ------- ---------- ------------
Combustion Turbines 789 789 Gas/Oil Iowa 1969-95
- ------------------------- -------- ------- ------- ---------- ------------
Moline Water Power 3 3 Hydro Illinois 1970
- ------------------------- -------- ------- ------- ---------- ------------
Cooper Nuclear Station(3) 758 379 Nuclear Nebraska 1974
- ------------------------- -------- ------- ------- ---------- ------------
Portable Power Modules 56 56 Oil Iowa 2000
- ------------------------- -------- ------- ------- ---------- ------------
Total Operating Power
Generation Facilities 7,058 4,461
- ------------------------- -------- ------- ------- ---------- ------------
Projects Under
Construction:
- ------------------------ --------- ------- ------- ---------- ------------
Greater Des Moines
Energy Center 540 540 Gas Iowa 2003-05
- ------------------------ --------- ------- ------- ---------- ------------
Total Power
Generation Facilities 7,598 5,001
- ------------------------ --------- ------- ------- ---------- ------------
(1) The Company operates all such power generation facilities other than Quad
Cities Generating Station, Ottumwa Generation Station and Cooper Nuclear
Station.
(2) Actual MW may vary depending on operating and reservoir conditions and plant
design. Facility Net Capacity (in MW) represents facility gross capacity (in
MW) less parasitic load. Parasitic load is electrical output used by the
facility and not made available for sale to utilities or other outside
purchasers. Net MW owned indicates current legal ownership, but, in some cases,
does not reflect the current allocation of partnership distributions.
(3) Cooper is owned by the Nebraska Public Power District and the amount shown
is MidAmerican Energy's entitlement (50%) of Cooper's accredited capacity under
a power purchase contract extending to September 2004.
MidAmerican Energy's accredited net generating capability in the summer
of 2001 was 4,735 MW. Accredited net generating capability represents the amount
of generation available to meet the requirements on MidAmerican Energy's energy
system, net of the effect of capacity purchases and sales, and consists of
Company-owned generation and generation under power purchase contracts. 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.
On July 10, 2001, MidAmerican Energy announced plans to develop and con-
struct two electric generating plants in Iowa, requiring an investment of
approximately $1.8 billion. Participation by others in a portion of the second
plant is being discussed. The two plants will provide approximately 1,400
megawatts of generating capacity. MidAmerican Energy expects to begin
construction in the Spring 2002 on the first project, the Greater Des Moines
Energy Center, a 540-megawatt natural gas-fired combined cycle unit that has an
estimated cost of $416 million. It is anticipated that the first phase of the
project will be completed in 2003 with the remainder being completed in 2005.
MidAmerican Energy presently expects that all utility construction expenditures
for the next five years will be met with the issuance of long-term debt and cash
generated from utility operations, net of dividends. The actual level of cash
generated from utility operations is affected by, among other things, economic
conditions in the utility service territory, weather and federal and state
regulatory actions.
MidAmerican Energy is interconnected with Iowa utilities and utilities
in neighboring states and is involved in an electric power pooling agreement
known as Mid-Continent Area Power Pool ("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.
MidAmerican Energy's reserve margin at peak demand for 2001 was approximately
25%. However, significantly higher-than-normal temperatures during the cooling
season could cause MidAmerican Energy's reserve to fall below the 15% minimum.
If MidAmerican Energy fails to maintain the appropriate reserve, significant
penalties could be contractually imposed by MAPP.
MidAmerican Energy's transmission system connects its generating
facilities with distribution substations and interconnects with 14 other
transmission providers in Iowa and five adjacent states. Under normal operating
conditions, MidAmerican Energy's transmission system 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 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. FERC approval of the plan is pending. 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.
Gas Operations
The following tables present historical regulated gas sales data,
excluding transportation throughput, related to customer class and
jurisdictions.
Total Regulated Gas Sales of MidAmerican Energy By Customer Class
2001 2000 1999
Residential 34.5% 34.9% 39.1%
Small General Service 18.2 17.4 19.8
Large General Service 1.5 2.2 2.4
Other 1.7 1.2 1.7
Sales for Resale 44.1 44.3 37.0
------ ------- ------
Total 100.0% 100.0% 100.0%
====== ======= ======
Regulated Retail Gas Sales of MidAmerican Energy By State
2001 2000 1999
Iowa 78.9% 78.0% 78.8%
Illinois 9.8 10.2 10.3
South Dakota 10.5 11.0 10.1
Nebraska 0.8 0.8 0.8
------ ------ ------
Total 100.0% 100.0% 100.0%
====== ====== ======
On February 2, 1996, MidAmerican Energy had its highest natural gas
peak-day delivery of 1,143,026 MMBtus. This peak-day delivery consisted of
approximately 88% traditional sales service and 12% transportation service of
customer-owned gas. MidAmerican Energy's 2001/2002 winter heating season
peak-day delivery of 932,615 MMBtus was reached on March 3, 2002. This peak-day
delivery included approximately 73% traditional sales service and 27%
transportation service.
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 Iowa Utilities Board
("IUB") and South Dakota Public Utility 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 the purchased gas adjustment clause.
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, which currently
has been extended through 2002. Under the program, as amended, MidAmerican
Energy is required to file with the IUB every six months a comparison of its gas
procurement costs to an index-based reference price. If MidAmerican Energy's
cost of gas for the period is less or greater than an established tolerance band
around the reference price, then MidAmerican Energy shares a portion of the
savings or costs with customers. A similar program is in effect in South Dakota.
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 require-
ments 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.
CE Electric UK Funding
The business of CE Electric UK Funding consists of Northern Electric plc
("Northern"), Yorkshire Power Group Ltd. ("Yorkshire"), and CalEnergy Gas
(Holdings) Limited ("CE Gas").
Yorkshire Swap
On September 21, 2001, CE Electric UK Ltd., an indirect wholly owned
subsidiary of the Company, and Innogy Holdings, plc closed an agreement to
exchange Northern's electricity and gas supply and metering assets for Innogy's
94.75% interest in Yorkshire's electricity distribution business. Northern's
supply business was initially valued at approximately $430 million ((pound)295
million), including working capital of approximately $53 million ((pound)37
million). 94.75% of Yorkshire's distribution business was initially valued at
approximately $395 million ((pound)271 million), including working capital of
approximately $48 million ((pound)33 million). The net cash received by Northern
for the exchange was approximately $35 million ((pound)24 million). Working
capital is subject to adjustment and is currently under review.
The Company paid $37.4 million, net of cash acquired of $362.8 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. This transaction
provides the opportunity to build on Northern and Yorkshire's strong reputations
for customer satisfaction by bringing together the skills and resources of two
neighboring distribution businesses to create one of the largest distribution
companies in the U.K., serving more than 3.6 million customers in an area of
approximately 10,000 square miles.
Electricity Distribution
Northern's and Yorkshire's operations consist primarily of the distribu-
tion of electricity and other auxiliary businesses in the United Kingdom.
Through September 21, 2001, Northern's operations also included the supply of
electricity and natural gas and the related metering business.
Northern and Yorkshire receive electricity from the national grid
transmission system and distribute it to customers' premises using their network
of transformers, switchgear and cables. Substantially all of the customers in
their distribution service areas are connected to their network and can only be
delivered through their distribution system, thus providing Northern and
Yorkshire with distribution volume that is stable from year to year. Northern
and Yorkshire charge access fees for the use of the distribution system. The
prices for distribution 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.
Integrated Utility Services Limited ("IUS"), a subsidiary of Northern,
is an engineering company whose main role is to provide electrical connection
services on behalf of CE Electric UK Funding's distribution businesses and to
provide electrical infrastructure contracting services to third parties. The
acquisition by CE Electric UK Funding in 2001 of Yorkshire has presented IUS the
opportunity to integrate all Yorkshire and external work into IUS thereby
creating one of the largest electricity connection companies in the UK. The
focus for IUS is to achieve the full integration of the connections businesses.
To achieve this aim, IUS has already commenced with the establishment of a
customer services operations center at Middlesbrough and the commissioning of a
dedicated data management and telephone system to facilitate these objectives.
Northern Electric Generation Limited ("Northern Generation"), a CE
Electric UK Funding subsidiary, primarily focuses on electricity generation,
mainly through its ownership in Teesside (described below) and its operation and
ownership of Viking (described below).
Teesside. Teesside Power Limited ("Teesside") owns and operates an
1,875 net MW combined cycle gas-fired power plant at Wilton. Northern Generation
owns a 15.4% interest in Teesside, but does not operate the plant. Enron Corp.
("Enron"), through its subsidiaries, owned a 42.5% interest, operated the plant,
and purchased 668 MW of capacity. Enron's subsidiary, who owns and operates
Teesside, is now in administration and administrators have been appointed to run
its business and are attempting to find a buyer.
As a result of Enron's subsidiary being in administration, Teesside is
in discussion with its lenders over a restructuring of the (pound)650 million
debt still outstanding. It is anticipated that there will be no further
dividends arising from this investment and, as a result, Northern Generation has
written off its equity investments as they were estimated to be of negligible
value.
Viking. Northern Generation owns 50% of this 50 MW gas-fired mid merit
power plant located on Teesside. The plant is currently in the commissioning
stage, however due to combustor issues it is unable to pass the performance
criteria required for hand-over. Northern Generation is being held financially
whole by the turnkey contractor (Rolls Royce) until the plant is fit for purpose
at which time the plant will be operated by Northern Generation. CE Electric UK
Funding is currently negotiating to sell Viking to Rolls Royce for a value
consistent with the original investment appraisal.
Northern Electric Retail Limited ("Northern Retail"), a subsidiary of
CE Electric UK Funding, sells electrical and gas appliances.
Gas Exploration and Production
CE Gas is a gas exploration and production company which 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. CE Gas holds various interests
in the southern basin of the United Kingdom sector of the North Sea, as shown
below. CE Gas has also been involved in certain gas development and exploration
activities relating to a large gas field prospect in Poland, the EP389
concession in the Perth Basin in Australia and the Yolla discovery in the Bass
Basin of Australia.
Share of 2001 Avg.
Remaining Net Current %
Reserves Production Working Commenced
Producing Gas Fields BCF(1) MMscf/d(2) Interest Production Location Gas Purchaser
- -------------------- --------- ---------- --------- ---------- -------- -------------
Anglia 61.0 13.5 55.000% 11/1991 U.K. Offshore (North Sea) Innogy plc
Windermere 6.2 3.9 20.000% 4/1997 U.K. Offshore (North Sea) N.V. Nederland's
Gasunic
Victor 7.7 3.5 5.000% 9/1984 U.K. Offshore (North Sea) British Gas
Trading Ltd.
Schooner 16.7 3.4 4.820% 10/1996 U.K. Offshore (North Sea) Innogy plc
Johnston 23.4 10.1 22.113% 10/1994 U.K. Offshore (North Sea) TXU Europe Energy
Trading Limited
Fields in Development Size Km2
- --------------------- --------
Pila Area Concession 9,480 N/A 100.000% N/A N.W. Poland (Polish Trough)
EP389 2,092 N/A 40.789% N/A S.W. Australia Onshore (Perth
Basin)
EP411 1,360 N/A 33.000% N/A S.W. Australia Onshore (Perth
Basin)
EP415 1,680 N/A 33.000% N/A S.W. Australia Onshore (Perth
Basin)
Yolla Discovery 550 N/A 20.000% N/A S.E. Australia Offshore (Bass
Basin)
Otway Basin 775 N/A 25.000% N/A S.E. Australia Offshore (Otway
Basin)
(1) Gas reserves in Billion cubic feet (or "Bcf") as of January 1, 2002. The
classification "Remaining" means reserves which geophysical, geological and
engineering data indicate to be in place or recoverable (as the case may be)
with a 50% probability the reserves will exceed the estimate.
(2) Million standard cubic feet per day.
CalEnergy Generation - Domestic
The following table sets out certain information concerning various domestic
independent power projects in operation.
- -------------------- -------- ------- ----- ------------ ---------- ------------
Project Facility Net MW Fuel Location Commercial Power
Net MW Owned1 Operation Purchaser2
- -------------------- -------- ------- ----- ------------ ---------- ------------
Cordova 537 537 Gas Illinois 2001 El Paso/MEC
- -------------------- -------- ------- ----- ------------ ---------- ------------
Salton Sea I 10 5 Geo California 1987 Edison
- -------------------- -------- ------- ----- ------------ ---------- ------------
Salton Sea II 20 10 Geo California 1990 Edison
- -------------------- -------- ------- ----- ------------ ---------- ------------
Salton Sea III 50 25 Geo California 1989 Edison
- -------------------- -------- ------- ----- ------------ ---------- ------------
Salton Sea IV 40 20 Geo California 1996 Edison
- -------------------- -------- ------- ----- ------------ ---------- ------------
Salton Sea V 49 25 Geo California 2000 El Paso/Zinc
- -------------------- -------- ------- ----- ------------ ---------- ------------
Vulcan 34 17 Geo California 1986 Edison
- -------------------- -------- ------- ----- ------------ ---------- ------------
Elmore 38 19 Geo California 1989 Edison
- -------------------- -------- ------- ----- ------------ ---------- ------------
Leathers 38 19 Geo California 1990 Edison
- -------------------- -------- ------- ----- ------------ ---------- ------------
Del Ranch 38 19 Geo California 1989 Edison
- -------------------- -------- ------- ----- ------------ ---------- ------------
CE Turbo 10 5 Geo California 2000 El Paso/Zinc
- -------------------- -------- ------- ----- ------------ ---------- ------------
Saranac 240 90 Gas New York 1994 NYSEG
- -------------------- -------- ------- ----- ------------ ---------- ------------
Power Resources 200 100 Gas Texas 1988 TXU
- -------------------- -------- ------- ----- ------------ ---------- ------------
Yuma 50 25 Gas Arizona 1994 SDG&E
- -------------------- -------- ------- ----- ------------ ---------- ------------
Roosevelt Hot
Springs 23 17 Geo Utah 1984 UP&L
- -------------------- -------- ------- ----- ------------ ---------- ------------
Total CalEnergy
Generation -
Domestic Operations 1,377 933
- -------------------- -------- ------- ----- ------------ ---------- ------------
1 Actual MW may vary depending on operating and reservoir conditions and plant
design. Facility Net Capacity (in MW) represents facility gross capacity (in MW)
less parasitic load. Parasitic load is electrical output used by the facility
and not made available for sale to utilities or other outside purchasers. Net MW
owned indicates current legal ownership, but, in some cases, does not reflect
the current allocation of partnership distributions.
2 Southern California Edison Company ("Edison"); San Diego Gas & Electric
Company ("SDGandE"); Utah Power & Light Company ("UP&L"); New York State
Electric & Gas Corporation ("NYSEG"); TXU Generation Company LP ("TXU"); Zinc
Recovery Project ("Zinc"); El Paso Corporation ("El Paso") and MidAmerican
Energy Company ("MEC").
Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned
subsidiary of the Company, operates a 537 MW gas-fired power plant in the Quad
Cities, Illinois area (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 Corporation ("El Paso") in which El Paso will
purchase all of the capacity and energy from the project until December 31,
2019. Cordova Energy exercised an option under the El Paso power purchase
agreement to callback 50% of the project output for sales to others for the
contract years ending on or prior to May 14, 2004. Cordova Energy subsequently
entered into a power purchase agreement with MidAmerican Energy whereby
MidAmerican Energy will purchase 50% of the capacity and energy from the Cordova
Project until May 14, 2004.
The Company has a 50% ownership interest in CE Generation LLC ("CE
Generation") which has interests in ten geothermal plants in the Imperial
Valley, California and three natural gas-fired cogeneration plants. For purposes
of consistent presentation, plant capacity factors for Vulcan, Hoch (Del Ranch),
Turbo, Elmore and Leathers (collectively the "Partnership Projects") are based
on capacity amounts of 34, 38, 10, 38, and 38 net MW, respectively, and for
Salton Sea I, Salton Sea II, Salton Sea III, Salton Sea IV and Salton Sea V
plants (collectively the "Salton Sea Projects") are based on capacity amounts of
10, 20, 50, 40 and 49 net MW, respectively (the Partnership Projects and the
Salton Sea Projects are collectively referred to as the "Imperial Valley
Projects"). Plant capacity factors for Saranac, Power Resources and Yuma
(collectively the "Gas Plants") are based on capacity amounts of 240, 200, and
50 net MW, respectively. Each plant possesses an operating margin that allows
for production in excess of the amount listed above. 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.
Imperial Valley Projects. The Vulcan Project, Hoch (Del Ranch) Project,
Elmore Project, Leathers Project, Salton Sea II Project and the Salton Sea III
Project sell electricity to Southern California Edison Company ("Edison") under
30-year Standard Offer No. 4 Agreements ("SO4 Agreements"). Under the SO4
Agreements, Edison is obligated to pay capacity payments, capacity bonus
payments and energy payments. The price for contract capacity payments is fixed
for the life of such SO4 Agreement. The contract energy payment was fixed for
the first ten years. The fixed price periods for the Vulcan, Del Ranch, Elmore,
Leathers, Salton Sea II and Salton Sea III Projects expired in February 1996,
January 1999, December 1998, December 1999, April 2000, and February 1999,
respectively. Thereafter, the energy payments are based on the cost Edison
avoids by purchasing energy from the projects 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 is 3.25 cents per kWh from December 1, 2001 through April
30, 2002 and 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.
The Salton Sea I Project and Salton Sea IV Project have negotiated
contracts with Edison. The Salton Sea I contract provides for a capacity payment
and energy payment for the life of the contract. Both payments are based upon an
initial value that is subject to quarterly adjustment by reference to various
inflation-related indices. The Salton Sea IV contract also provides for fixed
price capacity payments for the life of the contract. Approximately 56% of the
kWhs are sold under the Salton Sea IV Power Purchase Agreement at a fixed energy
price, which is subject to quarterly adjustment by reference to various
inflation-related indices, through June 20, 2017 (and at Edison's Avoided Cost
of Energy thereafter), while the remaining 44% of the Salton Sea IV Project kWhs
are sold according to a 10-year fixed price schedule followed by payments based
on a modified Avoided Cost of Energy for the succeeding 5 years and at Edison's
Avoided Cost of Energy thereafter.
The Salton Sea V Project began operations in 2000 and will sell approxi-
mately one-third of its net output to the Zinc Recovery Project which is
expected to become operational in 2002. The remainder is being sold through
other market transactions.
The net output of the Turbo Project is being sold through market trans-
actions but may be sold to the Zinc Recovery Project when completed.
Yuma Project. The Yuma Project is a 50 net MW natural gas-fired
cogeneration project in Yuma, Arizona providing 50 MW of electricity to San
Diego Gas & Electric Company ("SDG&E") under an existing 30-year power purchase
agreement ("Yuma PPA"). The project entity, Yuma Cogeneration Associates
("YCA"), has executed steam sales contracts with an adjacent industrial entity
to act as its thermal host. Since the industrial entity has the right under its
agreement to terminate the agreement upon one year's notice if a change in its
technology eliminates its need for steam, and in any case to terminate the
agreement at any time upon three years notice, there can be no assurance that
the Yuma Project will maintain its status as a qualifying facility ("QF").
However, if the industrial entity terminates the agreement, YCA anticipates that
it will be able to locate an alternative thermal host in order to maintain its
status as a QF.
Saranac Project. 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 (the "Saranac PPA") with New
York State Electric & Gas ("NYSEG"). The Saranac Project is a QF and has entered
into 15-year steam purchase agreements (the "Saranac Steam Purchase Agreements")
with Georgia-Pacific Corporation and Tenneco Packaging, Inc. The Saranac Project
has a 15-year natural gas supply agreement (the "Saranac Gas Supply Agreement")
with Shell Canada Limited ("Shell Canada") to supply 100% of the Saranac
Project's fuel requirements. Shell Canada is responsible for production and
delivery of natural gas to the U.S.-Canadian border; the gas is then transported
by the North Country Gas Pipeline Corporation ("NCGP") the remaining 22 miles to
the plant. NCGP is a wholly-owned subsidiary of Saranac Power Partners, L.P.
(the "Saranac Partnership"), which also owns the Saranac Project. NCGP also
transports gas for NYSEG and Georgia-Pacific. Each of the Saranac PPA, the
Saranac Steam Purchase Agreements and the Saranac Gas Supply Agreement contains
rates that are fixed for the respective contract terms. Revenues escalate at a
higher rate than fuel costs. The Saranac Partnership is indirectly owned by
subsidiaries of CE Generation, Tomen Corporation and General Electric Capital
Corporation.
Power Resources Project. 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 (the "Power Resources PPA") with TXU
Generation Company LP, formerly known as Texas Utilities Electric Company. The
Power Resources Project is a QF and the project entity, Power Resources Ltd.
("Power Resources"), has entered into a 15-year steam purchase agreement (the
"Power Resources Steam Purchase Agreement") with Fina Oil and Chemical Company
("Fina"), a subsidiary of Petrofina S.A. of Belgium. Power Resources has entered
into an agreement (the "CE Texas Gas Supply Agreement") with CE Texas Gas L.P.
("CE Texas Gas") for Power Resources' fuel requirements through December 2003.
In June 1995, CE Texas Gas and Louis Dreyfus Natural Gas Corp. ("Dreyfus")
executed an eight-year natural gas supply agreement (the "CE Texas Gas-Dreyfus
Gas Supply Agreement"), with which CE Texas Gas will fulfill its supply
commitment to Power Resources from October 1995 to the end of the term of the
Power Resources PPA. Each of the Power Resources PPA, the Power Resources Steam
Purchase Agreement and the CE Texas Gas-Dreyfus Gas Supply Agreement contains
rates that are fixed for the respective contract terms. Revenues escalate at a
higher rate than fuel costs.
Roosevelt Hot Springs. A subsidiary of the Company operates and owns an
approximately 70% indirect interest in a geothermal steam field which supplies
geothermal steam to a 23 net MW power plant owned by Utah Power & Light Company
("UP&L") located on the Roosevelt Hot Springs property under a 30-year steam
sales contract. The Company obtained approximately $20.3 million of cash under a
pre-sale agreement with UP&L whereby UP&L paid in advance for the steam produced
by the steam field. 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. The Company owns the rights to proprietary
processes for the extraction of minerals from elements in solution in the
geothermal brine and fluids utilized at its Imperial Valley plants. A pilot
plant has successfully produced commercial quality zinc at the Company's
Imperial Valley Projects.
CalEnergy Minerals LLC, an indirect wholly owned subsidiary of the
Company, is constructing the Zinc Recovery Project which will recover zinc from
the geothermal brine (the "Zinc Recovery Project"). Facilities are being
installed near the Imperial Valley Project's sites to extract a zinc chloride
solution from the geothermal brine through an ion exchange process. This
solution will be transported to a central processing plant where zinc ingots
will be 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 and is scheduled to commence
commercial operations in 2002. In September 1999, CalEnergy Minerals LLC entered
into a sales agreement whereby all zinc produced by the Zinc Recovery Project
will be sold to Cominco, Ltd. The initial term of the agreement expires in
December 2005.
Salton Sea Minerals Extraction. In addition to zinc recovery, the
Company intends to sequentially develop manganese, silver, gold, lead, boron,
lithium and other products as it further develops the extraction technology. If
successfully developed for the other products, the mineral extraction process
will provide an environmentally responsible and low cost minerals recovery
methodology.
CalEnergy Generation - Foreign
The following table sets out certain information concerning various foreign
independent power projects in operation.
- ------------------- -------- ------ ----- ----------- ---------- -------- ------------ ---------
Political
Facility Net MW Commercial U.S. $ Power Risk
Project Net MW Owned(1) Fuel Location Operation Payments Purchaser(2) Insurance
- ------------------- -------- ------ ----- ----------- ---------- -------- ------------- --------
Mahanagdong 165 149 Geo Philippines 1997 Yes PNOC-EDC GOP Yes
- ------------------- -------- ------ ----- ----------- --------- -------- ------------- ---------
Malitbog 216 216 Geo Philippines 1996-97 Yes PNOC-EDC GOP Yes
- ------------------- -------- ------ ----- ------------ --------- -------- ------------- --------
Upper Mahiao 119 119 Geo Philippines 1996 Yes PNOC-EDC GOP Yes
- ------------------- -------- ------ ----- ----------- ---------- -------- ------------- --------
Casecnan 150 150(3) Hydro Philippines 2001 Yes NIA GOP Yes
- ------------------- -------- ------ ----- ----------- ---------- -------- ------------- --------
Total CalEnergy
Generation -
Foreign Operations 650 634
- ------------------- -------- ------ ------ ---------- ---------- -------- ------------- --------
(1) Actual MW may vary depending on operating and reservoir conditions and plant
design. Facility Net Capacity (in MW) represents facility gross capacity (in MW)
less parasitic load. Parasitic load is electrical output used by the facility
and not made available for sale to utilities or other outside purchasers. Net MW
owned indicates current legal ownership, but, in some cases, does not reflect
the current allocation of partnership distributions.
(2) PNOC - Energy Development Corporation ("PNOC-EDC"); Government of the
Philippines ("GOP") and Philippine National Irrigation Administration ("NIA")
(NIA also purchases water from this facility). The Government of the Philippine
undertaking supports PNOC-EDC's and NIA's respective obligations.
(3) Subject to certain repurchase rights by the initial minority shareholders
The Company indirectly owns the Upper Mahiao, Malitbog and Mahanagdong
Projects (collectively, the "Leyte 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. The Casecnan Project
commenced commercial operations on December 11, 2001. For purposes of consistent
presentation, capacity amounts for Upper Mahiao, Malitbog, Mahanagdong and
Casecnan are 119, 216, 165 and 150 net MW, respectively. Each plant possesses an
operating margin that allows for production in excess of the amount listed
above. 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.
Upper Mahiao. The Upper Mahiao facility 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 an energy conversion agreement executed on September
6, 1993 (the "Upper Mahiao ECA"), 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
("PNOC-EDC") at no cost.
The Upper Mahiao Project is located on land provided by PNOC-EDC at no
cost. It 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. Specifically, PNOC-EDC is obligated to pay for 100% of
the electric capacity that is nominated each year by CE Cebu, irrespective of
whether PNOC-EDC is willing or able to accept delivery of such capacity.
PNOC-EDC pays to CE Cebu a fee (the "Capacity 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 revenues) and a fee (the "Energy Fee") based
on the electricity actually delivered to PNOC-EDC (approximately 5% of total
contract revenues). Payments under the Upper Mahiao ECA are denominated in U.S.
dollars, or computed in U.S. dollars and paid in Philippine pesos at the
then-current exchange rate, except for the Energy Fee. Significant portions of
the Capacity Fee and Energy Fee are indexed to U.S. and Philippine inflation
rates, respectively. PNOC-EDC's payment requirements, and its other obligations
under the Upper Mahiao ECA, are supported by the Government of the Philippines
through a performance undertaking.
The payment of the Capacity Fee is not excused if PNOC-EDC fails to
deliver or remove the steam or fluids or fails to provide the transmission
facilities, even if its failure was caused by a force majeure event (e.g., war,
nationalization, etc.). In addition, PNOC-EDC must continue to make Capacity Fee
payments if there is a force majeure event that affects the operation of the
Upper Mahiao Project and that is within the reasonable control of PNOC-EDC or
the Government of the Philippines or any agency or authority thereof.
PNOC-EDC is obligated to purchase CE Cebu's interest in the facility
under certain circumstances, including (i) extended outages resulting from the
failure of PNOC-EDC to provide the required geothermal fluid, (ii) certain
material changes in policies or laws which adversely affect CE Cebu's interest
in the project, (iii) transmission failure, (iv) failure of PNOC-EDC to make
timely payments of amounts due under the Upper Mahiao ECA, (v) privatization of
PNOC-EDC or NPC, and (vi) certain other events. The price will be the net
present value (at a discount rate based on the last published Commercial
Interest Reference Rate of the Organization for Economic Cooperation and
Development) of the total remaining amount of Capacity Fees over the remaining
term of the Upper Mahiao ECA.
Mahanagdong. 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 100% of the common stock is
indirectly owned by the Company. Another industrial company owns an approximate
10% preferred equity interest in the 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 Philippine National
Power Corporation ("NPC") for distribution to the island of Luzon.
The terms of an energy conversion agreement executed on September 18,
1993 (the "Mahanagdong ECA"), are substantially similar to those of the Upper
Mahiao ECA. The Mahanagdong ECA 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 ECA are
supported by the Government of the Philippines through a performance
undertaking. The capacity fees are approximately 97% of total revenues at the
design capacity levels and the energy fees are approximately 3% of such total
revenues.
Malitbog. 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 is selling 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 NPC.
The Malitbog Project is located on land provided by PNOC-EDC at no cost.
The electrical energy produced by the facility is sold to PNOC-EDC on a take-or-
pay basis. Specifically, PNOC-EDC is obligated to make payments (the "Capacity
Payments") to VGPC based upon the available capacity of the Malitbog Project.
The Capacity Payments equal approximately 100% of total revenues. The Capacity
Payments will be payable so long as the Malitbog Project is available to produce
electricity, even if the Malitbog Project is not operating due to scheduled
maintenance, because PNOC-EDC fails to supply steam to the Malitbog Project as
required or because NPC is unable (or unwilling) to accept delivery of
electricity from the Malitbog Project. In addition, PNOC-EDC must continue to
make the Capacity Payments if there is a force majeure event (e.g., war,
nationalization, etc.) that affects the operation of the Malitbog Project and
that is within the reasonable control of PNOC-EDC or the Government of the
Philippines or any agency or authority thereof. 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 ECA from 10% of VGPC's revenues in the early years of the
Cooperation Period (as defined below) to 23% of VGPC's revenues 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 ECA carry
the full faith and credit of, and are affirmed and guaranteed by, the Government
of the Philippines.
PNOC-EDC is obligated to purchase VGPC's interest in the facility under
certain circumstances, including (i) certain material changes in policies or
laws which adversely affect VGPC's interest in the project, (ii) any event of
force majeure which delays performance by more than 90 days and (iii) certain
other events. The price will be the net present value of the capital cost
recovery fees that would have been due for the remainder of the Cooperation
Period with respect to such generating unit(s).
The Malitbog ECA cooperation period expires ten years after the date of
commencement of commercial operation of Unit III (the "Cooperation Period"). At
the end of the Cooperation Period, the facility will be transferred to PNOC-EDC
at no cost, on an "as is" basis.
Casecnan. CE Casecnan Water and Energy Company, Inc., a Philippine
corporation ("CE Casecnan") and an indirectly majority owned subsidiary of the
Company, operates the Casecnan Project, a combined irrigation and 150 net MW
hydroelectric power generation project (the "Casecnan Project"). The Casecnan
Project consists generally of diversion structures in the Casecnan and Taan
Rivers that captures and diverts excess water in the Casecnan watershed by means
of concrete, in-stream diversion weirs and transfers that water through a
transbasin tunnel of approximately 23 kilometers (including the intake audit
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 net 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 powerhouse to the Pantabangan
Reservoir, providing additional water for irrigation and increasing the
potential electrical generation at two downstream existing hydroelectric
facilities of NPC, the government-owned and controlled corporation that is the
primary supplier of electricity in the Philippines.
CE Casecnan constructed the Casecnan Project under the terms of the
Project Agreement between CE Casecnan and the National Irrigation Administration
("NIA"). Under the Project Agreement, CE Casecnan developed, financed and
constructed the Casecnan Project over the construction period, and will own and
operate the Casecnan Project for 20 years (the "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 a minimum
volume of water and a fixed fee for the delivery of a minimum amount of
electricity. In addition, NIA will pay a fee for all electricity delivered in
excess of a threshold amount up to a specified amount. 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 U.S. dollars.
The fixed fees 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 and NPC for no additional
consideration on an "as is" basis.
The Project Agreement provides for additional compensation to CE
Casecnan upon the occurrence of certain events, including increases in
Philippine taxes and adverse changes in Philippine law. Upon the occurrence and
during the continuance of certain force majeure events, including those
associated with Philippine political action, NIA may be obligated to buy the
Casecnan Project from CE Casecnan at a buy out price expected to be in excess of
the aggregate principal amount of the outstanding CE Casecnan debt securities,
together with accrued but unpaid interest.
The Republic of the Philippines has provided a performance undertaking
under which NIA's obligations under the Project Agreement are guaranteed by the
full faith and credit of the Republic of the Philippines ("Performance
Undertaking"). The Project Agreement and the Performance Undertaking provide for
the resolution of disputes by binding arbitration in Singapore under
international arbitration rules.
HomeServices
HomeServices.Com Inc. ("HomeServices"), a wholly-owned subsidiary of the
Company, is the second largest residential real estate brokerage firm in the
United States based on aggregate closed transaction sides in 2001 for its
various brokerage firm operating subsidiaries. Closed transaction sides mean
either the buy side or sell side of any closed home purchase and is the standard
term used by industry participants and publications to rank real estate
brokerage firms. In addition to providing traditional residential real estate
brokerage services, HomeServices cross sells to its existing real estate
customers preclosing services, such as mortgage origination and title services,
including title insurance, title search, escrow and other closing administrative
services, assists in securing other preclosing and postclosing services provided
by third parties, such as home warranty, home inspection, home security,
property and casualty insurance, home maintenance, repair and remodeling and is
developing various related e-commerce services. HomeServices currently operates
in the following fourteen states: Minnesota, Iowa, California, Arizona, Kansas,
Missouri, Kentucky, Nebraska, Wisconsin, Indiana, Maryland, North Dakota, South
Dakota and Georgia. HomeServices generally occupies the number one or number two
market share position in each of its major markets based on aggregate closed
transaction sides for the year ended December 31, 2001. HomeServices' major
markets consist of the following metropolitan areas: Minneapolis and St. Paul,
Minnesota; Des Moines, Iowa; Los Angeles and San Diego, California; Omaha,
Nebraska; Kansas City, Kansas; Louisville, Kentucky; Springfield, Missouri;
Tucson, Arizona; Annapolis, Maryland and Atlanta, Georgia.
Regulatory Matters
United States
Each of the operating domestic power facilities partially owned through
CE Generation meets the requirements promulgated under the Public Utility
Regulatory Policies Act ("PURPA") to be qualifying facilities. Qualifying
facility status under PURPA provides two primary benefits. First, regulations
under PURPA exempt qualifying facilities from the Public Utility Holding Company
Act of 1935, as amended ("PUHCA"), most provisions of the Federal Power Act (the
"FPA") and the state laws concerning rates of electric utilities, and financial
and organization regulations of electric utilities. Second, FERC's regulations
promulgated under PURPA require that (1) electric utilities purchase electricity
generated by qualifying facilities, 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) the electric utility sell back-up, interruptible,
maintenance and supplemental power to the qualifying facility on a
non-discriminatory basis, and (3) the electric utility interconnect with a
qualifying facility in its service territory.
Congress is considering proposed legislation that would amend PURPA by
eliminating the requirement that utilities purchase electricity from qualifying
facilities at prices based on Avoided Cost of Energy. The Company does not know
whether such legislation will be passed or what form it may take. The Company
believes that if any such legislation is passed, it would apply to new projects
only and thus, although potentially impacting the Company's ability to develop
new domestic projects, it would not affect the Company's existing qualifying
facilities. There can be no assurance, however, that any legislation passed
would not adversely impact the Company's existing domestic projects.
In addition, many states are implementing or considering regulatory
initiatives designed to increase competition in the domestic power generation
industry and increase access to electric utilities' transmission and
distribution systems for independent power producers and electricity consumers.
On September 1, 1996, the California legislature adopted an industry
restructuring bill that would provide for a phased-in competitive power
generation industry with an independent system operator and direct access to
generation for all power purchasers under certain circumstances. Under the bill,
consistent with the requirements of PURPA, the existing qualifying facilities
power sales agreements would be honored. The Company cannot predict the final
form or timing of the proposed industry restructuring or the impact on its
operations.
MidAmerican Energy is subject to comprehensive regulation by several
utility regulatory agencies that significantly influences the operating
environment and the recoverability of costs from utility customers. 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 connection with the March 1999 approval by the IUB of the MidAmerican
acquisition and March 2000 affirmation as part of the Teton Transaction, the
Company is required, among other things, to use all commercially reasonable
efforts to maintain an investment grade credit rating for MidAmerican Energy and
its long-term debt and to seek the approval of the IUB of a reasonable utility
capital structure if MidAmerican Energy's common equity level decreases below
specified levels (42% and 39%, respectively, of total capitalization) under
certain circumstances. MidAmerican Energy's common equity level at December 31,
2001 was above these levels.
With the elimination of the energy adjustment clause in Iowa,
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 1997, the Governor of Illinois signed into law a bill to
restructure Illinois' electric utility industry and transition it to a
competitive market. Under the law, larger non-residential customers in Illinois
and 33% of the remaining non-residential Illinois customers were allowed to
select their provider of electric supply services beginning in October 1, 1999.
Starting December 31, 2000, all other non-residential customers were allowed
supplier choice. Residential customers all receive the opportunity to select
their electric supplier beginning May 1, 2002.
The law also provides for Illinois earnings above a computed level of
return on common equity to 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 30-year Treasury Bond rates plus a premium
of 5.5% for 1998 and 1999 and a premium of 8.5% for 2000 through 2004. The
two-year average above which sharing must occur for 2001 was 14.34%. The law
allows MidAmerican Energy to mitigate the sharing of earnings above the
threshold return on common equity through accelerated recovery of regulatory
assets.
In December 1999, 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 FERC a plan to create TRANSLink Transmission Company LLC
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. FERC approval of the
plan is pending. 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.
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 the Company, which would result in increased compliance costs,
could have a material adverse effect on the Company's results of operations.
United Kingdom
Since 1990, the electricity industry in Great Britain has seen the
privatization of electric generation, supply and distribution, and the
introduction of competition in generation and supply. Electricity is produced by
generators, transmitted through the national grid transmission system by The
National Grid Company plc ("NGC") (or in Scotland by Scottish Power or Scottish
Hydro Electric) and distributed to customers by the fourteen Distribution
License Holders ("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
granted at privatization was replaced by two separate licenses - the Electricity
Distribution license and the Electricity Supply license. The Public Electricity
Supplier ("PES") licenses formerly held by Northern Electric plc and Yorkshire
Electricity Group plc were split so that separate subsidiaries held licenses for
distribution and electricity supply. In order to comply with the legislation the
Northern Electric plc and Yorkshire Electricity Group plc each made a Statutory
Transfer Scheme ("Scheme") that was approved by the Secretary of State for Trade
and Industry. The Schemes provide 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
the Schemes the electricity distribution businesses of Northern Electric plc and
Yorkshire Electricity Group plc were transferred to Northern Electric
Distribution Ltd ("NEDL") and Yorkshire Electricity Distribution plc ("YEDL"),
respectively. NEDL and YEDL are each holders of an electricity distribution
license.
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. 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 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 kilowatt hour) which a DLH is
entitled to charge. The distribution price control formula permits DLHs to
receive additional revenues 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, additional cost savings therefore contribute directly to
profit.
In connection with the scheduled distribution price control review
concluded by Ofgem in 1999, the allowable revenue of NEDL's predecessor,
Northern Electric plc, was reduced by 24%, and the allowable revenue of YEDL's
predecessor, Yorkshire Electricity Group plc, was reduced by 23%, with effect
from April 1, 2000. As part of the review, the Xd factor was not modified and
therefore remained at 3%.
The distribution prices allowable under the current distribution price
control formula are expected to be reviewed by Ofgem at the expiration of the
formula's scheduled five-year duration in 2005. The formula may be further
reviewed at other times in the discretion of the regulator. Accordingly Ofgem is
proposing to modify the licenses of all DLHs to implement the Information and
Incentives Project under which up to two per cent of regulated income will
depend 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.
Philippines
The Philippine Congress has passed the Electric Power Industry Reform
Act of 2001 which is aimed at restructuring the electric industry, privatizing
of the NPC and introducing a competitive electricity market, among others. The
passage of the bill may have an impact on the Company's future operations and
the industry as a whole, the effect of which is not yet determinable and
estimable.
Environmental Regulation
United States
The Company is subject to a number of environmental laws and other
regulations affecting many aspects of its present and future operations. Such
laws and regulations generally require the Company to obtain and comply with a
wide variety of licenses, permits and other approvals. No assurance can be
given, however, that in the future all necessary permits and approvals will be
obtained and all applicable statutes and regulations complied with. In addition,
regulatory compliance for the construction of new facilities is a costly and
time-consuming process, and intricate and rapidly changing environmental
regulations may require major expenditures for permitting and create the risk of
expensive delays or material impairment of project value if projects cannot
function as planned due to changing regulatory requirements or local opposition.
The Company believes that its operating power facilities are currently in
material compliance with all applicable federal, state and local laws and
regulations. There can be no assurance that existing regulations will not be
revised or that new regulations will not be adopted or become applicable to the
Company which could have an adverse impact on its operations.
The Clean Air Act Amendments of 1990 ("CAAA") was signed into law in
November 1990. Essentially all utility generating units are subject to the
provisions of the CAAA which address continuous emissions monitoring, permit
requirements and fees and emissions of certain substances. MidAmerican Energy
has five jointly owned and six wholly owned coal-fired generating units, which
represent approximately 60% of MidAmerican Energy's electric generating
capability. MidAmerican Energy's generating units meet all requirements under
Title IV of the CAAA. Title IV of the CAAA, which is also known as the Acid Rain
Program, sets forth requirements for the emission of sulfur dioxide and nitrogen
oxides at electric utility generating stations.
In accordance with the requirements of Section 112 of the CAAA, the
Environmental Protection Agency ("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 February
1998, EPA issued its Final Report to Congress, indicating that mercury is the
hazardous air pollutant of greatest potential concern from coal-fired generating
units and that additional research and monitoring are necessary. As such the EPA
issued a request under Section 114 of the CAAA requiring all electric utilities
to provide information that will allow the EPA to calculate the annual mercury
emissions from each coal-fired generating unit for the calendar year 1999. In
December 2000, 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. The
cost to MidAmerican Energy of reducing its mercury emissions would depend on
available technology at the time, but could be material.
State and federal 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 the Company's
cost of waste disposal and possibly reducing the reliability of service provided
by the Company and the amount of energy available from the Company's facilities.
Any of such items could have a substantial impact on amounts required to be
expended by the Company in the future.
United Kingdom
CE Electric UK Funding's businesses are subject to numerous regulatory
requirements with respect to the protection of the environment. The Electricity
Act 1989 obligates either the UK Secretary of State or the Director General of
Electric Supply to take into account the effect of electricity generation,
transmission and supply activities upon the physical environment when approving
applications for the construction of generating facilities and the location of
overhead power lines. The Electricity Act requires CE Electric UK Funding 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 Funding 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.
CE Electric UK Funding's policy is to carry out its activities in such a
manner as to minimize the impact of its works and operations on the environment,
and in accordance with environmental legislation and good practice. There have
not been any significant regulatory environmental compliance issues and there
are no material legal or administrative proceedings pending against CE Electric
UK Funding with respect to any environmental matter.
Employees
As of December 31, 2001, the Company and its subsidiaries employed
approximately 9,780 people.
As of December 31, 2001, MidAmerican Energy employed approximately 3,770
people, of which approximately 47% are represented by labor unions. MidAmerican
Energy believes that its relations with its employees are good.
As of December 31, 2001, CE Electric UK Funding employed approximately
3,460 people, of which approximately 76% are represented by labor unions. All CE
Electric UK Funding employees who are not party to a personal employment
contract are subject to collective bargaining agreements that are covered by
eight separate business agreements. These arrangements may be amended by joint
agreement between the trade unions and the individual business through
negotiation in the appropriate Joint Business Council. CE Electric UK Funding
believes that its relations with its employees are good.
As of December 31, 2001, the CalEnergy Generation platforms employed
approximately 560 people, of which approximately 240 people were in the
Philippines. None of CalEnergy Generation's employees are covered by a
collective bargaining agreement. Management believes that CalEnergy Generation's
relations with its employees are good.
As of December 31, 2001, HomeServices employed approximately 1,930
individuals and had approximately 8,700 sales associates, who are independent
contractors and not employees. None of HomeServices' employees or sales
associates are covered by a collective bargaining agreement. HomeServices
believes that its relations with its employees and sales associates are good.
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 plant,
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 the Company are in good operating condition and well
maintained.
The electric transmission system of MidAmerican Energy at December 31,
2001, included 897 miles of 345-kV lines, and 1,122 miles of 161-kV lines. The
gas distribution facilities of MidAmerican Energy at December 31, 2001, included
20,561 miles of gas mains and services. Substantially all of the former
Iowa-Illinois Gas and Electric Company (predecessor to MidAmerican Energy)
utility property and franchises, and substantially all of the former Midwest
Power Systems Inc. (predecessor to MidAmerican Energy) electric utility property
located in Iowa, or approximately 79% of gross utility plant, is pledged to
secure mortgage bonds.
Northern's and Yorkshire's electricity distribution networks (excluding
service connection to consumers) included approximately 10,500 and 9,800 miles
of overhead lines and approximately 16,800 and 25,200 miles of underground
cables, respectively.
The Company's most significant physical properties, other than those
owned by CE Electric UK Funding and MidAmerican Energy, are its current
interests in operating power facilities, its plants under construction and
related real property interests. See Item 1 for further detail.
Item 3. Legal Proceedings
In addition to the proceedings described below, the Company and its
subsidiaries are currently parties to various minor items of litigation or
arbitration, none of which, if determined adversely, would have a material
adverse effect on the Company.
Southern California Edison
Southern California Edison Company ("Edison"), a wholly-owned subsidiary
of Edison International, is a public utility primarily engaged in the business
of supplying electric energy to retail customers in Central and Southern
California, excluding Los Angeles. The Company is aware that there have been
public announcements that Edison's financial condition has deteriorated as a
result of reduced liquidity. Following Edison's recent financing, Edison's
senior unsecured debt obligations were upgraded to Ba3 by Moody's and BB by S&P.
Edison failed to pay approximately $119 million due under the power
purchase agreement with CE Generation affiliates for power delivered in November
and December 2000 and January, February and March 2001, although the Power
Purchase Agreements provide for billing and payment on a schedule where payments
would have normally been received in early January, February, March, April and
May 2001.
On February 21, 2001, the Imperial Valley Projects (excluding the Salton
Sea V and Turbo Projects) filed a lawsuit against Edison in California's
Imperial County Superior Court seeking a court order requiring Edison to make
the required payments under the Power Purchase Agreements. The lawsuit also
requested, among other things, that the court order permit the Imperial Valley
Projects (excluding the Salton Sea V and Turbo Projects) to suspend deliveries
of power to Edison and to permit the Imperial Valley Projects to sell such power
to other purchasers in California.
On March 22, 2001, the Imperial County Superior Court granted the
Imperial Valley Projects' (excluding the Salton Sea V and Turbo Projects) Motion
for Summary Adjudication and a Declaratory Judgment ordering that: 1) under the
Power Purchase Agreements, the Imperial Valley Projects (excluding the Salton
Sea V and Turbo Projects) have the right to temporarily suspend deliveries of
capacity and energy to Edison, 2) such Imperial Valley Projects (excluding the
Salton Sea V and Turbo Projects) are entitled to resell the energy and capacity
to other purchasers and 3) the interim suspension of deliveries to Edison shall
not in any respect result in the modifications or termination of the Power
Purchase Agreements, and the Power Purchase Agreements shall in all respects
continue in full force and effect other than the temporary suspension of
deliveries to Edison.
As a result of the March 22, 2001 Declaratory Judgment, the Imperial
Valley Projects (excluding the Salton Sea V and Turbo Projects) suspended
deliveries of energy to Edison and entered into a transaction agreement with El
Paso Merchant Energy, L.P. ("EPME") in which the Imperial Valley Projects'
(excluding the Salton Sea V and Turbo Projects) available power was sold to EPME
based on percentages of the Dow Jones SP-15 Index. On June 18, 2001 the Superior
Court prospectively vacated its order authorizing the Imperial Valley Projects'
(excluding the Salton Sea V and Turbo Projects) right to resell power pursuant
to the Declaratory Judgment.
On June 20, 2001, the Imperial Valley Projects (excluding Salton Sea
Unit V and CE Turbo) entered into Agreements Addressing Renewable Energy Pricing
and Payment Issues with Edison ("Settlement Agreements") and, as a result,
resumed power sales to Edison on June 22, 2001. The Settlement Agreements
required that Edison make an initial payment to repay the past due balances
under the Power Purchase Agreements (the "stipulated amounts"). The initial
payment of approximately $11.6 million, which represented 10% of the stipulated
amounts, was received June 22, 2001. On October 2, 2001, the California Public
Utilities Commission announced an agreement with Edison that allowed Edison to
recover in retail electric rates its past due obligations. On November 30, 2001,
the Settlement Agreements were amended to reflect when Edison would be required
to make the final payment on past due amounts. On March 1, 2002, Edison obtained
$1.8 billion in secured financing that, when combined with cash on hand, enabled
Edison to pay off its past due debts. The final payment of approximately $104.6
million, representing the remaining stipulated amounts, was received March 1,
2002. In addition to these payments, Edison was required to make monthly
interest payments calculated at a rate of 7% per annum on the outstanding
stipulated amounts. The amended Settlement Agreements provide a revised energy
pricing structure, whereby Edison elects to pay the Imperial Valley Projects a
fixed energy price in lieu of the Commission-approved Avoided Cost of Energy
Methodology under the Power Purchase Agreements. The fixed energy price is 3.25
cents/kWh from December 2001 through April 30, 2002 and 5.37 cents/kWh
commencing May 1, 2002 for a five year period. Following the five year period,
the energy payments revert back to the Commission-approved Avoided Cost of
Energy Methodology under the Power Purchase Agreements. Estimates of Edison's
future Avoided Cost of Energy vary substantially from year to year.
As a result of Edison's failure to make the payments due under the Power
Purchase Agreements and the downgrades of Edison's credit rating, Moody's
downgraded the ratings for the Salton Sea Funding Corporation (the "Funding
Corporation") Securities to Caa2 (negative outlook) and S&P downgraded the
ratings for the Funding Corporation Securities to BBB- and placed the Securities
on "credit watch negative." Moody's downgraded the ratings for the CE Generation
Securities to B1 from Baa3 (review for possible downgrade). Following the
execution of the Settlement Agreements, Moody's placed the Salton Sea Funding
and CE Generation securities on "credit watch positive." The Funding Corporation
Securities are currently rated Ba3 by Moody's and BBB- by S&P. CE Generation
Securities are currently Ba2 by Moody's and BBB- by S&P.
Kvaerner Arbitration
The Zinc Recovery Project was being constructed by Kvaerner U.S. Inc.
("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering,
procure, construct and manage contract (the "Zinc Recovery Project EPC
Contract"). On June 14, 2001, CalEnergy Minerals, LLC issued notices of default,
termination and demand for payment of damages to Kvaerner under the Zinc
Recovery Project EPC Contract due to failure to meet performance obligations. As
a result of Kvaerner's failure to pay monetary obligations under the Zinc
Recovery Project EPC Contract, CalEnergy Minerals, LLC drew $29.6 million under
the EPC Contract Letter of Credit on July 20, 2001. CalEnergy Minerals, LLC has
entered into a time and materials reimbursable engineer, procure and
construction management contract with AMEC E&C Services, Inc. to complete the
Zinc Recovery Project.
On July 11, 2001, Kvaerner filed an Amended Demand For Arbitration
against CalEnergy Minerals LLC characterizing the nature of the dispute as
concerns regarding change orders and performance penalties. Kvaerner did not
state the amount of its claim.
On August 7, 2001, CalEnergy Minerals LLC filed an Answering Statement
and Counterclaim against Kvaerner. CalEnergy Minerals LLC denied all material
allegations in Kvaerner's Amended Demand for Arbitration, and asserted a
counterclaim against Kvaerner for breach of contract and specific performance.
CalEnergy Minerals LLC alleged that its total estimated damage for Kvaerner's
breach of contract are in excess of approximately $60 million; however,
CalEnergy Minerals LLC has offset approximately $42.5 million of these damages
by exercising its rights under the EPC Contract to claim the retainage and by
drawing on a letter of credit. Therefore, CalEnergy Minerals LLC asked for a
judgment in excess of approximately $20 million. The arbitration is scheduled
for June 2002.
Casecnan
The Casecnan Project was initially being constructed pursuant to a
fixed-price, date-certain, turnkey construction contract (the "Hanbo Contract")
on a joint and several basis by Hanbo Corporation ("Hanbo") and Hanbo
Engineering and Construction Co., Ltd. ("HECC"), both of which are South Korean
corporations. As of May 7, 1997, the Company terminated the Hanbo Contract due
to defaults by Hanbo and HECC including the insolvency of both companies. On the
same date, the Company entered into a new fixed-price, date certain, turnkey
engineering, procurement and construction contract to complete the construction
of the Casecnan Project (the "Replacement Contract"). The work under the
Replacement Contract was conducted by a consortium consisting of Cooperativa
Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa., working
together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power
Engineering Ltd. (collectively, the "Contractor").
On November 20, 1999, the Replacement Contract was amended to extend the
Guaranteed Substantial Completion Date for the Casecnan Project to March 31,
2001. This amendment was approved by the lender's independent engineer under the
Casecnan Indenture.
On February 12, 2001, the Contractor filed a Request for Arbitration
with the International Chamber of Commerce seeking an extension of the
Guaranteed Substantial Completion Date by up to 153 days through August 31, 2001
resulting from various alleged force majeure events. In a March 20, 2001
Supplement to Request for Arbitration, the Contractor also seeks 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 approximately $62 million in damages for the alleged force majeure
event (and geologic conditions) related to the collapse of the surge shaft. The
Contractor alleged that the circumstances surrounding the placing of the
Casecnan Project into commercial operation on December 11, 2001 amounted to a
termination of the Replacement Contract and filed a claim for unspecified
quantum meruit damages. CE Casecnan believes such allegations and claims are
without merit and is vigorously defending the Contractor's claims. The
arbitration is being conducted applying New York law and pursuant to the rules
of the International Chamber of Commerce.
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. Hearings on the force majeure claims were held in London from July 2 to
14, 2001, and hearings on the Contractor's April 20, 2001 supplement were held
in London from September 24 to October 3, 2001. Further hearings were held in
Paris from January 2 to February 1, 2002 and additional hearings were held from
March 14 to 19, 2002.
As of December 31, 2001 the Company has received approximately $6.0
million of liquidated damages from demands made or the demand guarantees posted
by Commerzbank on behalf of the Contractor. Although the outcome of the
arbitration is difficult to assess, CE Casecnan believes it will prevail and
receive substantial additional liquidated damages in the arbitration.
Malitbog Arbitration
VGPC and PNOC-EDC have been negotiating with respect to certain disputes
concerning the Malitbog ECA but have been unable to reach a mutually acceptable
resolution. Accordingly, on October 16, 2000, VGPC commenced arbitration against
PNOC-EDC by serving it with a Notice of Arbitration and Statement of Claim (the
"Notice of Arbitration"). In the Notice of Arbitration, VGPC claimed that
PNOC-EDC breached the Malitbog ECA by improperly characterizing certain No Fault
Outages as Forced Outage Hours and then deducting them from the total number of
hours each month. On December 22, 2000, VGPC filed an Amended Statement of Claim
pursuant to which VGPC added a claim that PNOC-EDC breached the Malitbog ECA by
refusing to accept VGPC's specified Nominated Capacity for contract years July
25, 1999 to July 25, 2000, and July 25, 2000 to July 25, 2001. A Second Amended
Statement of Claim was filed on March 9, 2001 to add the Scheduled Maintenance
issue. VGPC intends to vigorously pursue its claims in this proceeding.
Cooper Litigation
On July 23, 1997, the Nebraska Public Power District ("NPPD") filed a
complaint, in the United States District Court for the District of Nebraska,
naming MidAmerican Energy as the defendant and seeking declaratory judgment as
to three issues under the parties' long-term power purchase agreement for Cooper
capacity and energy. More specifically, NPPD sought a declaratory judgment in
the following respects:
(1) that MidAmerican Energy is obligated to pay 50% of all costs and
expenses associated with decommissioning Cooper, and that in the event
NPPD continues to operate Cooper after expiration of the power purchase
agreement (September 2004), MidAmerican Energy is not entitled to
reimbursement of any decommissioning funds it has paid to date or will
pay in the future;
(2) that the current method of allocating transition costs as a part of
the decommissioning cost is proper under the power purchase agree-
ment; and
(3) that the current method of investing decommissioning funds is proper
under the power purchase agreement.
MidAmerican Energy filed its answer and counterclaims. The counterclaims filed
by MidAmerican Energy are generally as follows:
(1) tha MidAmerican Energy has no duty under the power purchase agreement
to reimburse or pay 50% of the decommissioning costs unless conditions
to reimbursement occur;
(2) that the term "monthly power costs" as defined in the power purchase
agreement does not include costs and expenses associated with
decommissioning the plant;
(3) that NPPD violated MidAmerican Energy's directions for application of
payments;
(4) that transition costs are not included in any decommissioning costs and
are not any kind of costs that MidAmerican Energy is obligated to pay;
(5) that NPPD has the duty to repay all amounts that MidAmerican Energy has
prefunded for decommissioning in the event the Nebraska Public Power
District operates the plant after the term of the power purchase
agreement;
(6) that NPPD is equitably estopped from continuing to operate the plant
after the term of the power purchase agreement so long as NPPD does not
repay all amounts MidAmerican Energy has prefunded for estimated
decommissioning costs together with other amounts in certain funds and
accounts and for so long as NPPD fails to provide MidAmerican Energy
with certain requested accountings and information;
(7) that certain funds, accounts, and reserves are excessive and are
required to be paid to MidAmerican Energy or credited to MidAmerican
Energy's pre-2004 monthly power costs;
(8) that MidAmerican Energy has no duty to pay for nuclear fuel, operations
and maintenance projects or capital improvements that have useful lives
after the term of the power purchase agreement;
(9) that NPPD has mismanaged the plant in numerous described transactions
resulting in damage to MidAmerican Energy;
(10) that NPPD has breached its contractual and other duties to MidAmerican
Energy by not joining certain litigation and by failing to credit or
agree to credit MidAmerican Energy with any recovery for low-level
radioactive waste; and
(11) that NPPD has breached its duty to MidAmerican Energy in making invest-
ments of decommissioning funds;
On October 6, 1999, the court rendered summary judgment for NPPD on the
above-mentioned issue concerning liability for decommissioning (issue one in the
first paragraph above) and the related counterclaims filed by MidAmerican Energy
(issues one and two in the second paragraph above). The court referred all
remaining issues in the case to mediation, and cancelled the November 1999 trial
date.
MidAmerican Energy appealed the court's summary judgment ruling. On
December 12, 2000, the United States Court of Appeals for the Eighth Circuit
reversed the ruling of the district court and granted summary judgment in favor
of MidAmerican Energy on issues one and two in the second paragraph above, as
well as issue one in the first paragraph above. Additionally, it remanded the
case for trial on all other claims and counterclaims.
Since the remand to the District Court from the Eighth Circuit Court of
Appeals, NPPD has been granted permission, over MidAmerican Energy's objections,
to file a second amended complaint. The second amended complaint asserts that
even though the Eighth Circuit Court of Appeals held that MidAmerican Energy has
no liability under the power purchase agreement to reimburse or pay NPPD a 50%
share of decommissioning costs unless certain conditions occur, MidAmerican
Energy has unconditional liability for a 50% share based on agreements other
than the power purchase agreement as originally written. NPPD's post-remand
contentions -- all strongly disputed by MidAmerican Energy -- are that
MidAmerican Energy has unconditional liability for a 50% share of
decommissioning based on any of the following alternative theories: (i) the
parties without written amendment either modified the power purchase agreement
or made a separate agreement that imposes unconditional liability on MidAmerican
Energy for decommissioning costs; (ii) absent unconditional liability for a 50%
share of decommissioning costs, MidAmerican Energy would be unjustly enriched;
(iii) MidAmerican Energy has unconditional liability for a 50% share of
decommissioning costs based on promissory estoppel; or (iv) NPPD is entitled to
have the power purchase agreement reformed to provide that MidAmerican Energy
has unconditional liability for a 50% share of decommissioning costs. In
response to NPPD's second amended complaint, MidAmerican Energy filed its first
amended answer and third amended counterclaims containing denials, several
affirmative defenses, and the counterclaims summarized above. In the course of
discovery, NPPD has contended that MidAmerican Energy has some responsibility
for some costs of storage of spent fuel resulting from the operation of the
plant during the term of the power purchase agreement. MidAmerican Energy
disputes this. MidAmerican Energy recently filed a mandamus petition with Eighth
Circuit Court of Appeals seeking an order of that court directing the District
Court not to permit NPPD to pursue the above alternative theories at trial,
since the above alternative theories appear to be contrary to the December 12,
2000 Eighth Circuit Court of Appeals decision. If such relief is not granted,
MidAmerican Energy will strongly dispute at trial these contentions and theories
put forth by NPPD. Trial in these matters has been recently rescheduled to
September 9, 2002.
Item 4. Submission of Matters to a Vote of Security Holders.
Not applicable.
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder's
Matters
As of March 14, 2000, the Company's equity securities are owned by a
limited group of private investors and are not registered with the Securities
and Exchange Commission pursuant to the Securities Act of 1933, as amended,
listed on a stock exchange or otherwise publicly held or traded.
Item 6. Selected Financial Data
Reference is made to Part IV of this report.
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Reference is made to Part IV of this report.
Item 7A. Qualitative and Quantitative Disclosures About Market Risk
Reference is made to Part IV of this report. Refer to Note 16 in notes
to consolidated financial statements.
Item 8. Financial Statements and Supplementary Data
Reference is made to Part IV of this report.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
Not applicable.
PART III
MANAGEMENT
Item 10. Directors, Executive and Other Officers of the Company
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 and General Counsel
Keith D. Hartje Senior Vice President and Chief Administrative
Officer
Warren Buffett Director
Walter Scott Jr. Director
Marc D. Hamburg Director
W. David Scott Director
Edgar D. Aronson Director
John Boyer Director
Stanley J. Bright Director
Richard 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, 45, 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 PKS, and Ogden
Projects, Inc.
GREGORY E. ABEL, 39, 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, 35, 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, 44, 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, 52, 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 BUFFETT, 71, 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.
WALTER SCOTT, JR., 71, 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, 52, 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, 40, 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 Office 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, 67, 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 BOYER, 58, 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, 62, Director. Mr. Bright is Vice Chairman of the
Company and was Chairman and Chief Executive Officer of MidAmerican Energy
Company from July 1, 1995 until March 1999. Mr. Bright joined Iowa-Illinois Gas
and Electric Company (a predecessor of MidAmerican Energy Company) 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, 50, 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. From
1990 until January 8, 1992, Mr. Jaros served as a Vice President of Peter Kiewit
Sons Inc. Mr. Jaros serves as director of Commonwealth Telephone Enterprises,
Inc., RCN Corporation and Level 3 Communications, Inc.
Item 11. Executive Compensation
The following table sets forth the compensation of the chief executive officer
and the four other most highly compensated executive officers of the Company who
were employed as of December 31, 2001 ("Named Executive Officers"). Information
is provided regarding the Named Executive Officers for the last three fiscal
years during which they were executive officers of the Company, if applicable.
Year Other Restricted Securities All
Name and Ended Bonus Annual Stock Underlying LTIP Other
Principal Positions Dec 31, Salary Cash (1) Stock Comp (2) Awards Options Payouts Comp (3)
- ------------------- ------- ------ -------- ----- -------- ------ ------- -------- --------
David L. Sokol 2001 $750,000 $2,400,000 $ -- $ -- $ -- $ -- $ -- $6,630
Chairman and 2000 750,000 4,250,000 -- -- -- 2,199,277 -- 6,630
Chief Executive 1999 675,000 3,276,049 -- -- -- -- -- 6,240
Officer
Gregory E. Abel 2001 520,000 1,150,000 -- -- -- -- -- 6,630
President and 2000 500,000 1,100,000 -- -- -- 649,052 -- 6,630
Chief Operating 1999 357,933 1,452,234 -- -- -- -- -- 6,240
Officer
Ronald W. Stepien 2001 400,000 275,000 -- 7,270 -- -- 316,021 6,630
President, 2000 370,667 641,938 -- -- -- -- -- 6,630
MidAmerican 1999 350,000 1,052,069 -- -- -- 56,203 -- 6,240
Energy Company (4)
Patrick J. Goodman 2001 240,000 260,000 -- -- -- -- -- 6,630
Chief Financial 2000 230,000 1,183,071 -- -- -- -- -- 6,630
Officer 1999 199,279 334,374 -- -- -- 60,000 -- 6,240
Douglas L. Anderson 2001 154,427 200,000 -- -- -- -- -- 6,630
General Counsel and 2000 120,000 591,806 -- -- -- -- -- 6,630
Corporate Secretary 1999 110,000 40,000 -- -- -- 5,000 -- 3,654
(1) Includes amounts voluntarily deferred by the executive, if applicable.
Includes various expatriate compensation items, including expatriate
allowances, company provided transportation, housing and tax benefits.
(2) Includes payout of earnings on Long-Term Incentive Partnership Plan.
(3) Consists of 401(k) Plan contributions for 2001.
(4) Mr. Stepien retired from the Company effective December 31, 2001.
Option Grants in Last Fiscal Year
The Company did not grant any options during 2001.
Aggregated Option Exercises In Last Fiscal Year And Fiscal Year End Option
Values
The following table sets forth the option exercises and the number of
securities underlying exercisable and unexercisable options held by each of the
Named Executive Officers at December 31, 2001.
Underlying Unexercised Value of Unexercised
Shares Value Options Held In-the-Money Options ($) (1)
------------ ----------------------------
Name Acquired Realized $ Exercisable Unexercisable Exercisable Unexercisable
- ---- -------- ---------- ----------- ------------- ----------- -------------
David L. Sokol - - 1,970,412 228,865 N/A N/A
Gregory E. Abel - - 584,864 64,188 N/A N/A
Ronald W. Stepien - - - - -- --
Patrick J. Goodman - - - - -- --
Douglas L. Anderson - - - - -- --
(1) On March 14, 2000 the Company was acquired by an investor group in a
"going private" transaction (the "Teton Transaction"). As a privately
held company, the Company has no publicly traded equity securities and,
consequently, the Company's 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
Amount of Performance or other
Annual Award period until
Name ($) (1) maturation or payout
- ---- ------- --------------------
Ronald W. Stepien $ 56,106 December 31,2005
Patrick J. Goodman 107,212 December 31,2005
Douglas L. Anderson 87,769 December 31,2005
(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 with annual interest based on a composite of
funds or indices.
Compensation of Directors
All directors, excluding Messrs. Sokol, Abel, Buffet 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 of the
Company do not 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 ("Supplemental Plan") to provide additional retirement benefits to
designated participants, as determined by the Board of Directors. Messrs. Sokol,
Abel, Stepien and Goodman are participants in the Supplemental Plan. The
Supplemental Plan provides 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 (i) awards under an annual incentive bonus
program and (ii) 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 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 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, the
Company, through a rabbi trust, 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 Company
Cash Balance Retirement Plan ("MidAmerican Retirement Plan") that became
effective January 1, 1997, and by benefits under the Iowa-Illinois Gas and
Electric Company Supplemental Retirement Plan ("Iowa-Illinois 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 recordkeeping
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. Mr. Anderson is a participant in
this 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.
Pension Plan Table
Total Cash Estimated Annual Benefit
Compensation Age at Retirement
Retirement -----------------------------------------------------
- --------------- 55 60 65
--------- ---------- ----------
$400,000 $ 220,000 $240,000 $260,000
500,000 275,000 300,000 325,000
600,000 330,000 360,000 390,000
700,000 385,000 420,000 455,000
800,000 440,000 480,000 520,000
900,000 495,000 540,000 585,000
1,000,000 550,000 600,000 650,000
1,250,000 687,500 750,000 812,500
1,500,000 825,000 900,000 975,000
1,750,000 962,500 1,000,000 1,000,000
2,000,000 and greater 1,000,000 1,000,000 1,000,000
Employment Agreements
Pursuant to his Employment Agreement, Mr. Sokol will serve as Chairman
of the Board of Directors and Chief Executive Officer of the Company. The
Employment Agreement provides that Mr. Sokol is to receive an annual base salary
of not less than $750,000, senior executive employee benefits and annual bonus
awards that shall not be less than $675,000.
The Employment Agreement provides that the Company may terminate the
employment of Mr. Sokol (i) 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 (ii) 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 (a) his annual salary then in effect and
(b) 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 such fifth anniversary. If Mr. Sokol
relinquishes his position as Chief Executive Officer but offers to remain
employed as the Chairman of the Board, he is to receive a special achievement
bonus equal to two times the sum of (a) his annual salary then in effect and (b)
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 each of
Messrs. Abel and Goodman and the Company, 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 of the termination of his employment by the Company other than for cause.
If such persons were terminated without cause, Messrs. Sokol, Abel and Goodman
would currently be entitled to be paid approximately $12,225,000, $3,290,000 and
$780,000, respectively, pursuant to their employment agreements, without giving
effect to any tax related provisions.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The following table sets forth certain information regarding beneficial
ownership of the shares of Company common stock and certain information with
respect to the beneficial ownership of each director, the Named Executive
Officers and all directors and executive officers of the Company as a group as
of December 31, 2001.
Number Of Shares
Name and Address of Beneficially Percentage Of
Beneficial Owner (1) Owned (2) Class (2)
- -------------------- ---------------- -------------
Common Stock:
Gregory E. Abel (3) 649,362 5.47%
Douglas L. Anderson - -
Edgar D. Aronson - -
Berkshire Hathaway Inc. (4) 900,942 9.71%
Stanley J. Bright - -
John K. Boyer - -
Warren E. Buffett (5) - -
Patrick J. Goodman - -
Marc D. Hamburg (5) - -
Richard R. Jaros - -
W. David Scott (6) 624,350 6.73%
Walter Scott, Jr. (7) 5,000,000 53.87%
David L. Sokol (8) 2,325,132 19.58%
Ronald W. Stepien - -
All directors and executive
officers as a group
(14 persons) 9,499,786 80.00%
(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) Includes options to purchase 593,422 shares of common stock which are
exercisable within 60 days.
(4) Such beneficial owner's address is 1440 Kiewit Plaza, Omaha, Nebraska
68131.
(5) Excludes 900,942 shares of common stock held by Berkshire Hathaway Inc.
of which beneficial ownership of such shares is disclaimed.
(6) Includes shares held by trusts for the benefit of or controlled by W.
David Scott. Such beneficial owner's address is 402 South 36th Street,
Suite 800, Omaha, Nebraska 68131.
(7) 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.
(8) Includes options to purchase 2,000,927 shares of common stock that are
exercisable within 60 days.
The terms of the Company's Zero Coupon Convertible Preferred Stock held
by Berkshire athaway nc. entitle the holder thereof to designate two members
of the Company's Board of Directors. Similarly, 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 Inc. 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
Company common stock, provided that Berkshire Hathaway Inc. 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 registered
holding company under the Public Utility Holding Company Act of 1935, as amended
("PUHCA"). The consummation of such a transaction could result in a change in
control of the Company.
The Company's Amended and Restated Articles of Incorporation
("Articles") 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 Company common stock subject to certain adjustments
as described in the Articles, upon the occurrence of a Conversion Event. A
"Conversion Event" includes (i) 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 (ii) a Company Sale. A "Company Sale" includes any
involuntary or voluntary liquidation, dissolution, recapitalization, winding-up
or termination of the Company and any merger, consolidation or sale of all or
substantially all of the assets of the Company. The conversion by Berkshire
Hathaway Inc. of its shares of Zero Coupon Convertible Preferred Stock could
result in a change in control of the Company.
Item 13. Certain Relationships and Related Transactions
Under a subscription agreement with the Company, under certain
circumstances, Berkshire Hathaway has agreed to purchase additional 11% trust
issued preferred securities in the event preferred securities outstanding prior
to the closing of the Teton Transaction are tendered for conversion to cash by
the current holders.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) Financial Statements and Schedules
1. Financial Statements (included herein)
Page No.
Selected Consolidated Financial Data......................................36
Management's Discussion and Analysis of Financial Condition
And Results of Operations............................................37
Qualitative and Quantitative Disclosures About Market Risk................48
Consolidated Balance Sheets as of December 31, 2001 and 2000..............50
Consolidated Statements of Operations
For the Three Years Ended December 31, 2001, 2000 and 1999...........51
Consolidated Statements of Stockholders' Equity
For the Three Years Ended December 31, 2001, 2000 and 1999...........52
Consolidated Statements of Cash Flows
For the Three Years Ended December 31, 2001, 2000 and 1999...........53
Notes to Consolidated Financial Statements................................54
Independent Auditors' Report..............................................93
2. Financial Statement Schedules
Page No.
Schedule I, Financial Statements of the Company (Parent Company only).....94
Schedule II, Consolidated Valuation and Qualifying Accounts...............97
(b) Reports on Form 8-K
None.
(c) Exhibits
The exhibits listed on the accompanying Exhibit Index are filed as part
of this Annual Report.
(d) Financial statements required by Regulations S-X, which are excluded
from the Annual Report by Rule 14a-3(b).
Not applicable.
SELECTED CONSOLIDATED FINANCIAL DATA
(In millions)
MEHC (Predecessor)
March 14, 2000 -------------------------------------------------
Year Ended through January 1, 2000
December 31, December 31, through Year Ended December 31,
2001(1) 2000(2) March 13, 2000 1999 (3) 1998 (4) 1997
------- ------- -------------- -------- -------- ----
Income Statement Data:
Operating revenue $5,060.6 $4,147.9 $1,087.1 $4,184.5 $2,555.2 $2,166.3
Total revenues 5,336.8 4,242.7 1,106.6 4,466.4 2,682.7 2,270.9
Total costs and expenses 4,832.9 4,023.5 1,015.4 4,109.4 2,410.7 2,074.1
Income before provision for
income taxes 503.9 219.2 91.2 357.1 272.1 196.9(6)
Minority interest 106.5 84.7 8.9 46.9 41.3 46.0
Income before change in
accounting principle
and extraordinary item 147.3 81.3 51.3 216.7(5) 137.5 51.8(6)
Extraordinary item, net of tax - - - (49.4) (7.1) (135.9)
Cumulative effect of change
in accounting principle,
net of tax (4.6) - - - (3.4) -
Net income (loss) 142.7 81.3 51.3 167.2(5) 127.0 (84.0)(6)
Balance Sheet Data:
Total assets $12,615.3 $11,610.9 N/A $10,766.4 $9,103.5 $7,487.6
Total liabilities 9,767.4 8,911.3 N/A 8,978.9 7,598.0 5,282.2
Company-obligated mandatory
redeemable preferred securities
of subsidiary trusts 788.2 786.5 N/A 450.0 553.9 553.9
Subsidiary-obligated mandatorily
redeemable preferred securities
of subsidiary trusts 100.0 100.0 N/A 101.6 - -
Preferred securities of subsidiaries 121.2 145.7 N/A 146.6 66.0 56.2
Total stockholders' equity 1,708.2 1,576.4 N/A 994.6 827.1 765.3
(1) Reflects the Northern Supply/Yorkshire Electric swap on September 21, 2001.
(2) Reflects the Teton Transaction on March 14, 2000.
(3) Reflects the MidAmerican acquisition on March 12, 1999, the disposition of
Coso Joint Ventures on February 26, 1999 and the disposition of 50% owner-
ship interest in CE Generation on March 3, 1999.
(4) Reflects the acquisition of KDG on January 2, 1998.
(5) Includes $81.5 million for non-recurring Indonesia gain on settlement,
gains on sales of McLeod and qualified facilities, CE Electric UK Funding
restructuring charges and Teton Transaction costs.
(6) Includes $87 million non-recurring Indonesia asset impairment charge.
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.
As a result of the Northern Supply/Yorkshire Electric swap and the Teton
Transaction, the Company's future results will differ from the Company's
historical results.
Forward-looking Statements
Certain information included in this report contains forward-looking statements
made pursuant to the Private Securities Litigation Reform Act of 1995 ("Reform
Act"). Such statements are based on current expectations and involve a number of
known and unknown risks and uncertainties that could cause the actual results
and performance of the Company to differ materially from any expected future
results or performance, expressed or implied, by the forward-looking statements.
In connection with the safe harbor provisions of the Reform Act, the Company has
identified important factors that could cause actual results to differ
materially from such expectations, including development uncertainty, operating
uncertainty, acquisition uncertainty, uncertainties relating to doing business
outside of the United States, uncertainties relating to geothermal resources,
the financial condition of and relationships with customers and suppliers, the
availability and price of fuel and other inputs, uncertainties relating to
domestic and international economic and political conditions and uncertainties
regarding the impact of regulations, changes in government policy, industry
deregulation and competition. Reference is made to all of the Company's SEC
filings, including the Company's Report on Form 8-K dated March 26, 1999,
incorporated herein by reference, for a description of such factors. The Company
assumes no responsibility to update forward-looking information contained
herein.
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 in this Annual Report on
Form 10-K 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, contingent liabilities and
impairment of long-lived assets. 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.
Revenue Recognition
Revenues are recorded based upon services rendered and electricity, gas and
steam delivered, distributed or supplied to the end of the period. Where there
is an over recovery of distribution business revenues against the maximum
regulated amount, revenues are deferred 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.
The Company also records unbilled revenues 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. Accrued unbilled revenues are
included in accounts receivable on the consolidated balance sheets.
SFAS No. 71 - Accounting for the Effects of Certain Types of Regulation
A possible consequence of deregulation in the utility industry is that SFAS No.
71 may no longer apply. SFAS No. 71 sets forth accounting principles for
operations that are regulated and meet the stated criteria. For operations that
meet the criteria, SFAS No. 71 allows, among other things, the deferral of
expense or income that would otherwise be recognized when incurred. MidAmerican
Energy's electric and gas utility operations currently meet the criteria
required by SFAS No. 71, but its applicability is periodically reexamined. If
portions of its utility operations no longer meet the criteria of SFAS No. 71,
MidAmerican Energy 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 are not recovered in
transition provisions of any deregulation legislation. As of December 31, 2001,
the Company had $221.1 million of regulatory assets and $62.4 million of
regulatory liabilities on its consolidated balance sheet.
Impairment of Long-Lived Assets
The Company's long-lived assets consist primarily of property, plant and
equipment, goodwill and intangible assets that were acquired in business
acquisitions. The Company believes the useful lives assigned to these assets,
which range from 3 to 40 years, are reasonable. The Company evaluates the
long-lived assets for impairment when events or changes in circumstances
indicate, in management's judgment, that the carrying value of such assets may
not be recoverable. These computations utilize judgments and assumptions
inherent in management's estimate of undiscounted future cash flows to determine
recoverability of an asset. If management's assumptions about these assets
change as a result of events or circumstances, and management believes the
assets may have declined in value, then the Company may record impairment
charges, resulting in lower profits.
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
income 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, 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.
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 subsidiary trust and the effects
of purchase accounting, including goodwill amortization and fair value
adjustments to the carrying value of assets and liabilities. In order to provide
comparability between periods, the Company has prepared pro forma results as if
the Teton Transaction had occurred at the beginning of each year after giving
effect to pro forma adjustments related to the acquisition, including the
issuance of the 11% trust preferred securities. The discussion therefore will
highlight any significant variances on a pro forma basis from the year ended
December 31, 2000 to the year ended December 31, 2001.
Pro forma operating revenue for the year ended December 31, 2001 was $5,060.6
million compared with $5,235.0 million for the same period in 2000, a decrease
of 3.3%. MidAmerican Energy operating revenue increased for the year ended
December 31, 2001 to $2,752.5 million from $2,576.9 million for the same period
in 2000, primarily due to increases in volumes of non-regulated gas sold and
increases in volumes and prices on off-system electricity sales. CE Electric UK
Funding operating revenue decreased for the year ended December 31, 2001 to
$1,444.0 million from $1,997.9 million for the same period in 2000, primarily
due to the Northern Supply/Yorkshire swap and changes in foreign exchange rates.
The supply business that was sold is generally a high volume business that tends
to operate at lower profitability levels than the distribution 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.
The following data represents sales from MidAmerican Energy:
Year
Ended December 31,
----------------------------
2001 2000
-------- ---------
Electricity Retail Sales (GWh)....... 17,207 16,715
Electricity Sales for Resale (GWh)... 7,755 6,941
Regulated and Non-Regulated Gas
Supplied (Thousands of
MMBtus)............................. 264,338 174,385
MidAmerican Energy electric retail sales increased for the year ended December
31, 2001 from the same period in 2000 due to the more extreme temperatures
substantially offset by a decrease 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.
The following data represents the supply and distribution operations in the
U.K.:
Year
Ended December 31,
--------------------------------
2001 2000
--------- --------
Electricity Supplied (GWh)............ 12,745 19,925
Electricity Distributed (GWh)......... 23,770 16,350
Gas Supplied (Thousands of MMBtus).... 40,738 51,035
The decrease in electricity supplied for the year ended December 31, 2001 is due
to the sale of the Northern 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
Supply business.
Pro forma interest and other income for the year ended December 31, 2001 was
$96.7 million compared with $114.4 million for the same period in 2000. The
decrease was due primarily to reduced interest income and lower income from
equity investments.
The non-recurring gains in 2001 are comprised mainly of the pre-tax gain on the
sale of the Northern Supply business of $196.7 million, the loss on the impair-
ment of Teesside of $58.8 million, the gain on the sale of Telephone Flat, a
geothermal development project, of $20.7 million, the gain on the transfer of
shares of Bali, an indirect wholly owned subsidiary of the Company, of $10.4
million, and the gain on the sale of Western States Geothermal Company, an
indirect wholly owned subsidiary of the Company, of $9.8 million. The after-tax
gains and (losses) for the Northern Supply sale, the Teesside impairment, the
Telephone Flat sale, the transfer of the Bali shares, and the Western States
Geothermal sale were $10.8 million, ($20.7) million, $12.2 million, $6.5 million
and $6.4 million, respectively.
Pro forma cost of sales for the year ended December 31, 2001 was $2,705.0
million compared with $3,029.7 million for the same period in 2000, a decrease
of 10.7%. The decrease relates primarily to decreased cost of sales at CE
Electric UK Funding due to the sale of the Northern 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.
Pro forma operating expenses for the year ended December 31, 2001 were $1,176.4
million compared with $1,123.6 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 due to costs related to Cooper,
accounts receivable discounts and bad debts, partially offset by lower costs at
CE Electric UK Funding due to the sale of the Northern Supply business, lower
pension costs and a lower exchange rate, partially offset by the addition of
Yorkshire.
Pro forma depreciation and amortization for the year ended December 31, 2001 was
$538.7 million compared with $479.6 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 intangible assets related to the
HomeServices acquisitions, partially offset by lower depreciation at CE Electric
UK Funding due to lower amortization of operational assets and lower exchange
rate, partially offset by the addition of Yorkshire.
Pro forma interest expense, less amounts capitalized, for the year ended
December 31, 2001 was $412.8 million compared with $398.1 million for the same
period in 2000, an increase of 3.7%. 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 Northern.
The loss on non-recurring item of $7.6 million in the period from January 1,
2000 through March 13, 2000 represents the costs incurred related to the Teton
Transaction.
Pro forma tax expense for the year ended December 31, 2001 was $250.1 million
compared with $81.6 million for the same period in 2000. The increase is due
primarily to the tax on the gain related to the sale of Northern Supply business
and higher pre-tax income.
Pro forma minority interest for the year ended December 31, 2001 was $106.5
million compared with $104.3 million for the same period in 2000. The increase
is primarily due to increased minority interest at HomeServices.
The cumulative effect of change in accounting principle of $4.6 million in 2001
represents the change in accounting for major maintenance and overhauls.
Pro forma net income for the year ended December 31, 2001 was $142.7 million
compared with $124.9 million for the same period in 2000.
Results of Operations for the Periods March 14, 2000 through December 31, 2000,
January 1, 2000 through March 13, 2000 and for the Year Ended December 31, 1999:
The following is a discussion of the historical results of the Company for 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, and for the year ended December 31, 1999. Results for the
Company include the results of MEHC (Predecessor) beginning March 14, 2000, in
conjunction with the Teton Transaction. The impact of the transaction is
reflected in the Company's results of operations, predominately minority
interest costs on issuance of Company-obligated mandatorily redeemable preferred
securities of subsidiary trust and the effects of purchase accounting, including
goodwill amortization and fair value adjustments to the carrying value of assets
and liabilities. In order to provide comparability between periods, the Company
has prepared pro forma results as if the Teton Transaction and the MidAmerican
acquisition had occurred at the beginning of each year after giving effect to
pro forma adjustments related to the acquisitions, including the sales of the
qualified facilities, the redemption of limited recourse notes, the redemption
of the senior discount notes and the issuance of the 11% trust preferred
securities. The discussion therefore will highlight any significant variances on
a pro forma basis from the year ended December 31, 1999 to the year ended
December 31, 2000.
Pro forma operating revenue for the year ended December 31, 2000 was $5,235.0
million compared with $4,572.8 million for the same period in 1999, an increase
of 14.5%. MidAmerican operating revenue increased for the year ended December
31, 2000 to $2,576.9 million from $1,871.9 million for the same period in 1999,
primarily due to increases in nonregulated gas sales and higher rates in
regulated gas. CE Electric UK Funding operating revenue decreased for the year
ended December 31, 2000 to $1,997.9 million from $2,072.2 million for the same
period in 1999, primarily due to lower volumes of electricity supplied in the
franchise area and lower foreign exchange rates partially offset by higher
volumes of electricity supplied out of the franchise area and distribution
revenue from access charges. The remaining increase primarily relates to the
increase of revenue at HomeServices due to acquisitions in late 1999.
The following data represents sales from MidAmerican Energy:
Year Ended December 31,
2000 1999
-------- --------
Electricity Retail Sales (GWh)............. 16,715 16,007
Electricity Sales for Resale (GWh)......... 6,941 7,168
Regulated and Nonregulated Gas Supplied
(Thousands of MMBTUs)...................... 174,385 138,387
MidAmerican Energy electricity retail sales increased for the year ended
December 31, 2000 from the same period in 1999 due to increased customers and
non-weather related sales partially offset by more moderate temperatures.
Electricity sales for resale decreased for the year ended December 31, 2000 from
the same period in 1999 due to a lower power plant output primarily from the
Cooper facility which results in lower energy available for resale. Gas supplied
increased due to an increase in customers, an increase in heating degree days
and an increase in trading activity of nonregulated sales.
The following data represents the supply and distribution operations in the
U.K.:
Year Ended December 31,
2000 1999
---------- ----------
Electricity Supplied (GWh)............... 19,925 17,984
Electricity Distributed (GWh)............. 16,350 15,943
Gas Supplied (Thousands of MMBtus)...... 51,035 48,435
The increase in electricity supplied for the year ended December 31, 2000 is due
primarily to the increase in volumes for customers outside of the franchise
area. The increase in electricity distributed for the year ended December 31,
2000 is due to changes in demand in the franchise area. The increase in gas
supplied in 2000 from 1999 reflects higher volume in the U.K. industrial and
commercial markets.
Pro forma interest and other income for the year ended December 31, 2000 was
$114.4 million compared with $145.4 million for the same period in 1999. The
decrease was due primarily to the reduced interest income resulting from lower
cash balances, lower dividends from Teesside and gains on other asset sales in
1999, partially offset by proceeds on Company-owned life insurance of $7.5
million received in 2000.
The 1999 gain on non-recurring items resulted from the sale of approximately
6.74 million shares of McLeod Class A common stock, through a secondary offering
by McLeod, at $55.625 per share. Proceeds from the sale exceeded $375 million,
with a resulting after-tax gain to the Company of approximately $47.1 million.
As a result of the sales of Coso and an interest in CE Generation, the Company
recorded a gain of $20.2 million in the first quarter of 1999.
In the fourth quarter of 1999, the Company recorded a pre-tax gain of $40.3
million relating to insurance proceeds received from an arbitration settlement
between Himpurna California Energy Ltd. and Patuha Power Ltd., former
subsidiaries of the Company, and P.T. PLN (Persero), an Indonesian national
electric utility.
Pro forma cost of sales for the year ended December 31, 2000 was $3,029.7
million compared with $2,398.6 million for the same period in 1999, an increase
of 26.3%. The increase relates to increased sales at MidAmerican Energy and
HomeServices.
Pro forma operating expense for the year ended December 31, 2000 was $1,123.6
million compared with $1,115.8 million for the same period in 1999. The increase
primarily relates to the increase of operating expenses at HomeServices due to
acquisitions in late 1999.
Pro forma depreciation and amortization for the year ended December 31, 2000 was
$479.6 million compared with $462.0 million for the same period in 1999. The
increase was primarily due to higher depreciation at CE Electric UK Funding
primarily due to higher production at CE Gas.
Pro forma interest expense, less amounts capitalized, for the year ended
December 31, 2000 was $398.1 million compared with $447.0 million for the same
period in 1999, a decrease of 10.9%. This decrease was due to the repayment of
the 9.5% Senior Notes in 1999 and other reduced indebtedness and an increase in
capitalized interest related to the construction of Casecnan, Cordova and Zinc.
The loss on non-recurring items of $7.6 million in the period from January 1,
2000 through March 13, 2000 represents the costs related to the Teton
Transaction.
Pro forma tax expense for the year ended December 31, 2000 was $81.6 million
compared with $89.4 million for the same period in 1999. The decrease is due
primarily to lower pretax income in 2000.
Pro forma minority interest for the year ended December 31, 2000 was $104.3
million compared with $101.9 million for the same period in 1999. Minority
interest includes the dividends on the $455 million of Company-obligated
mandatorily redeemable preferred securities of subsidiary trusts.
Pro forma net income for the year ended December 31, 2000 was $124.9 million
compared with $138.3 million for the same period in 1999.
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 $386.7 million at December 31, 2001
compared to $38.2 million at December 31, 2000. The increase is primarily due to
the addition of Yorkshire and the timing of cash receipts and disbursements at
MidAmerican Energy. In addition, the Company recorded separately restricted cash
and investments of $54.8 million and $90.9 million at December 31, 2001 and
2000, respectively. The restricted cash balance as of December 31, 2001 is
comprised primarily of amounts deposited in restricted accounts from which the
Company will fund the various projects under construction. Additionally, the
Leyte Projects', Casecnan's and a portion of Cordova's restricted cash is
reserved for the service of debt obligations.
On March 1, 2001 MidAmerican Funding, LLC retired $200 million of 5.85% Senior
Secured Notes due 2001. On March 19, 2001 MidAmerican Funding, LLC issued $200
million of 6.75% Senior Secured Notes due March 1, 2011.
September 21, 2001, CE Electric UK Ltd., an indirect wholly owned subsidiary of
the Company, and Innogy Holdings, plc executed an agreement to exchange
Northern's electricity and gas supply and metering assets for Innogy's 94.75%
interest in Yorkshire's electricity distribution business. Northern's supply
business was initially valued at approximately $430 million ((pound)295
million), including working capital of approximately $53 million ((pound)37
million). 94.75% of Yorkshire's distribution business was initially valued at
approximately $395 million ((pound)271 million), including working capital of
approximately $48 million ((pound)33 million). The net cash received by Northern
for the exchange was approximately $35 million ((pound)24 million). Working
capital is subject to adjustment and is currently under review.
The Company paid $37.4 million, net of cash acquired of $362.8 million and
transaction costs, for 94.75% of the Yorkshire electricity distribution business
and related indebtedness.
Subsequent Events
Debt issuance
On February 8, 2002, MidAmerican Energy issued $400 million of 6.75% medium-term
notes due in 2031. The proceeds will be used to refinance existing debt and
preferred securities and for other corporate purposes. MidAmerican Energy has
redeemed its MidAmerican-obligated preferred securities of subsidiary trust on
March 11, 2002 at 100% of the principal amount plus accrued interest.
Prudential California Acquisition
In February 2002, HomeServices completed its purchase of a majority interest in
Prudential California Realty. The cash purchase price of Prudential California
Realty was approximately $74 million, with an option to purchase the remaining
interests. Additionally, HomeServices is obligated to pay a maximum earnout of
$18.5 million calculated based on certain 2002 financial performance measures.
The purchase price was financed using the Company's corporate revolver for $40
million which was contributed to HomeServices as equity and the remaining funds
were borrowed from available credit under the HomeServices's $65 million
revolving credit facility. It is anticipated that the borrowings in connection
with this acquisition will be repaid from HomeServices generated funds. The
acquisition will be accounted for by the purchase method of accounting, and the
Company is in the process of completing the allocation of the purchase price to
the assets and liabilities acquired.
Kern River Acquisition
On March 7, 2002, the Company reached a definitive agreement with The Williams
Companies, Inc. ("Williams") to acquire Williams' Kern River Gas Transmission
Company ("Kern River"), a 926-mile interstate pipeline transporting Rocky
Mountain and Canadian natural gas to markets in California, Nevada and Utah. The
purchase price was $956 million, including $506 million of assumed debt. As part
of the agreement, the Company will continue the planned expansion of the Kern
River system, a project that will more than double the pipeline's capacity with
expected capital expenditures of approximately $1.2 billion. The purchase was
completed on March 27, 2002.
The Kern River pipeline is an important route for the transmission of natural
gas from the vast reserves in the Rocky Mountain states to the rapidly growing
markets in Utah, Nevada and California. Constructed in 1992, Kern River extends
926 miles from Opal, Wyoming, to the San Joaquin Valley near Bakersfield,
California, and has a design capacity of 835 million cubic feet per day.
In August 2001, Williams filed with the Federal Energy Regulatory Commission to
more than double the capacity on the Kern River system by adding approximately
900 million cubic feet per day of additional capacity from Wyoming to California
and markets in between. Upon completion of the expansion project in May 2003,
Kern River will be capable of transporting 1.7 billion cubic feet of natural gas
per day. When converted to electricity, that is enough energy to power
approximately 10 million homes.
In connection with the acquisition of Kern River, the Company issued $323
million of Trust Preferred Securities and $127 million of convertible preferred
stock to Berkshire Hathaway.
In addition to the acquisition of Kern River, the Company also announced its
investment of $275 million in Williams, in exchange for shares of 9-7/8 percent
cumulative convertible preferred stock of Williams. In connection with this
investment, the Company issued $275 million of convertible preferred stock to
Berkshire Hathaway.
Construction
Zinc Recovery Project
CalEnergy Minerals LLC is constructing the Zinc Recovery Project. The Zinc
Recovery Project is designed to have a capacity of approximately 30,000 metric
tons per year and is scheduled to commence commercial operations in 2002. Total
project costs of the Zinc Recovery Project are expected to be approximately
$217.9 million, net of damages, which is being funded by $140.5 million of debt
and the balance from funds provided by the parent company. The Zinc Recovery
Project has incurred $158.8 million, net of damages, of such costs through
December 31, 2001.
MidAmerican Energy
MidAmerican Energy's primary need for capital is utility construction
expenditures. For the year ended December 31, 2001, utility construction
expenditures totaled $250 million, including allowance for funds used during
construction, or capitalized financing costs, and Quad Cities Station nuclear
fuel purchases. All such expenditures were met with cash generated from utility
operations, net of dividends.
Forecasted utility construction expenditures, including allowances for funds
used during construction are $332 million for 2002 and $1.614 billion for 2003
through 2006. Capital expenditure needs are reviewed regularly by management and
may change significantly as a result of such reviews. Through 2007, MidAmerican
Energy plans to develop and construct two electric generating plants in Iowa,
requiring an investment of approximately $1.8 billion. Participation by others
in a portion of the second plant is being discussed. The two plants will provide
approximately 1,400 megawatts of generating capacity. The first project is a
540-megawatt natural gas-fired combined cycle unit with an estimated cost of
$416 million. MidAmerican Energy expects to begin construction on the first
project in Spring 2002 following receipt of all regulatory approvals. It is
anticipated that the first phase of the project will be completed by 2003 with
the remainder being completed in 2005. MidAmerican Energy presently expects that
all utility construction expenditures for the next five years will be met with
the issuance of long-term debt and cash generated from utility operations, net
of dividends. The actual level of cash generated from utility operations is
affected by, among other things, economic conditions in the utility service
territory, weather and federal and state regulatory actions.
Obligations and Commitments
The Company has contractual obligations and commercial commitments that may
affect its financial condition. Based on management's assessment of the
underlying provisions and circumstances of the material contractual obligations
and commercial commitments of the Company, including material off-balance sheet
and structured finance arrangements, there is no known trend, demand,
commitment, event or uncertainty that is reasonably likely to occur which would
have a material effect on the Company's financial condition or results of
operations. The following tables identify material obligations and commitments
as of December 31, 2001 (in millions):
Period Payments Are Due
-----------------------------------------
Contractual Cash Obligations 2003- 2005- After
(in millions) Total 2002 2004 2006 2006
----- ---- ---- ---- ----
Parent company long-term debt (1) $1,850.0 $ - $ 215.0 $ 260.0 $1,375.0
Subsidiary and project debt (1) 5,078.3 317.2 571.6 620.9 3,568.6
Company-obligated mandatorily redeemable
Preferred securities of subsidiary trusts 880.3 - - 136.4 743.9
Subsidiary-obligated mandatorily redeemable
Preferred securities of subsidiary trusts (2) 100.0 100.0 - - -
Mandatorily redeemable preferred securities
of subsidiaries 26.7 6.7 13.3 6.7 -
Power purchase contract 25.9 17.4 8.5 - -
Coal, electricity and natural gas contract
commitments (3) 479.4 163.9 207.3 67.9 40.3
Operating leases (3) 135.6 31.2 46.7 24.2 33.5
-------- ------ ------- -------- --------
Total $8,576.2 $636.4 $1,062.4 $1,116.1 $5,761.3
======== ====== ======== ======== ========
(1) Excludes unamortized debt premiums and discounts
(2) The subsidiary-obligated mandatorily redeemable preferred securities of
subsidiary trusts were redeemed on March 11, 2002
(3) The fuel and energy commitments and operating leases are not reflected on
the consolidated balance sheets
Commitment Expiration per Period
---------------------------------
Other Commercial Commitments (in millions) 2003- 2005- After
Total 2002 2004 2006 2006
----- ---- ---- ---- ----
Unused parent company revolving lines of credit $ 200.7 $ 86.5 $ 114.2 $ - $ -
Parent company letters of credit 45.8 - 45.8 - -
Unused subsidiaries lines of credit 541.8 511.3 30.5 - -
Parent company guarantee of subsidiary debt 176.9 2.1 3.2 3.6 168.0
Subsidiary lines of credit from parent company 10.0 - - - 10.0
-------- ------- ------- ------ ------
Total $ 975.2 $ 599.9 $ 193.7 $ 3.6 $178.0
======== ======= ======= ====== ======
Off Balance Sheet Arrangements
The Company has certain investments that are accounted for under the equity
method in accordance with generally accepted accounting principles. Accordingly,
an amount is recorded on our 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.
The companies which are accounted for under the equity method have an aggregate
$1,120.7 million of debt on their combined, consolidated financial statements
and $105.8 million in outstanding letters of credit. The Company's pro-rata
share of the debt is $552.1 million and is non-recourse to the Company, except
for $139.9 million which the Company has guaranteed on the Salton Sea Funding
Notes and is included in the Company's consolidated balance sheet at December
31, 2001. (See Note 8 in the notes to the consolidated financial statements for
further discussion). The Company's pro-rata share of the outstanding letters of
credit is $52.9 million. The Company is generally not required to support the
debt service obligations of these companies. However, default with respect to
this non-recourse debt could result in a loss of invested equity.
Electric Rate Matters
In 1997, pursuant to a rate proceeding before the IUB, MidAmerican Energy, the
Office of Consumer Advocate and other parties entered into a pricing plan
settlement agreement establishing MidAmerican Energy's Iowa retail electric
rates. That settlement agreement expired on December 31, 2000.
On March 14, 2001, the Office of the Consumer Advocate filed a petition with the
IUB to reduce Iowa retail electric rates by approximately $77 million annually.
On June 11, 2001, MidAmerican Energy responded to that petition by filing a
request with the IUB to increase MidAmerican Energy's Iowa retail electric rates
by $51 million annually. On December 21, 2001, the IUB approved a settlement
agreement that freezes the rates in effect on December 31, 2000, through
December 31, 2005, and, with modifications, reinstates the revenue sharing
provisions of the 1997 pricing plan settlement agreement. Under the 2001
settlement agreement, an amount equal to 50% of revenues associated with returns
on equity between 12% and 14%, and 83.33% of revenues associated with returns on
equity above 14%, in each year will be recorded as a regulatory liability to be
used to offset a portion of the cost of future generating plant investments.
Environmental Matters: Domestic
The U.S. Environmental Protection Agency, or EPA, and 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 these contaminants are in sufficient quantities and at sufficient
concentrations as to warrant remedial action. MidAmerican Energy has evaluated
or is evaluating 27 properties which 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.
MidAmerican Energy's estimate of the probable costs for these sites as of
December 31, 2001, was $22 million. This estimate has been recorded as a
liability and a 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 the
Company's financial position or results of operations.
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 standard were subjected
to legal proceedings, and in February 2001, United States Supreme Court upheld
the constitutionality of the standards, through remanding the issue of
implementation of the ozone standard to the EPA. The impact of the new standards
on MidAmerican Energy is currently unknown.
Environmental Matters: U.K.
The U.K. Government introduced new contaminated land legislation in April 2000
that requires companies to:
o Put in place a program for investigating the company's history to identify
problem sites for which it is responsible;
o make a clear commitment to meeting responsibilities for cleaning up those
sites;
o provide funding to make sure that this can happen; and
o make commitments public.
CE Electric UK Funding 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 2000 were introduced on May 5, 2000. The regulations
required that transformers containing over 50 parts per million (PPM) be
registered with the Environment Agency by July 31, 2000. Transformers containing
500 PPM must be de-contaminated by December 31, 2000. CE Electric UK Funding has
registered 140 items above 50 PPM on 74 sites, decontaminated 18 items and
informed the Environment Agency that it is continuing with its sampling,
labeling and registration program.
The Groundwater Regulations seek to prevent List I and List II substances
entering groundwater and strengthens the UK Environment Agencies powers to
require additional protective measures, especially in areas of important
groundwater supplies. Mineral oils and hydrocarbons are included in the more
tightly controlled List I substances. This affects the high voltage fluid filled
electricity cable network incorporating an insulating fluid currently in the
List I category. Further research may result in recategorization because of the
biodegradable qualities of the cable fluid. The existing voluntary Operating
Code of Practice, as agreed between the Agency and the Electricity Supply
Industries, is undergoing revision through the services of the Electricity
Association to address the regulatory changes. Helpful discussions with the
Environment Agency continue.
The Oil Storage Regulations come into force in 2002 and requires the
introduction of secondary containment measures (bunding) for all above ground
oil storage locations where the capacity is more than 200 litres. 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 will be phased in over the next three years. The
Regulations come into effect as follows:
o March 1, 2002 for all new oil stores.
o September 1, 2003 for existing stores at "significant risk" (i.e. within 10
metres of a water course).
o September 1, 2005 for all remaining stores.
A detailed study of the impacts has been carried out and a plan of action
prepared to ensure compliance.
Nuclear Decommissioning
Each licensee of a nuclear facility is required to provide financial assurance
for the cost of decommissioning its licensed nuclear facility. In general,
decommissioning of a nuclear facility means to safely remove the facility from
service and restore the property to a condition allowing unrestricted use by the
operator. Based on information presently available, the Company expects to
contribute approximately $41 million during the period 2002 through 2006 to an
external trust established for the investment of funds for decommissioning Quad
Cities Station. Approximately 60% of the fair value of the trust's funds are now
invested in domestic corporate debt and common equity securities. The remainder
is invested in investment grade municipal and U.S. Treasury bonds.
Based on information presently available and assuming a September 2004 shutdown
of Cooper, MidAmerican Energy expects to accrue approximately $54 million for
Cooper decommissioning during the period 2002 through 2004. MidAmerican Energy's
obligation, if any, for Cooper decommissioning will be affected by the actual
plant shutdown date. In July 1997, NPPD filed a lawsuit in United States
District Court for the District of Nebraska naming MidAmerican Energy as the
defendant and seeking a declaration of MidAmerican Energy's rights and
obligations in connection with Cooper nuclear decommissioning funding. See
discussion in Item 3, Legal Proceedings.
Cooper and Quad Cities Station decommissioning costs charged to Iowa customers
are included in base rates, and recovery of increases in those amounts must be
sought through the normal ratemaking process. Cooper decommissioning costs
charged to Illinois customers are recovered through a rate rider on customer
billings.
Cooper Nuclear Station
Under a long-term power purchase contract with NPPD, MidAmerican Energy
purchases one-half of the output of Cooper. The Nuclear Regulatory Commission
(NRC) has notified NPPD that, effective April 1, 2002, it will place Cooper in
its "Multiple Repetitive Degraded Cornerstone" category of the NRC's Reactor
Oversight Process Action Matrix. As a result, the NRC will conduct extensive
diagnostic inspections at Cooper, which are currently anticipated to be
completed during the month of June 2002. MidAmerican Energy cannot, at this
time, predict the outcome of the NRC inspections and their impact on the
operation of Cooper. NPPD has informed MidAmerican Energy that it is currently
developing an improvement plan which it believes will address the issues that
caused Cooper to be placed into this category.
Development Activity
The Company is actively seeking to develop, construct, own and operate new
energy projects, both domestically and internationally, the completion of any of
which is subject to substantial risk. 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 and sales contracts 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.
The financing, construction and development of projects outside the United
States entail significant political and financial risks (including, without
limitation, uncertainties associated with first time privatization efforts in
the countries involved, currency exchange rate fluctuations, currency
repatriation restrictions, political instability, civil unrest and
expropriation) and other structuring issues that have the potential to cause
substantial delays or material impairment of the value of the project being
developed, which the Company may not be fully capable of insuring against. The
uncertainty of the legal environment in certain foreign countries in which the
Company may develop or acquire projects could make it more difficult for the
Company to enforce its rights under agreements relating to such projects. In
addition, the laws and regulations of certain countries may limit the ability of
the Company to hold a majority interest in some of the projects that it may
develop or acquire. The Company's international projects may, in certain cases,
be terminated by a government. Projects in operation, construction and
development are subject to a number of uncertainties more specifically described
in the Company's Form 8-K, dated March 26, 1999, filed with the Securities and
Exchange Commission.
New Accounting Pronouncements
In July 2001, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards ("SFAS") No. 141, "Business Combinations", and
SFAS No. 142, "Goodwill and Other Intangible Assets" which establish accounting
and reporting for business combinations. SFAS No. 141 requires all business
combinations entered into subsequent to June 30, 2001, to be accounted for using
the purchase method of accounting. SFAS No. 142 provides that goodwill and other
intangible assets with indefinite lives will not be amortized but tested for
impairment on an annual basis. SFAS No. 142 is effective for the Company
beginning January 1, 2002. Under the current method of assessing goodwill for
impairment, which uses an undiscounted cash flow approach, no material
impairment existed at December 31, 2001. For 2002, the Company will begin to
test goodwill for impairment under the new rules, applying a fair-value-based
approach. The Company is in the process of quantifying the anticipated impact on
its financial condition and results of operations of adopting the provisions of
SFAS No. 142, which could be significant. The historical impact of not
amortizing goodwill would have been to increase net income for the years ended
December 31, 2001, 2000 and 1999 by $94.4 million, $92.4 million and $62.3
million, respectively. However, impairment reviews may result in future periodic
write-downs.
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations", which addresses the accounting for legal obligations associated
with the retirement of tangible, long-lived assets, and the associated asset
retirement costs. This pronouncement is effective for years beginning after June
15, 2002. The Company is evaluating the impact that adoption of this standard
will have on its financial statements.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets", which addresses the financial accounting and
reporting for the impairment or disposal of long-lived assets. This
pronouncement is effective for years beginning after December 15, 2001. The
Company is evaluating the impact that adoption of this standard will have on its
financial statements, but does not believe it will have a material impact on its
financial statements.
QUALITATIVE AND QUANTITATIVE 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. The Company uses hedge accounting for derivative
instruments pertaining to its natural gas purchasing, wholesale electricity
activities, financing activities and preferred stock investing operations. Refer
to Note 16 in notes to consolidated financial statements for further discussion.
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands)
As of December 31,
2001 2000
---------- ----------
Assets
Current Assets:
Cash and investments................................................ $ 386,745 $ 38,152
Restricted cash and short term investments.......................... 30,565 42,129
Accounts receivable................................................. 332,553 833,757
Inventories......................................................... 103,078 81,943
Other current assets................................................ 131,968 96,784
---------- ----------
Total Current Assets............................................. 984,909 1,092,765
Property, plant, contracts and equipment, net ......................... 6,527,448 5,348,647
Excess of cost over fair value of net assets acquired, net............. 3,639,088 3,673,150
Regulatory assets...................................................... 221,120 240,934
Long-term restricted cash and investments.............................. 24,207 48,747
Nuclear decommissioning trust fund and other marketable securities..... 160,938 202,227
Equity investments..................................................... 259,619 246,466
Deferred charges, other investments and other assets................... 798,004 758,003
----------- -----------
Total Assets........................................................ $12,615,333 $11,610,939
=========== ===========
Liabilities and Stockholders' Equity
Current Liabilities:
Accounts payable.................................................... $ 266,027 $ 586,644
Accrued interest.................................................... 130,569 107,726
Accrued taxes....................................................... 88,973 125,645
Other accrued liabilities........................................... 308,924 250,975
Short-term debt..................................................... 256,012 261,656
Current portion of long-term debt................................... 317,180 438,978
----------- -----------
Total Current Liabilities........................................ 1,367,685 1,771,624
Other long-term accrued liabilities.................................... 526,176 976,030
Parent company debt.................................................... 1,834,498 1,829,971
Subsidiary and project debt............................................ 4,754,811 3,388,696
Deferred income taxes.................................................. 1,284,268 945,028
------------ ------------
Total Liabilities................................................... 9,767,438 8,911,349
------------ ------------
Deferred income........................................................ 85,917 79,489
Minority interest...................................................... 44,477 11,491
Company-obligated mandatorily redeemable
preferred securities of subsidiary trusts........................... 788,151 786,523
Subsidiary-obligated mandatorily redeemable
preferred securities of subsidiary trusts ......................... 100,000 100,000
Preferred securities of subsidiaries................................... 121,183 145,686
Commitments and contingencies (Note 20)
Stockholders' Equity:
Zero coupon convertible preferred stock - authorized 50,000 shares,
no par value, 34,563 shares outstanding at December 31, 2001 and 2000 - -
Common stock - authorized 60,000 no par value; 9,281 shares issued
and outstanding at December 31, 2001 and 2000....................... - -
Additional paid in capital............................................. 1,553,073 1,553,073
Retained earnings...................................................... 223,926 81,257
Accumulated other comprehensive loss, net.............................. (68,832) (57,929)
------------ -------------
Total Stockholders' Equity.......................................... 1,708,167 1,576,401
------------ -------------
Total Liabilities and Stockholders' Equity............................. $12,615,333 $11,610,939
=========== ===========
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands)
MEHC (Predecessor)
Year Ended March 14, 2000 January 1, 2000 Year Ended
December 31, through through December 31,
2001 December 31, 2000 March 13,2000 1999
---- ----------------- ------------- ----
Revenue:
Operating revenue................... $5,060,605 $4,147,867 $1,087,125 $4,184,546
Interest and other income........... 96,706 94,882 19,484 143,175
Gains on non-recurring items
(Notes 3 and 15)................... 179,493 - - 138,704
---------- ----------- ---------- ----------
Total revenues......................... 5,336,804 4,242,749 1,106,609 4,466,425
---------- ---------- ---------- ----------
Costs and expenses:
Cost of sales....................... 2,705,002 2,424,279 605,439 2,199,700
Operating expense................... 1,176,422 904,511 219,303 1,001,384
Depreciation and amortization....... 538,702 383,351 97,278 427,690
Interest expense.................... 499,263 396,773 101,330 496,578
Less interest capitalized........... (86,469) (85,369) (15,516) (70,405)
Losses on non-recurring items
(Notes 3 and 15)................... - - 7,605 54,409
---------- ---------- ---------- ----------
Total costs and expenses............... 4,832,920 4,023,545 1,015,439 4,109,356
---------- ---------- ---------- ----------
Income before provision for income
taxes................................ 503,884 219,204 91,170 357,069
Provision for income taxes............. 250,064 53,277 31,008 93,475
---------- ---------- ---------- ----------
Income before minority interest........ 253,820 165,927 60,162 263,594
Minority interest...................... 106,547 84,670 8,850 46,923
---------- ---------- ---------- ----------
Income before extraordinary item and
cumulative effect of change in
accounting principle................ 147,273 81,257 51,312 216,671
Extraordinary item, net of tax......... - - - (49,441)
Cumulative effect of change in
accounting principle, net of tax.... (4,604) - - -
---------- ---------- ---------- ---------
Net income available to common
stockholders....................... $ 142,669 $ 81,257 $ 51,312 $ 167,230
========= ========== ========== =========
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Three Years Ended December 31, 2001
(In thousands)
Accumulated Other
Compre-
Outstanding Additional hensive
Common Common Paid-In Retained Income Treasury
Shares Stock Capital Earnings (Loss) Stock Total
------ ----- ------- -------- ------ ----- -----
Balance January 1, 1999 59,605 $ - $1,238,690 $ 340,496 $ 45 $(752,178) $ 827,053
Net income - - - 167,230 - - 167,230
Other Comprehensive Income:
Foreign currency translation
adjustment * - - - - (12,047) - (12,047)
Unrealized losses on securities,
net of tax of $14 - - - - (27) - (27)
--------
Comprehensive income 155,156
Issuance of stock by subsidiary - - 9,113 - - - 9,113
Exercise of stock options and
other equity transactions 238 - (2,628) - - 7,779 5,151
Purchase of treasury stock (3,376) - - - - (104,847) (104,847)
Conversion of TIDES I 3,477 - 2,845 - - 99,058 101,903
Tax benefit from stock plan - - 1,059 - - - 1,059
- -------------------------------------------------------------------------------------------------------------------------
Balance December 31, 1999 59,944 - 1,249,079 507,726 (12,029) (750,188) 994,588
Net income January 1, 2000 - - - 51,312 - - 51,312
through March 13, 2000
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 losses on securities
net of tax of $1,164 - - - - 2,160 - 2,160
---------
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)
---------
Comprehensive income 131,766
- --------------------------------------------------------------------------------------------------------------------------
Balance December 31, 2001 9,281 $ - $1,553,073 $223,926 $(68,832) $ - $1,708,167
==========================================================================================================================
* Foreign currency translation adjustment has no tax effect
The accompanying notes are an integral part of these financial statements
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
MEHC (Predecessor)
-------------------
March 14, 2000 January 1, 2000 Year Ended
Year Ended through through December 31,
December 31, 2001 December 31, 2000 March 13, 2000 1999
----------------- ----------------- -------------- ----
Cash flows from operating activities:
Net income........................................... $ 142,669 $ 81,257 $ 51,312 $ 167,230
Adjustments to reconcile net cash flows from
operating activities:
Gains on non-recurring items...................... (179,493) - - (138,704)
Extraordinary item, net of tax.................... - - - 49,441
Cumulative effect of change in accounting
principle, net of tax.......................... 4,604 - - -
Depreciation and amortization..................... 442,284 303,354 83,097 363,737
Amortization of excess of cost over fair value of
net assets acquired............................. 96,418 79,997 14,181 63,953
Amortization of deferred financing and other costs 20,529 18,310 4,075 18,181
Provision for deferred income taxes............... 152,920 (15,460) 7,735 (56,590)
Income in excess of distributions on equity
investments..................................... (28,515) (26,607) (3,459) (22,796)
Changes in other items:
Accounts receivable and other current assets.... 617,679 (316,287) 440 53,016
Accounts payable, accrued liabilities, deferred
income and other................................ (424,985) 121,843 13,702 57,491
----------- ---------- --------- ----------
Net cash flows from operating activities............. 844,110 246,407 171,083 554,959
----------- ---------- --------- ----------
Cash flows from investing activities:
Purchase of Yorkshire Electric, MEHC (Predecessor),
and MidAmerican, net of cash acquired............ (41,670) (2,048,266) - (2,501,425)
Proceeds from sale of Northern Supply and qualified
facilities, net of cash disposed................. 377,396 - - 365,074
Proceeds from Indonesia settlement................... - - - 290,000
Acquisition of realty companies, net of cash
acquired......................................... (40,264) - - (36,858)
Purchase of marketable securities.................... - (44,686) (8,251) (92,523)
Proceeds from sale of marketable securities.......... - 69,375 12,562 498,676
Capital expenditures relating to operating projects.. (398,165) (301,948) (44,355) (360,898)
Philippine construction.............................. (82,181) (58,531) (22,736) (62,059)
Acquisition of U.K. gas assets....................... - - - (72,280)
Construction and other development costs............. (96,406) (178,250) (56,450) (180,683)
Decrease in restricted cash and investments.......... 24,540 157,905 48,788 199,588
Other................................................ 18,206 15,241 15,568 (7,432)
---------- ---------- --------- -----------
Net cash flows from investing activities............. (238,544) (2,389,160) (54,874) (1,960,820)
---------- ----------- ---------- -----------
Cash flows from financing activities:
Proceeds from issuance of common and preferred stock. - 1,428,024 - -
Proceeds from issuance of trust preferred securities. - 454,772 - -
Repayments of parent company debt.................... - (4,225) - (853,420)
Net proceeds from corporate revolver................. 68,500 85,000 - -
Net repayment of subsidiary short term debt.......... (74,144) (88,106) (124,761) (136)
Proceeds from subsidiary and project debt............ 200,000 262,176 6,043 1,394,094
Repayments of subsidiary and project debt............ (437,372) (234,776) (3,135) (331,880)
Deferred charges relating to debt financing.......... (2,073) (3,805) - 7,761
Redemption of preferred securities of subsidiaries... (24,910) (20,409) - -
Purchase of treasury stock........................... - - - (104,847)
Other................................................ 8,607 198 (6,648) 4,303
---------- ---------- ---------- ---------
Net cash flows from financing activities............. (261,392) 1,878,849 (128,501) 115,875
----------- ---------- ---------- ---------
Effect of exchange rate changes...................... (1,394) (1,555) (424) 165
----------- ---------- ---------- ----------
Net increase (decrease) in cash and cash equivalents. 342,780 (265,459) (12,716) (1,289,821)
Cash and cash equivalents at beginning of period..... 38,152 303,611 316,327 1,606,148
---------- ----------- ---------- ----------
Cash and cash equivalents at end of period........... $ 380,932 $ 38,152 $ 303,611 $ 316,327
========== ========== ========= ==========
Supplemental Disclosures:
Interest paid, net of amount capitalized............. $ 389,953 $ 351,532 $ 35,057 $ 439,894
========== ========== ========= ==========
Income taxes paid.................................... $ 133,139 $ 94,405 $ - $ 130,875
========== ========== ========= ==========
The accompanying notes are an integral part of these financial statements.
MidAmerican Energy Holdings Company
Notes To Consolidated Financial Statements
1. Business
MidAmerican Energy Holdings Company and its subsidiaries (the "Company" or
"MEHC"), is a United States-based privately owned global energy company with
publicly traded 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 the Company is organized
and managed on five separate platforms: MidAmerican Energy, CE Electric UK
Funding, CalEnergy Generation-Domestic, CalEnergy Generation-Foreign and
HomeServices.
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, 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.
MidAmerican Energy
MidAmerican Energy Company ("MidAmerican Energy") is a regulated public utility
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 the retail level in
Iowa, Illinois and South Dakota. It also distributes natural gas at the retail
level in Iowa, Illinois, South Dakota and Nebraska. As of December 31, 2001,
MidAmerican Energy had approximately 673,000 retail electric customers and
652,000 retail natural gas customers.
In addition to retail sales, MidAmerican Energy sells electric energy and
natural gas to other utilities, marketers and municipalities that distribute it
to end-use customers. These sales are referred to as sales for resale or
off-system 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.
A substantial portion of MidAmerican Energy's business still operates in a
rate-regulated environment and, accordingly, many decisions for obtaining and
using resources are evaluated from an electric and gas regulated business
perspective. MidAmerican Energy's operations are seasonal in nature with a
disproportionate percentage of revenues and earnings historically being earned
in the Company's first and third quarters.
CE Electric UK Funding
The business of CE Electric UK Funding, an indirect wholly owned subsidiary of
the Company, consists of Northern Electric plc ("Northern"), an indirect wholly
owned subsidiary of the Company, and Yorkshire Power Group Ltd. ("Yorkshire"),
an indirect majority owned subsidiary of the Company, and CalEnergy Gas
(Holdings) Limited ("CE Gas"), an indirect wholly owned subsidiary of the
Company.
Northern's and Yorkshire's operations consist primarily of the distribution of
electricity and other auxiliary businesses in the United Kingdom. Through
September 21, 2001, Northern's operations also included the supply of
electricity and natural gas and the related metering business.
Northern and Yorkshire receive electricity from the national grid transmission
system and distribute it to customers' premises using their network of
transformers, switchgear and cables. Substantially all of the customers in their
distribution service areas are connected to their network and can only be
delivered through their distribution system, thus providing Northern and
Yorkshire with distribution volume that is stable from year to year. Northern
and Yorkshire charge access fees for the use of the distribution system. The
prices for distribution 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.
Northern's supply business was primarily involved in the bulk purchase of
electricity, previously through a central pool and from March 27, 2001 on
through the New Electricity Trading Agreements ("NETA"), and subsequent resale
to individual customers throughout the U.K. The supply business generally is a
high volume business that tends to operate at lower profitability levels than
the distribution business. Northern also competed to supply gas inside and
outside its authorized area. See Note 3.
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. CE Gas holds various interests in the southern basin
of the United Kingdom sector of the North Sea. Also, CE Gas has been involved in
certain gas development and exploration activities relating to a large gas field
prospect in Poland, the EP389 concession in the Perth Basin in Australia and the
Yolla discovery in the Bass Basin of Australia.
CalEnergy Generation-Domestic
The Company has a 50% ownership interest in CE Generation LLC ("CE Generation")
that has interests in ten geothermal plants in the Imperial Valley, California
and three natural gas-fired cogeneration plants. For purposes of consistent
presentation, plant capacity factors for Vulcan, Hoch (Del Ranch), Turbo, Elmore
and Leathers (collectively the "Partnership Projects") are based on capacity
amounts of 34, 38, 10, 38, and 38 net MW, respectively, and for Salton Sea I,
Salton Sea II, Salton Sea III, Salton Sea IV and Salton Sea V plants
(collectively the "Salton Sea Projects") are based on capacity amounts of 10,
20, 50, 40 and 49 net MW, respectively (the Partnership Projects and the Salton
Sea Projects are collectively referred to as the "Imperial Valley Projects").
Plant capacity factors for Saranac, Power Resources and Yuma (collectively the
"Gas Plants") are based on capacity amounts of 240, 200, and 50 net MW,
respectively. Each plant possesses an operating margin that allows for
production in excess of the amount listed above. 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. Due to its 50% ownership
interest in CE Generation, the Company accounts for CE Generation as an equity
investment.
Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned
subsidiary of the Company, operates a 537 MW gas-fired power plant in the Quad
Cities, Illinois area (the "Cordova Project"). The Cordova Project commenced
commercial operations on June 19, 2001. Cordova Energy has entered into a power
purchase agreement with a unit of El Paso Energy Corporation ("El Paso") in
which El Paso will purchase all of the capacity and energy from the project
until December 31, 2019. Cordova Energy has exercised an option under the El
Paso Power Purchase Agreement to callback 50% of the project output for sales to
others for the contract years ending on or prior to May 14, 2004. Cordova Energy
subsequently entered into a power purchase agreement with MidAmerican Energy
whereby MidAmerican Energy will purchase 50% of the capacity and energy from the
Cordova Project until May 14, 2004.
CalEnergy Generation-Foreign
The Company indirectly owns the Upper Mahiao, Malitbog and Mahanagdong Projects
(collectively, the "Leyte Projects"), which are geothermal power plants located
on the island of Leyte in the Philippines, and the Casecnan Project, a combined
irrigation and hydroelectric power generation project located in the central
part of the island of Luzon in the Philippines. The Casecnan Project commenced
commercial operations on December 11, 2001. For purposes of consistent
presentation, capacity amounts for Upper Mahiao, Malitbog, Mahanagdong and
Casecnan are 119, 216, 165 and 150 net MW, respectively. Each plant possesses an
operating margin that allows for production in excess of the amount listed
above. 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.
HomeServices
HomeServices.Com, Inc. ("HomeServices"), a wholly-owned subsidiary of the
Company, is the second largest residential real estate brokerage firm in the
United States based on aggregate closed transaction sides in 2000 for its
various brokerage firm operating subsidiaries. Closed transaction sides mean
either the buy side or sell side of any closed home purchase and is the standard
term used by industry participants and publications to rank real estate
brokerage firms. In addition to providing traditional residential real estate
brokerage services, HomeServices cross sells to its existing real estate
customers preclosing services, such as mortgage origination and title services,
including title insurance, title search, escrow and other closing administrative
services, assists in securing other preclosing and postclosing services provided
by third parties, such as home warranty, home inspection, home security,
property and casualty insurance, home maintenance, repair and remodeling and is
developing various related e-commerce services. HomeServices currently operates
in the following fourteen states: Minnesota, Iowa, California, Arizona, Kansas,
Missouri, Kentucky, Nebraska, Wisconsin, Indiana, Maryland, North Dakota, South
Dakota and Georgia. HomeServices generally occupies the number one or number two
market share position in each of its major markets based on aggregate closed
transaction sides for the year ended December 31, 2001. HomeServices' major
markets consist of the following metropolitan areas: Minneapolis and St. Paul,
Minnesota; Des Moines, Iowa; Los Angeles and San Diego, California; Omaha,
Nebraska; Kansas City, Kansas; Louisville, Kentucky; Springfield, Missouri;
Tucson, Arizona; Annapolis, Maryland and Atlanta, Georgia.
2. Summary of Significant Accounting Policies
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.
Cash Equivalents, Investments, and Restricted Cash and Investments
The Company considers all investment instruments purchased with an original
maturity of three months or less to be cash equivalents. Investments other than
restricted cash are primarily commercial paper and money market securities.
Restricted cash is not considered a cash equivalent.
The 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 long-term restricted cash and investments balances are mainly composed of
amounts deposited in restricted accounts from which the Company will fund the
various projects under construction.
The Company's restricted investments are classified as held-to-maturity and are
accounted for at their amortized cost basis. The carrying amount of the
investments approximates the fair value based on quoted market prices as
provided by the financial institution that holds the investments.
The Company's nuclear decommissioning trust funds and other marketable
securities are classified as available for sale and are accounted for at fair
value.
Inventory
Inventory is primarily composed of materials and supplies, coal stocks, gas in
storage and fuel oil. Materials and supplies, coal stocks and fuel oil are at
average cost and gas in storage is accounted for under the LIFO method.
Property, Plant, Contracts, Equipment and Depreciation
The cost of major additions and betterments are capitalized, while replacements,
maintenance, and repairs that do not improve or extend the lives of the
respective assets are expensed.
Depreciation of the operating power plant costs, net of salvage value, is
computed on the straight-line method over the estimated useful lives, between
ten and thirty years. Depreciation of furniture, fixtures and equipment that are
recorded at cost, is computed on the straight-line method over the estimated
useful lives of the related assets, which range from three to ten years.
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.
Expenditures on major information technology systems are capitalized and
depreciated on a straight-line basis over the estimated useful lives of the
developed systems that range from three to fifteen years.
An allowance for the estimated annual decommissioning costs of the Quad Cities
Generating Station ("Quad Cities Station") equal to the level of funding is
included in depreciation expense. See Note 20 for additional information
regarding decommissioning costs.
Excess of Cost over Fair Value of Net Assets Acquired
Total acquisition costs in excess of the fair values assigned to the net assets
acquired are amortized using the straight line method over a 25 to 40 year
period.
Impairment of Long-Lived Assets
The Company reviews long-lived assets and certain identifiable intangibles for
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. An impairment loss would be
recognized, based on discounted cash flows or various fair value models,
whenever evidence exists that the carrying value is not recoverable.
Contingent Liabilities
The Company is subject to the possibility of various loss contingencies arising
in the ordinary course of business. Management considers the likelihood of the
loss or impairment of an asset or the incurrence of a liability as well as our
ability to reasonably estimate the amount of loss in determining loss
contingencies. An estimated loss contingency is accrued when it is probable that
a liability has been incurred or an asset has been impaired and the amount of
loss can be reasonably estimated. The Company regularly evaluates current
information available to determine whether such accruals should be adjusted.
Revenue Recognition
Revenues are recorded based upon services rendered and electricity, gas and
steam delivered, distributed or supplied to the end of the period. Where there
is an over recovery of distribution business revenues against the maximum
regulated amount, revenues are deferred 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.
The Company also records unbilled revenues 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. Accrued unbilled revenues are
included in accounts receivable on the consolidated balance sheets.
Capitalization of Interest and Deferred Financing Costs
Prior to the commencement of operations, interest is capitalized on the costs of
the construction projects and resource development to the extent incurred.
Capitalized interest and other deferred charges are amortized over the lives of
the related assets.
Deferred financing costs are amortized over the term of the related financing
using the effective interest method.
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.
Financial Instruments
The Company currently utilizes or had previously utilized 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.
Foreign Currency Translation and Transactions
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. Revenues and expenses
are translated at average exchange rates for the year.
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.
Reclassification
Certain amounts in the fiscal 2000 and 1999 consolidated financial statements
and supporting note disclosures have been reclassified to conform to the fiscal
2001 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 revenues and expenses during the reporting period. Actual
results could differ from those estimates.
Accounting for Long-Term Power Purchase Contract
Under a long-term power purchase contract with Nebraska Public Power District
("NPPD"), expiring in 2004, MidAmerican Energy purchases one-half of the output
of the 778-megawatt Cooper Nuclear Station ("Cooper"). The consolidated balance
sheets include a liability for MidAmerican Energy's fixed obligation to pay 50%
of NPPD's Nuclear Facility Revenue Bonds and other fixed liabilities. A like
amount representing MidAmerican Energy's right to purchase power is shown as an
asset.
Cooper capital improvement costs prior to 1997, including carrying costs, were
deferred in accordance with then applicable rate regulation and are being
amortized and recovered in rates over either a five-year period or the remaining
term of the power purchase contract. Beginning July 11, 1997, the Iowa portion
of capital improvement costs is recovered currently from customers and is
expensed as incurred. For jurisdictions other than Iowa, MidAmerican Energy
began charging Cooper capital improvement costs to expense as incurred in
January 1997.
The fuel cost portion of the power purchase contract is included in cost of
sales. All other costs MidAmerican Energy incurs in relation to its long-term
power purchase contract with NPPD are included in operating expense.
Accounting Principle Change
Effective January 1, 2001, the Company has changed its accounting policy
regarding major maintenance and repairs for nonregulated gas projects,
nonregulated 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 $.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
proforma basis.
Accounting for Derivatives
The Company is exposed to market risk, including changes in the market price of
certain commodities and interest rates. To manage the price volatility relating
to these exposures, the Company enters into various financial derivative
instruments. Senior management 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. The Company uses hedge accounting for derivative
instruments pertaining to its natural gas purchasing, wholesale electricity
activities, financing activities and preferred stock investing operations.
On January 1, 2001, the Company adopted Statement of Financial Accounting
Standards Nos. 133 and 138 (SFAS Nos. 133/138) pertaining to the accounting for
derivative instruments and hedging activities. SFAS Nos. 133/138 requires an
entity to recognize all of its derivatives as either assets or liabilities in
its statement of financial position and measure those instruments at fair value.
If the conditions specified in SFAS Nos. 133/138 are met, those instruments may
be designated as hedges. Changes in the value of hedge instruments would not
impact earnings, except to the extent that the instrument is not perfectly
effective as a hedge. At January 1, 2001, the Company recognized $44.9 million
and $38.0 million of energy-related assets and liabilities, respectively, as
being subject to fair value accounting pursuant to SFAS Nos. 133/138, all of
which are accounted for as hedges. Additionally, on January 1, 2001, the
Company's portfolio of preferred stock investments was transferred from the
available for sale category to the trading category, as permitted by SFAS No.
133. Initial adoption of SFAS Nos. 133/138 did not have a material impact on the
results of operations for the Company.
New Accounting Pronouncements
In July 2001, the FASB issued SFAS No. 141, "Business Combinations", and SFAS
No. 142, "Goodwill and Other Intangible Assets" which establish accounting and
reporting for business combinations. SFAS No. 141 requires all business
combinations entered into subsequent to June 30, 2001, to be accounted for using
the purchase method of accounting. SFAS No. 142 provides that goodwill and other
intangible assets with indefinite lives will not be amortized but tested for
impairment on an annual basis. SFAS No. 142 is effective for the Company
beginning January 1, 2002. Under the current method of assessing goodwill for
impairment, which uses an undiscounted cash flow approach, no material
impairment existed at December 31, 2001. For 2002, the Company will begin to
test goodwill for impairment under the new rules, applying a fair-value-based
approach. The Company is in the process of quantifying the anticipated impact on
its financial condition and results of operations of adopting the provisions of
SFAS No. 142, which could be significant. The historical impact of not
amortizing goodwill would have been to increase net income for the years ended
December 31, 2001, 2000 and 1999 by $94.4 million, $92.4 million and $62.3
million, respectively. However, impairment reviews may result in future periodic
write-downs.
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations", which addresses the accounting for legal obligations associated
with the retirement of tangible, long-lived assets, and the associated asset
retirement costs. This pronouncement is effective for years beginning after June
15, 2002. The Company is evaluating the impact that adoption of this standard
will have on its financial statements.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets", which addresses the financial accounting and
reporting for the impairment or disposal of long-lived assets. This
pronouncement is effective for years beginning after December 15, 2001. The
Company is evaluating the impact that adoption of this standard will have on its
financial statements, but does not believe it will have a material impact on its
financial statements.
3. Acquisitions/Dispositions
Yorkshire Swap
On September 21, 2001, CE Electric UK Ltd., an indirect wholly owned subsidiary
of the Company, and Innogy Holdings, plc executed an agreement to exchange
Northern's electricity and gas supply and metering assets for Innogy's 94.75%
interest in Yorkshire's electricity distribution business. Northern's supply
business was initially valued at approximately $430 million ((pound)295
million), including working capital of approximately $53 million ((pound)37
million). 94.75% of Yorkshire's distribution business was initially valued at
approximately $395 million ((pound)271 million), including working capital of
approximately $48 million ((pound)33 million). The net cash received by Northern
for the exchange was approximately $35 million ((pound)24 million). Working
capital is subject to adjustment and is currently under review.
The disposition of Northern'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 supply business was $504.4 million of goodwill
allocated based on the relative fair values of the Northern supply business. In
connection with the sale of the Northern supply business, management intends to
sell the associated Northern retail business.
The Company paid $37.4 million, net of cash acquired of $362.8 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.
The following table summarizes the estimated fair values of the assets acquired
and liabilities assumed at the date of acquisition (in millions).
Cash $ 362.8
Property, plant and equipment 1,262.7
Excess of cost over fair value
of net assets acquired 523.6
Other assets 11.6
--------
Total assets acquired 2,160.7
--------
Current liabilities (34.1)
Long-term debt (1,503.3)
Deferred income taxes (175.8)
Minority interest (40.7)
Other liabilities (6.6)
--------
Total liabilities assumed (1,760.5)
--------
Net assets acquired $ 400.2
========
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"). 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, Chief Operating Officer of the Company,
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 that is being
amortized using the straight-line method over a 40-year period.
The Company incurred approximately $7.6 million and $6.7 million of
non-recurring costs in 2000 and 1999 respectively, related to the Teton
Transaction, which were expensed.
Unaudited pro forma combined revenue, income before cumulative effect of change
in accounting principle and net income of the Company and MEHC (Predecessor) for
the years ended December 31, 2001 and 2000, as if the Yorkshire swap and the
Teton Transaction had occurred at the beginning of each year after giving effect
to pro forma adjustments related to the acquisitions, including the sale of the
Northern Supply business and the issuance of the 11% trust preferred securities,
were $4,401.0 million, $149.1 million and $144.5 million, respectively, compared
to $4,084.0 million, $113.3 million and $113.3 million, respectively.
HomeServices
On October 18, 1999, the Company closed on its initial public offering of 3.25
million shares of common stock of HomeServices at $15 per share. HomeServices
sold 2.19 million newly issued shares and the Company, the selling stockholder,
sold 1.06 million of its HomeServices shares in the offering. The offering
reduced the Company's ownership in HomeServices to approximately 65%.
On April 14, 2000, the Company purchased 500,000 shares of HomeServices' common
stock for $4.2 million, increasing the Company's ownership percentage to
approximately 70%.
In October 2000, HomeServices repurchased 1.7 million shares of treasury stock
for $17.9 million. This transaction increased the Company's ownership percentage
to approximately 83%.
On August 27, 2001, the Company commenced a tender offer to purchase the
remaining outstanding shares of common stock of HomeServices for a cash purchase
price of $17 per share. On September 25, 2001, the Company announced that it had
successfully completed the tender offer for all outstanding shares of the common
stock of HomeServices for $29.3 million. As a result, the Company owns 100% of
the outstanding HomeServices common stock, although options entitling employees
to purchase HomeServices common stock remain outstanding.
4. Property, Plant, Contracts and Equipment, Net
Property, plant, contracts and equipment, net comprise the following at December
31 (in thousands):
2001 2000
---- ----
Operating assets:
Utility generation and distribution
system................................ $7,574,339 $6,132,867
Independent power plants .............. 1,398,179 694,615
Utility non-operational assets......... 354,366 344,576
Power sales agreements................. 48,185 82,231
Realty company assets.................. 51,150 37,936
Other assets........................... 47,863 53,590
---------- ----------
Total operating assets................. 9,474,082 7,345,815
Less accumulated depreciation
and amortization...................... (3,650,862) (3,300,237)
---------- ----------
Net operating assets................... 5,823,220 4,045,578
Mineral and gas reserves and
exploration assets, net............... 387,697 378,495
Construction in progress:
Zinc recovery project............. 163,366 165,585
Utility generation and
distribution system............. 149,225 143,261
Casecnan.......................... - 387,274
Cordova........................... - 224,514
Other............................. 3,940 3,940
---------- ----------
Total $6,527,448 $5,348,647
========== ==========
Zinc Recovery Project
The Company owns the rights to proprietary processes for the extraction of
minerals from elements in solution in the geothermal brine and fluids utilized
at its Imperial Valley plants. A pilot plant has successfully produced
commercial quality zinc at the Company's Imperial Valley Projects.
CalEnergy Minerals LLC, an indirect wholly owned subsidiary of the Company, is
constructing the Zinc Recovery Project which will recover zinc from the
geothermal brine (the "Zinc Recovery Project"). Facilities are being installed
near the Imperial Valley Project's sites to extract a zinc chloride solution
from the geothermal brine through an ion exchange process. This solution will be
transported to a central processing plant where zinc ingots will be 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 and is scheduled to commence commercial operations in 2002. In
September 1999, CalEnergy Minerals LLC entered into a sales agreement whereby
all zinc produced by the Zinc Recovery Project will be sold to Cominco, Ltd. The
initial term of the agreement expires in December 2005.
The Zinc Recovery Project was being constructed by Kvaerner U.S. Inc.
("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering,
procure, construct and manage contract (the "Zinc Recovery Project EPC
Contract"). On June 14, 2001, CalEnergy Minerals LLC issued notices of default,
termination and demand for payment of damages to Kvaerner under the Zinc
Recovery Project EPC Contract due to failure to meet performance obligations. As
a result of Kvaerner's failure to pay monetary obligations under the Zinc
Recovery Project EPC Contract, CalEnergy Minerals LLC drew $29.6 million under
the EPC Contract Letter of Credit on July 20, 2001. CalEnergy Minerals LLC has
entered into a time and materials reimbursable engineer, procure and
construction management contract with AMEC E&C Services, Inc. to complete the
Zinc Recovery Project.
On July 11, 2001, Kvaerner filed an Amended Demand For Arbitration against
CalEnergy Minerals LLC characterizing the nature of the dispute as concerns
regarding change orders and performance penalties. Kvaerner did not state the
amount of its claim.
On August 7, 2001, CalEnergy Minerals LLC filed an Answering Statement and
Counterclaim against Kvaerner. CalEnergy Minerals LLC denied all material
allegations in Kvaerner's Amended Demand for Arbitration, and asserted a
counterclaim against Kvaerner for breach of contract and specific performance.
CalEnergy Minerals LLC alleged that its total estimated damage for Kvaerner's
breach of contract are in excess of approximately $60 million; however,
CalEnergy Minerals LLC has offset approximately $42.5 million of these damages
by exercising its rights under the EPC Contract to claim the retainage and by
drawing on a letter of credit. Therefore, CalEnergy Minerals LLC has asked for a
judgment in excess of approximately $20 million. The arbitration is scheduled
for June 2002.
5. Equity Investment in CE Generation
Due to the sale of 50% of its interests in CE Generation, the Company has
accounted for CE Generation as an equity investment beginning March 3, 1999. The
equity investment in CE Generation at December 31, 2001 and 2000 was
approximately $233.6 million and $220.0 million, respectively. The following is
summarized financial information for CE Generation as of and for the years ended
December 31 (in thousands):
2001 2000 1999
---- --- ----
Revenues.............................. $ 565,838 $ 510,796 $ 340,683
Income before extraordinary item
and cumulative effect of
change in accounting principle.... 74,194 73,535 61,970
Net income............................ 58,808 73,535 44,492
Current assets........................ 211,635 188,234
Total assets.......................... 1,932,119 1,984,445
Current liabilities................... 155,808 138,751
Long-term debt, including
current portion................... 1,096,256 1,163,729
Total liabilities..................... 1,404,910 1,477,066
6. Short-Term Debt
Short-term debt comprises the following at December 31 (in thousands):
2001 2000
---- ----
Corporate revolving credit facilities......... $153,500 $ 85,000
MidAmerican Energy short-term debt............ 91,780 81,600
HomeServices revolving credit facility........ 9,000 10,000
Other......................................... 1,732 85,056
-------- --------
$256,012 $261,656
========= ========
Corporate Revolving Credit Facilities
The Company has available $400 million in revolving credit facilities with $150
million expiring in June 2002 and $250 million expiring in June 2003. The
facilities are unsecured and are available to fund working capital requirements
and finance future business expansion opportunities. The facilities carry a
variable interest rate based on LIBOR and ranging from 2.8125% to 8.5% in 2001
(weighted average interest rate of 2.93% at December 31, 2001).
MidAmerican Energy Short-Term Debt
MidAmerican Energy has authority from the Federal Energy Regulatory Commission
("FERC") to issue short-term debt in the form of commercial paper and bank notes
aggregating $500 million. As of December 31, 2001, MidAmerican Energy had in
place a $370.4 million revolving credit facility that supports its $250 million
commercial paper program and its variable rate pollution control revenue
obligations. In addition, MidAmerican Energy has a $5 million line of credit. As
of December 31, 2001, commercial paper and bank notes totaled $89.4 million for
MidAmerican Energy.
MHC Inc., an indirect wholly owned subsidiary of the Company, has a $4.0 million
line of credit under which $2.4 million was outstanding at December 31, 2001.
The commercial paper, bank notes and outstanding line of credit have a weighted
average interest rate of 1.9% at December 31, 2001.
HomeServices Revolving Credit Facilities
HomeServices has available a $65 million senior secured revolving credit
facility of which HomeServices had drawn down approximately $9 million as of
December 31, 2001. This credit agreement has a variable interest rate at either
the prime lending rate or LIBOR plus a fixed spread of 1.25% to 2.50% that
varies based on HomeServices' cash flow leverage ratio, as defined in the
agreement. As of December 31, 2001, the blended average interest rate on the
senior secured revolving credit facility borrowings was 3.20%.
7. Parent Company Debt
Parent company debt is unsecured senior obligations of the Company and comprises
the following at December 31 (in thousands):
2001 2000
---- ----
7.63% Senior Notes due 2007.......... $ 350,000 $ 350,000
6.96% Senior Notes due 2003.......... 215,000 215,000
7.23% Senior Notes due 2005.......... 260,000 260,000
7.52% Senior Notes due 2008.......... 450,000 450,000
8.48% Senior Notes due 2028.......... 475,000 475,000
7.52% Senior Notes due 2008.......... 101,680 101,888
Fair value adjustments and other..... (17,182) (21,917)
---------- ----------
$1,834,498 $1,829,971
========== ==========
Interest on the 7.63% Senior Notes is payable semiannually on April 15 and
October 15 of each year. Interest on the remaining parent company debt is
payable semiannually on March 15 and September 15 of each year.
8. Subsidiary and Project Debt
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 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. "Subsidiaries" means all of the Company's direct or indirect
subsidiaries (1) owning interests in CE Electric UK Funding, MidAmerican
Funding, HomeServices, CE Generation, or the Imperial Valley, Saranac, Power
Resources, Mahanagdong, Malitbog, Upper Mahiao, Casecnan, and Cordova projects
or (2) owning interests in the subsidiaries that own interests in the foregoing
subsidiaries or projects.
Project loans held by subsidiaries and projects comprise the following at
December 31 (in thousands):
2001 2000
---- ----
MidAmerican Funding, LLC Senior Notes
and Bonds $ 700,000 $ 700,000
MidAmerican Energy Mortgage Bonds 340,570 340,570
MidAmerican Energy Pollution Control
Bonds 157,185 158,625
MidAmerican Energy Notes 322,240 422,240
CE Electric UK Funding Eurobonds 291,643 299,580
CE Electric UK Funding Company
Senior Notes and Sterling Bonds 646,500 653,750
Yorkshire Electric Debt 1,491,597 -
CE Gas Loan 70,180 73,162
Casecnan Notes and Bonds 320,138 346,439
Philippine Term Loans 313,221 392,625
Cordova Funding Senior Secured Bonds 225,000 225,000
Salton Sea Bonds 139,896 140,528
MidAmerican Capital 8.52% Notes 23,333 46,667
HomeServices 7.12% Senior Notes
and Other 36,780 37,607
Other, including fair value adjustments (6,292) (9,119)
---------- ----------
$5,071,991 $3,827,674
========== ==========
MidAmerican Funding, LLC Senior Notes and Bonds
On March 11, 1999, MidAmerican Funding, LLC, a wholly owned subsidiary of the
Company, issued $200 million of 5.85% Senior Secured Notes due in 2001, $175
million of 6.339% Senior Secured Notes due in 2009, and $325 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, LLC retired $200 million of 5.85% Senior
Secured Notes due 2001. On March 19, 2001 MidAmerican Funding, LLC issued $200
million of 6.75% Senior Secured Notes due March 1, 2011.
MidAmerican Energy Mortgage Bonds, Pollution Control Bonds and Notes
The components of MidAmerican Energy's Mortgage Bonds, Pollution Control Bonds
and Notes at December 31 are as follows (in thousands):
2001 2000
---- ----
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
-------- --------
$340,570 $340,570
======== ========
Pollution control revenue
obligations:
5.75% Series, due periodically
through 2003......................... $ 5,760 $ 7,200
5.95% Series, due 2023 (secured
by general mortgage bonds)........... 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, 1.77%
and 4.56% respectively............ 37,600 37,600
Due 2023 (secured by general
mortgage bond, 1.77% and 4.56%,
respectively)..................... 28,295 28,295
Due 2023, 1.77% and 4.56%
respectively...................... 6,850 6,850
Due 2024, 1.77% and 4.56%
respectively...................... 34,900 34,900
Due 2025, 1.77% and 4.56%
respectively...................... 12,750 12,750
-------- --------
$157,185 $158,625
======== ========
Notes:
8.75% Series, due 2002............... $ 240 $ 240
7.375% Series, due 2002.............. 162,000 162,000
6.5% Series, due 2001................ - 100,000
6.375% Series, due 2006.............. 160,000 160,000
-------- --------
$322,240 $422,240
======== ========
CE Electric UK Funding Eurobonds
The balances at December 31, 2001 and 2000 consists of the following (in
thousands):
2001 2000
---- ----
8.625% Bearer bonds due 2005 $145,879 $149,865
8.875% Bearer bonds due 2020 145,764 149,715
-------- --------
$291,643 $299,580
======== ========
CE Electric UK Funding Company Senior Notes and Sterling Bonds
The balances at December 31 are comprised of the following (in thousands):
2001 2000
---- ----
6.853% Senior Notes due 2004 $124,613 $124,503
6.995% Senior Notes due 2007 235,937 235,804
7.25% Sterling Bonds due 2022 285,950 293,443
-------- --------
$646,500 $653,750
======== ========
The CE Electric UK Funding Company Senior Notes and Sterling Bonds prohibit
distributions to any of its stockholders unless certain financial ratios are met
by the CE Electric UK Funding Company or the long-term debt rating falls below a
prescribed level.
Yorkshire Electric Debt
In connection with the Yorkshire/Northern supply swap on September 21, 2001, the
Company assumed approximately $1.5 billion in debt. The balance at December 31,
2001 is comprised of the following (in thousands):
2001
----
9.250% Eurobond due 2020 $ 383,576
7.250% Eurobond due 2028 311,427
Variable rate Trust Securities due 2020
(5.19% at December 31, 2001) 235,313
8.080% Trust Securities due 2038 261,082
6.496% Yankee Bonds due 2008 300,199
----------
$1,491,597
==========
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 falls below a prescribed level.
CE Gas Loan
CE Gas borrowed $70.2 million and $73.2 million on a (pound) 70 million
revolving facility at December 31, 2001 and 2000, respectively. The amount
carries a variable interest rate based on LIBOR (4.87% at December 31, 2001).
The revolving facility had utilized (pound) 48.3 million and (pound) 49.0
million at December 31, 2001 and 2000, respectively.
Casecnan Notes and Bonds
On November 27, 1995 CE Casecnan issued $371.5 million of notes and bonds to
finance the construction of the Casecnan Project. The balances at December 31
consist of the following (in thousands):
2001 2000
---- ----
Senior Secured Floating Rate Notes (FRNs)
due in 2002 $ 23,638 $ 49,939
11.45% Senior Secured Series A Notes
due in 2005 125,000 125,000
11.95% Senior Secured Series B Bonds
due in 2010 171,500 171,500
-------- --------
$320,138 $346,439
======== ========
The Company held $3.0 million and $6.3 million of the FRNs at December 31, 2001
and 2000, respectively.
The Casecnan Notes and Bonds are subject to redemption at the Company's option
as provided for in the Trust Indenture. The Casecnan Notes and Bonds are also
subject to mandatory redemption based on certain conditions.
Philippine Term Loans
The Overseas Private Investment Corporation ("OPIC") provided term loan
financing for the Company's Malitbog geothermal power project of $46.8 million
that was fixed at an interest rate of 9.176%. A syndicate of international
commercial banks is providing term loan financing of $84.4 million at a variable
interest rate based on LIBOR (4.295% at December 31, 2001). The loans have
scheduled repayments through June 2005.
Export-Import Bank of the United States ("Ex-Im Bank") provided term loan
financing for the Company's Upper Mahiao geothermal power project of $121.3
million at a fixed interest rate of 5.95%. United Coconut Planters Bank of the
Philippines is providing term loan financing of $8.3 million at a variable
interest rate based on LIBOR (5.130% at December 31, 2001). The loans have
scheduled repayments through June 2006.
Ex-Im Bank provided term loan financing for the Company's Mahanagdong geothermal
power project of $154.6 million at a fixed rate of 6.92%. OPIC is providing term
loan financing of $34.3 million at a fixed interest rate of 7.6%. The loans have
scheduled repayments through June 2007.
Cordova Funding Senior Secured Bonds
On September 10, 1999 Cordova Funding Corporation ("Cordova Funding"), a wholly
owned subsidiary of the Company, closed the $225 million aggregate principal
amount financing for the construction of the Cordova Project. The proceeds were
loaned to Cordova Energy and comprise the following (in thousands):
Series Issue Date Due Date Interest Rate Amount
- ------ ---------- -------- ------------- ------
Series A-1 Senior Secured Bonds September 10, 1999 2019 8.64% $93,515
Series A-2 Senior Secured Bonds December 15, 1999 2019 8.79% 31,309
Series A-3 Senior Secured Bonds March 15, 2000 2020 9.07% 29,300
Series A-4 Senior Secured Bonds June 15, 2000 2020 8.82% 58,121
Series A-5 Senior Secured Bonds September 15, 2000 2020 8.48% 12,755
--------
Total $225,000
========
MidAmerican Energy Holdings Company has guaranteed a specified portion of the
scheduled debt service on the Cordova Funding Senior Secured Bonds equal to $37
million.
Salton Sea Bonds
Salton Sea Funding Corporation, an indirect wholly owned subsidiary of CE
Generation, had a debt balance of $520.3 million at December 31, 2001. CalEnergy
Minerals LLC is one of several guarantors of the Salton Sea Funding
Corporation's debt. As a result of a note allocation agreement, CalEnergy
Minerals LLC is primarily responsible for $139.9 million of the 7.475% Senior
Secured Series F Bonds due November 30, 2018. MidAmerican Energy Holdings
Company has guaranteed a specified portion of the scheduled debt service on the
Series F Bonds equal to this current principal amount of $139.9 million and
associated interest.
Annual Repayments of Subsidiary and Project Debt
The annual repayments of the subsidiary and project debt for the years beginning
January 1, 2002 and thereafter are as follows (in thousands):
MidAmerican MidAmerican
Funding, MidAmerican Energy MidAmerican Home CE Electric
LLC Senior Energy Pollution Energy and Services Salton UK
Notes and Mortgage Control Capital Notes Sea Funding
Bonds Bonds Bonds Notes and Other Bonds Eurobonds
----------- ----------- ----------- ----------- ---------- ----------- ---------
2002 $ - $ - $ 1,440 $185,573 $ 706 $ 2,108 $ -
2003 - 100,000 5,320 - 583 1,405 -
2004 - 55,630 - - 5,133 1,757 -
2005 - 90,500 - - 5,048 1,756 145,879
2006 - - - 160,000 5,036 1,827 -
Thereafter 700,000 94,440 150,425 - 20,274 131,043 145,764
-------- -------- -------- --------- --------- -------- --------
$700,000 $340,570 $157,185 $345,573 $ 36,780 $139,896 $291,643
======== ======== ======== ======== ========= ======== ========
CE Electric UK Cordova
Funding Company Funding
Senior Notes Casecnan Philippine Senior
and Sterling Yorkshire CE Notes and Term Secured
Bonds Electric Debt Gas Loan Bonds Loans Bonds TOTAL
------------ ------------- ----------- ----------- ----------- ----------- -------
2002 $ - $ - $ 25,642 $ 32,214 $ 68,259 $ 1,238 $ 317,180
2003 - - 13,050 41,467 72,148 9,000 242,973
2004 124,613 - 16,897 49,360 67,148 8,100 328,638
2005 - - 14,455 54,752 63,034 7,875 383,299
2006 - - 136 36,015 30,037 4,500 237,551
Thereafter 521,887 1,491,597 - 106,330 12,595 194,287 3,568,642
-------- ---------- ---------- --------- --------- -------- ----------
$646,500 $1,491,597 $ 70,180 $320,138 $ 313,221 $225,000 $5,078,283
======== ========== ========== ======== ========= ======== ==========
9. Income Taxes
Provision for (benefit from) income taxes was comprised of the following (in
thousands):
MEHC (Predecessor)
------------------
Year Ended March 14, 2000 January 1, 2000 Year Ended
December 31, through through December 31,
2001 December 31, 2000 March 13, 2000 1999
------------ ----------------- -------------- ------------
Current:
State.......... $ 2,669 $10,527 $(1,886) $ 7,337
Federal........ 51,025 17,387 9,147 128,839
Foreign........ 43,450 40,823 16,012 13,889
-------- ------ ------- --------
97,144 68,737 23,273 150,065
-------- ------ ------- --------
Deferred:
State.......... 22,095 (1,933) 834 1,791
Federal........ (36,441) (32,469) 1,854 (75,510)
Foreign........ 167,266 18,942 5,047 17,129
-------- ------- ------- --------
152,920 (15,460) 7,735 (56,590)
-------- ------- ------- --------
Total.......... $250,064 $53,277 $31,008 $ 93,475
======== ======= ======= ========
A reconciliation of the federal statutory tax rate to the effective tax rate
applicable to income before provision for income taxes follows:
MEHC (Predecessor)
------------------------------
Year Ended March 14, 2000 January 1, 2000 Year Ended
December 31, through through December 31,
2001 December 31, 2000 March 13, 2000 1999
--------- ----------------- -------------- ----------
Federal statutory rate................... 35.0% 35.0% 35.0% 35.0%
Investment and energy tax credits........ (1.0) (2.3) (.7) (1.8)
State taxes, net of federal tax effect... 3.2 2.6 (.8) 1.7
Goodwill amortization.................... 5.9 12.1 5.9 5.5
Dividends on preferred
securities of subsidiary trusts*..... (6.1) (11.1) (2.8) (3.8)
Tax effect of foreign income............. (2.5) (5.8) (5.0) .3
Non-recurring items on CE Electric UK Funding,
net of tax effect of foreign income.. 19.2 - - -
Non-recurring items on Indonesia ........ - - - (11.0)
Dividends received deduction............. (2.6) (6.8) (1.0) (3.7)
Other items, net......................... (1.5) .6 3.4 3.9
------- ----- ----- -----
Effective tax rate....................... 49.6% 24.3% 34.0% 26.1%
===== ===== ===== =====
* Dividends on preferred securities of subsidiary trusts are included in
minority interest.
Deferred tax liabilities (assets) are comprised of the following at December 31
(in thousands):
2001 2000
---------- ----------
Property, plant, contracts and
equipment.................................... $1,245,140 $ 866,678
Income taxes recoverable through
future rates................................. 185,222 186,427
Fuel cost recoveries............................ 20,272 14,598
Reacquired debt................................. 7,544 10,256
--------- ---------
1,458,178 1,077,959
Nuclear reserve and decommissioning............. (17,898) (20,690)
Deferred income................................. (24,732) (8,883)
Deferred contract costs......................... (65,145) (51,703)
Revenue sharing accurals........................ (24,769) (3,742)
Accruals not currently deductible
for tax purposes............................. (35,221) (40,563)
Other........................................... (6,145) (7,350)
---------- ---------
(173,910) (132,931)
Net deferred income taxes....................... $1,284,268 $ 945,028
========== =========
10. 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):
Original Carrying Carrying
Issue Value Value Conversion
Issuer Issue Date Rate Amount December 31, 2001 December 31, 2000 Rate
- ------------------------------ -------------- ---- ------ ----------------- ----------------- ----------
CalEnergy Capital Trust II February 26, 1997 6.25% $180,000 $155,584 $156,084 1.1655
CalEnergy Capital Trust III August 12, 1997 6.50% 270,000 269,984 269,984 1.047
MidAmerican Capital Trust I
(issued to Berkshire) March 14, 2000 11.00% 454,772 454,772 454,772 N/A
Fair value adjustment (92,189) (94,317)
-------- --------
$788,151 $786,523
======== ========
During 2001 and 2000, CalEnergy Capital Trust II redeemed 10,000 and 477,000
shares, respectively, of preferred securities at an aggregate cost of
approximately $.4 million and $19.5 million, respectively.
The Company owns all of the common securities of the Trusts. The Trust
Securities have a liquidation preference of fifty dollars 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 due February
25, 2012, September 1, 2027, and March 14, 2010, respectively, in outstanding
aggregate principal amounts of approximately $155.5 million, $270 million and
$454.8 million, respectively (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.
11. Subsidiary-Obligated Mandatorily Redeemable Preferred Securities of
Subsidiary Trust
In December 1996, MidAmerican Energy Financing I, a wholly owned statutory
business trust of MidAmerican Energy, issued 4,000,000 shares of 7.98% Series
MidAmerican Energy-obligated mandatorily redeemable preferred securities. The
sole assets of MidAmerican Energy Financing are $103.1 million of MidAmerican
Energy 7.98% Series A Debentures due 2045 (the "Debentures"). There is a full
and unconditional guarantee by MidAmerican Energy of MidAmerican Energy
Financing's obligations under the preferred securities. MidAmerican Energy has
the right to defer payments of interest on the Debentures by extending the
interest payment period for up to 20 consecutive quarters. If interest payments
on the Debentures are deferred, distributions on the preferred securities will
also be deferred. During any deferral, distributions will continue to accrue
with interest thereon, and MidAmerican Energy may not declare or pay any
dividend or other distribution on, or redeem or purchase, any of its capital
stock.
If the Debentures, or a portion thereof, are redeemed, MidAmerican Energy
Financing must redeem a like amount of the preferred securities. If a
termination of MidAmerican Energy Financing occurs, MidAmerican Energy Financing
will distribute to the holders of the preferred securities a like amount of the
Debentures unless such a distribution is determined not to be practicable. If a
determination is made, the holders of the preferred securities will be entitled
to receive, out of the assets of MidAmerican Energy Financing after satisfaction
of its liabilities, a liquidation amount of $25 for each preferred security held
plus accrued and unpaid distributions. See Note 21.
12. Preferred Stock
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.
13. 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
granted under the 1996 plan 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 MidAmerican Energy Holdings Company 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.
14. 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.
2001 2000
--------------------------- -----------------------------
Estimated Estimated
Principal Fair Principal Fair
Amount Value Amount Value
----------- ---------- --------- ---------
(in thousands)
7.63% Senior Notes $ 350,000 $ 362,425 $ 350,000 $ 360,115
6.96% Senior Notes 215,000 222,676 215,000 216,570
7.23% Senior Notes 260,000 268,684 260,000 264,004
7.52% Senior Notes 450,000 455,085 450,000 459,090
8.48% Senior Notes 475,000 478,325 475,000 507,918
7.52% Senior Notes 101,680 102,130 101,888 102,020
MidAmerican Funding, LLC Senior Notes and Bonds 700,000 667,402 700,000 657,300
MidAmerican Energy Mortgage Bonds 340,570 356,087 340,570 345,692
MidAmerican Energy Pollution Control Bonds 157,185 157,672 158,625 158,914
MidAmerican Energy Notes 322,240 329,573 422,240 420,496
MidAmerican Capital Notes 23,333 23,849 46,667 46,464
HomeServices Senior Notes and Other 36,780 31,143 37,607 34,094
Salton Sea Bonds 139,896 121,290 140,528 116,947
CE Electric UK Funding Eurobonds 291,643 346,115 299,580 357,456
CE Electric UK Funding Company Senior Notes
and Sterling Bonds 646,500 702,643 653,750 694,031
Yorkshire Electric Debt 1,491,597 1,482,870 - -
Casecnan Notes and Bonds 320,138 291,517 346,439 319,056
Cordova Funding Senior Secured Bonds 225,000 227,442 225,000 224,018
CE Gas Loan 70,180 70,180 73,162 73,162
Company-obligated preferred securities of
subsidiary trusts 880,340 801,722 880,840 769,605
Subsidiary-obligated preferred securities
of subsidiary trusts 100,000 99,640 100,000 98,752
Preferred Securities of Subsidiaries 121,183 107,893 145,686 131,255
Interest Rate Risk
At December 31, 2001, 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 $7,678.0 million in principal amount and having a fair
value of $7,808.2 million. These instruments are fixed-rate and therefore do not
expose the Company to the risk of earnings loss due to changes in market
interest rates. However, the fair value of these instruments would decrease by
approximately $355.7 million if interest rates were to increase by 10% from
their levels at December 31, 2001. 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, 2001, the Company had floating-rate obligations of $281.4
million that expose the Company to the risk of increased interest expense in the
event of increases in short-term interest rates. These obligations are not
hedged. If the floating rates were to increase by 10% from December 31, 2001
levels, the Company's consolidated interest expense for unhedged floating-rate
obligations would increase by approximately $75,000 each month in which such
increase continued based upon December 31, 2001 principal balances.
The amortized cost, gross unrealized gain and losses and estimated fair value of
investments in debt and equity securities at December 31 are as follows (in
thousands):
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
-------- --------- -------- --------
$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
-------- - --------- -------- --------
$ 3,775 $ 85 $ (22) $ 3,838
======== ========= ======== ========
2000
-------------------------------------------------------
Amortized Unrealized Unrealized Fair
Cost Gains Losses Value
--------- ---------- ---------- --------
Available-for-sale:
Equity securities.................... $ 83,509 $ 34,110 $ (7,115) $110,504
Municipal bonds...................... 27,758 1,071 (175) 28,654
U. S. Government securities.......... 26,284 1,163 - 27,447
Corporate securities................. 25,737 48 (1,027) 24,758
Cash equivalents..................... 11,150 - - 11,150
-------- -------- -------- --------
$174,438 $ 36,392 $ (8,317) $202,513
======== ======== ======== ========
Held-to-Maturity:
Debt Securities...................... $ 2,077 $ - $ - $ 2,077
U.S. Treasury Strips................. 677 80 - 757
Agency Obligations................... 571 - (53) 518
-------- -------- -------- --------
$ 3,325 $ 80 $ (53) $ 3,352
======== ======== ======== ========
At December 31, 2001, 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........................... $ 3,269 $ 3,332 $ 3 $ 3
1 through 5 years....................... 28,851 30,706 2,323 2,357
5 through 10 years...................... 10,733 11,578 1,449 1,478
Over 10 years........................... 30,396 31,536 - -
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 March 14, 2000 January 1, Year
Ended through 2000 through Ended
December 31, December 31, March 13, December 31,
2001 2000 2000 1999
------------ -------------- ------------- -------------
Proceeds from sales............. $68,333 $93,531 $22,588 $617,262
Gross realized gains............ 2,676 6,464 1,560 97,545
Gross realized losses........... (7,314) (10,585) (2,556) (6,437)
15. Non-recurring Items
Teesside
In December 2001, the Company recorded a non-recurring charge of $20.7 million
representing an asset valuation impairment charge under SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets," relating to the Company's
15.4% interest in Teesside Power Ltd. ("Teesside"). Teesside owns and operates
an 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
668MW of capacity. Enron's subsidiary, who owns and operates Teesside, is now in
administration and administrators have been appointed to run its business and
are attempting to find a buyer. As a result of Enron's subsidiary being in
administration, Teesside is in discussion with its lenders over restructuring of
the (pound)650 million debt still outstanding. It is anticipated that there will
be no further dividends arising from the investment in Teesside and
subsequently, the Company has determined the investment in Teesside to be of
negligible value.
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.
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.
Qualified Facilities Dispositions
On February 26, 1999, the Company closed the sale of all of its indirect
ownership interests in the Coso Joint Ventures ("Coso") to Caithness Energy LLC
("Caithness") for $205 million in cash. On March 3, 1999, the Company closed the
sale of 50% of its ownership interests in CE Generation to an affiliate of El
Paso Energy Corporation for an aggregate consideration of approximately $245
million in cash, $6.5 million in contingent payments and $23.5 million in equity
commitments. The sales of the qualified facilities resulted in a net
non-recurring pre-tax gain of $20.2 million and an after-tax gain of
approximately $12.4 million.
McLeod
On May 18, 1999, the Company announced the sale of approximately 6.74 million
shares of McLeodUSA ("McLeod") Class A common stock, through a secondary
offering by McLeod, at $55.625 per share. Proceeds from the sale were
approximately $375 million, with a resulting pre-tax gain to the Company of
approximately $78.2 million, and an after-tax gain of approximately $47.1
million.
Indonesia
On December 2, 1994, former subsidiaries of the Company, Himpurna California
Energy Ltd. ("HCE") and Patuha Power, Ltd. ("PPL", together with HCE, the
"Indonesian Subsidiaries") executed separate joint operation contracts for the
development of geothermal steam fields and geothermal power facilities located
in Central Java in Indonesia.
In 1997 and 1998 a series of Indonesian government decrees and other actions
created significant uncertainty as to whether the Indonesian government would
honor their contractual obligations to the Indonesian Subsidiaries. In 1997, the
Company recorded a non-recurring charge of $87 million representing an asset
valuation impairment charge under SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets," relating to the Company's assets in Indonesia. The charge
of $87 million represented the amount by which the carrying amount of such
assets exceeded the estimated fair value of the assets determined by discounting
the expected future net cash flows of the Indonesia projects.
The Company carried political risk insurance on its investment in HCE and PPL
through OPIC, an agency of the U.S. Government, as well as through private
market insurers. On November 18, 1999, the Company transferred the Indonesian
Subsidiaries to OPIC and received payment from OPIC and the private market
insurers totaling $290 million under its political risk insurance policies,
reflecting the return of its equity investment less policy deductibles. Due
primarily to the timing of the receipt of proceeds, the Company recorded a
pre-tax gain of approximately $40.3 million on the insurance proceeds and an
additional tax benefit of $17.7 million for an after-tax gain of $58.0 million.
On September 13, 2001, the Company transferred shares of Bali Energy Ltd., an
indirect wholly owned Indonesian subsidiary of the Company, to PT Tenaga Burni
Bali. The Company recorded a pre-tax gain of $10.4 million and an after-tax gain
of $6.5 million on the transfer of the shares.
16. Accounting for Derivatives
Interest Rate Risk
MidAmerican Energy has entered into a two-year, $162 million fixed-to-floating
interest rate swap agreement in conjunction with its $162 million, 7.375% series
of medium-term notes due August 1, 2002. The floating rate of the swap is based
on a three-month LIBOR rate and the effective interest rate after the swap was
4.46% in 2001. As of December 31, 2001, the fair value of this swap was $9.1
million.
Currency Exchange Rate Risk
CE Electric UK Funding entered into certain currency rate swap agreements for
the CE Electric UK Funding 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 million of 6.853%
Senior Notes, the agreements extend until December 30, 2004 and convert the U.S.
dollar interest rate to a fixed Sterling rate of 7.744%. For the $237 million of
6.995% Senior Notes, the agreements extend until 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, 2001 is approximately $44.8
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. It is the Company's intention to hold these
swap agreements to maturity.
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 $255 million of 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 million of 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, 2001 is approximately $8.4 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. It is the
Company's intention to hold these swap agreements to maturity.
A decrease of 10% in the December 31, 2001 rate of exchange of Sterling to
dollars would increase the amount received if these swap agreements were
terminated by approximately $106.4 million.
Energy Commodity Price Risk
Under the current regulatory framework, MidAmerican Energy is allowed to recover
in revenues 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 enters into natural gas futures and swap agreements to
mitigate a portion of the market risk retained by its regulated gas customers
through the purchased gas adjustment clause. These financial derivative
activities are recorded as hedge accounting transactions, with net amounts
exchanged or accrued under swap agreements and realized gains or loses on
futures contracts included in the cost of gas sold and recovered in revenues
from regulated gas customers.
MidAmerican Energy also derives revenues from nonregulated sales of natural gas.
Pricing provisions are individually negotiated with these customers and may
include fixed prices or prices based on a daily or monthly market index.
MidAmerican Energy enters into natural gas futures 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 uses natural gas derivative instruments for trading purposes
pursuant to EITF 98-10 under strict value-at-risk 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. Trading
revenues and costs are reported gross on the consolidated statements of
operations.
MidAmerican Energy is exposed to variations in the price of fuel for generation
and the price of purchased power in its Iowa jurisdiction comprising 89% of 2001
electric operating revenues. Fuel price risk is mitigated through forward
contracts. Under typical operating conditions, MidAmerican Energy has sufficient
generation to supply its 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 wholesale electric power.
MidAmerican Energy and its customers are exposed to the effect of variations in
weather conditions on sales and purchased, respectively, of electricity and
natural gas. For the 2001-2002 heating season, MidAmerican Energy entered into
several degree-day swaps to offset a portion of the financial impact of those
variations on MidAmerican Energy and its customers.
MidAmerican Energy had the following financial derivative instruments for its
natural gas and electric operations as of December 31:
MidAmerican Energy derivative instruments used for other than trading purposes-
2001 2000
---------------- ----------------
Natural Gas Futures Contracts - NYMEX:
Net Contract Volumes- Long (Short) (600,000) MMBtu 1,460,000 MMBtu
Unrealized Gain, in thousands $40 $7,554
Weighted Average Settlement Price $(6.77) $9.42
Natural Gas Swap Contracts:
Contract Volumes- Pay Fixed 7,853,052 MMBtu 13,496,239 MMBtu
Contract Volumes - Receive Fixed 900,000 MMBtu 10,610,741 MMBtu
Unrealized Gain (Loss), in thousands $(7,643) $8,055
Weighted Average Pay Fixed Price $(0.97) $0.89
Weighted Average Receive Fixed Price $0.04 $(0.37)
Natural Gas Options:
Contract Volumes - Long 2,300,000 MMBtu 1,790,280 MMBtu
Unrealized Gain (Loss), in thousands $(1,212) $953
Degree Day Swap Contracts:
Contract Volumes - Long 20,000 $/Degree day - $/Degree Day
Unrealized Gain (Loss), in thousands $(3,486) $ -
Electric Forward Contracts:
Contract Volumes - (Short) (728,800) MWh (139,200) MWh
Unrealized Gain (Loss), in thousands $6,313 $(4,731)
A $1.00 decrease in underlying natural gas prices would decrease unrealized
gains on the futures contracts held at December 31, 2001, by approximately $0.6
million and would decrease unrealized losses on the above swap contracts by
approximately $7.0 million. A $5.00 increase in underlying electricity prices
would decrease unrealized gains on the forward contracts held at December 31,
2001, by approximately $3.6 million. The weighted average maturity for all
derivative instruments used for hedging purposes is under one year.
Unrealized gains and losses on cash flow hedges of future transactions are
recorded in other comprehensive income. Only hedges that are highly effective in
offsetting the risk of variability in future cash flows are accounted for in
this manner. Future 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
future 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 recorded in
either cost of sales or operating revenues, depending upon the nature of the
physical transaction being hedged.
For 2001, a net loss of $408,000 and a net gain of $36,000, representing the
ineffectiveness of cash flow hedges, are reflected in cost of sales. During the
twelve months beginning January 1, 2002, it is anticipated that $3.4 million of
the $3.5 million 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 future transactions through December 2003.
Unrealized 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 the changes in values also recognized in income and
substantially offsetting the impact of the hedges on earnings. For 2001, a net
pre-tax gain of $18,000, representing the ineffectiveness of fair value hedges,
is included in operating revenues.
MidAmerican Energy derivative instruments used for trading purposes -
2001 2000
------------- ---------------
Natural Gas Futures Contracts - NYMEX:
Net Contract Volumes- (Short) 120,000 MMBtu (20,000) MMBtu
Unrealized (Loss), in thousands $(224) $(79)
Weighted Average Settlement Price $1.69 $(15.92)
Natural Gas Swap Contracts:
Contract Volumes - Pay Fixed 17,519,581 MMBtu 1,000,000 MMBtu
Contract Volumes - Receive Fixed 17,850,372 MMBtu 1,010,000 MMBtu
Unrealized Gain (Loss), in thousands $2,045 $(261)
Weighted Average Pay Fixed Price $(0.99) $0.92
Weighted Average Receive Fixed Price $1.09 $(1.17)
A change in underlying natural gas prices would not materially affect unrealized
losses on the above future and swap contracts.
17. Securitization of Accounts Receivable
In December 1998, CE Electric UK Funding entered into a revolving receivable
purchase agreement with Kitty Hawk Funding Corporation ("Kitty Hawk"), an
unaffiliated special purpose entity established to purchase accounts receivable.
In October 2000, the facility was transferred to Mont Blanc Capital Corp,
administered by ING Barings, which allowed CE Electric UK Funding to sell all of
its rights, title and interest in the majority of its billed electricity
accounts receivable and to borrow against its unbilled electricity accounts
receivable. In March 1999, CE Electric UK Funding received $161 million in cash
associated with the agreement. In connection with the Northern Supply/Yorkshire
swap on September 21, 2001, CE Electric UK Funding repaid the outstanding
balance of this purchase agreement and ended their arrangement with Mont Blanc
Capital Corp. CE Electric UK Funding does not have any amounts outstanding at
December 31, 2001.
In 1997, MidAmerican Energy entered into a revolving agreement, which expires in
October 2002, to sell all of its right, title and interest in the majority of
its billed accounts receivable to MidAmerican Energy Funding Corporation, a
special purpose entity established to purchase accounts receivable from
MidAmerican Energy. MidAmerican Energy Funding Corporation in turn sells
receivable interests to outside investors. In consideration of the sale,
MidAmerican Energy received cash and a subordinated note, bearing interest at
8%, from MidAmerican Energy Funding Corporation. As of December 31, 2001, the
revolving cash balance was $44 million, down $26 million from December 31, 2000,
and the amount outstanding under the subordinated note was $28.7 million. The
agreement is structured as a true sale under which the creditors or MidAmerican
Energy Funding Corporation will be entitled to be satisfied out of the assets of
MidAmerican Energy Funding Corporation prior to any value being returned to
MidAmerican Energy or its creditors. Therefore, the accounts receivable sold are
not reflected on the consolidated balance sheets. At December 31, 2001, $71.5
million of accounts receivable, net of reserves, was sold under the agreement.
18. Regulatory Matters
CE Electric UK Funding
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 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 kilowatt hour) which a
DLH is entitled to charge. The distribution price control formula permits DLHs
to receive additional revenues 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, additional cost savings therefore contribute directly to
profit.
MidAmerican Energy
In 1997, pursuant to a rate proceeding before the Iowa Utilities Board ("IUB"),
MidAmerican Energy, the Office of Consumer Advocate and other parties entered
into a pricing plan settlement agreement establishing MidAmerican Energy's Iowa
retail electric rates. That settlement agreement expired on December 31, 2000.
On March 14, 2001, the Office of the Consumer Advocate filed a petition with the
IUB to reduce Iowa retail electric rates by approximately $77 million annually.
On June 11, 2001, MidAmerican Energy responded to that petition by filing a
request with the IUB to increase MidAmerican Energy's Iowa retail electric rates
by $51 million annually. On December 21, 2001, the IUB approved a settlement
agreement that freezes the rates in effect on December 31, 2000, through
December 31, 2005, and, with modifications, reinstates the revenue sharing
provisions of the 1997 pricing plan settlement agreement. Under the 2001
settlement agreement, an amount equal to 50% of revenues associated with returns
on equity between 12% and 14%, and 83.33% of revenues associated with returns on
equity above 14%, in each year will be recorded as a regulatory liability to be
used to offset a portion of the cost of future generating plant investments. An
amount equal to the regulatory liability will be recorded as depreciation
expense. As of December 31, 2001, MidAmerican Energy has recorded a $47.1
million regulatory liability that is reflected in other long-term accrued
liabilities on the consolidated balance sheet.
Under an Illinois restructuring law enacted in 1997, a sharing mechanism is in
place for MidAmerican Energy's Illinois regulated retail electric operations
whereby earnings above a computed threshold will be shared equally between
customers and shareholders. A two-year average return on common equity greater
than a two-year average benchmark will trigger an equal sharing of earnings on
the excess. MidAmerican Energy's computed level of return on common equity is
based on a rolling two-year average of the 30-year Treasury bond rates plus a
premium of 5.50% for 1998 and 1999 and a premium of 8.5% for 200 through 2004.
The two-year average above which sharing must occur for 2001 was 14.33%. 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 September 21, 2001, MidAmerican Energy filed a petition with the South Dakota
Public Utilities Commission ("SDPUC") to increase its South Dakota natural gas
rates. On February 20, 2002, the SDPUC approved a settlement agreement allowing
increased rates of $3.1 million annually.
On October 19, 2001, MidAmerican Energy filed a petition with the Illinois
Commerce Commission to increase its Illinois natural gas rates by $3.2 million
annually. A final decision on the petition is required within eleven months of
the date of filing.
On March 15, 2002, MidAmerican Energy made a filing with the IUB requesting an
increase in rates of approximately $26.6 million for its Iowa retail natural gas
customers. As part of the filing, MidAmerican Energy requested an interim rate
increase of approximately $20.4 million annually. The IUB may adjust the
requested interim amount and delay its implementation for up to ninety days.
MidAmerican Energy expects the final rates, which may differ from the requested
amount, to be implemented in the fourth quarter.
19. Pension Commitments
United Kingdom Operations
CE Electric UK Funding 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, 2001, 2000 and 1999 assumed interest
rates of 5.75%, 6.0% and 6.0% respectively, an expected return on plan assets of
7.0%, 6.5% and 6.5%, respectively, and annual compensation increases of 2.5%,
3.0% 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.
The following table details the funded status and the amount recognized in the
Company's consolidated balance sheets for CE Electric UK Funding's plan as of
December 31, 2001 and 2000 (in thousands):
2001 2000
--------- ----------
Change in benefit obligation:
Benefit obligation at beginning of year......... $ 951,553 $ 940,600
Service cost.................................... 7,854 8,660
Interest cost................................... 51,926 50,765
Participant contributions....................... 5,236 4,927
Benefits paid................................... (49,453) (49,272)
FAS 88 curtailment.............................. 7,127 6,570
Northern Supply/Yorkshire swap net effect....... 44,216 -
Experience gain and change of assumptions....... (44,381) (10,697)
--------- ---------
Benefit obligation at end of the year........... 974,078 951,553
--------- ---------
Change in plan assets:
Fair value of plan assets at beginning of
the year................................... 1,166,111 1,283,600
Actual return on plan assets.................... (98,799) (73,741)
Net asset transfer resulting from Northern
Supply/Yorkshire Swap....................... 46,980 -
Employer contributions.......................... 582 597
Participant contributions....................... 5,236 4,927
Benefits paid................................... (49,453) (49,272)
--------- ----------
Fair value of plan assets at end of the year.... 1,070,657 1,166,111
--------- ----------
Funded status................................... 96,579 214,558
Unrecognized net loss........................... (196,648) (77,193)
--------- ----------
Prepaid benefit cost............................ $ 293,227 $ 291,751
========= ==========
Net periodic pension cost (benefit) for CE Electric UK Funding's plan for 2001,
2000 and 1999 included the following components (in thousands):
MEHC (Predecessor)
------------------
March 14, 2000 January 1, 2000
through through
2001 December 31, 2000 March 13, 2000 1999
---- ----------------- -------------- ----
Service cost - benefits earned
during the period............. $ 7,854 $ 6,933 $ 1,727 $10,200
Interest cost on projected
benefit obligation............ 51,926 40,640 10,125 48,500
Expected return on plan
assets........................ (78,979) (50,800) (12,657) (59,500)
Curtailment loss................. 7,127 5,260 1,310 38,300
------- ------- ------- -------
Net periodic pension (benefit)
cost..........................$(12,072) $ 2,033 $ 505 $37,500
======== ======= ====== =======
As a result of the distribution price reviews in 1999, CE Electric UK Funding
implemented a review of staffing requirements primarily in its distribution
business. Following discussions with the trade unions, CE Electric UK Funding
put in place a workforce reduction program. In 1999, the Company recorded a
non-recurring pre-tax loss of approximately $47.7 million that included a
pension curtailment of $38.3 million. In 2000, the pension curtailment related
to this workforce reduction program was $6.6 million. The curtailment loss in
2001 of $7.1 million is a result of the Northern Supply/Yorkshire swap.
Domestic Operations
The Company has primarily noncontributory cash balance 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 has been allowed to recover pension costs
related to its employees in rates.
MidAmerican Energy currently provides certain postretirement health care and
life insurance benefits for retired employees. Under the plans, substantially
all of MidAmerican Energy's employees may become eligible for these benefits if
they reach retirement age while working for MidAmerican Energy. However,
MidAmerican Energy retains the right to change these benefits anytime at its
discretion. MidAmerican Energy expenses postretirement benefit costs on an
accrual basis and includes provisions for such costs in rates.
In 1999, the noncontributory cash balance defined benefit pension plans, the
noncontributory, nonqualified supplemental executive retirement plan, and the
postretirement plans were amended to include participants from the Company.
Prior to the amendment, these plans included only employees and participants of
MidAmerican Energy. This inclusion increased the benefit obligation by $14.8
million for the pension and nonqualified supplemental retirement plans and $2.8
million for the postretirement plans.
MidAmerican Energy also maintains noncontributory, nonqualified supplemental
executive retirement plans for active and retired participants.
During 2000, MidAmerican Energy adopted a market-related valuation of its
pension assets for purposes of calculating net periodic pension costs. This
change conforms MidAmerican Energy's accounting practices for pension costs to
that of the Company. Net periodic pension, supplemental retirement and
postretirement benefit costs included the following components for the Company:
MEHC (Predecessor)
------------------------------------
March 14, 2000 January 1, 2000 Year
Year Ended through through Ended
December 31, 2001 December 31, 2000 March 13, 2000 December 31, 1999
----------------- ----------------- --------------- ------------------
Pension Cost
Service cost........................ $ 18,114 $ 13,014 $ 3,242 $ 9,854
Interest cost....................... 33,027 28,329 7,058 25,505
Expected return on plan assets...... (36,326) (38,532) (9,600) (37,392)
Amortization of net transition
obligation........................ (2,591) (2,074) (517) -
Amortization of prior service
cost.............................. 2,729 2,310 575 -
Amortization of prior year gain..... (3,894) (3,297) (822) -
Curtailment loss.................... - - - 4,270
--------- -------- -------- --------
Net periodic pension cost
(benefit)...................... $ 11,059 $ (250) $ (64) $ 2,237
========= ======== ======== ========
MEHC (Predecessor)
-----------------------------------
March 14, 2000 January 1, 2000 Year
Year Ended through through Ended
December 31, 2001 December 31, 2000 March 13, 2000 December 31, 1999
------------------ ----------------- -------------- -----------------
Postretirement Cost
Service cost....................... $ 4,357 $ 2,089 $ 520 $ 2,478
Interest cost...................... 10,418 6,688 1,666 6,423
Expected return on plan assets..... (4,032) (3,947) (984) (3,540)
Amortization of net transition
obligation....................... 4,110 3,290 820 -
Amortization of prior service
cost............................. 425 340 85 -
Amortization of prior year (gain)
loss............................. 332 (699) (174) -
------- -------- -------- --------
Net periodic pension cost ...... $15,610 $ 7,761 $ 1,933 $ 5,361
======= ======== ======== ========
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, 2001, 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 $50.4 million and $44.7 million at December 31, 2001
and 2000, respectively.
During 1999 certain participants in the supplemental executive retirement plan
left MidAmerican Energy reducing the future service of active employees by 28%.
As a result, a curtailment loss of $5.3 million was recognized by the Company in
1999. Additionally, termination benefits provided to the participants, totaling
$3.5 million, were expensed by MidAmerican Energy during 1999.
The projected benefit obligation and accumulated benefit obligation for the
supplemental executive retirement plans were $91.2 million and $88.2 million,
respectively, as of December 31, 2001 and $82.7 million and $77.5 million,
respectively, as of December 31, 2000.
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 MidAmerican Energy's plans to the net amounts recognized in the
consolidated balance sheet as of December 31 (dollars in thousands):
2001 2001 2000 2000
Pension Postretirement Pension Postretirement
Benefits Benefits Benefits Benefits
-------- -------- -------- --------
Reconciliation of benefit obligation:
Benefit obligation at beginning of year.................... $472,349 $131,822 $447,170 $107,744
Service cost............................................... 18,114 4,357 16,256 2,609
Interest cost.............................................. 33,027 10,418 35,387 8,354
Participant contributions.................................. - 3,059 74 2,395
Plan amendments............................................ 652 - (132) -
Actuarial (gain) loss...................................... 17,333 57,101 6,007 20,589
Benefits paid.............................................. (23,267) (11,840) (32,413) (9,869)
-------- -------- --------- --------
Benefit obligation at end of year...................... 518,208 194,917 472,349 131,822
-------- -------- --------- --------
Reconciliation of the fair value of plan assets:
Fair value of plan assets at beginning of year................ 555,208 75,090 605,059 72,622
Employer contributions..................................... 4,576 16,022 4,355 10,543
Participant contributions.................................. - 3,059 74 2,395
Actual return on plan assets............................... (20,627) (1,202) (21,867) (601)
Benefits paid.............................................. (23,267) (11,840) (32,413) (9,869)
-------- -------- --------- --------
Fair value of plan assets at end of year............... 515,890 81,129 555,208 75,090
-------- -------- --------- --------
Funded status.............................................. (2,318) (113,788) 82,859 (56,732)
Unrecognized net (gain) loss............................... (52,244) 63,328 (130,423) 1,326
Unrecognized prior service cost............................ 22,885 4,264 24,962 4,689
Unrecognized net transition obligation (asset)............. (5,974) 45,212 (8,566) 49,322
--------- --------- --------- --------
Net amount recognized in the consolidated balance
sheet.................................................. $ (37,651) $ (984) $ (31,168) $ (1,395)
========== ========= ========= ========
Amounts recognized in the consolidated balance sheet consist of:
Prepaid benefit cost....................................... $ 15,381 $ 1,493 $ 16,773 $ 1,493
Accrued benefit liability.................................. (88,210) (2,477) (77,538) (2,888)
Intangible asset........................................... 22,796 - 25,510 -
Accumulated other comprehensive income..................... 12,382 - 4,087 -
--------- ---------- ---------- --------
Net amount recognized.................................. $ (37,651) $ (984) $ (31,168) $ (1,395)
========= ========= ========== ========
Pension and Postretirement
Assumptions
MEHC
(Predecessor)
----
2001 2000 1999
---- ---- ----
Assumptions used were:
Discount rate...................................... 6.50% 7.00% 7.75%
Rate of increase in compensation levels............ 5.00% 5.00% 5.00%
Weighted average expected long-term rate
of return on assets.......................... 7.00% 9.00% 9.00%
For purposes of calculating the postretirement benefit obligation, it is assumed
health care costs for all covered individuals will increase by 11.25% in 2002
and that the rate of increase thereafter will decrease to an ultimate rate of
5.25% by the year 2006.
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 2001 would increase by $3.0 million, and the postretirement
benefit obligation at December 31, 2001, would increase by $30.6 million. If the
assumed health care trend rates were to decrease by 1.0%, the total service and
interest cost for 2001 would decrease by $2.3 million and the postretirement
benefit obligation at December 31, 2001, would decrease by $24.2 million.
20. Commitments and Contingencies
A. Financial Condition of Edison
Southern California Edison Company ("Edison"), a wholly-owned subsidiary of
Edison International, is a public utility primarily engaged in the business of
supplying electric energy to retail customers in Central and Southern
California, excluding Los Angeles. The Company is aware that there have been
public announcements that Edison's financial condition has deteriorated as a
result of reduced liquidity. Following Edison's recent financing, Edison's
senior unsecured debt obligations were upgraded to Ba3 by Moody's and BB by S&P.
Edison failed to pay approximately $119 million due under the power purchase
agreement with CE Generation affiliates for power delivered in November and
December 2000 and January, February and March 2001, although the Power Purchase
Agreements provide for billing and payment on a schedule where payments would
have normally been received in early January, February, March, April and May
2001.
On February 21, 2001, the Imperial Valley Projects (excluding the Salton Sea V
and Turbo Projects) filed a lawsuit against Edison in California's Imperial
County Superior Court seeking a court order requiring Edison to make the
required payments under the Power Purchase Agreements. The lawsuit also
requested, among other things, that the court order permit the Imperial Valley
Projects (excluding the Salton Sea V and Turbo Projects) to suspend deliveries
of power to Edison and to permit the Imperial Valley Projects to sell such power
to other purchasers in California.
On March 22, 2001, the Imperial County Superior Court granted the Imperial
Valley Projects' (excluding the Salton Sea V and Turbo Projects) Motion for
Summary Adjudication and a Declaratory Judgment ordering that: 1) under the
Power Purchase Agreements, the Imperial Valley Projects (excluding the Salton
Sea V and Turbo Projects) have the right to temporarily suspend deliveries of
capacity and energy to Edison, 2) such Imperial Valley Projects (excluding the
Salton Sea V and Turbo Projects) are entitled to resell the energy and capacity
to other purchasers and 3) the interim suspension of deliveries to Edison shall
not in any respect result in the modifications or termination of the Power
Purchase Agreements, and the Power Purchase Agreements shall in all respects
continue in full force and effect other than the temporary suspension of
deliveries to Edison.
As a result of the March 22, 2001 Declaratory Judgment, the Imperial Valley
Projects (excluding the Salton Sea V and Turbo Projects) suspended deliveries of
energy to Edison and entered into a transaction agreement with El Paso Merchant
Energy, L.P. ("EPME") in which the Imperial Valley Projects' (excluding the
Salton Sea V and Turbo Projects) available power was sold to EPME based on
percentages of the Dow Jones SP-15 Index. On June 18, 2001 the Superior Court
prospectively vacated its order authorizing the Imperial Valley Projects'
(excluding the Salton Sea V and Turbo Projects) right to resell power pursuant
to the Declaratory Judgment.
On June 20, 2001, the Imperial Valley Projects (excluding Salton Sea Unit V and
CE Turbo) entered into Agreements Addressing Renewable Energy Pricing and
Payment Issues with Edison ("Settlement Agreements") and, as a result, resumed
power sales to Edison on June 22, 2001. The Settlement Agreements required that
Edison make an initial payment to repay the past due balances under the Power
Purchase Agreements (the "stipulated amounts"). The initial payment of
approximately $11.6 million, which represented 10% of the stipulated amounts,
was received June 22, 2001. On October 2, 2001, the California Public Utilities
Commission announced an agreement with Edison that allowed Edison to recover in
retail electric rates its past due obligations. On November 30, 2001, the
Settlement Agreements were amended to reflect when Edison would be required to
make the final payment on past due amounts. On March 1, 2002, Edison obtained
$1.8 billion in secured financing that, when combined with cash on hand, enabled
Edison to pay off its past due debts. The final payment of approximately $104.6
million, representing the remaining stipulated amounts, was received March 1,
2002. In addition to these payments, Edison was required to make monthly
interest payments calculated at a rate of 7% per annum on the outstanding
stipulated amounts. The amended Settlement Agreements provide a revised energy
pricing structure, whereby Edison elects to pay the Imperial Valley Projects a
fixed energy price in lieu of the Commission-approved Avoided Cost of Energy
Methodology under the Power Purchase Agreements. The fixed energy price is 3.25
cents/kWh from December 2001 through April 30, 2002 and 5.37 cents/kWh
commencing May 1, 2002 for a five year period. Following the five year period,
the energy payments revert back to the Commission-approved Avoided Cost of
Energy Methodology under the Power Purchase Agreements. Estimates of Edison's
future Avoided Cost of Energy vary substantially from year to year.
As a result of Edison's failure to make the payments due under the Power
Purchase Agreements and the downgrades of Edison's credit rating, Moody's
downgraded the ratings for the Salton Sea Funding Corporation (the "Funding
Corporation") Securities to Caa2 (negative outlook) and S&P downgraded the
ratings for the Funding Corporation Securities to BBB- and placed the Securities
on "credit watch negative." Moody's downgraded the ratings for the CE Generation
Securities to B1 from Baa3 (review for possible downgrade). Following the
execution of the Settlement Agreements, Moody's placed the Salton Sea Funding
and CE Generation securities on "credit watch positive." The Funding Corporation
Securities are currently rated Ba3 by Moody's and BBB- by S&P. CE Generation
Securities are currently Ba2 by Moody's and BBB- by S&P.
B. Casecnan
The Casecnan Project was initially being constructed pursuant to a fixed-price,
date-certain, turnkey construction contract (the "Hanbo Contract") on a joint
and several basis by Hanbo Corporation ("Hanbo") and Hanbo Engineering and
Construction Co., Ltd. ("HECC"), both of which are South Korean corporations. As
of May 7, 1997, the Company terminated the Hanbo Contract due to defaults by
Hanbo and HECC including the insolvency of both companies. On the same date, the
Company entered into a new fixed-price, date certain, turnkey engineering,
procurement and construction contract to complete the construction of the
Casecnan Project (the "Replacement Contract"). The work under the Replacement
Contract is being conducted by a consortium consisting of Cooperativa Muratori
Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa., working together
with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power
Engineering Ltd. (collectively, the "Contractor").
On November 20, 1999, the Replacement Contract was amended to extend the
Guaranteed Substantial Completion Date for the Casecnan Project to March 31,
2001. This amendment was approved by the lender's independent engineer under the
Casecnan Indenture.
On February 12, 2001, the Contractor filed a Request for Arbitration with the
International Chamber of Commerce seeking an extension of the Guaranteed
Substantial Completion Date by up to 153 days through August 31, 2001 resulting
from various alleged force majeure events. In a March 20, 2001 Supplement to
Request for Arbitration, the Contractor also seeks 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
approximately $62 million in damages for the alleged force majeure event (and
geologic conditions) related to the collapse of the surge shaft. The Contractor
alleged that the circumstances surrounding the placing of the Casecnan Project
into commercial operation on December 11, 2001 amounted to a termination of the
Replacement Contract and filed a claim for unspecified quantum meruit damages.
CE Casecnan believes such allegations and claims are without merit and is
vigorously defending the Contractor's claims. The arbitration is being conducted
applying New York law and pursuant to the rules of the International Chamber of
Commerce.
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. Hearings
on the force majeure claims were held in London from July 2 to 14, 2001, and
hearings on the Contractor's April 20, 2001 supplement were held in London from
September 24 to October 3, 2001. Further hearings were held from January 2 to
February 1, 2002 and additional hearings were held from March 14 to 19, 2002.
As of December 31, 2001 the Company has received approximately $6.0 million of
liquidated damages from demands made or the demand guarantees posted by
Commerzbank on behalf of the Contractor. Although the outcome of the arbitration
is difficult to assess, CE Casecnan believes it will prevail and receive
substantial additional liquidated damages in the arbitration.
Under the Project Agreement, if NIA is able to accept delivery of water into the
Pantabangan Reservoir and NPC has completed the Project's related transmission
line, the Company is liable to pay NIA $5,500 per day for each day of delay in
completion of the Casecnan Project beyond July 27, 2000, increasing to $13,500
per day for each day of delay in completion beyond November 27, 2000. NIA
completed the installation of the transmission line on August 13, 2001.
Accordingly, the Company accrued $1.6 million liquidated damages payable to NIA
for 120 days of delay.
The Company's ability to make payments on any of its existing and future
obligations is dependent on NIA's and the Republic of the Philippines'
performance of their obligations under the Project Agreement and the Performance
Undertaking, respectively. Except to the extent expressly provided for in the
Shareholder Support Letters, no shareholders, partners or affiliates of the
Company, including MidAmerican, and no directors, officers or employees of the
Company will guarantee or be in any way liable for payment of the Company's
obligations. As a result, payment of the Company's obligations depends upon the
availability of sufficient revenues from the Company's business after the
payment of operating expenses.
C. Decommissioning Costs
Expected decommissioning costs for Quad Cities Station and Cooper have been
developed based on site-specific decommissioning studies that include
decontamination, dismantling, site restoration, dry fuel storage cost and
assumed shutdown dates. In Illinois, Cooper nuclear decommissioning costs are
recovered through a rate rider on customer billings that permits annual
adjustments. Quad Cities Station and Cooper decommissioning costs are reflected
as base rates in Iowa tariffs.
MidAmerican Energy's share of expected decommissioning costs for Quad Cities
Station, in 2001 dollars, is $278 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, 2001, was $158.3 million
and is included in other long-term accrued liabilities, and a like amount is
reflected in Investments 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, $8.3 million, and $10.4 million for
2001, 2000 and 1999, respectively. The provision charged to depreciation expense
is equal to the funding that is being collected in rates. The decommissioning
funding component of MidAmerican Energy's Illinois and Iowa tariffs assumes
decommissioning costs, related to the Quad Cities Station, will escalate at an
annual rate of 4.5% and the assumed annual return on funds in the trust is 6.9%.
Realized income (loss), net of investment fees, on the assets in the trust fund
was $(0.6) million, $1.9 million and $1.9 million for 2001, 2000 and 1999,
respectively.
MidAmerican Energy's contribution toward payment of Cooper's projected
decommissioning costs have been based on the NPPD decommissioning funding plan
for Cooper. Total expected decommissioning costs for Cooper, in 2001 dollars,
are $577 million. For purposes of developing a decommissioning funding plan for
Cooper, the NPPD assumes that decommissioning costs will escalate at an annual
rate of 4.0%. Although Cooper's operating license expires in 2014, the funding
plan assumes decommissioning will start in 2004, the anticipated plant shutdown
date.
As of December 31, 2001, total funds set aside in the internal and external
accounts for Cooper decommissioning that are maintained by the NPPD were $291.3
million. In addition, the funding plan for Cooper also assumes various funds and
reserves currently held to satisfy the NPPD bond resolution requirements will be
available for plant decommissioning, which is to begin with the assumed plant
shutdown in September 2004. The funding schedule assumes a long-term return on
funds in the trust of 6.75% annually. Certain funds will be required to be
invested on a short-term basis when decommissioning begins and are assumed to
earn at a rate of 4.0% annually. Earnings from the internal account and external
trust fund, which are recognized by the NPPD as the owner of the plant, are tax
exempt and serve to reduce future funding requirements.
Beginning in December 2000, MidAmerican Energy ceased contributing to the
accounts maintained by NPPD and began contributing funds to a separate
MidAmerican Energy bank account based on the NPPD decommissioning funding plan
for Cooper. A liability equal to the amount of funds contributed, plus the
earnings on those funds, is reflected in other long-term accrued liabilities on
the consolidated balance sheets. MidAmerican Energy records expense equal to the
funds contributed to the separate account plus investment fees paid to the NPPD
for funds in the accounts they maintain. MidAmerican Energy's expense for Cooper
decommissioning was $11.6 million, $11.5 million and $11.3 million for the years
2001, 2000 and 1999, respectively, and is included in other operating expenses.
MidAmerican Energy is currently involved in litigation with NPPD in part related
to the determination of MidAmerican Energy's obligation, if any, for costs of
decommissioning Cooper. Refer to Note (20)(E) for a discussion of the
proceedings.
D. Nuclear Insurance
MidAmerican Energy maintains financial protection against catastrophic loss
associated with its interest in Quad Cities Station and Cooper through a
combination of insurance purchased by NPPD (the owner and operator of Cooper)
and Exelon Generation Company, LLC (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.
NPPD and Exelon Generation each purchase nuclear liability insurance for Cooper
and Quad Cities Station, respectively, in the maximum available amount of $200
million. In accordance with the Price-Anderson Amendments Act of 1988, excess
liability protection above the amount is provided by a mandatory industry-wide
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 Cooper and Quad Cities
Station combined is $88.1 million per incident, payable in installments not to
exceed $10 million annually.
The property coverage provides for property damage, stabilization and
decontamination of the facility, disposal of the decontaminated material and
premature decommissioning. For Quad Cities Station, Exelon Generation purchases
primary and excess property insurance protection for the combined interests in
Quad Cities Station, with coverage limits totaling $2.1 billion. For Cooper,
MidAmerican Energy and NPPD separately purchase primary and excess property
insurance protection for their respective obligations, with coverage limits of
$1.375 billion each. This structure provides that both MidAmerican Energy and
NPPD are covered for their respective 50% obligation in the event of a loss
totaling up to $2.75 billion. MidAmerican Energy also directly purchases 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 Cooper or
Quad Cities Station. The coverages purchased directly by MidAmerican Energy, and
the property coverages purchased 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 Cooper
and Quad Cities Station combined, total $20.5 million.
The master nuclear worker liability coverage, which is purchased by NPPD and
Exelon Generation for Cooper and Quad Cities Station, respectively, 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.
E. Cooper Litigation
On July 23, 1997, the Nebraska Public Power District ("NPPD") filed a complaint,
in the United States District Court for the District of Nebraska, naming
MidAmerican Energy as the defendant and seeking declaratory judgment as to three
issues under the parties' long-term power purchase agreement for Cooper capacity
and energy. More specifically, the NPPD sought a declaratory judgment in the
following respects:
(1) that MidAmerican Energy is obligated to pay 50% of all costs and
expenses associated with decommissioning Cooper, and that in the event
NPPD continues to operate Cooper after expiration of the power purchase
agreement (September 2004), MidAmerican Energy is not entitled to
reimbursement of any decommissioning funds it has paid to date or will
pay in the future;
(2) that the current method of allocating transition costs as a part of the
decommissioning cost is proper under the power purchase agreement; and
(3) that the current method of investing decommissioning funds is proper
under the power purchase agreement.
MidAmerican Energy filed its answer and counterclaims. The counterclaims filed
by MidAmerican Energy are generally as follows:
(1) that MidAmerican Energy has no duty under the power purchase agreement
to reimburse or pay 50% of the decommissioning costs unless conditions
to reimbursement occur;
(2) that the term "monthly power costs" as defined in the power purchase
agreement does not include costs and expenses associated with
decommissioning the plant;
(3) that NPPD violated MidAmerican Energy's directions for application of
payments;
(4) that transition costs are not included in any decommissioning costs and
are not any kind of costs that MidAmerican Energy is obligated to pay;
(5) that NPPD has the duty to repay all amounts that MidAmerican Energy has
prefunded for decommissioning in the event the Nebraska Public Power
District operates the plant after the term of the power purchase
agreement;
(6) that NPPD is equitably estopped from continuing to operate the plant
after the term of the power purchase agreement so long as NPPD does not
repay all amounts MidAmerican Energy has prefunded for estimated
decommissioning costs together with other amounts in certain funds and
accounts and for so long as NPPD fails to provide MidAmerican Energy
with certain requested accountings and information;
(7) that certain funds, accounts, and reserves are excessive and are
required to be paid to MidAmerican Energy or credited to MidAmerican
Energy's pre-2004 monthly power costs;
(8) that MidAmerican Energy has no duty to pay for nuclear fuel, operations
and maintenance projects or capital improvements that have useful lives
after the term of the power purchase agreement;
(9) that NPPD has mismanaged the plant in numerous described transactions
resulting in damage to MidAmerican Energy;
(10) that NPPD has breached its contractual and other duties to MidAmerican
Energy by not joining certain litigation and by failing to credit or
agree to credit MidAmerican Energy with any recovery for low-level
radioactive waste; and
(11) that NPPD has breached its duty to MidAmerican Energy in making invest-
ments of decommissioning funds;
On October 6, 1999, the court rendered summary judgment for NPPD on the
above-mentioned issue concerning liability for decommissioning (issue one in the
first paragraph above) and the related contingent counterclaims filed by
MidAmerican Energy (issues one and two in the second paragraph above). The court
referred all remaining issues in the case to mediation, and cancelled the
November 1999 trial date.
MidAmerican Energy appealed the court's summary judgment ruling. On December 12,
2000, the United States Court of Appeals for the Eighth Circuit reversed the
ruling of the district court and granted summary judgment in favor of
MidAmerican Energy on issues one and five in the second paragraph above.
Additionally, it remanded the case for trial on all other claims and
counterclaims.
Since the remand to the District Court from the Eighth Circuit Court of Appeals,
NPPD has been granted permission, over MidAmerican Energy's objections, to file
a second amended complaint. The second amended complaint asserts that even
though the Eighth Circuit Court of Appeals held that MidAmerican Energy has no
liability under the power purchase agreement to reimburse or pay NPPD a 50%
share of decommissioning costs unless certain conditions occur, MidAmerican
Energy has unconditional liability for a 50% share based on agreements other
than the power purchase agreement as originally written. NPPD's post-remand
contentions -- all strongly disputed by MEC -- are that MidAmerican Energy has
unconditional liability for a 50% share of decommissioning based on any of the
following alternative theories: (i) the parties without written amendment either
modified the power purchase agreement or made a separate agreement that imposes
unconditional liability on MidAmerican Energy for decommissioning costs; (ii)
absent unconditional liability for a 50% share of decommissioning costs,
MidAmerican Energy would be unjustly enriched; (iii) MidAmerican Energy has
unconditional liability for a 50% share of decommissioning costs based on
promissory estoppel; or (iv) NPPD is entitled to have the power purchase
agreement reformed to provide that MidAmerican Energy has unconditional
liability for a 50% share of decommissioning costs. In response to NPPD's second
amended complaint, MidAmerican Energy filed its first amended answer and third
amended counterclaims containing denials, several affirmative defenses, and the
counterclaims summarized above. In the course of discovery, NPPD has contended
that MidAmerican Energy has some responsibility for some costs of storage of
spent fuel resulting from the operation of the plant during the term of the
power purchase agreement. MidAmerican Energy disputes this. MidAmerican Energy
recently filed a mandamus petition with Eighth Circuit Court of Appeals seeking
an order of that court directing the District Court not to permit NPPD to pursue
the above alternative theories at trial, since the above alternative theories
appear to be contrary to the December 12, 2000 Eighth Circuit Court of Appeals
decision. If such relief is not granted, MidAmerican Energy will strongly
dispute at trial these contentions and theories put forth by NPPD. Trial in
these matters has been recently rescheduled to being on September 9, 2002.
F. Coal and Natural Gas Contract Commitments
MidAmerican Energy has supply and related transportation contracts for its
fossil fueled generating stations. The contracts, with expiration dates ranging
from 2002 to 2007, require minimum payments of $80.3 million, $70.6 million,
$36.2 million, $34.0 million and $2.6 million for the years 2002 through 2006,
respectively, and $2.6 million for the total of the years thereafter.
MidAmerican Energy expects to supplement these coal contracts with additional
contracts and spot market purchases to fulfill its future fossil fuel needs.
MidAmerican Energy has contracts with various companies to purchase electric
capacity. The contracts, with expiration dates ranging from 2002 to 2011,
require minimum payments of $27.0 million, $30.5 million, $15.3 million, $2.9
million and $2.2 million for the years 2002 through 2006, respectively, and
$11.0 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 $56.6
million, $41.3 million, $13.4 million, $13.2 million and $13.0 million for the
years 2002 through 2006, respectively, and $26.7 million for the total of the
years thereafter.
21. Subsequent Events
Debt issuance
On February 8, 2002, MidAmerican Energy issued $400 million of 6.75% medium-term
notes due in 2031. The proceeds will be used to refinance existing debt and
preferred securities and for other corporate purposes. On March 11, 2002,
MidAmerican Energy redeemed its MidAmerican-obligated mandatorily redeemable
preferred securities of subsidiary trust at 100% of the principal amount plus
accrued interest.
Prudential California Acquisition
In February 2002, HomeServices completed its purchase of a majority interest in
Prudential California Realty. The cash purchase price of Prudential California
Realty was approximately $74 million, with an option to purchase the remaining
interests. Additionally, HomeServices is obligated to pay a maximum earnout of
$18.5 million calculated based on certain 2002 financial performance measures.
The purchase price was financed using the Company's corporate revolver for $40
million which was contributed to HomeServices as equity and the remaining funds
were borrowed from available credit under the HomeServices's $65 million
revolving credit facility. It is anticipated that the borrowings in connection
with this acquisition will be repaid from HomeServices generated funds. The
acquisition will be accounted for by the purchase method of accounting, and the
Company is in the process of completing the allocation of the purchase price to
the assets acquired and liabilities assumed.
Kern River Acquisition
On March 7, 2002, the Company reached a definitive agreement with The Williams
Companies, Inc. ("Williams") to acquire Williams' Kern River Gas Transmission
Company, a 926-mile interstate pipeline transporting Rocky Mountain and Canadian
natural gas to markets in California, Nevada and Utah. The purchase price was
$956 million, including $506 million of assumed debt. As part of the agreement,
the Company will continue the planned expansion of the Kern River system, a
project that will more than double the pipeline's capacity with expected capital
expenditures of approximately $1.2 billion. The purchase was completed on March
27, 2002.
The Kern River pipeline is an important route for the transmission of natural
gas from the vast reserves in the Rocky Mountain states to the rapidly growing
markets in Utah, Nevada and California. Constructed in 1992, Kern River extends
926 miles from Opal, Wyoming, to the San Joaquin Valley near Bakersfield,
California, and has a design capacity of 835 million cubic feet per day.
In August 2001, Williams filed with FERC to more than double the capacity on the
Kern River system by adding approximately 900 million cubic feet per day of
additional capacity from Wyoming to California and markets in between. Upon
completion of the expansion project in May 2003, Kern River will be capable of
transporting 1.7 billion cubic feet of natural gas per day. When converted to
electricity, that is enough energy to power approximately 10 million homes.
In connection with the acquisition of Kern River, the Company issued $323
million of Trust Preferred Securities and $127 million of convertible preferred
stock to Berkshire Hathaway.
In addition to the acquisition of Kern River, the Company also announced its
investment of $275 million in Williams, in exchange for shares of 9-7/8 percent
cumulative convertible preferred stock of Williams. In connection with this
investment, the Company issued $275 million of convertible preferred stock to
Berkshire Hathaway.
22. Segment Information:
The Company has identified five reportable operating segments principally based
on management structure: CalEnergy Generation-Domestic, CalEnergy
Generation-Foreign (primarily the Philippines), MidAmerican Energy (domestic
utility operations), CE Electric UK Funding (foreign utility operations) and
HomeServices (real estate operations). Information related to the Company's
reportable operating segments are shown below (in thousands).
MEHC (Predecessor)
---------------------------------
Year Ended March 14, 2000 January 1, 2000 Year Ended
December 31, through through December 31,
2001 December 31, 2000 March 13, 2000 1999
------------ ----------------- -------------- ------------
Revenue: (1)
CalEnergy Generation-Domestic........ $ 75,541 $ 40,031 $ 4,520 $ 105,869
CalEnergy Generation-Foreign......... 207,386 156,504 42,726 210,571
MidAmerican Energy................... 2,795,838 2,132,273 491,636 1,525,157
CE Electric UK Funding............... 1,458,979 1,517,539 499,017 2,098,976
HomeServices......................... 644,741 405,805 66,880 357,728
------------ ----------- ------------ -----------
Segment revenue...................... 5,182,485 4,252,152 1,104,779 4,298,301
Corporate/other...................... (25,174) (9,403) 1,830 29,420
------------ ----------- ------------ -----------
$ 5,157,311 $ 4,242,749 $ 1,106,609 $ 4,327,721
============ =========== ============ ===========
Depreciation and amortization:
CalEnergy Generation-Domestic........ $ 5,439 $ 2,183 $ 250 $ 14,478
CalEnergy Generation-Foreign......... 66,315 52,685 13,514 66,063
MidAmerican Energy................... 286,590 184,955 45,184 182,638
CE Electric UK Funding............... 125,564 108,637 31,964 137,963
HomeServices......................... 17,201 8,695 2,891 7,772
------------- ----------- ------------ ------------
Segment depreciation................. 501,109 357,155 93,803 408,914
Corporate/other...................... 37,593 26,196 3,475 18,776
------------ ----------- ------------ ------------
$ 538,702 $ 383,351 $ 97,278 $ 427,690
============ =========== ============ ============
Interest expense, net:
CalEnergy Generation-Domestic........ $ 10,835 $ 1,829 $ 793 $ 17,851
CalEnergy Generation-Foreign......... 30,875 34,458 9,713 58,322
MidAmerican Energy................... 113,980 94,425 24,579 100,046
CE Electric UK Funding............... 112,308 74,335 21,189 96,759
HomeServices......................... 3,884 2,328 785 3,228
------------ ------------ ------------ -----------
Segment interest expense, net........ 271,882 207,375 57,059 276,206
Corporate/other...................... 140,912 104,029 28,755 149,967
----------- ----------- ----------- -----------
$ 412,794 $ 311,404 $ 85,814 $ 426,173
=========== =========== =========== ===========
Income before provisions for income taxes: (1)
CalEnergy Generation-Domestic........ $ 44,335 $ 30,697 $ 2,877 $ 49,095
CalEnergy Generation-Foreign......... 89,542 49,787 15,976 68,105
MidAmerican Energy................... 210,733 181,797 63,315 151,555
CE Electric UK Funding............... 159,850 83,108 58,673 152,126
HomeServices......................... 42,945 31,015 (4,929) 16,613
---------- ----------- ----------- -----------
Segment income....................... 547,405 376,404 135,912 437,494
Corporate/other...................... (223,014) (157,200) (37,137) (164,720)
---------- ----------- ----------- -----------
$ 324,391 $ 219,204 $ 98,775 $ 272,774
========== =========== =========== ===========
MEHC (Predecessor)
----------------------------------
Year Ended March 14, 2000 January 1, 2000 Year Ended
December 31, through through December 31,
2001 December 31, 2000 March 13, 2000 1999
------------ ----------------- --------------- -----------
Provisions for income taxes: (1)
CalEnergy Generation-Domestic........ $ (689) $ (1,929) $ (8) $ 6,347
CalEnergy Generation-Foreign......... 27,962 29,194 373 33,912
MidAmerican Energy................... 95,490 77,450 27,943 64,936
CE Electric UK Funding............... 47,866 30,065 18,761 59,183
HomeServices......................... 15,953 12,300 (1,992) 7,193
---------- ---------- ----------- ----------
Segment income....................... 186,582 147,080 45,077 171,571
Corporate/other...................... (100,314) (93,803) (14,069) (80,835)
---------- ---------- ----------- ----------
$ 86,268 $ 53,277 $ 31,008 $ 90,736
========== ========== =========== ==========
Capital expenditures:
CalEnergy Generation-Domestic........ $ 52,940 $ 151,289 $ 53,011 $ 145,255
CalEnergy Generation-Foreign......... 83,954 87,781 22,263 95,552
MidAmerican Energy................... 252,615 194,045 23,977 194,216
CE Electric UK Funding............... 176,464 95,806 22,210 231,634
HomeServices......................... 9,878 6,996 2,052 9,143
---------- ---------- ---------- ----------
Segment capital expenditures......... 575,851 535,917 123,513 675,800
Corporate/other...................... 901 2,812 28 120
---------- ---------- ---------- ----------
$ 576,752 $ 538,729 $ 123,541 $ 675,920
========== ========== ========== ==========
(1) Before non-recurring items.
MEHC (Predecessor)
As of December 31, As of December 31,
2001 2000 1999
----------- ---------- ----------
Total assets:
CalEnergy Generation-Domestic... $ 725,716 $ 663,125 $ 538,598
CalEnergy Generation-Foreign.... 925,825 965,913 1,115,661
MidAmerican Energy.............. 5,023,584 5,324,921 5,072,788
CE Electric UK Funding.......... 3,973,457 2,414,394 2,953,288
HomeServices.................... 226,588 169,470 166,658
----------- ----------- ----------
Segment assets.................. 10,875,170 9,537,823 $9,846,993
==========
Corporate/other................. 1,740,163 2,073,116
----------- -----------
$12,615,333 $11,610,939
=========== ===========
Long-lived assets:
CalEnergy Generation-Domestic... $ 441,603 $ 434,523 $ 222,357
CalEnergy Generation-Foreign.... 802,092 790,077 809,506
MidAmerican..................... 4,050,285 4,079,250 3,995,763
CE Electric UK Funding.......... 3,302,560 1,884,951 2,438,877
HomeServices.................... 165,689 125,894 129,649
----------- ----------- ----------
Segment long-lived assets....... 8,762,229 7,314,695 $7,596,152
===========
Corporate....................... 1,404,307 1,707,102
----------- -----------
$10,166,536 $ 9,021,797
=========== ===========
The remaining differences from the segment amounts to the consolidated amounts
described as "Corporate" relate principally to the corporate functions including
administrative costs, corporate cash and related interest income, intersegment
eliminations, unallocated goodwill and fair value adjustments relating to
acquisitions.
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, 2001 and 2000 for the Company, and the related
consolidated statements of operations, stockholders' equity, and cash flows for
the year ended December 31, 2001 for the Company, for the period January 1, 2000
to March 13, 2000 for MEHC (Predecessor), for the period March 14, 2000 to
December 31, 2000 for the Company, and for the year ended December 31, 1999 for
MEHC (Predecessor). Our audits also included the financial statement schedules
listed in the Index at Item 14. 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, 2001 and 2000, 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 2001 the
Company changed its accounting policy for major maintenance, overhaul and well
workover costs.
DELOITTE & TOUCHE LLP
Des Moines, Iowa
January 17, 2002
(March 27, 2002 as to Notes 20.A. and 21)
MidAmerican Energy Holdings Company Schedule I
Parent Company Only
Condensed Balance Sheets
As of December 31, 2001 and 2000
(In thousands)
2001 2000
---------- --------
ASSETS
Current Assets:
Cash and cash equivalents............ $ 2,524 $ 8,223
---------- ----------
Total current assets............... 2,524 8,223
Investments in and advances to
subsidiaries and joint ventures....... 3,432,528 3,125,487
Equipment, net.......................... 17,605 17,228
Excess of cost over fair value of
net assets acquired, net.............. 1,211,814 1,216,550
Deferred charges and other assets....... 129,501 127,966
---------- ----------
Total Assets............................ $4,793,972 $4,495,454
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and other
accrued liabilities................ $ 68,445 $ 54,073
Short term debt...................... 153,500 85,000
---------- ----------
Total current liabilities.......... 221,945 139,073
Non-current liabilities................. 6,480 6,435
Notes payable - affiliate............... 197,153 122,177
Parent company debt..................... 1,834,498 1,829,971
---------- -----------
Total liabilities.................... 2,260,076 2,097,656
---------- -----------
Deferred income......................... 37,578 34,874
Company-obligated mandatorily
redeemable preferred securities
of subsidiary trusts.................. 788,151 786,523
Stockholders' Equity:
Zero coupon convertible preferred stock
authorized 50,000 shares, no par value
34,563 shares issued and outstanding
at December 31, 2001 and 2000......... - -
Common stock -authorized 60,000 shares,
no par value; 9,281 shares issued and
outstanding at December 31, 2001 and
2000.................................. - -
Additional paid in capital.............. 1,553,073 1,553,073
Retained earnings....................... 223,926 81,257
Accumulated other comprehensive loss,
net................................... (68,832) (57,929)
---------- ----------
Total stockholders' equity.............. 1,708,167 1,576,401
---------- ----------
Total Liabilities and Stockholders'
Equity................................ $4,793,972 $4,495,454
========== ==========
The notes to the consolidated MEHC financial statements are an integral part of
this financial statement schedule.
MidAmerican Energy Holdings Company Schedule I
Parent Company Only (continued)
Condensed Statements of Operations
For the three years ended December 31, 2001
(In thousands)
2001 2000 1999
--------- --------- ---------
Revenue:
Equity in undistributed earnings of subsidiary companies
and joint ventures......................................... $608,896 $390,194 $166,428
Cash dividends and distributions from subsidiary
companies and joint ventures............................... 87,625 96,342 345,430
Interest and other income..................................... 2,248 13,818 34,002
----------- ---------- ---------
Total revenues............................................. 698,769 500,354 545,860
---------- --------- ---------
Expenses:
General and administration.................................... 41,078 45,089 39,174
Depreciation and amortization................................ 31,537 25,716 1,088
Interest, net of capitalized interest......................... 148,680 141,891 163,589
--------- --------- ----------
Total expenses............................................. 221,295 212,696 203,851
---------- --------- ----------
Income before provision for income taxes...................... 477,474 287,658 342,009
Provision for income taxes.................................... 250,064 84,285 93,475
--------- --------- ---------
Income before minority interest............................... 227,410 203,373 248,534
Minority interest............................................. 80,137 70,804 31,863
--------- --------- ---------
Income before extraordinary items and cumulative effect of
change in accounting principle............................. 147,273 132,569 216,671
Extraordinary items, net of tax............................... - - (49,441)
Cumulative effect of change in accounting principle, net of tax (4,604) - -
-------- -------- --------
Net income available to common stockholders................... $142,669 $132,569 $167,230
======== ======== ========
The notes to the consolidated MEHC financial statements are an integral part of
this financial statement schedule.
MidAmerican Energy Holdings Company Schedule I
Parent Company Only (continued)
Condensed Statements of Cash Flows
For the three years ended December 31, 2001
(In thousands)
2001 2000 1999
----------- ----------- -----------
Cash flows from operating activities.......................... $ (272,906) $ (299,862) $ (261,276)
----------- ----------- -----------
Cash flows from investing activities:
Decrease (increase) in advances to and investments in
subsidiaries and joint ventures............................ 204,118 143,052 (53,215)
Acquisition of MEHC (Predecessor)............................. - (2,048,266) -
Other......................................................... (5,297) 28,458 (4,390)
----------- ----------- -----------
Cash flows from investing activities.......................... 198,821 (1,876,756) (57,605)
----------- ----------- -----------
Cash flows from financing activities:
Proceeds from issuance of common and preferred stock ......... - 1,428,024 -
Proceeds from issuance of trust preferred securities.......... - 454,772 -
Repayments of parent company debt............................. (32) - (853,420)
Net proceeds from revolver.................................... 68,500 85,000 -
Purchase of treasury stock.................................... - - (104,847)
Other......................................................... (82) (23,893) (4,208)
----------- ---------- -----------
Cash flows from financing activities.......................... 68,386 1,943,903 (962,475)
----------- ---------- ------------
Net increase (decrease) in cash and cash equivalents.......... (5,699) (232,715) (1,281,356)
Cash and cash equivalents at beginning of period.............. 8,223 240,938 1,522,294
----------- ---------- -----------
Cash and cash equivalents at end of period.................... $ 2,524 $ 8,223 $ 240,938
=========== ========== ===========
Supplemental disclosures:
Interest paid (net of amount capitalized)..................... $ 148,999 $ 144,147 $ 180,274
=========== ========== ===========
Income taxes paid............................................. $ 133,139 $ 94,405 $ 130,875
=========== ========== ===========
The notes to the consolidated MEHC financial statements are an integral part of
this financial statement schedule.
SCHEDULE II
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2001
(In Thousands)
Column A Column B Column C Column D Column E
-------- -------- -------- -------- --------
Balance at Additions Balance at
Beginning Charged Other End
Description of Year to Income Accounts Deductions of Year
- ----------- ---------- --------- -------- ---------- -------
Reserves Deducted From Assets
To Which They Apply:
Reserve for uncollectible
accounts receivable:
Year ended 2001......... $ 32,685 $ 17,061 $ - $(42,427) $ 7,319
======== ======== ======= ======== =======
Year ended 2000......... $ 18,666 $ 40,024 $ - $(26,005) $32,685
======== ======== ======= ======== =======
Year ended 1999 ........ $ 11,994 $ 14,483 $ - $ (7,811) $18,666
======== ======== ======= ======== =======
Reserves Not Deducted From
Assets (1):
Year ended 2001......... $25,063 $ 5,046 $ - $(16,478) $13,631
======= ======== ======= ======== =======
Year ended 2000......... $17,696 $10,832 $ - $ (3,465) $25,063
======= ======= ======= ======== =======
Year ended 1999 ........ $ 5,660 $15,112 $ 2,148 $ (5,224) $17,696
======= ======= ==-==== ======== =======
(1) Reserves not deducted from assets include estimated liabilities for losses
retained by MHC for workers compensation, public liability and property
damage claims.
The notes to the consolidated MEHC financial statements are an integral part of
this financial statement schedule.
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 Omaha, State
of Nebraska, on this 30th day of March 2002.
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 30, 2002
David L. Sokol
Chairman of the Board,
Chief Executive Officer, and
Director
/s/ Gregory E. Abel*
- --------------------- March 30, 2002
Gregory E. Abel
President, Chief Operating Officer and Director
/s/ Patrick J. Goodman*
- ------------------------ March 30, 2002
Patrick J. Goodman
Senior Vice President and
Chief Financial Officer
/s/ Edgar D. Aronson*
- --------------------- March 30, 2002
Edgar D. Aronson
Director
/s/ Stanley J. Bright *
- ------------------------ March 30, 2002
Stanley J. Bright
Director
/s/ Walter Scott, Jr.*
- ---------------------- March 30, 2002
Walter Scott, Jr.
Director
/s/ Marc D. Hamburg *
- --------------------- March 30, 2002
Marc D. Hamburg
Director
/s/ Warren Buffett*
- -------------------- March 30, 2002
Warren Buffett
Director
/s/ John Boyer*
- ---------------- March 30, 2002
John Boyer
Director
/s/ W. David Scott*
- ------------------- March 30, 2002
W. David Scott
Director
/s/ Richard R. Jaros*
- ------------------- March 30, 2002
Richard R. Jaros
Director
*By:/s/ Douglas L. Anderson
- ---------------------------- March 30, 2002
Douglas L. Anderson
Attorney-in-Fact
EXHIBIT INDEX
3.1 Restated Articles of Incorporation of the Company in effect until March
6, 2002.
3.2 Bylaws of the Company.
3.3 Amended and Restated Articles of Incorporation of the Company effective
March 6, 2002.
4.2 Indenture for the 6 1/4% Convertible Junior Subordinated Debentures,
dated as of April 1, 1996, among CalEnergy Company, Inc., as Issuer,
and the Bank of New York, as Trustee (incorporated by reference to
Exhibit 4.3 to Amendment 1 to the Company's Registration Statement on
Form S-3, Registration No. 333-08315).
4.3 Indenture, dated as of September 20, 1996, between the Company and IBJ
Schroder Bank & Trust Company, as trustee, relating to $225,000,000
principal amount of 9 1/2% Senior Notes due 2006 (incorporated by
reference to Exhibit 4.1 to the Company's Registration Statement on
Form S-3, Registration No. 333-15591).
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 1996 Form 10-K).
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, 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, 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.)
4.8 Form of Third Supplemental Indenture, 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.
4.10 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of
March 14, 2000.
4.11 Indenture, dated as of March 12, 2002 among the Company and the Bank of
New York, as Trustee.
4.12 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of
March 7, 2002.
4.13 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of
March 12, 2002.
10.1 Employment Agreement between the Company and David L. Sokol, dated May
10, 1999.
10.2 Amendment No. 1 to the Amended and Restated Employment Agreement
between the Company and David L. Sokol, dated March 14, 2000.
10.3 Amended and Restated Employment Agreement between the Company and
Gregory E. Abel, dated May 10, 1999.
10.4 Amended and Restated Employment Agreement between the Company and
Steven A. McArthur, dated May 10, 1999.
10.5 Employment Agreement between the Company and Patrick J. Goodman, dated
May 10, 1999.
10.9 125 MW Power Plant - Upper Mahiao Agreement (the "Upper Mahiao ECA")
dated September 6, 1993 between PNOC-Energy Development Corporation
("PNOC-EDC") 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 1994 Form 10-K).
10.10 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 1994 Form 10-K).
10.11 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 1994 Form
10-K).
10.12 Pledge Agreement among CE Philippines Ltd, Ormat-Cebu Ltd., Credit
Suisse as Collateral Agent and CE Cebu Geothermal Power Company, Inc.
dated as of April 8, 1994 (incorporated by reference to Exhibit 10.98
to the Company's 1994 Form 10-K).
10.13 Overseas Private Investment Corporation Contract of Insurance dated
April 8, 1994 between the Overseas Private Investment Corporation
("OPIC") 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 1994 Form 10-K).
10.14 180 MW Power Plant - Mahanagdong Agreement ("Mahanagdong ECA") dated
September 18, 1993 between PNOC-EDC and CE Philippines Ltd. and the
Company, as amended by the First Amendment to Mahanagdong ECA dated
June 22, 1994, the Letter Agreement dated July 12, 1994, the Letter
Agreement dated July 29, 1994, and the Fourth Amendment to Mahanagdong
ECA dated March 3, 1995 (incorporated by reference to Exhibit 10.100 to
the Company's 1994 Form 10-K).
10.15 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 1994 Form 10-K).
10.16 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 1994 Form
10-K).
10.17 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 1994 Form
10-K).
10.18 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 1994 Form 10-K).
10.19 Overseas Private Investment Corporation Contract of Insurance dated
July 29, 1994 between OPIC 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 1994 Form 10-K).
10.20 231 MW Power Plant - Malitbog Agreement ("Malitbog ECA") dated
September 10, 1993 between PNOC-EDC 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 1994 Form 10-K).
10.21 Credit Agreement dated as of November 10, 1994 among Visayas Power
Capital Corporation, the Banks parties thereto and Credit Suisse Bank
Agent (incorporated by reference to Exhibit 10.107 to the Company's
1994 Form 10-K).
10.22 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 1994 Form
10-K).
10.23 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 1994 Form 10-K).
10.24 Overseas Private Investment Corporation Contract of Insurance dated
December 21, 1994 between OPIC and Magma Netherlands, B.V.
(incorporated by reference to Exhibit 10.110 to the Company's 1994 Form
10-K).
10.25 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, OPIC and the Banks named therein (incorporated by reference
to Exhibit 10.111 to the Company's 1994 Form 10-K).
10.26 Trust Indenture dated as of November 27, 1995 between the CE Casecnan
Water and Energy Company, Inc. ("CE Casecnan") and Chemical Trust
Company of California (incorporated by reference to Exhibit 4.1 to CE
Casecnan's Registration Statement on Form S-4 dated January 25, 1996
("Casecnan S-4").
10.27 Amended and Restated Casecnan Project Agreement between the National
Irrigation Administration and CE Casecnan Water and Energy Company Inc.
dated June 26, 1995 (incorporated by reference to Exhibit 10.1
to the Casecnan Form S-4).
10.28 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
1996 Form 10-K).
10.29 Public Electricity Supply License (incorporated by reference to Exhibit
10.131 to the Company's 1996 Form 10-K)
10.30 Second Tier Supply Licenses to Supply Electricity for England & Wales
and Scotland (incorporated by reference to Exhibit 10.132 to the
Company's 1996 Form 10-K).
10.31 Pooling and Settlement Agreement for the Electricity Industry in
England and Wales dated 30th March, 1990 (as amended at 17th October,
1996), among The Generators (named therein), the Suppliers (named
therein), Energy Settlements and Information Services Limited (as
Settlement System Administrator), Energy Pool Funds Administration
Limited (as Pool Funds Administrator), Scottish Power plc, Electricite
deFrance, Service National and Others (incorporated by reference to
Exhibit 10.133 to the Company's 1996 Form 10-K).
10.32 Master Connection and User System Agreement with The National Grid
Company plc (incorporated by reference to Exhibit 10.134 to the
Company's 1996 Form 10-K).
10.33 Gas Suppliers License dated February 21, 1996 (incorporated by
reference to Exhibit 10.135 to the Company's 1996 Form 10-K).
10.34 Acquisition Agreement by and between CalEnergy Company, Inc. and Kiewit
Diversified Group Inc. dated as of September 10, 1997 (incorporated
by reference to Exhibit 2 to the Company's Current Report on Form 8-K
dated September 11, 1997).
10.35 Agreement and Plan of Merger dated as of August 11, 1998 by and among
CalEnergy Company, Inc., Maverick Reincorporation Sub, Inc.,
MidAmerican Energy Holdings Company and MAVH Inc. (incorporated by
reference to the Company's Current Report on Form 8-K dated August 11,
1998).
10.36 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 1998 Form
10-K).
10.37 Settlement Agreement by and between MidAmerican Energy Company, the
Iowa Utilities Board, the Iowa Office of Consumer Advocate, and others.
(incorporated by reference to the Company's 1998 Form 10-K).
10.38 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 Midwest Resources Inc.'s Annual Report on Form 10-K for the
year ended December 31, 1992, Commission File No. 1-10654.)
10.39 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
Midwest Resources' Annual Report on Form 10-K for the year ended
December 31, 1992, Commission File No. 1-10654.)
10.40 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
Midwest Resources' Annual Report on Form 10-K for the year ended
December 31, 1992, Commission File No. 1-10654.)
10.41 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 Midwest
Resources' Annual Report on Form 10-K for the year ended December 31,
1993, Commission File No. 1-10654.)
10.42 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 Midwest Resources'
Annual Report on Form 10-K for the year ended December 31, 1994,
Commission File No. 1-10654.)
10.43 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 Midwest Resources'
Annual Report on Form 10-K for the year ended December 31, 1994,
Commission File No. 1-10654.)
10.44 Indenture of Mortgage and Deed of Trust, dated as of March 1, 1947.
(incorporated by reference to Iowa-Illinois Gas and Electric Company
("Iowa-Illinois") as Exhibit 7B to Commission File No. 2-6922.)
10.45 Sixth Supplemental Indenture dated as of July 1, 1967. (incorporated
by reference to Iowa-Illinois as Exhibit 2.08 to Commission File No.
2-28806.)
10.46 Twentieth Supplemental Indenture dated as of May 1, 1982. (incorporated
by reference to Exhibit 4.B.23 to Iowa-Illinois' Quarterly Report on
Form 10-Q for the period ended June 30, 1982, Commission File No.
1-3573.)
10.47 Resignation and Appointment of successor Individual Trustee.
(incorporated by reference to Iowa-Illinois as Exhibit 4.B.30 to
Commission File No. 33-39211.)
10.48 Twenty-Eighth Supplemental Indenture dated as of May 15, 1992.
(incorporated by reference to Exhibit 4.31.B to Iowa-Illinois' Current
Report on Form 8-K dated May 21, 1992, Commission File No.
1-3573.)
10.49 Twenty-Ninth Supplemental Indenture dated as of March 15, 1993.
(incorporated by reference to Exhibit 4.32.A to Iowa-Illinois' Current
Report on Form 8-K dated March 24, 1993, Commission File No.
1-3573.)
10.50 Thirtieth Supplemental Indenture dated as of October 1, 1993.
(incorporated by reference to Exhibit 4.34.A to Iowa-Illinois' Current
Report on Form 8-K dated October 7, 1993, Commission File No. 1-3573.)
10.51 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 MidAmerican Energy
Company's ("MidAmerican Energy") Annual Report on Form 10-K dated
December 31, 1995, Commission File No. 1-11505.)
10.52 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
MidAmerican Energy's Annual Report on Form 10-K dated December 31,
1995, Commission File No.
1-11505.)
10.53 Power Sales Contract between Iowa Power Inc. and Nebraska Public Power
District, dated September 22, 1967. (incorporated by reference to
Exhibit 4-C-2 to Iowa Power Inc.'s (IPR) Registration Statement,
Registration No. 2-27681).
10.54 Amendments Nos. 1 and 2 to Power Sales Contract between Iowa Power Inc.
and Nebraska Public Power District. (incorporated by reference to
Exhibit 4-C-2a to IPR's Registration Statement, Registration No.
2-35624.)
10.55 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 to
IPR's Registration Statement, Registration No. 2-42191.)
10.56 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 to
IPR's Registration Statement, Registration No. 2-51540.)
10.57 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 MidAmerican Energy's Quarterly Reports on the combined Form 10-Q
for the quarter ended September 30, 1997, Commission File Nos. 1-12459
and 1-11505, respectively.)
10.58 MidAmerican Energy Company Severance Plan For Specified Officers dated
November 1, 1996. (incorporated by reference to Exhibit 10.1 to
` MidAmerican Energy's Annual Reports on the combined Form 10-K for the
year ended December 31, 1996, Commission File Nos. 1-12459 and 1-11505,
respectively.)
10.59 MidAmerican Energy Holdings Company Executive Voluntary Deferred
Compensation Plan.
10.60 MidAmerican Energy Company Supplemental Retirement Plan for Designated
Officers. (incorporated by reference to Exhibit 10.3 to MidAmerican
Energy's Annual Report on Form 10-K dated December 31, 1995,
Commission File No. 1-11505.)
10.61 MidAmerican Energy Company Restated Executive Deferred Compensation
Plan.
10.62 MidAmerican Energy Holdings Company Restated Deferred Compensation Plan
- Board of Directors.
10.63 MidAmerican Energy Company Combined Midwest Resources/Iowa Resources
Restated Deferred Compensation Plan - Board of Directors.
10.66 Midwest Resources Inc. Supplemental Retirement Plan (formerly the
Midwest Energy Company Supplemental Retirement Plan). (incorporated
by reference to Exhibit 10.10 to Midwest Resources' Annual Report on
Form 10-K for the year ended December 31, 1993, Commission File No.
1-10654.)
10.72 Supplement Retirement Plan for Principal Officers, as amended as of
July 1, 1993. (incorporated by reference to Exhibit 10.K.2 to Iowa-
Illinois' Annual Report on Form 10-K for the year ended December 31,
1993, Commission File No. 1-3573.)
10.73 Compensation Deferral Plan for Principal Officers, as amended as of
July 1, 1993. (incorporated by reference to Exhibit 10.K.2 to Iowa-
Illinois' Annual Report on Form 10-K for the year ended December 31,
1993, Commission File No. 1-3573.)
10.74 Board of Directors' Compensation Deferral Plan. (incorporated by
reference to Exhibit 10.K.4 to Iowa-Illinois' Annual Report on Form
10-K for the year ended December 31, 1992, Commission File No.
1-3573.)
10.75 Amendment No. 1 to the Midwest Resources Inc. Supplemental Retirement
Plan. (incorporated by reference to Exhibit 10.24 to Midwest Resources'
Annual Report on Form 10-K for the year ended December 31, 1994,
Commission File No. 1-10654.)
10.78 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 MidAmerican Energy's Quarterly Reports on the combined Form 10-Q
for the quarter ended September 30, 1997, Commission File Nos. 1-12459
and 1-11505, respectively.)
21.0 Subsidiaries of Registrant.
24.0 Power of Attorney.
Exhibit 21
MIDAMERICAN ENERGY HOLDINGS COMPANY
SUBSIDIARIES AND JOINT VENTURES
Subsidiaries:
MidAmerican Energy Holdings Company Iowa
MidAmerican Funding, LLC Iowa
MHC Inc. Iowa
MidAmerican Energy Company Iowa
MidAmerican Energy Financing I Delaware
MidAmerican Energy Funding Corporation Delaware
CBEC Railway Inc. Iowa
MidAmerican Capital Company Delaware
AmGas Inc. Iowa
Cimmred Leasing Company South
InterCoast Capital Company South Dakota
InterCoast Energy Company Delaware
InterCoast Global Management, Inc Delaware
InterCoast Power Company Delaware
InterCoast Power Marketing Company Delaware
IWG Co. 8 Delaware
MHC Investment Company South Dakota
MidAmerican Rail Inc Iowa
MWR Capital Inc. South Dakota
TTP, Inc. of South Dakota South Dakota
Edge Technologies, Inc. Iowa
Micro-Generation Technology Fund, LLC Delaware
Tenaska III Texas Partners Texas
Utech Venture Capital Corporation Delaware
Midwest Capital Group, Inc. Iowa
Dakota Dunes Development Company Iowa
Two Rivers Inc. South Dakota
Northgate Park Associates Iowa
MidAmerican Services Company Iowa
MEC Construction Services Co. Iowa
HomeServices.Com Inc. Delaware
CBS Brokerage Systems Inc. Nebraska
CBSHome Real Estate Company Nebraska
Champion Realty, Inc. Maryland
Chancellor Mortgage Services, Inc. Maryland
Chancellor Title Services, Inc. Maryland
Edina Corporate Services, Inc. Minnesota
Edina Financial Services, Inc. Minnesota
Edina Realty Franchise Associates, Inc. Minnesota
Edina Realty, Inc. Minnesota
Edina Realty Insurance Agency, Inc. Minnesota
Edina Realty of Wisconsin, Inc. Wisconsin
Edina Realty Title, Inc. Minnesota
First Realty, Ltd. Iowa
For Rent, Inc. Arizona
HMSV Financial Services, Inc. Delaware
HMSV Technologies, Inc. Delaware
HomeServices of California, Inc. Delaware
IMO Co., Inc. Missouri
Iowa Realty Co., Inc. Iowa
Iowa Realty Insurance Agency, Inc. Iowa
Iowa Title Company Iowa
Iowa Title Linn County LLC Iowa
JC Nichols Residential Inc. Iowa
J. C. Nichols Residential Peculiar, LLC Missouri
J. P. & A., Inc. Georgia
Jenny Pruitt & Associates, Inc. Georgia
Kansas City Title, Inc. Missouri
Kentucky Residential Referral Service, LLC Kentucky
MidAmerican Commercial Real Estate Services, Inc. Kansas
Midland Escrow Services, Inc. Iowa
MRSCT, Inc. Kentucky
Nebraska Land Title and Abstract Company Nebraska
Paul Semonin Company Kentucky
Plaza Financial Services, LLC Kansas
Plaza Mortgage Services, LLC Kansas
Professional Referral Organization, Inc. Maryland
Reece & Nichols Realtors Inc. Kansas
The Referral Company Iowa
RHL Referral Company, LLC Arizona
Roy H. Long Realty Co., Inc. Arizona
Select Relocation Services, Inc. Nebraska
Semonin Mortgage Services, Inc. Kentucky
Southwest Relocation, LLC Arizona
Trinity Mortgage Partners, Inc. Georgia
Carol Jones Company Missouri
Carol Jones Properties, LTD Missouri
Cendant Home Funding-Nebraska, LLC Delaware
Edina Realty Mortgage, LLC Delaware
HomeServices Lending, LLC Delaware
Iowa Title Linn County II, LLC Iowa
Jenny Pruitt Insurance Services, LLC Georgia
Long Title Agency, LLC Arizona
Meridian Title Services, LLC Georgia
MidAmerican Home Services Mortgage, LLC Iowa
Real Estate Links, LLC Illinois
Service Mortgage Group, LLC Kentucky
United Settlement Services, LC Iowa
CE Electric UK Funding Company England and Wales
Avonmouth CHP Limited England and Wales
CalEnergy Gas (Holdings) Limited England and Wales
CalEnergy Gas Limited England and Wales
CalEnergy Gas (Australia) Limited England and Wales
CalEnergy Gas (UK) Limited England and Wales
CalEnergy Gas (Polska) Sp. z.o.o. Poland
CalEnergy Gas (Pipelines) Limited England and Wales
CalEnergy Power (Polska) SP. z.o.o. Poland
CE Electric (Ireland) Ltd. Republic of Ireland
CE Electric UK Holdings England and Wales
CE Electric UK Ltd. England and Wales
CE Insurance Services Isle of Man
CE UK Gas Holdings Limited England and Wales
Electra Brands Limited England and Wales
Electralink Limited England and Wales
Electricity Pensions Trustee Limited England and Wales
Empire Oil & Gas NL Australia
Integrated Utility Services Limited England and Wales
Northern Electric plc England and Wales
Northern Electric Distribution Limited England and Wales
Northern Electric Finance plc England and Wales
Northern Electric & Gas Limited England and Wales
Northern Electric Generation Limited England and Wales
Northern Electric Generation (TPL) Limited England and Wales
Northern Electric Generation (Peaking) Limited England and Wales
Northern Electric Genco Limited England and Wales
Northern Electric Insurance Services Limited Isle of Man
Northern Electric (Overseas Holdings) Limited England and Wales
Northern Electric Properties Limited England and Wales
Northern Electric Retail Limited England and Wales
Northern Electric Supply Limited England and Wales
Northern Infocom Limited England and Wales
Northern Metering Services Limited England and Wales
Northern Tracing & Collection Services Limited England and Wales
Northern Transport Finance Limited England and Wales
Ryhope Road Developments Ltd England and Wales
Stamfordham Road Developments Ltd. England and Wales
Kings Road Developments Limited England and Wales
REC Collect England and Wales
Selectusonline England and Wales
Teesside Power Limited England and Wales
Vehicle Lease and Service Limited England and Wales
Viking Power Ltd. England and Wales
Yorkshire Cayman Holding Limited Cayman Islands
Yorkshire Electricity Distribution plc England and Wales
Yorkshire Electricity Distribution Services Limited England and Wales
Yorkshire Electricity Group plc England and Wales
Yorkshire Holdings plc England and Wales
Yorkshire Power Finance Limited Cayman Islands
Yorkshire Power Finance 2 Limited Cayman Islands
Yorkshire Power Group Limited England and Wales
YPG Holdings LLC Delaware
CE Generation, LLC Nebraska
CalEnergy Operating Corporation Delaware
California Energy Development Corporation Delaware
California Energy Yuma Corporation Utah
CE Salton Sea Inc. Delaware
CE Texas Energy LLC Delaware
CE Texas Gas LP Delaware
CE Texas Fuel, LLC Delaware
CE Texas Pipeline, LLC Delaware
CE Texas Power, LLC Delaware
CE Texas Resources, LLC Delaware
CE Turbo LLC Delaware
Conejo Energy Company California
Del Ranch, L. P. California
Desert Valley Company California
Elmore, L.P. California
Falcon Power Operating Company Texas
Falcon Seaboard Oil Company Texas
Falcon Seaboard Pipeline Corporation Texas
Falcon Seaboard Power Corporation Texas
Fish Lake Power LLC Delaware
FSRI Holdings, Inc Texas
Imperial Magma LLC Delaware
Leathers, L.P. California
Magma Land Company I Nevada
Magma Power Company Nevada
Niguel Energy Company California
Power Resources, Ltd. Texas
Salton Sea Brine Processing L. P. California
Salton Sea Funding Corporation Delaware
Salton Sea Power Company Nevada
Salton Sea Power Generation L. P. California
Salton Sea Power L.L.C. Delaware
Salton Sea Royalty LLC Delaware
San Felipe Energy Company California
Saranac Energy Company, Inc. Delaware
SECI Holdings, Inc. Delaware
VPC Geothermal LLC Delaware
Vulcan Power Company Nevada.
Vulcan/BN Geothermal Power Company Nevada.
Yuma Cogeneration Associates Arizona
North Country Gas Pipeline Corporation New York
Saranac Power Partners, L. P. Delaware
American Pacific Finance Company Delaware
Aurora 2000, LLC Delaware
CalEnergy Capital Trust II Delaware
CalEnergy Capital Trust III Delaware
CalEnergy Company Inc. Delaware
CalEnergy Generation Operating Company Delaware
CalEnergy Holdings, Inc. Delaware
CalEnergy International Ltd. Bermuda
CalEnergy International Services, Inc. Delaware
CalEnergy Investments C.V. Netherlands
CalEnergy Minerals, LLC Delaware
CalEnergy Minerals Development LLC Delaware
CalEnergy Pacific Holdings Corp. Delaware
CalEnergy U.K. Inc. Delaware
CE Aurora I, Inc. Delaware
CE Casecnan Ltd. Bermuda
CE Cebu Geothermal Power Company, Inc. Philippines
CE (Bermuda) Financing Ltd. Bermuda
CE Electric, Inc. Delaware
CE Electric (NY), Inc. Delaware
CE Exploration Company Delaware
CE Geothermal, Inc. Delaware
CE Geothermal LLC Delaware
CE Indonesia Geothermal, Inc. Delaware
CE Insurance Services Limited Isle of Man
CE International, Inc. Delaware
CE International (Bermuda) Ltd Bermuda
CE International Investments, Inc. Delaware
CE Mahanagdong Ltd. Bermuda
CE Mahanagdong II, Inc. Philippines
CE Obsidian Energy LLC Delaware
CE Philippines Ltd. Bermuda
CE Philippines II, Inc. Philippines
CE Power, Inc. Delaware
CE Power LLC Delaware
CE Resources LLC Delaware
Cordova Energy Company, LLC Delaware
Cordova Funding Corporation Delaware
Fox Energy Company LLC Delaware
Intermountain Geothermal Company Delaware
Tongonan Power Investment, Inc. Philippines
Magma Netherlands B.V. Netherlands
MidAmerican Capital Trust I Delaware
Northern Aurora, Inc. Delaware
Quad Cities Energy Company Iowa
Salton Sea Minerals Corp. Delaware
Visayas Geothermal Power Company Philippines
CE Casecnan Water and Energy Company, Inc. Philippines
CE Luzon Geothermal Power Company, Inc. Philippines
American Pacific Finance Company II California
Arizona Home Services LLC Arizona
Big Springs Pipeline Company Texas
Bioclean Fuels, Inc. Delaware
CalEnergy BCF, Inc. Delaware
CalEnergy Capital Trust I Delaware
CalEnergy Capital Trust IV Delaware
CalEnergy Capital Trust V Delaware
CalEnergy Capital Trust VI Delaware
CalEnergy Europe Ltd. England and Wales
CalEnergy Imperial Valley Company, Inc. Delaware
CalEnergy Power Ltd. England and Wales
CalEnergy Power Ventures Ltd. England and Wales
California Energy Management Company Delaware
California Energy Retail Company, Inc. Delaware
CBE Engineering Co. California
CEABC Co. Delaware
CEXYZ Co. Delaware
CE Administrative Services, Inc. Delaware
CE Alberta Bioclean, Inc. Delaware
CE Argo Energy, Inc. Delaware
CE Argo Power LLC Delaware
CE Asia Ltd. Bermuda
CE Bali, Ltd. Bermuda
CE CIS-FSU, Inc. Delaware
CE Indonesia Ltd. Bermuda
CE Latin America Ltd Bermuda
CE Overseas Ltd. Bermuda
CE Singapore Ltd. Bermuda
CE/TA LLC Delaware
DCCO Inc. Minnesota
Direct Energy Ltd. England and Wales
Electric & Gas UK Ltd. England and Wales
Electricity & Gas UK Ltd. England and Wales
Electricity North East Ltd. England and Wales
Electricity North Ltd. England and Wales
Gas & Electricity UK Ltd. England and Wales
Gas UK Ltd. England and Wales
Gilbert/CBE Indonesia L.L.C. Nebraska
Gilbert/CBE L. P. Nebraska
Integrated Utility Services (UK) Ltd. England and Wales
IPP Co. Delaware
IPP Co. LLC Delaware
InterCoast Sierra Power Company Delaware
LW Technical (Northern) Ltd. England and Wales
Magma Generating Company I Nevada
Magma Generating Company II Nevada
MidAmerican Energy Financing II Delaware
Midwest Gas Company Iowa
NEEB Ltd. England and Wales
Neptune Power Ltd. England and Wales
NorCon Holdings, Inc. Delaware
NorCon Power Partners L.P. Delaware
Norming Investments B.V. Netherlands
North Eastern Electricity Ltd. England and Wales
Northern Aurora Limited England and Wales
Northern Billing and Customer Information Services Ltd. England and Wales
Northern Cablevision Ltd. England and Wales
Northern Cogen Ltd. England and Wales
Northern Consolidated Power, Inc. Delaware
Northern Electric Building Services Ltd. England and Wales
Northern Electric Computer Services Ltd. England and Wales
Northern Electric Consultants Ltd. England and Wales
Northern Electric Contracting Ltd. England and Wales
Northern Electric & Gas Distribution Ltd. England and Wales
Northern Electric Generation (NPL) Limited England and Wales
Northern Electric Generation (CPS) Limited England and Wales
Northern Electric Investments Ltd. England and Wales
Northern Electric Power Ltd. England and Wales
Northern Electric Share Scheme Trustee Ltd. England and Wales
Northern Electrics Ltd. England and Wales
Northern Electric Telecom Limited England and Wales
Northern Electric (TPL) Holdings Ltd. England and Wales
Northern Electric Training Limited England and Wales
Northern Electric Transport Limited England and Wales
Northern Energy Distribution Ltd. England and Wales
Northern Gas & Electricity Ltd. England and Wales
Northern Gas & Electric Ltd. England and Wales
Northern Gas Marketing Ltd. England and Wales
Northern Power Distribution Ltd. England and Wales
Northern Utilities Ltd. England and Wales
Northern Utility Services Ltd. England and Wales
NUSL International Ltd. England and Wales
Ormoc Cebu Ltd. Bermuda
Real Estate Referral Network, Inc. Nebraska
Seal Sands Network Ltd. England and Wales
Slupo I B.V. Netherlands
UK Electric & Gas Ltd. England and Wales
UK Electricity & Gas Ltd. England and Wales
UK Gas & Electricity Ltd. England and Wales
Yorkshire Electricity Distribution Holdings Ltd England and Wales