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, 2000
[ ] 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 amend-
ment 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 30, 2001, 9,281,087 shares of
common stock were outstanding.
TABLE OF CONTENTS
PART I.......................................................................4
Item 1. Business.............................................................4
General......................................................................4
Teton Transaction............................................................4
Business of MEHC.............................................................4
MidAmerican Energy......................................................4
Northern Electric.......................................................8
CalEnergy Generation....................................................14
Projects in Operation..............................................15
CE Generation Geothermal Facilities................................15
CE Generation Gas Facilities.......................................17
Other U.S. Geothermal Interests....................................18
The Philippines Power Generation...................................18
Projects in Construction................................................20
United States......................................................20
Philippines........................................................21
HomeServices............................................................23
The Global Energy Market.....................................................23
United States...........................................................24
United Kingdom..........................................................26
Regulatory, Energy and Environmental Matters.................................28
United States...........................................................28
United Kingdom..........................................................30
Employees....................................................................30
Item 2. Properties...........................................................31
Item 3. Legal Proceedings....................................................32
Item 4. Submission of Matters to a Vote of Security Holders..................33
PART II......................................................................34
Item 5. Market for Registrant's Common Equity and Related
Stockholder's Matters..............................................34
Item 6. Selected Financial Data..............................................34
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations................................34
Item 7A.Qualitative and Quantitative Disclosures About Market Risk...........34
Item 8. Financial Statements and Supplementary Data..........................34
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure...........................................34
PART III.....................................................................35
Item 10. Directors, Executive and Other Officers of the Company
and Significant Subsidiaries.......................................35
Item 11. Executive Compensation..............................................36
Item 12. Security Ownership of Certain Beneficial Owners and Management......36
Item 13. Certain Relationships and Related Transactions......................36
PART IV......................................................................37
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.....37
SIGNATURES...................................................................100
EXHIBIT INDEX................................................................102
PART I
Item 1. Business
General
MidAmerican Energy Holdings Company (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 Northern Electric plc ("Northern"), the Company
currently serves approximately 1.8 million electricity customers and 1.1 million
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 A+) and Northern (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 October 24, 1999, the Company entered into an Agreement and Plan of Merger
with an investor group that included Berkshire Hathaway Inc., Walter Scott, Jr.,
and David L. Sokol (the "Investor Group"). The Investor Group, along with
Gregory E. Abel, closed on the acquisition on March 14, 2000 (the "Teton
Transaction"). Pursuant to the acquisition, the Investor Group, including Mr.
Abel, paid the Company's shareholders $35.05 in cash for each outstanding share
of the Company's common stock and became the sole shareholders of the Company in
a "going private" transaction.
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 four separate platforms: MidAmerican Energy, Northern Electric,
CalEnergy Generation and HomeServices.
MidAmerican Energy
MidAmerican Energy is the largest energy company headquartered in Iowa, with
assets and 2000 revenues totaling $3.8 billion and $2.3 billion, respectively.
MidAmerican Energy is primarily 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, 2000,
MidAmerican Energy had 669,000 retail electric customers and 647,000 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.
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 2000 electric operating revenues or 2% of its total
2000 gas operating margin. Among the primary industries served by MidAmerican
Energy are those which are concerned with the manufacturing, processing and
fabrication of primary metals, real estate, food products, farm and other
non-electrical machinery, and cement and gypsum products.
For the year ended December 31, 2000, MidAmerican Energy derived approximately
52% of its gross operating revenues from its regulated electric business, 28%
from its regulated gas business and 20% from its nonregulated business
activities. For 1999 and 1998, the corresponding percentages were 66% electric,
25% gas and 9% nonregulated; and 69% electric, 25% gas and 6% nonregulated,
respectively. The change in revenue mix for 2000 was driven by an increase in
natural gas prices and in nonregulated natural gas sales activity.
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.
A substantial majority 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 also manages its operations as four distinct
business units: generation, transmission, energy distribution and retail. It is
under this framework that MidAmerican Energy believes it can best prepare for,
and succeed in, the energy business of the future. With these four business
units, MidAmerican Energy is able to focus on the specific needs and anticipated
risks and opportunities of its major businesses. Certain administrative
functions are handled by a corporate services group that supports all of the
business units.
Presently, significant functions of the generation business unit include the
production of electricity, the purchase of electricity and natural gas, and the
sale of wholesale electricity and natural gas. The transmission business unit
coordinates all activities related to MidAmerican Energy's electric transmission
facilities, including monitoring access to and assuring the reliability of the
transmission system. The energy distribution business unit distributes
electricity and natural gas to end-users, provides customer service and conducts
related activities. Retail includes marketing and related functions for core and
complementary products and services.
Historical electric sales by customer class as a percent of total electric sales
and retail electric sales data by state as a percent of total retail electric
sales are shown below:
Total Electric Sales of MidAmerican Energy By Customer Class
2000 1999 1998
Residential 20.7% 21.0% 22.2%
Small General Service 15.9 16.7 17.5
Large General Service 28.6 26.9 28.1
Other 5.4 4.5 4.4
Sales for Resale 29.4 30.9 27.8
----- ----- -----
Total 100.0% 100.0% 100.0%
====== ====== ======
Retail Electric Sales of MidAmerican Energy By State
2000 1999 1998
Iowa 89.3% 88.9% 88.4%
Illinois 10.0 10.4 10.9
South Dakota 0.7 0.7 0.7
------ ------ ------
Total 100.0% 100.0% 100.0%
====== ====== ======
Historical gas sales, excluding transportation throughput, by customer class as
a percent of total gas sales and by state as a percent of total retail gas sales
are shown below:
Total Regulated Gas Sales of MidAmerican Energy By Customer Class
2000 1999 1998
Residential 64.0% 63.5% 62.0%
Small General Service 31.8 32.2 33.2
Large General Service 4.0 4.0 3.8
Other 0.2 0.3 1.0
----- ------ -----
TOTAL 100.0% 100.0% 100.0%
====== ====== ======
Retail Gas Sales of MidAmerican Energy By State
2000 1999 1998
Iowa 78.0% 78.8% 79.0%
Illinois 10.2 10.3 10.2
South Dakota 11.0 10.1 10.1
Nebraska 0.8 0.8 0.7
------ ------ ------
TOTAL 100.0% 100.0% 100.0%
====== ====== ======
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 2000, 38% of MidAmerican Energy's electric revenues
were reported in the months of June, July, August and September, and 56% of
MidAmerican Energy's gas revenues were reported in the months of January,
February, March and December.
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
September 2000, MidAmerican Energy recorded an hourly peak demand of 3,648 MW,
which is 185 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 projects:
- ---------------------------- ----------- ---------- ----------- --------------- -------------
Project(1) Facility Net MW Fuel Location Commercial
Net MW Owned(2) Operation
- ---------------------------- ----------- ---------- ----------- --------------- -------------
Council Bluffs Energy 131 131 Coal Iowa 1954, 1958
Center units 1 & 2
- ---------------------------- ----------- ---------- ----------- --------------- -------------
Council Bluffs Energy 675 534 Coal Iowa 1978
Center unit 3
- ---------------------------- ----------- ---------- ----------- --------------- -------------
Louisa Generation Station 700 616 Coal Iowa 1983
- ---------------------------- ----------- ---------- ----------- --------------- -------------
Neal Generation Station 435 435 Coal Iowa 1964, 1972
units 1 & 2
- ---------------------------- ----------- ---------- ----------- --------------- -------------
Neal Generation Station 515 371 Coal Iowa 1975
unit 3
- ---------------------------- ----------- ---------- ----------- --------------- -------------
Neal Generation Station 624 261 Coal Iowa 1979
unit 4
- ---------------------------- ----------- ---------- ----------- --------------- -------------
Ottumwa Generation Station 716 372 Coal Iowa 1981
- ---------------------------- ----------- ---------- ----------- --------------- -------------
Quad Cities Power Station 1,529 383 Nuclear Illinois 1972
- ---------------------------- ----------- ---------- ----------- --------------- -------------
Riverside Generation 135 135 Coal Iowa 1925-61
Station
- ---------------------------- ----------- ---------- ----------- --------------- -------------
Combustion Turbines 789 789 Gas 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 7,066 4,465
- ---------------------------- ----------- ---------- ----------- --------------- -------------
(1)The Company operates all such projects other than Quad Cities Power 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 agreement extending to the year 2004.
All of the coal-fired generating stations operated by MidAmerican Energy are
fueled by low-sulfur, western coal from the Powder River Basin and Hanna Basin
mines. The use of low-sulfur western coal enables MidAmerican Energy to comply
with the current acid rain provisions of the Clean Air Act Amendments of 1990
("CAAA") without having to install additional costly emissions control equipment
at its generating stations or purchase additional emissions credits. MidAmerican
Energy's coal supply portfolio includes multiple suppliers and mines under
agreements of varying term and quantity flexibility. MidAmerican Energy
regularly monitors the western coal market, looking for opportunities to improve
its coal supply portfolio. MidAmerican Energy believes its sources of coal
supply are and will continue to be satisfactory.
MidAmerican Energy can use both the Union Pacific Railroad ("UP") and the
Burlington Northern and Santa Fe Railway ("BNSF") as originating carriers of its
coal supply. Coal is delivered directly to MidAmerican Energy's Neal Energy
Center by UP and to Council Bluffs Energy Center ("CBEC") by either UP or BNSF.
Coal for MidAmerican Energy's Louisa and Riverside Energy Centers is delivered
to an interchange point by BNSF or up for transportation to its destination by
the I&M Rail Link. MidAmerican Energy believes its coal transportation
arrangements are adequate to meet its coal delivery needs.
MidAmerican Energy uses natural gas and oil as fuel for peak demand electric
generation, transmission support and standby purposes. These sources are
presently in adequate supply and available to meet MidAmerican Energy's needs.
MidAmerican Energy is a 25% joint owner of Quad Cities Generating Station, a
nuclear power plant. MidAmerican Energy has been advised by Exelon Generation
Company, LLC ("Exelon"), the joint owner and operator of Quad Cities Station,
that the majority of its uranium concentrate and uranium conversion requirements
for Quad Cities Station through 2001 can be met under existing supplies or
commitments. Exelon foresees no problem in obtaining the remaining requirements
now or obtaining future requirements. Exelon further advises that all enrichment
requirements have been contracted through 2004. Commitments for fuel fabrication
have been obtained at least through 2006. Exelon does not anticipate that it
will have difficulty in contracting for uranium concentrates for conversion,
enrichment or fabrication of nuclear fuel needed to operate Quad Cities Station.
MidAmerican Energy's accredited net generating capability in the summer of 2000
was 4,507 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 a long-term power purchase
contract. The net generating capability at any time may be less due to
regulatory restrictions, fuel restrictions and generating units being
temporarily out of service for inspection, maintenance, refueling or
modifications.
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 Iowa, Minnesota, Nebraska and North Dakota
and portions of Illinois, Montana, South Dakota and Wisconsin and the Canadian
provinces of Saskatchewan and Manitoba. 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.
Each MAPP participant is required to maintain for emergency purposes a net
generating capability reserve of at least 15% above its system peak demand. If a
participant's capability reserve falls below the 15% minimum, significant
penalties could be contractually imposed by MAPP. MidAmerican Energy's reserve
margin at peak demand for 2000 was approximately 25%.
Northern Electric
The operations of Northern Electric plc ("Northern"), an indirect wholly owned
subsidiary of the Company, consist primarily of the distribution and supply of
electricity, supply of natural gas and other auxiliary businesses in the United
Kingdom. Northern's operations are seasonal in nature with a disproportionate
percentage of revenues and earnings historically being earned in the Company's
first and fourth quarters.
Northern Electric Distribution Limited ("NEDL"), a subsidiary of Northern,
receives electricity from the national grid transmission system and distributes
electricity to each of its authorized area customer's premises using Northern's
network of transformers, switchgear and cables. Substantially all of the
customers in Northern's authorized area are connected to Northern's network and
electricity can only be delivered to them through the Northern distribution
system, regardless of whether the electricity is supplied by Northern's supply
business or by other suppliers, thus providing Northern with distribution volume
that is stable from year to year. NEDL serves approximately 1.5 million
customers in Northern's area and charges its customers access fees for the use
of the distribution system.
At December 31, 2000, Northern's electricity distribution network (excluding
service connections to consumers) included approximately 17,000 kilometers of
overhead lines and approximately 27,000 kilometers of underground cables.
Substantially all substations are owned in freehold, and most of the balance are
held on leases which will not expire within 10 years. In addition to the
circuits referred to above, Northern's distribution facilities also include
approximately 26,000 transformers and approximately 25,000 substations.
Northern Electric Supply Limited ("NESL") focuses on Northern's supply business
and is responsible for marketing, tariff setting, contracts and customer service
in connection with the supply of both electricity and gas. Northern's supply
business involves the bulk purchase of electricity and gas and the subsequent
sale to individual customers. The purchase of electricity is primarily from the
Pool.
Under the terms of its PES license, Northern currently supplies approximately
1.04 million supply customers within its authorized area. In addition to
competing for supply customers in its authorized area, Northern holds a second
tier license to compete with the RECs and other suppliers to supply electricity
to customers outside its authorized area. Northern supplies customers in all 15
PES areas in Great Britain and Northern Ireland.
Total Electric Sales of Northern By Customer Class
2000 1999 1998
Residential 22.7% 27.5% 32.4%
Small General Service 12.0 12.7 16.2
Large General Service 64.2 58.1 49.9
Sales for Resale and Other 1.1 1.7 1.5
------ ------ -----
TOTAL 100.0% 100.0% 100.0%
====== ======= ======
Northern Electric & Gas Ltd. ("NEAGL"), a wholly owned subsidiary of Northern
Electric plc, holds a Gas Suppliers' License, under which it is authorized to
supply gas throughout Great Britain. This license includes standard terms
relating to supply obligations, social obligations and other miscellaneous
provisions dealing with metering, rights of entry, provision of information to
the Regulator and emergencies. There are no price control provisions in this
license. The gas supply market is now fully competitive, having been
progressively opened up to competition as the monopoly of the former state-owned
British Gas Corporation (which later became British Gas plc, and is now known as
Centrica) has been removed by legislation. Gas suppliers use the transmission
system of BG plc (now known as Lattice) to transport gas from the point at which
it is input into the national transmission system to the point at which it is
supplied to customers' premises. NEAGL also hold a Gas Shippers' License that
authorizes the company to make arrangements with gas transporters for gas to be
introduced into, conveyed by means of or taken out of pipeline system operated
by a gas transporter, either generally or for purposes connected with the supply
of gas to any premises specified in the license. As at December 31, 2000 NEAGL
had 470,000 gas customers in Great Britain. The gas supply offered by NEAGL and
the electricity supply offered by Northern Electric plc are available to
residential customers in one form of contract know as a "dual fuel contract."
Total Gas Sales of Northern By Customer Class
2000 1999 1998
Residential 64.2% 70.0% 45.5%
Commercial 35.8 30.0 54.5
----- ------ ------
TOTAL 100.0% 100.0% 100.0%
====== ====== ======
Integrated Utility Services Limited ("IUSL"), a subsidiary of Northern, is an
engineering company whose main role is to adapt and maintain the distribution
network of NEDL and to sell related services to third parties. IUSL continues to
work in close cooperation with NEDL that will see IUSL concentrate on new
connections and third party work in 2001. IUSL has continued to make cost
reductions and improve productivity during the past year by reviewing processes
with both suppliers and staff and the implementation of performance related pay
for staff. IUSL has pioneered techniques using innovative diagnostic testing
equipment that reduces the need for intrusive maintenance. The equipment can
identify some of the causes of potential systems failures before breakdown and
subsequent loss of supply occurs. IUSL continues to develop its third party
customer base with significant contracts with other electrical distribution
infrastructure owners.
Northern Electric Generation Limited ("Northern Generation"), a Northern
subsidiary, focuses on electricity generation, primarily through its ownership
in Teesside (described below) and its operation and ownership of Viking
(described below). Northern Generation also owns and operates a 5 MW diesel
power generating plant located in Northallerton, England, and has a 75%
ownership in a 1.8 MW windfarm located at Kirkheaton, Northumberland.
Teesside. Teesside Power Limited ("Teesside") owns and operates an 1,875 net MW
combined cycle gas-fired power plant at Wilton. Northern owns a 15.4% interest
in Teesside, but does not operate the plant. Northern purchases 400 MW of
electricity from Teesside under a long-term power purchase agreement which is
contracted until March 31, 2008.
Viking. Northern owns 50% of this 50MW gas fired mid merit power plant located
on Teesside. The plant is currently in the commissioning stage, however due to
combustor issues it is unlikely to pass the performance criteria required for
handover until early 2002. NEGL 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 NEGL. The plant will be used as part of Northern's
strategy to hedge the purchases and sales of electricity and gas, together with
obtaining the benefits of avoided charges together with sales premiums.
The Company, through Northern Generation, is pursuing a number of wind powered
generation opportunities both onshore and offshore in the U.K. and is also
evaluating a proposed 150 MW combined heat and power project under development
in Southern England with an industrial host. This project has been granted
section 14 approval which is required to be able to burn gas. Section 14 has
previously been the sanction, for non-approval, used by the U.K. government to
restrict the development of gas-fired plants in the U.K.
Northern Electric Retail Limited ("Northern Retail"), a subsidiary of Northern,
sells electrical and gas appliances and provides account collection and customer
services for Northern's other businesses.
Northern Metering Services Limited ("Northern Metering"), a subsidiary of
Northern, provides meter supply, installation, refurbishment and certification
services as well as meter operator and data collection services.
Producing Gas Field Operations and Fields in Development
CalEnergy Gas (Holdings) Limited. CalEnergy Gas (Holdings) Limited and its
subsidiaries ("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
described below. Also as is more fully discussed 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.
Producing Gas Fields Share of Remaining Current % Commenced Location
Reserves BCF(1) Working Interest Production
Anglia 45.5 to 65.9 55.000% 11/1991 U.K. Offshore (North Sea)
Windermere 6.8 20.000% 4/1997 U.K. Offshore (North Sea)
Victor 9.0 5.000% 9/1984 U.K. Offshore (North Sea)
Schooner 15.7 4.820% 10/1996 U.K. Offshore (North Sea)
Johnston 27.1 22.113% 10/1994 U.K. Offshore (North Sea)
Fields in Development Size Km2
Pila Area Concession 12,639(2) 100.000% N.W. Poland (Polish Trough)
EP389 10,000 40.789% S.W. Australia Onshore (Perth Basin)
Yolla Discovery 550 20.000% S.E. Australia Offshore (Bass Basin)
Otway Basin 775 25.000% S.E. Australia Offshore (Otway Basin)
(1)Gas reserves in Billion cubic feet (or "Bcf") as of January 1, 2001. 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)Subject to 25% relinquishment of the original area after years 2, 6, 8 and 10
during the 10 year contract term based on work program results.
Producing Fields
Anglia Field: The Anglia Field is located in the central part of the Southern
North Sea, approximately 36 miles north of Bacton on the UK coast. CalEnergy Gas
has a 55% working interest in this field. Remaining reserves as at January 1,
2001 are 45.5 to 65.9 Bcf net to CalEnergy Gas. The field is produced from an
unmanned platform (Anglia A) with six production wells and a two-well subsea
tieback (Anglia B). Anglia B is located three miles to the west of Anglia A and
is connected by a single 8" pipeline. Production is exported via a 16-mile, 12"
pipeline to the Conoco-operated Lincolnshire Offshore Gas Gathering System
(LOGGS) where gas and liquids are separated and transported via a 36" pipeline
to the Theddlethorpe gas terminal on the coast. The Anglia field's average net
production for the year 2000 was 22.3 MMscf/d (million standard cubic feet per
day). CalEnergy Gas sells its share of Anglia gas to its affiliate, Northern
Electric and Gas Limited, and to Innogy plc.
Windermere Field: The Windermere Field is located in the eastern part of the
Southern North Sea, approximately 62 miles east of Hull on the UK coast, and has
remaining reserves as at January 1, 2001 of 6.8 Bcf net to CalEnergy Gas. The
field is produced by an unmanned platform that has two wells. The gas is
transported via a single 8" pipeline to the Markham Field, where it is
compressed and redelivered through the K13 pipeline system to the Den Helder
terminal on the Netherlands coast. CalEnergy Gas holds a 20% working interest in
this field. The Windermere Field's average net production for the year 2000 was
5.3 MMscf/d. Gas is sold to N.V. Nederland's Gasunie.
Victor Field: The Victor Gas Field is located in the central part of the
Southern North Sea, approximately 80 miles east of the Theddlethorpe terminal
and has remaining reserves as at January 1, 2001 of 9.0 Bcf net to CalEnergy
Gas. An unmanned platform is installed and the field produces from five
production wells and a sixth subsea well tied back to the platform. The gas is
exported through a 16" pipeline to the Viking Field and then onwards to the
Theddlethorpe gas terminal. The Victor Field's average net production for the
year 2000 was 4.7 MMscf/d. Gas is sold to British Gas Trading Limited, a
subsidiary of Centrica. CalEnergy Gas holds a 5% working interest in this field.
Schooner Field: The Schooner Field is located in the northern part of the
Southern North Sea and has remaining reserves as at January 1, 2001 of 15.7 Bcf
net to CalEnergy Gas. The field is produced by an unmanned platform that is tied
back through a 17.5-mile, 16" flow line to the Murdoch platform. Production is
achieved from seven wells. The gas is transported through the Caister Murdoch
System (CMS) pipeline to the Theddlethorpe gas terminal. CalEnergy Gas holds a
4.82% working interest in the Schooner Field. The Schooner Field's average net
production for the year 2000 was 2.0 MMscf/d. CalEnergy Gas sells its share of
Schooner gas to its affiliate Northern Electric and Gas Limited.
Johnston Field: The Johnston Gas Field is located in the Southern North Sea
approximately 56 miles north east of Scarborough on the UK coast, and has
remaining reserves as at January 1, 2001 of 27.1 Bcf net to CalEnergy Gas. The
field is produced from three subsea wells tied back to the Ravenspurn North
field via a 4.5-mile, 12" pipeline. Gas is exported via the Cleeton Field to the
Dimlington terminal via a 33 mile, 36" pipeline. The field is unitized between
Blocks 43/26a and 43/27a. CalEnergy Gas derives its interest through a 30%
working interest in Block 43/27a. The Johnston Field's average net production
for the year 2000 was 53 MMscf/d. Gas is sold to TXU Europe Energy Trading
Limited. In 1999, as a result of a revision to the Unit Area, CalEnergy Gas
increased it working interest in the field from 18.264% to 22.113%. CalEnergy
Gas' share of production in 2000 was 16.0 MMscf/d.
Projects in Development
Pila Concession. Poland's energy market is currently undergoing major
adjustments as it moves from a centrally planned to an open, commercially driven
free market. During this process, CalEnergy Gas believes that there will be a
number of gas opportunities created. CalEnergy Gas' current interest in Poland
is centered on the Pila Concession, acquired by CalEnergy Gas (Polska) Sp z o.o
in 1998.
The Pila Concession, valid for a period of 30 years for the exploration and
exploitation of hydrocarbons, was effective from April 23, 1998 and is currently
in the exploration phase with a drilling program that commenced in September
2000. The original concession, covering an area of 12,639 km2 in the north west
of Poland, sits within the Permian Basin of north west Europe which stretches
from the UK sector of the Southern North Sea across the Netherlands and Germany
into Poland.
The prospects CalEnergy has identified to date has encouraged both POGC (10%)
and Petrobaltic (10%) to join CalEnergy Gas (80%) in the drilling phase of
exploration activity.
EP 389. The Perth Basin, situated onshore and offshore the south west corner of
Australia, contains a sequence of up to 15,000 meters of Permian to Cretaceous
sediments. To date, exploration in the Perth Basin has concentrated on the
onshore, with several hydrocarbon fields being discovered in the
central--northern portion of the basin.
Since August 1997, CalEnergy Gas (UK) Limited has had a 40.789% equity interest
in permit EP389. At the same time, CalEnergy Gas joined Empire in applications
for four other permits that were subsequently awarded, such that the joint
venture's portfolio of five permits now covers approximately 10,000 km2.
EP389 has recently entered a new five-year permit period following the
relinquishment of approximately 650 km2. The joint venture is planning to
commence exploratory drilling before the end of 2001.
Yolla. CalEnergy Gas owns interests in three licenses in the Bass Basin,
including a 20% interest in the Yolla gas field. Currently undeveloped, the
Yolla gas field is commercially viable and is planned to be developed in the
near future. Situated between Victoria and Tasmania in the Bass Straight, the
field is positioned to supply gas to Victoria, where a gas supply shortage is
predicted in the coming years. Preliminary engineering and design have been
completed, and commercial opportunities for Yolla are being reviewed.
The Yolla gas field contains recoverable reserves of approximately 400 Bcf and
30 million barrels of petroleum liquids in the main reservoir, with additional
reserves possible in other unexplored parts of the field.
Otway Basin. Just 40 km from the major gas markets of Victoria lies some
promising exploration acreage in the Offshore Otway Basin. CalEnergy Gas owns a
25% interest in the Vic/P43 license, acquired in 1999. In 2000, CalEnergy Gas
and their joint venture partners acquired 775 km2 of 3D seismic in this permit.
The two identified structures in Vic/P43 are thought to contain up to 1 Tcf of
gas.
CalEnergy Generation
The following tables set out certain information concerning various Company
independent power projects in operation and under construction.
- ---------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Project(1) Facility Net MW Fuel Location Commercial U.S. $ Power Political
Net MW Owned(2) Operation Payments Purchaser(3) Risk
Insurance
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Projects in Operation
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Salton Sea I 10 5 Geo California 1987 Yes Edison No
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Salton Sea II 20 10 Geo California 1990 Yes Edison No
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Salton Sea III 50 25 Geo California 1989 Yes Edison No
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Salton Sea IV 40 20 Geo California 1996 Yes Edison No
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Salton Sea V 49 25 Geo California 2000 Yes Market/Zinc No
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Vulcan 34 17 Geo California 1986 Yes Edison No
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Elmore 38 19 Geo California 1989 Yes Edison No
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Leathers 38 19 Geo California 1990 Yes Edison No
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Del Ranch 38 19 Geo California 1989 Yes Edison No
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
CE Turbo 10 5 Geo California 2000 Yes Market/Zinc No
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Saranac 240 90 Gas New York 1994 Yes NYSEG No
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Power Resources 200 100 Gas Texas 1988 Yes TUEC No
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Yuma 50 25 Gas Arizona 1994 Yes SDG&E No
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Roosevelt Hot Springs 23 17 Geo Utah 1984 Yes UP&L No
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Desert Peak 10 10 Geo Nevada 1985 Yes N/A No
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
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
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Total Projects in Operation 1,350 890
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Projects Under Construction
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Casecnan 150 105 Hydro Philippines 2001 Yes NIA GOP Yes
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Cordova 537 537 Gas Illinois 2001 Yes ElPaso/MEC No
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Total Projects Under
Construction 687 642
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
Total Power Generation
Projects 2,037 1,532
- ----------------------------- ---------- ---------- ----------- --------------- ------------- ----------- ------------- -----------
(1)The Company operates all such projects other than Desert Peak.
(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)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 Philippines
undertaking supports PNOC-EDC's and NIA's respective obligations. Southern
California Edison Company ("Edison"); San Diego Gas & Electric Company ("SDG&E);
Utah Power & Light Company ("UP&L"); Bonneville Power Administration ("BPA");
New York State Electric & Gas Corporation ("NYSEG"); Texas Utilities Electric
Company ("TUEC"); Zinc Recovery Project ("Zinc"); El Paso Energy Corporation
("El Paso") and MidAmerican Energy Company ("MEC").
Projects in Operation
CE Generation Geothermal Facilities
CE Generation LLC ("CE Generation"), a 50% owned subsidiary of the Company,
affiliates currently operate ten geothermal plants in the Imperial Valley in
California (the "Imperial Valley Projects"). Five of these Imperial Valley
Project plants (the "Partnership Projects") consist of the Vulcan, Hoch (Del
Ranch), Turbo, Elmore and Leathers projects (the "Vulcan Project," the "Hoch
(Del Ranch) Project," the "Turbo Project", the "Elmore Project" and the
"Leathers Project," respectively). The remaining five operating Imperial Valley
Project plants (the "Salton Sea Projects") consist of Salton Sea I, II, III, IV,
and V projects (the "Salton Sea I Project" the "Salton Sea II Project, the
"Salton Sea III Project", the "Salton Sea IV Project", and the "Salton Sea V
Project", respectively).
The 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
as-available capacity price is based on a payment schedule as approved by the
CPUC from time to time. 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 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), which 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 approximately
one-third of its net output to the Zinc Recovery Project. The remainder is being
sold through other market transactions.
The net output of the Turbo Project is being sold through market transactions
but may be sold to the Zinc Recovery Project when completed.
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. Based on public announcements, the Company
understands that Edison has not made payments to other qualifying facilities
("QFs") from which Edison purchases power and has not made scheduled payments of
debt service. Edison's senior unsecured debt obligations are currently rated
Caa2 (on watch for possible downgrade) by Moody's and by S&P.
The Company is aware that there have been public announcements that Edison,
other industry participants and governmental entities have taken actions in
response to Edison's financial condition. These actions include the following:
o The Federal Energy Regulatory Commission ("FERC") has issued an order
eliminating requirements that Edison and other California utilities
purchase power from the structured power market in California in order
to provide them with an opportunity to obtain power from alternative
sources at a lower cost.
o The State of California has enacted legislation to provide for the
California Department of Water Resources to purchase wholesale power
and sell it to retain customers, which will be funded by a surcharge on
retail rates. The California legislature is also considering other
legislation to improve the financial condition of the California
electric utilities.
o The California Public Utilities Commission ("CPUC") approved a decision
on March 27, 2001 to increase retail electricity rates by approximately
40%. In another decision that day, the CPUC ordered Edison to pay QFs
on a go forward basis within 15 days of the invoice and purportedly
modified the calculation of Short Run Avoided Cost.
o The State of California and Edison have announced a preliminary
agreement for the State to purchase Edison's transmission assets for
$2.7 billion and to allow Edison to issue bonds for a substantial
portion of its under collection or revenues.
The Company can give no assurance as to the likely result of any of the actions
described above or as to whether such actions will have a positive effect on the
financial condition of Edison or its willingness to make payments under the
Power Purchase Agreements.
Edison has failed to pay approximately $76 million due to CE Generation
affiliates under the Power Purchase Agreements for power delivered in November
and December 2000 and January 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 and March 2001. Edison has not notified
the Company as to when it can expect to receive these payments. This continued
non-payment by Edison could result in an untenable situation for the continued
operation of the Imperial Valley Projects unless additional funds are obtained
in the near future.
On February 21, 2001, the Imperial Valley 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 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' Motion for Summary Adjudication and a Declaratory Judgment
ordering that: 1) under the Power Purchase Agreements, the Imperial Valley
Projects have the right to temporarily suspend deliveries of capacity and energy
to Edison, 2) the Imperial Valley 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. The Imperial Valley Projects intend to vigorously
pursue its other remedies in this action in light of Edison's continuing
non-payment.
The Company is hopeful that the current Edison situation is temporary and the
proceedings in the legal, regulatory, financial and political arenas will lead
to the improvement of Edison's financial condition in the near future and the
payment by Edison of amounts due under the Power Purchase Agreements. However,
no assurance can be given that this will be the case.
As a result of Edison's failure to make the payments due under the Power
Purchase Agreements and the recent downgrades of Edison's credit ratings,
Moody's has downgraded the ratings for the Salton Sea Funding Corp. project
related debt to Caa2 (negative outlook) and S&P has downgraded the ratings for
the project related debt to BBB- and has placed the project related debt on
"credit watch negative". Accordingly, the Funding Corporation does not believe
it is currently able to obtain funds in the banking or capital markets. However,
a failure by Edison to make these payments as well as subsequent monthly
payments, for a substantial period of time after the payments are due, is not
expected to have a material adverse effect on the ability of the Company to make
payments on its debt obligations. However, there can be no assurance that such a
failure by Edison would not cause a material adverse effect.
CE Generation Gas Facilities
CE Generation affiliates currently operate the Saranac, Power Resources and Yuma
natural gas plants (the "Saranac Project", "Power Resources Project" and "Yuma
Project", respectively). The Saranac Project, Power Resources Project, and Yuma
Project are collectively referred to as the "Gas Plants".
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 contract
("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.
SDG&E, a wholly-owned subsidiary of Sempra Energy, is a public utility primarily
engaged in the business of supplying electric energy and natural gas service in
San Diego County and southern Orange County in California. The Company is aware
that there have been public announcements that SDG&E's financial condition has
deteriorated as a result of reduced liquidity. SDG&E has been current in its
payments to the Yuma Project for electricity generated. SDG&E's senior unsecured
debt obligations are currently rated Aa3 by Moody's and AA- by S&P.
The Company is hopeful that the current SDG&E situation is temporary and the
proceedings in the legal, regulatory, financial and political arenas will lead
to the improvement of SDG&E's financial condition in the near future. However,
no assurance can be given that this will be the case.
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 contract (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 ("Tomen") and General Electric
Capital Corporation ("GECC").
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 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.
Other U.S. Geothermal Interests
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.
Desert Peak. A subsidiary of the Company is the owner of a 10 net MW geothermal
plant at Sparks, Nevada. In 1998, the Company executed an agreement pursuant to
which the Desert Peak Project is leased to a third party power producer and the
Company receives rental payments.
The Philippines Power Generation
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 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 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 will be 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 (the
"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).
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.
The Malitbog ECA cooperation period will expire 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. All of PNOC-EDC's obligations under the
Malitbog ECA are supported by the Government of the Philippines through a
performance undertaking.
Projects in Construction
United States
Cordova. Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned
subsidiary of the Company, financed and commenced construction of a 537 MW gas
fired combined cycle merchant power plant to be located northeast of the Quad
Cities in Cordova, Illinois (the "Cordova Project"). The Cordova Project is
being constructed by Stone & Webster Engineering Corporation ("SWEC") pursuant
to a date certain, fixed price, turnkey engineering, procurement and
construction contract. Cordova is scheduled to commence commercial operation in
mid-2001.
Cordova Energy has entered into a power sales agreement with a unit of El Paso
Energy Corporation ("El Paso"). Under the power sales agreement, El Paso will
purchase all the capacity and energy from the project until December 31, 2019.
However, Cordova Energy has the option to elect on an annual basis to retain up
to 50% of the project capacity and energy for sales to others. Cordova Energy
has exercised this option for the full 50% for the first three years and has
entered into a power sales agreement to sell this capacity and energy to
MidAmerican Energy.
SWEC's parent, Stone & Webster, Incorporated, voluntarily filed Chapter 11
bankruptcy on September 2, 2000 and has sold substantially all of its assets to
Shaw Group, Inc. Shaw Group, Inc. has agreed to complete substantially all of
Stone & Webster's contracts for current and future projects including the
Cordova Project. The Company does not believe this situation will cause any
material adverse effect on the final completion of the Cordova Project or the
Company.
Zinc Recovery Project. The Company developed and owns the rights to a
proprietary process for the extraction of minerals from elements in solution in
the geothermal brine and fluids utilized at its Imperial Valley plants as well
as the production of power to be used in the extraction process. A pilot plant
has successfully produced commercial quality zinc at the Company's Imperial
Valley Project.
CalEnergy Minerals LLC ("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 will be
installed near Imperial Valley Project 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 mid-2001. In
September 1999, 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 is being constructed by Kvaerner U.S. Inc.
("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering,
procurement and construction contract (the "Zinc Recovery Project EPC
Contract"). Kvaerner is a wholly-owned indirect subsidiary of Kvaerner ASA, an
international engineering and construction firm experienced in the metals,
mining and processing industries. The payment obligations of Kvaerner, including
payment of liquidated damages of up to 20% of the contract price for certain
delays or failures to meet performance guarantees, are secured by a letter of
credit issued by Union Europeenne de CIC (or another financial institution rated
"A" or better by S&P or "A2" or better by Moody's and otherwise acceptable to
Minerals LLC) in an initial aggregate amount equal to $29.6 million.
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. The Company is also investigating producing silica from the solids
precipitated out of the geothermal power process. Silica is used as a filler for
such products as paint, plastics and high temperature cement.
Philippines
Casecnan. CE Casecnan Water and Energy Company, Inc., a Philippine corporation
("CE Casecnan") which is expected to be at least 70% indirectly owned by the
Company, was formed in September of 1994 solely to develop, construct, own and
operate the Casecnan Project, a multi-purpose irrigation and 150 net MW
hydroelectric power generation project (the "Casecnan Project") located on the
island of Luzon in the Republic of the Philippines. The Casecnan Project
consists generally of diversion structures in the Casecnan and Taan Rivers that
will capture and divert excess water in the Casecnan watershed by means of
concrete, in-stream diversion weirs and transfer that water through a transbasin
tunnel of approximately 23 kilometers (including the intake 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 will allow
electrical energy to be generated at a new 150 net MW rated capacity power
plant, which is being constructed in an underground powerhouse cavern located at
the end of the water tunnel. A tailrace discharge tunnel of approximately three
kilometers will deliver water from the water tunnel and the new powerhouse to
the Pantabangan Reservoir, providing additional water for irrigation and
increasing the potential electrical generation at two downstream existing
hydroelectric facilities of the Philippine National Power Corporation ("NPC"),
the government-owned and controlled corporation that is the primary supplier of
electricity in the Philippines.
CE Casecnan is constructing 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 will develop, finance and
construct the Casecnan Project over the construction period, and thereafter 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
70% 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
Philippines 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. The Project Agreement and
the Performance Undertaking provide for the resolution of disputes by binding
arbitration in Singapore under international arbitration rules.
NIA's payments of obligations under the Project Agreement are expected to be CE
Casecnan's sole source of operating revenues. Because of CE Casecnan's
dependence on NIA, any material failure of NIA to fulfill its obligations under
the Project Agreement and any material failure of the Republic of the
Philippines to fulfill its obligations under the Performance Undertaking would
significantly impair the ability of CE Casecnan to meet its existing and future
obligations.
CE Casecnan has entered into a fixed-price, date certain, turnkey engineering,
procurement and construction contract to complete the construction of the
Casecnan Project (the "Casecnan Construction Contract"). The work under the
Casecnan Construction 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 Casecnan Construction 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. In January 2001, CE Casecnan received a new working schedule
from the Contractor that showed a completion date of August 31, 2001.
Accordingly, the Casecnan Project is now expected to become operational by the
third quarter of 2001. The delay in completion is attributable in part to the
collapse in December 2000 of the Casecnan Project's partially completed vertical
surge shaft and the need to drill a replacement surge shaft.
The receipt of the working schedule does not change the Guaranteed Substantial
Completion Date under the Replacement Contract, and the Contractor is still
contractually obligated either to complete the Casecnan Project by March 31,
2001 or to pay delay liquidated damages. As a result of receipt of the working
schedule, however, CE Casecnan has sought and obtained from the lender's
independent engineer approval for a revised construction schedule under the
Casecnan Indenture. In connection with the revised schedule, the Company agreed
to make available up to $11.6 million of additional funds under certain
conditions pursuant to a Shareholder Support Letter dated February 8, 2001 (the
"Shareholder Support Letter") to cover additional costs resulting from the
Contractor's schedule delay.
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 force majeure events. In a March 20, 2001 Supplement to Request for
Arbitration, the Contractor also seeks compensation for alleged additional costs
it incurred from the claimed force majeure events to the extent it is unable to
recover from its insurer. CE Casecnan believes such allegations are without
merit and intends to vigorously defend the Contractor's claims.
The Republic of the Philippines ("RP") has recently experienced a period of
political unrest and governmental uncertainty relating to the impeachment of
former President Estrada which resulted in a change in the Presidency and
related changes to the RP cabinet and overall government administration.
Although the obligations of the NIA to make payments to CE Casecnan for water
and electricity fees under the Project Agreement with NIA and the obligations of
the RP under the related sovereign performance undertaking are in no way
dependent on maintaining any particular RP administration in place or on any
particular government's annual budgetary appropriations, it is possible that if
the recent Philippine governmental uncertainty would reoccur, it could have an
adverse impact on the Casecnan Project, which, as noted above, is scheduled to
commence commercial operation and commence receiving payments in 2001.
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, CE Casecnan 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. Although
the transmission line is complete, NIA has not yet installed the Casecnan
Project's metering equipment. Accordingly, no liquidated damages payments to NIA
have been made.
CE Casecnan'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 CE
Casecnan, including the Company, and no directors, officers or employees of the
Company will guarantee or be in any way liable for payment of CE Casecnan's
obligations. As a result, payment of CE Casecnan's obligations depends upon the
availability of sufficient revenues from CE Casecnan's business after the
payment of operating expenses.
HomeServices
The Company owns approximately 83% of HomeServices.Com, Inc. ("HomeServices"),
the second largest residential real estate brokerage firm in the United States
based on aggregate closed transaction sides in 1999 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 primarily
under the Edina Realty, Iowa Realty, J.C. Nichols Residential, CBSHOME, Paul
Semonin Realtors, Long Realty and Champion Realty brand names in the following
twelve states: Minnesota, Iowa, Arizona, Kansas, Missouri, Kentucky, Nebraska,
Wisconsin, Indiana, Maryland, North Dakota and South Dakota. HomeServices
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, 2000. HomeServices' major markets consist of the following metropolitan
areas: Minneapolis and St. Paul, Minnesota; Des Moines, Iowa; Omaha, Nebraska;
Kansas City, Kansas; Louisville, Kentucky; Springfield, Missouri; Tucson,
Arizona and Annapolis, Maryland.
The Global Energy Market
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. Set forth below is certain general information concerning
the present status of the energy markets in those countries in which the Company
currently has significant operations.
The United States
In the United States, the independent power industry expanded rapidly in the
1980s, facilitated by the enactment of the Public Utilities Regulatory Policies
Act ("PURPA"). PURPA was enacted to encourage the production of electricity by
non-utility companies (frequently referred to as independent power companies) as
well as to lessen reliance on imported fuels. According to the Utility Data
Institute, independent power producers were responsible for the installation of
approximately 30,000 MW of capacity, or 50%, of the United States electric
generation capacity that has been placed in service since 1988. However, as the
size of the United States independent power market increased, available domestic
power capacity and competition in the industry also significantly increased.
During the last few years, many states began to accelerate the movement toward
more competition in many aspects of the electric power market, including
generation, transmission, distribution and supply. Extensive federal and state
legislative and regulatory reviews are presently underway in an effort to
further such competition. In particular, the state of California, in which the
Company has several power production facilities, adopted a bill to restructure
California's electric industry by providing for a phased-in competitive power
generation industry, with an independent system operator, and for direct access
to generation for all power purchasers under certain circumstances. The bill
provided that existing qualifying facility power sales agreements will be
honored. Approximately one-half of the states have enacted electric choice
legislation and other states have or are expected to take similar steps aimed at
increasing competition by restructuring the electric industry, allowing retail
competition and deregulating most electric rates. In addition, recent federal
legislation has been proposed which would repeal PURPA and the Public Utility
Holding Company Act of 1935, as amended. However, the current energy crisis in
California has resulted in a slow down in deregulation of the electric utility
industry. The power exchange is no longer functioning and it is difficult to
predict the ramifications of the California energy crisis on the overall
deregulation of the electric utility industry.
Legislation to initiate retail electric competition was introduced in the Iowa
legislature in the 2000 session, but it did not pass. Deregulation of the gas
supply function related to small volume customers is also being considered by
the Iowa Utilities Board ("IUB"). MidAmerican Energy has actively participated
in the legislative and regulatory processes. MidAmerican Energy cannot predict
the timing or ultimate outcome of any potential electric restructuring
legislation or gas restructuring in Iowa.
The introduction of competition in the wholesale market has resulted in a
proliferation of power marketers and a substantial increase in market activity.
The wholesale market has also increased in volatility. As this market matures,
volatility may decline.
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.
The Company cannot predict the final form or timing of the proposed industry
restructuring or the impact on its operations. However, the Company believes
that the impending changes in the regulation of the United States power markets
will reflect many aspects of the United Kingdom model (discussed below) for
competitive generation, transmission, distribution and supply of energy. The
Company further expects that the current effort to introduce broader wholesale
and retail competition in the United States will result in a continuation and
acceleration of the recent trend toward consolidation among domestic utilities
and independent power producers and an increase in the trend toward
disaggregation (or unbundling) of vertically integrated utilities into separate
generation, transmission and distribution businesses.
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.
Under a 1997 pricing plan settlement agreement resulting from an IUB rate
proceeding, electric prices for MidAmerican Energy's Iowa industrial and
commercial customers were reduced through a retail access pilot project,
negotiated individual electric contracts and a tariffed rate reduction for some
non-contract commercial customers.
The negotiated electric contracts have differing terms and conditions as well as
prices. The vast majority of the contracts expire during the period 2003 through
2005, although some large customers have contracts extending to 2008. Some of
the contracts have price renegotiation and early termination provisions
exercisable by either party. Prices are set as fixed prices; however, many
contract allow for potential price adjustments with respect to environmental
costs, government imposed public purpose programs, tax changes, and transition
costs. While the contract prices are fixed (except for the potential adjustment
elements), the costs MidAmerican Energy incurs to fulfill these contracts will
vary. On an aggregate basis the annual revenues under contract are approximately
$180 million.
Under the 1997 pricing plan settlement agreement, if MidAmerican Energy's annual
Iowa electric jurisdictional return on common equity exceeds 12%, then earnings
above the 12% level will be shared equally between customers and MidAmerican
Energy. If the return exceeds 14%, then two-thirds of MidAmerican Energy's share
of those earnings above the 14% level will be used for accelerated recovery of
certain regulatory assets. During 2000, MidAmerican Energy credited $14.8
million to its Iowa non-contract customers related to the return calculation for
1999, which was approved by the IUB, subject to additional refund. In 2000,
MidAmerican Energy accrued $21.6 million for customer credits relating to 2000
operations. This Iowa electric retail revenue sharing plan remained in effect
through the year 2000. The rates established by the pricing plan settlement
agreement will remain in effect until either the plan is renegotiated or a
change in rates is approved by the IUB pursuant to a rate proceeding.
On March 14, 2001, the Office of Consumer Advocate of the Iowa Department of
Justice filed a petition with the IUB to reduce MidAmerican Energy's Iowa retail
electric rates by approximately $77 million annually. This filing will be
contested by MidAmerican Energy and, under Iowa law, the IUB must rule on the
petition within ten months from March 14, 2001. Iowa law provides that the rates
collected after the filing of the petition are subject to refund with interest
if they exceed rates finally approved by the IUB.
The pricing plan settlement agreement precluded MidAmerican Energy from filing
for increased rates prior to January 1, 2001, unless the return fell below 9%.
Other parties signing the agreement were prohibited from filing for reduced
rates prior to 2001 unless the return, after reflecting credits to customers,
exceeded 14%. The agreement also eliminated MidAmerican Energy's energy
adjustment clause, and, as a result, the cost of fuel is not directly passed on
to customers.
In connection with the March 1999 approval by the IUB of the MidAmerican Merger
and March 2000 affirmation as part of the Investor Group's acquisition of the
Company, 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, 2000 was above these levels.
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
5.50% for 1998 and 1999 and a premium of 8.5% for 2000 through 2004. The
two-year average above which sharing must occur for 2000 was 12.83%. Using the
same 30-year Treasury Bond average, the compute level of return would be 14.33%
for 2001 through 2004. 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, the Federal Energy Regulatory Commission 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 a schedule that would allow the regional
transmission organization to commence operating by December 15, 2001. On October
16, 2000, MidAmerican Energy filed with the Federal Energy Regulatory Commission
a plan for MidAmerican Energy to comply with Order No. 2000 by participating in
the formation of a for profit independent transmission company. MidAmerican
Energy continues in its effort to form such a company.
The 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 Public Electricity
Suppliers ("PESs") in their respective authorized areas. The majority of
customers are still supplied with electricity by their local PES, although there
are other suppliers holding second tier supply licenses, including generators
and other PESs, who can compete to supply customers throughout Great Britain.
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 is to be
replaced by two separate licenses - the Distribution license and the Supply
license. The Public Electricity Supplier ("PES") license currently held by
Northern Electric plc is to be split so that separate subsidiaries will own
licenses for distribution and energy supply. In order to comply with the
legislation the Company has submitted a draft Statutory Transfer Scheme
("Scheme") to The Secretary of State for Trade and Industry for consideration.
Once approved, the Scheme provides for the transfer of certain assets and
liabilities to the newly created subsidiaries. This will occur on a date to be
set by the Secretary of State for Trade and Industry, currently anticipated to
be in July 2001.
Distribution. Each of the PESs is required to offer terms for connection to its
distribution system to any person, and for use of its distribution system to any
authorized electricity operator. In providing the use of its distribution
system, a PES must not discriminate between its own supply business and that of
any other authorized electricity supplier, nor may its charges differ except
where justified by differences in cost. These obligations will transfer to
holders of Distribution licenses when the PES license is replaced.
Most revenue of the distribution business is controlled by a distribution price
control formula. The Retail Price Index ("RPI") used in this formula 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 inflation factor ("Xd") which was established by the regulator (and
continues to be set) at 3%. This formula determines the maximum average price
per unit of electricity distributed (in pence per kilowatt hour) which a PES is
entitled to charge. The distribution price control formula permits PESs 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 PES from year to year. It is a control on revenue
that operates independently of most of the PES'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
the regulator in 1999, Northern's allowable distribution revenue was reduced by
24% 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 the regulator 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, including in the
next several years in connection with the proposed Information and Incentives
Project under which it is proposed that two per cent of regulated income will
depend upon the performance of the PES's distribution system as measured by the
number and duration of customer interruptions and upon the level of customer
satisfaction monitored by the regulator.
Supply. Subject to minor exceptions, all electricity customers in the United
Kingdom must be supplied by a licensed supplier. Licensed suppliers purchase
electricity and make use of the transmission and distribution networks to
achieve delivery to customers' premises.
There are currently two types of licensed suppliers: PES (or "first tier")
suppliers and second tier suppliers. First tier suppliers are the successor
companies to the former state owned Area Electricity Boards acting as suppliers
within their respective geographical authorized areas. Second tier suppliers are
those suppliers which supply outside any area which is the subject of any PES
license which they may hold and include PESs supplying outside their authorized
area, generators and independent suppliers. Northern holds both first and second
tier licenses. This distinction between first and second tier suppliers is to be
abolished under the Utilities Act 2000. From a date to be set by the Secretary
of State for Trade and Industry there will be only one class of licensed
supplier. This is anticipated to be in July 2001.
The price of electricity supplied by a PES to most of its domestic customers
within its authorized area is controlled by a formula. As part of the scheduled
review of the formula carried out by the regulator in 1999, Northern was
required to reduce its prices to most of its domestic customers within its
authorized area by about 11% from April 1, 2000. The price cap is due to be
reviewed with effect from April 1, 2002.
The Pool. Virtually all electricity generated in England and Wales was sold by
generators and bought by suppliers through the Pool described below. A generator
that is a Pool member and also a licensed supplier must nevertheless sell all
the electricity it generates into the Pool, and purchase all the electricity
that it supplies from the Pool. Because Pool prices fluctuate, generators and
suppliers may enter into bilateral arrangements, such as contracts for
differences ("CFDs"), to provide a degree of protection against such
fluctuations.
The Pool was established at the time of privatization for bulk trading of
electricity in England and Wales between generators and suppliers. The Pool
reflects two principal characteristics of the physical generation and supply of
electricity from a particular generator to a particular supplier. First, it is
not possible to trace electricity from a particular generator to a particular
supplier. Second, it is not practicable to store electricity in significant
quantities, creating the need for a constant matching of supply and demand.
Subject to certain exceptions, all electricity generated in England and Wales
must be sold and purchased through the Pool. All licensed generators and
suppliers must become and remain signatories to the Pooling and Settlement
Agreement, which governs the constitution and operation of the Pool and the
calculation of payments due to and from generators and suppliers. The Pool also
provides centralized settlement of accounts and clearing. The Pool does not
itself supply electricity.
Prices for electricity have been set by the Pool daily for each one-half hour of
the following day based on the bids of the generators and a complex set of
calculations matching supply and demand and taking account of system stability,
security and other costs. A settlement system is used to calculate prices and to
process metered, operational and other data and to carry out the other
procedures necessary to calculate the payments due under the Pool trading
arrangements. The settlement system is administered on a day-to-day basis by
Energy Settlements and Information Services, Limited, a subsidiary of NGC, as
settlement system administrator.
In order to hedge against Pool price volatility, parties enter Contracts for
Differences ("CFDs"). Generally, CFDs are contracts between generators and
suppliers that have the effect of fixing the price of electricity for a
contracted quantity of electricity over a specific time period. Differences
between the actual price set by the Pool and the agreed prices give rise to
difference payments between the parties to the particular CFD. At any time,
Northern's forecast supply market demand is substantially hedged through various
types of agreements including CFDs.
Northern's supply business generally involves entering into fixed price
contracts to supply electricity to its customers. Northern obtains the
electricity to satisfy its obligations under such contracts primarily by
purchases from the Pool. Because the price of electricity purchased from the
Pool varies, Northern is exposed to risk arising from differences between the
fixed price at which it sells and the fluctuating prices at which it purchases
electricity, unless it can effectively hedge such exposure.
The United Kingdom government introduced legislation to reform the wholesale
trading market for electricity by eliminating the Pool and creating a bilateral
wholesale trading market. The elimination of the Pool and the introduction of
the New Electricity Trading Arrangements ("NETA") occurred on March 27, 2001.
Elimination of the Pool will create risks of a mismatch between the prices at
which Northern purchases electricity from wholesale suppliers and the price at
which it has, or will, contract to sell electricity to its customers. Northern's
ability to manage such risks at acceptable levels will depend, in part, on the
specifics of the supply contracts that Northern enters into, Northern's ability
to implement and manage an appropriate contracting and hedging strategy, and the
development of an adequate market for hedging instruments.
Under NETA, suppliers will need to buy physical electricity from generators
equal to the forecast demand of customers. NETA will create additional risks and
opportunities and in order to mitigate them, Northern is developing a new suite
of information technology systems in coordination with industry leading software
development companies.
Regulatory, Energy and Environmental Matters
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. In particular, the
independent power market in the United States is dependent on the existing
energy regulatory structure, including PURPA and its implementation by utility
commissions in the various states.
Each of the operating domestic power facilities partially owned through CE
Generation meets the requirements promulgated under 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 full Avoided Cost, (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.
Currently, 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 Costs. 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,
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.
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 65% 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.
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 certain 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.
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
Northern's businesses are subject to numerous regulatory requirements with
respect to the protection of the environment. The Electricity Act obligates the
UK Secretary of State or the Regulator 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 Northern 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. Northern mitigates the effects its proposals have on natural and
man-made features and administers an environmental assessment when it intends to
lay cables, construct overhead lines or carry out any other development in
connection with its licensed activities.
The Environmental Protection Act of 1990 addresses waste management issues and
imposes certain obligations and duties on companies which handle and dispose of
waste. Some of Northern's distribution activities produce waste, but Northern
believes that it is in compliance with the applicable standards in such regard.
Possible adverse health effects of electromagnetic fields ("EMFs") from various
sources, including transmission and distribution lines, have been the subject of
a number of studies and increasing public discussion. Current scientific
research is inconclusive as to whether EMFs may cause adverse health effects.
The only United Kingdom standards for exposure to power frequency EMFs are those
promulgated by the National Radiological Protection Board and relate to the
levels above which non-reversible physiological effects may be observed.
Northern fully complies with these standards. However, there is the possibility
that passage of legislation and change of regulatory standards would require
measures to mitigate EMFs, with resulting increases in capital and operating
costs. In addition, the potential exists for public liability with respect to
lawsuits brought by plaintiffs alleging damages caused by EMFs.
Northern believes that it has taken and continues to take measures to comply
with the applicable laws and governmental regulations for the protection of the
environment. There are no material legal or administrative proceedings pending
against Northern with respect to any environmental matter.
The UK government has recently introduced into Parliament legislation which, if
enacted, will facilitate certain aspects of the reform of the wholesale
electricity trading market described above, and reform UK utility law in
connection with the licensing regime for electricity and gas utilities,
electricity and gas regulatory institutions and procedures, and social, consumer
and environmental protection related to utilities.
Employees
As of December 31, 2000, the Company and its subsidiaries employed approximately
9,550 people.
As of December 31, 2000, the CalEnergy Generation platform employed
approximately 500 people, of which approximately 230 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, 2000, Northern employed approximately 3,560 people, of which
approximately 67% are represented by labor unions. All Northern 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. Northern believes that its relations with its employees are
good.
As of December 31, 2000, MidAmerican Energy employed approximately 3,720 people,
of which approximately one half are represented by labor unions. MidAmerican
Energy believes that its relations with its employees are good.
As of December 31, 2000, HomeServices employed approximately 1,670 individuals
and had approximately 6,600 sales associates, who are independent contractors
and not employees. None of HomeServices' employees or sales associates are
covered by a collective bargaining agreement. Management believes that
HomeServices' relations with its employees and sales associates are good.
Item 2. Properties
Property. Northern leases its principal executive offices in Newcastle upon
Tyne, England. Northern has both network and non-network land and buildings. At
December 31, 2000, Northern had freehold and leasehold interests in
approximately 8,500 network properties, comprising principally substation sites.
Northern owns, directly or indirectly, the freehold or leasehold interests of
such land and buildings. At December 31, 2000, Northern had freehold and
leasehold interests in approximately 63 non-network properties comprising
chiefly offices, retail outlets, depots, warehouses and workshops.
MidAmerican Energy's utility properties consist of physical assets necessary and
appropriate to render electric and gas service in its service territories.
Electric property consists primarily of generation, transmission and
distribution facilities. Gas property consists primarily of 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 MidAmerican Energy are in good operating condition and well
maintained.
The electric transmission system of MidAmerican Energy at December 31, 2000,
included 897 miles of 345-kV lines, and 1,110 miles of 161-kV lines. The gas
distribution facilities of MidAmerican Energy at December 31, 2000, included
20,259 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 80% of gross utility plant, is pledged to
secure mortgage bonds.
The Company's most significant physical properties, other than those owned by
Northern and MidAmerican Energy, are its current interest in operating power
facilities, its plants under construction and related real property interests.
The Company also maintains an inventory of approximately 150,000 acres of
geothermal property leases. The Company leases its principal executive offices
and its offices in Manila.
HomeServices' principal offices are located in Edina, Minnesota, where
HomeServices leases approximately 46,000 square feet of office space. This lease
expires in 2003. In addition, HomeServices has a total of 160 branch offices,
substantially all of which are leased. HomeServices' office leases generally
have initial terms ranging from three to ten years, with an option to extend the
lease for additional periods. The leases are typically net leases, which means
that HomeServices is required to pay property taxes, utilities and maintenance.
HomeServices believes that its present facilities are adequate for its current
level of operations.
Item 3. Legal Proceedings
The Company and its subsidiaries have no material legal proceedings except for
the following:
Southern California Edison
The Imperial Valley Projects have filed a lawsuit seeking a court order
requiring Edison to make the required payments under the Power Purchase
Agreements. See page 16.
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
that 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 contingent counterclaims. The contingent
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 NPPD has the duty to repay all amounts that MidAmerican Energy
has prefunded for decommissioning in the event the NPPD operates the
plant after the term of the power purchase agreement;
(3) that the NPPD is equitably estopped from continuing to operate the
plant after the term of the power purchase agreement;
(4) that the NPPD has granted MidAmerican Energy an option to continue
taking 50% of the power from the plant;
(5) that the term "monthly power costs" as defined in the power purchase
agreement does not include costs and expenses associated with
decommissioning the plant;
(6) 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;
(7) that transition costs are not included in any decommissioning costs and
expenses;
(8) that the NPPD has breached its duty to MidAmerican Energy in making
investments of decommissioning funds;
(9) that reserves in named accounts are excessive and should be refunded to
MidAmerican Energy; and
(10) that the NPPD must credit MidAmerican Energy for payments by
MidAmerican Energy for low-level radioactive waste disposal.
On October 6, 1999, the court rendered summary judgment for the 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, two, three and five 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 issues one and five in the second paragraph above.
Additionally, it remanded the case for trial on all other claims and
counterclaims. It is not likely that a trial will occur prior to late spring or
early summer of 2001.
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 the members
of the Investor Group 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.
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 and Significant
Subsidiaries
The Company's management structure is organized functionally and the current
executive and other officers of the Company and their positions are as follows:
Name Position
David L. Sokol Chairman of the Board & Chief Executive Officer
Gregory E. Abel President & Chief Operating Officer
Patrick J. Goodman Senior Vice President & Chief Financial Officer
Steven A. McArthur Senior Vice President, General Counsel & Secretary
Keith D. Hartje Senior Vice President & Chief Administrative Officer
Ronald W. Stepien President, MidAmerican Energy
P. Eric Connor President & Chief Operating Officer, Northern
Set forth below is certain information with respect to each of the foregoing
officers:
DAVID L. SOKOL, 44, 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, 38, President and Chief Operating Officer. Mr. Abel joined the
Company in 1992 and initially served as Vice President and Controller. Mr. Abel
is a Chartered Accountant and from 984 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, 34, Senior Vice President and Chief Financial Officer. Mr.
Goodman joined the Company in 1 995, 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.
STEVEN A. McARTHUR, 43, Senior Vice President, General Counsel and Secretary.
Mr. McArthur joined the Company in February 1991 and has served in various
executive capacities. From 1988 to 1991 he was an attorney in the Corporate
Finance Group at Shearman & Sterling in San Francisco. From 1984 to 1988 he was
an attorney in the Corporate Finance Group at Winthrop, Stimson, Putnam &
Roberts in New York.
KEITH D. HARTJE, 51, 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.
RONALD W. STEPIEN, 54, President, MidAmerican Energy. Mr. Stepien served as
Executive Vice President from November 1, 1996 to October 31, 1998 and Group
Vice President from 1995 to November 1, 1996. Prior to that Mr. Stepien served
as Vice President of Iowa-Illinois Gas and Electric Company, a predecessor
company, from 1990 to 1995.
P. ERIC CONNOR, 52, President and Chief Operating Officer, Northern Electric.
Mr. Connor joined Northern in 1992 as a Director. Prior to joining Northern, he
was a Director at NEI Reyrolle Ltd. and prior to that, his appointments
included: deputy group head of engineering, National Nuclear Corporation;
manager computer systems, NEI Electronics (C&I Systems); systems engineer, Davy-
Leowy; software engineer, Marconi Space & Defense.
Item 11. Executive Compensation
To be filed by amendment.
Item 12. Security Ownership of Certain Beneficial Owners and Management
To be filed by amendment.
Item 13. Certain Relationships and Related Transactions
To be filed by amendment.
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................................38
Management's Discussion and Analysis of Financial Condition
And Results of Operations......................................39
Qualitative and Quantitative Disclosures About Market Risk..........53
Consolidated Balance Sheets as of December 31, 2000 and 1999........57
Consolidated Statements of Operations
For the Three Years Ended December 31, 2000, 1999 and 1998.....58
Consolidated Statements of Stockholders' Equity
For the Three Years Ended December 31, 2000, 1999 and 1998.....59
Consolidated Statements of Cash Flows
For the Three Years Ended December 31, 2000, 1999 and 1998.....60
Notes to Consolidated Financial Statements..........................61
Independent Auditor's Report........................................96
2. Financial Statement Schedules
Page No.
Schedule I, Financial Statements of the Company
(Parent Company only)..........................................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 thousands)
MEHC (Predecessor)
---------------------------------------------------------------------
March 14, 2000 January 1, 2000
through through Year Ended December 31,
-----------------------------------------------------
December 31,2000(1) March 13, 2000 1999 (2) 1998 (3) 1997 1996 (4)
------------------- -------------- ------------ ----------- --------- ----------
Income Statement Data:
Operating revenue $3,945,716 $1,043,072 $4,128,737 $2,555,206 $2,166,338 $518,934
Total revenues 4,040,598 1,062,556 4,410,616 2,682,711 2,270,911 576,195
Total costs and expenses 3,821,394 971,386 4,053,547 2,410,658 2,074,051 435,791
Income before provision for
income taxes 219,204 91,170 357,069 272,053 196,860(6) 140,404
Minority interest 84,670 8,850 46,923 41,276 45,993 6,122
Income before change in
accounting principle
and extraordinary item 81,257 51,312 216,671(5) 137,512 51,823(6) 92,461
Extraordinary item, net of tax - - (49,441) (7,146) (135,850) -
Cumulative effect of change
in accounting principle,
net of tax - - - (3,363) - -
Net income (loss) 81,257 51,312 167,230(5) 127,003 (84,027)(6) 92,461
Balance Sheet Data:
Total assets $11,680,651 N/A $10,766,352 $9,103,524 $7,487,626 $5,630,156
Total liabilities 8,981,061 N/A 8,978,924 7,598,040 5,282,162 4,181,052
Company-obligated mandatory
redeemable preferred securities
of subsidiary trusts 786,523 N/A 450,000 553,930 553,930 103,930
Subsidiary-obligated mandatorily
redeemable preferred securities
of subsidiary trusts 100,000 N/A 101,598 - - -
Preferred securities of subsidiaries 145,686 N/A 146,606 66,033 56,181 136,065
Total stockholders' equity 1,576,401 N/A 994,588 827,053 765,326 880,790
(1) Reflects the Teton Transaction on March 14, 2000.
(2) Reflects the MidAmerican Merger on March 12, 1999, the disposition of
Coso Joint Ventures on February 26, 1999 and the disposition of 50%
ownership interest in CE Generation on March 3, 1999.
(3) Reflects the acquisition of KDG on January 2, 1998.
(4) Reflects the acquisitions of Northern, Falcon Seaboard and the
Partnership Interest owned for a portion of the year.
(5) Includes $81.5 million for non-recurring Indonesia gain on settlement,
gains on sales of McLeod and qualified facilities, Northern
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 Teton Transaction, the MidAmerican Merger and the sales of
Coso and an interest in CE Generation, the Company's future results will differ
significantly from the Company's historical results.
Teton Transaction
On October 24, 1999, the Company and entities representing an investor group
comprised of Berkshire Hathaway Inc. ("Berkshire Hathaway"), Walter Scott, Jr.,
a director of the Company, and David L. Sokol, Chairman and Chief Executive
Officer of the Company, 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. The 11% trust preferred securities have
a liquidation preference of $25 each and are subject to mandatory redemption in
ten equal semi-annual installments commencing December 15, 2005. 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.
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 four separate platforms: MidAmerican, Northern, CalEnergy
Generation and HomeServices.
MidAmerican
MidAmerican Energy ("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, 2000,
MidAmerican Energy had 669,000 retail electric customers and 647,000 retail
natural gas customers.
In addition to retail sales, MidAmerican Energy delivers electric energy to
other utilities, marketers and municipalities who 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.
Most of MidAmerican Energy's business is conducted in a rate-regulated
environment and accordingly, many of its decisions as to the source and use of
resources and other strategic matters are evaluated from a utility 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.
Northern
The operations of Northern Electric plc ("Northern"), an indirect wholly owned
subsidiary of the Company, consist primarily of the distribution and supply of
electricity, supply of natural gas and other auxiliary businesses in the United
Kingdom. Northern's operations are seasonal in nature with a disproportionate
percentage of revenues and earnings historically being earned in the Company's
first and fourth quarters.
Northern receives electricity from the national grid transmission system and
distributes it to customers' premises using its network of transformers,
switchgear and cables. Substantially all of the customers in Northern's
authorized area are connected to Northern's network and can only be delivered
electricity through Northern's distribution system, regardless of whether it is
supplied by Northern's own supply business or by other suppliers, thus providing
Northern with distribution volume that is stable from year to year. Northern
charges 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 primarily involves the bulk purchase of electricity,
through a central pool, and subsequent resale to individual customers. The
supply business generally is a high volume business that tends to operate at
lower profitability levels than the distribution business. As of December 31,
2000, Northern supplied electricity to approximately 1.1 million customers.
Northern also competes to supply gas inside and outside its authorized area. As
of December 31, 2000, Northern supplies gas to approximately 470,000 customers
in the residential market.
CalEnergy Generation
The Company indirectly owns the Upper Mahiao, Malitbog and Mahanagdong Projects
(collectively, the "Philippine Projects"), which are geothermal power plants
located on the island of Leyte in the Philippines. For purposes of consistent
presentation, capacity amounts for Upper Mahiao, Malitbog and Mahanagdong
(collectively, the "Philippine Projects") are 119, 216 and 165 net MW,
respectively. Each plant possesses an operating margin which 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.
On February 8, 1999, the Company created a new subsidiary, CE Generation LLC
("CE Generation") and subsequently transferred its interest in the Imperial
Valley Projects and Gas Plants to CE Generation. 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").
Turbo became operational in the third quarter of 2000. Salton Sea V became
operational in the second quarter of 2000. 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 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.
Prior to that date, CE Generation results were fully consolidated.
On February 26, 1999, the Company closed the sale of all of its ownership
interests in the Navy I, Navy II and BLM, collectively the Coso Joint Ventures,
to Caithness Energy, LLC for $205 million in cash.
HomeServices
The Company owns approximately 83% of HomeServices.Com, Inc. ("HomeServices"),
the second largest residential real estate brokerage firm in the United States
based on aggregate closed transaction sides in 1999 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 primarily
under the Edina Realty, Iowa Realty, J.C. Nichols Residential, CBSHOME, Paul
Semonin Realtors, Long Realty and Champion Realty brand names in the following
twelve states: Minnesota, Iowa, Arizona, Kansas, Missouri, Kentucky, Nebraska,
Wisconsin, Indiana, Maryland, North Dakota and South Dakota. HomeServices
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, 1999. HomeServices' major markets consist of the following metropolitan
areas: Minneapolis and St. Paul, Minnesota; Des Moines, Iowa; Omaha, Nebraska;
Kansas City, Kansas; Louisville, Kentucky; Springfield, Missouri; Tucson,
Arizona and Annapolis, Maryland.
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
Merger 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 $4,988.8
million compared with $4,517.0 million for the same period in 1999, an increase
of 10.4%. MidAmerican operating revenue increased for the year ended December
31, 2000 to $2,330.7 million from $1,816.1 million for the same period in 1999,
primarily due to increases in nonregulated gas sales and higher rates in
regulated gas. Northern Electric 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 sub-
sidiaries 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 $2,783.5
million compared with $2,342.8 million for the same period in 1999, an increase
of 18.8%. 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 Northern 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.
Results of Operations For The Years Ended December 31, 1999 and 1998
Operating revenue increased in the year ended December 31, 1999 to $4,128.7
million from $2,555.2 million for the same period in 1998, a 61.6% increase.
Northern's operating revenue increased in the year ended December 31, 1999 to
$2,072.2 million from $1,823.9 million for the same period in 1998, primarily
due to higher volumes of gas supplied as well as higher electricity supply
revenues. The MidAmerican Merger added $1,687.9 million in the period from March
12, 1999 through December 31, 1999. These increases were partially offset by the
sales of Coso and reporting the 50% interest in CE Generation using the equity
method beginning March 3, 1999.
The following data represents sales from utility operations for MidAmerican
Energy. The financial results of MidAmerican Energy are consolidated with the
Company beginning on March 12, 1999.
Year Ended December 31,
1999 1998
------------ -----------
Electricity Retail Sales (GWh)............... 16,007 16,088
Electricity Sales for Resale (GWh)........... 7,168 6,186
Regulated and Nonregulated Gas
Supplied (Thousands of MMBtus)............... 138,387 139,563
The following data represents the supply and distribution operations in the
U.K.:
Year Ended December 31,
1999 1998
------------- -----------
Electricity Supplied (GWh)..................... 17,984 15,313
Electricity Distributed (GWh).................. 15,943 15,904
Gas Supplied (Thousands of MMBtus)............. 48,435 35,950
The increases in electricity supplied for the year ended December 31, 1999 from
the same period in 1998 are due primarily to the increase in supply volumes for
customers outside of the franchise area. The increases in electricity
distributed for the year ended December 31, 1999 from the same period in 1998
are due to changes in demand in the franchise area. The increases in gas
supplied in 1999 from 1998 reflects the increased volume as the domestic gas
supply business in the U.K. opened up to competition as a result of regulatory
changes and the successful dual fuel marketing campaign.
Interest and other income increased for the year ended December 31, 1999 to
$143.2 million from $127.5 million in the same period in 1998. The increase was
due to the MidAmerican Merger and the addition of equity income from CE
Generation partially offset by the reduction of operator fees related to the
CalEnergy Generation facilities that were sold in 1999.
The gains on non-recurring items of $138.7 million in 1999 represent the pre-tax
gain on the sale of the qualified facilities of $20.2 million, the pre-tax gain
on the sale of McLeod common stock of $78.2 million and the pre-tax gain on the
Indonesia settlement of $40.3 million.
Cost of sales increased in the year ended December 31, 1999 to $2,143.9 million
from $1,258.5 million from the same period in 1998, a 70.4% increase. The
increase is primarily due to the MidAmerican Merger and higher volumes of gas
and electricity supplied at Northern. The MidAmerican Merger added $655.2
million in the period March 12, 1999 through December 31, 1999.
Operating expense increased in the year to date ended December 31, 1999 to
$1,001.4 million from $471.4 million for the same period in 1998, a 112.4%
increase. The MidAmerican Merger added $609.1 million in the period from March
12, 1999 through December 31, 1999, partially offset by the sales of Coso and an
interest in CE Generation.
Depreciation and amortization increased in the year to date December 31, 1999 to
$427.7 million from $333.4 million in the same period in 1998, a 28.3% increase.
The MidAmerican Merger added $187.3 million in the period from March 12, 1999
through December 31, 1999, partially offset by the sales of Coso and the 50%
interest in CE Generation.
Interest expense, less amounts capitalized, increased in the year to date
December 31, 1999 to $426.2 million from $347.3 million, a 22.7% increase. The
increase is primarily due to the MidAmerican Merger and the greater average
outstanding debt balances.
The losses on non-recurring items of $54.4 million in 1999 represent the pre-tax
loss of $47.7 million related to the costs associated with the reduction of
Northern's workforce and the $6.7 million of costs related to the Teton
Transaction.
The provision for income taxes increased marginally to $93.5 million in 1999
from $93.3 million in 1998. After adjusting for the non-recurring gains and
losses and the deductible dividends on preferred securities, the effective tax
rate was 38.7% and 39.5% in 1999 and 1998 respectively.
Minority interest consists of dividends on preferred securities of subsidiaries
and minority ownership of HomeServices. Minority interest increased in the year
ended December 31, 1999 to $46.9 million from $41.3 million in the same period
in 1998, a 13.6% increase. The increase is primarily due to the MidAmerican
Merger that has minority interests in the form of preferred stock outstanding.
Due to the early retirements of the Senior Discount Notes, the Limited Recourse
Notes and the 9.5% Senior Notes, the Company recorded extraordinary losses of
approximately $49.4 million, net of tax, in the year ended December 31, 1999.
During 1998, the Company recognized an extraordinary loss of $7.1 million, net
of tax, related to the redemption of the Senior Discount Notes. The Company also
recognized the cumulative effect of a change in accounting principle of $3.4
million, net of tax, by adopting Statement of Position 98-5, "Reporting on the
Costs of Start-Up Activities."
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's unrestricted cash and cash equivalents were $38.2 million at
December 31, 2000 as compared to $316.3 million at December 31, 1999. The
majority of this decrease was due to the cash used to partially fund the Teton
Transaction. In addition, the Company recorded separately restricted cash and
investments of $90.9 million and $291.7 million at December 31, 2000 and 1999,
respectively. The restricted cash balance as of December 31, 2000 is comprised
primarily of amounts deposited in restricted accounts from which the Company
will fund the various projects under construction, and the Philippine Projects'
cash reserves for the service of debt obligations.
Teton Transaction
On October 24, 1999, the Company and entities representing an investor group
comprised of Berkshire Hathaway Inc., Walter Scott, Jr., a director of the
Company and David L. Sokol, Chairman and Chief Executive Officer of the Company,
executed a definitive agreement and plan of merger whereby the investor group
would acquire all of the outstanding common stock of the Company for $35.05 per
share in cash, representing a total purchase price of approximately $2.2
billion, including transaction costs. The Teton Transaction closed on March 14,
2000 and Berkshire Hathaway invested approximately $1.24 billion in common stock
and non-dividend paying convertible preferred stock and approximately $455
million in 11% nontransferable trust preferred securities due March 14, 2010.
The 11% trust preferred securities have a liquidation preference of $25 each and
are subject to mandatory redemption in ten equal semi-annual installments
commencing December 15, 2005. 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.
Financing Activities
On June 30, 2000, the Company redeemed the remaining $4.2 million of Limited
Recourse Notes at a redemption price of 104.9375% plus accrued interest.
Throughout 2000, CalEnergy Capital Trust II, a subsidiary of the Company,
redeemed approximately 477,000 shares of preferred securities at an aggregate
cost of approximately $19.5 million. Prior to the Teton Transaction, each
preferred security was convertible at anytime into shares of the Company's
common stock based on a stated conversion rate. As a result of the Teton
Transaction, in lieu of shares of the Company's common stock, holders of these
preferred securities received $35.05 for each share of common stock they would
have been entitled to receive on conversion.
Construction
Minerals Extraction
The Company developed and 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 (the "Salton Sea Extraction
Project") as well as the production of power to be used in the extraction
process. A pilot plant has successfully produced commercial quality zinc at the
Company's Imperial Valley Projects. The Company intends to sequentially develop
facilities for the extraction of manganese, silver, gold, lead, boron, lithium
and other products as it further develops the extraction technology. The Company
is also investigating producing silica as an extraction project. Silica is used
as a filler for such products as paint, plastics and high temperature cement.
CalEnergy Minerals LLC, an indirect wholly owned subsidiary of the Company, is
constructing the Zinc Recovery Project that will recover zinc from the
geothermal brine (the "Zinc Recovery Project"). Facilities will be 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 mid-2001. 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 is being constructed by Kvaerner U.S. Inc.
("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering,
procurement and construction contract (the "Zinc Recovery Project EPC
Contract"). Kvaerner is a wholly owned indirect subsidiary of Kvaerner ASA, an
international engineering and construction firm experienced in the metals,
mining and processing industries. Total project costs, including financing
costs, of the Zinc Recovery Project are expected to be approximately $200.9
million. The Company has incurred approximately $165.6 million of such costs
through December 31, 2000.
Casecnan
CE Casecnan Water and Energy Company, Inc., a Philippine corporation ("CE
Casecnan") which at completion of the Casecnan Project is expected to be at
least 70% indirectly owned by the Company, is constructing the Casecnan Project,
a combined irrigation and 150 net MW hydroelectric power generation project (the
"Casecnan Project") located in the central part of the island of Luzon in the
Republic of the Philippines.
CE Casecnan has entered into a fixed-price, date certain, turnkey engineering,
procurement and construction contract to complete the construction of the
Casecnan Project (the "Casecnan Construction Contract"). The work under the
Casecnan Construction Contract is being conducted by a consortium consisting of
Cooperative 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 Casecnan Construction 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. In January 2001, CE Casecnan received a new working schedule
from the Contractor that showed a completion date of August 31, 2001.
Accordingly, the Casecnan Project is now expected to become operational by the
third quarter of 2001. The delay in completion is attributable in part to the
collapse in December 2000 of the Casecnan Project's partially completed vertical
surge shaft and the need to drill a replacement surge shaft.
The receipt of the working schedule does not change the Guaranteed Substantial
Completion Date under the Replacement Contract, and the Contractor is still
contractually obligated either to complete the Casecnan Project by March 31,
2001 or to pay delay liquidated damages. As a result of receipt of the working
schedule, however, CE Casecnan has sought and obtained from the lender's
independent engineer approval for a revised construction schedule under the
Casecnan Indenture. In connection with the revised schedule, the Company agreed
to make available up to $11.6 million of additional funds under certain
conditions pursuant to a Shareholder Support Letter dated February 8, 2001 (the
"Shareholder Support Letter") to cover additional costs resulting from the
Contractor's schedule delay.
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 force majeure events. In a March 20, 2001 Supplement to Request for
Arbitration, the Contractor also seeks compensation for alleged additional costs
it incurred from the claimed force majeure events to the extent it is unable to
recover from its insurer. CE Casecnan believes such allegations are without
merit and intends to vigorously defend the Contractor's claims.
The Republic of the Philippines ("RP") has recently been experiencing a period
of political unrest and governmental uncertainty relating to the impeachment of
President Estrada which resulted in a change in the Presidency and related
changes to the RP cabinet and overall government administration.
Although the obligations of the National Irrigation Administration ("NIA") to
make payments to CE Casecnan for water and electricity fees under the Project
Agreement with NIA and the obligations of the RP under the related sovereign
Performance Undertaking are in no way dependent on maintaining any particular RP
administration in place or on any particular government's annual budgetary
appropriations, it is possible that if the recent Philippine governmental
uncertainty would reoccur, it could have an adverse impact on the Casecnan
Project, which, as noted above, is scheduled to commence commercial operation
and commerce receiving payments in 2001.
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, CE Casecnan 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. Although
the transmission line is complete, NIA has not yet installed the Casecnan
Project's metering equipment. Accordingly, no liquidated damages payments to NIA
have been made.
CE Casecnan'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 CE
Casecnan, including the Company, and no directors, officers or employees of the
Company will guarantee or be in any way liable for payment of CE Casecnan's
obligations. As a result, payment of CE Casecnan's obligations depends upon the
availability of sufficient revenues from CE Casecnan's business after the
payment of operating expenses.
NIA's payments of obligations under the Project Agreement are expected to be CE
Casecnan's sole source of operating revenues. Because of CE Casecnan's
dependence on NIA, any material failure of NIA to fulfill its obligations under
the Project Agreement and any material failure of the RP to fulfill its
obligations under the Performance Undertaking would significantly impair the
ability of CE Casecnan to meet its existing and future obligations.
Cordova
Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned
subsidiary of the Company, has commenced construction of a 537 MW gas-fired
power plant in the Quad Cities, Illinois area (the "Cordova Project"). Cordova
Energy has entered into an engineering, procurement and construction ("EPC")
contract with Stone & Webster Engineering Corporation ("SWEC") to build the
project. Total project costs are estimated to be approximately $288.9 million.
The construction of the Cordova Project is expected to be completed in mid-2001.
Cordova Energy has entered into a power sales agreement with a unit of El Paso
Energy Corporation ("El Paso"). Under the power sales agreement, El Paso will
purchase all the capacity and energy from the project until December 31, 2019.
However, Cordova Energy has the option to elect on an annual basis to retain up
to 50% of the project capacity and energy for sales to others. Cordova Energy
has exercised this option for the full 50% for the first 3 years and has entered
into a power sales agreement to sell this capacity and energy to MidAmerican
Energy.
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. As part of the
financing, approximately $93.5 million of 8.64% Series A-1 Senior Secured Bonds
due in 2019 were issued. An additional $31.3 million of 8.79% Series A-2 Senior
Secured Bonds were issued on December 15, 1999, $29.3 million of 9.07% Series
A-3 Senior Secured Bonds were issued on March 15, 2000, $58.1 million of 8.82%
Series A-4 Senior Secured Bonds were issued on June 15, 2000 and $12.8 million
of 8.48% Series A-5 Senior Secured Bonds were issued September 15, 2000. Cordova
Funding has loaned the proceeds to Cordova Energy. The Company has incurred
$224.5 million of construction costs through December 31, 2000. Total equity
funding is expected to be approximately $63.9 million.
SWEC's parent, Stone & Webster, Incorporated, voluntarily filed Chapter 11
bankruptcy on September 2, 2000 and has sold substantially all of its assets to
Shaw Group, Inc. Shaw Group, Inc. has agreed to complete substantially all of
Stone & Webster's contracts for current and future projects including the
Cordova Project. The Company does not believe this situation will cause any
material adverse effect on the final completion of the Cordova Project or on the
Company.
Accounting Effects of Industry Restructuring
A possible consequence of competition in the utility industry is that SFAS 71
may no longer apply. SFAS 71 sets forth accounting principles for operations
that are regulated and meet certain criteria. For operations that meet the
criteria, SFAS 71 allows, among other things, the deferral of costs that would
otherwise be expensed when incurred. With exception of the generation operations
serving the Illinois jurisdiction, MidAmerican Energy's electric and gas utility
operations currently meet the criteria required by SFAS 71, but its
applicability is periodically reexamined. If other portions of MidAmerican
Energy's utility operations no longer meet the criteria of SFAS 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 resulting legislation. As of December 31, 2000, the Company
had $240.9 million of regulatory assets on its consolidated balance sheet.
Domestic Rate Matters: Electric
Under a 1997 pricing plan settlement agreement resulting from an IUB rate
proceeding, electric prices for MidAmerican Energy's Iowa industrial and
commercial customers were reduced through a retail access pilot project,
negotiated individual electric contracts and a tariffed rate reduction for some
non-contract commercial customers.
The negotiated electric contracts have differing terms and conditions as well as
prices. The vast majority of the contracts expire during the period 2003 through
2005, although some large customers have contracts extending to 2008. Some of
the contracts have price renegotiations and early termination provisions
exercisable by either party. Prices are set as fixed prices; however, many
contracts allow for potential price adjustments with respect to environmental
costs, government imposed public purpose programs, tax changes, and transition
costs. While the contract prices are fixed (except for the potential adjustment
elements), the costs MidAmerican Energy incurs to fulfill these contracts will
vary. On an aggregate basis the annual revenues under contract are approximately
$180 million.
Under a 1997 pricing plan settlement agreement, if MidAmerican Energy's annual
Iowa electric jurisdictional return on common equity exceeds 12%, then earnings
above the 12% level will be shared equally between customers and MidAmerican
Energy. If the return exceeds 14%, then two-thirds of MidAmerican Energy's share
of those earnings above the 14% level will be used for accelerated recovery of
certain regulatory assets. During 2000, MidAmerican Energy credited $14.8
million to its Iowa non-contract customers related to the return calculation for
1999 which was approved by the IUB, subject to additional refund. In 2000,
MidAmerican Energy accrued $21.6 million for customer credits relating to 2000
operations. This Iowa electric retail revenue sharing plan remained in effect
through the year 2000. The rates established by the pricing plan settlement
agreement will remain in effect until either the plan is renegotiated or a
change in rates is approved by the IUB pursuant to a rate proceeding.
On March 14, 2001, the Office of Consumer Advocate of the Iowa Department of
Justice filed a petition with the IUB to reduce MidAmerican Energy's Iowa retail
electric rates by approximately $77 million annually. This filing will be
contested by MidAmerican Energy and, under Iowa law, the IUB must rule on the
petition within ten months from March 14, 2001. Iowa law provides that the rates
collected after the filing of the petition are subject to refund with interest
if they exceed rates finally approved by the IUB.
The pricing plan settlement agreement precluded MidAmerican Energy from filing
for increased rates prior to January 1, 2001, unless the return fell below 9%.
Other parties signing the agreement were prohibited from filing for reduced
rates prior to 2001 unless the return, after reflecting credits to customers,
exceeded 14%. The agreement also eliminated MidAmerican Energy's energy
adjustment clause, and, as a result, the cost of fuel is not directly passed on
to customers.
UK Rate Matters:
Distribution
Northern charges access fees for the use of the distribution system. Most
revenue of the distribution business 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 RPI reflects the
average of the twelve months' inflation rates recorded for the previous July to
December period and Xd is 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. The
formula determines the maximum average price per unit of electricity distributed
(in pence per kilowatt hour) which a PES is entitled to charge. The price
control does not seek to constrain the profits of a PES from year to year. It is
a control on revenue that operates independently of the PES's costs. During the
lifetime of the price control, additional cost savings therefore contribute
directly to profit.
The previous distribution price control period expired on March 31, 2000.
Changes to the formula took effect from April 1, 2000 resulting in a one-off
reduction in allowed income per unit distributed of around 24%. As part of the
review, the Xd factor remains at 3%. The distribution prices allowable under the
current distribution price control formula are expected to be reviewed by the
Office of Gas and Electricity Markets ("Ofgem") at the expiration of the
formula's scheduled five-year duration in 2005. The formula may be reviewed at
other times at the discretion of Ofgem, including in connection with the
proposed Information and Incentive Project (IIP) under which it is proposed that
2% of regulated income will depend upon the performance of the PES's
distribution system as measured by the number and duration of customer
interruptions and upon the level of customer satisfaction monitored by the
regulator.
Supply
In December 1999, Ofgem announced revised electric supply price controls. Since
April 2000, these have been applied to most domestic and small commercial
customers in the below 100kW market of Northern's designated area, and result in
a further lowering of price caps. The new price control applies for two years to
March 2002.
While the impact of the latest regulatory review varied across companies, the
impact on a standard Northern customer was a price reduction of approximately
11%.
The supply companies are able to propose and amend the detailed structure of
tariffs, but these must be submitted to Ofgem to ensure their consistency with
the prescribed price caps. Prices are then monitored on an ongoing basis, and
any proposed further amendments must be submitted to Ofgem for review.
In addition to the constraint of regulatory price caps, competitive pressures
from other suppliers are exerted against Northern's tariffs and contracts. The
costs of fulfilling customer requirements are also subject to market pressures,
with energy prices varying on a half hourly basis. At present, electric prices
are established on a national half hourly basis through the electric pool.
Northern principally employs contracts to hedge the risk contingent on movements
in pool price.
Beginning on March 27, 2001, the New Electricity Trading Arrangements ("NETA")
replaced the Pool with market arrangements more reflective of other commodities.
The bulk of energy settlement under this system should occur either bilaterally
or through power exchanges. Risk mitigation should be dependent on the
establishment of effective load forecasting tools, addressing short and
longer-term requirements. In addition, it is expected that new hedging
facilities will be established, although the form of these has yet to be
defined.
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, 2000, was $24 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.
On July 18, 1997, the EPA adopted revisions to the National Ambient Air Quality
Standards for ozone and a new standard for fine particulate patter. In May 1999,
the U.S. Court of Appeals for the District of Columbia Circuit remanded the
standards adopted in July 1997 back to the EPA indicating the EPA had not
expressed sufficient justification for the basis of establishing the standards
and ruling that the EPA has exceeded its constitutionally-delegated authority in
setting the standards. As a result of the court's initial decision and the
current status of the standards, the impact of any new standards on the Company
is currently unknown. If the EPA successfully appeals the court's decision,
however, and the new standards are implemented, then MidAmerican Energy could
incur increased costs and a decrease in revenues.
Environmental Matters: U.K.
Northern carries 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 been no significant
environmental compliance issues.
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.
Northern is in the process of completing the evaluation work on the seven sites
which may be subject to the legislation. A compliance strategy will then be
developed. Exploratory work with an environmental remediation company is
expected to minimize any clean up costs.
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 decontaminated by December 31, 2000. Northern has registered 62
items above 50 PPM, decontaminated 4 items and informed the Environment Agency
that it is continuing with its sampling, labeling and registration program.
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 2001 through 2005 to an
external trust established for the investment of funds for decommissioning Quad
Cities Station. Approximately 60% 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.
In addition, during the year 2000, MidAmerican Energy made payments to the
Nebraska Public Power District ("NPPD") related to decommissioning Cooper
Nuclear Station ("Cooper") based on an assumed shutdown of Cooper in September
2004. These payments are reflected in operating expense in the consolidated
statements of operations. Based on NPPD estimates assuming a September 2004
shutdown of Cooper, MidAmerican Energy expects to accrue approximately $55
million for Cooper decommissioning during the period 2001 through 2004. The
funds that have been provided to NPPD, with the understanding that Cooper will
be shut down in September 2004, are invested predominately in U.S. Treasury
Bonds and other U.S. Government securities. Approximately 30% was invested in
domestic corporate debt. MidAmerican Energy's obligation, if any, for Cooper
decommissioning may 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.
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.
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 June 1998, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative
Instruments and Hedging Activities," which was delayed by SFAS No. 137 and
amended by SFAS No. 138. SFAS 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. The Company implemented
the new standards on January 1, 2001. The initial adoption of the SFAS 133/138
did not have a material impact on the Company's financial position, results of
operations or any impact on its cash flows.
The FASB's Derivatives Implementation Group continues to identify and provide
guidance on various implementation issues related to SFAS 133/138 that are in
varying stages of review and clearance by the Derivatives Implementation Group
and the FASB. The Company has not determined if the ultimate resolution of those
issues would have a material impact on its financial statements.
In September 2000, the FASB issued SFAS No. 140, "Accounting for Transfers and
Servicing of Financial Assets and extinguishments of Liabilities" (FAS 140),
replacing SFAS No. 125, "Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities" (SFAS 125). SFAS 140 revised criteria
for accounting for securitizations, other financial asset transfers and
collateral, and introduces new disclosures. SFAS 140 is effective for fiscal
2000 with respect to the new disclosure requirements and amendments of the
collateral provisions originally presented in SFAS 125. All other provisions are
effective for transfers of financial assets and extinguishments of liabilities
occurring after March 31, 2001. The provisions are to be applied prospectively
with certain exceptions. Management is currently assessing the impact that FAS
140 will have on the Company's consolidated financial statements.
Qualitative and Quantitative Disclosures About Market Risk
The following discussion of the Company's exposure to various market risks
contains "forward-looking statements" that involve risks and uncertainties.
These projected results have been prepared utilizing certain assumptions
considered reasonable in the circumstances and in light of information currently
available to the Company. Actual results could differ materially from those
projected in the forward-looking information.
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.
Interest Rate Risk
At December 31, 2000, 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 $6,548.7 million in principal amount and having a fair value of
$6,400.1 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 $234 million if interest rates were to increase by 10% from their
levels at December 31, 2000. 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, 2000, the Company had floating-rate obligations of $229.2
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, 2000
levels, the Company's consolidated interest expense for unhedged floating-rate
obligations would increase by approximately $139,000 each month in which such
increase continued based upon December 31, 2000 principal balances.
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. As of December 31, 2000, the market value of this
swap was $5.0 million.
Currency Exchange Rate Risk
At December 31, 2000, CE Electric UK Funding Company had fixed-rate obligations
denominated in U.S. dollars that expose CE Electric UK Funding Company to losses
in the event of increases in the exchange rate of U.S. dollars to Sterling. CE
Electric UK Funding Company entered into certain currency rate swap agreements
that effectively convert the U.S. dollar fixed interest rate to a fixed rate in
Sterling. At December 31, 2000, these currency rate swap agreements had an
aggregate notional amount of $362 million, which the Company would receive
approximately $23.1 million at termination. A decrease of 10% in the December
31, 2000 rate of exchange of Sterling to dollars would increase the cost of
terminating these swap agreements by approximately $39.5 million.
Energy Commodity Price Risk
Northern
Northern utilizes contracts for differences ("CFDs"), as part of the overall
risk management strategy of its electricity supply business, to mitigate its
exposure to volatility in the price of electricity purchased through the
electricity pool (the "Pool").
The portfolio of CFDs held for risk management purposes is established to match
the notional quantity of the expected or committed transaction volumes that will
be subject to commodity price risk over the same time period. The portfolio is
therefore managed to complement the expected electricity purchase transaction
portfolio, thereby reducing electricity price change risk to within acceptable
limits.
As a consequence, the value of the portfolio of CFDs, which are held for risk
management purposes, is directly linked to the hypothetical changes in Pool
price, such that an adverse movement in Pool price would be offset by a
compensating impact on the contract. For the specified volumes, therefore, the
impact of Pool risk is constrained at a pre-determined level, assuming:
(i) The CFD is not closed in advance of its agreed term.
(ii) The level of purchase occurs as expected, matching volumes covered by
the CFD.
Therefore, disclosure in respect to CFDs relies on the assumption that the
contracts exist in parallel to underlying actual electricity purchases. In the
absence of such purchases the contract would generate a loss or gain dependent
on the pool prices prevailing over the periods covered by the contract terms. As
of December 31, 2000, the notional amount of executed CFDs was approximately
$590.4 million, representing approximately 18% of the expected or committed
transaction volumes through December 31, 2004. The fair value of these contracts
was a liability of approximately $30.5 million discounted at 15%, based upon
quoted market prices at December 31, 2000. A hypothetical decrease of 10% in the
market price of electricity from the December 31, 2000 levels would further
decrease the fair value of these contracts by approximately $49.5 million.
However, as stated above, the value of the portfolio of CFDs, which are held for
risk management purposes, is directly linked to the hypothetical changes in Pool
price, such that a movement in Pool price would be offset by a compensating
impact on the contract.
The current gas purchasing strategy of Northern's gas supply business minimizes
risks in a rapidly changing market by buying both medium and short-term gas
forward contracts directly backing sales to customers within prudent
anticipation of future demand growth.
The portfolio of contracts is varied so as to lock in price at an early stage.
This portfolio may take various forms including long-term daily swing contracts,
annual swing contracts and flat monthly or quarterly standard blocks.
Over time, each month's coverage is assessed as to the likelihood of matching
demand and supply cover. Any changes to the forecast are built into the forward
purchase requirements. In addition, applying pricing scenarios to the uncovered
portion of the portfolio continuously assesses the supply risk to the business.
As of December 31, 2000, the notional amount of outstanding forward purchase
contracts was approximately $201.0 million, representing approximately 10% of
expected sales through December 31, 2007. The fair value of such contracts was
an asset of approximately $60.2 million discounted at 15%, based upon quoted
market prices at December 31, 2000. A hypothetical decrease of 10% in the market
price of gas from the December 31, 2000 levels would further decrease the fair
value of these contracts by approximately $22.5 million.
Northern had the following financial derivative instruments for its electric
operations as of December 31:
Derivative instruments used for other than trading purposes-
- ------------------------------------------------------------
2000 1999
--------------- --------------
Electricity Contracts for Differences:
Net Contract Volumes - Long 17,081,000 MWh 14,981,000 MWh
Unrealized Loss, in thousands $30,543 $8,212
A $5.00 increase in underlying electricity prices would decrease unrealized
losses into an unrealized gain on the contract for differences held at December
31, 2000 by approximately $85.4 million.
MidAmerican
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 losses 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
under strict value at risk guidelines outlined by senior management. In
accordance with the FASB's Emerging Issues Task Force Abstract No. 98-10 (EITF
98-10), derivative instruments held for trading purposes are recorded at fair
value and any unrealized gains or losses are reported in earnings. EITF 98-10
has not had a material effect on the Company's financial position, results of
operations or cash flows.
MidAmerican Energy uses electricity forward contracts to hedge anticipated sales
of wholesale electric power. Electric forward contracts are not reflected in the
financial statements until they are settled.
MidAmerican Energy had the following financial derivative instruments for its
natural gas and electric operations as of December 31:
Derivative instruments used for other than trading purposes-
- ------------------------------------------------------------
2000 1999
---------------- -----------------
Natural Gas Futures Contracts - NYMEX:
Net Contract Volumes- Long (Short) 1,460,000 MMBtu (500,000) MMBtu
Unrealized Gain (Loss), in thousands $7,554 $(410)
Natural Gas Swap Contracts:
Contract Volumes 24,106,980 MMBtu 85,520,442 MMBtu
Unrealized Gain (Loss), in thousands $8,055 $(1,576)
Natural Gas Options:
Contract Volumes - Long 1,790,280 MMBtu -
Unrealized Gain, in thousands $953 -
Electric Forward Contracts:
Contract Volumes - (Short) (139,200) MWh -
Unrealized (Loss), in thousands $(4,731) -
A $1.00 increase in underlying natural gas prices would increase unrealized
gains on the futures contracts held at December 31, 2000 by approximately $1.5
million and would increase unrealized gains on the above swap contracts by
approximately $2.3 million. A $5.00 increase in underlying electricity prices
would increase unrealized losses on the forward contracts held at December 31,
2000 by approximately $0.7 million.
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.
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands)
As of December 31,
-------------------------------
2000 1999
-------------- -------------
Assets
Current Assets:
Cash and investments................................................ $ 38,152 $ 316,327
Restricted cash and short term investments.......................... 42,129 36,294
Accounts receivable................................................. 903,469 600,564
Inventories......................................................... 81,943 94,981
Other current assets................................................ 96,784 90,147
---------- ----------
Total Current Assets............................................. 1,162,477 1,138,313
Property, plant, contracts and equipment, net ......................... 5,348,647 5,463,329
Excess of cost over fair value of net assets acquired, net............. 3,673,150 2,712,677
Regulatory assets...................................................... 240,934 278,757
Long-term restricted cash and investments.............................. 48,747 255,440
Nuclear decommissioning trust fund and other marketable securities..... 202,227 226,298
Equity investments..................................................... 246,466 208,023
Deferred charges, other investments and other assets................... 758,003 483,515
----------- -----------
Total Assets........................................................ $11,680,651 $10,766,352
=========== ===========
Liabilities and Stockholders' Equity
Current Liabilities:
Accounts payable.................................................... $ 656,356 $ 449,203
Accrued interest.................................................... 107,726 94,983
Accrued taxes....................................................... 125,645 145,534
Other accrued liabilities........................................... 250,975 218,150
Short-term debt..................................................... 251,656 379,523
Current portion of long-term debt................................... 438,978 235,202
----------- ----------
Total Current Liabilities........................................ 1,831,336 1,522,595
Other long-term accrued liabilities.................................... 976,030 1,054,440
Parent company debt.................................................... 1,829,971 1,856,318
Subsidiary and project debt............................................ 3,398,696 3,642,703
Deferred income taxes.................................................. 945,028 902,868
---------- ----------
Total Liabilities................................................... 8,981,061 8,978,924
---------- ----------
Deferred income........................................................ 79,489 65,509
Minority interest...................................................... 11,491 29,127
Company-obligated mandatorily redeemable
preferred securities of subsidiary trusts........................... 786,523 450,000
Subsidiary-obligated mandatorily redeemable
preferred securities of subsidiary trusts ......................... 100,000 101,598
Preferred securities of subsidiaries................................... 145,686 146,606
Commitments and contingencies (Notes 4, 15, 17, 18 and 19)
Stockholders' Equity:
Zero coupon convertible preferred stock - authorized 50,000 shares,
no par value, 34,563 shares outstanding at December 31, 2000....... - -
Common stock - authorized 60,000 and 180,000 shares, no par value;
9,281 and 82,980 shares issued, 9,281 and 59,944 shares outstanding,
at December 31, 2000 and 1999, respectively......................... - -
Additional paid in capital............................................. 1,553,073 1,249,079
Retained earnings...................................................... 81,257 507,726
Accumulated other comprehensive loss, net.............................. (57,929) (12,029)
Treasury stock - 23,036 common shares at December 31, 1999 at cost..... - (750,188)
----------- -----------
Total Stockholders' Equity.......................................... 1,576,401 994,588
----------- -----------
Total Liabilities and Stockholders' Equity............................. $11,680,651 $10,766,352
=========== ===========
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands)
MEHC (Predecessor)
-----------------------------------------------
March 14, 2000 January 1, 2000
through through Year Ended December 31,
-----------------------
December 31, 2000 March 13, 2000 1999 1998
----------------- -------------- ---- ----
Revenue:
Operating revenue.............................. $3,945,716 $1,043,072 $4,128,737 $2,555,206
Interest and other income...................... 94,882 19,484 143,175 127,505
Gains on non-recurring items................... - - 138,704 -
---------- ---------- ---------- ----------
Total revenues.................................... 4,040,598 1,062,556 4,410,616 2,682,711
---------- ---------- ---------- ----------
Costs and expenses:
Cost of sales.................................. 2,222,128 561,386 2,143,891 1,258,539
Operating expense.............................. 904,511 219,303 1,001,384 471,405
Depreciation and amortization.................. 383,351 97,278 427,690 333,422
Interest expense............................... 396,773 101,330 496,578 406,084
Less interest capitalized...................... (85,369) (15,516) (70,405) (58,792)
Losses on non-recurring items.................. - 7,605 54,409 -
---------- --------- ---------- ----------
Total costs and expenses.......................... 3,821,394 971,386 4,053,547 2,410,658
---------- --------- ---------- ----------
Income before provision for income taxes.......... 219,204 91,170 357,069 272,053
Provision for income taxes........................ 53,277 31,008 93,475 93,265
---------- --------- ---------- ----------
Income before minority interest................... 165,927 60,162 263,594 178,788
Minority interest................................. 84,670 8,850 46,923 41,276
---------- --------- ---------- ----------
Income before extraordinary item and
cumulative effect of change in accounting
principle..................................... 81,257 51,312 216,671 137,512
Extraordinary item, net of tax.................... - - (49,441) (7,146)
Cumulative effect of change in accounting
principle, net of tax.......................... - - - (3,363)
----------- ---------- ---------- ---------
Net income available to common
stockholders.................................. $ 81,257 $ 51,312 $ 167,230 $ 127,003
=========== ========== =========== =========
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, 2000
(In thousands)
Accumulated
Other Additional
Compre- Common Stock
Outstanding Additional hensive & Options
Common Common Paid-In Retained Income Subject to Treasury
Shares Stock Capital Earnings (Loss) Redemption Stock Total
------ ----- ------- -------- ------ ---------- ----- -----
Balance January 1, 1998 81,322$ - $1,266,683 $ 213,493 $ (3,589) $(654,736) $ (56,525) $ 765,326
Net income - - - 127,003 - - - 127,003
Other Comprehensive Income:
Foreign currency translation
adjustment * - - - - 3,634 - - 3,634
---------
Comprehensive income 130,637
Exercise of stock options and
other equity transactions 226 - (7,841) - - - 7,825 (16)
Purchase of treasury stock (21,943) - (21,313) - - - (703,478) (724,791)
Common stock and options
subject to redemption - - - - - 654,736 - 654,736
Tax benefit from stock plan - - 1,161 - - - - 1,161
- ----------------------------------------------------------------------------------------------------------------------
Balance December 31, 1998 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)
Unrealized losses on securities,
net of tax of $123 - - - - (228) - - (228)
-------
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
======================================================================================================================
* 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
through through Year Ended December 31,
-----------------------
December 31, 2000 March 13, 2000 1999 1998
----------------- -------------- ---- ----
Cash flows from operating activities:
Net income........................................... $ 81,257 $ 51,312 $ 167,230 $ 127,003
Adjustments to reconcile net cash flows from
operating activities:
Gains on non-recurring items...................... - - (138,704) -
Extraordinary item, net of tax.................... - - 49,441 7,146
Cumulative effect of change in accounting principle - - - 3,363
Depreciation and amortization..................... 310,418 83,194 363,737 290,794
Amortization of excess of cost over fair value of net
assets acquired................................. 72,933 14,084 63,953 42,628
Amortization of deferred financing and other costs 17,402 4,334 18,181 21,723
Provision for deferred income taxes............... (15,460) 7,735 (56,590) 34,332
Distributions in excess of (less than) income on
equity investments.............................. (26,607) (3,459) (22,796) 6,171
Changes in other items:
Accounts receivable and other current assets.... (360,710) 46,436 61,209 (135,124)
Accounts payable, accrued liabilities, deferred
income and other................................ 71,474 63,447 47,157 (36,490)
---------- --------- ---------- ----------
Net cash flows from operating activities............. 150,707 267,083 552,818 361,546
---------- --------- ---------- ----------
Cash flows from investing activities:
Purchase of MEHC (Predecessor), MidAmerican, and
Kiewit's Interests, net of cash acquired......... (2,048,266) - (2,501,425) (500,916)
Proceeds from sale of qualified facilities, net of cash
disposed........................................ - - 365,074 -
Proceeds from Indonesia settlement................... - - 290,000 -
Purchase of marketable securities.................... (44,686) (8,251) (92,523) -
Proceeds from sale of marketable securities.......... 72,225 10,665 498,676 -
Capital expenditures relating to operating projects.. (174,361) (21,685) (331,337) (227,071)
Philippine construction.............................. (58,531) (22,736) (62,059) (112,263)
Acquisition of U.K. gas assets....................... - - (72,280) (35,677)
Construction and other development costs............. (176,323) (56,720) (180,683) (119,916)
Decrease in restricted cash and investments.......... 158,049 42,809 199,588 20,568
Other................................................ 38,971 (74,765) (58,263) (32,505)
---------- --------- ---------- ----------
Net cash flows from investing activities............. (2,232,922) (130,683) (1,945,232) (1,007,780)
---------- --------- ---------- ----------
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 - - -
Proceeds from issuance of parent company debt........ - - - 1,502,243
Repayments of parent company debt.................... (4,225) - (853,420) (167,285)
Net proceeds from revolver........................... 85,000 - - -
Proceeds from subsidiary and project debt............ 256,133 6,043 1,429,856 464,974
Repayments of subsidiary and project debt............ (317,553) (133,060) (369,016) (255,711)
Deferred charges relating to debt financing.......... (4,292) - 7,761 (47,205)
Redemption of preferred securities of subsidiaries... (20,415) - - -
Purchase of treasury stock........................... - - (104,847) (724,791)
Other................................................ 358 (149) 4,306 25,113
----------- ----------- ----------- -----------
Net cash flows from financing activities............. 1,877,802 (127,166) 114,640 797,338
----------- ----------- ----------- -----------
Effect of exchange rate changes...................... (61,046) (21,950) (12,047) 3,634
----------- ----------- ----------- -----------
Net increase (decrease) in cash and cash equivalents. (265,459) (12,716) (1,289,821) 154,738
Cash and cash equivalents at beginning of period..... 303,611 316,327 1,606,148 1,451,410
----------- ---------- ----------- -----------
Cash and cash equivalents at end of period........... $ 38,152 $ 303,611 $ 316,327 $ 1,606,148
=========== ========== =========== ===========
Supplemental Disclosures:
Interest paid, net of amount capitalized............. $ 351,532 $ 35,057 $ 439,894 $ 341,645
=========== ========== =========== ===========
Income taxes paid.................................... $ 94,405 $ - $ 130,875 $ 53,609
=========== ========== =========== ===========
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 (successor to MidAmerican Energy Holdings
Company (Predecessor), referred to as "MEHC (Predecessor)") and subsidiaries
(collectively referred to as the "Company" or "MEHC"), is a United States-based
privately owned global energy company with publicly traded fixed income
securities which 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 four
separate platforms: MidAmerican, Northern, CalEnergy Generation and
HomeServices.
MidAmerican
The MidAmerican Platform consists primarily of the Company's ownership in
MidAmerican Energy Company ("MidAmerican Energy"). MidAmerican Energy is the
largest energy company headquartered in Iowa and 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 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, 2000, MidAmerican Energy
had 669,000 retail electric customers and 647,000 retail natural gas customers.
In addition to retail sales, MidAmerican Energy sells electric energy to other
utilities, marketers and municipalities who 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.
Northern
The operations of Northern Electric plc ("Northern"), an indirect wholly owned
subsidiary of the Company, consist primarily of the distribution and supply of
electricity, supply of natural gas and other auxiliary businesses in the United
Kingdom.
Northern receives electricity from the national grid transmission system and
distributes it to customers' premises using its network of transformers,
switchgear and cables. Substantially all of the customers in Northern's
authorized area are connected to Northern's network and can only be delivered
electricity through Northern's distribution system, regardless of whether it is
supplied by Northern's own supply business or by other suppliers, thus providing
Northern with distribution volume that is stable from year to year. Northern
charges 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 primarily involves the bulk purchase of electricity,
through a central pool, and subsequent resale to individual customers. The
supply business generally is a high volume business that tends to operate at
lower profitability levels than the distribution business. As of December 31,
2000, Northern supplied electricity to approximately 1.1 million customers.
Northern also competes to supply gas inside and outside its authorized area. In
the residential market Northern currently supplies gas to approximately 470,000
customers.
CalEnergy Generation
The CalEnergy Platform is engaged in the development, ownership and operation of
environmentally responsible independent power production facilities worldwide
utilizing geothermal, natural gas, hydroelectric and other energy sources.
Through the Company's 50% owned subsidiary, CE Generation LLC ("CE Generation"),
the Company has interests in ten operating geothermal plants in Imperial Valley,
California and three operating natural gas fired cogeneration plants in New
York, Texas and Arizona. The Company accounts for CE Generation under the equity
method.
The Company also indirectly owns the Upper Mahiao, Malitbog and Mahanagdong
Projects (collectively, the "Philippine Projects"), which are geothermal power
plants located on the island of Leyte in the Philippines. Plant capacity amounts
for the Upper Mahiao, Malitbog and Mahanagdong Projects are 119, 216 and 165 net
MW, respectively.
HomeServices
The Company owns approximately 83% of HomeServices.Com, Inc. ("HomeServices"),
the second largest residential real estate brokerage firm in the United States
based on aggregate closed transaction sides in 1999 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 primarily
under the Edina Realty, Iowa Realty, J.C. Nichols Residential, CBSHOME, Paul
Semonin Realtors, Long Realty and Champion Realty brand names in the following
twelve states: Minnesota, Iowa, Arizona, Kansas, Missouri, Kentucky, Nebraska,
Wisconsin, Indiana, Maryland, North Dakota and South Dakota. HomeServices
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, 1999. HomeServices' major markets consist of the following metropolitan
areas: Minneapolis and St. Paul, Minnesota; Des Moines, Iowa; Omaha, Nebraska;
Kansas City, Kansas; Louisville, Kentucky; Springfield, Missouri; Tucson,
Arizona and Annapolis, Maryland.
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.
Beginning March 14, 2000, the financial statements reflect the Teton Transaction
(described in Note 3) and the resulting push down of the accounting as a
purchase business combination.
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 17 for additional information
regarding decommissioning costs.
Well, Resource Development and Exploration Costs
The Company follows the full cost method of accounting for costs incurred in
connection with the exploration and development of geothermal and natural gas
resources. All such costs, which include dry hole costs and the cost of drilling
and equipping production wells and directly attributable administrative and
interest costs, are capitalized and amortized over their estimated useful lives
when production commences. The estimated useful lives of geothermal production
wells are ten to twenty years depending on the characteristics of the underlying
resource; exploration costs and development costs, other than production wells,
are generally amortized over the weighted average remaining term of the
Company's power and steam purchase contracts.
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 40 year period for
the Teton and MidAmerican acquisitions, and a 32 year period for the acquisition
of Kiewit's interests.
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 models, whenever evidence
exists that the carrying value is not recoverable.
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.
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 bases 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 utilizes swap agreements, contracts for differences 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. For contracts for differences, the net cash amounts paid or
received on the agreements are accrued and recognized as an adjustment to cost
of sales. 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 1999 and 1998 consolidated financial statements
and supporting note disclosures have been reclassified to conform to the fiscal
2000 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"). Other accrued liabilities
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 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 the remaining 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.
New Accounting Pronouncements
On January 1, 2001, the Company adopted Statement of Financial Accounting
Standards Nos. 133 and 138 (SFAS 133/138) pertaining to the accounting for
derivative instruments and hedging activities. SFAS 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 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 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 133. Initial adoption of SFAS
133/138 did not have a material impact on the results of operations for the
Company.
The FASB's Derivatives Implementation Group continues to identify and provide
guidance on various implementation issues related to SFAS 133/138 that are in
varying stages of review and clearance by the Derivatives Implementation Group
and the FASB. The Company has not determined if the ultimate resolution of those
issues would have a material impact on its financial statements.
In September 2000, the FASB issued SFAS No. 140, "Accounting for Transfers and
Servicing of Financial Assets and extinguishments of Liabilities" (SFAS 140),
replacing SFAS No. 125, "Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities" (SFAS 125). SFAS 140 revised criteria
for accounting for securitizations, other financial asset transfers and
collateral, and introduces new disclosures. SFAS 140 is effective for fiscal
2000 with respect to the new disclosure requirements and amendments of the
collateral provisions originally presented in SFAS 125. All other provisions are
effective for transfers of financial assets and extinguishments of liabilities
occurring after March 31, 2001. The provisions are to be applied prospectively
with certain exceptions. Management is currently assessing the impact that SFAS
140 will have on the Company's consolidated financial statements.
3. Acquisitions/Dispositions
Teton Transaction
On October 24, 1999, the Company and entities representing an investor group
comprised of Berkshire Hathaway Inc. ("Berkshire Hathaway"), Walter Scott, Jr.,
a director of the Company, and David L. Sokol, Chairman and Chief Executive
Officer of the Company, 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. The 11% trust preferred securities have
a liquidation preference of $25 each and are subject to mandatory redemption in
ten equal semi-annual installments commencing December 15, 2005. 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
based on preliminary valuations. The final purchase price allocation has not
been completed; however, the Company does not anticipate any material changes
based on currently available information. The Company recorded goodwill of
approximately $1,242 million that is being amortized using the straight-line
method over a 40-year period.
Unaudited pro forma combined revenue, income before extraordinary items and net
income of the Company and MEHC (Predecessor) for the years ended December 31,
2000 and 1999, as if the Teton Transaction and the MidAmerican Merger (see
below) 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, were $5,103.2 million, $124.9 million and $124.9 million,
respectively, compared to $4,801.1 million, $187.7 million and $138.3 million,
respectively.
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.
MidAmerican Merger
On August 11, 1998, the Company entered into an Agreement and Plan of Merger
with MHC Inc., formerly MidAmerican Energy Holdings Company ("MHC"). The
MidAmerican Merger closed on March 12, 1999 and the Company paid $27.15 in cash
for each outstanding share of MHC common stock for a total of approximately
$2.42 billion in a merger, pursuant to which MHC became an indirect wholly owned
subsidiary of the Company. Additionally, the Company reincorporated in the State
of Iowa, was renamed MidAmerican Energy Holdings Company and, upon closing,
became an exempt public utility holding company.
The MidAmerican Merger has been accounted for as a purchase business combination
and as such the results of operations of the Company include the results of MHC
beginning March 12, 1999. The purchase price has been allocated to assets
acquired and liabilities assumed. The Company recorded goodwill of approximately
$1.5 billion, which is being amortized using the straight-line method over a
40-year period.
Qualified Facilities Dispositions
The consummation of the MidAmerican Merger was conditioned upon receipt of a
number of regulatory approvals. Regulatory approval required the disposition of
partial interests in certain of the Company's independent power generating
facilities prior to the consummation of the MidAmerican Merger in order to
maintain the qualifying facilities status of such power generating facilities.
To accomplish this disposition, the following events occurred in the first
quarter of 1999:
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 February 8, 1999, the Company created a new subsidiary, CE Generation LLC
("CE Generation") and subsequently transferred its interest in the Company's
power generation assets in the Imperial Valley Projects and the Gas Plants to CE
Generation. On March 2, 1999, CE Generation closed the sale of $400 million
aggregate principal amount of its 7.416% Senior Secured Bonds due in 2018 and
distributed the proceeds to the Company.
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. 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 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.
HomeServices.Com
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%. The
Company recognized a pre-tax gain on the sale of its HomeServices stock of $7.9
million, which is reported in interest and other income. The Company recognized
a gain for HomeServices' sale of newly issued stock of $9.1 million, net of
deferred tax of $0.8 million, which was recorded as a credit to additional paid
in capital.
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%.
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 with Perusahaan Petambangan Minyak Dan Gas Gumi
Negara ("Pertamina"), the Indonesian national oil company, and executed separate
"take-or-pay" energy sales contracts ("ESCs") with both Pertamina and P.T. PLN
(Persero) ("PLN"), the Indonesian national electric utility. The Government of
Indonesia provided sovereign performance undertakings of the obligations under
the joint operating and "take-or-pay" contracts. The Company carried political
risk insurance on its investment in HCE and PPL through the Overseas Private
Investment Corporation ("OPIC"), an agency of the U.S. Government, as well as
through private market insurers.
In 1997 and 1998 a series of Indonesian government decrees and other actions
(including the non-payment of all monthly invoices from HCE's Dieng Unit I,
which became operational in March 1998) created significant uncertainty as to
whether PLN and 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.
On or about August 14, 1998, the Company, through the Indonesian Subsidiaries,
began arbitration proceedings against PLN in connection with the HCE's and PPL's
geothermal power projects in Indonesia, the Dieng Project and the Patuha
Project. An arbitral tribunal found that PLN had materially breached the
provisions of the ESCs between PLN and both HCE and PPL, and awarded HCE
approximately $391.7 million and PPL $180.6 million, and ordered PLN to pay
these amounts immediately.
Following PLN's failure to pay such amounts, HCE and PPL demanded payment
pursuant to the sovereign performance undertakings issued by the Minister of
Finance on behalf of the Republic of Indonesia ("ROI") and, following the ROI's
failure to pay, brought an arbitration against the ROI for breach of those
undertakings. A final award was issued by an international arbitration panel in
the ROI arbitration on October 15, 1999 that found that the ROI materially
breached its performance undertakings and violated international law, and the
ROI was required to pay HCE and PPL an aggregate amount of approximately $575
million.
Following ROI's failure to pay such amount, 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.
4. Property, Plant, Contracts and Equipment, Net:
Property, plant, contracts and equipment, net comprise the following at December
31 (in thousands):
MEHC
(Predecessor)
2000 1999
---------- ----------
Operating assets:
Utility generation and distribution system........... $6,266,391 $6,362,975
Independent power plants ............................ 740,631 705,346
Wells and resource development....................... 47,916 123,845
Power sales agreements............................... 82,231 -
Other assets......................................... 387,709 377,897
---------- ----------
Total operating assets............................... 7,524,878 7,570,063
Less accumulated depreciation and amortization....... (3,332,098) (3,062,387)
---------- ----------
Net operating assets................................. 4,192,780 4,507,676
Mineral and gas reserves and exploration assets, net. 378,494 476,416
Construction in progress:
Casecnan........................................ 387,274 306,007
Zinc recovery project........................... 165,585 92,794
Cordova......................................... 224,514 79,982
Other........................................... - 454
----------- ----------
Total $5,348,647 $5,463,329
========== ==========
Minerals Extraction
The Company developed and 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 as well as the production of power
to be used in the extraction process. 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 that will recover zinc from the
geothermal brine (the "Zinc Recovery Project"). Facilities will be installed
near the Imperial Valley Projects 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 operation in mid-2001. 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 is being constructed by Kvaerner U.S. Inc.
("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering,
procurement and construction contract (the "Zinc Recovery Project EPC
Contract"). Kvaerner is a wholly owned indirect subsidiary of Kvaerner ASA, an
international engineering and construction firm experienced in the metals,
mining and processing industries. Total project costs of the Zinc Recovery
Project are expected to be approximately $200.9 million.
Casecnan
CE Casecnan Water and Energy Company, Inc., a Philippine corporation ("CE
Casecnan") which at completion of the Casecnan Project is expected to be at
least 70% indirectly owned by the Company, is constructing the Casecnan Project,
a combined irrigation and 150 net MW hydroelectric power generation project (the
"Casecnan Project") located in the central part of the island of Luzon in the
Republic of the Philippines.
CE Casecnan has entered into a fixed-price, date certain, turnkey engineering,
procurement and construction contract to complete the construction of the
Casecnan Project (the "Casecnan Construction Contract"). The work under the
Casecnan Construction 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 Casecnan Construction 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. In January 2001, CE Casecnan received a new working schedule
from the Contractor that showed a completion date of August 31, 2001.
Accordingly, the Casecnan Project is now expected to become operational by the
third quarter of 2001. The delay in completion is attributable in part to the
collapse in December 2000 of the Casecnan Project's partially completed vertical
surge shaft and the need to drill a replacement surge shaft.
The receipt of the working schedule does not change the Guaranteed Substantial
Completion Date under the Replacement Contract, and the Contractor is still
contractually obligated either to complete the Casecnan Project by March 31,
2001 or to pay delay liquidated damages. As a result of receipt of the working
schedule, however, CE Casecnan has sought and obtained from the lender's
independent engineer approval for a revised construction schedule under the
Casecnan Indenture. In connection with the revised schedule, the Company agreed
to make available up to $11.6 million of additional funds under certain
conditions pursuant to a Shareholder Support Letter dated February 8, 2001 (the
"Shareholder Support Letter") to cover additional costs resulting from the
Contractor's schedule delay.
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, 2001resulting
from various force majeure events. In a March 20, 2001 Supplement to Request for
Arbitration, the Contractor also seeks compensation for alleged additional costs
it incurred from the claimed force majeure events to the extent it is unable to
recover from its insurer. CE Casecnan believes such allegations are without
merit and intends to vigorously defend the Contractor's claims.
Cordova
Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned
subsidiary of the Company, has commenced construction of a 537 MW gas-fired
power plant in the Quad Cities, Illinois area (the "Cordova Project"). Cordova
Energy has entered into an engineering, procurement and construction contract
with Stone & Webster Engineering Corporation ("SWEC") to build the project. The
construction of the Cordova Project is expected to be completed in mid-2001.
Total project costs are estimated to be approximately $288.9 million.
Cordova Energy has entered into a power sales agreement with a unit of El Paso
Energy Corporation ("El Paso"). Under the power sales agreement, El Paso will
purchase all the capacity and energy from the project until December 31, 2019.
However, Cordova Energy has the option to elect on an annual basis to retain up
to 50% of the project capacity and energy for sales to others.
5. Equity Investments
CE Generation, the Company's 50% owned subsidiary, has interests in ten
operating geothermal plants in Imperial Valley, California and three operating
natural gas-fired cogeneration plants in New York, Texas and Arizona. 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 following is
summarized financial information for CE Generation as of and for the years ended
December 31 (in thousands):
2000 1999
---- ----
Current assets $191,112 $119,829
Total assets 1,987,323 1,725,419
Current liabilities 138,751 92,842
Total liabilities 1,479,944 1,333,139
Revenues 510,796 340,683
Income before extraordinary item 73,535 61,970
Net income 73,535 44,492
6. Short-Term Debt
Short-term debt comprises the following at December 31 (in thousands):
MEHC (Predecessor)
2000 1999
-------- --------
Revolving credit facilities................... $ 85,000 $ -
Northern treasury loan and other ............. 85,056 175,523
MidAmerican Energy commercial paper........... 81,600 204,000
-------- ---------
$251,656 $379,523
======== ========
Revolving Credit Facilities
The Company has available $400 million in revolving credit facilities expiring
in June 2001 and June 2003. The facilities are unsecured and are available to
fund working capital requirements and finance future business expansion
opportunities. As of December 31, 2000 there was an outstanding balance of $85
million under these revolving credit facilities. The facility carries a variable
interest rate based on LIBOR and ranging from 6.6875% to 9.5% in 2000 (weighted
average interest rate of 8.16% at December 31, 2000).
MidAmerican Energy Commercial Paper
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 $400 million. As of December 31, 2000, MidAmerican Energy had in
place a $370.4 million revolving credit facility which 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, 2000, commercial paper and bank notes totaled $81.6 million for
MidAmerican Energy with a weighted average interest rate of 6.6%.
Northern Short Term Treasury Loan
Northern had short-term money market loans in place at December 31, 2000 and
1999 of $85.1 million and $174.6 million, respectively. The amounts have varying
maturities generally less than one month and carry variable interest rates based
on LIBOR and ranging from 4.95% to 6.41% at December 31, 2000.
7. Parent Company Debt
Parent company debt comprises the following at December 31 (in thousands):
MEHC (Predecessor)
2000 1999
---------- -----------
9.5% Senior Notes......................... $ 32 $ 32
7.63% Senior Notes........................ 350,000 350,000
Limited Recourse Senior Secured Notes..... - 4,225
$1.4 Billion Senior Notes ................ 1,400,000 1,400,000
$100 Million Senior Notes................. 101,888 102,061
Fair Value Adjustment (see Note 3)........ (21,949) -
---------- -----------
$1,829,971 $1,856,318
9.5% Senior Notes
On September 20, 1996, the Company issued $225 million of 9.5% Senior Notes (the
"9.5% Senior Notes") due in 2006. Interest on the 9.5% Senior Notes is payable
semiannually on March 15 and September 15 of each year, commencing March 15,
1997. The 9.5% Senior Notes are redeemable at any time on or after September 15,
2001 initially at a redemption price of 104.75% declining to 100% on September
15, 2004 plus accrued interest to the date of redemption. During 1999, the
Company repurchased and retired substantially all of the notes at an average
price of 110.055% plus accrued interest. Due to the early extinguishments of the
9.5% Senior Notes, the Company recorded an extraordinary loss in 1999 of $17.9
million, net of tax. The 9.5% Senior Notes are unsecured senior obligations of
the Company.
7.63% Senior Notes
On October 28, 1997, the Company issued $350 million of 7.63% Senior Notes (the
"7.63% Senior Notes") due in 2007. Interest on the 7.63% Senior Notes is payable
semiannually on April 15 and October 15 of each year, commencing April 15, 1998.
The 7.63% Senior Notes are unsecured senior obligations of the Company.
Limited Recourse Senior Secured Notes
On July 21, 1995, the Company issued $200 million of 9 7/8% Limited Recourse
Senior Secured Notes due in 2003 (the "Limited Recourse Notes"). Interest on the
Limited Recourse Notes was payable on June 30 and December 30 of each year,
commencing December 1995.
On January 29, 1999, the Company commenced a cash offer for all of its
outstanding Limited Recourse Notes. The Company received tenders from holders of
an aggregate of approximately $195.8 million of principal which were paid on
March 3, 1999 at a redemption price of 110.025% plus accrued interest. Due to
early extinguishments of the Limited Recourse Notes, the Company recorded an
extraordinary loss of $17.5 million, net of tax. On June 30, 2000, the Company
redeemed the remaining $4.2 million of Limited Recourse Notes at a redemption
price of 104.9375% plus accrued interest.
$1.4 Billion Senior Notes
On September 22, 1998, the Company issued $215 million of 6.96% Senior Notes due
in 2003, $260 million of 7.23% Senior Notes due in 2005, $450 million of 7.52%
Senior Notes due in 2008, and $475 million of 8.48% Senior Bonds due in 2028
(collectively, the "$1.4 Billion Senior Notes"). Interest on the $1.4 Billion
Senior Notes is payable semiannually on March 15 and September 15 of each year,
commencing March 15, 1999. The $1.4 Billion Senior Notes are unsecured senior
obligations of the Company.
$100 Million Senior Notes
On November 13, 1998, the Company issued $100 million at a premium of
approximately 102.243% of 7.52% Senior Notes (the "$100 Million Senior Notes")
due in 2008. Interest on the $100 Million Senior Notes is payable semiannually
on March 15 and September 15 of each year, commencing March 15, 1999. The $100
Million Senior Notes are unsecured senior obligations of the Company.
8. Subsidiary and Project Debt
Project loans held by subsidiaries and projects comprise the following at
December 31 (in thousands):
MEHC (Predecessor)
2000 1999
------------ -----------
MidAmerican Funding, LLC Senior Notes and Bonds $ 702,287 $ 702,089
MidAmerican Energy Mortgage Bonds 340,570 450,570
MidAmerican Energy Pollution Control Bonds 158,625 159,129
MidAmerican Energy Notes 422,240 260,240
MidAmerican Capital Notes 46,667 70,098
HomeServices Senior Notes and Revolving Debt 47,607 48,817
Salton Sea Bonds 140,528 140,528
Northern Eurobonds 299,580 324,850
CE Electric UK Funding Company Senior Notes
and Sterling Bonds 653,750 670,327
Casecnan Notes and Bonds 346,439 363,085
Philippine Term Loans 392,625 449,739
Cordova Funding Senior Secured Bonds 225,000 124,824
CE Gas Loan 73,162 113,267
Other 239 342
Fair Value Adjustment (see Note 3) (11,645) -
----------- ----------
$3,837,674 $3,877,905
========== ==========
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 Northern, 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.
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 Merger.
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):
MEHC (Predecessor)
2000 1999
---- ----
Mortgage bonds:
6% Series, due 2000.......................... $ - $ 35,000
6.75% Series, due 2000....................... - 75,000
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 $450,570
======== ========
Pollution control revenue obligations:
5.75% Series, due periodically through 2003.. $ 7,200 $ 7,704
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, 3.95% ................. 37,600 37,600
Due 2023 (secured by general mortgage
bond, 3.95%).............................. 28,295 28,295
Due 2023, 3.95%........................... 6,850 6,850
Due 2024, 3.95%........................... 34,900 34,900
Due 2025, 3.95%........................... 12,750 12,750
-------- --------
$158,625 $159,129
======== ========
Notes:
8.75% Series, due 2002....................... $ 240 $ 240
7.375% Series, due 2002...................... 162,000 -
6.5% Series, due 2001........................ 100,000 100,000
6.375% Series, due 2006...................... 160,000 160,000
-------- --------
$422,240 $260,240
======== ========
MidAmerican Capital Notes
MidAmerican Capital Company, a wholly owned subsidiary of the Company, has debt
of $46.7 million of 8.52% Senior Notes. These notes are due in annual increments
of $23.3 million in 2001 and 2002.
HomeServices Senior Notes and Revolving Debt
HomeServices debt includes $35 million of 7.12% Senior Notes due in annual
increments of $5 million beginning in 2004. HomeServices also obtained a $65
million senior secured revolving credit facility of which HomeServices had drawn
down approximately $10 million as of December 31, 2000. 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, 2000, the
blended average interest rate on the senior secured revolving credit facility
borrowings was 7.91%.
Salton Sea Bonds
CalEnergy Minerals LLC, is one of several guarantors of the Salton Sea Funding
Corporation's debt, which had a balance as of December 31, 2000 of approximately
$543.9 million. As a result of a note allocation agreement, CalEnergy Minerals
LLC is primarily responsible for $140.5 million of the 7.475% Senior Secured
Series F Bonds due November 30, 2018. The Company has guaranteed a specified
portion of the scheduled debt service on the Series F Bonds equal to this
current principal amount of $140.5 million and associated interest.
Northern Eurobonds
The balance at December 31, 2000 and 1999 consists of the following (in
thousands):
MEHC (Predecessor)
2000 1999
-------- --------
8.625% Bearer bonds due 2005 $149,865 $162,512
8.875% Bearer bonds due 2020 149,715 162,338
-------- --------
$299,580 $324,850
======== ========
CE Electric UK Funding Company Senior Notes and Sterling Bonds
On December 15, 1997, CE Electric UK Funding Company, an indirect subsidiary of
the Company (the "CE Electric UK Funding Company"), issued the Senior Notes and
Sterling Bonds. The balances at December 31 are comprised of the following (in
thousands):
MEHC (Predecessor)
2000 1999
-------- ---------
6.853% Senior Notes due 2004 $124,503 $ 121,754
6.995% Senior Notes due 2007 235,804 230,662
7.25% Sterling Bonds due 2022 293,443 317,911
-------- --------
$653,750 $670,327
======== ========
The CE Electric UK Funding Company Senior Notes and Sterling Bonds prohibit
distributions to any of its shareholders unless certain financial ratios are met
by the CE Electric UK Funding Company or the long-term debt rating falls below a
prescribed level.
CE Electric UK Funding Company 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, 2000 is approximately $23.1 million based on quotes from the counterparty to
these instruments and represents the estimated amount that the Company would
expect to receive when these agreements terminate. It is the Company's intention
to hold these swap agreements to maturity.
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. These consist of the following
(in thousands):
MEHC (Predecessor)
2000 1999
--------- --------
Senior Secured Floating Rate Notes (FRNs) due in 2002 $ 49,939 $ 66,585
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
-------- --------
$346,439 $363,085
======== ========
Quarterly interest payments for the FRNs commenced on February 15, 1996, and
semiannual interest payments for Series A Notes and Series B Bonds commenced on
May 15, 1996. The Company held $6.3 million and $8.4 million of the FRNs at
December 31, 2000 and 1999, 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
On April 8, 1998, the Company converted the construction project financing for
its Malitbog geothermal power project to term loans. OPIC is providing term loan
financing of $46.8 million that was fixed as of June 15, 1998 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
(9.005% at December 31, 2000). The loans have scheduled repayments through June
2005.
On May 5, 1998, the Company converted the construction project financing for its
Upper Mahiao geothermal power project to term loans. Export-Import Bank of the
United States ("Ex-Im Bank") is providing term loan financing 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 (9.7488% at December 31, 2000). The loans have
scheduled repayments through June 2006.
On June 18, 1998, the Company converted the construction project financing for
its Mahanagdong geothermal power project to term loans. Ex-Im Bank is providing
term loan financing of $154.6 million at a fixed rate of 6.92%. OPIC is
providing term loan financing of $34.3 million that was fixed as of September
30, 1998 at an 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):
MEHC
(Predecessor)
Series Issue Date Due Date Interest Rate 2000 1999
- ------ ---------- -------- ------------- ---- ----
Series A-1 Senior Secured Bonds September 10, 1999 2019 8.64% $93,515 $93,515
Series A-2 Senior Secured Bonds December 15, 1999 2019 8.79% 31,309 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 -
CE Gas Loan
CE Gas, a wholly owned subsidiary of the Company, had borrowed $73.2 million and
$113.3 million on a (pound) 70 million revolving facility at December 31, 2000
and 1999, respectively, to fund the purchases of UK gas assets in the North Sea.
The amount carries a variable interest rate based on LIBOR (6.67% at December
31, 2000). The revolving facility had utilized (pound) 49 million and (pound) 70
million at December 31, 2000 and 1999, respectively.
Annual Repayments of Subsidiary and Project Debt
The annual repayments of the subsidiary and project debt for the years beginning
January 1, 2001 and thereafter are as follows (in thousands):
MidAmerican MidAmerican HomeServices
Funding, MidAmerican Energy MidAmerican Senior Notes
LLC Senior Energy Pollution Energy and and Salton
Notes and Mortgage Control Capital Revolving Sea Northern
Bonds Bonds Bonds Notes Debt Bonds Eurobonds
---------- ----------- ----------- ----------- ----------- --------- ---------
2001 $200,000 $ - $ 1,440 $123,333 $ 742 $ 632 $ -
2002 - - 1,440 185,574 10,718 2,108 -
2003 - 100,000 5,320 - 532 1,405 -
2004 - 55,630 - - 5,094 1,757 -
2005 - 90,500 - - 5,025 1,757 149,865
Thereafter 502,287 94,440 150,425 160,000 25,496 132,869 149,715
-------- -------- -------- -------- -------- -------- --------
$702,287 $340,570 $158,625 $468,907 $ 47,607 $140,528 $299,580
======== ======== ======== ======== ======== ======== ========
CE Electric
Funding Cordova
Senior Funding
Notes and Casecnan Philippine Senior
Sterling Notes and Term Secured CE
Bonds Bonds Loans Bonds Gas Loan TOTAL
-------- -------- -------- -------- ------- --------
2001 $ - $ 26,301 $ 79,406 $ - $ 7,124 $438,978
2002 - 32,213 68,259 1,238 19,902 321,452
2003 - 41,468 72,148 9,000 19,116 248,989
2004 124,503 49,360 67,148 8,100 15,949 327,541
2005 - 54,753 63,034 7,875 11,071 383,880
Thereafter 529,247 142,344 42,630 198,787 - 2,128,240
--------- -------- -------- -------- -------- ----------
$653,750 $346,439 $392,625 $225,000 $ 73,162 $3,849,080
======== ======== ======== ======== ======== ==========
9. Income Taxes
Provision for (benefit from) income taxes was comprised of the following (in
thousands):
MEHC (Predecessor)
-------------------------------------------------------
March 14, 2000 January 1, 2000 Year Ended Year Ended
through through December 31, December 31,
December 31, 2000 March 13, 2000 1999 1998
----------------- -------------- ----------- ------------
Current:
State..................... $10,527 $(1,886) $ 7,337 $ 5,677
Federal................... 17,387 9,147 128,839 33,160
Foreign................... 40,823 16,012 13,889 20,096
------- ------- -------- -------
68,737 23,273 150,065 58,933
------- ------- -------- -------
Deferred:
State..................... (1,933) 834 1,791 161
Federal................... (32,469) 1,854 (75,510) 14,973
Foreign................... 18,942 5,047 17,129 19,198
------- ------- -------- -------
(15,460) 7,735 (56,590) 34,332
------- ------- -------- -------
Total..................... $53,277 $31,008 $ 93,475 $93,265
======= ======= ======== ========
A reconciliation of the federal statutory tax rate to the effective tax rate
applicable to income before provision for income taxes follows:
MEHC (Predecessor)
March 14, 2000 January 1, 2000 Year Ended Year Ended
through through December 31, December 31,
December 31, 2000 March 13, 2000 1999 1998
----------------- -------------- ----------- -----------
Federal statutory rate................... 35.00% 35.00% 35.00% 35.00%
Percentage depletion in excess of
cost depletion........................ - - (.38) (3.52)
Investment and energy tax credits........ (2.26) (.66) (1.78) (.93)
State taxes, net of federal tax effect... 2.55 (.75) 1.66 1.71
Goodwill amortization.................... 12.13 5.87 5.46 2.51
Dividends on preferred
securities of subsidiary trusts*..... (11.11) (2.80) (3.75) (4.63)
Tax effect of foreign income............. (5.83) (5.02) .36 1.86
Non-recurring items on Indonesia ........ - - (10.99) -
Dividends received deduction............. (6.77) (1.04) (3.74) -
Other items, net......................... .59 3.41 4.34 2.28
----- ----- ----- -----
Effective tax rate....................... 24.30% 34.01% 26.18% 34.28%
===== ===== ===== =====
* 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):
MEHC (Predecessor)
2000 1999
---------- ----------
Property, plant and equipment..................... $866,678 $ 983,038
Income taxes recoverable through future rates..... 186,427 187,379
Demand side management............................ 4,391 14,805
Reacquired debt................................... 10,256 12,476
--------- ---------
1,067,752 1,197,698
Nuclear reserve and decommissioning................ (20,690) (20,280)
Deferred income.................................... (8,883) (19,502)
Deferred contract costs............................ (51,703) (215,388)
Accruals not currently deductible for tax purposes. (36,255) (32,211)
Other.............................................. (5,193) (7,449)
--------- ---------
(122,724) (294,830)
--------- ---------
Net deferred income taxes.......................... $ 945,028 $ 902,868
========= =========
10. Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary
Trusts
The Company has organized special purpose Delaware business trusts ("Trust I",
"Trust II" and "Trust III" or collectively, the "Trusts") pursuant to their
respective amended and restated declarations of trusts (collectively, the
"Declarations"). On April 12, 1996, February 26, 1997 and August 12, 1997, the
Company, through these Trusts, issued Company-obligated mandatorily redeemable
convertible preferred securities (collectively, the "Trust Securities") as
follows (in thousands):
Conversion
Issuer Issue Date Rate Amount Rate
- ---------------------------- ----------------- ---- -------- ----------
CalEnergy Capital Trust I April 12, 1996 6.25% $103,930 1.6728
CalEnergy Capital Trust II February 26, 1997 6.25% $180,000 1.1655
CalEnergy Capital Trust III August 12, 1997 6.50% $270,000 1.047
On March 14, 2000, the Company, through CalEnergy Capital Trust 1, issued 11%
Company-obligated manditorily redeemable preferred securities of approximately
$454.8 million to Berkshire Hathaway.
On May 18, 1999, CalEnergy Capital Trust I effected the conversion of $103.9
million of the convertible preferred securities into approximately 3.5 million
shares of common stock of the Company. The Securities were converted at a rate
equivalent to a conversion price of $29.89 per share of Company common stock.
Throughout 2000, CalEnergy Capital Trust II redeemed approximately 477,000
shares of preferred securities at an aggregate cost of approximately $19.5
million.
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 $156.1 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 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.
The Debentures may be redeemed by MidAmerican Energy on or after December 18,
2001, or at an earlier time if there is more than an insubstantial risk that
interest paid on the Debentures will not be deductible for federal income tax
purposes. 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
such 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.
12. Preferred Stock
The Company distributed a dividend of one preferred share purchase right
("right") for each outstanding share of common stock. The rights are not
exercisable until ten days after a person or group acquires or has the right to
acquire, beneficial ownership of 20% or more of the Company's common stock or
announces a tender or exchange offer for 30% or more of the Company's common
stock. Each right entitles the holder to purchase one one-hundredth of a share
of Series A junior preferred stock for $52. The rights may be redeemed by the
Board of Directors up to ten days after an event triggering the distribution of
certificates for the rights. The rights are automatically attached to, and trade
with, each share of common stock.
In 1999, the Board of Directors renewed the Company's shareholder rights plan.
The expiration date of the rights plan was extended to September 14, 2009. The
amended plan reflects prevailing shareholder rights plan terms. The share
ownership level which triggers the exercise of the rights and the flip-in and
flip-over features of the rights plan has been reduced to 15% and the exercise
price of the rights has been increased to $140 per right. The Teton Transaction
was approved by the Board of Directors and did not trigger the dividend of a
preferred share purchase right.
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 options are fully vested and 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:
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.
MEHC (Predecessor)
2000 1999
----------------------- -----------------------
Estimated Estimated
Principal Fair Principal Fair
Amount Value Amount Value
--------- ---------- --------- ---------
(in thousands)
9.5% Senior Notes $ 32 $ 34 $ 32 $ 34
7.63% Senior Notes 350,000 360,115 350,000 346,220
Limited Recourse Senior Secured Notes - - 4,225 4,449
$1.4 Billion Senior Notes 1,400,000 1,447,581 1,400,000 1,396,360
$100 Million Senior Notes 101,888 102,020 102,061 97,920
Revolving Credit Facilities 85,000 85,000 - -
MidAmerican Funding, LLC Senior Notes and Bonds 702,287 657,300 702,089 638,101
MidAmerican Energy Mortgage Bonds 340,570 345,692 450,570 445,502
MidAmerican Energy Pollution Control Bonds 158,625 158,914 159,129 159,868
MidAmerican Energy Notes 422,240 420,496 260,240 247,084
MidAmerican Energy Commercial Paper 81,600 81,600 204,000 204,000
MidAmerican Capital Notes 46,667 46,464 70,098 71,526
HomeServices Senior Notes and Revolving Debt 47,607 44,094 48,817 44,862
Salton Sea Bonds 140,528 116,947 140,528 128,815
Northern Eurobonds 299,580 357,456 324,850 379,987
CE Electric UK Funding Company Senior Notes
and Sterling Bonds 653,750 694,031 670,327 671,779
Casecnan Notes and Bonds 346,439 319,056 363,085 353,789
Northern Short Term Treasury Loan 83,166 83,166 175,523 175,523
Cordova Funding Senior Secured Bonds 225,000 224,018 124,824 120,399
CE Gas Loan 73,162 73,162 113,267 113,267
Company-obligated preferred securities of subsidiary trusts 880,840 769,605 450,000 353,925
Subsidiary-obligated preferred securities of subsidiary trusts 100,000 98,752 101,598 87,240
Preferred Securities of Subsidiaries 145,686 131,255 146,606 135,216
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):
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........................... 25,449 48 (1,025) 24,472
Cash equivalents............................... 11,150 - - 11,150
-------- -------- -------- --------
$174,150 $ 36,392 $ (8,315) $202,227
======== ======== ======== ========
MEHC (Predecessor)
1999
----------------------------------------------------------
Amortized Unrealized Unrealized Fair
Cost Gains Losses Value
------------- ----------- ----------- --------
Available-for-sale:
Equity securities.............................. $122,327 $ 37,941 $(13,530) $146,738
Municipal bonds................................ 30,913 868 (355) 31,426
U. S. Government securities.................... 14,159 78 (123) 14,114
Corporate securities........................... 26,935 5 (1,511) 25,429
Cash equivalents............................... 8,591 - - 8,591
-------- -------- -------- --------
$202,925 $ 38,892 $(15,519) $226,298
======== ======== ======== ========
15. Accounting for Derivatives
MidAmerican Energy
MidAmerican Energy uses gas futures contracts and swap contracts to reduce the
volatility in the price of natural gas purchased to meet the needs of its regu-
lated customers, to hedge the impact of changing prices on margins earned from
nonregulated as sales and to take trading positions at levels permitted by its
risk management policy. Investments in natural gas futures contracts, which
total $4.8 million and $0.6 million as of December 31, 2000 and 1999, respec-
tively, are included in receivables on the consolidated balance sheets. Gains
and losses on gas futures contracts that qualify for hedge accounting are
deferred and reflected as adjustments to the carrying value of the hedged item
or included in other assets on the consolidated balance sheets until the under-
lying physical transaction is recorded if the instrument is used to hedge an
anticipated future transaction. The net gain or loss on gas futures contracts is
included in the determination of income in the same period as the expense for
the physical delivery of the natural gas. Realized gains and losses on gas
futures contracts and the net amounts exchanged or accrued under the natural
gas swap contracts are included in cost of sales. Deferred net gains/(losses)
related to MidAmerican Energy's gas futures contracts are $7.6 million an
$(0.4) million as of December 31, 2000 and 1999, respectively.
MidAmerican Energy uses natural gas derivative instruments for trading purposes
under strict value at risk guidelines outlined by senior management. In
accordance with the FASB's Emerging Issues Task Force Abstract No. 98-10 (EITF
98-10), derivative instruments held for trading purposes are recorded at fair
value and any unrealized gains or losses are reported in earnings. EITF 98-10
has not had a material effect on the Company's financial position, results of
operations or cash flows.
MidAmerican Energy also uses electric forward contracts to hedge anticipated
future sales of electricity. Realized gains or losses on electric derivative
products are included in cost of sales on the consolidated statements of income.
Unrecognized net losses related to MidAmerican Energy's electric derivatives
total $4.7 million and zero as of December 31, 2000 and 1999, respectively.
MidAmerican Energy periodically evaluates the effectiveness of its natural gas
and electricity hedging programs. If a high degree of correlation between prices
for the hedging instruments and prices for the physical delivery is not
achieved, the contracts are recorded at fair value and the gains or losses are
included in the determination of income. MidAmerican Energy also uses derivative
instruments for trading purposes. The following derivative instruments were
outstanding at December 31:
2000 1999
-------------------------- ----------------------------
Weighted Weighted
Average Average
Unit of Notional Market Notional Market
Measure Volume Value Per Unit Volume Value Per Unit
------- -------- -------------- -------- --------------
Hedging Instruments:
Natural Gas Futures - Long............ MMBtu 1,630,000 $ 9.46 2,700,000 $ 2.34
Natural Gas Futures - (Short) ........ MMBtu (170,000) $ (9.78) (3,250,000) $ (2.34)
Natural Gas Swaps..................... MMBtu 24,106,980 $ 0.33 85,520,442 $ (0.02)
Natural Gas Options - Long ........... MMBtu 1,790,280 $ 0.53 - -
Electric Forwards - (Short) .......... MWh (139,200) $(33.99) - -
Trading instruments:
Natural Gas Futures - NYMEX(Short).... MMBtu (20,000) $(15.92) - -
Natural Gas Swaps..................... MMBtu (10,000) $(26.14) - -
Northern
Northern utilizes contracts for differences ("CFDs"), as part of the overall
risk management strategy of its electricity supply business, to mitigate its
exposure to volatility in the price of electricity purchased through the
electricity pool (the "Pool").
The portfolio of CFDs held for risk management purposes is established to match
the notional quantity of the expected or committed transaction volumes that will
be subject to commodity price risk over the same time period. The portfolio is
therefore managed to complement the expected electricity purchase transaction
portfolio, thereby reducing electricity price change risk to within acceptable
limits.
As a consequence, the value of the portfolio of CFDs, which are held for risk
management purposes, is directly linked to the hypothetical changes in Pool
price, such that an adverse movement in Pool price would be offset by a
compensating impact on the contract. For the specified volumes, therefore, the
impact of pool risk is constrained at a pre-determined level, assuming:
(iii) The CFD is not closed in advance of its agreed term.
(iv) The level of purchase occurs as expected, matching volumes covered by
the CFD.
Therefore, disclosure in respect to CFDs relies on the assumption that the
contracts exist in parallel to underlying actual electricity purchases. In the
absence of such purses the contract would generate a loss or gain dependent on
the pool prices prevailing over the periods covered by the contract terms. As of
December 31, 2000, the national amount of executed CFDs was approximately $590.4
million, representing approximately 18% of the expected or committed transaction
volumes through December 31, 2004. The fair value of these contracts was a
liability of approximately $30.5 million discounted at 15%, based upon quoted
market prices at December 31, 2000. A hypothetical decrease of 10% in the market
price of electricity from the December 31, 2000 levels would further decrease
the fair value of these contracts by approximately $49.5 million. However, as
stated above, the value of the portfolio of CFDs, which are held for risk
management purposes, is directly liked to the hypothetical changes in Pool
price, such that a movement in Pool price would be offset by a compensating
impact on the contract.
The following derivative instruments at Northern were outstanding at December
31:
2000 1999
------------------------------- ---------------------------
Weighted Weighted
Average Average
Unit of Notional Market Notional Market
Measure Volume Value Per Unit Volume Value Per Unit
------- ------ -------------- ------ --------------
Hedging Instruments:
Net Contracts for Differences - Long MWh 17,080,000 $28.96 14,981,000 $36.49
16. Securitization of Accounts Receivable
In December 1998, Northern 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 allows Northern 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, Northern
received $161 million in cash associated with the agreement. As of December 31,
2000, approximately $37 million was accounted for as a loan.
In 1997 MidAmerican Energy entered into a revolving agreement, which expires in
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, 2000, the revolving cash balance was $70
million, and the amount outstanding under the subordinated note was $114.9
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, 2000, $185.8 million of accounts receivable, net of reserves, was
sold under the agreement.
17. Regulatory Matters
Northern
Northern is subject to price cap regulation and the Office of Gas and
Electricity Markets ("Ofgem") enforces the price control formulas for the supply
and distribution businesses.
The current distribution price control period expires on March 31, 2002. The
current formula requires that regulated distribution income per unit is
increased or decreased each year by RPI-Xd where RPI reflects the average of the
twelve months' inflation rates recorded for the previous July to December period
and Xd is 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.
Northern's current supply price control applies only to domestic and some
smaller non-domestic customers in the North East of England and is due to expire
on March 31, 2002. The current formula took effect on April 1, 2000. This
control relates to domestic customers only and led to a further price reduction
for those customers of 10.8% beginning on April 1, 2000.
MidAmerican Energy
Under a 1997 pricing plan settlement agreement resulting from an Iowa Utilities
Board rate proceeding, electric prices for MidAmerican Energy's Iowa industrial
and commercial customers were reduced through a retail access pilot project,
negotiated individual electric contracts and a tariffed rate reduction for some
non-contract commercial customers.
The negotiated electric contracts have differing terms and conditions as well as
prices. The vast majority of the contracts expire during the period 2003 through
2005, although some large customers have contracts extending to 2008. Some of
the contracts have price renegotiation and early termination provisions
exercisable by either party. Prices are set as fixed prices; however, many
contracts allow for potential price adjustments with respect to environmental
costs, government imposed public purpose programs, tax changes, and transition
costs. While the contract prices are fixed (except for the potential adjustment
elements), the costs MidAmerican Energy incurs to fulfill these contracts will
vary. On an aggregate basis the annual revenues under contract are approximately
$180 million.
Under the 1997 pricing plan settlement agreement, if MidAmerican Energy's annual
Iowa electric jurisdictional return on common equity exceeds 12%, then earnings
above the 12% level will be shared equally between customers and MidAmerican
Energy. If the return exceeds 14%, then two-thirds of MidAmerican Energy's share
of those earnings above the 14% level will be used for accelerated recovery of
certain regulatory assets. During 2000, MidAmerican Energy credited $14.8
million to its Iowa non-contract customers related to the return calculation for
1999, which was approved by the Iowa Utilities Board, subject to additional
refund. In 2000, MidAmerican Energy accrued $21.6 million for customer credits
relating to 2000 operations. This Iowa electric retail revenue sharing plan
remained in effect through the year 2000. The rates established by the pricing
plan settlement agreement will remain in effect until either the plan is
renegotiated or a change in rates is approved by the Iowa Utilities Board
pursuant to a rate proceeding.
The pricing plan settlement agreement also precluded MidAmerican Energy from
filing for increased rates prior to January 1, 2001 unless the return fell below
9%. Other parties signing the agreement were prohibited form filing for reduced
rates prior to 2001 unless the return, after reflecting credits to customers,
exceeded 14%. The agreement also eliminated MidAmerican Energy's energy
adjustment clause, and, as a result, the cost of fuel is not directly passed on
to customers.
On March 14, 2001, the Office of the Consumer Advocate of the Iowa Department of
Justice filed a petition with the Iowa Utilities Board to reduce MidAmerican
Energy's Iowa retail electric rates by approximately $77 million annually. This
filing will be contested by MidAmerican Energy and, under Iowa law, the Iowa
Utilities Board must rule on the petition within ten months from March 14, 2001.
Iowa provides that the rates collected after the filing the petition are subject
to refund with interest if they exceed rates finally approved by the Iowa
Utilities Board.
Under an Illinois restructuring law enacted in 1997, a similar sharing mechanism
is in place for MidAmerican Energy's Illinois electric operations. 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 2000 through 2004. The two-year average above which
sharing must occur for 2000 was 12.83%. Using the same 30-year Treasury Bond
average, the computed level or return would be 14.33% for 2001 through 2004. The
law allows MidAmerican Energy to mitigate the sharing of earnings above the
threshold return on common equity through accelerated recovery of regulatory
assets.
18. Pension Commitments
United Kingdom Operations
Northern 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, 2000, 1999 and 1998 assumed interest
rates of 6.0%, 6.0% and 5.5% respectively, an expected return on plan assets of
6.5%, 6.5% and 6.0%, respectively, and annual compensation increases of 3.0%,
3.0% and 3.5%, 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. Northern's funding policy for the plan is to
contribute annually at a rate that is intended to remain a level percentage of
compensation for the covered employees.
The following table details the funded status and the amount recognized in the
consolidated balance sheets for Northern's plan as of December 31, 2000 and 1999
(in thousands):
MEHC (Predecessor)
2000 1999
----------- ----------
Change in benefit obligation:
Benefit obligation at beginning of year........ $ 940,600 $ 926,000
Service cost................................... 8,660 10,200
Interest cost.................................. 50,765 48,500
Participant contributions...................... 4,927 5,700
Benefits paid.................................. (49,272) (53,700)
FAS 88 curtailment............................. 6,570 38,300
Experience gain and change of assumptions...... (10,697) (34,400)
--------- ---------
Benefit obligation at end of the year.......... 951,553 940,600
--------- ---------
Change in plan assets:
Fair value of plan assets at beginning of the
year......................................... 1,283,600 1,143,100
Actual return on plan assets................... (73,741) 181,600
Employer contributions......................... 597 6,946
Participant contributions...................... 4,927 5,654
Benefits paid.................................. (49,272) (53,700)
---------- ----------
Fair value of plan assets at end of the year... 1,166,111 1,283,600
---------- ----------
Funded status.................................. 214,558 343,000
Unrecognized net (loss) gain................... (77,193) 300,100
---------- ----------
Prepaid benefit cost........................... $ 291,751 $ 42,900
========== ==========
As a result of the distribution price reviews in 1999, Northern implemented a
review of staffing requirements primarily in its distribution business.
Following discussions with the trade unions, Northern 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.
Net periodic pension cost (benefit) for Northern's plan for 2000, 1999 and 1998
included the following components (in thousands):
MEHC (Predecessor)
------------------------------
March 14, 2000 January 1, 2000
through through
December 31, 2000 March 13, 2000 1999 1998
----------------- -------------- ---- ----
Service cost - benefits
earned during the period....... $ 6,933 $ 1,727 $ 10,200 $ 12,600
Interest cost on projected
benefit obligation............. 40,640 10,125 48,500 58,800
Expected return on plan assets... (50,800) (12,657) (59,500) (68,000)
-------- -------- -------- --------
Net periodic pension cost
(benefit)...................... $ (3,227) $ (805) $ (800) $ 3,400
======== ======= ======= ========
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 health care and life insurance
(postretirement) 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
through through Ended
December 31, 2000 March 13, 2000 December 31, 1999
----------------- -------------- -----------------
Pension Cost
Service cost.............. $ 13,014 $ 3,242 $ 9,854
Interest cost............. 28,329 7,058 25,505
Expected return on
plan assets............. (38,532) (9,600) (37,392)
Amortization of net
transition obligation... (2,074) (517) -
Amortization of prior
service cost............ 2,310 575 -
Amortization of prior
year gain............... (3,297) (822) -
Curtailment loss.......... - - 4,270
-------- -------- --------
Net periodic pension
cost (benefit)........ $ (250) $ (64) $ 2,237
======== ======== ========
MEHC (Predecessor)
---------------------------------
March 14, 2000 January 1, 2000 Year
through through Ended
Postretirement Cost December 31, 2000 March 13, 2000 December 31, 1999
----------------- -------------- -----------------
Service cost.............. $ 2,089 $ 520 $ 2,478
Interest cost............. 6,688 1,666 6,423
Expected return on
plan assets............. (3,947) (984) (3,540)
Amortization of net
transition obligation... 3,290 820 -
Amortization of prior
service cost............ 340 85 -
Amortization of prior
year gain............... (699) (174) -
------- ------- -------
Net periodic pension
cost ................. $ 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, 2000, 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 $44.7 million and $37.9 million at December 31, 2000
and 1999, 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 $4.3 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 $82.7 million and $77.5 million,
respectively, as of December 31, 2000 and $68.8 million and $65.5 million,
respectively, as of December 31, 1999.
The following table presents a reconciliation of the beginning and ending
balances of the benefit obligation, fair value of plan assets and the funded
status of the Company plans to the net amounts recognized in the consolidated
balance sheet as of December 31 (dollars in thousands):
MEHC (Predecessor)
-------------------------------
2000 2000 1999 1999
Pension Postretirement Pension Postretirement
Benefits Benefits Benefits Benefits
-------- -------- -------- --------
Reconciliation of benefit obligation:
Benefit obligation at beginning of year.................... $447,170 $107,744 $456,475 $120,188
Service cost............................................... 16,256 2,609 12,192 3,066
Interest cost.............................................. 35,387 8,354 31,556 7,947
Participant contributions.................................. 74 2,395 107 1,838
Plan amendments............................................ (132) - 14,823 2,775
Actuarial (gain) loss...................................... 6,007 20,589 (41,567) (18,248)
Curtailment................................................ - - (705) -
Termination benefits....................................... - - 3,471 -
Benefits paid.............................................. (32,413) (9,869) (29,182) (9,822)
------- ------- ------- -------
Benefit obligation at end of year...................... 472,349 131,822 447,170 107,744
------- ------- ------- -------
Reconciliation of the fair value of plan assets:
Fair value of plan assets at beginning of year............. 605,059 72,622 524,508 63,093
Employer contributions..................................... 4,355 10,543 4,201 12,405
Participant contributions.................................. 74 2,395 107 1,838
Actual return on plan assets............................... (21,867) (601) 105,425 5,108
Benefits paid.............................................. (32,413) (9,869) (29,182) (9,822)
------- ------- ------- -------
Fair value of plan assets at end of year............... 555,208 75,090 605,059 72,622
------- ------- ------- -------
Funded status.............................................. 82,859 (56,732) 157,889 (35,122)
Unrecognized net (gain) loss............................... (130,423) 1,326 (101,434) (18,943)
Unrecognized prior service cost............................ 24,962 4,689 9,540 2,776
Unrecognized net transition obligation (asset)............. (8,566) 49,322 - -
-------- ------- ------- -------
Net amount recognized in the consolidated balance.
sheet.................................................. $(31,168) $ (1,395) $ 65,995 $(51,289)
======== ======== ======== ========
MEHC (Predecessor)
-------------------------------
2000 2000 1999 1999
Pension Postretirement Pension Postretirement
Benefits Benefits Benefits Benefits
-------- -------- -------- --------
Amounts recognized in the consolidated balance sheet consist of:
Prepaid benefit cost....................................... $ 16,773 $ 1,493 $108,907 $ 1,042
Accrued benefit liability.................................. (77,538) (2,888) (65,533) (52,331)
Intangible asset........................................... 25,510 - 22,621 -
Accumulated other comprehensive income..................... 4,087 - - -
-------- --------- -------- --------
Net amount recognized.................................. $(31,168) $ (1,395) $ 65,995 $(51,289)
======== ======== ======== ========
Pension and Postretirement
Assumptions
-----------
MEHC (Predecessor)
2000 1999
---- ----
Assumptions used were:
Discount rate...................................... 7.00% 7.75%
Rate of increase in compensation levels............ 5.00% 5.00%
Weighted average expected long-term
rate of return on assets....................... 9.00% 9.00%
For purposes of calculating the postretirement benefit obligation, it is assumed
health care costs for covered individuals prior to age 65 will increase by 6.5%
in 2001 and that the rate of increase thereafter will decrease to an ultimate
rate of 5.5% by the year 2004. For covered individuals age 65 and older, it is
assumed health care costs will increase by 5.5% annually.
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 2000 would increase by $1.6 million, and the postretirement
benefit obligation at December 31, 2000, would increase by $16.5 million. If the
assumed health care trend rates were to decrease by 1.0%, the total service and
interest cost for 2000 would decrease by $1.4 million and the postretirement
benefit obligation at December 31, 2000, would decrease by $15.1 million.
19. 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. Based on public announcements, the Company
understands that Edison has not made payments to other qualifying facilities
("QFs") from which Edison purchases power and has not made scheduled payments of
debt service. Edison's senior unsecured debt obligations are currently rated
Caa2 (on watch for possible downgrade) by Moody's and D by S&P.
The Company is aware that there have been public announcements that Edison,
other industry participants and governmental entities have taken actions in
response to Edison's financial condition. These actions include the following:
o The Federal Energy Regulatory Commission ("FERC") has issued an order
eliminating requirements that Edison and other California utilities
purchase power from the structured power market in California in order
to provide them with an opportunity to obtain power from alternative
sources at a lower cost.
o The State of California has enacted legislation to provide for the
California Department of Water Resources to purchase wholesale power
and sell it to retain customers, which will be funded by a surcharge on
retail rates. The California legislature is also considering other
legislation to improve the financial condition of the California
electric utilities.
o The California Public Utilities Commission ("CPUC") approved a decision
on March 27, 2001 to increase retail electricity rates by approximately
40%. In another decision that day, the CPUC ordered Edison to pay QFs
on a go forward basis within 15 days of the invoice and purportedly
modified the calculation of Short Run Avoided Cost.
o The State of California and Edison have announced a preliminary
agreement for the State to purchase Edison's transmission assets for
$2.7 billion and to allow Edison to issue bonds for a substantial
portion of its under collection or revenues.
The Company can give no assurance as to the likely result of any of the actions
described above or as to whether such actions will have a positive effect on the
financial condition of Edison or its willingness to make payments under the
Power Purchase Agreements.
Edison has failed to pay approximately $76 million due to CE Generation
affiliates under the Power Purchase Agreements for power delivered in November
and December 2000 and January 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 and March 2001. Edison has not notified
the Company as to when it can expect to receive these payments. This continued
non-payment by Edison could result in an untenable situation for the continued
operation of the Imperial Valley Projects unless additional funds are obtained
in the near future.
On February 21, 2001, the Imperial Valley 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 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' Motion for Summary Adjudication and a Declaratory Judgment
ordering that: 1) under the Power Purchase Agreements, the Imperial Valley
Projects have the right to temporarily suspend deliveries of capacity and energy
to Edison, 2) the Imperial Valley 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. The Imperial Valley Projects intend to vigorously
pursue its other remedies in this action in light of Edison's continuing
non-payment.
The Company is hopeful that the current Edison situation is temporary and the
proceedings in the legal, regulatory, financial and political arenas will lead
to the improvement of Edison's financial condition in the near future and the
payment by Edison of amounts due under the Power Purchase Agreements. However,
no assurance can be given that this will be the case.
As a result of Edison's failure to make the payments due under the Power
Purchase Agreements and the recent downgrades of Edison's credit ratings,
Moody's has downgraded the ratings for the Salton Sea Funding Corp. project
related debt to Caa2 (negative outlook) and S&P has downgraded the ratings for
the project related debt to BBB- and has placed the project related debt on
"credit watch negative". Accordingly, the Funding Corporation does not believe
it is currently able to obtain funds in the banking or capital markets. However,
a failure by Edison to make these payments as well as subsequent monthly
payments, for a substantial period of time after the payments are due, is not
expected to have a material adverse effect on the ability of the Company to make
payments on its debt obligations. However, there can be no assurance that such a
failure by Edison would not cause a material adverse effect.
B. Decommissioning Costs
Based on site-specific decommissioning studies that include decontamination,
dismantling, site restoration and dry fuel storage cost, MidAmerican Energy's
share of expected decommissioning costs for Cooper and Quad Cities Station, in
2000 dollars, is $277 million and $266 million, respectively. In Illinois,
nuclear decommissioning costs are included in customer billings through a
mechanism that permits annual adjustments. These costs are reflected in base
rates in Iowa tariffs.
For purposes of developing a decommissioning funding plan for Cooper, Nebraska
Public Power District ("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, 2000, MidAmerican Energy's share of funds set aside in
internal and external accounts for decommissioning was $128.6 million. In
addition, the funding plan also assumes various funds and reserves currently
held to satisfy NPPD bond resolution requirements will be available for plant
decommissioning costs which is to begin with a 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.
MidAmerican Energy's expense for Cooper decommissioning components was $11.5 and
$9.1 million, for the year ended December 31, 2000 and the period from March 12,
1999 through December 31, 1999 and is included in operating expense. Earnings
from the internal account and external trust fund, which are recognized by NPPD
as the owner of the plant, are tax exempt and serve to reduce future funding
requirements.
External trusts have been established for the investment of funds for
decommissioning the Quad Cities Station. The total accrued balance as of
December 31, 2000, was $153.1 million and is included in other long-term accrued
liabilities and a like amount is reflected in nuclear decommissioning trust fund
and other marketable securities and represents the fair value of the assets held
in the trusts.
MidAmerican Energy's provision for depreciation included costs for Quad Cities
Station nuclear decommissioning of $8.3 million for year ended December 31, 2000
and $8.2 million for the period from March 12, 1999 through December 31, 1999.
The provision charged to 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%. Earnings, net of investment fees, on the assets
in the trust fund were $1.9 million for the year ended December 31, 2000 and
$1.6 million for the period from March 12, 1999 through December 31, 1999.
C. 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 the 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.
The 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 that 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, with coverage limits totaling $2.1 billion. For Cooper, MidAmerican
Energy and the 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 the 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 $8.5 million.
The master nuclear worker liability coverage, which is purchased by the 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 of
workers in nuclear-related industries.
20. Segment Information:
The Company has identified five reportable business segments principally based
on management structure: CalEnergy Generation-Domestic, CalEnergy
Generation-Foreign (primarily the Philippines), MidAmerican (domestic utility
operations), Northern (foreign utility operations) and HomeServices (real estate
operations). Information related to the Company's reportable operating segments
are shown below (in thousands).
MEHC (Predecessor)
-----------------------------------------------------
March 14, 2000 January 1, 2000
through through Year Ended December 31,
----------------------------
December 31, 2000 March 13, 2000 1999 1998
----------------- -------------- ---- ----
Revenue: (1)
CalEnergy Generation-Domestic........ $ 40,031 $ 4,520 $ 105,869 $ 583,311
CalEnergy Generation-Foreign......... 156,504 42,726 210,571 223,650
MidAmerican.......................... 1,930,122 447,583 1,469,348 -
Northern............................. 1,517,539 499,017 2,098,976 1,842,930
HomeServices......................... 405,805 66,880 357,728 -
------------ ----------- ----------- ------------
Segment Revenue...................... 4,050,001 1,060,726 4,242,492 2,649,891
Corporate............................ (9,403) 1,830 29,420 32,820
------------ ----------- ------------ ------------
$ 4,040,598 $ 1,062,556 $ 4,271,912 $ 2,682,711
============ =========== ============ ============
Depreciation and Amortization
CalEnergy Generation-Domestic........ $ 2,183 $ 250 $ 14,478 $ 122,111
CalEnergy Generation-Foreign......... 52,685 13,514 66,063 65,729
MidAmerican.......................... 184,955 45,184 182,638 -
Northern............................. 108,637 31,964 137,963 130,404
HomeServices.com..................... 8,695 2,891 7,772 -
------------ ----------- ------------ ------------
Segment Depreciation................. 357,155 93,803 408,914 318,244
Corporate/other...................... 26,196 3,475 18,776 15,178
------------ ----------- ------------ ------------
$ 383,351 $ 97,278 $ 427,690 $ 333,422
============ =========== =========== ============
MEHC (Predecessor)
------------------------------------------------------
March 14, 2000 January 1, 2000
through through Year Ended December 31,
-------------------------
December 31, 2000 March 13, 2000 1999 1998
----------------- -------------- ---- ----
Interest Expense net
CalEnergy Generation-Domestic........ $ 1,829 $ 793 $ 17,851 $ 80,721
CalEnergy Generation-Foreign......... 34,458 9,713 58,322 71,270
MidAmerican.......................... 94,425 24,579 100,046 -
Northern............................. 74,335 21,189 96,759 83,985
HomeServices.com..................... 2,328 785 3,228 -
------------ ----------- ------------ -----------
Segment Interest Expense, net........ 207,375 57,059 276,206 235,976
Corporate/other...................... 104,029 28,755 149,967 111,316
------------ ----------- ------------ -----------
$ 311,404 $ 85,814 $ 426,173 $ 347,292
============ =========== ============ ===========
Income before provisions for income taxes: (1)
CalEnergy Generation-Domestic........ $ 30,697 $ 2,877 $ 49,095 $ 232,303
CalEnergy Generation-Foreign......... 49,787 15,976 68,105 72,693
MidAmerican.......................... 181,797 63,315 151,555 -
Northern............................. 83,108 58,673 152,126 88,787
HomeServices......................... 31,015 (4,929) 16,613 -
------------ ----------- ----------- ---------
Segment income....................... 376,404 135,912 437,494 393,783
Corporate............................ (157,200) (37,137) (164,720) (121,730)
------------ ------------ ----------- ----------
$ 219,204 $ 98,775 $ 272,774 $ 272,053
============ =========== =========== ==========
Capital expenditures:
CalEnergy Generation-Domestic........ $ 151,289 $ 53,011 $ 145,255 $ 105,458
CalEnergy Generation-Foreign......... 87,781 22,263 95,552 204,301
MidAmerican.......................... 194,045 23,977 194,216 -
Northern (2)......................... 109,174 15,701 202,073 184,631
HomeServices......................... 6,996 2,052 9,143 -
------------ ----------- ----------- -----------
Segment capital expenditures......... 549,285 117,004 646,239 494,390
Corporate............................ 2,812 28 120 537
------------ ----------- ----------- -----------
$ 552,097 $ 117,032 $ 646,359 $ 494,927
============ =========== =========== ===========
(1) Before non-recurring items.
(2) Capital expenditures at the foreign utility exclude the effect of exchange
rate changes.
MEHC
(Predecessor)
As of December 31,
------------------
2000 1999
------------- -----------
Identifiable assets:
CalEnergy Generation-Domestic........... $ 968,444 $ 858,812
CalEnergy Generation-Foreign............ 1,188,445 1,270,516
MidAmerican............................. 5,392,273 5,072,788
Northern................................ 2,929,665 2,972,705
HomeServices............................ 163,101 162,714
----------- -----------
Segment identifiable assets............. 10,641,928 10,337,535
Corporate............................... 1,038,723 428,817
----------- -----------
$11,680,651 $10,766,352
============ ===========
Long-lived assets:
CalEnergy Generation-Domestic........... $ 731,276 $ 595,607
CalEnergy Generation-Foreign............ 960,835 956,433
MidAmerican............................. 4,079,250 3,995,763
Northern................................ 2,127,175 2,438,877
HomeServices............................ 125,894 128,024
---------- ----------
Segment long-lived assets............... 8,024,430 8,114,704
Corporate............................... 997,367 61,302
---------- ----------
$9,021,797 $8,176,006
========== ==========
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 and related amortization.
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, 2000 for the Company and as of December 31, 1999
for MEHC (Predecessor), and the related consolidated statements of operations,
stockholders' equity, and cash flows for the period January 1, 2000 to March 13,
2000 for MEHC (Predecessor) and for the period March 14, 2000 to December 31,
2000 for the Company, and for the years ended December 31, 1999 and 1998 for
MEHC (Predecessor). Our audits also included the financial statement schedule
listed in the Index at Item 14. These financial statements and financial
statement schedule are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements and
financial statement schedule 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 the Company as of December 31, 2000
and MEHC (Predecessor) as of December 31, 1999, 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 schedule, when considered in relation
to the basic consolidated financial statements taken as a whole, presents fairly
in all material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Des Moines, Iowa
January 18, 2001
(March 27, 2001 as to Notes 17 and 19.A.)
MidAmerican Energy Holdings Company Schedule I
Parent Company Only
Condensed Balance Sheets
As of December 31, 2000 and 1999
(In thousands)
2000 1999
----------- ----------
ASSETS
Current Assets:
Cash and cash equivalents................ $ 8,223 $ 240,938
----------- -----------
Total current assets................... 8,223 240,938
Investments in and advances to subsidiaries
and joint ventures....................... 3,087,166 3,138,484
Equipment, net.............................. 17,228 16,728
Excess of cost over fair value of net
assets acquired, net..................... 1,216,550 -
Deferred charges and other assets........... 166,287 158,887
---------- -----------
Total assets................................ $4,495,454 $3,555,037
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and other accrued
liabilities............................ $ 54,073 $ 82,055
Short term debt.......................... 85,000 -
---------- ----------
Total current liabilities.............. 139,073 82,055
Non-current liabilities..................... 6,435 6,435
Notes payable - affiliate................... 122,177 136,755
Parent company debt......................... 1,829,971 1,856,318
---------- ----------
Total liabilities........................ 2,097,656 2,081,563
---------- ----------
Deferred income............................. 34,874 28,886
Company-obligated mandatorily redeemable
preferred securities of subsidiary
trusts................................... 786,523 450,000
Stockholders' Equity:
Zero coupon convertible preferred stock -
authorized 50,000 shares, no par value,
34,563 shares outstanding at
December 31, 2000........................ - -
Common stock -authorized 60,000 and 180,000
shares, no par value; 9,281 and 82,980
shares issued, 9,281 and 59,944 shares
outstanding, at December 31, 2000 and
1999, respectively........................ - -
Additional paid in capital................... 1,553,073 1,249,079
Retained earnings............................ 81,257 507,726
Accumulated other comprehensive loss, net.... (57,929) (12,029)
Treasury stock - 23,036 common shares at
December 31, 1999 at cost................. - (750,188)
---------- -----------
Total stockholders' equity................... 1,576,401 994,588
---------- -----------
Total Liabilities and Stockholders' Equity... $4,495,454 $3,555,037
========== ==========
The notes to the consolidated MEHC financial statements are an integral part of
these financial statements.
MidAmerican Energy Holdings Company Schedule I
Parent Company Only (continued)
Condensed Statements of Operations
For the three years ended December 31, 2000
(In thousands)
2000 1999 1998
---- ---- ----
Revenue:
Equity in undistributed earnings of
subsidiary companies and joint ventures.. $390,194 $166,428 $205,049
Cash dividends and distributions from
subsidiary companies and joint ventures.. 96,342 345,430 179,782
Interest and other income.................... 13,818 34,002 44,686
-------- -------- --------
Total revenues............................ 500,354 545,860 429,517
-------- -------- --------
Expenses:
General and administration................... 45,089 39,174 28,584
Depreciation and amortization................ 25,716 1,088 1,943
Interest, net of capitalized interest........ 141,891 163,589 132,250
-------- -------- --------
Total expenses............................ 212,696 203,851 162,777
--------- -------- --------
Income before provision for income taxes..... 287,658 342,009 266,740
Provision for income taxes................... 84,285 93,475 93,265
-------- -------- --------
Income before minority interest.............. 203,373 248,534 173,475
Minority interest............................ 70,804 31,863 35,963
-------- -------- --------
Income before extraordinary items and cumulative
effect of change in accounting principle.. 132,569 216,671 137,512
Extraordinary items, net of tax.............. (49,441) (7,146)
Cumulative effect of change in accounting
principle, net of tax..................... - - (3,363)
-------- -------- --------
Net income available to common stockholders.. $132,569 $167,230 $127,003
======== ======== ========
The notes to the consolidated MEHC financial statements are an integral part of
these financial statements.
MidAmerican Energy Holdings Company Schedule I
Parent Company Only (continued)
Condensed Statements of Cash Flows
For the three years ended December 31, 2000
(In thousands)
2000 1999 1998
---------- ---------- ----------
Cash flows from operating activities.. $ (299,862) $ (261,276) $ (219,705)
---------- ---------- ----------
Cash flows from investing activities:
Decrease (increase) in advances to
and investments in subsidiaries
and joint ventures................. 143,052 (53,215) (103,494)
Acquisition of MEHC (Predecessor)..... (2,048,266) - -
Other................................. 28,458 (4,390) (24,328)
---------- --------- --------
Cash flows from investing activities.. (1,876,756) (57,605) (127,822)
---------- --------- --------
Cash flows from financing activities:
Proceeds from issuance of common and
preferred stock..................... 1,428,024 - -
Proceeds from issuance of parent
company debt........................ - - 1,502,243
Proceeds from issuance of trust
preferred securities................ 454,772 - -
Repayments of parent company debt...... - (853,420) (167,285)
Net proceeds from revolver............. 85,000 - -
Purchase of treasury stock............. - (104,847) (724,791)
Other.................................. (23,893) (4,208) (20,823)
--------- --------- ----------
Cash flows from financing activities... 1,943,903 (962,475) 589,344
---------- ---------- ---------
Net increase (decrease) in cash and
cash equivalents.................... (232,715) (1,281,356) 241,817
Cash and cash equivalents at beginning
of period........................... 240,938 1,522,294 1,280,477
------------ ---------- ----------
Cash and cash equivalents at end of
period.............................. $ 8,223 $ 240,938 $1,522,294
========= ========== ==========
Supplemental disclosures:
Interest paid (net of amount
capitalized)........................ $ 144,147 $ 180,274 $ 104,350
========= ========== =========
Income taxes paid...................... $ 94,405 $ 130,875 $ 53,609
========= ========== =========
The notes to the consolidated MEHC financial statements are an integral part of
these financial statements.
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, 2001.
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, 2001
- -------------------
David L. Sokol
Chairman of the Board,
Chief Executive Officer, and
Director
/s/ Gregory E. Abel* March 30, 2001
- --------------------
Gregory E. Abel
President, Chief Operating Officer and Director
/s/ Patrick J. Goodman* March 30, 2001
- -----------------------
Patrick J. Goodman
Senior Vice President and
Chief Financial Officer
/s/ Edgar D. Aronson* March 30, 2001
- ---------------------
Edgar D. Aronson
Director
/s/ Stanley J. Bright * March 30, 2001
- ----------------------
Stanley J. Bright
Director
/s/ Walter Scott, Jr.* March 30, 2001
- ----------------------
Walter Scott, Jr.
Director
/s/ Marc D. Hamburg * March 30, 2001
- ---------------------
Marc D. Hamburg
Director
/s/ Warren Buffett* March 30, 2001
- -------------------
Warren Buffett
Director
/s/ John Boyer* March 30, 2001
- ---------------
John Boyer
Director
/s/ W. David Scott* March 30, 2001
- -------------------
W. David Scott
Director
*By:/s/ Steven A. McArthur March 30, 2001
- ---------------------------
Steven A. McArthur
Attorney-in-Fact
EXHIBIT INDEX
3.1 Restated Articles of Incorporation of the Company.
3.2 Bylaws of the Company.
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.
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 refer-
ence 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 (incor-
porated 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., Mid-
American 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. (incorpor-
ated 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. (incor-
porated 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. (incor-
porated 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. (incor-
porated 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. (incor-
porated 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, Regis-
tration 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 Mid-
American 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 Com-
pensation 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 Mid-
west 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, Com-
mission 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.
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.
23.0 Consent of Independent Auditors
24.0 Power of Attorney.