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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)