UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[ X ] Annual Report Pursuant to Section 13 or 15 (d) of
the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2001
[ ] Transition Report Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
For the transition period from _____ to _____
Commission File No. 0-25551
MIDAMERICAN ENERGY HOLDINGS COMPANY
(Exact name of registrant as specified in its charter)
Iowa 94-2213782
---- ----------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
666 Grand Avenue, Des Moines, IA 50309
-------------------------------- -----
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (515) 242-4300
--------------
Securities registered pursuant to Section 12(b) of the Act: N/A
Securities registered pursuant to Section 12(g) of the Act: N/A
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days:
Yes X No
---------- -----------
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of Registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. [X]
All of the shares of MidAmerican Energy Holdings Company are held by a
limited group of private investors. As of March 28, 2002, 9,281,087 shares of
common stock were outstanding.
TABLE OF CONTENTS
PART I........................................................................3
Item 1. Business.............................................................3
General.......................................................................3
Teton Transaction.............................................................3
Business Strategy.............................................................3
Business of MEHC..............................................................4
MidAmerican Energy.....................................................4
CE Electric UK Funding.................................................8
CalEnergy Generation - Domestic.......................................12
CalEnergy Generation - Foreign....................................15
HomeServices......................................................17
Regulatory Matters...........................................................18
United States.........................................................18
United Kingdom........................................................19
Philippines...........................................................20
Environmental Regulation.....................................................20
United States.........................................................20
United Kingdom........................................................21
Employees....................................................................21
Item 2. Properties..........................................................22
Item 3. Legal Proceedings...................................................22
Item 4. Submission of Matters to a Vote of Security Holders.................26
PART II......................................................................27
Item 5. Market for Registrant's Common Equity and Related Stockholder's
Matters.............................................................27
Item 6. Selected Financial Data..............................................27
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations...............................................27
Item 7A. Qualitative and Quantitative Disclosures About Market Risk..........27
Item 8. Financial Statements and Supplementary Data..........................27
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure................................................27
PART III.....................................................................28
Item 10. Directors, Executive and Other Officers of the Company and
Significant Subsidiaries............................................28
Item 11. Executive Compensation..............................................30
Item 12. Security Ownership of Certain Beneficial Owners and Management......34
Item 13. Certain Relationships and Related Transactions......................35
PART IV......................................................................36
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K....36
SIGNATURES...................................................................99
EXHIBIT INDEX...............................................................101
PART I
Item 1. Business
General
MidAmerican Energy Holdings Company and its subsidiaries (the "Company"
or "MEHC") is a United States-based privately owned global energy company with
publicly traded fixed income securities. Through its subsidiaries, MidAmerican
Energy Company ("MidAmerican Energy") and CE Electric UK Funding, the Company
currently serves approximately 4.3 million electricity customers and 652,000
natural gas customers worldwide. In addition, through its subsidiaries, the
Company owns interests in over 10,000 megawatts ("MW") of diversified power
generation facilities in operation, construction and development. The Company's
Senior unsecured obligations have received investment grade ratings of Baa3,
BBB- and BBB from Moody's Investor Services Inc. ("Moody's"), Standard & Poors
Ratings Services ("S&P") and Fitch ("Fitch"). The Company's utility subsidiaries
are also investment grade rated by Moody's, S&P and Fitch: MidAmerican Energy
(A3, A- and AA-), Northern Electric, plc (A3, A- and A-) and Yorkshire
Electricity Group, plc (A3, A- and A-).
In this Annual Report, references to "U.S. dollars," "dollars," "US $,"
"$" or "cents" are to the currency of the United States and references to
"pounds sterling," "pounds," "sterling," "pence" or "p" are to the currency of
the United Kingdom.
The principal executive offices of the Company are located at 666 Grand
Avenue, Des Moines, Iowa 50309 and its telephone number is (515) 242-4300. The
Company was initially incorporated in 1971 under the laws of the State of
Delaware. The Company was reincorporated in 1999 in Iowa.
Teton Transaction
On March 14, 2000, the Company and an investor group comprised of
Berkshire Hathaway Inc., Walter Scott, Jr., a director of the Company, David L.
Sokol, Chairman and Chief Executive Officer of the Company, and Gregory E. Abel,
Chief Operating Officer of the Company closed on a definitive agreement and plan
of merger whereby the investor group acquired all of the outstanding common
stock of the Company (the "Teton Transaction"). As a result of the Teton
Transaction, Berkshire Hathaway, Mr. Scott, Mr. Sokol and Mr. Abel became the
sole shareholders of the Company in a "going private" transaction.
Business Strategy
The opportunity for independent power generation and energy distribution and
supply is a global competitive market as many countries have initiated
restructuring and privatization policies that encourage the development of
independent power generation and independent distribution and supply of energy.
The movement toward privatization in some developing countries has created new
markets. The need for economic expansion has caused many countries to select
private power development as their only practical alternative and to restructure
their legislative and regulatory systems to facilitate such development. The
Company intends to evaluate opportunities in these markets and to develop,
construct and acquire power generation, distribution and supply and related
energy projects meeting its strategic criteria both inside and outside the
United States. In addition, as privatization, deregulation and restructuring
initiatives are enacted in various countries and states, the Company will
evaluate opportunities to acquire power generation, distribution and supply
assets, as well as other energy related infrastructure assets.
In pursuing its strategy, the Company presently intends to focus upon
development and acquisition opportunities in countries possessing
characteristics that meet the Company's general investment criteria. At the
present time, the Company is active in the United States, the Philippines and
the United Kingdom.
Business of MEHC
The Company is a United States-based privately owned global energy
company with publicly traded fixed income securities that generates, distributes
and supplies energy to utilities, government entities, retail customers and
other customers located throughout the world. Through its subsidiaries, the
Company is organized and managed on five separate platforms: MidAmerican Energy,
CE Electric UK Funding, CalEnergy Generation-Domestic, CalEnergy
Generation-Foreign, and HomeServices.
MidAmerican Energy
MidAmerican Energy is the largest energy company headquartered in Iowa,
with assets at December 31, 2001 and 2001 revenues totaling $3.6 billion and
$2.7 billion, respectively. MidAmerican Energy is principally engaged in the
business of generating, transmitting, distributing and selling electric energy
and in distributing, selling and transporting natural gas. MidAmerican Energy
distributes electricity at retail in Iowa, Illinois and South Dakota. It also
distributes natural gas at retail in Iowa, Illinois, South Dakota and Nebraska.
As of December 31, 2001, MidAmerican Energy had 673,000 retail electric
customers and 652,000 retail natural gas customers.
In addition to retail sales, MidAmerican Energy sells electric energy
and natural gas to other utilities, marketers and municipalities outside of
MidAmerican Energy's delivery system. These sales are referred to as wholesale
sales. It also transports natural gas through its distribution system for a
number of end-use customers who have independently secured their supply of
natural gas.
MidAmerican Energy's regulated electric and gas operations are
conducted under franchises, certificates, permits and licenses obtained from
state and local authorities. The franchises, with various expiration dates, are
typically for 25-year terms.
MidAmerican Energy has a residential, agricultural, commercial and
diversified industrial customer group, in which no single industry or customer
accounted for more than 4% of its total 2001 electric operating revenues or 4%
of its total 2001 gas operating margin. Among the primary industries served by
MidAmerican Energy are those which are concerned with food products, the
manufacturing, processing and fabrication of primary metals, real estate, farm
and other non-electrical machinery, and cement and gypsum products.
For the year ended December 31, 2001, MidAmerican Energy derived
approximately 48% of its gross operating revenues from its regulated electric
business, 32% from its regulated gas business and 20% from its nonregulated
business activities. For 2000 and 1999, the corresponding percentages were 48%
electric, 37% gas and 15% nonregulated; and 63% electric, 30% gas and 7%
nonregulated, respectively. The change in revenue mix is principally driven by
an increase in natural gas prices and in nonregulated natural gas sales
activity.
There are seasonal variations in MidAmerican Energy's electric and gas
businesses, which are principally related to the use of energy for air
conditioning and heating. In 2001, 38% of MidAmerican Energy's regulated
electric revenues were reported in the months of June, July, August and
September, and 59% of MidAmerican Energy's regulated gas revenues were reported
in the months of January, February, March and December.
Electric Operations
The electric utility industry continues to undergo regulatory change.
Traditionally, prices charged by electric utility companies have been regulated
by federal and state commissions and have been based on cost of service. In
recent years, changes have been occurring that move the electric utility
industry toward a more competitive, market-based pricing environment. These
changes may have a significant impact on the way MidAmerican Energy does
business.
MidAmerican Energy manages its operations as four separate business
units: generation, energy delivery, transmission and marketing and sales. The
generation segment derives most of its revenue from the sale of regulated
wholesale electricity and nonregulated wholesale and retail natural gas. The
energy delivery segment derives its revenue principally from the delivery of
retail electricity and natural gas, while the transmission segment obtains most
of its revenue from the sale of transmission capacity. The marketing and sales
segment receives its revenue principally from nonregulated sales of natural gas
and electricity.
The following tables present historical regulated electric sales data
related to customer class and jurisdictions.
Total Regulated Electric Sales of MidAmerican Energy By Customer Class
2001 2000 1999
Residential 20.6% 20.7% 21.0%
Small General Service 15.3 15.9 16.7
Large General Service 25.8 28.6 26.9
Other 7.3 5.4 4.5
Sales for Resale 31.0 29.4 30.9
----- ----- -----
Total 100.0% 100.0% 100.0%
====== ====== ======
Regulated Retail Electric Sales of MidAmerican Energy By State
2001 2000 1999
Iowa 88.6% 89.3% 88.9%
Illinois 10.6 10.0 10.4
South Dakota 0.8 0.7 0.7
------ ------ ------
Total 100.0% 100.0% 100.0%
====== ====== ======
The annual hourly peak demand on MidAmerican Energy's electric system
occurs principally as a result of air conditioning use during the cooling
season. In August 2001, MidAmerican Energy recorded an hourly peak demand of
3,758 MW, which is 75 MW less than MidAmerican Energy's previous record hourly
peak of 3,833 MW set in 1999.
The following table sets out certain information concerning various MidAmerican
Energy power generation facilities:
- ------------------------- -------- ------- ------- ---------- ------------
Operating Project(1) Facility Net MW Fuel Location Commercial
Net MW Owned(2) Operation
- ------------------------- -------- ------- ------- ---------- ------------
Council Bluffs Energy
Center units 1 & 2 131 131 Coal Iowa 1954, 1958
- ------------------------- -------- ------- ------- ---------- ------------
Council Bluffs Energy
Center unit 3 675 534 Coal Iowa 1978
- ------------------------- -------- ------- ------- ---------- ------------
Louisa Generation
Station 700 616 Coal Iowa 1983
- ------------------------- -------- ------- ------- ---------- ------------
Neal Generation Station
units 1 & 2 435 435 Coal Iowa 1964, 1972
- ------------------------- -------- ------- ------- ---------- ------------
Neal Generation Station
unit 3 515 371 Coal Iowa 1975
- ---------------------------------- ------- ------- ---------- ------------
Neal Generation Station
unit 4 624 261 Coal Iowa 1979
- ------------------------- -------- ------- ------- ---------- ------------
Ottumwa Generation
Station 708 368 Coal Iowa 1981
- ------------------------- -------- ------- ------- ---------- ------------
Quad Cities
Generating Station 1,529 383 Nuclear Illinois 1972
- ------------------------- -------- ------- ------- ---------- ------------
Riverside Generation
Station 135 135 Coal Iowa 1925-61
- ------------------------- -------- ------- ------- ---------- ------------
Combustion Turbines 789 789 Gas/Oil Iowa 1969-95
- ------------------------- -------- ------- ------- ---------- ------------
Moline Water Power 3 3 Hydro Illinois 1970
- ------------------------- -------- ------- ------- ---------- ------------
Cooper Nuclear Station(3) 758 379 Nuclear Nebraska 1974
- ------------------------- -------- ------- ------- ---------- ------------
Portable Power Modules 56 56 Oil Iowa 2000
- ------------------------- -------- ------- ------- ---------- ------------
Total Operating Power
Generation Facilities 7,058 4,461
- ------------------------- -------- ------- ------- ---------- ------------
Projects Under
Construction:
- ------------------------ --------- ------- ------- ---------- ------------
Greater Des Moines
Energy Center 540 540 Gas Iowa 2003-05
- ------------------------ --------- ------- ------- ---------- ------------
Total Power
Generation Facilities 7,598 5,001
- ------------------------ --------- ------- ------- ---------- ------------
(1) The Company operates all such power generation facilities other than Quad
Cities Generating Station, Ottumwa Generation Station and Cooper Nuclear
Station.
(2) Actual MW may vary depending on operating and reservoir conditions and plant
design. Facility Net Capacity (in MW) represents facility gross capacity (in
MW) less parasitic load. Parasitic load is electrical output used by the
facility and not made available for sale to utilities or other outside
purchasers. Net MW owned indicates current legal ownership, but, in some cases,
does not reflect the current allocation of partnership distributions.
(3) Cooper is owned by the Nebraska Public Power District and the amount shown
is MidAmerican Energy's entitlement (50%) of Cooper's accredited capacity under
a power purchase contract extending to September 2004.
MidAmerican Energy's accredited net generating capability in the summer
of 2001 was 4,735 MW. Accredited net generating capability represents the amount
of generation available to meet the requirements on MidAmerican Energy's energy
system, net of the effect of capacity purchases and sales, and consists of
Company-owned generation and generation under power purchase contracts. The net
generating capability at any time may be less than it would otherwise be due to
regulatory restrictions, fuel restrictions and generating units being
temporarily out of service for inspection, maintenance, refueling or
modifications.
On July 10, 2001, MidAmerican Energy announced plans to develop and con-
struct two electric generating plants in Iowa, requiring an investment of
approximately $1.8 billion. Participation by others in a portion of the second
plant is being discussed. The two plants will provide approximately 1,400
megawatts of generating capacity. MidAmerican Energy expects to begin
construction in the Spring 2002 on the first project, the Greater Des Moines
Energy Center, a 540-megawatt natural gas-fired combined cycle unit that has an
estimated cost of $416 million. It is anticipated that the first phase of the
project will be completed in 2003 with the remainder being completed in 2005.
MidAmerican Energy presently expects that all utility construction expenditures
for the next five years will be met with the issuance of long-term debt and cash
generated from utility operations, net of dividends. The actual level of cash
generated from utility operations is affected by, among other things, economic
conditions in the utility service territory, weather and federal and state
regulatory actions.
MidAmerican Energy is interconnected with Iowa utilities and utilities
in neighboring states and is involved in an electric power pooling agreement
known as Mid-Continent Area Power Pool ("MAPP"). MAPP is a voluntary association
of electric utilities doing business in Minnesota, Nebraska, North Dakota and
the Canadian provinces of Saskatchewan and Manitoba and portions of Iowa,
Montana, South Dakota and Wisconsin. Its membership also includes power
marketers, regulatory agencies and independent power producers. MAPP facilitates
operation of the transmission system and is responsible for the safety and
reliability of the bulk electric system.
In November 2001, MAPPCOR, the contractor to MAPP, sold its
transmission-related assets to the Midwest Independent Transmission System
Operator, Inc. ("Midwest ISO"). The Midwest ISO now has responsibility for
administration of MAPP's Open-Access Transmission Tariff.
Each MAPP participant is required to maintain for emergency purposes a
net generating capability reserve of at least 15% above its system peak demand.
MidAmerican Energy's reserve margin at peak demand for 2001 was approximately
25%. However, significantly higher-than-normal temperatures during the cooling
season could cause MidAmerican Energy's reserve to fall below the 15% minimum.
If MidAmerican Energy fails to maintain the appropriate reserve, significant
penalties could be contractually imposed by MAPP.
MidAmerican Energy's transmission system connects its generating
facilities with distribution substations and interconnects with 14 other
transmission providers in Iowa and five adjacent states. Under normal operating
conditions, MidAmerican Energy's transmission system is unconstrained and has
adequate capacity to deliver energy to MidAmerican Energy's distribution system
and to export and import energy with other interconnected systems.
In December 1999, the Federal Energy Regulatory Commission ("FERC")
issued Order No. 2000 establishing, among other things, minimum characteristics
and functions for regional transmission organizations. Public utilities that
were not a member of an independent system operator at the time of the order
were required to submit a plan by which its transmission facilities would be
transferred to a regional transmission organization. On September 28, 2001
MidAmerican Energy and five other electric utilities filed with the FERC a plan
to create TRANSLink Transmission Company LLC and to integrate their electric
transmission systems into a single, coordinated system operating as a for-profit
independent transmission company in conjunction with a FERC-approved regional
transmission organization. FERC approval of the plan is pending. Transferring
operation and control of MidAmerican Energy's transmission assets to other
entities could increase costs for MidAmerican Energy; however, the actual impact
of TRANSLink on MidAmerican Energy's future transmission costs is not yet known.
Gas Operations
The following tables present historical regulated gas sales data,
excluding transportation throughput, related to customer class and
jurisdictions.
Total Regulated Gas Sales of MidAmerican Energy By Customer Class
2001 2000 1999
Residential 34.5% 34.9% 39.1%
Small General Service 18.2 17.4 19.8
Large General Service 1.5 2.2 2.4
Other 1.7 1.2 1.7
Sales for Resale 44.1 44.3 37.0
------ ------- ------
Total 100.0% 100.0% 100.0%
====== ======= ======
Regulated Retail Gas Sales of MidAmerican Energy By State
2001 2000 1999
Iowa 78.9% 78.0% 78.8%
Illinois 9.8 10.2 10.3
South Dakota 10.5 11.0 10.1
Nebraska 0.8 0.8 0.8
------ ------ ------
Total 100.0% 100.0% 100.0%
====== ====== ======
On February 2, 1996, MidAmerican Energy had its highest natural gas
peak-day delivery of 1,143,026 MMBtus. This peak-day delivery consisted of
approximately 88% traditional sales service and 12% transportation service of
customer-owned gas. MidAmerican Energy's 2001/2002 winter heating season
peak-day delivery of 932,615 MMBtus was reached on March 3, 2002. This peak-day
delivery included approximately 73% traditional sales service and 27%
transportation service.
MidAmerican Energy purchases gas supplies from producers and third party
marketers. To ensure system reliability, a geographically diverse supply
portfolio with varying terms and contract conditions is utilized for the gas
supplies.
MidAmerican Energy has rights to firm pipeline capacity to transport gas
to its service territory through direct interconnects to the pipeline systems of
Northern Natural Gas, Natural Gas Pipeline Company of America, Northern Border
Pipeline Company and ANR Pipeline Company. Firm capacity in excess of
MidAmerican Energy's system needs, resulting from differences between the
capacity portfolio and seasonal system demand, can be resold to other companies
to achieve optimum use of the available capacity. Past Iowa Utilities Board
("IUB") and South Dakota Public Utility Commission rulings have allowed
MidAmerican Energy to retain 30% of Iowa and South Dakota margins, respectively,
earned on the resold capacity, with the remaining 70% being returned to
customers through the purchased gas adjustment clause.
MidAmerican Energy's cost of gas is recovered from customers through
purchased gas adjustment clauses. In 1995, the IUB gave initial approval of
MidAmerican Energy's Incentive Gas Supply Procurement Program, which currently
has been extended through 2002. Under the program, as amended, MidAmerican
Energy is required to file with the IUB every six months a comparison of its gas
procurement costs to an index-based reference price. If MidAmerican Energy's
cost of gas for the period is less or greater than an established tolerance band
around the reference price, then MidAmerican Energy shares a portion of the
savings or costs with customers. A similar program is in effect in South Dakota.
Since the implementation of the program, MidAmerican Energy has successfully
achieved and shared savings with its natural gas customers.
MidAmerican Energy utilizes leased gas storage to meet peak day require-
ments and to manage the daily changes in demand due to changes in weather. The
storage gas is typically replaced during the summer months. In addition,
MidAmerican Energy also utilizes three liquefied natural gas plants and two
propane-air plants to meet peak day demands.
MidAmerican Energy has strategically built multiple pipeline
interconnections into several of its larger communities. Multiple pipeline
interconnects create competition among pipeline suppliers for transportation
capacity to serve those communities, thus reducing costs. In addition, multiple
pipeline interconnects give MidAmerican Energy the ability to optimize delivery
of the lowest cost supply from the various pipeline supply basins into these
communities and increase delivery reliability. Benefits to MidAmerican Energy's
system customers are shared with all jurisdictions through a consolidated
purchased gas adjustment clause.
CE Electric UK Funding
The business of CE Electric UK Funding consists of Northern Electric plc
("Northern"), Yorkshire Power Group Ltd. ("Yorkshire"), and CalEnergy Gas
(Holdings) Limited ("CE Gas").
Yorkshire Swap
On September 21, 2001, CE Electric UK Ltd., an indirect wholly owned
subsidiary of the Company, and Innogy Holdings, plc closed an agreement to
exchange Northern's electricity and gas supply and metering assets for Innogy's
94.75% interest in Yorkshire's electricity distribution business. Northern's
supply business was initially valued at approximately $430 million ((pound)295
million), including working capital of approximately $53 million ((pound)37
million). 94.75% of Yorkshire's distribution business was initially valued at
approximately $395 million ((pound)271 million), including working capital of
approximately $48 million ((pound)33 million). The net cash received by Northern
for the exchange was approximately $35 million ((pound)24 million). Working
capital is subject to adjustment and is currently under review.
The Company paid $37.4 million, net of cash acquired of $362.8 million
and transaction costs, for 94.75% of the Yorkshire electricity distribution
business and related indebtedness. The acquisition has been accounted for as a
purchase business combination. The results of operations for Yorkshire are
included in the Company's results beginning September 21, 2001. This transaction
provides the opportunity to build on Northern and Yorkshire's strong reputations
for customer satisfaction by bringing together the skills and resources of two
neighboring distribution businesses to create one of the largest distribution
companies in the U.K., serving more than 3.6 million customers in an area of
approximately 10,000 square miles.
Electricity Distribution
Northern's and Yorkshire's operations consist primarily of the distribu-
tion of electricity and other auxiliary businesses in the United Kingdom.
Through September 21, 2001, Northern's operations also included the supply of
electricity and natural gas and the related metering business.
Northern and Yorkshire receive electricity from the national grid
transmission system and distribute it to customers' premises using their network
of transformers, switchgear and cables. Substantially all of the customers in
their distribution service areas are connected to their network and can only be
delivered through their distribution system, thus providing Northern and
Yorkshire with distribution volume that is stable from year to year. Northern
and Yorkshire charge access fees for the use of the distribution system. The
prices for distribution are controlled by a prescribed formula that limits
increases (and may require decreases) based upon the rate of inflation in the
United Kingdom and other regulatory action.
Integrated Utility Services Limited ("IUS"), a subsidiary of Northern,
is an engineering company whose main role is to provide electrical connection
services on behalf of CE Electric UK Funding's distribution businesses and to
provide electrical infrastructure contracting services to third parties. The
acquisition by CE Electric UK Funding in 2001 of Yorkshire has presented IUS the
opportunity to integrate all Yorkshire and external work into IUS thereby
creating one of the largest electricity connection companies in the UK. The
focus for IUS is to achieve the full integration of the connections businesses.
To achieve this aim, IUS has already commenced with the establishment of a
customer services operations center at Middlesbrough and the commissioning of a
dedicated data management and telephone system to facilitate these objectives.
Northern Electric Generation Limited ("Northern Generation"), a CE
Electric UK Funding subsidiary, primarily focuses on electricity generation,
mainly through its ownership in Teesside (described below) and its operation and
ownership of Viking (described below).
Teesside. Teesside Power Limited ("Teesside") owns and operates an
1,875 net MW combined cycle gas-fired power plant at Wilton. Northern Generation
owns a 15.4% interest in Teesside, but does not operate the plant. Enron Corp.
("Enron"), through its subsidiaries, owned a 42.5% interest, operated the plant,
and purchased 668 MW of capacity. Enron's subsidiary, who owns and operates
Teesside, is now in administration and administrators have been appointed to run
its business and are attempting to find a buyer.
As a result of Enron's subsidiary being in administration, Teesside is
in discussion with its lenders over a restructuring of the (pound)650 million
debt still outstanding. It is anticipated that there will be no further
dividends arising from this investment and, as a result, Northern Generation has
written off its equity investments as they were estimated to be of negligible
value.
Viking. Northern Generation owns 50% of this 50 MW gas-fired mid merit
power plant located on Teesside. The plant is currently in the commissioning
stage, however due to combustor issues it is unable to pass the performance
criteria required for hand-over. Northern Generation is being held financially
whole by the turnkey contractor (Rolls Royce) until the plant is fit for purpose
at which time the plant will be operated by Northern Generation. CE Electric UK
Funding is currently negotiating to sell Viking to Rolls Royce for a value
consistent with the original investment appraisal.
Northern Electric Retail Limited ("Northern Retail"), a subsidiary of
CE Electric UK Funding, sells electrical and gas appliances.
Gas Exploration and Production
CE Gas is a gas exploration and production company which is focused on
developing integrated upstream gas projects. Its "upstream gas" business
consists of the exploration, development and production, including
transportation and storage, of gas for delivery to a point of sale into either a
gas supply market or a power generation facility. CE Gas holds various interests
in the southern basin of the United Kingdom sector of the North Sea, as shown
below. CE Gas has also been involved in certain gas development and exploration
activities relating to a large gas field prospect in Poland, the EP389
concession in the Perth Basin in Australia and the Yolla discovery in the Bass
Basin of Australia.
Share of 2001 Avg.
Remaining Net Current %
Reserves Production Working Commenced
Producing Gas Fields BCF(1) MMscf/d(2) Interest Production Location Gas Purchaser
- -------------------- --------- ---------- --------- ---------- -------- -------------
Anglia 61.0 13.5 55.000% 11/1991 U.K. Offshore (North Sea) Innogy plc
Windermere 6.2 3.9 20.000% 4/1997 U.K. Offshore (North Sea) N.V. Nederland's
Gasunic
Victor 7.7 3.5 5.000% 9/1984 U.K. Offshore (North Sea) British Gas
Trading Ltd.
Schooner 16.7 3.4 4.820% 10/1996 U.K. Offshore (North Sea) Innogy plc
Johnston 23.4 10.1 22.113% 10/1994 U.K. Offshore (North Sea) TXU Europe Energy
Trading Limited
Fields in Development Size Km2
- --------------------- --------
Pila Area Concession 9,480 N/A 100.000% N/A N.W. Poland (Polish Trough)
EP389 2,092 N/A 40.789% N/A S.W. Australia Onshore (Perth
Basin)
EP411 1,360 N/A 33.000% N/A S.W. Australia Onshore (Perth
Basin)
EP415 1,680 N/A 33.000% N/A S.W. Australia Onshore (Perth
Basin)
Yolla Discovery 550 N/A 20.000% N/A S.E. Australia Offshore (Bass
Basin)
Otway Basin 775 N/A 25.000% N/A S.E. Australia Offshore (Otway
Basin)
(1) Gas reserves in Billion cubic feet (or "Bcf") as of January 1, 2002. The
classification "Remaining" means reserves which geophysical, geological and
engineering data indicate to be in place or recoverable (as the case may be)
with a 50% probability the reserves will exceed the estimate.
(2) Million standard cubic feet per day.
CalEnergy Generation - Domestic
The following table sets out certain information concerning various domestic
independent power projects in operation.
- -------------------- -------- ------- ----- ------------ ---------- ------------
Project Facility Net MW Fuel Location Commercial Power
Net MW Owned1 Operation Purchaser2
- -------------------- -------- ------- ----- ------------ ---------- ------------
Cordova 537 537 Gas Illinois 2001 El Paso/MEC
- -------------------- -------- ------- ----- ------------ ---------- ------------
Salton Sea I 10 5 Geo California 1987 Edison
- -------------------- -------- ------- ----- ------------ ---------- ------------
Salton Sea II 20 10 Geo California 1990 Edison
- -------------------- -------- ------- ----- ------------ ---------- ------------
Salton Sea III 50 25 Geo California 1989 Edison
- -------------------- -------- ------- ----- ------------ ---------- ------------
Salton Sea IV 40 20 Geo California 1996 Edison
- -------------------- -------- ------- ----- ------------ ---------- ------------
Salton Sea V 49 25 Geo California 2000 El Paso/Zinc
- -------------------- -------- ------- ----- ------------ ---------- ------------
Vulcan 34 17 Geo California 1986 Edison
- -------------------- -------- ------- ----- ------------ ---------- ------------
Elmore 38 19 Geo California 1989 Edison
- -------------------- -------- ------- ----- ------------ ---------- ------------
Leathers 38 19 Geo California 1990 Edison
- -------------------- -------- ------- ----- ------------ ---------- ------------
Del Ranch 38 19 Geo California 1989 Edison
- -------------------- -------- ------- ----- ------------ ---------- ------------
CE Turbo 10 5 Geo California 2000 El Paso/Zinc
- -------------------- -------- ------- ----- ------------ ---------- ------------
Saranac 240 90 Gas New York 1994 NYSEG
- -------------------- -------- ------- ----- ------------ ---------- ------------
Power Resources 200 100 Gas Texas 1988 TXU
- -------------------- -------- ------- ----- ------------ ---------- ------------
Yuma 50 25 Gas Arizona 1994 SDG&E
- -------------------- -------- ------- ----- ------------ ---------- ------------
Roosevelt Hot
Springs 23 17 Geo Utah 1984 UP&L
- -------------------- -------- ------- ----- ------------ ---------- ------------
Total CalEnergy
Generation -
Domestic Operations 1,377 933
- -------------------- -------- ------- ----- ------------ ---------- ------------
1 Actual MW may vary depending on operating and reservoir conditions and plant
design. Facility Net Capacity (in MW) represents facility gross capacity (in MW)
less parasitic load. Parasitic load is electrical output used by the facility
and not made available for sale to utilities or other outside purchasers. Net MW
owned indicates current legal ownership, but, in some cases, does not reflect
the current allocation of partnership distributions.
2 Southern California Edison Company ("Edison"); San Diego Gas & Electric
Company ("SDGandE"); Utah Power & Light Company ("UP&L"); New York State
Electric & Gas Corporation ("NYSEG"); TXU Generation Company LP ("TXU"); Zinc
Recovery Project ("Zinc"); El Paso Corporation ("El Paso") and MidAmerican
Energy Company ("MEC").
Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned
subsidiary of the Company, operates a 537 MW gas-fired power plant in the Quad
Cities, Illinois area (the "Cordova Project"). The Cordova Project commenced
commercial operations in June 2001. Cordova Energy entered into a power purchase
agreement with a unit of El Paso Corporation ("El Paso") in which El Paso will
purchase all of the capacity and energy from the project until December 31,
2019. Cordova Energy exercised an option under the El Paso power purchase
agreement to callback 50% of the project output for sales to others for the
contract years ending on or prior to May 14, 2004. Cordova Energy subsequently
entered into a power purchase agreement with MidAmerican Energy whereby
MidAmerican Energy will purchase 50% of the capacity and energy from the Cordova
Project until May 14, 2004.
The Company has a 50% ownership interest in CE Generation LLC ("CE
Generation") which has interests in ten geothermal plants in the Imperial
Valley, California and three natural gas-fired cogeneration plants. For purposes
of consistent presentation, plant capacity factors for Vulcan, Hoch (Del Ranch),
Turbo, Elmore and Leathers (collectively the "Partnership Projects") are based
on capacity amounts of 34, 38, 10, 38, and 38 net MW, respectively, and for
Salton Sea I, Salton Sea II, Salton Sea III, Salton Sea IV and Salton Sea V
plants (collectively the "Salton Sea Projects") are based on capacity amounts of
10, 20, 50, 40 and 49 net MW, respectively (the Partnership Projects and the
Salton Sea Projects are collectively referred to as the "Imperial Valley
Projects"). Plant capacity factors for Saranac, Power Resources and Yuma
(collectively the "Gas Plants") are based on capacity amounts of 240, 200, and
50 net MW, respectively. Each plant possesses an operating margin that allows
for production in excess of the amount listed above. Utilization of this
operating margin is based upon a variety of factors and can be expected to vary
between calendar quarters, under normal operating conditions.
Imperial Valley Projects. The Vulcan Project, Hoch (Del Ranch) Project,
Elmore Project, Leathers Project, Salton Sea II Project and the Salton Sea III
Project sell electricity to Southern California Edison Company ("Edison") under
30-year Standard Offer No. 4 Agreements ("SO4 Agreements"). Under the SO4
Agreements, Edison is obligated to pay capacity payments, capacity bonus
payments and energy payments. The price for contract capacity payments is fixed
for the life of such SO4 Agreement. The contract energy payment was fixed for
the first ten years. The fixed price periods for the Vulcan, Del Ranch, Elmore,
Leathers, Salton Sea II and Salton Sea III Projects expired in February 1996,
January 1999, December 1998, December 1999, April 2000, and February 1999,
respectively. Thereafter, the energy payments are based on the cost Edison
avoids by purchasing energy from the projects instead of obtaining the energy
from other sources ("Avoided Cost of Energy").
In June and November 2001, the Imperial Valley Projects which receive
Edison`s Avoided Cost of Energy, entered into agreements that provide for
amended energy payments under the SO4 Agreements. The amendments provide for
fixed energy payments per kWh in lieu of Edison's Avoided Cost of Energy. The
fixed energy payment is 3.25 cents per kWh from December 1, 2001 through April
30, 2002 and 5.37 cents per kWh commencing May 1, 2002 for a five year period.
Following the five year period, the energy payments revert back to Edison's
Avoided Cost of Energy.
The Salton Sea I Project and Salton Sea IV Project have negotiated
contracts with Edison. The Salton Sea I contract provides for a capacity payment
and energy payment for the life of the contract. Both payments are based upon an
initial value that is subject to quarterly adjustment by reference to various
inflation-related indices. The Salton Sea IV contract also provides for fixed
price capacity payments for the life of the contract. Approximately 56% of the
kWhs are sold under the Salton Sea IV Power Purchase Agreement at a fixed energy
price, which is subject to quarterly adjustment by reference to various
inflation-related indices, through June 20, 2017 (and at Edison's Avoided Cost
of Energy thereafter), while the remaining 44% of the Salton Sea IV Project kWhs
are sold according to a 10-year fixed price schedule followed by payments based
on a modified Avoided Cost of Energy for the succeeding 5 years and at Edison's
Avoided Cost of Energy thereafter.
The Salton Sea V Project began operations in 2000 and will sell approxi-
mately one-third of its net output to the Zinc Recovery Project which is
expected to become operational in 2002. The remainder is being sold through
other market transactions.
The net output of the Turbo Project is being sold through market trans-
actions but may be sold to the Zinc Recovery Project when completed.
Yuma Project. The Yuma Project is a 50 net MW natural gas-fired
cogeneration project in Yuma, Arizona providing 50 MW of electricity to San
Diego Gas & Electric Company ("SDG&E") under an existing 30-year power purchase
agreement ("Yuma PPA"). The project entity, Yuma Cogeneration Associates
("YCA"), has executed steam sales contracts with an adjacent industrial entity
to act as its thermal host. Since the industrial entity has the right under its
agreement to terminate the agreement upon one year's notice if a change in its
technology eliminates its need for steam, and in any case to terminate the
agreement at any time upon three years notice, there can be no assurance that
the Yuma Project will maintain its status as a qualifying facility ("QF").
However, if the industrial entity terminates the agreement, YCA anticipates that
it will be able to locate an alternative thermal host in order to maintain its
status as a QF.
Saranac Project. The Saranac Project is a 240 net MW natural gas-fired
cogeneration facility located in Plattsburgh, New York. The Saranac Project has
entered into a 15-year power purchase agreement (the "Saranac PPA") with New
York State Electric & Gas ("NYSEG"). The Saranac Project is a QF and has entered
into 15-year steam purchase agreements (the "Saranac Steam Purchase Agreements")
with Georgia-Pacific Corporation and Tenneco Packaging, Inc. The Saranac Project
has a 15-year natural gas supply agreement (the "Saranac Gas Supply Agreement")
with Shell Canada Limited ("Shell Canada") to supply 100% of the Saranac
Project's fuel requirements. Shell Canada is responsible for production and
delivery of natural gas to the U.S.-Canadian border; the gas is then transported
by the North Country Gas Pipeline Corporation ("NCGP") the remaining 22 miles to
the plant. NCGP is a wholly-owned subsidiary of Saranac Power Partners, L.P.
(the "Saranac Partnership"), which also owns the Saranac Project. NCGP also
transports gas for NYSEG and Georgia-Pacific. Each of the Saranac PPA, the
Saranac Steam Purchase Agreements and the Saranac Gas Supply Agreement contains
rates that are fixed for the respective contract terms. Revenues escalate at a
higher rate than fuel costs. The Saranac Partnership is indirectly owned by
subsidiaries of CE Generation, Tomen Corporation and General Electric Capital
Corporation.
Power Resources Project. The Power Resources Project is a 200 net MW
natural gas-fired cogeneration project located near Big Spring, Texas, which has
a 15-year power purchase agreement (the "Power Resources PPA") with TXU
Generation Company LP, formerly known as Texas Utilities Electric Company. The
Power Resources Project is a QF and the project entity, Power Resources Ltd.
("Power Resources"), has entered into a 15-year steam purchase agreement (the
"Power Resources Steam Purchase Agreement") with Fina Oil and Chemical Company
("Fina"), a subsidiary of Petrofina S.A. of Belgium. Power Resources has entered
into an agreement (the "CE Texas Gas Supply Agreement") with CE Texas Gas L.P.
("CE Texas Gas") for Power Resources' fuel requirements through December 2003.
In June 1995, CE Texas Gas and Louis Dreyfus Natural Gas Corp. ("Dreyfus")
executed an eight-year natural gas supply agreement (the "CE Texas Gas-Dreyfus
Gas Supply Agreement"), with which CE Texas Gas will fulfill its supply
commitment to Power Resources from October 1995 to the end of the term of the
Power Resources PPA. Each of the Power Resources PPA, the Power Resources Steam
Purchase Agreement and the CE Texas Gas-Dreyfus Gas Supply Agreement contains
rates that are fixed for the respective contract terms. Revenues escalate at a
higher rate than fuel costs.
Roosevelt Hot Springs. A subsidiary of the Company operates and owns an
approximately 70% indirect interest in a geothermal steam field which supplies
geothermal steam to a 23 net MW power plant owned by Utah Power & Light Company
("UP&L") located on the Roosevelt Hot Springs property under a 30-year steam
sales contract. The Company obtained approximately $20.3 million of cash under a
pre-sale agreement with UP&L whereby UP&L paid in advance for the steam produced
by the steam field. The Company must make certain penalty payments to UP&L if
the steam produced does not meet certain quantity and quality requirements.
Zinc Recovery Project. The Company owns the rights to proprietary
processes for the extraction of minerals from elements in solution in the
geothermal brine and fluids utilized at its Imperial Valley plants. A pilot
plant has successfully produced commercial quality zinc at the Company's
Imperial Valley Projects.
CalEnergy Minerals LLC, an indirect wholly owned subsidiary of the
Company, is constructing the Zinc Recovery Project which will recover zinc from
the geothermal brine (the "Zinc Recovery Project"). Facilities are being
installed near the Imperial Valley Project's sites to extract a zinc chloride
solution from the geothermal brine through an ion exchange process. This
solution will be transported to a central processing plant where zinc ingots
will be produced through solvent extraction, electrowinning and casting
processes. The Zinc Recovery Project is designed to have a capacity of
approximately 30,000 metric tons per year and is scheduled to commence
commercial operations in 2002. In September 1999, CalEnergy Minerals LLC entered
into a sales agreement whereby all zinc produced by the Zinc Recovery Project
will be sold to Cominco, Ltd. The initial term of the agreement expires in
December 2005.
Salton Sea Minerals Extraction. In addition to zinc recovery, the
Company intends to sequentially develop manganese, silver, gold, lead, boron,
lithium and other products as it further develops the extraction technology. If
successfully developed for the other products, the mineral extraction process
will provide an environmentally responsible and low cost minerals recovery
methodology.
CalEnergy Generation - Foreign
The following table sets out certain information concerning various foreign
independent power projects in operation.
- ------------------- -------- ------ ----- ----------- ---------- -------- ------------ ---------
Political
Facility Net MW Commercial U.S. $ Power Risk
Project Net MW Owned(1) Fuel Location Operation Payments Purchaser(2) Insurance
- ------------------- -------- ------ ----- ----------- ---------- -------- ------------- --------
Mahanagdong 165 149 Geo Philippines 1997 Yes PNOC-EDC GOP Yes
- ------------------- -------- ------ ----- ----------- --------- -------- ------------- ---------
Malitbog 216 216 Geo Philippines 1996-97 Yes PNOC-EDC GOP Yes
- ------------------- -------- ------ ----- ------------ --------- -------- ------------- --------
Upper Mahiao 119 119 Geo Philippines 1996 Yes PNOC-EDC GOP Yes
- ------------------- -------- ------ ----- ----------- ---------- -------- ------------- --------
Casecnan 150 150(3) Hydro Philippines 2001 Yes NIA GOP Yes
- ------------------- -------- ------ ----- ----------- ---------- -------- ------------- --------
Total CalEnergy
Generation -
Foreign Operations 650 634
- ------------------- -------- ------ ------ ---------- ---------- -------- ------------- --------
(1) Actual MW may vary depending on operating and reservoir conditions and plant
design. Facility Net Capacity (in MW) represents facility gross capacity (in MW)
less parasitic load. Parasitic load is electrical output used by the facility
and not made available for sale to utilities or other outside purchasers. Net MW
owned indicates current legal ownership, but, in some cases, does not reflect
the current allocation of partnership distributions.
(2) PNOC - Energy Development Corporation ("PNOC-EDC"); Government of the
Philippines ("GOP") and Philippine National Irrigation Administration ("NIA")
(NIA also purchases water from this facility). The Government of the Philippine
undertaking supports PNOC-EDC's and NIA's respective obligations.
(3) Subject to certain repurchase rights by the initial minority shareholders
The Company indirectly owns the Upper Mahiao, Malitbog and Mahanagdong
Projects (collectively, the "Leyte Projects"), which are geothermal power plants
located on the island of Leyte in the Philippines, and the Casecnan Project, a
combined irrigation and hydroelectric power generation project, which is located
in the central part of Island of Luzon in the Philippines. The Casecnan Project
commenced commercial operations on December 11, 2001. For purposes of consistent
presentation, capacity amounts for Upper Mahiao, Malitbog, Mahanagdong and
Casecnan are 119, 216, 165 and 150 net MW, respectively. Each plant possesses an
operating margin that allows for production in excess of the amount listed
above. Utilization of this operating margin is based upon a variety of factors
and can be expected to vary between calendar quarters, under normal operating
conditions.
Upper Mahiao. The Upper Mahiao facility is a 119 net MW geothermal
power project owned and operated by CE Cebu Geothermal Power Company, Inc. ("CE
Cebu"), a Philippine corporation that is 100% indirectly owned by the Company.
The Upper Mahiao facility has been in commercial operation since June 17, 1996.
Under the terms of an energy conversion agreement executed on September
6, 1993 (the "Upper Mahiao ECA"), CE Cebu owns and operates the Upper Mahiao
Project during the ten-year cooperation period, which commenced in June, 1996
after which ownership will be transferred to PNOC-Energy Development Corporation
("PNOC-EDC") at no cost.
The Upper Mahiao Project is located on land provided by PNOC-EDC at no
cost. It takes geothermal steam and fluid, also provided by PNOC-EDC at no cost,
and converts its thermal energy into electrical energy which is sold to PNOC-EDC
on a "take-or-pay" basis. Specifically, PNOC-EDC is obligated to pay for 100% of
the electric capacity that is nominated each year by CE Cebu, irrespective of
whether PNOC-EDC is willing or able to accept delivery of such capacity.
PNOC-EDC pays to CE Cebu a fee (the "Capacity Fee") based on the plant capacity
nominated to PNOC-EDC in any year (which, at the plant's design capacity, is
approximately 95% of total contract revenues) and a fee (the "Energy Fee") based
on the electricity actually delivered to PNOC-EDC (approximately 5% of total
contract revenues). Payments under the Upper Mahiao ECA are denominated in U.S.
dollars, or computed in U.S. dollars and paid in Philippine pesos at the
then-current exchange rate, except for the Energy Fee. Significant portions of
the Capacity Fee and Energy Fee are indexed to U.S. and Philippine inflation
rates, respectively. PNOC-EDC's payment requirements, and its other obligations
under the Upper Mahiao ECA, are supported by the Government of the Philippines
through a performance undertaking.
The payment of the Capacity Fee is not excused if PNOC-EDC fails to
deliver or remove the steam or fluids or fails to provide the transmission
facilities, even if its failure was caused by a force majeure event (e.g., war,
nationalization, etc.). In addition, PNOC-EDC must continue to make Capacity Fee
payments if there is a force majeure event that affects the operation of the
Upper Mahiao Project and that is within the reasonable control of PNOC-EDC or
the Government of the Philippines or any agency or authority thereof.
PNOC-EDC is obligated to purchase CE Cebu's interest in the facility
under certain circumstances, including (i) extended outages resulting from the
failure of PNOC-EDC to provide the required geothermal fluid, (ii) certain
material changes in policies or laws which adversely affect CE Cebu's interest
in the project, (iii) transmission failure, (iv) failure of PNOC-EDC to make
timely payments of amounts due under the Upper Mahiao ECA, (v) privatization of
PNOC-EDC or NPC, and (vi) certain other events. The price will be the net
present value (at a discount rate based on the last published Commercial
Interest Reference Rate of the Organization for Economic Cooperation and
Development) of the total remaining amount of Capacity Fees over the remaining
term of the Upper Mahiao ECA.
Mahanagdong. The Mahanagdong Project is a 165 net MW geothermal power
project owned and operated by CE Luzon Geothermal Power Company, Inc. ("CE
Luzon"), a Philippine corporation of which 100% of the common stock is
indirectly owned by the Company. Another industrial company owns an approximate
10% preferred equity interest in the project. The Mahanagdong Project has been
in commercial operation since July 25, 1997. The Mahanagdong Project sells 100%
of its capacity on a similar basis as described above for the Upper Mahiao
Project to PNOC-EDC, which in turn sells the power to the Philippine National
Power Corporation ("NPC") for distribution to the island of Luzon.
The terms of an energy conversion agreement executed on September 18,
1993 (the "Mahanagdong ECA"), are substantially similar to those of the Upper
Mahiao ECA. The Mahanagdong ECA provides for a ten-year cooperation period. At
the end of the cooperation period, the facility will be transferred to PNOC-EDC
at no cost. All of PNOC-EDC's obligations under the Mahanagdong ECA are
supported by the Government of the Philippines through a performance
undertaking. The capacity fees are approximately 97% of total revenues at the
design capacity levels and the energy fees are approximately 3% of such total
revenues.
Malitbog. The Malitbog Project is a 216 net MW geothermal project owned
and operated by Visayas Geothermal Power Company ("VGPC"), a Philippine general
partnership that is wholly owned, indirectly, by the Company. The three units of
the Malitbog facility were put into commercial operation on July 25, 1996 (for
Unit I) and July 25, 1997 (for Units II and III). VGPC is selling 100% of its
capacity on substantially the same basis as described above for the Upper Mahiao
Project to PNOC-EDC, which sells the power to NPC.
The Malitbog Project is located on land provided by PNOC-EDC at no cost.
The electrical energy produced by the facility is sold to PNOC-EDC on a take-or-
pay basis. Specifically, PNOC-EDC is obligated to make payments (the "Capacity
Payments") to VGPC based upon the available capacity of the Malitbog Project.
The Capacity Payments equal approximately 100% of total revenues. The Capacity
Payments will be payable so long as the Malitbog Project is available to produce
electricity, even if the Malitbog Project is not operating due to scheduled
maintenance, because PNOC-EDC fails to supply steam to the Malitbog Project as
required or because NPC is unable (or unwilling) to accept delivery of
electricity from the Malitbog Project. In addition, PNOC-EDC must continue to
make the Capacity Payments if there is a force majeure event (e.g., war,
nationalization, etc.) that affects the operation of the Malitbog Project and
that is within the reasonable control of PNOC-EDC or the Government of the
Philippines or any agency or authority thereof. A substantial majority of the
Capacity Payments are required to be made by PNOC-EDC in dollars. The portion of
Capacity Payments payable to PNOC-EDC in pesos is expected to vary over the term
of the Malitbog ECA from 10% of VGPC's revenues in the early years of the
Cooperation Period (as defined below) to 23% of VGPC's revenues at the end of
the Cooperation Period. Payments made in pesos will generally be made to a
peso-dominated account and will be used to pay peso-denominated operation and
maintenance expenses with respect to the Malitbog Project and Philippine
withholding taxes, if any, on the Malitbog Project's debt service. The
Government of the Philippines has entered into a performance undertaking, which
provides that all of PNOC-EDC's obligations pursuant to the Malitbog ECA carry
the full faith and credit of, and are affirmed and guaranteed by, the Government
of the Philippines.
PNOC-EDC is obligated to purchase VGPC's interest in the facility under
certain circumstances, including (i) certain material changes in policies or
laws which adversely affect VGPC's interest in the project, (ii) any event of
force majeure which delays performance by more than 90 days and (iii) certain
other events. The price will be the net present value of the capital cost
recovery fees that would have been due for the remainder of the Cooperation
Period with respect to such generating unit(s).
The Malitbog ECA cooperation period expires ten years after the date of
commencement of commercial operation of Unit III (the "Cooperation Period"). At
the end of the Cooperation Period, the facility will be transferred to PNOC-EDC
at no cost, on an "as is" basis.
Casecnan. CE Casecnan Water and Energy Company, Inc., a Philippine
corporation ("CE Casecnan") and an indirectly majority owned subsidiary of the
Company, operates the Casecnan Project, a combined irrigation and 150 net MW
hydroelectric power generation project (the "Casecnan Project"). The Casecnan
Project consists generally of diversion structures in the Casecnan and Taan
Rivers that captures and diverts excess water in the Casecnan watershed by means
of concrete, in-stream diversion weirs and transfers that water through a
transbasin tunnel of approximately 23 kilometers (including the intake audit
from the Taan to the Casecnan River), with a diameter of approximately 6.5
meters to an existing underutilized water storage reservoir at Pantabangan.
During the water transfer, the elevation differences between the two watersheds
allows electrical energy to be generated at a 150 net MW rated capacity power
plant, which is located in an underground powerhouse cavern at the end of the
water tunnel. A tailrace discharge tunnel of approximately three kilometers
delivers water from the water tunnel and the powerhouse to the Pantabangan
Reservoir, providing additional water for irrigation and increasing the
potential electrical generation at two downstream existing hydroelectric
facilities of NPC, the government-owned and controlled corporation that is the
primary supplier of electricity in the Philippines.
CE Casecnan constructed the Casecnan Project under the terms of the
Project Agreement between CE Casecnan and the National Irrigation Administration
("NIA"). Under the Project Agreement, CE Casecnan developed, financed and
constructed the Casecnan Project over the construction period, and will own and
operate the Casecnan Project for 20 years (the "Cooperation Period"). During the
Cooperation Period, NIA is obligated to accept all deliveries of water and
energy, and so long as the Casecnan Project is physically capable of operating
and delivering in accordance with agreed levels set forth in the Project
Agreement, NIA will pay CE Casecnan a fixed fee for the delivery of a minimum
volume of water and a fixed fee for the delivery of a minimum amount of
electricity. In addition, NIA will pay a fee for all electricity delivered in
excess of a threshold amount up to a specified amount. NIA will sell the
electricity it purchases to NPC, although NIA's obligations to CE Casecnan under
the Project Agreement are not dependent on NPC's purchase of the electricity
from NIA. All fees to be paid by NIA to CE Casecnan are payable in U.S. dollars.
The fixed fees for the delivery of water and energy, regardless of the amount of
electricity or water actually delivered, are expected to provide approximately
78% of CE Casecnan's revenues. At the end of the Cooperation Period, the
Casecnan Project will be transferred to NIA and NPC for no additional
consideration on an "as is" basis.
The Project Agreement provides for additional compensation to CE
Casecnan upon the occurrence of certain events, including increases in
Philippine taxes and adverse changes in Philippine law. Upon the occurrence and
during the continuance of certain force majeure events, including those
associated with Philippine political action, NIA may be obligated to buy the
Casecnan Project from CE Casecnan at a buy out price expected to be in excess of
the aggregate principal amount of the outstanding CE Casecnan debt securities,
together with accrued but unpaid interest.
The Republic of the Philippines has provided a performance undertaking
under which NIA's obligations under the Project Agreement are guaranteed by the
full faith and credit of the Republic of the Philippines ("Performance
Undertaking"). The Project Agreement and the Performance Undertaking provide for
the resolution of disputes by binding arbitration in Singapore under
international arbitration rules.
HomeServices
HomeServices.Com Inc. ("HomeServices"), a wholly-owned subsidiary of the
Company, is the second largest residential real estate brokerage firm in the
United States based on aggregate closed transaction sides in 2001 for its
various brokerage firm operating subsidiaries. Closed transaction sides mean
either the buy side or sell side of any closed home purchase and is the standard
term used by industry participants and publications to rank real estate
brokerage firms. In addition to providing traditional residential real estate
brokerage services, HomeServices cross sells to its existing real estate
customers preclosing services, such as mortgage origination and title services,
including title insurance, title search, escrow and other closing administrative
services, assists in securing other preclosing and postclosing services provided
by third parties, such as home warranty, home inspection, home security,
property and casualty insurance, home maintenance, repair and remodeling and is
developing various related e-commerce services. HomeServices currently operates
in the following fourteen states: Minnesota, Iowa, California, Arizona, Kansas,
Missouri, Kentucky, Nebraska, Wisconsin, Indiana, Maryland, North Dakota, South
Dakota and Georgia. HomeServices generally occupies the number one or number two
market share position in each of its major markets based on aggregate closed
transaction sides for the year ended December 31, 2001. HomeServices' major
markets consist of the following metropolitan areas: Minneapolis and St. Paul,
Minnesota; Des Moines, Iowa; Los Angeles and San Diego, California; Omaha,
Nebraska; Kansas City, Kansas; Louisville, Kentucky; Springfield, Missouri;
Tucson, Arizona; Annapolis, Maryland and Atlanta, Georgia.
Regulatory Matters
United States
Each of the operating domestic power facilities partially owned through
CE Generation meets the requirements promulgated under the Public Utility
Regulatory Policies Act ("PURPA") to be qualifying facilities. Qualifying
facility status under PURPA provides two primary benefits. First, regulations
under PURPA exempt qualifying facilities from the Public Utility Holding Company
Act of 1935, as amended ("PUHCA"), most provisions of the Federal Power Act (the
"FPA") and the state laws concerning rates of electric utilities, and financial
and organization regulations of electric utilities. Second, FERC's regulations
promulgated under PURPA require that (1) electric utilities purchase electricity
generated by qualifying facilities, the construction of which commenced on or
after November 9, 1978, at a price based on the purchasing utility's Avoided
Cost of Energy, (2) the electric utility sell back-up, interruptible,
maintenance and supplemental power to the qualifying facility on a
non-discriminatory basis, and (3) the electric utility interconnect with a
qualifying facility in its service territory.
Congress is considering proposed legislation that would amend PURPA by
eliminating the requirement that utilities purchase electricity from qualifying
facilities at prices based on Avoided Cost of Energy. The Company does not know
whether such legislation will be passed or what form it may take. The Company
believes that if any such legislation is passed, it would apply to new projects
only and thus, although potentially impacting the Company's ability to develop
new domestic projects, it would not affect the Company's existing qualifying
facilities. There can be no assurance, however, that any legislation passed
would not adversely impact the Company's existing domestic projects.
In addition, many states are implementing or considering regulatory
initiatives designed to increase competition in the domestic power generation
industry and increase access to electric utilities' transmission and
distribution systems for independent power producers and electricity consumers.
On September 1, 1996, the California legislature adopted an industry
restructuring bill that would provide for a phased-in competitive power
generation industry with an independent system operator and direct access to
generation for all power purchasers under certain circumstances. Under the bill,
consistent with the requirements of PURPA, the existing qualifying facilities
power sales agreements would be honored. The Company cannot predict the final
form or timing of the proposed industry restructuring or the impact on its
operations.
MidAmerican Energy is subject to comprehensive regulation by several
utility regulatory agencies that significantly influences the operating
environment and the recoverability of costs from utility customers. That
regulatory environment has to date, in general, given MidAmerican Energy an
exclusive right to serve electricity customers within its service territory and,
in turn, the obligation to provide electric service to those customers.
In connection with the March 1999 approval by the IUB of the MidAmerican
acquisition and March 2000 affirmation as part of the Teton Transaction, the
Company is required, among other things, to use all commercially reasonable
efforts to maintain an investment grade credit rating for MidAmerican Energy and
its long-term debt and to seek the approval of the IUB of a reasonable utility
capital structure if MidAmerican Energy's common equity level decreases below
specified levels (42% and 39%, respectively, of total capitalization) under
certain circumstances. MidAmerican Energy's common equity level at December 31,
2001 was above these levels.
With the elimination of the energy adjustment clause in Iowa,
MidAmerican Energy is financially exposed to movements in energy prices.
Although MidAmerican Energy has sufficient low cost generation under typical
operating conditions for its retail electric needs, a loss of adequate
generation by MidAmerican Energy requiring the purchase of replacement power at
a time of high market prices could subject MidAmerican Energy to losses on its
energy sales.
In December 1997, the Governor of Illinois signed into law a bill to
restructure Illinois' electric utility industry and transition it to a
competitive market. Under the law, larger non-residential customers in Illinois
and 33% of the remaining non-residential Illinois customers were allowed to
select their provider of electric supply services beginning in October 1, 1999.
Starting December 31, 2000, all other non-residential customers were allowed
supplier choice. Residential customers all receive the opportunity to select
their electric supplier beginning May 1, 2002.
The law also provides for Illinois earnings above a computed level of
return on common equity to be shared equally between customers and MidAmerican
Energy. MidAmerican Energy's computed level of return on common equity is based
on a rolling two-year average of the 30-year Treasury Bond rates plus a premium
of 5.5% for 1998 and 1999 and a premium of 8.5% for 2000 through 2004. The
two-year average above which sharing must occur for 2001 was 14.34%. The law
allows MidAmerican Energy to mitigate the sharing of earnings above the
threshold return on common equity through accelerated recovery of regulatory
assets.
In December 1999, FERC issued Order No. 2000 establishing among other
things minimum characteristics and functions for regional transmission
organizations. Public utilities that were not a member of an independent system
operator at the time of the order were required to submit a plan by which its
transmission facilities would be transferred to a regional transmission
organization. On September 28, 2001, MidAmerican Energy and five other electric
utilities filed with FERC a plan to create TRANSLink Transmission Company LLC
and to integrate their electric transmission systems into a single, coordinated
system operating as a for-profit independent transmission company in conjunction
with a FERC approved regional transmission organization. FERC approval of the
plan is pending. Transferring operation and control of MidAmerican Energy's
transmission assets to other entities could increase costs for MidAmerican
Energy; however, the actual impact of TRANSLink on MidAmerican Energy's future
transmission costs is not yet known.
The structure of such federal and state energy regulations have in the
past, and may in the future, be the subject of various challenges and
restructuring proposals by utilities and other industry participants. The
implementation of regulatory changes in response to such changes or
restructuring proposals, or otherwise imposing more comprehensive or stringent
requirements on the Company, which would result in increased compliance costs,
could have a material adverse effect on the Company's results of operations.
United Kingdom
Since 1990, the electricity industry in Great Britain has seen the
privatization of electric generation, supply and distribution, and the
introduction of competition in generation and supply. Electricity is produced by
generators, transmitted through the national grid transmission system by The
National Grid Company plc ("NGC") (or in Scotland by Scottish Power or Scottish
Hydro Electric) and distributed to customers by the fourteen Distribution
License Holders ("DLHs") in their respective distribution service areas. During
the fourth quarter of 1998, the market for supplying electricity began to be
opened to competition through a phased-in program. This program, which proceeded
by geographic areas, was completed in 1999.
Under the Utilities Act 2000, the Public Electricity Supply License
granted at privatization was replaced by two separate licenses - the Electricity
Distribution license and the Electricity Supply license. The Public Electricity
Supplier ("PES") licenses formerly held by Northern Electric plc and Yorkshire
Electricity Group plc were split so that separate subsidiaries held licenses for
distribution and electricity supply. In order to comply with the legislation the
Northern Electric plc and Yorkshire Electricity Group plc each made a Statutory
Transfer Scheme ("Scheme") that was approved by the Secretary of State for Trade
and Industry. The Schemes provide for the transfer of certain assets and
liabilities to the licensed subsidiaries. This occurred on October 1, 2001, a
date set by the Secretary of State for Trade and Industry. As a consequence of
the Schemes the electricity distribution businesses of Northern Electric plc and
Yorkshire Electricity Group plc were transferred to Northern Electric
Distribution Ltd ("NEDL") and Yorkshire Electricity Distribution plc ("YEDL"),
respectively. NEDL and YEDL are each holders of an electricity distribution
license.
Each of the DLHs is required to offer terms for connection to its
distribution system and for use of its distribution system to any person. In
providing the use of its distribution system, a DLH must not discriminate
between users, nor may its charges differ except where justified by differences
in cost.
Most revenue of the DLHs is controlled by a distribution price control
formula. The current formula requires that regulated distribution income per
unit is increased or decreased each year by RPI-Xd where the Retail Price Index
("RPI") reflects the average of the 12-month inflation rates recorded for each
month in the previous July to December period. The distribution price control
formula also reflects an adjustment factor ("Xd") which was established by the
regulatory body, the Office of Gas and Electricity Markets ("Ofgem"), at the
last price control review (and continues to be set) at 3%. The formula also
takes account of the changes in system electrical losses, the number of
customers connected and the voltage at which customers receive the units of
electricity distributed. This formula determines the maximum average price per
unit of electricity distributed (in pence per kilowatt hour) which a DLH is
entitled to charge. The distribution price control formula permits DLHs to
receive additional revenues due to increased distribution of units and a
predetermined increase in customer numbers. The price control does not seek to
constrain the profits of a DLH from year to year. It is a control on revenue
that operates independently of most of the DLH's costs. During the lifetime of
the price control, additional cost savings therefore contribute directly to
profit.
In connection with the scheduled distribution price control review
concluded by Ofgem in 1999, the allowable revenue of NEDL's predecessor,
Northern Electric plc, was reduced by 24%, and the allowable revenue of YEDL's
predecessor, Yorkshire Electricity Group plc, was reduced by 23%, with effect
from April 1, 2000. As part of the review, the Xd factor was not modified and
therefore remained at 3%.
The distribution prices allowable under the current distribution price
control formula are expected to be reviewed by Ofgem at the expiration of the
formula's scheduled five-year duration in 2005. The formula may be further
reviewed at other times in the discretion of the regulator. Accordingly Ofgem is
proposing to modify the licenses of all DLHs to implement the Information and
Incentives Project under which up to two per cent of regulated income will
depend upon the performance of the DLH's distribution system as measured by the
number and duration of customer interruptions and upon the level of customer
satisfaction monitored by Ofgem.
Philippines
The Philippine Congress has passed the Electric Power Industry Reform
Act of 2001 which is aimed at restructuring the electric industry, privatizing
of the NPC and introducing a competitive electricity market, among others. The
passage of the bill may have an impact on the Company's future operations and
the industry as a whole, the effect of which is not yet determinable and
estimable.
Environmental Regulation
United States
The Company is subject to a number of environmental laws and other
regulations affecting many aspects of its present and future operations. Such
laws and regulations generally require the Company to obtain and comply with a
wide variety of licenses, permits and other approvals. No assurance can be
given, however, that in the future all necessary permits and approvals will be
obtained and all applicable statutes and regulations complied with. In addition,
regulatory compliance for the construction of new facilities is a costly and
time-consuming process, and intricate and rapidly changing environmental
regulations may require major expenditures for permitting and create the risk of
expensive delays or material impairment of project value if projects cannot
function as planned due to changing regulatory requirements or local opposition.
The Company believes that its operating power facilities are currently in
material compliance with all applicable federal, state and local laws and
regulations. There can be no assurance that existing regulations will not be
revised or that new regulations will not be adopted or become applicable to the
Company which could have an adverse impact on its operations.
The Clean Air Act Amendments of 1990 ("CAAA") was signed into law in
November 1990. Essentially all utility generating units are subject to the
provisions of the CAAA which address continuous emissions monitoring, permit
requirements and fees and emissions of certain substances. MidAmerican Energy
has five jointly owned and six wholly owned coal-fired generating units, which
represent approximately 60% of MidAmerican Energy's electric generating
capability. MidAmerican Energy's generating units meet all requirements under
Title IV of the CAAA. Title IV of the CAAA, which is also known as the Acid Rain
Program, sets forth requirements for the emission of sulfur dioxide and nitrogen
oxides at electric utility generating stations.
In accordance with the requirements of Section 112 of the CAAA, the
Environmental Protection Agency ("EPA") has performed a study of the hazards to
public health reasonably anticipated to occur as a result of emissions of
hazardous air pollutants by electric utility steam generating units. In February
1998, EPA issued its Final Report to Congress, indicating that mercury is the
hazardous air pollutant of greatest potential concern from coal-fired generating
units and that additional research and monitoring are necessary. As such the EPA
issued a request under Section 114 of the CAAA requiring all electric utilities
to provide information that will allow the EPA to calculate the annual mercury
emissions from each coal-fired generating unit for the calendar year 1999. In
December 2000, the EPA concluded that it is appropriate and necessary to
regulate mercury emissions from coal-fired generating units. It is anticipated
that rules will be developed to regulate these emissions in 2003 or 2004. The
cost to MidAmerican Energy of reducing its mercury emissions would depend on
available technology at the time, but could be material.
State and federal environmental laws and regulations currently have,
and future modifications may have, the effect of increasing the lead time for
the construction of new facilities, significantly increasing the total cost of
new facilities, requiring modification of the Company's existing facilities,
increasing the risk of delay on construction projects, increasing the Company's
cost of waste disposal and possibly reducing the reliability of service provided
by the Company and the amount of energy available from the Company's facilities.
Any of such items could have a substantial impact on amounts required to be
expended by the Company in the future.
United Kingdom
CE Electric UK Funding's businesses are subject to numerous regulatory
requirements with respect to the protection of the environment. The Electricity
Act 1989 obligates either the UK Secretary of State or the Director General of
Electric Supply to take into account the effect of electricity generation,
transmission and supply activities upon the physical environment when approving
applications for the construction of generating facilities and the location of
overhead power lines. The Electricity Act requires CE Electric UK Funding to
consider the desirability of preserving natural beauty and the conservation of
natural and man-made features of particular interest when it formulates
proposals for development in connection with certain of its activities. CE
Electric UK Funding mitigates the effects its proposals have on natural and
man-made features and administers an environmental assessment when it intends to
lay cables, construct overhead lines or carry out any other development in
connection with its licensed activities.
CE Electric UK Funding's policy is to carry out its activities in such a
manner as to minimize the impact of its works and operations on the environment,
and in accordance with environmental legislation and good practice. There have
not been any significant regulatory environmental compliance issues and there
are no material legal or administrative proceedings pending against CE Electric
UK Funding with respect to any environmental matter.
Employees
As of December 31, 2001, the Company and its subsidiaries employed
approximately 9,780 people.
As of December 31, 2001, MidAmerican Energy employed approximately 3,770
people, of which approximately 47% are represented by labor unions. MidAmerican
Energy believes that its relations with its employees are good.
As of December 31, 2001, CE Electric UK Funding employed approximately
3,460 people, of which approximately 76% are represented by labor unions. All CE
Electric UK Funding employees who are not party to a personal employment
contract are subject to collective bargaining agreements that are covered by
eight separate business agreements. These arrangements may be amended by joint
agreement between the trade unions and the individual business through
negotiation in the appropriate Joint Business Council. CE Electric UK Funding
believes that its relations with its employees are good.
As of December 31, 2001, the CalEnergy Generation platforms employed
approximately 560 people, of which approximately 240 people were in the
Philippines. None of CalEnergy Generation's employees are covered by a
collective bargaining agreement. Management believes that CalEnergy Generation's
relations with its employees are good.
As of December 31, 2001, HomeServices employed approximately 1,930
individuals and had approximately 8,700 sales associates, who are independent
contractors and not employees. None of HomeServices' employees or sales
associates are covered by a collective bargaining agreement. HomeServices
believes that its relations with its employees and sales associates are good.
Item 2. Properties
The Company's utility properties consist of physical assets necessary
and appropriate to render electric and gas service in its service territories.
Electric property consists primarily of generation, transmission and
distribution facilities. Gas property consists primarily of distribution plant,
including feeder lines to communities served from natural gas pipelines owned by
others. It is the opinion of management that the principal depreciable
properties owned by the Company are in good operating condition and well
maintained.
The electric transmission system of MidAmerican Energy at December 31,
2001, included 897 miles of 345-kV lines, and 1,122 miles of 161-kV lines. The
gas distribution facilities of MidAmerican Energy at December 31, 2001, included
20,561 miles of gas mains and services. Substantially all of the former
Iowa-Illinois Gas and Electric Company (predecessor to MidAmerican Energy)
utility property and franchises, and substantially all of the former Midwest
Power Systems Inc. (predecessor to MidAmerican Energy) electric utility property
located in Iowa, or approximately 79% of gross utility plant, is pledged to
secure mortgage bonds.
Northern's and Yorkshire's electricity distribution networks (excluding
service connection to consumers) included approximately 10,500 and 9,800 miles
of overhead lines and approximately 16,800 and 25,200 miles of underground
cables, respectively.
The Company's most significant physical properties, other than those
owned by CE Electric UK Funding and MidAmerican Energy, are its current
interests in operating power facilities, its plants under construction and
related real property interests. See Item 1 for further detail.
Item 3. Legal Proceedings
In addition to the proceedings described below, the Company and its
subsidiaries are currently parties to various minor items of litigation or
arbitration, none of which, if determined adversely, would have a material
adverse effect on the Company.
Southern California Edison
Southern California Edison Company ("Edison"), a wholly-owned subsidiary
of Edison International, is a public utility primarily engaged in the business
of supplying electric energy to retail customers in Central and Southern
California, excluding Los Angeles. The Company is aware that there have been
public announcements that Edison's financial condition has deteriorated as a
result of reduced liquidity. Following Edison's recent financing, Edison's
senior unsecured debt obligations were upgraded to Ba3 by Moody's and BB by S&P.
Edison failed to pay approximately $119 million due under the power
purchase agreement with CE Generation affiliates for power delivered in November
and December 2000 and January, February and March 2001, although the Power
Purchase Agreements provide for billing and payment on a schedule where payments
would have normally been received in early January, February, March, April and
May 2001.
On February 21, 2001, the Imperial Valley Projects (excluding the Salton
Sea V and Turbo Projects) filed a lawsuit against Edison in California's
Imperial County Superior Court seeking a court order requiring Edison to make
the required payments under the Power Purchase Agreements. The lawsuit also
requested, among other things, that the court order permit the Imperial Valley
Projects (excluding the Salton Sea V and Turbo Projects) to suspend deliveries
of power to Edison and to permit the Imperial Valley Projects to sell such power
to other purchasers in California.
On March 22, 2001, the Imperial County Superior Court granted the
Imperial Valley Projects' (excluding the Salton Sea V and Turbo Projects) Motion
for Summary Adjudication and a Declaratory Judgment ordering that: 1) under the
Power Purchase Agreements, the Imperial Valley Projects (excluding the Salton
Sea V and Turbo Projects) have the right to temporarily suspend deliveries of
capacity and energy to Edison, 2) such Imperial Valley Projects (excluding the
Salton Sea V and Turbo Projects) are entitled to resell the energy and capacity
to other purchasers and 3) the interim suspension of deliveries to Edison shall
not in any respect result in the modifications or termination of the Power
Purchase Agreements, and the Power Purchase Agreements shall in all respects
continue in full force and effect other than the temporary suspension of
deliveries to Edison.
As a result of the March 22, 2001 Declaratory Judgment, the Imperial
Valley Projects (excluding the Salton Sea V and Turbo Projects) suspended
deliveries of energy to Edison and entered into a transaction agreement with El
Paso Merchant Energy, L.P. ("EPME") in which the Imperial Valley Projects'
(excluding the Salton Sea V and Turbo Projects) available power was sold to EPME
based on percentages of the Dow Jones SP-15 Index. On June 18, 2001 the Superior
Court prospectively vacated its order authorizing the Imperial Valley Projects'
(excluding the Salton Sea V and Turbo Projects) right to resell power pursuant
to the Declaratory Judgment.
On June 20, 2001, the Imperial Valley Projects (excluding Salton Sea
Unit V and CE Turbo) entered into Agreements Addressing Renewable Energy Pricing
and Payment Issues with Edison ("Settlement Agreements") and, as a result,
resumed power sales to Edison on June 22, 2001. The Settlement Agreements
required that Edison make an initial payment to repay the past due balances
under the Power Purchase Agreements (the "stipulated amounts"). The initial
payment of approximately $11.6 million, which represented 10% of the stipulated
amounts, was received June 22, 2001. On October 2, 2001, the California Public
Utilities Commission announced an agreement with Edison that allowed Edison to
recover in retail electric rates its past due obligations. On November 30, 2001,
the Settlement Agreements were amended to reflect when Edison would be required
to make the final payment on past due amounts. On March 1, 2002, Edison obtained
$1.8 billion in secured financing that, when combined with cash on hand, enabled
Edison to pay off its past due debts. The final payment of approximately $104.6
million, representing the remaining stipulated amounts, was received March 1,
2002. In addition to these payments, Edison was required to make monthly
interest payments calculated at a rate of 7% per annum on the outstanding
stipulated amounts. The amended Settlement Agreements provide a revised energy
pricing structure, whereby Edison elects to pay the Imperial Valley Projects a
fixed energy price in lieu of the Commission-approved Avoided Cost of Energy
Methodology under the Power Purchase Agreements. The fixed energy price is 3.25
cents/kWh from December 2001 through April 30, 2002 and 5.37 cents/kWh
commencing May 1, 2002 for a five year period. Following the five year period,
the energy payments revert back to the Commission-approved Avoided Cost of
Energy Methodology under the Power Purchase Agreements. Estimates of Edison's
future Avoided Cost of Energy vary substantially from year to year.
As a result of Edison's failure to make the payments due under the Power
Purchase Agreements and the downgrades of Edison's credit rating, Moody's
downgraded the ratings for the Salton Sea Funding Corporation (the "Funding
Corporation") Securities to Caa2 (negative outlook) and S&P downgraded the
ratings for the Funding Corporation Securities to BBB- and placed the Securities
on "credit watch negative." Moody's downgraded the ratings for the CE Generation
Securities to B1 from Baa3 (review for possible downgrade). Following the
execution of the Settlement Agreements, Moody's placed the Salton Sea Funding
and CE Generation securities on "credit watch positive." The Funding Corporation
Securities are currently rated Ba3 by Moody's and BBB- by S&P. CE Generation
Securities are currently Ba2 by Moody's and BBB- by S&P.
Kvaerner Arbitration
The Zinc Recovery Project was being constructed by Kvaerner U.S. Inc.
("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering,
procure, construct and manage contract (the "Zinc Recovery Project EPC
Contract"). On June 14, 2001, CalEnergy Minerals, LLC issued notices of default,
termination and demand for payment of damages to Kvaerner under the Zinc
Recovery Project EPC Contract due to failure to meet performance obligations. As
a result of Kvaerner's failure to pay monetary obligations under the Zinc
Recovery Project EPC Contract, CalEnergy Minerals, LLC drew $29.6 million under
the EPC Contract Letter of Credit on July 20, 2001. CalEnergy Minerals, LLC has
entered into a time and materials reimbursable engineer, procure and
construction management contract with AMEC E&C Services, Inc. to complete the
Zinc Recovery Project.
On July 11, 2001, Kvaerner filed an Amended Demand For Arbitration
against CalEnergy Minerals LLC characterizing the nature of the dispute as
concerns regarding change orders and performance penalties. Kvaerner did not
state the amount of its claim.
On August 7, 2001, CalEnergy Minerals LLC filed an Answering Statement
and Counterclaim against Kvaerner. CalEnergy Minerals LLC denied all material
allegations in Kvaerner's Amended Demand for Arbitration, and asserted a
counterclaim against Kvaerner for breach of contract and specific performance.
CalEnergy Minerals LLC alleged that its total estimated damage for Kvaerner's
breach of contract are in excess of approximately $60 million; however,
CalEnergy Minerals LLC has offset approximately $42.5 million of these damages
by exercising its rights under the EPC Contract to claim the retainage and by
drawing on a letter of credit. Therefore, CalEnergy Minerals LLC asked for a
judgment in excess of approximately $20 million. The arbitration is scheduled
for June 2002.
Casecnan
The Casecnan Project was initially being constructed pursuant to a
fixed-price, date-certain, turnkey construction contract (the "Hanbo Contract")
on a joint and several basis by Hanbo Corporation ("Hanbo") and Hanbo
Engineering and Construction Co., Ltd. ("HECC"), both of which are South Korean
corporations. As of May 7, 1997, the Company terminated the Hanbo Contract due
to defaults by Hanbo and HECC including the insolvency of both companies. On the
same date, the Company entered into a new fixed-price, date certain, turnkey
engineering, procurement and construction contract to complete the construction
of the Casecnan Project (the "Replacement Contract"). The work under the
Replacement Contract was conducted by a consortium consisting of Cooperativa
Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa., working
together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power
Engineering Ltd. (collectively, the "Contractor").
On November 20, 1999, the Replacement Contract was amended to extend the
Guaranteed Substantial Completion Date for the Casecnan Project to March 31,
2001. This amendment was approved by the lender's independent engineer under the
Casecnan Indenture.
On February 12, 2001, the Contractor filed a Request for Arbitration
with the International Chamber of Commerce seeking an extension of the
Guaranteed Substantial Completion Date by up to 153 days through August 31, 2001
resulting from various alleged force majeure events. In a March 20, 2001
Supplement to Request for Arbitration, the Contractor also seeks compensation
for alleged additional costs of approximately $4 million it incurred from the
claimed force majeure events to the extent it is unable to recover from its
insurer. On April 20, 2001, the Contractor filed a further supplement seeking an
additional approximately $62 million in damages for the alleged force majeure
event (and geologic conditions) related to the collapse of the surge shaft. The
Contractor alleged that the circumstances surrounding the placing of the
Casecnan Project into commercial operation on December 11, 2001 amounted to a
termination of the Replacement Contract and filed a claim for unspecified
quantum meruit damages. CE Casecnan believes such allegations and claims are
without merit and is vigorously defending the Contractor's claims. The
arbitration is being conducted applying New York law and pursuant to the rules
of the International Chamber of Commerce.
On June 25, 2001, the arbitration tribunal temporarily enjoined CE
Casecnan from making calls on the demand guaranty posted by Banca di Roma in
support of the Contractor's obligations to CE Casecnan for delay liquidated
damages. Hearings on the force majeure claims were held in London from July 2 to
14, 2001, and hearings on the Contractor's April 20, 2001 supplement were held
in London from September 24 to October 3, 2001. Further hearings were held in
Paris from January 2 to February 1, 2002 and additional hearings were held from
March 14 to 19, 2002.
As of December 31, 2001 the Company has received approximately $6.0
million of liquidated damages from demands made or the demand guarantees posted
by Commerzbank on behalf of the Contractor. Although the outcome of the
arbitration is difficult to assess, CE Casecnan believes it will prevail and
receive substantial additional liquidated damages in the arbitration.
Malitbog Arbitration
VGPC and PNOC-EDC have been negotiating with respect to certain disputes
concerning the Malitbog ECA but have been unable to reach a mutually acceptable
resolution. Accordingly, on October 16, 2000, VGPC commenced arbitration against
PNOC-EDC by serving it with a Notice of Arbitration and Statement of Claim (the
"Notice of Arbitration"). In the Notice of Arbitration, VGPC claimed that
PNOC-EDC breached the Malitbog ECA by improperly characterizing certain No Fault
Outages as Forced Outage Hours and then deducting them from the total number of
hours each month. On December 22, 2000, VGPC filed an Amended Statement of Claim
pursuant to which VGPC added a claim that PNOC-EDC breached the Malitbog ECA by
refusing to accept VGPC's specified Nominated Capacity for contract years July
25, 1999 to July 25, 2000, and July 25, 2000 to July 25, 2001. A Second Amended
Statement of Claim was filed on March 9, 2001 to add the Scheduled Maintenance
issue. VGPC intends to vigorously pursue its claims in this proceeding.
Cooper Litigation
On July 23, 1997, the Nebraska Public Power District ("NPPD") filed a
complaint, in the United States District Court for the District of Nebraska,
naming MidAmerican Energy as the defendant and seeking declaratory judgment as
to three issues under the parties' long-term power purchase agreement for Cooper
capacity and energy. More specifically, NPPD sought a declaratory judgment in
the following respects:
(1) that MidAmerican Energy is obligated to pay 50% of all costs and
expenses associated with decommissioning Cooper, and that in the event
NPPD continues to operate Cooper after expiration of the power purchase
agreement (September 2004), MidAmerican Energy is not entitled to
reimbursement of any decommissioning funds it has paid to date or will
pay in the future;
(2) that the current method of allocating transition costs as a part of
the decommissioning cost is proper under the power purchase agree-
ment; and
(3) that the current method of investing decommissioning funds is proper
under the power purchase agreement.
MidAmerican Energy filed its answer and counterclaims. The counterclaims filed
by MidAmerican Energy are generally as follows:
(1) tha MidAmerican Energy has no duty under the power purchase agreement
to reimburse or pay 50% of the decommissioning costs unless conditions
to reimbursement occur;
(2) that the term "monthly power costs" as defined in the power purchase
agreement does not include costs and expenses associated with
decommissioning the plant;
(3) that NPPD violated MidAmerican Energy's directions for application of
payments;
(4) that transition costs are not included in any decommissioning costs and
are not any kind of costs that MidAmerican Energy is obligated to pay;
(5) that NPPD has the duty to repay all amounts that MidAmerican Energy has
prefunded for decommissioning in the event the Nebraska Public Power
District operates the plant after the term of the power purchase
agreement;
(6) that NPPD is equitably estopped from continuing to operate the plant
after the term of the power purchase agreement so long as NPPD does not
repay all amounts MidAmerican Energy has prefunded for estimated
decommissioning costs together with other amounts in certain funds and
accounts and for so long as NPPD fails to provide MidAmerican Energy
with certain requested accountings and information;
(7) that certain funds, accounts, and reserves are excessive and are
required to be paid to MidAmerican Energy or credited to MidAmerican
Energy's pre-2004 monthly power costs;
(8) that MidAmerican Energy has no duty to pay for nuclear fuel, operations
and maintenance projects or capital improvements that have useful lives
after the term of the power purchase agreement;
(9) that NPPD has mismanaged the plant in numerous described transactions
resulting in damage to MidAmerican Energy;
(10) that NPPD has breached its contractual and other duties to MidAmerican
Energy by not joining certain litigation and by failing to credit or
agree to credit MidAmerican Energy with any recovery for low-level
radioactive waste; and
(11) that NPPD has breached its duty to MidAmerican Energy in making invest-
ments of decommissioning funds;
On October 6, 1999, the court rendered summary judgment for NPPD on the
above-mentioned issue concerning liability for decommissioning (issue one in the
first paragraph above) and the related counterclaims filed by MidAmerican Energy
(issues one and two in the second paragraph above). The court referred all
remaining issues in the case to mediation, and cancelled the November 1999 trial
date.
MidAmerican Energy appealed the court's summary judgment ruling. On
December 12, 2000, the United States Court of Appeals for the Eighth Circuit
reversed the ruling of the district court and granted summary judgment in favor
of MidAmerican Energy on issues one and two in the second paragraph above, as
well as issue one in the first paragraph above. Additionally, it remanded the
case for trial on all other claims and counterclaims.
Since the remand to the District Court from the Eighth Circuit Court of
Appeals, NPPD has been granted permission, over MidAmerican Energy's objections,
to file a second amended complaint. The second amended complaint asserts that
even though the Eighth Circuit Court of Appeals held that MidAmerican Energy has
no liability under the power purchase agreement to reimburse or pay NPPD a 50%
share of decommissioning costs unless certain conditions occur, MidAmerican
Energy has unconditional liability for a 50% share based on agreements other
than the power purchase agreement as originally written. NPPD's post-remand
contentions -- all strongly disputed by MidAmerican Energy -- are that
MidAmerican Energy has unconditional liability for a 50% share of
decommissioning based on any of the following alternative theories: (i) the
parties without written amendment either modified the power purchase agreement
or made a separate agreement that imposes unconditional liability on MidAmerican
Energy for decommissioning costs; (ii) absent unconditional liability for a 50%
share of decommissioning costs, MidAmerican Energy would be unjustly enriched;
(iii) MidAmerican Energy has unconditional liability for a 50% share of
decommissioning costs based on promissory estoppel; or (iv) NPPD is entitled to
have the power purchase agreement reformed to provide that MidAmerican Energy
has unconditional liability for a 50% share of decommissioning costs. In
response to NPPD's second amended complaint, MidAmerican Energy filed its first
amended answer and third amended counterclaims containing denials, several
affirmative defenses, and the counterclaims summarized above. In the course of
discovery, NPPD has contended that MidAmerican Energy has some responsibility
for some costs of storage of spent fuel resulting from the operation of the
plant during the term of the power purchase agreement. MidAmerican Energy
disputes this. MidAmerican Energy recently filed a mandamus petition with Eighth
Circuit Court of Appeals seeking an order of that court directing the District
Court not to permit NPPD to pursue the above alternative theories at trial,
since the above alternative theories appear to be contrary to the December 12,
2000 Eighth Circuit Court of Appeals decision. If such relief is not granted,
MidAmerican Energy will strongly dispute at trial these contentions and theories
put forth by NPPD. Trial in these matters has been recently rescheduled to
September 9, 2002.
Item 4. Submission of Matters to a Vote of Security Holders.
Not applicable.
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder's
Matters
As of March 14, 2000, the Company's equity securities are owned by a
limited group of private investors and are not registered with the Securities
and Exchange Commission pursuant to the Securities Act of 1933, as amended,
listed on a stock exchange or otherwise publicly held or traded.
Item 6. Selected Financial Data
Reference is made to Part IV of this report.
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Reference is made to Part IV of this report.
Item 7A. Qualitative and Quantitative Disclosures About Market Risk
Reference is made to Part IV of this report. Refer to Note 16 in notes
to consolidated financial statements.
Item 8. Financial Statements and Supplementary Data
Reference is made to Part IV of this report.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
Not applicable.
PART III
MANAGEMENT
Item 10. Directors, Executive and Other Officers of the Company
The Company's management structure is organized functionally and the
current executive officers and directors of the Company and their positions are
as follows:
Name Position
David L. Sokol Chairman of the Board, Chief Executive Officer and
Director
Gregory E. Abel President, Chief Operating Officer and Director
Patrick J. Goodman Senior Vice President and Chief Financial Officer
Douglas L. Anderson Senior Vice President and General Counsel
Keith D. Hartje Senior Vice President and Chief Administrative
Officer
Warren Buffett Director
Walter Scott Jr. Director
Marc D. Hamburg Director
W. David Scott Director
Edgar D. Aronson Director
John Boyer Director
Stanley J. Bright Director
Richard Jaros Director
Officers are elected annually by the Board of Directors. There are no
family relationships among the executive officers, nor any arrangements or
understanding between any officer and any other person pursuant to which the
officer was selected.
Set forth below is certain information with respect to each of the
foregoing officers:
DAVID L. SOKOL, 45, Chairman of the Board of Directors and Chief
Executive Officer. Mr. Sokol has been CEO since April 19, 1993 and served as
President of MEHC from April 19, 1993 until January 21, 1995. Mr. Sokol has been
Chairman of the Board of Directors since May 1994 and a director since March
1991. Formerly, among other positions held in the independent power industry,
Mr. Sokol served as President and Chief Executive Officer of Kiewit Energy
Company, which at that time was a wholly owned subsidiary of PKS, and Ogden
Projects, Inc.
GREGORY E. ABEL, 39, President, Chief Operating Officer and Director.
Mr. Abel joined the Company in 1992 and initially served as Vice President and
Controller. Mr. Abel is a Chartered Accountant and from 1984 to 1992 he was
employed by Price Waterhouse. As a Manager in the San Francisco office of Price
Waterhouse, he was responsible for clients in the energy industry.
PATRICK J. GOODMAN, 35, Senior Vice President and Chief Financial
Officer. Mr. Goodman joined the Company in 1995, and served in various
accounting positions including Senior Vice President and Chief Accounting
Officer. Prior to joining the Company, Mr. Goodman was a financial manager for
National Indemnity Company and a senior associate at Coopers & Lybrand.
DOUGLAS L. ANDERSON, 44, Senior Vice President and General Counsel.
Mr. Anderson joined the Company in February 1993 and has served in various legal
positions including General Counsel of the Company's independent power
affiliates. From 1990 to 1993 Mr. Anderson was a corporate attorney with Fraser,
Stryker in Omaha, NE. Prior to that Mr. Anderson was a principal in the firm
Anderson and Anderson.
KEITH D. HARTJE, 52, Senior Vice President and Chief Administrative
Officer. Mr. Hartje has been with MidAmerican Energy and its predecessor
companies since 1973. In that time, he has held a number of positions, including
General Counsel and Corporate Secretary, District Vice President for southwest
Iowa operations, and Vice President, Corporate Communications.
WARREN BUFFETT, 71, Director. Mr. Buffett has been a director of the
Company since March 2000. He is Chairman of the Board and Chief Executive Office
of Berkshire Hathaway Inc. Mr. Buffett is a Director of the Coca-Cola Company,
the Gillette Company and The Washington Post Company.
WALTER SCOTT, JR., 71, Director. Mr. Scott has been a director of
the Company since June 1991. Mr. Scott was the Chairman and Chief Executive
Officer of the Company from January 8, 1992 until April 19, 1993. For more than
the past five years, he has been Chairman of the Board of Directors of Level 3
Communications, Inc., a successor to certain businesses of Peter Kiewit Sons
Inc. Mr. Scott is a director of Peter Kiewit Sons Inc., Berkshire Hathaway Inc.,
Burlington Resources, Inc., ConAgra, Inc., Valmont Industries, Inc., Kiewit
Materials Co., Commonwealth Telephone Enterprises, Inc. and RCN Corporation.
MARC D. HAMBURG, 52, Director. Mr. Hamburg has been a director of the
Company since March 2000. He has served as Vice President - Chief Financial
Officer of Berkshire Hathaway Inc. since October 1, 1992 and Treasurer since
June 1, 1987, his date of employment with Berkshire Hathaway Inc.
W. DAVID SCOTT, 40, Director. Mr. Scott has been a director of the
Company since March 2000. Mr. Scott formed Magnum Resources, Inc., a commercial
real estate investment and management company, in October 1994 and has served as
its President and Chief Executive Office since its inception. Before forming
Magnum Resources, Mr. Scott worked for America First Companies, Cornerstone
Banking Group and Peter Kiewit Sons Inc. Mr. Scott has been a director of
America First Mortgage Investments, Inc., a mortgage REIT, since 1998.
EDGAR D. ARONSON, 67, Director. Mr. Aronson has been a director of the
Company since 1983. Mr. Aronson founded EDACO, Inc., a private venture capital
company, in 1981, and has been President of EDACO, Inc. since that time. Prior
to that, Mr. Aronson was Chairman of Dillon, Read International from 1979 to
1981 and a General Partner in charge of the International Department of Salomon
Brothers Inc. from 1973 to 1979. Mr. Aronson served during 1962-1968 as Vice
President consecutively in the International Departments of First National Bank
of Chicago and Republic National Bank of New York. He founded the International
Department of Salomon Brothers and Hutzler in 1968.
JOHN BOYER, 58, Director. Mr. Boyer has been a director of the Company
since March 2000. He is a partner with Fraser, Stryker, Meusey, Olson, Boyer &
Bloch, P.C. from 1973 to present with emphasis on corporate, commercial,
federal, state, and local taxation.
STANLEY J. BRIGHT, 62, Director. Mr. Bright is Vice Chairman of the
Company and was Chairman and Chief Executive Officer of MidAmerican Energy
Company from July 1, 1995 until March 1999. Mr. Bright joined Iowa-Illinois Gas
and Electric Company (a predecessor of MidAmerican Energy Company