Back to GetFilings.com
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
Annual Report Pursuant to Section 13 or 15 (d) of
the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2002
MIDAMERICAN ENERGY HOLDINGS COMPANY
(Exact name of registrant as specified in its charter)
Iowa 94-2213782
---- -------------
(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 each of the registrants' knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Act). Yes [ ] No [X]
All of the shares of MidAmerican Energy Holdings Company are held by a limited
group of private investors. As of March 31, 2003, 9,281,087 shares of common
stock were outstanding.
TABLE OF CONTENTS
PART I
Item 1. Business.......................................................... 3
Item 2. Properties........................................................ 30
Item 3. Legal Proceedings................................................. 32
Item 4. Submission of Matters to a Vote of Security Holders............... 34
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters............................................. 35
Item 6. Selected Financial Data........................................... 36
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations....................................... 37
Item 7A. Quantitative and Qualitative Disclosures About Market Risk........ 49
Item 8. Financial Statements and Supplementary Data....................... 50
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure........................................ 96
PART III
Item 10. Directors and Executive Officers of the Registrant................ 97
Item 11. Executive Compensation............................................ 99
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters......................103
Item 13. Certain Relationships and Related Transactions....................104
Item 14. Controls and Procedures...........................................105
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K...106
SIGNATURES ..................................................................111
CERTIFICATIONS...............................................................113
Exhibit Index................................................................115
-2-
PART I
ITEM 1. BUSINESS.
GENERAL
MidAmerican Energy Holdings Company and its subsidiaries (the "Company" or
"MEHC") is a United States-based privately owned global energy company. The
Company's subsidiaries' principal businesses are regulated electric and natural
gas utilities, regulated interstate natural gas transmission and electric power
generation. Its operations are organized and managed on seven distinct
platforms: MidAmerican Energy Company ("MidAmerican Energy"), Kern River Gas
Transmission Company ("Kern River"), Northern Natural Gas Company ("Northern
Natural Gas"), CE Electric UK Funding ("CE Electric UK") (which includes
Northern Electric plc ("Northern Electric") and Yorkshire Power Group Ltd.
("Yorkshire")), CalEnergy Generation - Domestic, CalEnergy Generation-Foreign
(the Upper Mahiao, Malitbog and Mahanagdong Projects (collectively the "Leyte
Projects") and the Casecnan Project) and HomeServices of America, Inc.
("HomeServices"). Through six of these platforms, the Company owns and operates
a combined electric and natural gas utility company in the United States, two
natural gas pipeline companies in the United States, two electricity
distribution companies in the United Kingdom, and a diversified portfolio of
domestic and international independent power projects. The Company also owns the
second largest residential real estate brokerage firm in the United States.
The Company's principal subsidiaries generate, transmit, store, distribute and
supply energy. The Company's electric and natural gas utility subsidiaries
currently serve approximately 4.3 million electricity customers and
approximately 660,000 natural gas customers. Its natural gas pipeline
subsidiaries operate interstate natural gas transmission systems with
approximately 17,500 miles of pipeline in operation and peak delivery capacity
of 5.3 Bcf of natural gas per day. The Company has interests in 6,191 net owned
MW of power generation facilities in operation and construction, including 4,618
net owned MW in facilities that are part of the regulated return asset base of
its electric utility business (as further described in "Business--MidAmerican
Energy--Electric Operations") and 1,573 net owned MW in non-utility power
generation facilities. Substantially all of the non-utility power generation
facilities have long-term contracts for the sale of energy and/or capacity from
the facilities.
On March 14, 2000, the Company and an investor group comprised of Berkshire
Hathaway Inc., Walter Scott, Jr., a Director of the Company, David L. Sokol,
Chairman and Chief Executive Officer of the Company, and Gregory E. Abel,
President and Chief Operating Officer of the Company, closed on a definitive
agreement and plan of merger whereby the investor group acquired all of the
outstanding common stock of the Company (the "Teton Transaction"). As a result
of the Teton Transaction, Berkshire Hathaway, Mr. Scott, Mr. Sokol and Mr. Abel
own approximately 9.7%, 86%, 3% and 1% of the voting stock respectively.
The principal executive offices of the Company are located at 666 Grand Avenue,
Des Moines, Iowa 50309 and its telephone number is (515) 242-4300. The Company
initially incorporated in 1971 under the laws of the State of Delaware and was
reincorporated in 1999 in Iowa, at which time it changed its name from CalEnergy
Company, Inc. to MidAmerican Energy Holdings Company.
In this Annual Report, references to "U.S. dollars," "dollars," "$" or "cents"
are to the currency of the United States, references to "pounds sterling,"
"(pound)," "sterling," "pence" or "p" are to the currency of the United Kingdom
and references to "pesos" are to the currency of the Philippines. References to
MW means megawatts, MWh means megawatt hours, Bcf means billion cubic feet, mmcf
means million cubic feet, GWh means gigawatts per hour, kV means 1000 volts, Tcf
means trillion cubic feet, kWh means kilowatt hours and MMBtus means million
British thermal units.
MIDAMERICAN ENERGY
MidAmerican Energy is the largest energy company headquartered in Iowa, with
$3.8 billion of assets as of December 31, 2002, and revenue for 2002 totaling
$2.2 billion. MidAmerican Energy is principally engaged in the business of
generating, transmitting, distributing and selling electric energy and in
distributing, selling and transporting natural gas. MidAmerican Energy
distributes electricity at retail in Council Bluffs, Des Moines, Fort Dodge,
Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities (Davenport and
Bettendorf, Iowa and Rock Island, Moline and East Moline, Illinois); and a
number of adjacent communities and areas. It also distributes natural gas at
retail in Cedar Rapids, Des Moines, Fort Dodge, Iowa City, Sioux City and
Waterloo, Iowa; the Quad Cities; Sioux Falls, South Dakota; and a number of
adjacent communities and areas. As of December 31, 2002, MidAmerican Energy had
approximately 681,000 retail electric customers and 660,000 retail natural gas
customers.
-3-
In addition to retail sales, MidAmerican Energy sells electric energy and
natural gas to other utilities, marketers and municipalities outside of
MidAmerican Energy's delivery system. These sales are referred to as wholesale
sales. It also transports natural gas through its distribution system for a
number of end-use customers who have independently secured their supply of
natural gas.
MidAmerican Energy's regulated electric and gas operations are conducted under
franchises, certificates, permits and licenses obtained from state and local
authorities. The franchises, with various expiration dates, are typically for
25-year terms.
MidAmerican Energy has a diverse customer base consisting of residential,
agricultural and a variety of commercial and industrial customer groups. Among
the primary industries served by MidAmerican Energy are those that are concerned
with food products, the manufacturing, processing and fabrication of primary
metals, real estate, farm and other non-electrical machinery, and cement and
gypsum products.
For the year ended December 31, 2002, MidAmerican Energy derived approximately
61% of its gross operating revenues from its electric utility business, 31% from
its gas utility business and 8% from its non-regulated business activities. For
2001 and 2000, the corresponding percentages were 56% electric, 37% gas and 7%
non-regulated and 53% electric, 41% gas and 6% non-regulated, respectively. The
change in revenue mix is principally driven by changes in natural gas prices and
seasonality.
There are seasonal variations in MidAmerican Energy's electric and gas
businesses, which are principally related to the use of energy for air
conditioning and heating. In 2002, 41% of MidAmerican Energy's electric utility
revenues were reported in the months of June, July, August and September, and
47% of MidAmerican Energy's gas utility revenues were reported in the months of
January, February, March and December.
Electric Operations
The electric utility industry continues to undergo regulatory change.
Traditionally, prices charged by electric utility companies have been regulated
by federal and state commissions and have been based on cost of service. In
recent years, changes have been occurring that move the electric utility
industry toward a more competitive, market-based pricing environment. These
changes may have a significant impact on the way MidAmerican Energy does
business.
MidAmerican Energy manages its operations as four separate business units:
generation, energy delivery, transmission, and marketing and sales. The
generation segment derives most of its revenue from the sale of regulated
wholesale electricity and non-regulated wholesale and retail natural gas. The
energy delivery segment derives its revenue principally from the delivery of
regulated electricity and natural gas, while the transmission segment obtains
most of its revenue from the sale of transmission capacity. The marketing and
sales segment receives its revenue principally from non-regulated sales of
natural gas and electricity.
For the year ended December 31, 2002, regulated electric sales by MidAmerican
Energy by customer class were as follows: 19.8% were to residential customers,
14.2% were to small general service customers, 24.5% were to large general
service customers, 9.1% were to other customers, and 32.4% were wholesale sales.
For the year ended December 31, 2002, regulated electric sales by MidAmerican
Energy by jurisdiction were as follows: 88.5% to Iowa, 10.7% to Illinois and
0.8% to South Dakota.
The annual hourly peak demand on MidAmerican Energy's electric system occurs
principally as a result of air conditioning use during the cooling season. In
July 2002, MidAmerican Energy recorded an hourly peak demand of 3,889 MW, which
was 56 MW greater than MidAmerican Energy's previous record hourly peak of 3,833
MW set in 1999.
-4-
The following table sets out certain information concerning MidAmerican Energy's
power generation facilities based upon summer 2002 accreditation:
FACILITY NET
CAPACITY NET MW COMMERCIAL
OPERATING PROJECT (1) (MW)(2) OWNED(2) FUEL LOCATION OPERATION
- ------------------------------------------ ------------ ------- -------- -------- ----------
COAL FACILITIES:
Council Bluffs Energy Center Units 1 & 2 133 133 Coal Iowa 1954, 1958
Council Bluffs Energy Center Unit 3 .... 690 546 Coal Iowa 1978
Louisa Generation Station .............. 700 616 Coal Iowa 1983
Neal Generation Station Units 1 & 2 .... 435 435 Coal Iowa 1964, 1972
Neal Generation Station Unit 3 ......... 515 371 Coal Iowa 1975
Neal Generation Station Unit 4 ......... 644 261 Coal Iowa 1979
Ottumwa Generation Station ............. 708 368 Coal Iowa 1981
Riverside Generation Station ........... 135 135 Coal Iowa 1925-61
----- -----
Total coal facilities ................ 3,960 2,865
----- -----
OTHER FACILITIES:
Combustion Turbines .................... 785 785 Gas/Oil Iowa 1969-95
Moline Water Power ..................... 3 3 Hydro Illinois 1970
Quad Cities Generating Station ......... 1,636 409 Nuclear Illinois 1974
Portable Power Modules ................. 56 56 Oil Iowa 2000
----- -----
Total other facilities ............... 2,480 1,253
----- -----
ACCREDITED GENERATING CAPACITY ........... 6,440 4,118
Projects Under Construction -
Greater Des Moines Energy Center ....... 500 500 Gas Iowa 2003-05
----- -----
TOTAL POWER GENERATION CAPACITY .......... 6,940 4,618
===== =====
(1) MidAmerican Energy operates all such power generation facilities other than
Quad Cities Generating Station and Ottumwa Generation Station.
(2) Represents accredited net generating capability. Actual MW may vary
depending on operating conditions and plant design for operating projects.
Net MW owned indicates ownership of accredited capacity for the summer of
2002 as approved by the Mid- Continent Area Power Pool ("MAPP").
MidAmerican Energy's accredited net generating capability in the summer of 2002
was 4,724 MW. Accredited net generating capability represents the amount of
generation available to meet the requirements on MidAmerican Energy's system and
consists of MidAmerican Energy-owned generation of 4,118 MW, generation under
power purchase contracts of 630 MW and the net amount of capacity purchases and
sales of (24) MW. The net generating capability at any time may be less than it
would otherwise be due to regulatory restrictions, fuel restrictions and
generating units being temporarily out of service for inspection, maintenance,
refueling or modifications.
MidAmerican Energy plans to develop and construct three electric generating
projects in Iowa. The projects would provide service to regulated retail
electricity customers and be included in regulated rate base in Iowa, Illinois
and South Dakota. Wholesale sales may also be made from the projects to the
extent the power is not needed for regulated retail service.
The first project will be a 500-MW (based on expected accreditation) natural
gas-fired, combined cycle plant with an estimated cost of $415 million.
MidAmerican Energy will own 100% of the plant and operate it. The plant will be
operated in simple cycle mode during 2003 and 2004, resulting in 310 MW of
accredited capacity. The combined cycle operation will commence in 2005.
MidAmerican Energy has received a certificate from the Iowa Utilities Board
"(IUB") allowing it to construct the plant. In May 2002, the IUB issued an order
that specified the Iowa ratemaking principles that will apply to the plant over
its life. As a result of that order, MidAmerican Energy is proceeding with the
construction of the plant.
-5-
The second project is currently under development and is expected to be a 790-MW
(based on expected accreditation) super-critical-temperature, coal-fired plant
fueled with low-sulfur coal. If constructed, MidAmerican Energy will operate the
plant and expects to own approximately 475 MW of the plant. Municipal,
cooperative and public power utilities will own the remainder, which is a
typical ownership arrangement for large base-load plants in Iowa. On January 23,
2003, MidAmerican Energy received an order approving the issuance of a
certificate from the IUB allowing it to construct the plant. MidAmerican Energy
has made a filing with the IUB for approval of Iowa ratemaking principles for
this second plant. The development of this plant is subject to obtaining
environmental and other required permits, as well as to receiving orders from
the IUB approving construction of the associated transmission facilities and
establishing ratemaking principles which are satisfactory to MidAmerican Energy.
The third project is currently under development and is expected to be wind
power facilities totaling 310 MW (nameplate rating). If constructed, MidAmerican
Energy will own and operate these facilities, which are expected to cost
approximately $323 million, plus associated transmission facilities. MidAmerican
Energy's plan to construct the wind project is in conjunction with a settlement
proposal to extend through December 31, 2010, a rate freeze that is currently
scheduled to expire at the end of 2005. The proposed settlement requires
enactment of Iowa legislation and is subject to approval by the IUB.
MidAmerican Energy is interconnected with Iowa utilities and utilities in
neighboring states and is involved in an electric power pooling agreement known
as MAPP. MAPP is a voluntary association of electric utilities doing business in
Minnesota, Nebraska, North Dakota and the Canadian provinces of Saskatchewan and
Manitoba and portions of Iowa, Montana, South Dakota and Wisconsin. Its
membership also includes power marketers, regulatory agencies and independent
power producers. MAPP facilitates operation of the transmission system and is
responsible for the safety and reliability of the bulk electric system.
In November 2001, MAPPCOR, the contractor to MAPP, sold its transmission-related
assets to the Midwest Independent Transmission System Operator, Inc. ("Midwest
ISO"). The Midwest ISO now has responsibility for administration of MAPP's
Open-Access Transmission Tariff.
Each MAPP participant is required to maintain for emergency purposes a net
generating capability reserve of at least 15% above its system peak demand. If a
participant's capability reserve falls below the 15% minimum, significant
penalties could be contractually imposed by MAPP. MidAmerican Energy's reserve
margin at peak demand for 2002 was approximately 21%.
MidAmerican Energy's transmission system connects its generating facilities with
distribution substations and interconnects with 14 other transmission providers
in Iowa and five adjacent states. Under normal operating conditions, MidAmerican
Energy's transmission system is unconstrained and has adequate capacity to
deliver energy to MidAmerican Energy's distribution system and to export and
import energy with other interconnected systems.
In December 1999, the Federal Energy Regulatory Commission ("FERC") issued Order
No. 2000 establishing, among other things, minimum characteristics and functions
for regional transmission organizations. Public utilities that were not a member
of an independent system operator at the time of the order were required to
submit a plan by which its transmission facilities would be transferred to a
regional transmission organization. On September 28, 2001, MidAmerican Energy
and five other electric utilities filed with the FERC a plan to create TRANSLink
Transmission Company LLC ("TRANSLink") and to integrate their electric
transmission systems into a single, coordinated system operating as a for-profit
independent transmission company in conjunction with a FERC-approved regional
transmission organization. On April 25, 2002, the FERC issued an order approving
the transfer of control of MidAmerican Energy and other utilities' transmission
assets to TRANSLink in conjunction with TRANSLink's participation in the Midwest
ISO regional transmission organization. MidAmerican Energy has filed
applications for state regulatory approval from states in which TRANSLink will
be operating but does not anticipate rulings until late in 2003. Transferring
the operations and control of MidAmerican Energy's transmission assets to other
entities could increase costs for MidAmerican Energy; however, the actual impact
of TRANSLink on MidAmerican Energy's future transmission costs is not yet known.
On July 31, 2002, the FERC issued a notice of proposed rulemaking with respect
to Standard Market Design. The FERC has characterized the proposal as portending
"sweeping changes" to the use and expansion of the interstate transmission and
wholesale bulk power systems in the United States. The proposal includes
numerous proposed changes in the current regulation of transmission and
generation facilities designed "to promote economic efficiency" and replace the
"obsolete patchwork we have today," according to the FERC's chairman. The final
rule, if adopted as currently proposed, would require all public utilities
operating transmission facilities subject to the FERC jurisdiction to file
revised open access transmission tariffs that would require changes to the basic
services these public utilities currently provide. The
-6-
proposed rule may impact the pricing of MidAmerican Energy's electricity and
transmission products. The FERC does not envision that a final rule will be
fully implemented until 2004. MidAmerican Energy is still evaluating the
proposed rule and recognizes the final rule could vary considerably from the
initial proposal. Accordingly, the likely impact of the proposed rule on
MidAmerican Energy's transmission and generation businesses is unknown.
Gas Operations
- --------------
For the year ended December 31, 2002, regulated gas sales by MidAmerican Energy,
excluding transportation throughput, by customer class were as follows: 39.0%
were to residential customers, 19.7% were to small general service customers,
1.5% were to large general service customers, 1.2% were to other customers, and
38.6% were wholesale sales. For the year ended December 31, 2002, regulated gas
sales by MidAmerican Energy, excluding transportation throughput, by
jurisdiction were as follows: 78.0% to Iowa, 11.2% to South Dakota, 10.0% to
Illinois, and 0.8% to Nebraska.
MidAmerican Energy purchases gas supplies from producers and third party
marketers. To ensure system reliability, a geographically diverse supply
portfolio with varying terms and contract conditions is utilized for the gas
supplies.
MidAmerican Energy has rights to firm pipeline capacity to transport gas to its
service territory through direct interconnects to the pipeline systems of
Northern Natural Gas, Natural Gas Pipeline Company of America, Northern Border
Pipeline Company and ANR Pipeline Company. Firm capacity in excess of
MidAmerican Energy's system needs, resulting from differences between the
capacity portfolio and seasonal system demand, can be resold to other companies
to achieve optimum use of the available capacity. Past IUB and South Dakota
Public Utilities Commission rulings have allowed MidAmerican Energy to retain
30% of Iowa and South Dakota margins, respectively, earned on the resold
capacity, with the remaining 70% being returned to customers through a purchased
gas adjustment clause as described below.
MidAmerican Energy's cost of gas is recovered from customers through purchased
gas adjustment clauses. In 1995, the IUB gave initial approval of MidAmerican
Energy's Incentive Gas Supply Procurement Program. Under the program, as
amended, MidAmerican Energy is required to file with the IUB every six months a
comparison of its gas procurement costs to an index-based and historical
reference price. If MidAmerican Energy's costs of gas for the period are less or
greater than an established tolerance band around the reference price, then
MidAmerican Energy shares a portion of the savings or costs with customers. In
October 2002, the IUB approved a one-year extension of the program through
October 31, 2003. A similar program is currently in effect in South Dakota
through October 31, 2005. Since the implementation of the program, MidAmerican
Energy has successfully achieved and shared savings with its natural gas
customers.
MidAmerican Energy utilizes leased gas storage to meet peak day requirements and
to manage the daily changes in demand due to changes in weather. The storage gas
is typically replaced during the summer months. In addition, MidAmerican Energy
also utilizes three liquefied natural gas plants and two propane-air plants to
meet peak day demands.
MidAmerican Energy has strategically built multiple pipeline interconnections
into several of its larger communities. Multiple pipeline interconnects create
competition among pipeline suppliers for transportation capacity to serve those
communities, thus reducing costs. In addition, multiple pipeline interconnects
give MidAmerican Energy the ability to optimize delivery of the lowest cost
supply from the various pipeline supply basins into these communities and
increase delivery reliability. Benefits to MidAmerican Energy's system customers
are shared with all jurisdictions through a consolidated purchased gas
adjustment clause.
-7-
KERN RIVER
Kern River's principal asset is a 926-mile interstate natural gas transmission
pipeline system, with an original approximate capacity of 700 mmcf per day,
extending from supply areas in the Rocky Mountains to consuming markets in Utah,
Nevada and California. Following the completion of recent expansion projects,
including the 2002 expansion project and the California Action Project, the
design capacity of the pipeline is currently 845.5 mmcf per day. Construction of
the original pipeline began on January 2, 1991 and was completed in early 1992.
Kern River's pipeline is comprised of two distinguishable sections: the mainline
and the common facilities. The 707-mile mainline section extends from the
pipeline's point of origination in Opal, Wyoming through the Central Rocky
Mountains area to Daggett, California and is owned entirely by Kern River. The
common facilities consist of the 219-mile section of pipeline that extends from
Daggett to Bakersfield, California. The common facilities are jointly owned by
Kern River (currently approximately 67.9%) and Mojave Pipeline Company
(currently approximately 32.1%), as tenants-in-common. Kern River's ownership
percentage in the common facilities will increase or decrease pursuant to each
completed expansion by the respective joint owners.
Kern River's 2003 Expansion Project
- -----------------------------------
The 2003 Expansion Project is a new parallel 717-mile loop pipeline that will
begin in Lincoln County, Wyoming and terminate in Kern County, California. The
2003 Expansion Project began construction on August 6, 2002 and is expected to
be completed and operational May 1, 2003 at a total cost of approximately $1.2
billion. The pipeline will include 36- and 42-inch diameter pipe, most of which
will be laid in the existing Kern River rights-of-way at a 25-foot offset from
the existing pipeline, and new above ground facilities. Three segments along the
rights-of-way, approximately 205 miles in Utah, Nevada and California, will not
require additional pipeline but will instead be areas where the gas will be
compressed and transported through the existing pipeline. The existing pipeline
rights-of-way, compressor facilities and receipt/delivery facilities will all be
utilized by the 2003 Expansion Project, streamlining the permitting, acquisition
of rights-of-way and ultimately the construction and operations of the 2003
Expansion Project.
The 2003 Expansion Project includes the construction of three new compressor
stations and the installation of additional compression and other modifications
at six existing facilities. When completed, the Kern River system will have a
summer day design capacity of approximately 1.73 Bcf per day, an increase of
approximately 886 mmcf per day.
Kern River has 18 long-term firm transportation service agreements with 17
shippers for 100% of the 2003 Expansion Project's capacity. The term for all
these service agreements is either 10 or 15 years from the date on which
transportation services on the 2003 Expansion Project commence.
The 2003 Expansion Project is being financed with approximately 70% debt and 30%
equity, consistent with Kern River's original capital structure, the application
for FERC approval of the 2003 Expansion Project and the limitations contained in
the indenture for Kern River's existing secured senior notes. On June 21, 2002,
Kern River entered into an $875 million credit facility to fund a portion of the
costs of the 2003 Expansion Project and the Company issued a completion
guarantee in favor of the lenders under that credit facility.
NORTHERN NATURAL GAS
Northern Natural Gas is one of the largest interstate natural gas pipeline
systems in the United States. It reaches from Texas to Michigan's Upper
Peninsula and is engaged in the transmission and storage of natural gas for
utilities, municipalities, other pipeline companies, gas marketers, industrial
and commercial users and other end users. Northern Natural Gas operates
approximately 16,600 miles of natural gas pipelines with a design capacity of
4.4 Bcf per day that deliver approximately 5.0% of the total natural gas
consumed in the United States. The Northern Natural Gas system is believed to be
the largest in the United States as measured by pipeline miles and the eighth
largest as measured by throughput. The pipeline system is powered by 92
transmission compressor stations with an aggregate of approximately 840,000
horsepower. Northern Natural Gas' storage services are provided through the
operation of three underground storage fields (one in Iowa and two in Kansas)
and two LNG storage peaking units. The three underground natural gas storage
facilities and Northern Natural Gas' two LNG storage peaking units have a total
storage capacity of approximately 59 Bcf and over 1.3 Bcf per day of peak day
deliverability. These storage facilities provide Northern Natural Gas with
operational flexibility for daily balancing of its system and providing services
to customers for meeting their year-round loadswing requirements. In 2002,
approximately 11% of Northern Natural Gas' revenue was generated from storage
services.
Northern Natural Gas' system is comprised of two distinct areas, its traditional
end-use and distribution market area at the
-8-
northern end of the system, including delivery points in Michigan, Illinois,
Iowa, Minnesota, Nebraska, Wisconsin and South Dakota, which the Company refers
to as the Market Area, and the natural gas supply and market area at the
southern end of the system, including Kansas, Oklahoma, Texas and New Mexico,
which the Company refers to as the Field Area. Northern Natural Gas' Field Area
is interconnected with many interstate and intrastate pipelines in the national
grid system. A majority of Northern Natural Gas' capacity in both the Market
Area and the Field Area is dedicated to Market Area customers under long-term
firm transportation contracts. Approximately 49% of Northern Natural Gas'
capacity subject to firm transportation contracts is under contracts that extend
beyond 2005.
The northern portion of Northern Natural Gas' pipeline system transports natural
gas primarily to end-user and local distributor markets in the Market Area.
Customers consist of LDCs, municipalities, other pipeline companies, gas
marketers and end-users. While approximately ten large LDCs account for the
majority of Market Area volumes, Northern Natural Gas also serves numerous small
communities through these large LDCs as well as municipalities or smaller LDCs
and directly serves several large end-users. In 2002, approximately 85% of
Northern Natural Gas' revenue was from capacity charges under firm
transportation and storage contracts and approximately 82% of that revenue was
from LDCs. In 2002, approximately 68% of Northern Natural Gas' revenue was
generated from Market Area customer contracts.
As noted above, the Field Area of Northern Natural Gas' system provides access
to natural gas supply from key production areas such as the Hugoton, Permian and
Anadarko Basins. In each of these areas, Northern Natural Gas has numerous
interconnecting receipt and delivery points, with volumes received in the Field
Area consisting of both directly connected supply and volumes from
interconnections with other pipeline systems. In addition, Northern Natural Gas
has the ability to aggregate processable natural gas for deliveries to various
gas processing facilities.
In the Field Area, customers holding transportation capacity consist of LDCs,
marketers, producers, and end-users. The majority of Northern Natural Gas' Field
Area firm transportation is provided to Northern Natural Gas' Market Area firm
customers under long-term firm transportation contracts with such volumes
supplemented by volumes transported on an interruptible basis or pursuant to
short-term firm contracts. In 2002, approximately 21% of Northern Natural Gas'
revenue was generated from Field Area customer transportation contracts.
Northern Natural Gas' system is characterized by significant seasonal swings in
demand, which provide opportunities to deliver high value-added services.
Because of its location and multiple interconnections with other interstate and
intrastate pipelines, Northern Natural Gas is able to access natural gas both
from traditional production areas, such as the Hugoton, Permian and Anadarko
Basins, as well as growing supply areas such as the Rocky Mountains through
Trailblazer Pipeline Company, Pony Express Pipeline and Colorado Interstate Gas
Company, and from Canadian production areas through Northern Border Pipeline
Company, Great Lakes Gas Transmission Limited Partnership and Viking Gas
Transmission Company. As a result of Northern Natural Gas' geographic location
in the middle of the United States and its many interconnections with other
pipelines, Northern Natural Gas augments its steady end-user and LDC revenue by
taking advantage of opportunities to provide intermediate transportation through
pipeline interconnections for customers in other markets including Chicago,
other parts of the Midwest and Texas.
Northern Natural Gas' revenue is derived from the interstate transportation and
storage of natural gas for third parties. Except for small quantities of natural
gas owned for system operations, Northern Natural Gas does not own the natural
gas that is transported through its system. Northern Natural Gas' transportation
and storage operations are subject to a FERC-regulated tariff that is designed
to allow it an opportunity to recover its costs together with a regulated return
on equity.
Northern Natural Gas' strategic plan is focused on taking advantage of the
system's bi-directional and relatively flexible natural gas transportation
capabilities and its storage assets to maximize economic returns. A key
component of this strategic plan is to build upon Northern Natural Gas' asset
base located in the center of the North American natural gas grid by increasing
flexibility through additional pipeline interconnects. Through existing
interconnections, Northern Natural Gas' shippers have supply access to Canadian,
Rocky Mountain, Hugoton, Anadarko and Permian supplies. Northern Natural Gas
also expects to pursue selective pipeline expansions, storage service
enhancement and improved utilization of existing systems. In addition, Northern
Natural Gas is focused on utilizing its ability to transport both dry natural
gas and processable natural gas to take advantage of opportunities presented by
natural gas processing facility consolidations in the Mid-continent area.
Northern Natural Gas expects to be able to meet the expected demand growth in
its Market Area with only modest investment in new facilities as a result of the
flexibility in Northern Natural Gas' system. Furthermore, Northern Natural Gas'
access to supply diversity is expected to provide it with a significant
competitive advantage because of the ability of the system to provide shippers
access to many sources of low cost natural gas.
-9-
KERN RIVER AND NORTHERN NATURAL GAS COMPETITION
Natural gas competes with other forms of energy, including electricity, coal and
fuel oil, primarily on the basis of price. Legislation and governmental
regulations, the weather, the futures market, production costs, and other
factors beyond the control of Kern River and Northern Natural Gas influence the
price of natural gas. Industrial end-users often have the ability to choose from
alternative fuel sources in addition to natural gas, such as fuel oil and coal.
Pipelines compete on the basis of cost, flexibility, reliability of service and
overall customer service. More specifically, Kern River competes with various
interstate pipelines and its shippers in serving the southern California, Las
Vegas and Salt Lake City market areas, in order to market any unsubscribed
capacity and expansion capacity. Kern River provides its customers with supply
diversity through pipeline interconnects with Northwest Pipeline, Colorado
Interstate Gas Pipeline, Overland Trail Pipeline, and Questar Pipeline. These
interconnects allow Kern River to access natural gas reserves in Colorado,
northwestern New Mexico, Wyoming, Utah and the Western Canadian Sedimentary
Basin.
Approximately 100% of Kern River's original pipeline capacity is contractually
committed with 14 extended term rate shippers until September 30, 2011. Beyond
that, approximately 86% of the original pipeline capacity is contractually
committed, with 11 shippers, until September 30, 2016. Nearly 100% of the
additional permanent capacity constructed in connection with the 2002 expansion
and to be constructed for the 2003 Expansion Project is contractually committed
under 10- and 15-year agreements.
Even though Kern River does not market natural gas supply, in each market area
the purchaser evaluates the total cost of natural gas supply, including
transportation rates, from each alternative supplier/transporter. Based on
published rates and fuel percentages, the Company believes Kern River currently
has the lowest transportation costs from well-head to burner tip of any
interstate pipeline serving its direct markets in Nevada and southern
California, with gas transportation costs of approximately $0.45 per MMBtu
compared to approximately $0.84-$1.29 per MMBtu on competing pipelines. There
can be no assurance that its competitors do not or will not charge rates that
are discounted to these published rates, particularly on a short-term basis. The
2003 Expansion Project shippers' initial tariff rates in the original FERC
filing were $0.57-$0.70 per MMBtu. These rates are expected to be reduced
slightly in a FERC compliance filing Kern River is required to make 60 days
prior to placing the 2003 Expansion Project in service.
Kern River is the only interstate pipeline that presently delivers natural gas
directly from a gas supply basin into the intrastate California market, which
enables its customers to avoid paying a "rate stack" (i.e., additional
transportation costs attributable to the movement from one or more interstate
pipeline systems to an intrastate system within California). The Company
believes that Kern River's rate structure and access to upstream
pipelines/storage facilities and to low-cost Rocky Mountain gas reserves
increases its competitiveness and attractiveness to end-users. Kern River
believes it is advantaged relative to other competing interstate pipelines
because its relatively new pipeline can be expanded at lower costs than those
that apply to other systems and it directly links the market along its system to
low cost Rocky Mountain gas supplies. Kern River's strategic advantages were the
main reasons the electric generation market purposely selected sites next to the
Kern River pipeline to build their new power plants. Kern River expects to
directly serve over 7,000 MW's of new electric generation load, which is
currently under construction or recently placed in commercial operation. Close
to 90% of the 2003 Expansion Project contract demand is with shippers who either
own or intend to serve power generation facilities.
Historically, Northern Natural Gas has been able to provide competitive cost
service because of its access to a variety of low cost supply basins, its cost
control measures and its relatively high load factor through-put, which lowers
the cost per unit of transportation. Although Northern Natural Gas has
experienced pipeline system bypass affecting a small percentage of its market,
to date Northern Natural Gas has been able to more than offset any load lost to
bypass in the Market Area through expansion projects such as the Peak Day 2000
project.
Major competitors in the Market Area include ANR Pipeline Company and Natural
Gas Pipeline Company of America. Other competitors include Northern Border
Pipeline Company, Great Lakes Gas Transmission Limited Partnership and Viking
Gas Transmission Company. In the Field Area, Northern Natural Gas competes with
a large number of other competitors. Particularly in the Field Area, a
significant amount of Northern Natural Gas' capacity is used on an interruptible
or short-term basis. In summer months, Northern Natural Gas' Market Area
customers often release significant amounts of their unused firm capacity to
other shippers, which competes with Northern Natural Gas' short-term or
interruptible services.
Northern Natural Gas believes that current and anticipated changes in its
competitive environment have created
-10-
opportunities to serve existing customers more efficiently and to meet certain
growing supply needs. While LDCs provide peak day delivery growth driven by
population growth and alternative fuel replacement, new off-peak demand growth
is being driven primarily by power and ethanol plant expansion. Off-peak demand
growth is important to Northern Natural Gas as this demand can generally be
satisfied with little or no requirement for the construction of new facilities.
Approximately 3,800 MW of natural gas-fired electric power plants in development
have been announced in close proximity to Northern Natural Gas' system. Northern
Natural Gas has been successful in competing for a significant amount of the
increased demand related to the construction of new power and ethanol plants.
Over the last five years, Northern Natural Gas has contracted approximately 430
mmcf per day of volume on its system from such new facilities, of which
approximately 258 mmcf per day is currently in service and approximately 172
mmcf per day is scheduled to begin service between 2003 and 2005.
CE ELECTRIC UK
The business of CE Electric UK consists primarily of the distribution of
electricity in the United Kingdom by Northern Electric and Yorkshire.
In December 1996, CE Electric UK Ltd., an indirect wholly owned subsidiary of CE
Electric UK, acquired Northern Electric. Northern Electric was one of the twelve
original United Kingdom regional electric companies that came into existence in
1990 as a result of the restructuring and subsequent privatization of the
electricity industry that occurred in the United Kingdom. On September 21, 2001,
CE Electric UK Ltd. acquired 94.75% of Yorkshire from Innogy Holdings plc
("Innogy"), and simultaneously sold Northern Electric's electricity and gas
supply and metering businesses to Innogy. The Company sometimes refers to these
transactions as the "Yorkshire Swap". In August 2002, CE Electric UK acquired
the remaining 5.25% of Yorkshire that it did not already own from Xcel Energy
International ("Xcel Energy"), an affiliate of Xcel Energy Inc.
With the acquisition of Yorkshire and the disposition of the electricity and gas
supply and metering businesses of Northern Electric and certain other recent
strategic dispositions, CE Electric UK is positioned to continue to bring
together the skills and resources of two neighboring distribution businesses to
create one of the largest distribution companies in the United Kingdom, serving
more than 3.6 million customers in an area of approximately 10,000 square miles.
CE Electric UK has also implemented a number of initiatives that have produced
savings in ongoing operating and capital costs at its businesses.
Descriptions of the functional business units of each of Northern Electric's and
Yorkshire's distribution businesses are set forth below.
Electricity Distribution
- ------------------------
Northern Electric's and Yorkshire's operations consist primarily of the
distribution of electricity and other auxiliary businesses in the United
Kingdom. Northern Electric's and Yorkshire's distribution licensee companies,
Northern Electric Distribution Limited ("NEDL"), and Yorkshire Electricity
Distribution plc ("YEDL"), respectively, receive electricity from the national
grid transmission system and distribute it to their customers' premises using
their network of transformers, switchgear and cables. Substantially all of the
customers in NEDL's and YEDL's distribution service areas are connected to the
NEDL and YEDL networks and electricity can only be delivered through their
distribution system, thus providing NEDL and YEDL with distribution volume that
is relatively stable from year to year. NEDL and YEDL charge fees for the use of
the distribution system to the suppliers of electricity. The suppliers, which
purchase electricity from generators and sell the electricity to end-user
customers, use NEDL's and YEDL's distribution networks pursuant to an industry
standard "Use of System Agreement" which NEDL and YEDL separately entered into
with the various suppliers of electricity in their respective distribution
areas. The fees that may be charged by NEDL and YEDL for use of their
distribution systems are controlled by a prescribed formula that limits
increases (and may require decreases) based upon the rate of inflation in the
United Kingdom and other regulatory action.
At December 31, 2002, NEDL's and YEDL's electricity distribution network
(excluding service connections to consumers) on a combined basis included
approximately 31,000 kilometers of overhead lines and approximately 65,000
kilometers of underground cables. In addition to the circuits referred to above,
at December 31, 2002, NEDL's and YEDL's distribution facilities also included
approximately 57,000 transformers and approximately 58,000 substations.
Substantially all substations are owned in freehold, and most of the balance are
held on leases that will not expire within 10 years.
-11-
Utility Services
- ----------------
Integrated Utility Services Limited ("IUS"), a subsidiary of Northern Electric,
is an engineering contracting company whose main business is providing
electrical connection services on behalf of NEDL's and YEDL's distribution
businesses and providing electrical infrastructure contracting services to third
parties.
Gas Exploration and Production
- ------------------------------
CE Gas is a gas exploration and production company that is focused on developing
integrated upstream gas projects. Its upstream gas business consists of the
exploration, development and production, including transportation and storage,
of gas for delivery to a point of sale into either a gas supply market or a
power generation facility.
In May 2002, CE Gas, an indirect wholly owned subsidiary of the Company,
executed the sale of several of its U.K. natural gas assets to Gaz de France for
(pound)137.0 million (approximately $200.0 million). CE Gas sold four natural
gas-producing fields located in the southern basin of the U.K. North Sea,
including Anglia, Johnston, Schooner and Windermere. The transaction also
included the sale of rights in four gas fields (in development/construction) and
three exploration blocks owned by CE Gas.
In addition to retaining its interest in the Victor Field and the ETS pipeline,
CE Gas retained certain development interests in Poland (Polish Trough) and
Australia (Perth, Bass and Otway Basins).
-12-
CALENERGY GENERATION - DOMESTIC
Business
Through CalEnergy Generation - Domestic, the Company owns interests in 15
operating non-utility power projects in the United States. The following table
sets out certain information concerning CalEnergy Generation-Domestic's
non-utility power projects in operation as of December 31, 2002:
FACILITY NET PURCHASE
CAPACITY NET MW AGREEMENT
OPERATING PROJECT (MW) (1) OWNED (1) FUEL LOCATION EXPIRATION POWER PURCHASER (2)
- ---------------------- ------------- --------- ---- ---------- ----------- -------------------
Cordova ...................... 537 537 Gas Illinois 2017 El Paso/MidAmerican Energy
Salton Sea I ................. 10 5 Geo California 2017 Edison
Salton Sea II ................ 20 10 Geo California 2020 Edison
Salton Sea III ............... 50 25 Geo California 2019 Edison
Salton Sea IV ................ 40 20 Geo California 2026 Edison
Salton Sea V ................. 49 25 Geo California Year-to-year El Paso/Minerals(3)
Vulcan ....................... 34 17 Geo California 2016 Edison
Elmore ....................... 38 19 Geo California 2018 Edison
Leathers ..................... 38 19 Geo California 2019 Edison
Del Ranch .................... 38 19 Geo California 2019 Edison
CE Turbo ..................... 10 5 Geo California Year-to-year El Paso/Minerals(3)
Saranac ...................... 240 90 Gas New York 2009 NYSE&G
Power Resources .............. 200 100 Gas Texas 2003 TXU
Yuma ......................... 50 25 Gas Arizona 2024 SDG&E
Roosevelt Hot Springs (4) .... 23 17 Geo California Year-to-year UP&L
----- ---
DOMESTIC OPERATING PROJECTS .. 1,377 933
===== ===
(1) Represents accredited net generating capability. Actual MW may vary
depending on operating conditions and plant design. Net MW owned indicates
current legal ownership, but, in some cases, does not reflect the current
allocation of partnership distributions.
(2) El Paso Corporation ("El Paso"); Southern California Edison Company
("Edison"); CalEnergy Minerals LLC ("Minerals"), a zinc facility owned by a
subsidiary of the Company; New York State Electric & Gas Corporation
("NYSE&G"), TXU Generation Company LP ("TXU"); San Diego Gas & Electric
Company ("SDG&E"), and Utah Power & Light Company ("UP&L").
(3) Each contract governing power purchases by Minerals will expire 33 years
from the date of the initial power delivery under such contract. Pursuant
to a Transaction Agreement dated January 29, 2003, Salton Sea Power LLC
("Salton Sea Power") and CE Turbo LLC ("CE Turbo") began selling available
power to a subsidiary of TransAlta Corporation ("TransAlta") on February
12, 2003 based on percentages of the Dow Jones SP-15 Index. Such agreement
will expire on October 31, 2003.
(4) The Company's subsidiary owns an approximately 70% indirect interest in
this project which supplies geothermal steam to a power plant owned by
UP&L. The Company obtained a cash prepayment under a pre-sale agreement
with UP&L whereby UP&L paid in advance for the steam produced by this steam
field.
Cordova Energy owns a 537 MW gas-fired power plant in the Quad Cities, Illinois
area that the Company refers to as the Cordova Project. CalEnergy Generation
Operating Company, its indirect wholly owned subsidiary, operates the Cordova
Project. The Cordova Project commenced commercial operations in June 2001.
Cordova Energy entered into a power purchase agreement with a unit of El Paso,
under which El Paso will purchase all of the capacity and energy from the
project until December 31, 2019. Cordova Energy has exercised an option to
recall from El Paso 50% of the output through May 14, 2004, reducing El Paso's
purchase obligation to 50% of the output during such period. The recalled output
is being sold to MidAmerican Energy. The Company is aware there have been public
announcements that El Paso's financial condition has deteriorated as a result
of, among other things, reduced liquidity. The Company will continue to monitor
the situation.
-13-
MEHC has a 50% ownership interest in CE Generation, whose affiliates currently
operate ten geothermal plants (the "Imperial Valley Projects") in the Imperial
Valley in California. The "Salton Sea Projects" consist of the Salton Sea I,
Salton Sea II, Salton Sea III, Salton Sea IV and Salton Sea V Projects (the
"Salton Sea I Project", the "Salton Sea II Project", the "Salton Sea III
Project," the "Salton Sea IV Project," and the "Salton Sea V Project"
respectively). The "Partnership Projects" consist of the Vulcan, Elmore,
Leathers, Del Ranch and CE Turbo projects (the "Vulcan Project," the "Elmore
Project", the "Leathers Project", the "Del Ranch Project," and the "CE Turbo
Project" respectively). The CE Turbo Project and the Salton Sea V Project
commenced commercial operations in 2000.
Each of the Imperial Valley Projects, excluding the Salton Sea V and CE Turbo
Projects, sells electricity to Edison pursuant to a separate Standard Offer No.
4 Agreement ("SO4 Agreement") or a negotiated power purchase agreement. Each
power purchase agreement is independent of the others, and the performance
requirements specified within one such agreement apply only to the project,
which is subject to the agreement. The power purchase agreements provide for
energy payments, capacity payments and capacity bonus payments. Edison makes
fixed annual capacity payments and capacity bonus payments to the applicable
projects to the extent that capacity factors exceed certain benchmarks. The
price for capacity was fixed for the life of the SO4 Agreements and is
significantly higher in the months of June through September.
Energy payments for the SO4 Agreements were at increasing fixed rates for the
first ten years after firm operation and thereafter at a rate based on the cost
that Edison avoids by purchasing energy from the project instead of obtaining
the energy from other sources ("Avoided Cost of Energy"). In June and November
2001, the Imperial Valley Projects, which receive Edison's Avoided Cost of
Energy, entered into agreements that provide for amended energy payments under
the SO4 Agreements. The amendments provide for fixed energy payments per kWh in
lieu of Edison's Avoided Cost of Energy. The fixed energy payment was 3.25 cents
per kWh from December 1, 2001 through April 30, 2002 and is 5.37 cents per kWh
commencing May 1, 2002 for a five-year period. Following the five-year period,
the energy payments revert back to Edison's Avoided Cost of Energy.
For the years ended December 31, 2002, 2001 and 2000, respectively, Edison's
Average Avoided Cost of Energy was 3.5 cents per kWh, 7.4 cents per kWh and 5.8
cents per kWh, respectively. Estimates of Edison's future Avoided Cost of Energy
vary substantially from year to year.
The Salton Sea V and CE Turbo projects began operations in 2000 and, when the
Zinc Recovery Project (defined below) achieves 100% production, the Salton Sea V
Project and the CE Turbo Project would expect to sell approximately 22 MW to the
Zinc Recovery Project at a price based on market transactions. The remainder is
being sold through other market transactions.
The Saranac Project is a 240 net MW natural gas-fired cogeneration facility
located in Plattsburgh, New York. The Saranac Project has entered into a 15-year
power purchase agreement with NYSE&G expiring in 2009. The Saranac Project is a
qualifying facility ("QF") and has entered into 15-year steam purchase
agreements with Georgia-Pacific Corporation and Pactiv Corporation. The Saranac
Project has a 15-year natural gas supply agreement with Shell Canada Limited, to
supply 100% of the Saranac Project's fuel requirements. Each of the Saranac
power purchase agreement, the Saranac steam purchase agreements and the Saranac
gas supply agreement contains rates that are fixed for their respective contract
terms. Revenues escalate at a higher rate than fuel costs. The Saranac
partnership is indirectly owned by subsidiaries of CE Generation, ArcLight
Capital Partners LLC and General Electric Capital Corporation.
The Power Resources Project is a 200 net MW natural gas-fired cogeneration
project located near Big Spring, Texas, which has a 15-year power purchase
agreement with TXU Generation Company LP, formerly known as Texas Utilities
Electric Company expiring in 2003. The Power Resources Project is a QF and has a
steam purchase agreement with Alon USA, L.P. On December 30, 2002, Power
Resources obtained an exempt wholesale generator order from the FERC. The status
as an exempt wholesale generator would facilitate the Power Resources Project
sale of energy in market transactions.
The Yuma Project is a 50 net MW natural gas-fired cogeneration project in Yuma,
Arizona providing 50 MW of electricity to SDG&E under an existing 30-year power
purchase agreement which expires in 2024. The Yuma project is a QF and has
executed steam sales contracts with an adjacent industrial entity to act as its
thermal host.
The Roosevelt Hot Springs Project is a geothermal steam field which supplies
geothermal steam to a 23 net MW power plant owned by UP&L located on the
Roosevelt Hot Springs property under a 30-year steam sales contract expiring in
2020. The Company obtained a cash prepayment under a pre-sale agreement with
UP&L
-14-
whereby UP&L paid in advance for the steam produced by the steam field. The
Company guarantees the performance of this subsidiary. The Company must make
certain penalty payments to UP&L if the steam produced does not meet certain
quantity and quality requirements.
Zinc Recovery Project
- ---------------------
Minerals developed and owns the rights to proprietary processes for the
extraction of zinc from elements in solution in the geothermal brine and fluids
utilized at the Imperial Valley Projects. A plant has successfully produced
commercial quality zinc at the projects. The affiliates of Minerals may develop
facilities for the extraction of manganese, silica and other products as they
further develop the extraction technology.
Minerals constructed the Zinc Recovery Project, which is recovering zinc from
the geothermal brine (the "Zinc Recovery Project"). Facilities have been
installed near the Imperial Valley Projects sites to extract a zinc chloride
solution from the geothermal brine through an ion exchange process. This
solution is being transported to a central processing plant where zinc ingots
are being produced through solvent extraction, electrowinning and casting
processes. The Zinc Recovery Project is designed to have a capacity of
approximately 30,000 metric tons per year. Limited production began during
December 2002 and full production is expected by late-2003. In September 1999,
Minerals entered into a sales agreement whereby all high-grade zinc produced by
the Zinc Recovery Project will be sold to Cominco, Ltd. The initial term of the
agreement expires in December 2005.
Development Projects
- --------------------
The Company's subsidiary, Fox Energy Company LLC ("Fox"), is evaluating the
development of a 635 net MW gas fired power generating facility in Kaukanna,
Outagamie County, Wisconsin. A subsidiary of TransAlta has agreed to participate
in the development of this project at a level of 50% and has an option to own
50% of the project. The Public Service Commission of Wisconsin issued a
Certificate of Public Convenience and Necessity on November 8, 2002. An air
permit for construction and initial operations was issued by the Wisconsin
Department of Natural Resources on November 4, 2000 and such application was
deemed complete on April 25, 2002. A final environmental impact statement was
issued by the Wisconsin Department of Natural Resources on August 19, 2002.
Electrical and natural gas interconnection agreements and a water supply
agreement have also been executed for this project.
The Company's subsidiary, CE Obsidian Energy LLC ("Obsidian"), is evaluating the
development of a 185 net MW geothermal facility in Imperial Valley, California.
Substantially all the output of the facility will be sold to the Imperial
Irrigation Disctrict pursuant to a power purchase agreement. An affiliate of
TransAlta has elected to participate in the ownership and development of this
project at a level of 50%. On July 29, 2002, Obsidian filed an application for
certification seeking approval from the California Energy Commission to
construct and operate the facility.
CALENERGY GENERATION - FOREIGN
Business
- --------
The Company indirectly owns the Upper Mahiao, Malitbog and Mahanagdong projects,
which are geothermal power plants located on the island of Leyte in the
Philippines, and the Casecnan Project, a combined irrigation and hydroelectric
power generation project, which is located in the central part of Island of
Luzon in the Philippines. Each plant possesses an operating margin that allows
for production in excess of the amount listed below. Utilization of this
operating margin is based upon a variety of factors and can be expected to vary
between calendar quarters under normal operating conditions.
-15-
Operating Projects
- ------------------
The following table sets out certain information concerning CalEnergy
Generation-Foreign's non-utility power projects in operation as of December 31,
2002:
FACILITY NET POWER
CAPACITY NET MW COMMERCIAL PURCHASER/
OPERATING PROJECT (1) (MW) (2) OWNED (2) FUEL OPERATION GUARANTOR (3)
- -------------------------------- ------------ --------- ------ ------------ -------------
Upper Mahiao ................... 119 119 Geo 1996 PNOC-EDC/ROP
Mahanagdong .................... 165 155 Geo 1997 PNOC-EDC/ROP
Malitbog ....................... 216 216 Geo 1996-97 PNOC-EDC/ROP
Casecnan (4) ................... 150 150 Hydro 2001 NIA/ROP
--- ---
INTERNATIONAL OPERATING PROJECTS 650 640
=== ===
(1) All operating projects are located in the Philippines; all operating
projects are governed by contracts which are payable in U.S. dollars; and
all operating projects carry political risk insurance.
(2) Actual MW may vary depending on operating and reservoir conditions and
plant design. Facility Net Capacity (MW) represents the contract capacity
for the facility. Net MW owned indicates current legal ownership, but, in
some cases, does not reflect the current allocation of distributions.
(3) PNOC-Energy Development Corporation ("PNOC-EDC"), Republic of the
Philippines ("ROP"), and National Irrigation Administration ("NIA") (NIA
also purchases water from this facility). The government of the Philippines
undertaking supports PNOC-EDC's and NIA's respective obligations.
(4) Net MW Owned is subject to repurchase rights of up to 15% of the project by
an initial minority shareholder and a dispute with the other initial
minority shareholder regarding an additional 15% of the project. Also see
"Legal Proceedings-Philippines."
The Upper Mahiao project is a 119 net MW geothermal power project owned and
operated by CE Cebu Geothermal Power Company, Inc. ("CE Cebu"), a Philippine
corporation that is 100% indirectly owned by the Company. The Upper Mahiao
facility has been in commercial operation since June 17, 1996.
Under the terms of the Upper Mahiao energy conversion agreement, CE Cebu owns
and operates the Upper Mahiao Project during the ten-year cooperation period,
which commenced in June 1996, after which ownership will be transferred to
PNOC-Energy Development Corporation at no cost.
The Upper Mahiao Project is located on land provided by PNOC-EDC at no cost. The
project takes geothermal steam and fluid, also provided by PNOC-EDC at no cost,
and converts its thermal energy into electrical energy which is sold to PNOC-EDC
on a "take-or-pay" basis, which in turn sells the power to the National Power
Corporation (`NPC"), for distribution on the island of Cebu. PNOC-EDC pays to CE
Cebu a fee based on the plant capacity nominated to PNOC-EDC in any year (which,
at the plant's design capacity, is approximately 95% of total contract revenue)
and a fee based on the electricity actually delivered to PNOC-EDC (approximately
5% of total contract revenue). Payments under the Upper Mahiao agreement are
denominated in U.S. dollars, or computed in U.S. dollars and paid in pesos at
the then-current exchange rate, except for the energy fee. PNOC-EDC's payment
requirements, and its other obligations under the Upper Mahiao agreement, are
supported by the ROP through a performance undertaking.
The Mahanagdong Project is a 165 net MW geothermal power project owned and
operated by CE Luzon Geothermal Power Company, Inc. ("CE Luzon"), a Philippine
corporation of which the Company indirectly owns 100% of the common stock.
Another industrial company owns an approximate 6% preferred equity interest in
the Mahanagdong Project. The Mahanagdong Project has been in commercial
operation since July 25, 1997. The Mahanagdong Project sells 100% of its
capacity on a similar basis as described above for the Upper Mahiao Project to
PNOC-EDC, which in turn sells the power to the NPC for distribution on the
island of Luzon.
The terms of the Mahanagdong energy conversion agreement are substantially
similar to those of the Upper Mahiao agreement. The Mahanagdong agreement
provides for a ten-year cooperation period. At the end of the cooperation
period, the facility will be transferred to PNOC-EDC at no cost. All of
PNOC-EDC's obligations under the Mahanagdong agreement are supported by the ROP
through a performance undertaking. The capacity fees are approximately 97% of
total revenue at the design capacity levels and the energy fees are
approximately 3% of such total revenue. PNOC-EDC's payment requirements, and its
other obligations under the Mahanagdong agreement, are supported by the ROP
through
-16-
a performance undertaking.
The Malitbog Project is a 216 net MW geothermal project owned and operated by
Visayas Geothermal Power Company ("VGPC"), a Philippine general partnership that
is wholly owned, indirectly, by the Company. The three units of the Malitbog
facility were put into commercial operation on July 25, 1996 (for Unit I) and
July 25, 1997 (for Units II and III). VGPC sells 100% of its capacity on
substantially the same basis as described above for the Upper Mahiao Project to
PNOC-EDC, which sells the power to the NPC for distribution on the islands of
Cebu and Luzon.
The electrical energy produced by the facility is sold to PNOC-EDC on a
take-or-pay basis. These capacity payments equal approximately 100% of total
revenue. A substantial majority of the capacity payments are required to be made
by PNOC-EDC in dollars. The portion of capacity payments payable to PNOC-EDC in
pesos is expected to vary over the term of the Malitbog energy conversion
agreement from 10% of VGPC's revenue in the early years of the 10-year
cooperation period to 23% of VGPC's revenue at the end of the cooperation
period. Payments made in pesos will generally be made to a peso-dominated
account and will be used to pay peso-denominated operation and maintenance
expenses with respect to the Malitbog Project and Philippine withholding taxes,
if any, on the Malitbog Project's debt service. The government of the
Philippines has entered into a performance undertaking, which provides that all
of PNOC-EDC's obligations pursuant to the Malitbog energy conversion agreement
carry the full faith and credit of, and are affirmed and guaranteed by, the ROP.
The Malitbog energy conversion agreement cooperation period expires ten years
after the date of commencement of commercial operation of Unit III. At the end
of this cooperation period, the facility will be transferred to PNOC-EDC at no
cost, on an "as is" basis. See "Legal Proceedings - Philippines" for a
description of legal proceedings related to the Malitbog Project.
CE Casecnan Ltd. ("CE Casecnan"), the Company's indirectly majority owned
subsidiary, operates the Casecnan Project, a combined irrigation and 150 Net MW
hydroelectric power generation project. The Casecnan Project consists generally
of diversion structures in the Casecnan and Taan rivers that capture and divert
excess water in the Casecnan watershed by means of concrete, in-stream diversion
weirs and transfer that water through a transbasin tunnel of approximately 23
kilometers (including the intake adit from the Taan to the Casecnan river), with
a diameter of approximately 6.5 meters to an existing underutilized water
storage reservoir at Pantabangan. During the water transfer, the elevation
differences between the two watersheds allows electrical energy to be generated
at a 150 MW rated capacity power plant, which is located in an underground
powerhouse cavern at the end of the water tunnel. A tailrace discharge tunnel of
approximately three kilometers delivers water from the water tunnel and the new
powerhouse to the Pantabangan reservoir, providing additional water for
irrigation and increasing the potential electrical generation at two downstream
existing hydroelectric facilities of the Philippine National Power Corporation
("NPC"), the government-owned and controlled corporation that is the primary
supplier of electricity in the Philippines. Since the water has been determined
to remain suitable for irrigation throughout the Casecnan Project operations of
capturing, diverting and transferring the water, other than removing sediments
at the diversion structures, no treatment is required. Once in the reservoir at
Pantabangan, the water is under the control of, and for the use of the NIA.
CE Casecnan constructed and operates the Casecnan Project under the terms of the
Project Agreement between CE Casecnan and NIA. Under the Project Agreement, CE
Casecnan developed, financed and constructed the Casecnan Project during the
construction period and will own and operate the Project during the 20-year
Cooperation Period. During the Cooperation Period, NIA is obligated to accept
all deliveries of water and energy, and so long as the Casecnan Project is
physically capable of operating and delivering in accordance with agreed levels
set forth in the Project Agreement, NIA will pay CE Casecnan a fixed fee for the
delivery of water and a fixed fee for the delivery of a threshold amount of
electricity. In addition, NIA will pay a fee for all electricity delivered in
excess of the threshold amount up to a specified amount. The water delivery fee
is a fixed monthly amount, to be received in US dollars at the end of each
month, based on 801.9 million cubic meters of water flow past the water delivery
point per year, pro-rated to 66.8 million cubic meters per month. The unit price
for water is established at $0.029 per cubic meter (subject to adjustment as set
forth in the Project Agreement) as of January 1, 1994 and escalated at seven and
one-half percent (7.5%) per annum, pro-rated on a monthly basis, through the end
of the fifth year of the Cooperation Period and then kept flat at that level for
the last fifteen years of the Cooperation Period. The unit price for water is to
be adjusted by $.00043 for each $1.0 million of certain taxes and fees paid by
the Company as specified in the Project Agreement. The unit price of water as of
December 31 2002 is $0.1017. Actual deliveries of water greater than or less
than 66.8 million cubic meters in any month will not result in any adjustment of
the water delivery fee. The guaranteed energy fee is a fixed monthly amount, to
be received in US dollars at the end of each month, based on energy deliveries
of 228.0 million kWh per year, pro-rated to 19.0 million kWh per month. Actual
deliveries of energy less than 19.0 million kWh per month will not result in any
reduction of the guaranteed energy fee but will result in an adjustment to the
excess energy fee. The unit price for
-17-
guaranteed energy is $0.1596 per kWh. The excess energy fee is a variable
amount, to be received in US dollars at the end of each month, for electrical
energy delivered in that month in excess of 19.0 million kWh. No excess energy
delivery fee will be due until all cumulative electrical energy shortfalls below
19.0 million kWh in previous months have been made up. The unit price of excess
energy is $0.1509 per kWh. NIA will sell the electricity it purchases to NPC,
although NIA's obligations to CE Casecnan under the Project Agreement are not
dependent on NPC's purchase of the electricity from NIA. All fees to be paid by
NIA to CE Casecnan are payable in US dollars. The fixed fees paid for the
delivery of water and energy, regardless of the amount of electricity or water
actually delivered, are expected to provide approximately 78% of CE Casecnan's
revenues. At the end of the Cooperation Period, the Casecnan Project will be
transferred to NIA at no additional consideration on an "as is" basis.
The ROP has provided a Performance Undertaking under which NIA's obligations
under the Project Agreement are guaranteed by the full faith and credit of the
ROP. The Project Agreement and the Performance Undertaking provide for the
resolution of disputes by binding arbitration in Singapore under international
arbitration rules.
HOMESERVICES
Business
- --------
HomeServices is the second largest full-service independent residential real
estate brokerage firm in the United States. In addition to providing traditional
residential real estate brokerage services, HomeServices offers other integrated
real estate services, including mortgage originations, title and closing
services and other related services. HomeServices currently operates in 15
states under the following brand names: Carol Jones Realty, CBSHOME Real Estate,
Champion Realty, Edina Realty HomeServices, First Realty/GMAC, Home Real Estate,
Iowa Realty, Jenny Pruitt and Associates REALTORS, Long Realty, Prudential
California Realty, RealtySouth, Reece & Nichols, Semonin REALTORS and Woods
Bros. Realty. HomeServices generally occupies the number one or number two
market share position in each of its major markets based on aggregate closed
transaction sides. HomeServices' major markets consist of the following
metropolitan areas: Minneapolis and St. Paul, Minnesota; Los Angeles and San
Diego, California; Kansas City, Kansas; Des Moines, Iowa; Omaha and Lincoln,
Nebraska; Birmingham, Alabama; Tucson, Arizona; Louisville, Kentucky; Annapolis,
Maryland; Atlanta, Georgia and Springfield, Missouri.
HomeServices' 2002 Acquisitions
- -------------------------------
In 2002, HomeServices separately acquired three real estate companies. For the
year ended December 31, 2001, these real estate companies had combined revenue
of approximately $356.0 million on 42,000 closed sides representing $13.7
billion of sales volume.
-18-
REGULATORY MATTERS
The Company's operating platforms are subject to a number of federal, state,
local and international regulations.
MIDAMERICAN ENERGY
MidAmerican Energy is subject to comprehensive regulation by the FERC as well as
utility regulatory agencies in Iowa, Illinois and South Dakota that
significantly influences the operating environment and the recoverability of
costs from utility customers. Except for Illinois, that regulatory environment
has to date, in general, given MidAmerican Energy an exclusive right to serve
electricity customers within its service territory and, in turn, the obligation
to provide electric service to those customers. In Illinois all customers are
free to choose their electricity provider. MidAmerican Energy has an obligation
to serve customers at regulated rates that leave MidAmerican Energy's system,
but later choose to return. To date, there has been no significant loss of
customers from MidAmerican Energy's existing regulated Illinois rates.
In connection with the March 1999 approval by the IUB of the MidAmerican Energy
acquisition and March 2000 affirmation as part of the Company's acquisition by a
private investor group, MidAmerican Energy agreed, among other things, to use
all commercially reasonable efforts to maintain an investment grade credit
rating for MidAmerican Energy's utility operations and its long-term debt and to
seek the approval of the IUB of a reasonable utility capital structure if
MidAmerican Energy's utility operations' common equity level decreases below
42%, excluding circumstances beyond its control, or below 39%, under any
circumstances. MidAmerican Energy's utility operations' common equity level at
December 31, 2002 and 2001, was above these levels.
With the elimination of its energy adjustment clause in Iowa in 1997,
MidAmerican Energy is financially exposed to movements in energy prices.
Although MidAmerican Energy has sufficient low cost generation under typical
operating conditions for its retail electric needs, a loss of adequate
generation by MidAmerican Energy requiring the purchase of replacement power at
a time of high market prices could subject MidAmerican Energy to losses on its
energy sales.
In December 1999, the FERC issued Order No. 2000 establishing, among other
things, minimum characteristics and functions for regional transmission
organizations. Public utilities that were not a member of an independent system
operator at the time of the order were required to submit a plan by which their
transmission facilities would be transferred to a regional transmission
organization. On September 28, 2001, MidAmerican Energy and five other electric
utilities filed with the FERC a plan to create TRANSLink Transmission Company
LLC ("TRANSLink") and to integrate their electric transmission systems into a
single, coordinated system operating as a for-profit independent transmission
company in conjunction with a FERC approved regional transmission organization.
On April 25, 2002, the FERC issued an order approving the transfer of control of
MidAmerican Energy's and other utilities' transmission assets to TRANSLink in
conjunction with TRANSLink's participation in the Midwest ISO. Additionally,
state regulatory approval is required from states in which TRANSLink will be
operating, MidAmerican Energy does not anticipate rulings in the state
proceedings until some time in late 2003. Transferring operation and control of
MidAmerican Energy's transmission assets to other entities could increase costs
for MidAmerican Energy; however, the actual impact of TRANSLink on MidAmerican
Energy's future transmission costs is not yet known.
On July 31, 2002, the FERC issued a notice of proposed rulemaking with respect
to Standard Market Design for the electric industry. The FERC has characterized
the proposal as portending "sweeping changes" to the use and expansion of the
interstate transmission and the wholesale bulk power systems in the United
States. The proposal includes numerous proposed changes to the current
regulation of transmission and generation facilities designed "to promote
economic efficiency" and replace the "obsolete patchwork we have today,"
according to the FERC's chairman. The final rule, if adopted as currently
proposed, would require all public utilities operating transmission facilities
subject to the FERC jurisdiction to file revised open access transmission
tariffs that would require changes to the basic services these public utilities
currently provide. The proposed rule may impact the costs and/or pricing of
MidAmerican Energy's electricity and transmission products. The FERC does not
envision that a final rule will be fully implemented until September 30, 2004.
MidAmerican Energy is still evaluating the proposed rule, and believes that the
final rule could vary considerably from the initial proposal. Accordingly,
MidAmerican Energy is presently unable to quantify the likely impact of the
proposed rule.
The structure of such federal and state energy regulations have in the past, and
may in the future, be the subject of various challenges and restructuring
proposals by utilities and other industry participants. The implementation of
regulatory changes in response to such changes or restructuring proposals, or
otherwise imposing more comprehensive or stringent requirements on MidAmerican
Energy which would result in increased compliance costs, could have a material
adverse effect on its results of operations.
Under a settlement agreement approved by the IUB on December 21, 2001,
MidAmerican Energy's Iowa retail rates in effect
-19-
on December 31, 2000 are frozen through December 31, 2005. In approving that
settlement, the IUB specifically allows the filing of the electric rate design
and/or cost of service rate changes that are intended to keep overall company
revenue unchanged but could result in changes to individual tariffs. Under the
2001 settlement agreement further provides that an amount equal to 50% of
revenues associated with Iowa retail electric returns on equity between 12% and
14%, and 83.33% of revenues associated with Iowa retail electric returns on
equity above 14%, in each year is recorded as a regulatory liability to be used
to offset a portion of the cost to Iowa customers of future generating plant
investment. An amount equal to the regulatory liability is recorded as a
regulatory charge in depreciation and amortization expense when the liability is
accrued. Interest expense is accrued on the portion of the regulatory liability
related to prior years. Beginning in 2002, the liability is being reduced as it
is credited against allowance for funds used during construction or capitalized
financing costs associated with generating plant additions. As of December 31,
2002, the related regulatory liability was $102.9 million.
On March 20, 2003, MidAmerican Energy and the Iowa Office of Consumer Advocate
agreed upon a settlement proposal in which the rate freeze described above would
be extended through December 31, 2010. Under the settlement proposal, for
calendar years 2006 through 2010, an amount equal to 40% of revenues associated
with Iowa retail electric returns on equity between 11.75% and 13.0%; 50% of
revenues associated with Iowa retail electric returns on equity between 13.0%
and 14.0%; and 83.3% of revenues associated with Iowa retail electric returns on
equity greater than 14.0% will be applied as a reduction to offset some of the
capital costs on the Iowa portion of three generation projects. If Iowa retail
electric returns on equity fall below 10% in any 12-month period after January
1, 2006, MidAmerican Energy has the ability to file for a general increase in
rates under the proposed settlement. The proposed settlement is subject to
approval by the IUB and requires enactment of Iowa legislation. The IUB is
expected to rule on the proposal during the second half of 2003.
Under an Illinois restructuring law enacted in 1997, as amended in 2002, a
sharing mechanism is in place for MidAmerican Energy's Illinois regulated retail
electric operations whereby earnings above a computed level of return on common
equity will be shared equally between customers and MidAmerican Energy.
MidAmerican Energy's computed level of return on common equity is based on a
rolling two-year average of the Monthly Treasury Long-Term Average Rate, as
published by the Federal Reserve System, plus a premium of 8.5% for 2000 through
2004 and a premium of 12.5% for 2005 and 2006. The two-year average above which
sharing must occur for 2002 was 14.03%. The law allows MidAmerican Energy to
mitigate the sharing of earnings above the threshold return on common equity
through accelerated recovery of regulatory assets.
On March 15, 2002, MidAmerican Energy made a filing with the IUB requesting an
increase in rates. On June 12, 2002, the IUB issued an order granting
MidAmerican Energy an interim increase of approximately $13.8 million annually,
effective. On July 15, 2002 MidAmerican Energy and the Iowa Office of Consumer
Advocate filed a proposed settlement agreement with the IUB. The settlement
agreement, which was approved by the IUB on November 8, 2002, provides for an
increase in rates of $17.7 million annually for MidAmerican Energy's Iowa retail
natural gas customers and freezes such rates for two years after the date the
IUB approves tariffs implementing the settlement agreement. MidAmerican Energy
implemented the new rates effective November 25, 2002.
KERN RIVER AND NORTHERN NATURAL GAS
Kern River and Northern Natural Gas are subject to regulation by various federal
and state agencies as discussed below.
As owners of interstate natural gas pipelines, Northern Natural Gas' and Kern
River's rates, services and operations are subject to regulation by the FERC.
The FERC administers, among other things, the Natural Gas Act and the Natural
Gas Policy Act of 1978. Additionally, interstate pipeline companies are subject
to regulation by the Department of Transportation pursuant to the Natural Gas
Pipeline Safety Act, which establishes safety requirements in the design,
construction, operations and maintenance of interstate natural gas transmission
facilities.
The FERC has jurisdiction over, among other things, the construction and
operation of pipelines and related facilities used in the transportation,
storage and sale of natural gas in interstate commerce, including the extension,
enlargement or abandonment of such facilities. The FERC also has jurisdiction
over the rates and charges and terms and conditions of service for the
transportation of natural gas in interstate commerce. Its pipeline subsidiaries
also are required to file with the FERC an annual report on Form 2, which is
publicly available, disclosing general corporate information and financial
statements regarding its pipeline subsidiaries.
Kern River's tariff rates were designed to recover a cost of service that
reflects a 13.25% return on equity. Kern River's rates are set using a
"levelized cost-of-service" methodology so that the rate is constant over the
contract period. This is achieved by using a FERC-approved depreciation schedule
in which depreciation increases as interest expense decreases.
-20-
Northern Natural Gas has implemented a straight fixed variable rate design which
provides that all fixed costs assignable to firm capacity customers, including a
return on equity, are to be recovered through fixed monthly demand or capacity
reservation charges which are not a function of throughput volumes.
Northern Natural Gas' current tariff structure provides for:
o seasonality in demand rates;
o extension of the majority of firm storage and transport contracts
through May 31, 2003 and October 31, 2003, respectively;
o a rate moratorium through October 31, 2003, with limited re-openers
based on the FERC's rulemaking changes; and
o the right of Northern Natural Gas to file for term-differentiated
rates, if allowed.
Northern Natural Gas' tariff rates were designed to recover a cost of service
that would reflect a 12.3% return on equity based upon the settlement reached in
FERC Docket No. RP 98-203. Northern Natural Gas' last rate case was filed on May
1, 1998, and its next rate case may be filed no earlier than May 2003 and no
later than May 2004. Northern Natural Gas' most likely next rate case filing
date is May 1, 2003 with filed rates to be effective November 1, 2003.
In 2000, the FERC issued new rules with respect to terms and conditions of
interstate pipeline transportation service pursuant to Order No. 637. In Order
No. 637, the FERC made changes to its regulatory model to enhance the
effectiveness and efficiency of gas markets as they evolved since the series of
FERC orders commonly referred to as Order No. 436, No. 500 and No. 636 which
were adopted beginning in the mid-1980s to the early 1990s and which provided
for the restructuring of interstate pipeline sales and services. Specifically,
in Order No. 637 the FERC:
o addressed alternatives to traditional pipeline pricing by permitting
peak/off-peak and term differentiated rate structures;
o revised certain reporting requirements; and
o made changes in regulations related to (1) scheduling equality for
released capacity, (2) capacity segmentations, and (3) pipeline
imbalance services, operational flow orders and penalties.
On July 17, 2000, Northern Natural Gas made its initial compliance filing in
accordance with Order No. 637. Northern Natural Gas made a revised Order No. 637
compliance filing on March 4, 2002 and a supplemental filing on May 10, 2002. On
November 21, 2002, the FERC issued an Order on Compliance with Order Nos. 637,
587-G and 587-L. In the November 21, 2002 Order, the FERC found that Northern
Natural Gas generally complied with Order Nos. 637, 587-G and 587-L, subject to
certain modifications, and ordered Northern Natural Gas to file compliance
tariffs within 30 days. Northern filed in compliance with the November 21, 2002
order on December 21, 2002. At this time, an order on Compliance has not been
issued. In addition, numerous parties filed for rehearing of the November 21,
2002 order, which are also pending.
As a result of the FERC's policies favoring competition in gas markets and the
expansion of existing pipelines and construction of new pipelines, the
interstate pipeline industry has begun to experience some turnback of firm
capacity as existing transportation service agreements expire and are
terminated. LDCs and end-use customers have more choices in the new, more
competitive environment and may be able to shift load from one pipeline to
another. If a pipeline experiences capacity turnback and is unable to remarket
the capacity, the pipeline or its other customers may have to bear the costs
associated with the capacity that is turned back. These issues will be resolved
in a pipeline's general rate case proceedings.
The FERC also has authority over gas pipelines' accounting practices. The FERC
recently issued a notice of proposed rulemaking regarding gas accounting issues
which would limit the ability of gas pipelines to enter into cash management
agreements with their parent companies. The Company is in the process of
reviewing such proposed rule, but the Company does not believe the rule will
have a material adverse impact on it and its pipeline subsidiaries.
On August 1, 2002, the FERC issued an Order to respond to Northern Natural Gas
related to Northern Natural Gas'
-21-
existing $450.0 million revolving credit facility and to cash management record
keeping by Northern Natural Gas. Pursuant to a Stipulation and Consent Agreement
dated August 8, 2002, Northern Natural Gas agreed to comply with the FERC's cash
management practices and to not include the costs associated with its existing
$450.0 million revolving credit facility in any future rate proceeding.
Additional proposals and proceedings that might affect the interstate pipeline
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. In some states various forms of restructuring
legislation have been passed and in many states local utility regulatory
agencies are overseeing the restructuring. As a result of restructuring, LDCs
could unbundle their services and withdraw from all or part of their merchant
function, and electric utilities could divest their generating function. This
restructuring would result in the interstate pipelines having different customer
profiles, including independent gas marketers and independent power generators
and end-users. The Company cannot predict when or if any new proposals might be
implemented or, if so, how Kern River and Northern Natural Gas might be
affected.
OTHER UNITED STATES REGULATION
The Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"), and
the Public Utility Holding Company Act of 1935, as amended ("PUHCA"), are two of
the laws (including the regulations thereunder) that affect the Company and
certain of its subsidiaries' operations. PURPA provides to QFs certain
exemptions from federal and state laws and regulations, including
organizational, rate and financial regulation. PUHCA extensively regulates and
restricts the activities of registered public utility holding companies and
their subsidiaries. Congress is currently considering major changes to both
PUHCA and PURPA. Any such legislation, if adopted, could vary considerably from
the terms contained in either or both of the House and Senate versions which are
presently under consideration. The Company believes that if the current proposed
legislation is passed, it would apply to new projects only and thus, although
potentially impacting its ability to develop new domestic projects, it would not
affect the Company's existing qualifying facilities. The Company cannot provide
assurance, however, that legislation, if passed, or any other similar
legislation proposed in the future, would not adversely impact its existing
domestic projects.
The Company is currently exempt from regulation under all provisions of PUHCA,
except the provisions that regulate the acquisition of securities of public
utility companies, based on the intrastate exemption in Section 3(a)(1) of
PUHCA. In order to maintain this exemption, the Company and each of its public
utility subsidiaries from which it derives a material part of its income
(currently only MidAmerican Energy) must be predominantly intrastate in
character and organized in and carry on the Company's and MidAmerican Energy's
respective utility operations substantially in the Company's state of
organization (currently Iowa). Except for MidAmerican Energy's generating plant
assets, the majority of the Company's domestic power plants and all of its
foreign utility operations are not public utilities within the meaning of PUHCA
as a result of their status as QFs under PURPA (with the Company's ownership
interest therein limited to 50%), exempt wholesale generators or foreign utility
companies, or are otherwise exempted from the definition of "public utility"
under PUHCA. Although the Company believes that it will continue to qualify for
exemption from additional regulation under PUHCA, it is possible that as a
result of the expansion of its public utility operations, loss of exempt status
by one or more of its domestic power plants or foreign utilities, or amendments
to PUHCA or the interpretation of PUHCA, the Company could become subject to
additional regulation under PUHCA in the future. There can be no assurances that
such regulation would not have a material adverse effect on the Company.
In the event the Company was unable to avoid the loss of QF status for one or
more of its affiliate's facilities, such an event could result in termination of
a given project's power sales agreement and a default under the project
subsidiary's project financing agreements, which, in the event of the loss of QF
status for one or more facilities, could have a material adverse effect on the
Company.
Regulatory requirements applicable in the future to nuclear generating
facilities could adversely affect the results of operations of the Company and
MidAmerican Energy, in particular. The Company is subject to certain generic
risks associated with utility nuclear generation, including risks arising from
the operation of nuclear facilities and the storage, handling and disposal of
high-level and low-level radioactive materials; risks of a serious nuclear
incident; limitations on the amounts and types of insurance commercially
available in respect of losses that might arise in connection with nuclear
operations; and uncertainties with respect to the technological and financial
aspects of decommissioning nuclear plants at the end of their licensed lives.
The Nuclear Regulatory Commission ("NRC") has broad authority under federal law
to impose licensing and safety-related requirements for the operation of nuclear
generating facilities. Revised safety requirements promulgated by the NRC have,
in the past, necessitated substantial capital expenditures at nuclear plants,
including those in which MidAmerican Energy has an ownership interest, such as
the Quad Cities units, and additional such expenditures could be required in the
future.
-22-
CE ELECTRIC UK
Since 1990, the electricity generation, supply and distribution industries in
Great Britain have been privatized, and competition has been introduced in
generation and supply. Electricity is produced by generators, transmitted
through the national grid transmission system and distributed to customers by
the fourteen Distribution License Holders, which the Company refers to as DLHs,
in their respective distribution service areas. During the fourth quarter of
1998, the market for supplying electricity began to be opened to competition
through a phased-in program. This program, which proceeded by geographic areas,
was completed in 1999.
Under the Utilities Act 2000, the public electricity supply license created
pursuant to the Electricity Act 1989 was replaced by two separate licenses-the
electricity distribution license and the electricity supply license. When the
relevant provision of the Utilities Act 2000 became effective on October 1,
2001, the public electricity supply licenses formerly held by Northern Electric
and Yorkshire were split so that separate subsidiaries held licenses for
electricity distribution and electricity supply. In order to comply with the
Utilities Act 2000 and to facilitate this license splitting, Northern Electric
and Yorkshire (and each of the other holders of the former public electricity
supply licenses) each made a statutory transfer scheme that was approved by the
Secretary of State for Trade and Industry. These schemes provided for the
transfer of certain assets and liabilities to the licensed subsidiaries. This
occurred on October 1, 2001, a date set by the Secretary of State for Trade and
Industry. As a consequence of these schemes, the electricity distribution
businesses of Northern Electric and Yorkshire were transferred to NEDL and YEDL,
respectively. NEDL and YEDL are each holders of an electricity distribution
license. The residual elements of the Electricity Supply licenses were
transferred to Innogy in connection with the sale of Northern Electric's
electricity and gas supply business to Innogy and the retention by Innogy of the
electricity and gas supply business of Yorkshire, all as a part of the Yorkshire
Swap on September 21, 2001.
Each of the DLHs is required to offer terms for connection to its distribution
system and for use of its distribution system to any person. In providing the
use of its distribution system, a DLH must not discriminate between users, nor
may its charges differ except where justified by differences in cost.
Most revenue of the DLHs is controlled by a distribution price control formula
which is set out in the license of each DLH. It has been the practice of the
Office of Gas and Electric Markets ("Ofgem") (and its predecessor body, the
Office of Electricity Regulation), to review the formula periodically and to
reset it at intervals of five year duration. The formula may be varied with the
consent of the DLH, or if the DLH does not consent, following a review by the
U.K.'s competition authority.
The periodic review during which the formula is reset is the process by which
Ofgem determines its view of the future allowed revenue of DLHs. The procedure
and methodology adopted at a price control review is at the reasonable
discretion of Ofgem. At the last such review, concluded in 1999 and effective
April 2000, Ofgem's judgment of the future allowed revenue of licensees was
based upon, among other things:
o the actual operating costs of each of the licensees;
o the operating costs which each of the licensees would incur if it were
as efficient as, in Ofgem's judgment, the most efficient licensee;
o the regulatory value to be ascribed to each of the licensees'
distribution network assets;
o the allowance for depreciation of the distribution network assets of
each of the licensees;
o the rate of return to be allowed on investment in the distribution
network assets by all licensees; and
o the financial ratios of each of the licensees and the license
requirement for each licensee to maintain an investment grade status.
As a result of the most recent review, the allowed revenue of Northern
Electric's distribution business was reduced by 24%, in real terms, and the
allowed revenue of Yorkshire's distribution business was reduced by 23%, in real
terms, with effect from April 1, 2000. The range of reductions for all licensees
in Great Britain was between 4% and 33%.
For the duration of the current regulatory period, the 1999 review also requires
that regulated distribution revenue per unit
-23-
be increased or decreased each year by RPI-Xd, where the factor "RPI" is the
United Kingdom retail price index reflecting the average of the 12-month
inflation rates recorded for each month in the previous July to December period
and "Xd" is an adjustment factor which was established by Ofgem at the 1999
review (and continues to be set) at 3%. The formula also takes account of the
changes in system electrical losses, the number of customers connected and the
voltage at which customers receive the units of electricity distributed. This
formula determines the maximum average price per unit of electricity distributed
(in pence per kWh) which a DLH is entitled to charge. The distribution price
control formula permits DLHs to receive additional revenue due to increased
distribution of units and a predetermined increase in customer numbers. Once
set, the price control formula does not, during its duration, seek to constrain
the profits of a DLH from year to year. It is a control on revenue that operates
independently of most of the DLH's costs. During the duration of the price
control, additional cost savings or costs, if any, therefore directly impact
profit.
The distribution prices allowable under the current distribution price control
formula are expected to be reviewed by Ofgem in time for a revised formula to
take effect from April 1, 2005. The formula may be further reviewed at other
times in the discretion of the regulator. Ofgem has recently modified the
licenses of all DLHs to implement an "Information and Incentives Project" under
which up to 2% of a DLH's regulated income depends upon the performance of the
DLH's distribution system as measured by the number and duration of customer
interruptions and upon the level of customer satisfaction monitored by Ofgem.
Under the Utilities Act 2000, the Gas and Electricity Markets Authority ("GEMA")
is able to impose financial penalties on license holders who contravene (or have
in the past contravened) any of their license duties or certain of their duties
under the Electricity Act 1989 or who are failing (or have in the past failed)
to achieve a satisfactory performance in relation to the individual standards of
performance prescribed by GEMA. Any penalty imposed must be reasonable and may
not exceed 10% of the licensee's revenue.
CALENERGY GENERATION - DOMESTIC
Each of the operating domestic power facilities owned through CE Generation
meets the requirements promulgated under PURPA to be qualifying facilities. QF
status under PURPA provides two primary benefits. First, regulations under PURPA
exempt QFs from PUHCA, the FERC rate regulation under the Federal Power Act and
the state laws concerning rates of electric utilities and financial and
organization regulations of electric utilities. Second, the FERC's regulations
promulgated under PURPA require that (1) electric utilities purchase electricity
generated by QFs, the construction of which commenced on or after November 9,
1978, at a price based on the purchasing utility's Avoided Cost of Energy, (2)
electric utilities sell back-up, interruptible, maintenance and supplemental
power to QFs on a non-discriminatory basis, and (3) electric utilities
interconnect with QFs in their service territories. There can be no assurance
that the QF status of such CalEnergy Generation-Domestic facilities will be
maintained.
CORDOVA ENERGY AND POWER RESOURCES
Cordova Energy and Power Resources are exempt from regulation under PUHCA
because they are exempt wholesale generators. Power Resources is also a QF.
PUHCA provides that an exempt wholesale generator is not considered to be an
electric utility company. An exempt wholesale generator is permitted to sell
capacity and electricity in the wholesale markets, but not in the retail
markets.
If an exempt wholesale generator is subject to a "material change" in facts that
might affect its continued eligibility for exempt wholesale generator status,
within 60 days of such material change, the exempt wholesale generator must (1)
file a written explanation of why the material change does not affect its exempt
wholesale generator status, (2) file a new application for exempt wholesale
generator status, or (3) notify the FERC that it no longer wishes to maintain
exempt wholesale generator status.
CALENERGY GENERATION - FOREIGN
The Philippine Congress has passed the Electric Power Industry Reform Act of
2001, which is aimed at restructuring the Philippine power industry,
privatization of the NPC and introduction of a competitive electricity market,
among other initiatives. The implementation of the bill may have an impact on
the Philippines power industry as a whole and the Company's future operations in
the Philippines, the effect of which is not yet determinable and estimable.
In connection with an interagency review of approximately 40 independent power
project contracts in the Philippines, the Casecnan Project (along with four
other unrelated projects) has reportedly been identified as raising legal and
financial questions and, with those projects, has been prioritized for
renegotiation. The Company's subsidiaries' Upper Mahiao, Malitbog, and
Mahanagdong projects, which, together with the Casecnan Project, collectively
referred to as the Philippine
-24-
Projects, have also reportedly been identified as raising financial questions.
No written report has yet been issued with respect to the interagency review,
and the timing and nature of steps, if any that the Philippine Government may
take in this regard are not known. Accordingly, it is not known what, if any,
impact the government's review will have on the operations of the Company's
Philippines Projects. CE Casecnan representatives, together with certain current
and former government officials, were requested to appear and did appear during
2002 before a Philippine Senate committee which has raised questions and made
allegations with respect to the Casecnan Project's tariff structure and
implementation. No further Senate hearings are scheduled at this time although
hearings before a Philippine House committee were scheduled for the first
quarter of 2003.
HOMESERVICES
The Department of Housing and Urban Development and the Federal Home
Administration ("FHA"), lender guidelines prohibit the collection of a
broker-fee from FHA financed buyers where the FHA lender is affiliated with the
real estate broker or where there is no buyer-broker agreement. The majority of
HomeServices' subsidiaries have been charging a broker fee to their buyers and
sellers, except in circumstances where the FHA guidelines prohibit it.
Nonetheless, HomeServices is working with the FHA to change the lenders'
guidelines to permit collection of these fees.
PIPELINE SAFETY REGULATION
The Company's pipeline operations are subject to regulation by the United States
Department of Transportation under the Natural Gas Pipeline Safety Act of 1969,
as amended, relating to design, installation, testing, construction, operation
and management of its pipeline system. The Natural Gas Pipeline Safety Act
requires any entity that owns or operates pipeline facilities to comply with
applicable safety standards, to establish and maintain inspection and
maintenance plans and to comply with such plans. The Company conducts internal
audits of its facilities every four years, with more frequent reviews of those
it deems higher risk. The Department of Transportation also routinely audits the
Company's pipeline facilities. Compliance issues that arise during these audits
or during the normal course of business are addressed on a timely basis.
The aging pipeline infrastructure in the United States has led to heightened
regulatory and legislative scrutiny of pipeline safety and integrity practices.
The Natural Gas Pipeline Safety Act was amended by the Pipeline Safety Act of
1992 to require the Department of Transportation's Office of Pipeline Safety to
consider protection of the environment when developing minimum pipeline safety
regulations. In addition, the amendments require that the Department of
Transportation issue pipeline regulations concerning, among other things, the
circumstances under which emergency flow restriction devices should be required,
training and qualification standards for personnel involved in maintenance and
operation, and requirements for periodic integrity inspections, as well as
periodic inspection of facilities in navigable waters which could pose a hazard
to navigation or public safety. In addition, the amendments narrowed the scope
of its gas pipeline exemption pertaining to underground storage tanks under the
Resource Conservation and Recovery Act. While the effect of new legislation,
which has been passed by Congress but not yet signed by the President, on the
Company is still being determined, the Company expects to spend the capital or
make the operational changes necessary to comply with all pipeline integrity
legislation.
MEHC believes its subsidiaries' pipeline operations comply in all material
respects with the Natural Gas Pipeline Safety Act, but the industry, including
its subsidiaries, could be required to incur additional capital expenditures and
increased costs depending upon final regulations issued by the Department of
Transportation under the Natural Gas Pipeline Safety Act.
ENVIRONMENTAL REGULATION
Domestic
- --------
The Company is subject to a number of federal, state and local environmental and
environmentally related laws and regulations affecting many aspects of its
present and future operations in the United States. Such laws and regulations
generally require the Company to obtain and comply with a wide variety of
licenses, permits and other approvals. The Company believes that its operating
power facilities and gas pipeline operations are currently in material
compliance wit