As filed with the Securities and Exchange Commission on July 27, 1999
Registration No. 333-
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM S-4
REGISTRATION STATEMENT
Under
The Securities Act of 1933
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CAITHNESS COSO FUNDING CORP.
(Exact name of Registrant as specified in its charter)
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Delaware 525990 94-3328762
(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer
incorporation or organization) Classification Code Number) Identification No.)
Coso Finance Partners California 221119 68-0133679
Coso Energy Developers California 221119 94-3071296
Coso Power Developers California 221119 94-3102796
(Exact names of (State or other (Primary Standard
Registrants as jurisdiction of Industrial (I.R.S. Employer
specified in their incorporation or Classification Code
charters) organization) Number) Identification No.)
1114 Avenue of the Americas, 41st Floor
New York, New York 10036-7790
(212) 921-9099
(Address, including zip code, and telephone number, including area code, of
Caithness Coso Funding Corp.'s principal executive offices)
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Christopher T. McCallion
Executive Vice President and Chief Financial Officer
Caithness Coso Funding Corp.
1114 Avenue of the Americas, 41st Floor
New York, New York 10036-7790
(212) 921-9099
(Name, address, including zip code, and telephone number, including area code,
of agent for service)
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With a Copy to:
Mitchell S. Cohen, Esq.
Riordan & McKinzie
300 South Grand Avenue, 29th Floor
Los Angeles, California 90071
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Approximate date of commencement of proposed sale to the public: As soon as
practicable after this Registration Statement becomes effective.
If the securities being registered on this Form are being offered in
connection with the formation of a holding company and there is compliance
with General Instruction G, check the following box: [_]
If this form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, check the following box and
list the Securities Act registration statement number of the earlier effective
registration statement for the same offering. [_]
If this form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [_]
CALCULATION OF REGISTRATION FEE
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Proposed Maximum Proposed Maximum
Title of Each Class of Amount to be Offering Price Aggregate Amount of
Securities to be Registered Registered per Security(1) Offering Price(1) Registration Fee
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6.80% Senior Secured Notes due 2001.. $110,000,000 100% $110,000,000 $30,580
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9.05% Senior Secured Notes due 2009.. $303,000,000 100% $303,000,000 $84,234
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Guarantees(2)........................ (3) (3) (3) (3)
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Total............................... $413,000,000 100% $413,000,000 $114,814
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(1) Estimated solely for the purpose of calculating the registration fee
pursuant to Rule 457 under the Securities Act.
(2) Coso Finance Partners, Coso Energy Developers and Coso Power Developers
are each registering guarantees of the payment of the principal of,
premium, if any, and interest on the Senior Secured Notes being registered
hereby. Pursuant to Rule 457(n) under the Securities Act of 1933, as
amended, no registration fee is required with respect to the guarantees.
(3) Not applicable.
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The Registrants hereby amend this Registration Statement on such date or
dates as may be necessary to delay its effective date until the Registrants
shall file a further amendment which specifically states that this
Registration Statement shall thereafter become effective in accordance with
Section 8(a) of the Securities Act of 1933 or until this Registration
Statement shall become effective on such date as the Securities and Exchange
Commission, acting pursuant to said Section 8(a), may determine.
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SUBJECT TO COMPLETION, DATED , 1999
PROSPECTUS
Caithness Coso Funding Corp.
Offer to Exchange
Any and All Outstanding 6.80% Series A Senior Secured Notes due 2001
for
6.80% Series B Senior Secured Notes due 2001
and
Any and All Outstanding 9.05% Series A Senior Secured Notes due 2009
for
9.05% Series B Senior Secured Notes due 2009
This is an offer to exchange any and all outstanding, unregistered Caithness
Coso Funding Corp. 6.80% Series A Senior Secured Notes due 2001 you now hold
for new, substantially identical 6.80% Series B Senior Secured Notes due 2001
and any and all outstanding, unregistered Caithness Coso Funding Corp. 9.05%
Series A Senior Secured Notes due 2009 for new, substantially identical 9.05%
Series B Senior Secured Notes due 2009. The 6.80% Series A Senior Secured Notes
due 2001 and the 9.05% Series A Senior Secured Notes due 2009 are called the
Series A notes, and the new 6.80% Series B Senior Secured Notes due 2001 and
the new 9.05% Series B Senior Secured Notes due 2001 are called the Series B
notes. The Series B notes will be free of the transfer restrictions that apply
to the Series A notes.
This exchange offer will expire at 5:00 p.m., New York City time, on ,
1999, unless we extend the expiration date. You must tender your Series A notes
before the exchange offer expires to obtain the respective Series B notes and
the liquidity benefits they offer. Only Series B notes due 2001 may be
exchanged for tendered Series A notes due 2001, and only Series B notes due
2009 may be exchanged for tendered Series A notes due 2009. We will exchange
Series A notes only in integral multiples of $1,000.
We agreed with the initial purchaser of the Series A notes to make this
exchange offer and register the issuance of the Series B notes following the
closing of the issuance and sale of the Series A notes to the initial purchase
of those notes. This exchange offer applies to any and all outstanding Series A
notes tendered before the exchange offer expires.
The Series B notes will not trade on any established exchange. The Series B
notes will have the same financial terms and covenants as the Series A notes,
and are subject to the same business and financial risks.
A description of those risks begins on page 34.
The terms of the exchange offer will include the following:
. We will exchange any and all outstanding Series A notes that are validly
tendered and not withdrawn before the exchange offer expires;
. You may withdraw your tender of Series A notes at any time before the
exchange offer expires; and
. We will not receive any proceeds from the exchange offer.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if
this prospectus is truthful or complete. Any representation to the contrary is
a criminal offense.
The date of this prospectus is , 1999.
TABLE OF CONTENTS
Page
Forward-Looking Statements............................................... i
Prospectus Summary....................................................... 1
Risk Factors............................................................. 34
The Exchange Offer....................................................... 49
Capitalization........................................................... 59
Selected Historical and Pro Forma Financial and Operating Data........... 61
Unaudited Pro Forma Financial Data....................................... 66
Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................... 82
Business................................................................. 101
Summary Descriptions of Principal Agreements Relating to the Coso
Projects................................................................ 124
Regulation............................................................... 136
Management............................................................... 141
Page
Ownership.................................................................. 147
Certain Relationships and Related Transactions............................. 150
Description of Series B Notes.............................................. 155
Material Federal Income Tax Consequences of the Exchange Offer............. 204
Plan of Distribution....................................................... 205
Legal Matters.............................................................. 205
Change in Independent Accountants.......................................... 205
Experts.................................................................... 206
Available Information...................................................... 207
Index to Financial Statements.............................................. F-1
Exhibit A--Independent Engineer's Report
Exhibit B--Energy Markets Consultant's Report
Exhibit C--Geothermal Consultant's Report
FORWARD-LOOKING STATEMENTS
This prospectus includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. All statements other than statements of historical facts
included in this prospectus regarding industry prospects, our prospects and our
financial position are forward-looking statements. Although we believe that our
expectations reflected in these forward-looking statements are reasonable, we
cannot assure you that our expectations will prove to be correct. We have based
these forward-looking statements on our beliefs, assumptions and expectations
and on information currently available to us. These statements involve known
and unknown risks, uncertainties and other important factors that could cause
actual results, performance or achievements to differ materially from the
results, performance or achievements expressed or implied by these statements.
Forward-looking statements are not guarantees of performance.
Under the safe harbor provisions of the Private Securities Litigation Reform
Act of 1995, we have identified some of these risks, uncertainties and other
important factors in "Risk Factors," in "Management's Discussion and Analysis
of Financial Condition and Results of Operations" and in the assumptions made
by our independent engineer, our energy markets consultant and our geothermal
consultant in their respective reports, copies of which are included in the
prospectus. You should also consider, among others, the following important
factors:
. general economic and business conditions in the United States;
. changes in governmental regulations affecting us and our affiliates, our
and their businesses and operations and the United States electric power
industry;
i
. general industry trends;
. changes to the competitive environment;
. power costs and resource availability;
. changes in business strategy, development plans or vendor or customer
relationships;
. availability, terms and deployment of capital; and
. availability of qualified personnel.
These forward-looking statements speak only as of the date of this
prospectus. We undertake no obligation to publicly update or revise any
forward-looking statements to reflect events or circumstances after the date of
this prospectus, and we do not assume any responsibility to do so.
ii
PROSPECTUS SUMMARY
This summary may not contain all of the information that may be important to
you. We encourage you to read this entire prospectus, including the financial
data and the related notes, before deciding to tender your Series A notes in
the exchange offer. Whenever this prospectus uses the terms "we," "us," "our"
"ourselves" or "Funding Corp.," it is referring to Caithness Coso Funding
Corp., the issuer of the Series A notes and the Series B notes, which we
collectively call the senior secured notes.
The Issuer
We are a special purpose corporation and a wholly owned subsidiary of Coso
Finance Partners, which we call the Navy I partnership, Coso Energy Partners,
which we call the BLM partnership, and Coso Power Developers, which we call the
Navy II partnership. We call the Navy I partnership, the BLM partnership and
the Navy II partnership the Coso partnerships. We were formed for the purpose
of issuing the senior secured notes for ourselves and on behalf of the Coso
partnerships. The Coso partnerships have guaranteed our obligations to repay
the senior secured notes.
On May 28, 1999, we and the Coso partnerships completed the following
transactions:
. We sold $110,000,000 of our 6.80% Series A Senior Secured Notes due 2001
and $303,000,000 of our 9.05% Series A Senior Secured Notes due 2009 to
Donaldson, Lufkin & Jenrette Securities Corporation, which we call the
initial purchaser of the Series A notes, under a purchase agreement,
dated May 21, 1999, among the initial purchaser, the Coso partnerships
and us. We call the sale of the Series A notes to the initial purchaser
the Series A notes offering;
. We loaned all of the proceeds from the Series A notes offering to the
Coso partnerships; and
. The Coso partnerships, in turn, caused the net proceeds from the Series A
notes offering, together with cash on their balance sheets and funds from
other sources, to (1) retire all Coso project debt that existed prior to
the Series A notes offering, including the payment of accrued and unpaid
interest and premiums, of approximately $150.7 million, (2) initially
fund the Debt Service Reserve Account established under a Deposit and
Disbursement Agreement dated as of May 28, 1998, which we call the
Depositary Agreement, in the amount of $50.0 million, (3) repay
approximately $216.9 million of short term debt, including accrued
interest, incurred by one of our affiliates to purchase all of the
remaining interests in the Coso projects as described under "The
Purchase" below and (4) make distributions of the remaining balance to
the owners of the Coso partnerships other than the beneficial owners of
Caithness Energy, LLC, the sponsor of the Coso projects and which we call
Caithness Energy.
We have no other material assets, other than the loans we made to the Coso
partnerships, and do not conduct any business, other than issuing the senior
secured notes and making the loans to be Coso partnerships. Our principal
executive offices are located at 1114 Avenue of the Americas, 41st floor, New
York, New York 10036-7790, and our telephone number is (212) 921-9099.
1
The Coso Projects
The Coso projects consist of three 80 megawatt (MW) geothermal power plants,
which we call Navy I, BLM and Navy II, and their transmission lines, wells,
gathering system and other related facilities. The Coso projects are located
near one another in the Mojave Desert approximately 150 miles northeast of Los
Angeles, California, and have been generating electricity since the late 1980s.
Unlike fossil fuel-fired power plants, the Coso projects' power plants use
geothermal energy derived from the natural heat of the earth's interior to
generate electricity. Since geothermal power plants have no fossil fuel costs,
we believe our plants enjoy higher and more stable gross operating margins than
fossil fuel-fired power plants with similarly rated capacities.
The Navy I partnership owns Navy I and its related facilities, the BLM
partnership owns BLM and its related facilities and the Navy II partnership
owns Navy II and its related facilities. The Coso partnerships and their
affiliates own the exclusive right to explore, develop and use, currently
without any known interference from any other power developers, a portion of
the Coso Known Geothermal Resource Area. Since 1991, the Coso partnerships have
drilled 56 geothermal wells, approximately 91% of which have contributed to the
commercial production of geothermal energy.
The geothermal power plants, each of which has three separate turbine
generator units, have consistently operated above their nominal capacities, and
the combined average capacity factor for the plants has exceeded 100%, for each
of the last six years. For the three months ended March 31, 1999, the plants
operated at a combined average capacity factor of approximately 99.3%.
The Coso partnerships sell 100% of the electrical energy generated at the
plants to Southern California Edison Company, which we call Edison, under three
long-term Standard Offer No. 4 power purchase agreements. Each power purchase
agreement expires after the last maturity date of the senior secured notes.
Edison is one of the largest investor-owned electric utilities in the United
States. As of December 31, 1998, Edison reported in its 1998 annual report
total assets of $16.9 billion and operating revenues of $8.8 billion. Edison is
currently rated A1 by Moody's and A+ by Standard & Poor's.
Under the power purchase agreements, the Coso partnerships receive the
following payments:
. Capacity payments for being able to produce electricity at certain
levels. Capacity payments are fixed throughout the lives of the power
purchase agreements;
. Capacity bonus payments if they are able to produce electricity above a
specified higher level. The maximum capacity bonus payment available is
also fixed throughout the lives of the power purchase agreements; and
. Energy payments which are based on the amount of electricity their
respective plants actually produce.
Energy payments are fixed for the first ten years of "firm operation" under
the power purchase agreements. Firm operation was achieved for each Coso
partnership when Edison and that Coso partnership agreed that each generating
unit at that Coso partnership's plant was a reliable source of generation and
could reasonably be expected to operate continuously at its effective rating.
After the first ten years of firm operation and until a Coso partnership's
power purchase agreement expires,
2
Edison makes energy payments to the Coso partnership based on Edison's "avoided
cost of energy." Edison's avoided cost of energy is Edison's cost to generate
electricity if Edison were to produce it itself or buy it from another power
producer rather than buy it from the relevant Coso partnership. The Navy I
partnership and the BLM partnership currently receive energy payments from
Edison based on Edison's avoided cost of energy. The Navy II partnership
receives energy payments from Edison based on higher fixed energy prices
provided for in its power purchase agreement and will continue to do so until
at least January 2000.
The Edison power purchase agreements will expire:
. in August 2011 for the Navy I partnership;
. in March 2019 for the BLM partnership; and
. in January 2010 for the Navy II partnership.
In addition to receiving payments under the power purchase agreements, the
Navy I partnership and the BLM partnership currently qualify for and receive
subsidy payments from a special purpose state fund established under California
Assembly Bill 1890, which we call AB1890. The California Energy Commission
administers the fund. AB1890 provides in part for subsidy payments from 1998
through 2001 to power generators using renewable sources of energy, including
geothermal energy, and who are being paid based on an avoided cost of energy
basis. Under AB1890, the Navy I partnership and the BLM partnership are
expected to continue to receive in the future subsidy payments for energy
delivered to Edison by the Navy I partnership or the BLM partnership, as the
case may be, whenever Edison's avoided cost of energy falls below 3.0c per
kilowatt hour (kWh). This subsidy is capped at 1.0c per kWh. We expect the Navy
II partnership to also qualify for these subsidy payments through 2001 once the
fixed energy price period under its power purchase agreement expires.
As of March 31, 1999, the unaudited combined net book value of the property,
plant and equipment of the Coso partnerships was approximately $471.0 million,
including approximately $158.4 million at the Navy I partnership, $163.2
million at the BLM partnership and $149.4 million at the Navy II partnership.
Operating Strategy
The Coso partnerships seek to maximize cash flow at the Coso projects through
active management of the Coso projects' cost structure and the Coso geothermal
resource. As a result of the closing of the purchase described in "--The
Purchase" below:
. The Coso partnerships have retained two new operators at the Coso
projects: FPL Energy Operating Services, Inc., which we call FPL
Operating, and Coso Operating Company, LLC, which we call Coso Operating
Company. FPL Operating currently operates and maintains all three plants,
the transmission lines and the geothermal fields at the Coso projects
under three short-term operations and maintenance, or O&M, agreements.
Coso Operating Company, which is one of our affiliates, currently manages
the geothermal resource, including well drilling, under three additional
O&M agreements. Also:
. FPL Operating and Coso Operating Company have retained substantially
the same employees who were employed by the prior operator.
Approximately 70% of the
3
employees who currently work at the Coso projects' sites have been
employed there since 1992; and
. As a result of the change in operators and the restructuring of
operator fees, the aggregate annual fees to be paid by the Coso
partnerships to FPL Operating and Coso Operating Company have been
reduced from approximately $7.5 million, which had been paid to the
prior operator in 1998, to approximately $2.0 million. Payment of
these reduced operator fees are subordinated to all payments to be
made under the senior secured notes;
. One of our affiliates, which recently purchased the managing partners of
the Coso partnerships, has caused any management committee fees payable
by each Coso partnership to its partners to be subordinated to all
payments to be made under the senior secured notes;
. The Coso partnerships expect to reduce annual non-fee related costs at
the Coso projects, including insurance, maintenance and other costs, by
approximately $1.9 million. However, the pro forma financial data
included in this prospectus does not give effect to this cost savings;
and
. The Coso partnerships are expanding a steam sharing program they
previously implemented among the Coso projects to enhance the management,
and to optimize the overall use, of the Coso geothermal resource. As part
of this program, the Coso partnerships plan to conserve the geothermal
resource whenever possible by, among other things:
. Transferring steam between and among the Coso projects and from an
adjoining site, which we call BLM North, rather than drilling new
wells at the Coso projects' sites prematurely; and
. Expanding the flexible field-wide water reinjection program.
4
The Purchase
In late 1998, CalEnergy Company, Inc., which is now known as MidAmerican
Energy Holdings Company and which we call CalEnergy, announced that it was
planning to merge with MidAmerican Energy. As a consequence of the planned
merger, the Federal Energy Regulatory Commission, which we call FERC, required
CalEnergy to divest itself of at least a portion of its approximately 48%
equity interest in the Coso projects if the Coso projects were to continue to
qualify as "Qualifying Facilities," or QFs, under the Public Utility Regulatory
Policies Act of 1978, which we call PURPA. See "--The Independent Power
Industry." Each Coso partnership is required to operate and maintain its Coso
project as a QF under its power purchase agreement and under the Indenture
described below.
On February 25, 1999, one of our affiliates, Caithness Acquisition Company,
LLC, which we call Caithness Acquisition, purchased all of CalEnergy's
interests in the Coso projects. Caithness Acquisition is a wholly owned
subsidiary of Caithness Energy. See "--The Sponsor." The purchase price
consisted of $205.0 million in cash, plus $5.0 million in contingent payments,
plus the assumption of CalEnergy's and its affiliates' share of debt
outstanding at the Coso projects which then totaled approximately $67.0
million. In order to complete the purchase, Caithness Acquisition arranged for
short-term debt financing in the principal amount of approximately $211.5
million. Caithness Acquisition used a portion of the net proceeds from the
Series A notes offering that it received from the Coso partnerships, together
with funds from other sources, to repay all amounts owed under this short-term
debt facility.
The Sponsor
Caithness Energy, the principal operating subsidiary of Caithness
Corporation, is a developer and owner of independent power projects and is the
sponsor of the Coso projects. Since 1966, the current owners of Caithness
Corporation have been involved in the development of long-term investment
opportunities involving natural resources. Caithness Corporation is one of the
two original sponsors of the Coso projects and formed Caithness Energy in 1995
to consolidate its ownership of independent power projects.
Caithness Energy believes that it is currently the second largest owner of
geothermal power projects in the United States, based on the total electrical
generating capacity of its power projects. Through its controlled affiliates,
Caithness Energy owns interests in seven geothermal plants, including the Coso
projects, totaling 420 MW. Caithness Energy is also seeking to develop two
additional geothermal power projects with a total potential electrical
generating capacity of over 400 MW, and has interests in other operating power
generating facilities, including solar, wind and natural gas, totaling an
additional 400 MW.
5
Caithness Energy typically partners with strategic investors in its power
project investments. The largest such investors in the Coso projects currently
are:
. a subsidiary of FPL Energy, Inc., the independent power subsidiary of FPL
Group, Inc., which is the parent company of Florida Power & Light
Company, one of the largest investor-owned utilities in the United
States; and
. Dominion Energy, Inc., a subsidiary of Dominion Resources, Inc., which
also is a large investor-owned utility.
Caithness Energy is headquartered in New York City and has additional offices
in California, Colorado and Florida.
The Coso Partnerships
Affiliates of Caithness Energy and CalEnergy formed the Coso partnerships
during the 1980s to develop, own and operate Navy I, BLM and Navy II. As we
described in "--The Purchase" above, Caithness Acquisition recently purchased
all of CalEnergy's interests in the Coso projects. Caithness Energy now
indirectly controls the BLM partnership and the Navy II partnership, while
Caithness Energy and FPL Energy, Inc. indirectly share control of the Navy I
partnership. You should read "Management" for more details regarding who
manages and controls the Coso partnerships.
6
Recent Developments
Purchase of 1992 Notes
Concurrently with the closing of the Series A notes offering, Coso Funding
Corp., one of our other affiliates, purchased for cash all of its then
outstanding 8.53% Senior Secured Notes due 1999 and 8.87% Senior Secured Notes
due 2001, which we collectively call the 1992 Notes. The proceeds of the 1992
Notes were originally loaned by Coso Funding Corp. to the Coso partnerships,
and these loans constituted the existing project debt that was repaid with a
portion of the proceeds from the Series A notes offering.
Return to Service of Navy I Unit
In January 1999, one of Navy I's three turbine generator units, known as Unit
1, automatically shut down when the stator coils attached to it experienced a
ground fault. The stator coil was repaired, and Unit 1 was scheduled to return
to service in March 1999. However, electrical faults recurred during the start-
up testing stage of Unit 1's generators, and the Navy I partnership postponed
Unit 1's return to service while it repaired the unit. Unit 1 returned to
service prior to June 1, 1999, and is currently in service. The Navy I
partnership had filed a claim in connection with Unit 1's shutdown under its
business interruption and casualty insurance policies. It expects that any
losses resulting from this shutdown will be covered by insurance, subject to a
deductible of $500,000 for property damage and a 25-day deductible for business
interruption. We have included amounts expected to be recovered under these
insurance policies in the Navy I partnership's total revenues for the three
months ended March 31, 1999. See "--Summary Selected Historical and Pro Forma
Financial and Operating Data" and "Business--Overview of the Coso Projects--
Plants--Navy I." The other two turbine generator units at Navy I and the three
generator units at BLM and Navy II are also currently in service.
Negotiations with FPL Operating and its Affiliates
The Coso partnerships and Coso Operating Company, one of the two existing
operators of the Coso projects and our affiliate, have been negotiating with
FPL Operating and its affiliates to acquire all of the equity interests in the
Navy I partnership held by one of FPL Operating's affiliates and to terminate
the existing O&M agreements with FPL Operating. Subject to reaching a final
agreement on terms, we currently expect that the Coso partnerships will sign
definitive documentation prior to the end of 1999. At this time, Caithness
Energy and the Coso partnerships are considering whether to engage a new
independent operator to assume the operational and maintenance functions that
FPL Operating currently has or whether to have Coso Operating Company assume
those functions and engage additional personnel as appropriate.
7
Geothermal Energy
Geothermal energy is:
. an established and generally sustainable source of energy that
releases significantly lower levels of emissions than result when
energy is generated by burning fossil fuels;
. derived from the natural heat of the earth when water comes
sufficiently close to hot molten rock to heat the water to
temperatures of 400 degrees Fahrenheit or more. The heated water then
ascends toward the surface of the earth where, if geological
conditions are suitable, it can be extracted for commercial use by
drilling geothermal wells; and
. a renewable source of energy so long as natural ground water flows and
reinjection of extracted geothermal fluids are adequate over the long
term to replenish the geothermal reservoir after geothermal fluids
have been withdrawn.
Compared to fossil fuel-fired power plants, geothermal energy facilities
typically have higher capital costs, primarily as a result of wellfield
development, but tend to have significantly lower variable operating costs.
The Independent Power Industry
The Coso projects are part of the growing domestic independent power
industry. Utilities in the United States have been the predominant producers of
electric power since the early 1900s. In 1978, however, Congress enacted PURPA,
which removed regulatory constraints relating to the production and sale of
electricity by certain non-utility power producers. PURPA requires electric
utilities to buy electricity from non-utility power producers that use
renewable energy sources, known as Small Power QFs, or that produce both
electrical energy and useful thermal energy used for industrial, commercial,
heating or cooling purposes, known as Cogeneration QFs. This encouraged
companies other than electric utilities to enter the electric power production
market. Under PURPA, electric utilities are required to comply with state law
guidelines and, in general, must interconnect with and buy capacity and energy
offered by non-utility power producers meeting certain ownership and, in the
case of Small Power QFs, fuel use standards established by FERC if there is a
need for such electricity and if it is priced at or below the utility's avoided
cost of energy at the time of the agreements.
The Coso projects qualify as Small Power QFs under PURPA and the rules and
regulations promulgated under PURPA by FERC. PURPA exempts the Coso projects
from certain federal and state regulations. The Coso projects must continue to
satisfy certain ownership and fuel-use standards to maintain their QF status.
Since their inception, the Coso projects have satisfied these standards and we
expect that they will continue to do so.
8
SUMMARY OF THE EXCHANGE OFFER
On May 28, 1999, we completed the Series A notes offering. The initial
purchaser subsequently resold the Series A notes in reliance on Rule 144A and
other available exemptions under the Securities Act of 1933. As part of the
completion of the Series A notes offering, we, the Coso partnerships and the
initial purchaser entered into a registration rights agreement dated May 28,
1999, which we call the registration rights agreement, in which we agreed,
among other things, to deliver this prospectus to you and complete an exchange
offer for the Series A notes. Set forth below is a summary of the terms of the
exchange offer. See "The Exchange Offer."
The Exchange Offer.......... We are offering to exchange (1) up to
$110,000,000 aggregate principal amount of our
6.80% Series B Senior Secured Notes due 2001,
which have been registered under the Securities
Act, for up to $110,000,000 aggregate principal
amount of any and all outstanding 6.80% Series A
Senior Secured Notes due 2001 and (2) up to
$303,000,000 aggregate principal amount of our
9.05% Series B Senior Secured Notes due 2009,
which have been registered under the Securities
Act, for up to $303,000,000 aggregate principal
amount of any and all outstanding 9.05% Series A
Senior Secured Notes due 2009. Only Series B
notes due 2001 may be exchanged for tendered
Series A notes due 2001, and only Series B notes
due 2009 may be exchanged for tendered Series A
notes due 2009. We will exchange Series A notes
only in integral multiples of $1,000.
In order to be exchanged, the Series A notes must
be properly tendered and accepted. Subject to
certain exceptions, we will accept for exchange
any and all Series A notes that are properly
tendered and not withdrawn before the exchange
offer expires. As of the date of this prospectus,
there is $413,000,000 aggregate principal amount
of Series A notes outstanding. We will issue the
Series B notes promptly after the exchange offer
expires.
Expiration Date; Withdrawal
Rights..................... The exchange offer will expire at 5:00 p.m., New
York City time, on , 1999, unless we
extend the expiration date. You may withdraw your
tender of Series A notes at any time before the
exchange offer expires. If we terminate this
exchange offer and do not accept for exchange any
Series A notes, we will promptly return tendered
Series A notes to their holders.
Conditions to the Exchange
Offer...................... The exchange offer is subject to customary
conditions, any or all of which we may waive in
our sole discretion. See "The Exchange Offer--
Conditions to the Exchange Offer."
9
Accrued Interest on the
Notes...................... The Series B notes will bear interest from and
including the date of issuance of the Series A
notes. Accordingly, if you receive Series B notes
in exchange for your tendered Series A notes, you
will forego accrued but unpaid interest on your
exchanged Series A notes for the period from and
including the date of issuance of the Series A
notes to the date of the exchange. Instead, you
will be entitled to such interest under the
Series B notes. See "The Exchange Offer--Terms of
the Exchange Offer."
Procedures for Tendering
Series A Notes............. If you wish to tender your Series A notes, you
must complete, sign and date the letter of
transmittal, or a facsimile of it, in accordance
with the instructions contained therein, and
submit the letter of transmittal, and all other
documents required by the letter of transmittal,
to the exchange agent identified below on or
prior to the expiration date of the exchange
offer. By executing the letter of transmittal,
you will represent to us that you are acquiring
the Series B notes in the ordinary course of your
business, that you are not participating, do not
intend to participate and have no arrangement or
understanding with any person to participate, in
any distribution of the Series B notes, and that
you are not an "affiliate" of ours. See "The
Exchange Offer--Procedures for Tendering."
Guaranteed Delivery
Procedures.................. If you wish to tender your Series A notes and
your Series A notes are not immediately available
or you cannot deliver your Series A notes and the
letter of transmittal and any documents required
by the letter of transmittal to the exchange
agent prior to the expiration of the exchange
offer, you must tender your Series A notes
according to the guaranteed delivery procedures
set forth in "The Exchange Offer--Guaranteed
Delivery Procedures."
Material Federal Income Tax
Considerations............. We believe that your exchange of Series A notes
for Series B notes pursuant to the exchange offer
will not result in a taxable event for federal
income tax purposes. See "The Exchange Offer--
Material Federal Income Tax Consequences of the
Exchange Offer."
Rights of Dissenting
Holders..................... Holders of Series A notes do not have any
appraisal or dissenters' rights under Delaware
General Corporation Law in connection with this
exchange offer.
10
Exchange Agent.............. U.S. Bank Trust National Association is serving
as the exchange agent for the exchange offer.
Use of Proceeds; Expenses... We will not receive any proceeds from the
issuance of Series B notes pursuant to the
exchange offer. We will pay all expenses incident
to the completion of the exchange offer.
Consequences of exchanging Series A notes pursuant to this Exchange Offer
Based on interpretative rulings by the staff of the Securities and Exchange
Commission (SEC) set forth in several no-action letters issued to unrelated
third parties, if you exchange your Series A notes for Series B notes pursuant
to this exchange offer, we believe that you generally may offer for resale,
resell or otherwise transfer your Series B notes without complying with the
registration and prospectus delivery requirements of the Securities Act,
provided that (1) you acquired the Series B notes in the ordinary course of
your business, (2) you are not participating, do not intend to participate and
have no arrangement or understanding with any person to participate, in a
distribution of your Series B notes and (3) you are not our "affiliate" within
the meaning of Rule 405 under the Securities Act. If you are not acquiring the
Series B notes in the ordinary course of business, are engaged in or intend to
engage in or have any arrangement or understanding with any person to
participate in the distribution of the Series B notes or are our affiliate,
then (1) you cannot rely on the applicable interpretations of the staff of the
SEC and (2) you must comply with the registration requirements of the
Securities Act in connection with any resale transaction. Each broker-dealer
that receives Series B notes for its own account in exchange for Series A notes
that were acquired as a result of market-making or other trading activities
must acknowledge that it will deliver a prospectus in connection with any
resale of the Series B notes. See "Plan of Distribution." In addition, to
comply with the securities laws of certain jurisdictions, if applicable, the
Series B notes may not be offered or sold unless they have been registered or
qualified for sale in such jurisdiction or an exemption from registration or
qualification is available and the conditions thereto have been met. See "The
Exchange Offer--Purpose of the Exchange Offer."
11
Summary of the Terms of the Series B Notes
The form and terms of the Series B notes will be identical in all material
respects to the form and terms of the Series A notes, except that (1) the
Series B notes will have been registered under the Securities Act and,
therefore, will not bear legends restricting the transfer thereof and (2)
holders of the Series B notes will not be and, upon the completion of the
exchange offer, certain holders of Series A notes will no longer be, entitled
to certain rights under the registration rights agreement intended for holders
of transfer restricted notes, except in limited circumstances. See "The
Exchange Offer--Termination of Certain Rights." The Series B notes will
evidence the same debt as the Series A notes and will be governed by the
Indenture.
Issuer...................... Caithness Coso Funding Corp., a Delaware
corporation.
Guarantors.................. The Navy I partnership, the BLM partnership and
the Navy II partnership. Each Coso partnership is
a California general partnership.
Securities Offered.......... The Series B notes, consisting of the following:
$110,000,000 aggregate principal amount of
Series B Senior Secured Notes due 2001; and
$303,000,000 aggregate principal amount of
Series B Senior Secured Notes due 2009.
Maturity Dates.............. The Series B notes due 2001 will mature on
December 15, 2001, and the Series B notes due
2009 will mature on December 15, 2009. For more
details, see "Description of Series B Notes--
Principal, Maturity and Interest."
Average Life................ The average life of the Series B notes due 2001
is 1.2 years, and the average life of the Series
B notes due 2009 is 7.2 years.
Interest.................... The Series B notes due 2001 will accrue interest
at the rate of 6.80% per annum. We will pay
interest on these notes semi-annually in arrears
on December 15 and June 15, commencing December
15, 1999, to holders of record on the immediately
preceding December 1 and June 1.
The Series B notes due 2009 will accrue interest
at the rate of 9.05% per annum. We will pay
interest on these notes semi-annually in arrears
on December 15 and June 15, commencing December
15, 1999, to holders of record on the immediately
preceding December 1 and June 1. For more
details, see "Description of Series B Notes--
Principal, Maturity and Interest."
12
Scheduled Principal
Payments................... We will pay the principal of the Series B notes
due 2001 in semi-annual installments, commencing
December 15, 1999, as follows:
Scheduled Percentage of Principal
Payment Date Amount Payable
December 15,
1999........... 47.8773%
June 15, 2000... 11.0736%
December 15,
2000........... 16.4427%
June 15, 2001... 10.1900%
December 15,
2001........... 14.4164%
We will pay the principal of the Series B notes
due 2009 in semi-annual installments, commencing
June 15, 2002, as follows:
Scheduled Percentage of Principal
Payment Date Amount Payable
June 15, 2002... 2.8743%
December 15,
2002........... 4.3109%
June 15, 2003... 3.6564%
December 15,
2003........... 5.4584%
June 15, 2004... 4.1363%
December 15,
2004........... 6.2043%
June 15, 2005... 4.6838%
December 15,
2005........... 7.0257%
June 15, 2006... 5.0541%
December 15,
2006........... 7.5815%
June 15, 2007... 6.2601%
December 15,
2007........... 9.3898%
June 15, 2008... 6.4927%
December 15,
2008........... 9.7650%
June 15, 2009... 6.8231%
December 15,
2009........... 10.2835%
Ratings of Series B Notes... The Series B notes due 2001 have been rated "Ba1"
by Moody's, "BB" by S&P and "BB+" by Duff &
Phelps, and the Series B notes due 2009 have been
rated "Ba2" by Moody's, "BB" by S&P and "BB" by
Duff & Phelps. See "Description of Series B
Notes--Ratings."
Senior Secured Notes
Guarantees................. The Coso partnerships have fully and
unconditionally guaranteed on a joint and several
basis all of our obligations under the Indenture
and the Series B notes, subject to fraudulent
conveyance limitations. If we cannot make
payments on the Series B notes when due, the Coso
partnerships must make them instead.
The Coso partnerships' guarantees are secured by:
. a perfected, first priority lien on
substantially all of the assets of the
Coso partnerships; and
13
. a perfected, first priority pledge of all
ownership interests in the Coso
partnerships.
For more details, see "Description of Series B
Notes--Brief Description of Series B Notes and
Guarantees."
Senior Secured Notes
Collateral................. The Series B notes are secured by:
. a perfected, first priority pledge of the
promissory notes, which we call the
project notes, evidencing the Coso
partnerships' obligations to repay the
loans made by us to the Coso partnerships;
. a perfected, first priority lien on the
funds deposited in the accounts which we
established under the Depositary
Agreement; and
. a perfected, first priority pledge of all
of our outstanding capital stock.
In addition, our affiliates (other than the Coso
partnerships) that hold any material assets
related to the Coso projects have provided a lien
on these assets to secure the Series B notes. For
more details, see "Description of Series B
Notes--Security."
Ranking..................... The Series B notes will rank senior in right of
payment to all of our subordinated indebtedness
issued in the future, if any. The Series B notes
will rank equally in right of payment with our
future senior borrowings, if any. See
"Description of Series B Notes--Brief Description
of the Series B Notes and Guarantees."
Debt Service Reserve
Account.................... We established a Debt Service Reserve Account for
the benefit of the holders of the senior secured
notes under the Depositary Agreement. We
initially funded the Debt Service Reserve Account
at the closing of the Series A notes offering by
depositing into that account $50.0 million from
the proceeds of the Series A notes offering. The
Depositary Agreement requires us to deposit cash
in and/or post a letter of credit for the Debt
Service Reserve Account in an amount equal to the
aggregate amount of principal and interest due on
the Series B notes on the next succeeding semi-
annual scheduled payment date. For more details,
see "Description of Series B Notes--Debt Service
Reserve Account."
14
Capital Expenditure Reserve
Account.................... We established a Capital Expenditure Reserve
Account for the benefit of the holders of senior
secured notes under the Depositary Agreement. The
Capital Expenditure Reserve Account will be
funded from the Coso partnerships' revenues in
accordance with the terms of the Depositary
Agreement and in accordance with the operating
budgets for the Coso projects as approved by
Sandwell Engineering Inc., our independent
engineer. Amounts on deposit in the Capital
Expenditure Reserve Account will be used for
capital expenditures to be made in accordance
with prudent industry practice and as may be
required pursuant to the terms of the Indenture
and each of the three Credit Agreements between
the Coso partnerships and us, respectively. For
more details, see "Description of Series B
Notes--Capital Expenditure Reserve Account."
Optional Redemption......... We may not redeem the Series B notes due 2001.
We may redeem the Series B notes due 2009 at our
option at any time and from time to time, in
whole or in part, upon not less than 30 nor more
than 60 days notice to each holder of these
notes. If we choose to redeem the Series B notes
due 2009, the redemption price will be at par,
plus accrued interest through the date of
redemption, plus a premium calculated to "make
whole" the holder of these notes to comparable
U.S. Treasury securities plus 50 basis points.
For more details, see "Description of Series B
Notes--Optional Redemption."
Mandatory Redemption........ We will be required to redeem the Series B notes
under certain circumstances, in whole or in part,
ratably among each series at a redemption price
equal to the principal amount of the Series B
notes being redeemed plus accrued and unpaid
interest to the redemption date. For more
details, see "Description of Series B Notes--
Mandatory Redemption."
Change of Control........... If a change of control occurs, each holder of
Series B notes would be able to require us to
repurchase its Series B notes, in whole or in
part, at a price equal to 101% of the principal
amount of those notes, plus any accrued and
unpaid interest thereon. See "Description of
Series B Notes--Repurchase at the Option of
Holders upon Change of Control."
15
Principal Covenants......... The Indenture contains certain restrictive
covenants that, among other things, limit our
ability to:
. incur additional indebtedness;
. release funds from reserve accounts
established under the Depositary
Agreement;
. become liable in connection with
guarantees;
. create liens;
. pay dividends or make distributions;
. take certain actions with respect to the
Credit Agreements; and
. enter into any transaction of merger or
consolidation or change our form of
organization or our business.
For a more detailed description of these
covenants, see "Description of Series B Notes--
Certain Covenants."
Principal Credit Agreement
Covenants.................. The Credit Agreement with each Coso partnership
contains certain restrictive covenants that,
among other things, limit that Coso partnership's
ability to:
. incur additional indebtedness;
. release funds from reserve accounts
established under the Depositary
Agreement;
. create liens;
. sell assets;
. sell partnership interests in the Coso
partnerships;
. pay dividends or make distributions;
. enter into certain transactions with
affiliates;
. take certain actions with respect to the
material agreements to which they are a
party;
. become liable in connection with
guarantees (other than their guarantees of
the Series B notes); and
. enter into any transaction of merger or
consolidation or change their form of
organization or business.
For a more detailed description of these
covenants, see "Description of Credit
Agreements--Certain Covenants" under the heading
"Description of Series B Notes."
16
Certain Accounts............ In accordance with the Depositary Agreement, we
and the Coso partnerships have established
certain accounts, including:
. the Revenue Account;
. the Principal Account;
. the Interest Account;
. the Debt Service Reserve Account;
. the Capital Expenditure Reserve Account;
. the Operating and Maintenance Fees
Account;
. the Management Fees Account;
. the Distribution Account;
. the Distribution Suspense Account;
. the Loss Proceeds Account; and
. the Redemption Account.
The Coso partnerships have limited rights to
withdraw funds from these accounts in accordance
with the terms and conditions set forth in the
Depositary Agreement. For more information
regarding these accounts, see "Description of
Series B Notes--Flow of Funds."
Absence of Public Market
for Notes.................. There has been no public market for the Series A
notes and no active public market for the Series
B notes is currently anticipated. We currently do
not intend to apply for the listing of the Series
B notes on any securities exchange or to seek
approval for quotation through any automated
quotation system. Donaldson, Lufkin & Jenrette
Securities Corporation, the initial purchaser of
the Series A notes, has advised us that it
currently intends to make a market in the Series
B notes; however, it is not obligated to do so
and it may discontinue any market making at any
time without notice. Accordingly, we cannot
assure you as to the liquidity or the trading
market for the Series B notes.
Risk Factors
The "Risk Factors" section contains a discussion of certain factors that you
should consider in evaluating an investment in the Series B notes.
17
The Independent Engineer's Report
Exhibit A of this prospectus contains a report prepared by Sandwell
Engineering Inc. dated May 20, 1999. We also call Sandwell Engineering Inc. our
independent engineer. We included this report, which we call the independent
engineer's report, to help you understand and evaluate the Coso projects.
Sandwell Engineering Inc. performed an independent engineer's review of the
Coso projects. The independent engineer's report assesses, as of its date,
technical, environmental and economic aspects of the Coso projects, including
certain financial and operational estimates and projections of the Coso
projects' revenue generation capacity and associated costs. These estimates and
projections were prepared by us and are our responsibility. They have not been
examined, compiled or subjected to any procedures by either KPMG LLP, our
independent accountants, or PricewaterhouseCoopers LLP, the former independent
accountants of the Coso projects. Accordingly, neither KPMG LLP nor
PricewaterhouseCoopers LLP expresses any opinion or other form of assurance
with respect to these estimates and projections. The PricewaterhouseCoopers LLP
reports included in this prospectus relate to the Coso partnerships' historical
financial information. The KPMG LLP report included in this prospectus relates
to our historical balance sheet as of April 22, 1999 (our date of inception).
These reports do not extend to the estimates and projections included in the
independent engineer's report and should not be read to do so.
For purposes of preparing the estimates and projections, we relied upon
assumptions about material contingencies and other matters that are not within
our control nor the control of any other person. You should be aware that
actual results will differ, perhaps materially, from those estimated or
projected. No one can assure you that the assumptions used are correct or that
the estimates and projections will match actual results of operations.
Therefore, we do not make, nor intend to make, nor should you infer, any
representation with respect to the likelihood of any future outcome. If actual
results are materially less favorable than those shown or if the assumptions
used in formulating the estimates and projections prove to be incorrect, the
Coso partnerships' ability to make payments to us under their project notes,
our ability to make payments of principal, premium, if any, and interest on the
Series B notes when due, and the Coso partnerships' ability to meet their
obligations under their guarantees could be materially and adversely affected.
You should read "Risk Factors--Uncertainties of Estimates, Projections and
Assumptions" for additional information about the assumptions, estimates and
projections in the independent engineer's report.
We retained Sandwell Engineering Inc. based upon its expertise in industrial
and power plant engineering. It has provided services to the Coso partnerships
for approximately ten years and continues to provide services to the Coso
projects. Sandwell Engineering Inc. has no affiliation with Caithness Energy,
the Coso partnerships or us. We did not impose any limitations on the scope of
the independent engineer's investigation, nor did Caithness Energy or the Coso
partnerships.
On the basis of Sandwell Engineering Inc.'s review of the Coso projects'
facilities, including the plants, wellfields and gathering system, the
information provided to it on our behalf and the assumptions set forth in the
independent engineer's report, Sandwell Engineering Inc. was of the opinion
that:
. The current operations and maintenance practices employed by FPL
Operating as operator of the Coso projects' facilities are reasonable for
operation and maintenance of facilities of this type, to maintain
compliance with all relevant environmental and other permits and
approvals that are required, and to produce the predicted revenues and
cash flow of the facilities.
18
. FPL Operating, as operator, has the geothermal plant operating experience
and resources necessary to operate the facilities so as to produce the
predicted revenues and cash flow for the Coso projects' facilities.
. The 1999 operating and maintenance financial projections and capital
expenditures forecasts proposed by us or on our behalf for the Coso
projects' facilities are consistent with the operating and
maintenance needs of the facilities, are prudent, and are reasonably
designed to produce the predicted revenues and cash flow of the
facilities.
. If the Coso projects' facilities are maintained and operated in
accordance with current practices, and if the quality and quantity of
the geothermal resources for these facilities are as projected by us
or on our behalf, then the eleven-year financial projections of
operating and maintenance expenditures, and of capital expenditures,
for these facilities are consistent with the operating and
maintenance needs of these facilities. Based on these operating
assumptions, the projected revenues and cash flows of these
facilities, as shown in the financial projections, are reasonable.
. All major permits and approvals required from federal, state and
local agencies for current operation of the Coso projects' facilities
have been obtained, and all required environmental reporting is being
carried out.
. The management organization for operating the Coso projects is
acceptable. The attention given to safety matters, and the safety
programs being implemented are reasonable and acceptable. The
training and certification program for plant operators and
maintenance staff is acceptable.
. Assuming annual rates of interest of 6.80% for the senior secured
notes due 2001 and of 9.05% for the senior secured notes due 2009,
the debt service coverage ratios, or DSCR, would be:
For the period 1999 through 2001:
Navy I partnership: Minimum DSCR 1.32
Average DSCR 1.32
BLM partnership: Minimum DSCR 1.28
Average DSCR 1.32
Navy II partnership: Minimum DSCR 1.32
Average DSCR 1.34
For the period 2002 through 2009:
Navy I partnership: Minimum DSCR 1.50
Average DSCR 1.58
BLM partnership: Minimum DSCR 1.49
Average DSCR 1.58
Navy II partnership: Minimum DSCR 1.53
Average DSCR 1.59
You should read "Exhibit A--The Independent Engineer's Report" for a more
complete discussion of the methodology used by Sandwell Engineering Inc. and
the assumptions underlying the foregoing opinions.
19
The Energy Markets Consultant's Report
Exhibit B of this prospectus contains a report prepared by Henwood Energy
Services, Inc. dated May 20, 1999. We also call Henwood Energy Services, Inc.
our energy markets consultant. We included this report, which we call the
energy markets consultant's report, to help you understand and evaluate the
Coso projects. The energy markets consultant prepared its report to, among
other things, provide:
. an independent forecast of energy prices in the Southern California
market for the period 1999 through 2009,
. an assessment of the competitive position of the Coso projects in the
Southern California market, and
. confirmation of the reasonableness of our AB1890 payment forecasts in our
projections.
These projections were prepared by us and are our responsibility. They have not
been examined, compiled or subjected to any procedures by either KPMG LLP or
PricewaterhouseCoopers LLP. Accordingly, neither KPMG LLP nor
PricewaterhouseCoopers LLP expresses any opinion or other form of assurance
with respect to these projections. The PricewaterhouseCoopers LLP reports
included in this prospectus relate to the Coso partnerships' historical
financial information. The KPMG LLP report included in this prospectus relates
to our historical balance sheet as of April 22, 1999 (our date of inception).
These reports do not extend to the projections included in the energy markets
consultant's report and should not be read to do so.
The assumptions contained in the projections and evaluated by the energy
markets consultant concern a number of matters that are not within our control
nor the control of any other person. You should be aware that actual results
will differ, perhaps materially, from those projected. No one can assure you
that the assumptions used are correct or that the projections will match actual
results of operations. Therefore, we do not make, nor intend to make, nor
should you infer, any representation with respect to the likelihood of any
future outcome. If actual results are materially less favorable than those
shown or if the assumptions evaluated in the energy markets consultant's report
and utilized in preparing the projections prove to be incorrect, the Coso
partnerships' ability to make payments to us under their project notes, our
ability to make payments of principal, premium, if any, and interest on the
Series B notes when due, and the Coso partnerships' ability to meet their
obligations under their guarantees could be materially and adversely affected.
You should read "Risk Factors--Uncertainties of Estimates, Projections and
Assumptions" for more information.
We retained Henwood Energy Services, Inc. based upon its expertise in power
market price forecasting. It has no affiliation with Caithness Energy, the Coso
partnerships or us. We did not impose any limitations on the scope of the
energy markets consultant's investigation, nor did Caithness Energy or the Coso
partnerships.
Based on its analyses in the energy markets consultant's report, Henwood
Energy Services, Inc. expressed the following major conclusions in its report:
. Henwood Energy Services, Inc.'s market clearing prices forecast indicates
that the Southern California annual average power price will increase
from $26.9 per MW hour (MWh) in 2000 to $44.3/MWh by 2009--which
translates into an average annual rate of increase of approximately 5.7%
over that period (inflation is included in all prices and is equal to
3.0% per year).
20
. However, there are three distinct periods of price movement. Between 2000
and 2002 in California, which Henwood Energy Services, Inc. calls the
Transition Period, prices increase at an annual average rate of 12.6%.
During the Transition Period, prices bid into the California Power
Exchange reflect short-run marginal fuel costs because most utility-owned
generators receive payments for capacity from "must-run" contracts, if in
California, or through traditional tariffs, if outside of California.
. After the Transition Period ends in March 2002, the California Power
Exchange should cease to behave as a marginal cost pool. This change is
reflected in the forecast. The average market-clearing prices increase
from $34.1/MWh in 2002 to $40.4/MWh by 2005--an average rate of increase
of about 5.7% per year. Price increases in this period reflect attempts
by generators in California to recover at least a portion of fixed
capacity costs through market sales.
. Beyond 2005, prices are forecast to increase gradually but steadily,
about 2.3% per year, which is less than the inflation rate. The growth
rate during the 2005 to 2009 period is influenced largely by the
introduction into the generation market of high efficiency gas-fired
combined cycle plants. These plants are frequently on the margin. That
is, they establish the market-clearing price, and thus are in a position
to push power prices down gradually over time as they replace less
efficient thermal generation plants.
. Based on Henwood Energy Services, Inc.'s long-run natural gas price
forecast and a 3.0% annual inflation rate, the energy markets consultant
estimates Edison's short-run avoided cost of energy prices to be
$31.3/MWh for the remaining months of 1999 (May through December),
$32.4/MWh in 2000 and $33.4/MWh in 2001. These prices are higher than
Henwood Energy Services, Inc.'s forecast of power prices on the
California Power Exchange during the same period.
. The energy markets consultant expects the Coso projects to be a low-cost
producer in all of the years of the study. According to data provided by
us or on our behalf, the annual average operating cost in 2005 is
$10.83/MWh. About 70.0% of the electricity produced in the Western
Systems Coordinating Council in 2005--the first year of full
competition--is generated from units with higher costs. Of all the
generation in the region, only hydro and wind generators have lower
operating costs (hydro and wind power account for about 24.0% and 1.0%,
respectively, of all electric generation in California).
. The Coso projects' annual average operating costs are about 69.0% below
annual Southern California power prices, averaged over all years of the
forecast. In fact, the Coso partnerships' operating costs are
significantly below even the off-peak market-clearing prices in all
forecasted years.
. The low-cost relationship between Henwood Energy Services, Inc.'s market
clearing prices forecast and our operating costs continues in the Low Gas
Price sensitivity cases set forth in the energy markets consultant's
report. Under the worst-case scenario set forth in the energy markets
consultant's report, Low Gas Price Case 2, the Coso partnerships'
operating costs are, on average, about 58.0% below off-peak prices.
. The energy markets consultant estimates that the Southern California
market clearing prices will be greater than or equal to $19.7/MWh in
about 96.0% of all hours in 2005. This means that the Coso partnerships,
with an average operating cost of $10.8/MWh, will be below the market-
clearing prices in each of those hours and, in the absence of a power
purchase agreement, would be dispatched accordingly.
21
. The Coso partnerships are eligible to receive AB1890 sponsored renewable
energy subsidies under Tier 3 of the Existing Renewable Energy category.
However, based on the assumptions made by us or on our behalf and by
Henwood Energy Services, Inc., the Transition Period short-run avoided
cost of energy price exceeds 3.0c per kWh (the floor price guaranteed by
AB1890) during most months of 2000 and 2001. Consequently, although
subsidy funds are available, short-run avoided cost of energy prices are
forecast to be sufficiently high that Tier 3 producers will not require a
subsidy in most months. In the event that future short-run avoided cost
of energy prices are lower than forecast in the energy markets
consultant's report, Henwood Energy Services, Inc. believes that the
AB1890 program has ample funds to ensure that Tier 3 producers receive a
minimum of 3.0c per kWh until the end of 2001.
. Henwood Energy Services, Inc. has reviewed the methodology and
assumptions used by us to estimate the AB1890 subsidy payments and it
believes that our assumptions are reasonable and our methodology and
calculations are consistent with and similar to its own procedures.
You should read "Exhibit B--The Energy Markets Consultant's Report" for a
more complete discussion of the conclusions expressed by Henwood Energy
Services, Inc.
The Geothermal Consultant's Report
Exhibit C of this prospectus contains a report prepared by GeothermEx, Inc.
dated May 1999. We call GeothermEx, Inc. our geothermal consultant. We included
this report, which we call the geothermal consultant's report, to help you
understand and evaluate the Coso projects. The geothermal consultant's work
consisted of:
. a review of the status of the steam supply from the geothermal resource,
. a review of resource-related capital and operating costs, and
. an assessment of the reasonableness of the forecasts of power production
and resource-related costs contained in the projections provided by us or
on our behalf.
These projections have not been examined, compiled or subjected to any
procedures by either KPMG LLP or PricewaterhouseCoopers LLP. Accordingly,
neither KPMG LLP nor PricewaterhouseCoopers LLP expresses any opinion or other
form of assurance with respect to these projections. The PricewaterhouseCoopers
LLP reports included in this prospectus relate to the Coso partnerships'
historical financial information. The KPMG LLP report included in this
prospectus relates to our historical balance sheet as of April 22, 1999 (our
date of inception). These reports do not extend to the projections included in
the geothermal consultant's report and should not be read to do so.
We omitted from Exhibit C of this prospectus Appendices A through F of the
geothermal consultant's report. Appendices A through F include the production
histories for Navy I, BLM and Navy II production wells and the injection
histories for Navy I, BLM and Navy II injection wells. You can obtain copies of
Appendices A through F of the geothermal consultant's report from us upon
request (subject to possible confidentiality restrictions). See "Available
Information."
22
The geothermal consultant's report contains assumptions concerning material
contingencies and other matters that are not within our control or the control
of any other person. You should be aware that actual results will differ,
perhaps materially, from those projected. No one can assure you that these
assumptions are correct or that the conclusions in geothermal consultant's
report will match actual results of operations. Therefore, we do not make, or
intend to make, nor should you infer, any representation with respect to the
likelihood of any future outcome. If actual results are materially less
favorable than those shown or if the assumptions evaluated in the geothermal
consultant's report prove to be incorrect, the Coso partnerships' ability to
make payments to us under their project notes, our ability to make payments of
principal, premium, if any, and interest on the Series B notes when due, and
the Coso partnerships' ability to meet their obligations under their guarantees
could be materially and adversely affected. You should read "Risk Factors--
Uncertainties of Estimates, Projections and Assumptions" for more information.
We retained GeothermEx, Inc. based upon its expertise in the field of
geothermal energy. It has no affiliation with Caithness Energy, the Coso
partnerships or us.
Based upon its review, GeothermEx, Inc. reached the following main
conclusions in its report:
. The resource data supplied to GeothermEx, Inc. by us or on our behalf
appear reasonable based upon GeothermEx, Inc.'s long familiarity with the
Coso projects.
. The Coso geothermal resource has supplied steam to the plants for more
than ten years and has proven to be one of the most reliable geothermal
reservoirs in the United States.
. Geothermal energy reserves at the Coso geothermal resource are more than
sufficient to support the plants for 30 years. However, as in all
geothermal fields, make-up well drilling will be necessary to maintain
power output.
. Development of leaseholds adjacent to the Coso projects' acreage is
unlikely, and the possibility of any impact of offsetting development on
the performance of the Coso geothermal resource is remote.
. The financial projections provided to GeothermEx, Inc. by us or on our
behalf show a combined generation capacity of about 264 MW until year
2006 and declining thereafter. The forecasts of the generation decline
trend after year 2006 made by us are reasonable and very similar to
GeothermEx, Inc.'s forecasts.
. The well drilling and workover programs assumed in the financial
projections provided by us or on our behalf are reasonable and should
result in steam supply sufficient to maintain the generation capacity
forecast in our financial projections.
. Resource-related capital and operating costs assumed in our financial
projections are reasonable and consistent with the historical trend and
industry practice.
You should read "Exhibit C--The Geothermal Consultant's Report" for a more
complete discussion of the conclusions reached by GeothermEx, Inc.
23
Summary Selected Historical and Pro Forma Financial and Operating Data
Because we were only recently formed, we have no financial or operating
history. The following tables set forth summary selected historical and pro
forma financial and operating data for each of the Coso partnerships on a
stand-alone basis, and summary selected pro forma financial and operating data
for the Coso partnerships on a combined basis, as of and for the periods
presented. The summary selected historical financial data for each of the five
years ended December 31, 1998 is derived from the audited financial statements
of each of the Coso partnerships. The summary selected historical financial
data as of and for the three months ended March 31, 1998 and 1999 is unaudited.
The pro forma financial data for the three months ended March 31, 1999 and as
of March 31, 1999 is also unaudited.
The unaudited statement of operations data for the three months ended March
31, 1998 and the two months ended February 28, 1999, have been prepared on the
same basis as the audited financial statements included elsewhere in this
prospectus. The unaudited statement of operations data for the one month ended
March 31, 1999, has been prepared on a new basis of accounting adopted by the
Coso partnerships in connection with Caithness Acquisition's purchase of all of
CalEnergy's interests in the Coso projects. See "--The Purchase." In the
opinion of management, the unaudited statement of operations data contain all
adjustments, consisting only of normally recurring adjustments, necessary for a
fair presentation of such financial information. The unaudited financial
information set forth below is not necessarily indicative of results to be
expected for any future periods and should be read in conjunction with the
historical financial statements of the Coso partnerships, including the related
notes thereto, "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and the other financial information included elsewhere
in this prospectus.
The energy revenues received by the Coso partnerships during the five-year
period ended December 31, 1998 and the three month periods ended March 31, 1998
and 1999, as reflected in the tables below, should not be viewed as an
indicator of energy revenues to be received by the Coso partnerships during any
future periods. During the periods reflected in the tables below, Edison made
energy payments to the Coso partnerships based on the fixed energy prices
provided for in the power purchase agreements, except that, since August 1997,
Edison has been making energy payments to the Navy I partnership based on
Edison's avoided cost of energy and, in March 1999, Edison began making
payments to the BLM partnership based on Edison's avoided cost of energy.
Edison's avoided cost of energy has been and is expected to be in the future
substantially lower than the fixed energy prices received by the Coso
partnerships in the past. Once the fixed energy price period for the Navy II
partnership expires, Edison is also expected to make energy payments to the
Navy II partnership based on Edison's avoided cost of energy. See "Risk
Factors--Impact of Avoid Cost of Energy Pricing" and "Management's Discussion
and Analysis of Financial Condition and Results of Operations."
Since the information in the following tables is only a summary, you should
read the historical financial statements of each of the Coso partnerships,
including the related notes thereto, "Management's Discussion and Analysis of
Financial Condition and Results of Operations," "Unaudited Pro Forma Financial
Data" and the other financial information included elsewhere in this
prospectus.
24
Navy I Partnership
(Stand-alone)(a)
Pro Forma
Year Ended December 31, Year Ended
------------------------------------------------- December 31,
1994 1995 1996 1997 1998 1998(c)
(In thousands, except ratio data)
Statement of Operations
Data:
Energy revenues........ $ 87,223 $ 92,797 $103,940 $ 86,586(b) $39,580(b) $39,580
Capacity revenues(f)... 14,258 14,266 14,266 13,845 13,573 13,573
Interest and other
income................ 2,529 2,893 3,286 1,980 585 585
-------- -------- -------- -------- ------- -------
Total revenues....... 104,020 109,956 121,492 102,411 53,738 53,738
Operating expenses..... 36,512 37,145 36,147 33,992 31,894 29,835
-------- -------- -------- -------- ------- -------
Operating income....... $ 67,508 $ 72,811 $ 85,345 $ 68,419 $21,844 $23,903
======== ======== ======== ======== ======= =======
Additional Financial
Data:
Net cash flows from
operating
activities............ $ 74,516 $ 70,192 $ 83,779 $ 88,540 $32,163
Net cash flows from
investing
activities............ (14,954) (7,922) (3,149) 17,948 (7,728)
Net cash flows from
financing
activities............ (23,499) (55,846) (109,999) (119,324) (27,323)
Ratio of earnings to
fixed charges(g)...... 5.2x 6.4x 9.6x 10.9x 5.0x 1.8x
EBITDA before
cumulative effect of
accounting
change(h)............. $ 79,617 $ 85,581 $ 98,670 $ 81,233 $33,616 $35,259
Capital expenditures... 14,417 6,965 2,294 4,589 6,683 6,683
-------- -------- -------- -------- ------- -------
EBITDA before
cumulative effect of
accounting change
less capital
expenditures.......... $ 65,200 $ 78,616 $ 96,376 $ 76,644 $26,933 $28,576
======== ======== ======== ======== ======= =======
Ratio of EBITDA before
cumulative effect of
accounting change to
fixed charges(i)...... 6.1x 7.5x 11.1x 13.0x 7.8x 2.6x
Ratio of EBITDA before
cumulative effect of
accounting change
less capital
expenditures to fixed
charges(i)............ 5.0x 6.9x 10.9x 12.2x 6.2x 2.1x
Operating Data:
Operating capacity
factor(j)(k).......... 114.0% 112.1% 112.1% 103.2% 94.6%
kWh produced........... 799,200 785,400 787,688 723,116 662,560
Three Months Ended March 31, 1999
---------------------------------
Two Months One Month Pro Forma
Three Months Ended Ended Three Months
Ended February 28, March 31, Ended
March 31, 1999 1999 March 31,
1998 (prior basis) (new basis)(d) Total 1999(e)
(In thousands, except ratio data)
Statement of Operations
Data:
Energy revenues........ $ 9,993 $ 8,098 $4,399 $12,497 $12,497
Capacity revenues(f)... 813 474 237 711 711
Interest and other
income................ 136 824 827 1,651 1,651
------- ------- ------ ------- -------
Total revenues....... 10,942 9,396 5,463 14,859 14,859
Operating expenses..... 7,423 5,716 2,692 8,408 8,079
------- ------- ------ ------- -------
Operating income....... $ 3,519 $ 3,680 $2,771 $ 6,451 $ 6,780
======= ======= ====== ======= =======
Additional Financial
Data:
Net cash flows from
operating
activities............ $ 7,804 $ 6,592 $2,665 $9,257
Net cash flows from
investing
activities............ (24) (538) (397) (935)
Net cash flows from
financing
activities............ (108) (1,926) -- (1,926)
Ratio of earnings to
fixed charges(g)...... 3.1x 5.6x 1.7x(p) 2.8x 2.0x
EBITDA(h).............. $ 6,476 $ 5,284 $3,554 $ 8,838 $ 9,112
Capital expenditures... 24 538 271 809 809
------- ------- ------ ------- -------
EBITDA less capital
expenditures.......... $ 6,452 $ 4,746 $3,283 $ 8,029 $ 8,303
======= ======= ====== ======= =======
Ratio of EBITDA to
fixed charges(i)...... 5.8x 8.0x 2.2x 3.9x 2.7x
Ratio of EBITDA less
capital expenditures
to fixed charges(i)... 5.7x 7.2x 2.0x 3.5x 2.4x
Operating Data:
Operating capacity
factor(j)(k).......... 83.0% 73.4% 77.4% 75.4%
kWh produced........... 143,400 83,100 46,041 129,141
See Footnotes to Summary Selected Historical and Pro Forma Financial and
Operating Data
25
BLM Partnership
(Stand-alone)
Pro Forma
Year Ended December 31, Year Ended
------------------------------------------------ Dec 31,
1994 1995 1996 1997 1998 1998(c)
(In thousands, except ratio data)
Statement of Operations
Data:
Energy revenues........ $ 76,134 $ 86,596 $ 87,985 $ 88,929 $ 93,352 $ 93,352
Capacity revenues(f)... 13,929 13,938 13,938 13,939 13,847 13,847
Interest and other
income................ 2,509 2,644 2,520 1,712 1,181 1,181
-------- -------- -------- -------- -------- --------
Total revenues....... 92,572 103,178 104,443 104,580 108,380 108,380
Operating expenses..... 41,289 40,418 40,017 43,193 44,687 40,654
-------- -------- -------- -------- -------- --------
Operating income....... $ 51,283 $ 62,760 $ 64,426 $ 61,387 $ 63,693 $ 67,726
======== ======== ======== ======== ======== ========
Additional Financial
Data:
Net cash flows from
operating
activities............ $ 60,603 $ 63,426 $ 64,335 $ 60,948 $ 75,520
Net cash flows from
investing
activities............ (17,916) (8,480) (5,798) 19,280 (20,302)
Net cash flows from
financing
activities............ (21,194) (46,311) (85,590) (92,521) (56,091)
Ratio of earnings to
fixed charges(g)...... 3.2x 4.2x 4.9x 6.7x 10.2x 6.9x
EBITDA before
cumulative effect of
accounting
change(h)............. $ 63,575 $ 75,930 $ 78,357 $ 75,644 $ 78,001 $ 80,383
Capital expenditures
(reimbursements)...... 17,437 8,425 6,033 3,728 20,302 20,302
-------- -------- -------- -------- -------- --------
EBITDA before
cumulative effect of
accounting change
less capital
expenditures.......... $ 46,138 $ 67,505 $ 72,324 $ 71,916 $ 57,699 $ 60,081
======== ======== ======== ======== ======== ========
Ratio of EBITDA before
cumulative effect of
accounting change to
fixed charges(i)...... 4.0x 5.0x 6.0x 8.3x 12.4x 8.2x
Ratio of EBITDA before
cumulative effect of
accounting change
less capital
expenditures to fixed
charges(i)............ 2.9x 4.5x 5.5x 7.9x 9.2x 6.1x
Operating Data:
Operating capacity
factor(j)(k).......... 99.5% 107.5% 107.9% 99.6% 104.4%
kWh produced........... 697,000 753,200 758,115 697,794 731,767
Three Months Ended March 31, 1999
------------------------------------
Two Months One Month Pro Forma
Three Months Ended Ended March Three Months
Ended February 28, 31, Ended
March 31, 1999 1999 March 31,
1998 (prior basis) (new basis)(d) Total 1999(e)
(In thousands, except ratio data)
Statement of Operations
Data:
Energy revenues........ $21,592 $16,716 $3,434 $20,150 $20,150
Capacity revenues(f)... 1,136 817 410 1,227 1,227
Interest and other
income................ 217 78 118 196 196
------- ------- ------ ------- -------
Total revenues....... 22,945 17,611 3,962 21,573 21,573
Operating expenses..... 11,242 8,181 3,126 11,307 10,643
------- ------- ------ ------- -------
Operating income....... $11,703 $ 9,430 $ 836 $10,266 $10,930
======= ======= ====== ======= =======
Additional Financial
Data:
Net cash flows from
operating
activities............ $18,478 $10,367 $6,595 $16,962
Net cash flows from
investing
activities............ (3,556) 120 (294) (174)
Net cash flows from
financing
activities............ (413) 425 (198) 227
Ratio of earnings to
fixed charges(g)...... 6.6x 15.3x 0.7x(p) 5.6x 4.5x
EBITDA(h).............. $15,327 $11,980 $2,011 $13,991 $14,388
Capital expenditures
(reimbursements)...... 3,556 (120) 311 191 191
------- ------- ------ ------- -------
EBITDA less capital
expenditures.......... $11,771 $12,100 $1,700 $13,800 $14,197
======= ======= ====== ======= =======
Ratio of EBITDA to
fixed charges(i)...... 8.6x 19.4x 1.6x 7.6x 5.9x
Ratio of EBITDA less
capital expenditures
to fixed charges(i)... 6.6x 19.6x 1.4x 7.5x 5.8x
Operating Data:
Operating capacity
factor(j)(k).......... 98.0% 109.8% 112.0% 110.9%
kWh produced........... 169,400 124,400 66,656 191,056
See Footnotes to Summary Selected Historical and Pro Forma Financial and
Operating Data
26
Navy II Partnership
(Stand-alone)
Pro Forma
Year Ended December 31, Year Ended
------------------------------------------------- Dec. 31,
1994 1995 1996 1997 1998 1998(c)
(In thousands, except ratio data)
Statement of Operations
Data:
Energy revenues........ $ 81,210 $ 94,372 $101,108 $ 98,778 $105,546 $105,546
Capacity revenues(f)... 14,008 14,018 14,018 14,018 14,018 14,018
Interest and other
income................ 3,072 3,040 3,174 2,187 1,799 1,799
-------- -------- -------- --------- -------- --------
Total revenues....... 98,290 111,430 118,300 114,983 121,363 121,363
Operating expenses..... 31,620 39,168 37,911 37,749 41,120 38,940
-------- -------- -------- --------- -------- --------
Operating income....... $ 66,670 $ 72,262 $ 80,389 $ 77,234 $ 80,243 $ 82,423
======== ======== ======== ========= ======== ========
Additional Financial
Data:
Net cash flows from
operating
activities............ $ 68,432 $ 70,158 $ 74,611 $ 80,660 $ 84,762
Net cash flows from
investing
activities............ (15,091) (6,437) (3,883) 14,399 (6,939)
Net cash flows from
financing
activities............ (29,219) (60,843) (97,316) (112,044) (78,153)
Ratio of earnings to
fixed charges(g)...... 4.5x 5.2x 6.6x 7.3x 9.9x 6.3x
EBITDA before
cumulative effect of
accounting
change(h)............. $ 78,470 $ 85,110 $ 93,443 $ 90,588 $ 93,987 $ 95,937
Capital expenditures... 18,894 6,367 4,333 7,992 6,939 6,939
-------- -------- -------- --------- -------- --------
EBITDA before
cumulative effect of
accounting change
less capital
expenditures.......... $ 59,576 $ 78,743 $ 89,110 $ 82,596 $ 87,048 $ 88,998
======== ======== ======== ========= ======== ========
Ratio of EBITDA before
cumulative effect of
accounting change to
fixed charges(i)...... 5.3x 6.1x 7.7x 8.6x 11.6x 7.3x
Ratio of EBITDA before
cumulative effect of
accounting change
less capital
expenditures to fixed
charges(i)............ 4.0x 5.7x 7.3x 7.8x 10.7x 6.8x
Operating Data:
Operating capacity
factor(j)............. 105.9% 111.3% 110.6% 108.9% 108.6%
kWh produced........... 742,400 779,800 777,243 762,821 760,659
Three Months Ended March 31, 1999
------------------------------------ Pro Forma
Three Two Months Three
Months Ended One Month Months
Ended February 28, Ended March Ended
March 31, 1999 31, 1999 March 31,
1998 (prior basis) (new basis)(d) Total 1999(e)
(In thousands, except ratio data)
Statement of Operations
Data:
Energy revenues........ $25,415 $16,687 $6,716 $23,403 $23,403
Capacity revenues(f)... 1,234 822 412 1,234 1,234
Interest and other
income................ 319 150 156 306 306
------- ------- ------ ------- -------
Total revenues....... 26,968 17,659 7,284 24,943 24,943
Operating expenses..... 10,629 7,340 3,545 10,885 10,560
------- ------- ------ ------- -------
Operating income....... $16,339 $10,319 $3,739 $14,058 $14,383
======= ======= ====== ======= =======
Additional Financial
Data:
Net cash flows from
operating
activities............ $19,352 $12,016 $6,265 $18,281
Net cash flows from
investing
activities............ (808) (1,126) (218) (1,344)
Net cash flows from
financing
activities............ 273 1,766 518 2,284
Ratio of earnings to
fixed charges(g)...... 7.3x 10.8x 2.1x(p) 5.1x 4.4x
EBITDA(h).............. $19,832 $12,658 $4,927 $17,585 $17,910
Capital expenditures... 808 1,126 191 1,317 1,317
------- ------- ------ ------- -------
EBITDA less capital
expenditures.......... $19,024 $11,532 $4,736 $16,268 $16,593
======= ======= ====== ======= =======
Ratio of EBITDA to
fixed charges(i)...... 8.9x 13.3x 2.7x 6.4x 5.5x
Ratio of EBITDA less
capital expenditures
to fixed charges(i)... 8.5x 12.1x 2.6x 5.9x 5.1x
Operating Data:
Operating capacity
factor(j)............. 109.9% 112.7% 112.6% 112.7%
kWh produced........... 190,800 127,700 67,018 194,718
See Footnotes to Summary Selected Historical and Pro Forma Financial and
Operating Data
27
The Coso Partnerships
(Combined)(l)
Pro Forma
Three
Pro Forma Months
Year Ended Ended
Dec. 31, March 31,
1998(c) 1999(e)
(In thousands,
except ratio data)
Statement of Operations Data:
Energy revenues.......................................... $238,478 $56,050
Capacity revenues(f)..................................... 41,438 3,172
Interest and other income................................ 3,565 2,153
-------- -------
Total revenues......................................... 283,481 61,375
Operating expenses....................................... 109,429 29,282
-------- -------
Operating income......................................... $174,052 $32,093
======== =======
Additional Financial Data:
Ratio of earnings to fixed charges(g).................... 4.8x 3.5x
EBITDA before cumulative effect of accounting
change(h)............................................... $211,579 $41,410
Capital expenditures..................................... 33,924 2,317
-------- -------
EBITDA before cumulative effect of accounting change
less capital expenditures............................... $177,655 $39,093
======== =======
Ratio of EBITDA before cumulative effect of accounting
change to fixed charges(i).............................. 5.8x 4.5x
Ratio of EBITDA before cumulative effect of accounting
change less capital expenditures to fixed charges(i).... 4.9x 4.3x
See Footnotes to Summary Selected Historical and Pro Forma Financial and
Operating Data
28
Pro Forma
As of December 31, As of As of As of
-------------------------------------------- March 31, March 31, March 31,
1994 1995 1996 1997 1998 1998 1999 1999(m)
(In thousands)
Balance Sheet Data:
Navy I Partnership (stand-alone)(a)
Cash.................. $ 38,669 $ 45,093 $ 15,724 $ 2,888 $ -- $ 10,560 $ 6,397 $ --
Restricted cash and
investments.......... 27,204 28,161 29,016 6,479 7,524 6,731 7,808 26,155
Property, plant and
equipment, net....... 211,453 205,648 194,617 186,392 180,380 183,459 158,367 158,367
Power purchase
agreement, net....... -- -- -- -- -- -- 14,573 14,573
Total assets.......... 298,684 301,436 264,209 209,390 201,888 213,639 198,326 212,442
Project loans:
Existing project
debt, payable to
Coso Funding
Corp. .............. $154,432 $127,340 $ 76,056 $ 45,666 $ 40,566 $ 45,666 $ 40,566 $ --
Project notes(n)..... -- -- -- -- -- -- -- 151,550
Acquisition debt(o)... -- -- -- -- -- -- 77,610 --
Partners' capital..... 131,880 164,581 167,834 155,568 149,933 158,618 66,763 49,043
-------- -------- -------- -------- -------- -------- -------- --------
Total capitalization.. $286,312 $291,921 $243,890 $201,234 $190,499 $204,284 $184,939 $200,593
======== ======== ======== ======== ======== ======== ======== ========
BLM Partnership (stand-
alone)
Cash.................. $ 31,584 $ 40,219 $ 13,166 $ 873 $ -- $ 15,382 $ 17,015 $ --
Restricted cash and
investments.......... 23,478 23,533 23,298 290 290 290 247 13,310
Property, plant and
equipment, net....... 220,881 216,136 208,238 197,709 201,600 197,641 163,269 163,269
Power purchase
agreement, net....... -- -- -- -- -- -- 20,498 20,498
Total assets.......... 298,893 305,106 269,318 224,912 228,087 236,843 223,739 221,330
Project loans:
Existing project
debt, payable to
Coso Funding
Corp. .............. $155,661 $137,748 $105,990 $ 76,654 $ 37,958 $ 76,654 $ 37,958 $ --
Project notes(n)..... -- -- -- -- -- -- -- 107,900
Acquisition debt(o)... -- -- -- -- -- -- 55,256 --
Partners' capital..... 100,261 119,560 112,666 124,113 163,191 134,686 105,606 89,800
-------- -------- -------- -------- -------- -------- -------- --------
Total capitalization.. $255,922 $257,308 $218,656 $200,767 $201,149 $211,340 $198,820 $197,700
======== ======== ======== ======== ======== ======== ======== ========
Navy II Partnership (stand-alone)
Cash.................. $ 41,843 $ 44,721 $ 18,133 $ 1,148 $ 818 $ 19,965 $ 20,039 $ --
Restricted cash and
investments.......... 22,771 22,841 22,391 -- -- -- -- 18,590
Property, plant and
equipment, net....... 219,047 212,566 203,845 198,483 188,862 195,798 149,380 149,380
Power purchase
agreement, net....... -- -- -- -- -- -- 29,656 29,656
Total assets.......... 309,212 307,537 270,522 226,949 218,965 243,895 230,653 231,400
Project loans:
Existing project
debt, payable to
Coso Funding
Corp. .............. $173,413 $156,043 $124,361 $ 97,267 $ 61,323 $ 97,267 $ 61,323 $ --
Project notes(n)..... -- -- -- -- -- -- -- 153,550
Acquisition debt(o)... -- -- -- -- -- -- 78,634 --
Partners' capital..... 125,161 140,082 126,092 125,413 153,661 140,172 82,392 71,527
-------- -------- -------- -------- -------- -------- -------- --------
Total capitalization.. $298,574 $296,125 $250,453 $222,680 $214,984 $237,439 $222,349 $225,077
======== ======== ======== ======== ======== ======== ======== ========
See Footnotes to Summary Selected Historical and Pro Forma Financial and
Operating Data
29
Pro Forma
As of
March 31,
1999(m)
(In thousands)
Balance Sheet Data:
The Coso partnerships (combined)(l)
Cash.......................................................... $ --
Restricted cash............................................... 58,055
Property, plant and equipment, net............................ 471,016
Power purchase agreement, net................................. 64,727
Total assets.................................................. 665,172
Project loans:
Existing project debt, payable to Coso Funding Corp. ........ $ --
Project notes(n)............................................. 413,000
Acquisition debt(o)........................................... --
Partners' capital............................................. 210,370
--------
Total capitalization.......................................... $623,370
========
See Footnotes to Summary Selected Historical and Pro Forma Financial and
Operating Data
30
Footnotes to Summary Selected Historical and Pro Forma Financial and Operating
Data
(a) Reflects the combined financial results of the Navy I partnership and Coso
Finance Partners II, a California general partnership ("CFP II"). The Navy
I partnership and CFP II were first formed as separate entities to
facilitate the initial bank financing for the construction and development
of Navy I. Initially, the Navy I partnership acquired all of the assets
relating to the first turbine generator unit at Navy I and CFP II acquired
all of the assets of Navy I relating to the second and third generator
units at Navy I. In 1988, CFP II assigned all of its rights and interests
in the second and third generator units at Navy I to the Navy I partnership
in return for a 5.0% royalty to be paid based on the Navy I partnership's
steam production. Since the Navy I partnership and CFP II operate under
common ownership and management control, the historical financial
statements of the entities have been combined after elimination of
intercompany amounts related to the royalty arrangement. At the closing of
the Series A notes offering, CFP II merged with and into the Navy I
partnership and the accrued royalty was extinguished. In addition, the
royalty will no longer accrue from and after the Series A notes offering.
See Note 1 to Notes to Combining and Combined Financial Statements of Coso
Finance Partners and Coso Finance Partners II.
(b) The decrease in energy revenues is due to the fact that Edison paid the
Navy I partnership energy payments based on Edison's position that the
fixed energy price period expired for the Navy I partnership in August
1997. Edison has also taken the position that the fixed energy price period
for the BLM partnership expired in March 1999 and will expire for the Navy
II partnership in January 2000. The Coso partnerships believe that under
the power purchase agreements each of the three turbine generator units at
each Coso project has its own ten-year fixed energy price period. This
issue is one of several currently in dispute and subject to an ongoing
lawsuit between, among others, the Coso partnerships and Edison. You should
read "Business--Legal Proceedings" for more information regarding this
issue and the lawsuit.
(c) Pro forma financial information is based upon the historical financial
statements of each of the Coso partnerships on a stand-alone basis or the
Coso partnerships on a combined basis, as the case may be, for the year
ended December 31, 1998, adjusted for (1) a reduction in O&M and management
committee fees, (2) a net reduction in depreciation and amortization
expenses relating to Caithness Acquisition's purchase of all of CalEnergy's
interests in the Coso projects and (3) an increase in interest expense
relating to the offering, as if such transactions had occurred on January
1, 1998. See "Unaudited Pro Forma Financial Data."
(d) After Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso partnerships adopted a new basis of accounting.
The purchase price was allocated to the portion of the assets and
liabilities purchased from CalEnergy based on their fair values, with the
amount of fair value of net assets in excess of the purchase price being
allocated to long-lived assets on a pro-rata basis.
(e) Pro forma financial information is based upon the historical financial
statements of each of the Coso partnerships on a stand-alone basis or the
Coso partnerships on a combined basis, as the case may be, for the three
months ended March 31, 1999, adjusted for (1) a reduction in O&M and
management committee fees, (2) a net reduction in depreciation and
amortization expenses relating to Caithness Acquisition's purchase of all
of CalEnergy's interests in the Coso projects and (3) an increase in
interest expense relating to the offering, as if such transactions had
occurred on January 1, 1999. See "Unaudited Pro Forma Financial Data."
31
(f) Includes capacity payments and capacity bonus payments paid to the
applicable Coso partnership under its power purchase agreement.
(g) For purposes of computing the ratio of earnings to fixed charges, fixed
charges consist of interest expense and amortization of debt issuance
costs. Earnings used in computing the ratio of earnings to fixed charges
consist of net income plus fixed charges.
(h) EBITDA is defined as earnings before interest expense, depreciation and
amortization and the cumulative effect of the accounting change for start-
up costs (for the year ended December 31, 1998 only). The Coso partnerships
are general partnerships and therefore do not pay income taxes. We believe
that EBITDA provides useful information regarding the Coso partnerships'
ability to service its indebtedness, but it should not be considered in
isolation or as a substitute for operating income or cash flow from
operations (in each case as determined in accordance with GAAP), as an
indicator of the Coso partnerships' operating performance or as a measure
of the Coso partnerships' liquidity. Other companies may calculate EBITDA
in a different manner than the Coso partnerships. EBITDA does not take into
consideration substantial costs and cash flows of doing business, such as
interest expense, depreciation, and amortization. EBITDA does not represent
funds available for discretionary use by the Coso partnerships because
those funds are required for debt service, capital expenditures to replace
fixed assets, working capital and other commitments and contingencies.
EBITDA is not an accounting term.
(i) For purposes of computing the ratio of EBITDA before cumulative effect of
accounting change to fixed charges and EBITDA before cumulative effect of
accounting change less capital expenditures to fixed charges, fixed charges
consist of interest expense and amortization of debt issuance costs. We
believe that these ratios provide useful information regarding the Coso
partnerships' ability to service its indebtedness, but they should not be
considered in isolation or as a substitute for operating income or cash
flow from operations (in each case as determined in accordance with GAAP)
or the ratio of earnings to fixed charges, as an indicator of the Coso
partnerships' operating performance or as a measure of the Coso
partnerships' liquidity. Other companies may calculate these ratios in a
different manner than the Coso partnerships. These ratios are not
accounting terms.
(j) Based on a generating capacity of 80 MW.
(k) The reduction in the operating capacity factor for the Navy I partnership
and the increase in the operating capacity factor for the BLM partnership
is due to the transfer of steam from the Navy I partnership to the BLM
partnership and the Navy II partnership under the steam sharing program.
See "Business--Steam Sharing Program" and "Summary Descriptions of
Principal Agreements Relating to the Coso Projects--Steam Exchange and
Cotenancy Agreements."
(l) Reflects the mathematical summation of pro forma financial information of
the Coso partnerships on a combined basis as of and for the year ended
December 31, 1998, and as of and for the three months ended March 31, 1999.
These combined amounts are unaudited. The combined presentation does not
necessarily reflect the financial condition or results of operations that
would have occurred had the Coso partnerships constituted a single entity
as of or during the same period. Because the Coso partnerships are under
common management and have jointly and severally guaranteed all of our
obligations under the Indenture and the senior secured notes, such
guarantees being secured by (1) a perfected, first priority lien on
substantially all of the assets of the Coso partnerships and (2) a
perfected, first priority pledge of all of the ownership interests in the
Coso partnerships, the combined financial information of the Coso
partnerships has been presented.
32
(m) Reflects (1) the completion of the Series A notes offering and the
application of the proceeds therefrom and (2) certain related adjustments,
as if such transactions had occurred on March 31, 1999. See "Unaudited Pro
Forma Financial Data."
(n) Reflects indebtedness owed to us. We loaned all of the proceeds from the
offering to the Coso partnerships at interest rates and maturities
identical to the interest rates and maturities of the senior secured notes.
(o) In order to complete the purchase, Caithness Acquisition arranged for
short-term debt financing in the principal amount of approximately $211.5
million. Caithness Acquisition used a portion of the proceeds from the
Series A notes offering that it received from the Coso partnerships,
together with funds from other sources, to repay all amounts owed under
this short-term debt facility. As a result of "push down" accounting, a
portion of this short-term debt has been reflected in the financial
statements of each Coso partnerships on a stand-alone basis, and the entire
amount of this short-term debt has been reflected in the combined financial
statements of the Coso partnerships.
(p) The decrease in the ratio of earnings to fixed charges for the one month
ended March 31, 1999 is primarily due to the amortization of debt issuance
costs of approximately $2.0 million, $1.4 million and $2.0 million for the
Navy I partnership, BLM partnership and Navy II partnership, respectively,
related to the short-term debt financing associated with Caithness
Acquisition's purchase of CalEnergy's interests in the Coso projects over
the three-month estimated life of the short-term debt.
33
RISK FACTORS
In addition to the other information set forth in this prospectus, you
should carefully consider the risks described below before deciding to tender
your Series A notes in the exchange offer. These risks are not the only ones
facing the Coso partnerships and us. Additional risks not presently known to
us or that we deem immaterial may also impair the Coso partnerships'
operations and our ability to make payments to you under the Series B notes.
This prospectus also contains forward-looking statements that involve risks
and uncertainties. Our and the Coso partnerships' actual results could differ
materially from those anticipated in these forward-looking statements as a
result of certain factors, including the risks faced by the Coso partnerships
and us described below and elsewhere in this prospectus. You should read
"Forward-Looking Statements" for more information regarding these forward-
looking statements.
Your failure to exchange your Series A notes for Series B notes could have
adverse consequences to you.
The Series A notes were not registered under the Securities Act or under the
securities laws of any state and may not be resold, offered for resale or
otherwise transferred unless they are subsequently registered or resold
pursuant to an exemption from the registration requirements of the Securities
Act and applicable state securities laws. If you do not exchange your
unregistered Series A notes for registered Series B notes pursuant to the
exchange offer, you will not be able to resell, offer to resell or otherwise
transfer the Series A notes unless they are registered under the Securities
Act or unless you resell them, offer to resell or otherwise transfer them
under an exemption from the registration requirements of, or in a transaction
not subject to, the Securities Act. In addition, we and the Coso partnerships
will not be obligated to register the Series A notes under the Securities Act
after the Exchange Offer except in the limited circumstances provided under
the registration rights agreement. In addition, to the extent that Series A
notes are tendered for exchange and accepted in the exchange offer, the market
for the untendered and tendered but unaccepted Series A notes could be
materially and adversely affected.
Your recourse if a default occurs will be limited to the assets and cash flow
of the Coso projects.
We are a special purpose company formed for the purpose of issuing the
senior secured notes for ourselves and on behalf of the Coso partnerships. At
the closing of the Series A notes offering, we loaned all of the proceeds from
the offering to the Coso partnerships. We do not conduct any business, other
than issuing the senior secured notes and making the loans to the Coso
partnerships. Our ability to make payments to you under the Series B notes
will be entirely dependent on the performance of the Coso partnerships under
their project notes. As is common in non-recourse, project finance structures,
the assets and cash flow of the Coso partnerships are the sole source of
payment under their project notes and guarantees.
The Coso partnerships own no significant assets other than those related to
the ownership and operation of the Coso projects. If a Coso partnership
defaults under its project note, credit agreement or guarantee, our remedies
under the Coso partnerships' project notes, credit agreements and guarantees,
including foreclosure of that Coso partnership's assets, may not provide
sufficient funds to pay that Coso partnership's, or any other Coso
partnership's, obligations under its project notes, credit agreements and
guarantees. None of our shareholders, partners or affiliates (other than the
34
Coso partnerships), none of the partners or affiliates of the Coso partnerships
(other than the partners of the Coso partnerships solely with respect to their
ownership interests in the Coso partnerships) and none of our, Caithness
Energy's or the Coso partnerships' directors, officers or employees will
guarantee or be in any way liable for payment of the Series B notes, the
project notes or the guarantees. See "Description of Series B Notes--Brief
Description of the Series B Notes and Guarantees."
Our ability to make payments to you under the Series B notes will depend
entirely on the successful operation of the Coso projects.
Our ability to make payments of principal, premium, if any, and interest on
the Series B notes depends entirely on our receipt of payments from the Coso
partnerships under their project notes and guarantees, and their ability to
make payments under their project notes and guarantees depends entirely on the
successful operation of the Coso projects. If one or more Coso partnerships
cannot make payments under their project notes and guarantees, we might not
have sufficient funds to pay you.
Operating the Coso projects involves, among other things, general economic,
financial, competitive, legislative, regulatory and other factors that are
beyond our control. Changes in these factors could make it more expensive for
the Coso partnerships to operate the Coso projects, could require additional
capital expenditures or could reduce certain benefits currently available to
the Coso partnerships. A variety of other risks affect the Coso projects, some
of which are beyond our control, including:
. One or more of the Coso projects could perform below expected levels of
output or efficiency;
. The Coso geothermal resource could be interrupted or unavailable;
. Operating costs could increase;
. Energy prices paid by Edison could decrease;
. Delivery of electrical energy to Edison could be disrupted;
. Environmental problems could arise which could lead to fines or a
shutdown of one or more plants;
. Plant units and equipment have broken down or failed in the past and
could break down or fail in the future;
. The operators of the Coso projects could suffer labor disputes;
. The government could change permit or governmental approval requirements;
. Third parties could fail to perform their contractual obligations to the
Coso partnerships; and
. Catastrophic events, such as fires, earthquakes, explosions, floods,
severe storms or other occurrences, could affect one or more of the Coso
projects or Edison.
No one can assure you that none of these events will happen. For some
information regarding the recent shutdown of Unit 1 at Navy I resulting from
equipment failure, see "Business--Overview of Coso Projects--Plants--Navy I."
35
Further, no one can assure you that the Coso partnerships' operations will
generate sufficient cash, that currently anticipated cost savings or capital or
other operating improvements will be realized on schedule or that the Coso
partnerships will be successfully operated in the future to enable the Coso
partnerships to make payments under their project notes and guarantees. In
addition, no one can assure you that the Coso partnerships' financial condition
or results of operations in the future will match those of the past.
In addition, the Coso partnerships must meet specified performance
requirements under their power purchase agreements during the months of June
through September to continue to qualify for the maximum capacity and capacity
bonus payments. If one or more of the events listed above occur and
substantially affect the performance of one or more of the plants during these
months, operating revenues would significantly decrease. If operating revenues
decrease, one or more of the Coso partnerships may not be able to make payments
under their project notes and guarantees. This would impair our ability to make
payments to you under the Series B notes.
Future energy payments paid by Edison to the Coso partnerships will most likely
be less than historical energy payments because they will be paid based on
Edison's avoided cost of energy.
The Coso partnerships sell 100% of the electrical energy generated at the
plants to Edison under the power purchase agreements. For more information
regarding the power purchase agreements, see "Summary Descriptions of Principal
Agreements Relating to the Coso Projects--Power Purchase Agreements."
Under the power purchase agreements, Edison must pay to the Coso partnerships
capacity payments which are fixed throughout the lives of these agreements.
Edison must also pay capacity bonus payments under the power purchase
agreements. The maximum annual capacity bonus payment available is also fixed
throughout the lives of the power purchase agreements. Edison must also pay to
the Coso partnerships energy payments which are fixed for only the first ten
years of the terms of the power purchase agreements. Thereafter, energy
payments will depend on Edison's avoided cost of energy, as determined under
certain legislation being implemented by the California Public Utilities
Commission. Edison has taken the position that the fixed energy price period
expired in August 1997 for the Navy I partnership and in March 1999 for the BLM
partnership, and will expire in January 2000 for the Navy II partnership. See
"--The Coso partnerships and their managing partners are currently involved in
material litigation with Edison, their sole customer" and "Business--Legal
Proceedings."
Edison has made energy payments to the Navy I partnership since the end of
August 1997 based upon Edison's avoided cost of energy. For the year ended
December 31, 1998, Edison's average avoided cost of energy paid to the Navy I
partnership was 3.0c per kWh, which is substantially below the fixed energy
prices earned by the Navy I partnership prior to August 1997 and by the BLM
partnership and the Navy II partnership in 1998. The BLM partnership is now
receiving energy payments based on Edison's avoided cost of energy and will
likely receive energy payments in the future which are substantially less than
the fixed energy prices it earned in 1998. We also expect that, after the Navy
II partnership's fixed energy price period expires, Edison's avoided cost of
energy payable to the Navy II partnership will be substantially below the fixed
energy prices currently being paid by Edison to the Navy II partnership under
its power purchase agreement. You should read "Management's Discussion and
Analysis of Financial Condition and Results of Operations" for more information
regarding energy payments received by the Coso partnerships.
36
Although Edison pays the Navy I partnership and the BLM partnership energy
payments based on 100% of its currently published avoided cost of energy, as
determined by a methodology approved by, and subject to change by, the
California Public Utilities Commission (currently based on a formula tied to
the price of natural gas), this will change within the next two to three years.
Under AB1890, the comprehensive restructuring legislation enacted in California
in September 1996, the California Public Utilities Commission is required to
calculate short-term avoided cost of energy for payments made to non-utility
power generators, such as the Coso partnerships, based on the clearing price
paid by the California Power Exchange when certain conditions are met. These
conditions include that (1) the California Public Utilities Commission has
issued an order determining that the California Power Exchange is "functioning
properly" and (2) either:
(a) the fossil-fired generation units owned by the purchasing utility
(such as Edison) are authorized to charge market-based rates and
the variable costs of such units are being recovered solely through
clearing prices being paid by the California Power Exchange or from
contracts with the independent system operator discussed under "--
The operations of the Coso projects could be adversely affected by
an inability to comply with regulatory standards--Changes in
California Electric Market"; or
(b) the purchasing utility has divested ninety percent of its gas-fired
generation facilities that were operated to meet load in 1994 and
1995.
For more information regarding the California Power Exchange, you should read
"--The operations of the Coso projects could be adversely affected by an
inability to comply with regulatory standards--Changes in California Electric
Market" and "Business--Power Sales--Energy Payments." Divestiture of such gas-
fired generation facilities by Edison and the other two large California
utilities is expected to be complete by the end of 1999.
It is likely that within the next two years, pursuant to AB1890, Edison's
short-term avoided cost of energy will equal the then-prevailing market
clearing price for wholesale energy at the California Power Exchange. Whether
this pricing will be on an hourly basis, a daily or block average basis
(i.e., a daily average, daily off-peak or daily on-peak time period averages)
or some other variation has not been determined. The market clearing prices for
wholesale energy on the California Power Exchange have occasionally for brief
periods exceeded current energy prices paid by Edison under the power purchase
agreements based on its short-term avoided cost of energy. This has occurred
most often during high load conditions, warm weather and other daily or
seasonal peak periods. At other times, the market clearing prices have been
lower than Edison's short-term avoided cost of energy. No one can predict the
outcome of the final implementation of this change in computing short-term
avoided cost of energy, or the performance of California Power Exchange
clearing prices over time. See "--The operations of the Coso projects could be
adversely affected by an inability to comply with regulatory standards--Changes
in California Electric Market."
In addition, under AB1890, the Navy I partnership has been eligible to
receive since 1998 subsidy payments for energy delivered by it to Edison. Going
forward, the Navy I partnership and the other Coso partnerships should at times
qualify to receive subsidy payments through 2001 for energy delivered to
Edison. Subsidy payments are made if Edison's avoided cost of energy falls
below 3.0c per kWh, subject to a maximum subsidy of 1.0c per kWh. No one can
assure you that the AB1890 fund will have funds sufficient to continue to make
their subsidy payments to the Coso partnerships through 2001. See "Business--
AB1890 Energy Subsidy Payments."
37
The Navy could terminate the Coso partnerships' rights to use the Coso
geothermal resource at any time.
Under a Geothermal Power Development Service Contract with the United States
Government acting through the United States Navy (the "Navy"), the Navy I
partnership and the Navy II partnership have exclusive contractual rights to
explore, develop and use, currently without any known interference from any
other power developers, a portion of the Coso Known Geothermal Resource Area at
and around Navy I and Navy II. We call this contract the Navy Contract. The
Navy Contract expires in December 2009, the same month and year in which the
maturity date of the Series B notes due 2009 occurs.
The Navy has the right to terminate the Navy Contract at any time for reasons
of national security, national defense preparedness or national emergency, or
for any other reasons that are in the best interests of the United States
Government. If the Navy were to terminate the Navy Contract, the United States
Government would be obligated to pay the Navy I partnership a maximum amount of
approximately $165.0 million and the Navy II partnership a maximum amount of
approximately $187.5 million, or a maximum aggregate amount of approximately
$352.5 million, to compensate it or them for the unamortized portion of their
exploratory investment and for the investment in their installed power plant
facilities. Such payment would not take into consideration the loss of
anticipated future profits resulting from such termination and may be
insufficient to enable the Coso partnerships to repay their project notes and
guarantees fully. This would materially adversely affect our ability to make
payments to you under the Series B notes. In addition, the Navy would not make
any payments to the BLM partnership, which might not be able to continue to
operate BLM and its facilities following such termination. For more
information, you should read "Summary Descriptions of Principal Agreements
Relating to the Coso Projects--The Navy Contract."
In addition to its right to terminate the Navy Contract, the Navy may, from
time to time, impose certain access and operational restrictions on all three
Coso partnerships for purposes of national security, personnel safety,
protection of property or protection of the environment, and under certain
circumstances may impose emissions standards. The Navy has periodically ordered
all personnel at the Coso projects to evacuate the plant sites and fields.
Evacuation periods have typically continued for three-to-four hours, although
the periods have continued for up to 12 hours. During such evacuation periods,
the plants must be operated via a remote station located at the outskirts of
the Navy base. This station currently utilizes rights of way obtained from the
Bureau of Land Management. These rights of way are still held by CalEnergy, and
CalEnergy has agreed to transfer them to the Coso partnerships once the consent
of the Bureau of Land Management has been obtained. No one can assure you that
this consent will be obtained. Periodic evacuations will likely recur in the
future. We cannot assure you that the Coso partnerships will always be able to
operate the plants from this remote station during evacuation periods. For more
information regarding this station, you should read "Summary Descriptions of
Principal Agreements Relating to the Coso Projects--The Navy Contract."
The Coso partnerships rely on certain contractual arrangements among them
relating to the transfer of steam among the Coso projects, which we call the
steam sharing agreement. Each of the Navy and the Bureau of Land Management has
reserved the right in its sole discretion to suspend or limit the transfer of
steam among the Coso projects under certain circumstances. See "Business--Steam
Sharing Program" and "Summary Description of Principal Agreements Relating to
the Coso Projects--Steam Sharing and Co-Tenancy Agreements."
38
Our ability to repay the Series B notes will depend on unrelated third parties
fulfilling their commitments to the Coso partnerships.
The viability of the Coso projects, the Coso partnerships' ability to make
payments under their project notes and guarantees, and our ability to make
payments of principal, premium, if any, and interest on the Series B notes when
due, may be materially and adversely affected by the performance of third
parties whom we do not control under commercial agreements to which the Coso
partnerships are parties. These third parties include, among others:
. the Navy under the Navy Contract and the steam sharing agreement;
. the Bureau of Land Management under the BLM lease, the steam sharing
agreement and the leases on which BLM North is located, which we call the
LADWP leases;
. FPL Operating under its O&M agreements; and
. Edison under the power purchase agreements.
We call these commercial agreements, together with the other documents and
agreements relating to the Coso projects, the project documents.
If any of these third parties:
. claim that there was a defect in proceedings with respect to the approval
of their project documents,
. claim that their project documents were not duly authorized by them,
. disavow their obligations under their project documents,
. fail to perform their contractual or other obligations, or
. are excused from performing their obligations because the Coso
partnerships have failed to perform theirs or because an event has
occurred outside of our or their control,
then the Coso partnerships may not be able to obtain alternate customers, goods
or services to cover these third parties' non-performance. In particular, if
Edison fails to fulfill its contractual obligations under any power purchase
agreement, it would have a material adverse effect on the Coso projects'
revenues and would materially and adversely affect the Coso partnerships'
ability to make payments under their project notes and guarantees. This would
materially and adversely affect our ability to make payments of principal,
premium, if any, and interest on the Series B notes when due.
The Coso partnerships depend on Edison's purchases of all electrical energy
generated by the plants for substantially all of their operating revenues. The
payments being made by Edison to the Navy II partnership for energy under its
power purchase agreement currently exceed Edison's actual avoided cost of
energy by a substantial margin. If this situation continues, or if Edison
experiences financial, regulatory or other pressures, Edison could try to amend
the Navy II partnership's power purchase agreement. Edison could also attempt,
as it has in the past, to terminate the power purchase agreements. The
provisions of the power purchase agreements do not permit Edison to amend or
terminate any of the agreements early without the consent of the applicable
Coso partnership, and the Indenture prohibits the Coso partnerships from giving
such consent if the effect on the holders of the senior secured notes would be
materially adverse. Nonetheless, it is possible that, upon a change in
applicable legislation, case law and/or regulations, a court or governmental
authority could order or allow such an amendment or termination of one or more
power purchase agreements. Such an
39
amendment or termination would materially and adversely affect the revenues of
the affected Coso partnership or partnerships and consequently the cash flow
available to make payments under its or their project notes and guarantees.
This would materially and adversely affect our ability to make payments to you
under the Series B notes. It would probably also constitute an event of default
under the Indenture. See "--The Coso partnerships and their managing partners
are currently involved in material litigation with Edison, their sole customer"
and "Business--Legal Proceedings."
The Coso partnerships and their managing partners are currently involved in
material litigation with Edison, their sole customer.
The Coso partnerships, the Coso partnerships' managing partners and
CalEnergy, which we collectively refer to as the Coso Parties, are involved in
an ongoing lawsuit with Edison. Edison is the Coso partnerships' sole customer.
Edison asserts a number of breach of contract claims that relate to the alleged
surreptitious venting of certain non-condensable gases from unmonitored
reinjection wells located adjacent to the plants. The Coso Parties have filed a
cross-complaint against Edison asserting, among others, breach of contract
claims, violations of state law and of decisions of the California Public
Utilities Commission and that Edison's lawsuit is barred by a settlement
agreement entered into in 1993. In addition, the Coso partnerships have filed a
separate lawsuit against Edison seeking restitution and injunctive relief for
unfair competition and false advertising. You should read "Business--Legal
Proceedings" for a more thorough discussion of the issues and claims in this
lawsuit.
No one can predict at this time whether Edison will prevail on its claims
against any or all of the Coso Parties or whether any or all of the Coso
Parties will prevail on their claims against Edison, in part because pre-trial
discovery has not been completed and in part because of the complexity of the
factual and legal issues involved. While the parties to the lawsuits have
signed a stipulation agreeing to a moratorium on all ongoing activities in the
lawsuit to explore the possibility of a negotiated settlement, no one can
assure you that the parties will be able reach a settlement or, if they do,
what the terms of that settlement would be. The moratorium was originally set
to expire on May 30, 1999. By agreement of the parties, this moratorium has
been extended to September 30, 1999, and the parties have agreed to hold a
mediation session before a former California supreme court justice during the
week of September 7, 1999.
It is possible that the parties will be unable to reach a settlement and
Edison could recover significant damages in the lawsuit. Edison has not yet
provided the Coso Parties with any calculation or estimate of its alleged
damages, but the Coso Parties expect Edison to seek damages in an amount which
would be material to the financial condition and results of operations of the
Coso partnerships, either individually or taken as a whole.
Our substantial debt and our ability to incur additional debt in the future
could adversely affect our financial health and prevent us from satisfying our
obligations under the Series B notes.
We have now and, after this exchange offer, will continue to have a
significant amount of debt and interest expense. Assuming, as of March 31,
1999, the completion of the Series A notes offering and the Coso partnerships'
use of the proceeds of the Series A notes offering, the Coso partnerships'
total aggregate debt would have been $413.0 million and partners' aggregate
capital would have been $210.4 million. This would have resulted in a total
debt to total capitalization ratio of 0.66x as of March 31, 1999.
40
Our substantial indebtedness could have important consequences to you. For
example, it could:
. make it more difficult for the Coso partnerships to make payments to
us under their project notes and for us to make payments to you under
the Series B notes;
. increase our vulnerability to general adverse economic and industry
conditions;
. limit our flexibility in planning for, or reacting to, changes in our
business and the industry in which we operate; and
. limit, along with the financial and other restrictive covenants in
our debt documents, among other things, our ability to borrow
additional funds.
In addition, failure to comply with covenants in our debt documents could
result in an event of default which, if not cured or waived, could have a
material adverse effect on us.
In addition, we and the Coso partnerships will be able to incur additional
debt from time to time in the future. The terms of the Indenture do not fully
prohibit us or the Coso partnerships from doing so. If new debt is added to our
current debt levels, the related risks that we now face could intensify. See
"Capitalization" and "Selected Historical and Pro Forma Financial and Operating
Data."
Exploring and developing geothermal resources is inherently risky.
Geothermal exploration, development and operations are subject to
uncertainties which vary among different geothermal reservoirs and are similar
to those typically associated with oil and gas exploration and development,
including unproductive wells and uncontrolled releases. The geographic area and
sustainable output thereof can only be estimated and cannot be definitively
established because of the geological complexities of geothermal reservoirs.
Consequently, the Coso partnerships could experience an unexpected decline in
the capacity of their geothermal wells, and the Coso geothermal reservoir might
not be sufficient for the sustained production of steam and electricity
throughout the maturity dates of the Series B notes.
The operations of the Coso projects could be adversely affected by the Coso
partnerships' and their operators' inability to comply with regulatory
standards.
Permitting; Environmental
The Coso partnerships and their operators are required to comply with many
federal, state and local statutory and regulatory standards and to maintain
numerous permits and governmental approvals required to operate the Coso
projects. Some of these permits and governmental approvals contain specific
conditions. Over the years, there have been numerous violations of these
permits, governmental approvals and conditions, as well as of regulations of
governmental authorities charged with enforcing these matters. If any Coso
partnership fails to satisfy applicable permits, governmental approval,
conditions or regulations, it could be prevented from operating its Coso
project and incur additional costs. No one can assure you that the Coso
partnerships and their operators will be able to operate the Coso projects in
the future in accordance with applicable permits, governmental approvals,
conditions or regulations, or that the conditions contained in these permits or
governmental approvals will not change.
In addition, the Coso partnerships usually have several applications for new
permits and governmental approvals, or renewals of existing permits and
governmental approvals, pending before certain governmental authorities. These
governmental authorities can sometimes take up to several
41
years to approve an application. No one can assure you that the Coso
partnerships will be able to obtain, renew or maintain the permits and
governmental approvals required to operate the Coso projects through the
maturity dates of the Series B notes. If any Coso partnership fails to obtain,
renew or maintain any required permit or governmental approval or is unable to
satisfy any conditions, its operations could be limited or suspended.
In addition, you can expect that the laws and regulations affecting the Coso
projects, the Coso partnerships and us will change while the Series B notes are
outstanding, and those changes could adversely affect the Coso projects, the
Coso partnerships and us. For example, changes in laws or regulations
(including, but not limited to, taxes and environmental laws) could impose more
stringent or comprehensive requirements on the operation or maintenance of the
Coso projects, resulting in increased compliance costs, the need for additional
capital expenditures or the reduction of certain benefits currently available
to the Coso projects, or could expose the Coso partnerships or us or both to
liabilities for previous actions taken in compliance with laws in effect at the
time or for actions taken by or conditions caused by third parties. In
addition, the Coso partnerships could become liable for the investigation and
removal of hazardous materials that may be found at the Coso projects, no
matter what the source of such hazardous materials. Failure to comply with any
such statutes or regulations or any change in the requirements of such statutes
or regulations could result in civil or criminal liability, imposition of
cleanup liens and fines and large expenditures to bring the Coso projects into
compliance. You should read "Business--Environmental Matters" for more
information regarding environmental requirements.
Qualifying Facility Status
PURPA provides QFs, such as the Coso projects, with certain exemptions from
federal and state law and regulation, including regulation of the rates at
which electricity can be sold. If:
. any Coso project fails to maintain its QF status,
. PURPA is repealed or amendments to PURPA are enacted that substantially
reduce the benefits currently afforded QFs, or
. the requirements for the Coso projects to maintain their status as QFs
are made more burdensome,
then, operations at the Coso projects or compliance with the terms of the power
purchase agreements could be made much more difficult. The Coso partnerships'
ability to make payments under their project notes and guarantees and our
ability to make payments to you under the Series B notes when due may be
materially and adversely affected by any of these events.
Changes in California Electric Market
The electric industry in California has changed dramatically as a result of
recent decisions by the California Public Utilities Commission and the
enactment of AB1890 in September 1996. The new California electric market
structure, including the independent system operator/power exchange system,
which we call the ISO PX system, began operations on March 31, 1998. The
California Power Exchange portion of the ISO PX system, through which Edison is
required to sell power generated by QFs, is responsible for managing the
transactions for all power auctioned through, and purchased by, market
participants except those bound by contract. The ISO portion of the ISO PX
system is responsible for scheduling, transmission access and operation of the
transmission assets formerly operated by Edison, San Diego Gas & Electric
Company and Pacific Gas & Electric
42
Company. The complex grid operation, software, forecasting, bidding and market
clearing mechanism of the ISO PX system has a limited operating history. Many
elements of the new market structure present novel regulatory issues that have
not yet been resolved, as well as many practical issues of implementation such
as the development of systems, software and procedures for the California Power
Exchange, the ISO and all of the market participants who will transact with the
ISO PX system.
If the still-developing ISO PX system fails or does not operate as
anticipated, electricity generation, transmission and distribution in
California may be materially and adversely affected. Edison's business may also
be materially and adversely affected. Furthermore, since Edison's avoided cost
of energy ultimately will be tied to the clearing price of the California Power
Exchange, the ISO PX system's functionality will have a significant effect on
the Coso partnerships.
When the California Power Exchange began operations on March 31, 1998, the
only available clearing mechanism was for day-ahead bidding. In August 1998,
the California Power Exchange began hour-ahead trading. The hour-ahead
mechanism has not operated during a full year of seasonal transitions, maximum
load conditions and other relevant factors, and the limited operating history
of the ISO PX system makes it impossible to predict how the markets or
transmission systems will perform over time with any certainty. During the
summer of 1998, spot prices "spiked" in several recently deregulated markets,
including those in California and Illinois, creating short-term situations in
which certain market participants asserted that the markets had "failed." Both
FERC and the California Public Utilities Commission are reviewing pricing
policies and market mechanisms in light of these experiences, and modifications
to the market may occur as a result.
In addition, a number of substantial issues remain undecided in California
that will require ongoing regulatory involvement by FERC and the California
Public Utilities Commission. One of these issues is the final mechanism for
local reliability contracts and pricing for ancillary services from so-called
"reliability must-run" plants, which are required to operate at certain times
and provide certain services to maintain transmission system reliability. The
Coso projects have not been designated as "reliability must-run" plants.
Furthermore, as part of the California restructuring legislation,
California's investor-owned utilities were permitted to recover certain
authorized transition costs, primarily related to above-market costs associated
with nuclear generation assets and with long-term power purchases, including
from QFs such as the Coso projects, that are currently included in the rates
paid by ratepayers, which we call stranded costs. One of these investor-owned
utilities, San Diego Gas & Electric Company, has recently announced its
intention to eliminate the majority of the charges for stranded costs. These
continuing issues, along with ongoing monitoring by FERC and the California
Public Utilities Commission of the markets and the ISO PX system, leave the
deregulated market subject to potential regulatory action and revisions, with
concomitant consequences both to Edison and to the payments received from
Edison by the Coso partnerships under their power purchase agreements. For more
information, you should read "--Future energy payments paid by Edison to the
Coso partnerships will most likely be less than historical energy payments
because they will be paid based on Edison's avoided cost of energy" and
"Regulation."
In addition to actions taken by the California Legislature and regulation by
the California Public Utilities Commission, bills have been introduced into the
United States Congress mandating the deregulation of the electric utility
industry on the state level. On April 16, 1999, the Clinton Administration's
latest restructuring plan was introduced. In general, the bills provide for
open
43
competition in the furnishing of electricity to all customers. No one can
predict whether these bills, or any future legislation relating to the
deregulation of the electric industry, will become law or, if they become law,
what their final effect will be. Changes in the existing legal structure
regulating the electric utility industry, particularly in California, will most
likely have an impact on the manner in which electricity is distributed and
payments are collected or on Edison and its business. This may affect Edison's
ability to fulfill its obligations to the Coso partnerships under the power
purchase agreements. For more information, you should read "--Our ability to
repay the Series B notes will depend on unrelated third parties fulfilling
their commitments to the Coso partnerships" and "Regulation--Energy
Regulation--California Deregulation."
Although the Coso partnerships currently maintain insurance, loss proceeds
might not be enough to satisfy our obligations under the Series B notes.
The Coso partnerships currently maintain property, business interruption,
earthquake, catastrophic and general liability insurance for the Coso projects.
If an insurable loss occurs, the proceeds of insurance will be paid to the
Depositary for the Coso partnerships' account and will be applied as required
under the Indenture and the Depositary Agreement. No one can give you any
assurance that this insurance coverage will be available in the future at
commercially reasonable costs or terms or that the amounts for which the Coso
projects are or will be insured will cover all potential losses.
As part of the Series A notes offering, the Coso partnerships obtained title
insurance policies in the aggregate amount of $200.0 million in favor of U.S.
Bank Trust National Association, which we call the Trustee. Primarily because
of the nature of the rights obtained by one or more of the Coso partnerships
from the Navy and the Bureau of Land Management, the insurance coverage
afforded by these policies is narrower, and the exceptions to coverage are
broader, than those which are commonly provided to companies that are engaged
in activities similar to those of the Coso partnerships. No one can assure you
that the title insurer or its reinsurers will be willing or able to satisfy any
claims which may be made under those policies. Also, the coverage amounts under
these policies may not be sufficient to satisfy amounts outstanding under the
senior secured notes at any given time. See "Business--Insurance."
Geothermally active areas, such as the area in which the Coso projects are
located, are subject to frequent low-level seismic disturbances. Serious
seismic disturbances in that area are possible. The Coso partnerships currently
have business interruption and property damage insurance to address certain
losses which may be caused by these disturbances. This insurance coverage
currently includes $200.0 million of earthquake insurance. This amount of
insurance coverage is substantially less than the aggregate principal amount of
the senior secured notes, and no one can assure you that seismic disturbances
of a nature and magnitude so as to cause material damage to Navy I, BLM or Navy
II, the transmission lines, wells, gathering system or other related
facilities, or a material change in the nature of the geothermal resource, will
not occur. Also, no one can assure you that insurance proceeds will be adequate
to cover all losses sustained, or that insurance will continue to be available
in the future in the amounts presently carried or other amounts adequate to
insure against losses from seismic disturbances.
44
The Trustee's ability to foreclose on the Coso partnerships' assets depends on
it being able to obtain the consents of third parties who do not have to
consent and it being able to obtain new permits and governmental approvals.
Certain assets comprising the collateral securing the senior secured notes
require the consent of third parties as a condition to their transfer or
utilization upon or following a foreclosure. Since the Coso projects are
located on Navy and Bureau of Land Management property, this would include
their consents as well. No one can give you any assurance that these third
parties will give their consents or cooperation when asked to facilitate a
transfer of assets or operating rights to the Trustee or any other person upon
or following a foreclosure. Accordingly, although the Coso partnerships'
obligations under their guarantees are secured by a pledge of all of their
ownership interests in the Coso partnerships and liens on all of the material
rights and assets of the Coso partnerships, the Trustee may not have the
ability to foreclose upon all of these pledges and liens without these consents
or, following a foreclosure, to operate or utilize such assets. Further, no one
can assure you that the Navy or the Bureau of Land Management will permit a
receiver to take control of or operate such assets pending foreclosure.
Some of the permits and governmental approvals that serve as collateral for
the senior secured notes are not transferable. In the event of a foreclosure,
the acquiror of the Coso projects would have to apply for new permits and
governmental approvals in order to continue the operations at the Coso
projects. Any delays or inability in obtaining such new permits or appeals
could reduce the proceeds available to the holders of senior secured notes in
the event of a foreclosure.
In addition, contract rights under certain project documents serve as
collateral for the senior secured notes, including rights that stem from
agreements to which the Coso partnerships are parties. If a bankruptcy case
were commenced by or against a Coso partnership, all or part of the project
documents could possibly be rejected by that Coso partnership or a trustee
appointed in a bankruptcy case pursuant to section 365 and section 1123 of the
federal bankruptcy code and, therefore, not be specifically enforceable.
The Coso projects are being managed by new managing partners and operators.
Prior to Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects on February 25, 1999, CalEnergy owned and controlled the
managing partners of the Coso partnerships and operated the Coso projects. As a
result, CalEnergy made most of the day-to-day business decisions relating to
the management and the operations of the Coso projects. Since Caithness
Acquisition purchased CalEnergy's interests in the Coso projects, Caithness
Energy has indirectly owned and controlled the managing partners of the Coso
partnerships, and FPL Operating and Coso Operating Company have been operating
the Coso projects under their respective O&M agreements. If the Coso projects
are not managed effectively, the financial health of the Coso partnerships
could be materially and adversely affected. You should read "--Our ability to
repay the Series B notes will depend on unrelated third parties fulfilling
their commitments to the Coso partnerships" and "Management" for some related
information.
Our estimates, projections and assumptions could prove to be incorrect.
In connection with the issuance of the Series A notes, we prepared certain
estimates, projections and assumptions for the revenue generation capacity of
the Coso partnerships and the associated costs, and provided them to Sandwell
Engineering Inc. and GeothermEx, Inc. Sandwell Engineering Inc. evaluated the
reasonableness of these projections in light of the technical operating
parameters of
45
the Coso projects, the operations and maintenance budgets of the Coso projects
and the related assumptions and forecasts contained therein. GeothermEx, Inc.
evaluated the reasonableness of these projections with respect to the wellfield
capital expenditures and production levels. These evaluations were based upon
an inspection and review of certain technical, environmental, economic and
regulatory aspects at the Coso projects. These projections incorporated energy
payments and AB1890 subsidy payments which were based on the energy markets
consultant's report. Sandwell Engineering Inc.'s report attached as Exhibit A
to this prospectus and GeothermEx, Inc.'s report attached as Exhibit C to this
prospectus contain some discussion of the assumptions and forecasts used in
preparing the projections, which concern the operations and maintenance budgets
of the Coso projects. We urge you to read these reports and the energy markets
consultant's report attached as Exhibit B to this prospectus. However, you
should be aware that the three consultant's reports were prepared in connection
with the Series A notes offering and have not been updated since then.
For purposes of preparing the projections, we made certain assumptions about
general business and economic conditions, such as real property and sales taxes
payable by the Coso partnerships and other persons, and about numerous other
material contingencies and matters that are not within our control or the
control of any other person and the outcome of which cannot be predicted by us
or any other person with any expectation of complete accuracy. We also made
assumptions concerning operations and maintenance costs under the applicable
O&M agreements. You should be aware that assumptions are inherently subject to
significant uncertainties, and actual results will differ, perhaps materially,
from those projected. Accordingly, the projections are not necessarily
indicative of future performance, and neither we nor the Coso partnerships
assume any responsibility for the accuracy of the projections. If, for example,
sales of revenues generated by the Coso projects from sales of electricity to
Edison decline below those assumed in the projections contained in the
independent engineer's report, this could impair the Coso partnerships' ability
to make payments under their project notes and guarantees and our ability to
make payments of principal, premium, if any, and interest on the Series B notes
when due.
We do not make, or intend to make, any representation or warranty, nor should
any representation be inferred, about the likely existence of any particular
future set of facts or circumstances, and you should not place undue reliance
on the projections, the independent engineer's report, the energy markets
consultant's report or the geothermal engineer's report. If actual results are
less favorable than those shown or if the estimates and assumptions used in
formulating the projections prove to be incorrect, each Coso partnership's
financial performance may be less favorable than that set forth in the
projections. As a consequence, the Coso partnerships' ability to make payments
under their project notes and guarantees, and our ability to make payments of
principal, premium, if any, and interest on the Series B notes when due could
be materially and adversely affected.
We prepared the projections contained in the independent engineer's report
based on our knowledge at the time of the Series A notes offering and on
certain assumptions we made. The projections have not been examined, compiled
or subjected to any procedures by either KPMG LLP or by PricewaterhouseCoopers
LLP. Accordingly, neither KPMG LLP nor PricewaterhouseCoopers LLP expresses any
opinion or other form of assurance with respect thereto. The
PricewaterhouseCoopers LLP reports included in this prospectus relate solely to
the Coso partnerships' historical financial information. The KPMG LLP report
included in this prospectus relates to an historical balance sheet as of April
22, 1999 (date of inception). Those reports do not extend to the projections
contained in the independent engineer's report and the geothermal
46
engineer's report and should not be read to do so. Neither we, Sandwell
Engineering Inc. nor GeothermEx, Inc. intend to provide to the holders of the
senior secured notes any projections or to evaluate any projections other than
the projections set forth in the independent engineer's report and the
geothermal engineer's report.
The Coso partnerships could be materially adversely affected by unanticipated
Year 2000 compliance problems.
At the end of 1999, the operations of the Coso partnerships' computer systems
could be disrupted because these systems might interpret the Year 2000 as
"1900." The Coso partnerships have been working to resolve the potential impact
of the Year 2000 issue on the processing of information in their computer
systems. No one can assure you, however, that the Coso partnerships will not
experience material disruptions in their operations as a result of Year 2000
non-compliance.
The Coso partnerships have also been working with third parties, including
Edison, to identify and assess the potential impact that this issue may have on
its relationship with these parties. If Edison fails to fulfill its contractual
obligations under the power purchase agreements because it failed to resolve
its own Year 2000 issues, it could have a material adverse effect on the Coso
partnerships' revenues and their ability to make payments under their project
notes and guarantees. While the Coso partnerships intend to continue to work
with Edison and other third parties to minimize any potential Year 2000
problems, no one can assure you that these issues will be resolved to the Coso
partnerships' satisfaction or that the Coso partnerships will not experience a
material adverse effect to their operations from unanticipated Year 2000 issues
or problems, including failure to resolve Year 2000 issues in a timely manner,
or delays or changes in the estimated time of their compliance. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Year 2000 Issue."
We may not have the funds necessary to finance a change of control offer which
may be required under the Indenture.
If certain specific kinds of change of control events occur, we will be
required under the Indenture to offer to repurchase all outstanding senior
secured notes. No one can assure you that we will have sufficient funds at the
time of a change of control to be able to make the required repurchases of the
senior secured notes, or that restrictions contained in documents governing our
other indebtedness will allow those repurchases. You should note that certain
important corporate events, such as leveraged recapitalizations that would
increase the level of our indebtedness, would not constitute a change of
control under the Indenture. See "Description of Series B Notes-- Repurchase at
the Option of Holders upon a Change of Control."
Federal and state statutes allow courts, under specific circumstances, to void
guarantees and require noteholders to return payments received from guarantors.
One or more Coso partnerships' guarantees could be voided under federal
bankruptcy law and comparable provisions of state law if the guarantees are
deemed to involve a fraudulent conveyance. Under the federal bankruptcy law and
comparable provisions of state fraudulent transfer laws, a guarantee could be
voided, or claims in respect of a guarantee could be subordinated to all other
debts of that guarantor, if, among other things, the guarantor, at the time it
incurred the indebtedness evidenced by its guarantee:
. received less than reasonably equivalent value or fair consideration for
the incurrence of such guarantee and either:
. one, was insolvent or rendered insolvent by reason of such
incurrence; or
47
. two, was engaged in a business or transaction for which the
guarantor's remaining assets constituted unreasonably small capital;
or
. three, intended to incur, or believed that it would incur, debts
beyond its ability to pay such debts as they mature.
In addition, any payment by that guarantor pursuant to its guarantee could be
voided and required to be returned to the guarantor, or to a fund for the
benefit of the creditors of the guarantor.
The measures of insolvency for purposes of these fraudulent transfer laws
will vary depending upon the law applied in any proceeding to determine whether
a fraudulent transfer has occurred. Generally, however, a guarantor would be
considered insolvent if:
. the sum of its debts, including contingent liabilities, was greater than
the fair saleable value of all of its assets; or
. if the present fair saleable value of its assets was less than the amount
that would be required to pay its probable liability on its existing
debts, including contingent liabilities, as they become absolute and
mature; or
. it could not pay its debts as they become due.
If one or more Coso partnerships' guarantees were voided, you may be required
to return payments made by the Coso partnerships to you under the guarantees.
There is no established market for the Series B notes and they will not be
listed on any securities exchange.
The Series A notes are eligible for trading in the PORTAL market. The Series
B notes are a new issue of securities with no established trading market and
will not be listed on any securities exchange. The initial purchaser of the
Series A notes has informed us that it intends to make a market in the Series B
notes. However, it may discontinue making a market at any time without notice.
The liquidity of any market for the Series B notes will depend upon the
number of holders of the Series B notes, our performance, the market for
similar securities, the interest of securities dealers in making a market in
the Series B notes and other factors. A liquid trading market may not develop
for the Series B notes.
48
THE EXCHANGE OFFER
Purpose of the Exchange Offer
The exchange offer is designed to provide holders of Series A notes with
an opportunity to acquire Series B notes which, unlike the Series A notes, will
be freely tradable at all times, subject to any restrictions on transfer
imposed by state securities or "blue sky" laws, provided that the holder is not
our "affiliate" within the meaning of the Securities Act and represents that
the Series B notes are being acquired in the ordinary course of the holder's
business and the holder is not engaged in, and does not intend to engage in, a
distribution of the Series B notes. The outstanding Series A notes in the
aggregate principal amount of $413.0 million were originally issued and sold on
May 28, 1999 to the initial purchaser. The sale of the Series A notes to the
initial purchaser was not registered under the Securities Act in reliance upon
the exemption provided by Section 4(2) of the Securities Act. The concurrent
resale of the Series A notes to investors was not registered under the
Securities Act in reliance upon the exemption provided by Rule 144A of the
Securities Act. The Series A notes may not be reoffered, resold or transferred
other than pursuant to a registration statement filed pursuant to the
Securities Act or unless an exemption from the registration requirements of the
Securities Act is available. Pursuant to Rule 144, Series A notes may generally
be resold:
. commencing one year after their original issue date, in an amount up
to, for any three-month period, the greater of 1% of the Series A
notes then outstanding or the average weekly trading volume of the
Series A notes during the four calendar weeks immediately preceding
the filing of the required notice of sale with the commission; or
. commencing two years after the original issue date, in any amount and
otherwise without restriction by a holder who is not, and has not
been for the preceding 90 days, our affiliate. The Series A notes are
eligible for trading in the PORTAL market, and may be resold to
certain qualified institutional buyers pursuant to Rule 144A. Other
exemptions may also be available under other provisions of the
federal securities laws for the resale of the Series A notes.
At the closing of the Series A notes offering, we entered into a
registration rights agreement pursuant to which we agreed to file with the
commission a registration statement covering the exchange by us of the Series B
notes for the Series A notes. The registration rights agreement provides that:
. unless the exchange offer would not be permitted by applicable law or
commission policy, we will file a registration statement with the SEC
no later than 90 days after the closing date of the Series A notes
offering,
. unless the exchange offer would not be permitted by applicable law or
commission policy, we will use our best efforts to have the
registration statement declared effective by the SEC no later than
180 days after the closing date of the Series A notes offering,
. unless the exchange offer would not be permitted by applicable law or
commission policy, we will commence the exchange offer no later than
30 business days after the date that the exchange offer registration
statement becomes effective, and
. if obligated to file a shelf registration statement covering the
Series B notes, we will use our best efforts to file the shelf
registration statement with the commission no later than 45 days
after such filing obligation arises and use our best efforts to cause
the shelf registration statement to be declared effective by the
commission on or prior to 90 days after the date we are required to
file the shelf registration statement.
49
We will pay liquidated damages to each holder of transfer restricted
notes, as described below, if any of the following occurs:
. we fail to file any of the registration statements required by the
registration rights agreement on or before the date specified for
such filing,
. the commission does not declare any of the registration statements
effective on or prior to the date specified for effectiveness,
. we fail to consummate this exchange offer within 30 business days
after the date on which the registration statement covering the
exchange of notes for Series A notes is first declared effective, or
. any registration statement filed by us pursuant to the terms of the
registration rights agreement is declared effective but thereafter,
subject to limited exceptions, ceases to be effective or usable in
connection with resales of transfer restricted notes without being
succeeded immediately by a post-effective amendment that cures such
failure.
We will pay liquidated damages to each holder of transfer restricted
notes, with respect to the first 90-day period immediately following the
occurrence of the first such default in an amount equal to $.05 per week per
$1,000 principal amount of Series A notes. The amount of liquidated damages
will increase by an additional $.05 per week per $1,000 principal amount of
Series A notes with respect to each subsequent 90-day period, or portion
thereof, until all defaults have been cured, up to a maximum amount of
liquidated damages for all defaults of $.25 per week per $1,000 principal
amount of Series A notes. "Transfer restricted notes" means each Series A note
until the earliest to occur of:
. the date on which such Series A note has been exchanged by a person
other than a broker-dealer for a Series B note in the exchange offer,
. following the exchange by a restricted broker-dealer in the offering
of a Series B note for a Series A note, the date on which the Series
B note is sold to a purchaser who receives from such restricted
broker-dealer on or prior to the date of said sale, a copy of this
prospectus,
. the date on which the Series A note has been effectively registered
under the Securities Act and disposed of in accordance with the shelf
registration statement, or
. the date on which the Series A note is distributed to the public
pursuant to Rule 144(k) under the Securities Act.
The staff of the SEC has issued certain interpretive letters that
concluded, in circumstances similar to those contemplated by this exchange
offer, that new debt securities issued in a registered exchange for outstanding
debt securities, which new securities are intended to be substantially
identical to the securities for which they are exchanged, may be offered for
resale, resold and otherwise transferred by a holder thereof, other than a
broker-dealer who purchases such securities from the issuer to resell pursuant
to Rule 144A or any other available exemption under the Securities Act or a
person who is an affiliate of the issuer within the meaning of Rule 405 under
the Securities Act, without compliance with the registration and prospectus
delivery provision of the Securities Act; provided that the new securities are
acquired in the ordinary course of such holder's business and such holder has
no arrangement with any person to participate in the distribution of the new
securities. However, a broker-dealer who holds outstanding debt securities that
were acquired for its own account as a result of market-making or other trading
activities may be deemed to be an
50
"underwriter" within the meaning of the Securities Act and must, therefore,
deliver a prospectus meeting the requirements of the Securities Act in
connection with any resales of the new securities received by the broker-dealer
in any such exchange. See "--Resales of Notes."
We have not requested or obtained an interpretive letter from the SEC
staff with respect to this exchange offer. Neither the holders of Series A
notes nor we are entitled to rely on interpretive advice provided by the staff
to other persons, which advice was based on the facts and conditions
represented in such letters. However, this exchange offer is being conducted in
a manner intended to be consistent with the facts and conditions represented in
such letters. If any holder of Series A notes has any arrangement or
understanding with respect to the distribution of the Series B notes to be
acquired pursuant to this exchange offer, such holder:
. may not rely on the applicable interpretations of the SEC's the
staff; and
. must comply with the registration and prospectus delivery
requirements of the Securities Act in connection with any resale
transaction.
In addition, each broker-dealer that receives Series B notes for its own
account in exchange for Series A notes, where such Series A notes were acquired
by such broker-dealer as a result of market-making activities or other trading
activities, must acknowledge that it will deliver a prospectus in connection
with any resale of such Series B notes. See "Plan of Distribution." By
delivering the letter of transmittal, you will represent and warrant to us that
you are acquiring the Series B notes in the ordinary course of your business
and that your are not engaged in, and do not intend to engage in, a
distribution of the Series B notes. If you are using this exchange offer to
participate in a distribution of the Series B notes, you must comply with the
registration and prospectus delivery requirements of the Securities Act in
connection with a secondary resale transaction. If you do not exchange your
Series A notes pursuant to this exchange offer, you will continue to hold
Series A notes that are subject to restrictions on transfer. See "Risk
Factors--Your failure to exchange your Series A notes for Series B notes could
have advance consequences to you."
It is expected that the Series B notes will be freely transferable by the
holders thereof, subject to the limitations described in the immediately
preceding paragraph. Sales of Series B notes acquired in this exchange offer by
holders who are our "affiliates" within the meaning of the Securities Act will
be subject to certain limitations on resale under Rule 144 of the Securities
Act. Such persons will only be entitled to sell Series B notes in compliance
with the volume limitations set forth in Rule 144, and sales of Series B notes
by affiliates will be subject to certain Rule 144 requirements as to the manner
of sale, notice and the availability of our current public information. The
foregoing is a summary only of Rule 144 as it may apply to our affiliates. If
you are an affiliate, you must consult your own legal counsel for advice as to
any restrictions that might apply to the resale of your Series B notes.
The Series B notes otherwise will be substantially identical in all
material respects, including interest rate, maturity, security and restrictive
covenants, to the Series A notes for which they may be exchanged pursuant to
this exchange offer.
Terms of the Exchange Offer
Upon the terms and subject to the conditions set forth in this prospectus
and in the accompanying letter of transmittal, we will exchange $1,000
principal amount of Series B notes due 2001 for each $1,000 principal amount of
our outstanding Series A notes due 2001, and $1,000 principal amount of Series
B notes due 2009 for each $1,000 principal amount of Series B notes due
51
2009. Only Series B notes due 2001 may be exchanged for tendered Series A notes
due 2001, and only Series B notes due 2009 may be exchanged for tendered Series
A notes due 2009. Series B notes will be issued only in integral multiplies of
$1,000 to each tendering holder of Series A notes whose Series A notes are
accepted in this exchange offer.
The Series B notes will bear interest from and including the original
issue date of the Series A notes. Accordingly, if you receive Series B notes in
exchange for your tendered Series A notes, you will forego accrued but unpaid
interest on your exchanged Series A notes for the period from and including the
issue date of the Series A notes to the date of their exchange for Series B
notes, but will be entitled to such interest under the Series B notes.
As of 1999, $110.0 million aggregate principal amount of Series A
notes due 2001 were outstanding and $303.0 million aggregate principal amount
of Series A notes due 2009 were outstanding. This prospectus and the letter of
transmittal are being sent to all registered holders of Series A notes as of
that date. You will not be required to pay brokerage commissions or fees or,
subject to the instructions in the letter of transmittal, transfer taxes with
respect to your exchange of Series A notes pursuant to this exchange offer. We
will pay all charges and expenses, other than certain transfer taxes which may
be imposed, in connection with this exchange offer. See "--Payment of Expenses"
below.
As a holder of Series A notes, you do not have any appraisal or
dissenters' rights under the Delaware General Corporation Law in connection
with this exchange offer.
Expiration Date; Extensions; Termination
This exchange offer will expire at 5:00 P.M., New York City time, on
, 1999 subject to our extension by notice to U.S. Bank Trust National
Association, N.A., the exchange agent. We reserve the right to extend this
exchange offer in our discretion, in which event the expiration date will be
the time and date on which this exchange offer as so extended shall expire. We
will notify the exchange agent of any extension by oral or written notice and
shall mail to you an announcement thereof, each prior to 9:00 A.M., New York
City time, on the next business day after the previously scheduled expiration
date.
We reserve the right to extend or terminate this exchange offer and not
accept for exchange any Series A notes if any of the events set forth below
under "--Conditions to the Exchange Offer" occur and are not waived by us, by
giving oral or written notice of such delay or termination to the exchange
agent. See "--Conditions to the Exchange Offer." The rights we reserve in this
paragraph are in addition to our rights set forth below under the caption "--
Conditions to the Exchange Offer."
Procedures for Tendering
Your tender of Series A notes pursuant to one of the procedures set forth
below and our acceptance will constitute an agreement between you and us in
accordance with the terms and subject to the conditions set forth in this
prospectus and in the letter of transmittal.
52
Except as set forth below, if you wish to tender your Series A notes for
exchange pursuant to this exchange offer, you must transmit a properly
completed and duly signed letter of transmittal, including all other documents
required by such letter of transmittal, to the exchange agent at the address
set forth below under "--Exchange Agent" on or prior to the expiration date. In
addition, either:
. certificates for such Series A notes must be received by the exchange
agent along with the letter of transmittal; or
. a timely confirmation of a book-entry transfer of such Series A
notes, if such procedure is available, into the exchange agent's
account at DTC pursuant to the procedure of book-entry transfer
described below, must be received by the exchange agent prior to the
expiration date; or
. you must comply with the guaranteed delivery procedures described
below. Letters of transmittal and Series A notes should not be sent
to us. We are not asking you for a proxy and you are requested not to
send us a proxy.
Signatures on a letter of transmittal must be guaranteed unless the
Series A notes tendered pursuant thereto are tendered:
. by a registered holder of Series A notes who has not completed the
box entitled "Special Issuance and Delivery Instructions" on the
letter of transmittal, or
. for the account of any firm that is a member of a registered national
securities exchange or a member of the National Association of
Securities Dealers, Inc. or a commercial bank or trust company having
an office in the United States, sometimes referred to as an eligible
institution.
In the event that signatures on a letter of transmittal are required to be
guaranteed, such guarantee must be by an eligible institution.
Your method of delivery of Series A notes and other documents to the
exchange agent is at your election and risk, but if delivery is by mail, we
suggest that the mailing be made sufficiently in advance of the expiration date
to permit delivery to the exchange agent before the expiration date.
If the letter of transmittal is signed by a person other than a
registered holder of any Series A note tendered therewith, such Series A note
must be endorsed or accompanied by appropriate bond powers, in either case
signed exactly as the name or names of the registered holder or holders appear
on the Series A note.
If the letter of transmittal or any Series A notes or bond powers are
signed by trustees, executors, administrators, guardians, attorneys-in-fact,
officers of corporations or others acting in a fiduciary or representative
capacity, such persons should so indicate when signing, and, unless waived by
us, you must submit proper evidence satisfactory of their authority to so act.
We will resolve all questions as to the validity, form, eligibility,
including time of receipt, and acceptance of tendered Series A notes, which
determination will be final and binding. We reserve the absolute right to
reject any or all tenders that are not in proper form or the acceptance of
which would, in the opinion of our counsel be unlawful. We also reserve the
right to waive any irregularities or conditions of tender as to particular
Series A notes. Our interpretation of the terms and conditions of this exchange
offer, including the instructions in the letter of transmittal, will be
53
final and binding. Unless waived, any irregularities in connection with tenders
must be cured within such time as we shall determine. Neither the exchange
agent nor we are under any duty to give notification of defects in such tenders
or shall incur liabilities for failure to give such notification. Tenders of
Series A notes will not be deemed to have been made until such irregularities
have been cured or waived. Any Series A notes received by the exchange agent
that are not properly tendered and as to which the irregularities have not been
cured or waived will be returned by the exchange agent to the tendering holder,
unless otherwise provided in the letter of transmittal, as soon as practicable
following the expiration date.
Our acceptance for exchange of Series A notes tendered pursuant to this
exchange offer will constitute a binding agreement between the tendering person
and us upon the terms and subject to the conditions of this exchange offer.
Guaranteed Delivery Procedures
If you wish to tender your Series A notes and your Series A notes are not
immediately available or you cannot deliver your Series A notes, the letter of
transmittal or any other required documents to the exchange agent prior to the
expiration date, you may effect a tender if:
. your tender is made through an eligible institution;
. prior to the expiration date, the exchange agent receives from such
eligible institution a properly completed and duly executed notice of
guaranteed delivery by facsimile transmission, mail or hand delivery
setting forth your name and address, the certificate number or
numbers of your tendered Series A notes and the principal amount of
your Series A notes tendered, stating that the tender is being made
thereby and guaranteeing that, within five New York Stock Exchange
trading days after the expiration date, the letter of transmittal or
facsimile thereof together with the certificate(s) representing the
Series A notes, or a book-entry confirmation, as the case may be, and
any other documents required by the letter of transmittal will be
deposited by the eligible institution with the exchange agent within
five New York Stock Exchange trading days after the expiration date;
and
. such properly completed and executed letter of transmittal or
facsimile thereof, as well as the certificate(s) representing all
your tendered Series A notes in proper form for transfer, or a book-
entry confirmation, as the case may be, and all other documents
required by the letter of transmittal are received by the exchange
agent within five New York Stock Exchange trading days after the
expiration date.
Upon request of the exchange agent, a notice of guaranteed delivery will
be sent to you if you wish to tender your Series A notes according to the
guaranteed delivery procedures set forth above.
Conditions to the Exchange Offer
Notwithstanding any other provisions of this exchange offer, or any
extension of this exchange offer, we will not be required to issue Series B
notes in respect of any properly tendered Series A notes not previously
accepted, and may terminate this exchange offer by oral or written notice to
the exchange agent and the holders, or at our option, modify or otherwise amend
this
54
exchange offer, if any material change occurs that is likely to affect this
exchange offer, including, but not limited to, the following:
. there shall be instituted or threatened any action or proceeding
before any court or governmental agency challenging this exchange
offer or otherwise directly or indirectly relating to this exchange
offer or otherwise affecting us;
. there shall occur any development in any pending action or proceeding
that, in our sole judgment, would or might have an adverse effect on
our business, prohibit, restrict or delay consummation of this
exchange offer, or impair the contemplated benefits of this exchange
offer;
. any statute, rule or regulation shall have been proposed or enacted,
or any action shall have been taken by any governmental authority
which, in our sole judgment, would or might have an adverse effect on
our business, prohibit, restrict or delay consummation of this offer,
or impair the contemplated benefits of this exchange offer; or
. there exists, in our sole judgment, any actual or threatened legal
impediment including a default or prospective default under an
agreement, indenture or other instrument or obligation to which we
are a party or by which we are bound to the consummation of the
transactions contemplated by this exchange offer.
We expressly reserve the right to terminate this exchange offer and not
accept for exchange any Series A notes upon the occurrence of any of the
foregoing conditions. In addition, we may amend this exchange offer at any time
prior to 5:00 P.M., New York City time, on the expiration date if any of the
conditions set forth above occur. Moreover, regardless of whether any of such
conditions has occurred, we may amend the exchange offer in any manner which,
in our good faith judgment, is advantageous to you.
The foregoing conditions are for our sole benefit and may be waived by
us, in whole or in part, in our sole discretion. Any determination we make
concerning an event, development or circumstance described or referred to above
will be final and binding on all parties.
Acceptance of Series A Notes for Exchange; Delivery of Series B Notes
Upon the terms and subject to the conditions of this exchange offer, we
will accept all Series A notes validly tendered prior to 5:00 P.M., New York
City time, on the expiration date. We will deliver Series B notes in exchange
for Series A notes promptly following the expiration date.
For purposes of this exchange offer, we shall be deemed to have accepted
validly tendered Series A notes when, as and if we have given oral or written
notice thereof to the exchange agent. The exchange agent will act as agent for
the tendering holders for the purpose of receiving the Series A notes. Under no
circumstances will interest be paid by us or the exchange agent by reason of
any delay in making such payment or delivery.
If any tendered Series A notes are not accepted for exchange because of
an invalid tender, the occurrence of certain other events set forth herein or
otherwise, any such unaccepted Series A notes will be returned, at our expense,
to you as promptly as practicable after the expiration or termination of this
exchange offer.
55
Withdrawal Rights
Your tenders of Series A notes may be withdrawn at any time prior to the
expiration date.
For a withdrawal to be effective, a written notice of withdrawal must be
received by the exchange agent at the address set forth below under "--
Exchange Agent." Any notice of withdrawal must specify the name of the person
having tendered the Series A notes to be withdrawn, identify the Series A
notes to be withdrawn, including the principal amount of such Series A notes,
and, where certificates for Series A notes have been transmitted, specify the
name in which such Series A notes are registered, if different from that of
the withdrawing holder. If certificates for Series A notes have been delivered
or otherwise identified to the exchange agent, then, prior to the release of
such certificates, the withdrawing holder must also submit the serial numbers
of the particular certificates to be withdrawn and a signed notice of
withdrawal with signatures guaranteed by an eligible institution unless such
holder is an eligible institution. If Series A notes have been tendered
pursuant to the procedure for book-entry transfer described above, any notice
of withdrawal must specify the name and number of the account at DTC to be
credited with the withdrawn Series A notes and otherwise comply with the
procedures of such facility. We will determine all questions as to the
validity, form and eligibility, including time of receipt, of such notices
which determination shall be final and binding on all parties.
Any Series A notes so withdrawn will be deemed not to have been validly
tendered for exchange for purposes of this exchange offer. Any Series A notes
which have been tendered for exchange but which are not exchanged for any
reason will be returned to the holder thereof without cost to such holder, or,
in the case of Series A notes tendered by book-entry transfer into the
exchange agent's account at DTC pursuant to the book-entry transfer procedures
described above, such Series A notes will be credited to an account maintained
with DTC for the Series A notes, as soon as practicable after withdrawal,
rejection of tender or termination of the exchange offer. Properly withdrawn
Series A notes may be retendered by following one of the procedures described
under "--Procedures for Tendering" above at any time on or prior to the
expiration date.
Material Federal Income Tax Consequences
The following discussion summarizing the material federal income tax
consequences of this exchange offer. This discussion is not binding on the
Internal Revenue Service or the courts, and we cannot assure you that the IRS
will not take, and that a court would not sustain, a position contrary to that
described below. Moreover, the following discussion is for general information
only and does not constitute comprehensive tax advice to any particular holder
of Series A notes. This summary is based on the current provisions of the
Internal Revenue Code of 1986, as amended, and applicable Treasury
regulations, judicial authority and administrative pronouncements. The tax
consequences described below could be modified by future changes in the
relevant law, which could have retroactive effect. You should consult your own
tax adviser as to these and any other federal income tax consequences of this
offer as well as any tax consequences to it under foreign, state, local or
other law.
Exchanges of Series A notes for Series B notes pursuant to this exchange
offer should be treated as a modification of the Series A notes that does not
constitute a material change in their terms, and we intend to treat the
exchanges in that manner. Under that approach, a Series B note is treated as a
continuation of the corresponding Series A note. An exchanging holder's
holding period for a Series B note would include the holder's holding period
for the Series A note. The holder
56
would not recognize any gain or loss, and the holder's basis in the Series B
note would be the same as such holder's basis in the Series A note. This
exchange offer will result in no federal income tax consequences to a non-
exchanging holder. See "Material Federal Income Tax Considerations of the
Exchange Offer."
Exchange Agent
U.S. Bank Trust National Association has been appointed as exchange agent
for this exchange offer. All correspondence in connection with this exchange
offer and the letter of transmittal should be addressed to the exchange agent
as follows:
To: U.S. Bank Trust National Association
By Registered or Certified By Overnight Delivery or
Mail: By Hand: Courier:
U.S. Bank Trust National U.S. Bank Trust U.S. Bank Trust National
Association National Association Association
180 East Fifth Street 180 East Fifth Street 180 East Fifth Street
St. Paul, MN 55101 St. Paul, MN 55101 St. Paul, MN 55101
Attention:
4th Floor Bond Drop Window
Facsimile Transmission Number:
(For Eligible Institutions Only)
(651) 244-1537
Confirm by Telephone:
Bondholder Communications
(800) 934-6802
You may request additional copies of this prospectus or the letter of
transmittal from the exchange agent or us.
Payment of Expenses
We have not retained any dealer-manager or similar agent in connection
with this exchange offer and will not make any payments to brokers, dealers or
others for soliciting acceptances of this exchange offer. We, however, will pay
reasonable and customary fees and reasonable out-of-pocket expenses to the
exchange agent in connection with the solicitation of acceptances. We will also
pay the cash expenses to be incurred in connection with this exchange offer,
including accounting, legal, printing, and related fees and expenses.
Accounting Treatment
The Series B notes will be recorded at the same carrying value as the
Series A notes, as reflected in our accounting records on the date of the
exchange. Accordingly, no gain or loss for accounting purposes will be
recognized. Our expenses of this exchange offer will be capitalized for
accounting purposes.
Resales of Notes
For resales of Series B notes, based on certain interpretive letters
issued by the staff of the SEC to unrelated third parties, we believe that a
holder of Series B notes who exchanges Series A notes for Series B notes in the
ordinary course of business and who is not participating, does not intend to
participate, and has no arrangement or understanding with any person to
participate, in a distribution of the Series B notes, will be allowed to resell
the Series B notes to the public without
57
further registration under the Securities Act and without delivering to the
purchasers of the Series B notes a prospectus that satisfies the requirements
of the Securities Act, except for:
. a broker-dealer who purchases Series B notes directly from us to
resell pursuant to Rule 144A or any other available exemption under
the Securities Act, or
. a person who is our "affiliate" within the meaning of Rule 405 under
the Securities Act.
However, a broker-dealer who holds Series A notes that were acquired for
its own account as a result of market-making or other trading activities may be
deemed to be an underwriter within the meaning of the Securities Act and must,
therefore, deliver a prospectus meeting the requirements of the Securities Act.
If any other holder is deemed to be an underwriter within the meaning of the
Securities Act or acquires Series B notes in this exchange offer for the
purpose of distributing or participating in a distribution of the Series B
notes, such holder must comply with the registration and prospectus delivery
requirements of the Securities Act in connection with a secondary resale
transaction, unless an exemption from registration is otherwise available. We
have agreed that for a period of 180 days from the expiration date, we will
make this prospectus, as amended or supplemented, available to any broker-
dealer for use in connection with any such resale.
58
CAPITALIZATION
Because we were only recently formed, we have no historical balance sheet or
capitalization as of March 31, 1999. The following tables set forth, as of
March 31, 1999, the cash and cash equivalents, long-term debt and
capitalization of (1) each Coso partnership on a stand-alone basis, on an
historical basis and as adjusted to give effect to (a) the completion of the
Series A notes offering and the application of the proceeds therefrom and (b)
certain related adjustments, as if the Series A notes offering had occurred on
March 31, 1999, and (2) the Coso partnerships on a combined basis, as adjusted
to give effect to the foregoing transactions as if such transactions had
occurred on March 31, 1999. This table should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the financial statements, including the related notes thereto,
found elsewhere in this prospectus.
As of
March 31, 1999
--------------------
(In thousands)
Actual As Adjusted
Capitalization of the Navy I Partnership (stand-alone)(a)
Cash...................................................... $ 6,397 $ --
Restricted cash and investments(b)........................ 7,808 26,155
======== ========
Project loans:
Existing project debt, payable to Coso Funding Corp..... $ 40,566 $ --
Project notes, payable to Funding Corp.................. -- 151,550
Acquisition debt(c)....................................... 77,610 --
-------- --------
Total debt.............................................. 118,176 151,550
Partners' capital......................................... 66,763 49,043
-------- --------
Total capitalization.................................... $184,939 $200,593
======== ========
Capitalization of the BLM Partnership (stand-alone)
Cash...................................................... $ 17,015 $ --
Restricted cash and investments........................... 247 13,310
======== ========
Project loans:
Existing project debt, payable to Coso Funding Corp..... $ 37,958 $ --
Project notes, payable to Funding Corp.................. -- 107,900
Acquisition debt(c)....................................... 55,256 --
-------- --------
Total debt.............................................. 93,214 107,900
Partners' capital......................................... 105,606 89,800
-------- --------
Total capitalization.................................... $198,820 $197,700
======== ========
Capitalization of the Navy II Partnership (stand-alone)
Cash...................................................... $ 20,039 $ --
Restricted cash and investments........................... -- 18,590
======== ========
Project loans:
Existing project debt, payable to Coso Funding Corp..... $ 61,323 $ --
Project notes, payable to Funding Corp.................. -- 153,550
Acquisition debt(c)....................................... 78,634 --
-------- --------
Total debt.............................................. 139,957 153,550
Partners' capital......................................... 82,392 71,527
-------- --------
Total capitalization.................................... $222,349 $225,077
======== ========
59
March 31, 1999
--------------------
(in thousands)
Actual As Adjusted
Capitalization of the Navy I Partnership, BLM Partnership
and Navy II Partnership (combined)(d)
Cash..................................................... $ 43,451 $ --
Restricted cash and investments.......................... 8,055 58,055
======== ========
Project loans:
Existing project debt, payable to Coso Funding Corp.... $139,847 $ --
Project notes, payable to Funding Corp................. -- 413,000
Acquisition debt(c)...................................... 211,500 --
-------- --------
Total debt............................................. 351,347 413,000
Partners' capital........................................ 254,761 210,370
-------- --------
Total capitalization................................... $606,108 $623,370
======== ========
- ---------------------
(a) Reflects the combined capitalization of the Navy I partnership and CFP II.
The Navy I partnership and CFP II were first formed as separate entities to
facilitate the initial bank financing for the construction and development
of Navy I. Initially, the Navy I partnership acquired all of the assets
relating to the first turbine generator unit at Navy I and CFP II acquired
all of the assets of Navy I relating to the second and third generator
units at Navy I. In 1988, CFP II assigned all of its rights and interests
in the second and third generator units at Navy I to the Navy I partnership
in return for a 5.0% royalty to be paid based on the Navy I partnership's
steam production. Since the Navy I partnership and CFP II operate under
common ownership and management control, the historical financial
statements of the entities have been combined after elimination of
intercompany amounts related to the royalty arrangement. At the closing of
the Series A notes offering, CFP II was merged with and into the Navy I
partnership and the accrued royalty was extinguished. In addition, the
royalty will no longer accrue from and after the closing of the Series A
notes offering. See Note 1 to Notes to Combining and Combined Financial
Statements of Coso Finance Partners and Coso Finance Partners II.
(b) Includes funds on deposit in the sinking fund established for the benefit
of the Navy. See "Business--Royalty and Revenue-Sharing Arrangements--Navy
I."
(c) In order to complete the purchase of all of CalEnergy's interests in the
Coso projects, Caithness Acquisition arranged for short-term debt financing
in the principal amount of approximately $211.5 million. Caithness
Acquisition used a portion of the proceeds from the Series A notes offering
that it received from the Coso partnerships, together with funds from other
sources, to repay all amounts owed under this short-term debt facility. As
a result of "push down" accounting, a portion of this short-term debt has
been reflected in the capitalization of each Coso partnership on a stand-
alone basis, and the entire amount of this short-term debt has been
reflected in the combined capitalization of the Coso partnerships.
(d) Reflects the mathematical summation of the Coso partnerships on a combined
basis as of March 31, 1999. These combined amounts are unaudited. The
combined presentation does not necessarily reflect the financial position
that would have occurred had the Coso partnerships constituted a single
entity as of March 31, 1999. Because the Coso partnerships are under common
management and are jointly and severally guaranteeing all of Funding
Corp.'s obligations under the Indenture and the senior secured notes, such
guarantees being secured by (1) a perfected, first priority lien on
substantially all of the assets of the Coso partnerships and (2) a
perfected, first priority pledge of all of the ownership interests in the
Coso partnerships, the combined financial information of the Coso
partnerships has been presented.
60
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA
The following tables set forth selected historical financial and operating
data for each of the Coso partnerships on a stand-alone basis as of and for the
periods presented. The selected historical financial data for each of the five
years ended December 31, 1998, is derived from the audited financial statements
of each of the Coso partnerships. The financial and operating data presented
below should be read in conjunction with the financial statements of the Coso
partnerships, including the related notes thereto, "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the other
financial information found elsewhere in this prospectus.
The selected historical financial and operating data for the three months
ended March 31, 1998 and 1999 is unaudited. The unaudited statement of
operations data and balance sheet data as of and for the three months ended
March 31, 1998 and the unaudited statement of operations data for the two
months ended February 28, 1999, have been prepared on the same basis as the
audited financial statements included elsewhere in this prospectus. The
unaudited statement of operations data and balance sheet data as of and for the
one month ended March 31, 1999, has been prepared on a new basis of accounting
adopted by the Coso partnerships after Caithness Acquisition purchased all of
CalEnergy's interests in the Coso projects. In the opinion of management, the
unaudited financial data contains all adjustments, consisting only of normally
recurring adjustments, necessary for a fair presentation of such financial
presentation. The unaudited financial information set forth below is not
necessarily indicative of results to be expected for any future periods.
The energy revenues received by the Coso partnerships during the five-year
period ended December 31, 1998 and the three month periods ended March 31, 1998
and 1999, as reflected in the tables below, should not be viewed as an
indicator of energy revenues to be received by the Coso partnerships during any
future periods. During the periods reflected in the tables below, Edison made
energy payments to the Coso partnerships based on the fixed energy prices
provided for in the power purchase agreements, except that, since August 1997,
Edison has been making energy payments to the Navy I partnership based on
Edison's avoided cost of energy and, in March 1999, Edison began making
payments to the BLM partnership based on Edison's avoided cost of energy.
Edison's avoided cost of energy has been and is expected to be in the future
substantially lower than the fixed energy prices received by the Coso
partnerships in the past. Once the fixed energy price period for the Navy II
partnership expires, Edison is also expected to make energy payments to the
Navy II partnership based on Edison's avoided cost of energy. See "Risk
Factors--Future energy payments paid by Edison to the Coso partnerships will
most likely be less than historical energy payments because they will be paid
based on Edison's avoided cost of energy" and "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
61
Navy I Partnership(a)
Three Months Ended March 31, 1999
------------------------------------
Two Months
Three Months Ended One Month
Year Ended December 31, Ended February 28, Ended
------------------------------------------------ March 31, 1999 March 31, 1999
1994 1995 1996 1997 1998 1998 (prior basis) (new basis)(c) Total
(In thousands, except ratio data)
Statement of
Operations Data:
Energy revenues... $ 87,233 $92,797 $103,940 $ 86,586(b) $39,580(b) $ 9,993 $8,098 $4,399 $12,497
Capacity
revenues(d)...... 14,258 14,266 14,266 13,845 13,573 813 474 237 711
Interest and other
income........... 2,529 2,893 3,286 1,980 585 136 824 827 1,651
-------- ------- -------- -------- ------- ------- ------ ------ -------
Total revenues... 104,020 109,956 121,492 102,411 53,738 10,942 9,396 5,463 14,859
-------- ------- -------- -------- ------- ------- ------ ------ -------
Plant operations.. 14,007 13,565 11,763 11,329 13,298 3,571 3,125 1,458 4,583
Royalty expense... 10,396 10,810 11,059 9,849 6,824 895 987 451 1,438
Depreciation and
amortization..... 12,109 12,770 13,325 12,814 11,772 2,957 1,604 783 2,387
-------- ------- -------- -------- ------- ------- ------ ------ -------
Total cost of
operations...... 36,512 37,145 36,147 33,992 31,894 7,423 5,716 2,692 8,408
-------- ------- -------- -------- ------- ------- ------ ------ -------
Operating income.. 67,508 72,811 85,345 68,419 21,844 3,519 3,680 2,771 6,451
Interest expense.. 12,991 11,356 8,868 6,260 4,333 1,124 663 1,630 2,293
Cumulative effect
of accounting
change........... -- -- -- -- 923 -- -- -- --
-------- ------- -------- -------- ------- ------- ------ ------ -------
Net income........ $ 54,517 $61,455 $ 76,477 $ 62,159 $16,588 $ 2,395 $3,017 $1,141 $ 4,158
======== ======= ======== ======== ======= ======= ====== ====== =======
Ratio of earnings
to fixed
charges(e)....... 5.2x 6.4x 9.6x 10.9x 5.0x 3.1x 5.6x 1.7x(g) 2.8x
As of December 31, As of As of
-------------------------------------------- March 31, March 31,
1994 1995 1996 1997 1998 1998 1999
(In thousands)
Balance Sheet Data:
Cash--unrestricted.... $ 38,669 $ 45,093 $ 15,724 $ 2,888 $ -- $ 10,560 $ 6,397
Cash and investments--
restricted........... 27,204 28,161 29,016 6,479 7,524 6,731 7,808
Total assets.......... 298,684 301,436 264,209 209,390 201,888 213,639 198,326
Acquisition debt(f)... -- -- -- -- -- -- 77,610
Project loan.......... 154,432 127,340 76,056 45,666 40,566 45,666 40,566
Total liabilities..... 166,804 136,855 96,375 53,822 51,955 55,021 131,563
Total partners'
capital.............. 131,880 164,581 167,834 155,568 149,933 158,618 66,763
- --------------------
(a) Reflects the combined financial results of the Navy I partnership and CFP
II. The Navy I partnership and CFP II were first formed as separate
entities to facilitate the initial bank financing for the construction and
development of Navy I. Initially, the Navy I partnership acquired the
assets of Navy I as they related to first turbine generator unit at Navy I
and CFP II acquired the assets of Navy I as they related to the second and
third generator units at Navy I. In 1988, CFP II assigned all of its rights
and interests in the second and third generator units at Navy I to the
Navy I partnership in return for a 5.0% royalty based on the Navy I
partnership's steam production. Since the Navy I partnership and CFP II
operate under common ownership and management control, the historical
financial statements of the entities have been combined after elimination
of intercompany amounts related to the royalty arrangement. At the Series A
notes closing, CFP II merged with and into the Navy I partnership and the
accrued royalty was extinguished. In addition, the royalty will no longer
accrue from and after the closing of the Series A notes offering. See Note
1 to Notes to Combining and Combined Financial Statements of Coso Finance
Partners and Coso Finance Partners II.
(b) The decrease in energy revenues is due to the fact that Edison paid the
Navy I partnership energy payments based on its position that the fixed
energy period expired in August 1997. Edison has also taken the position
that the fixed energy price period for the BLM partnership expired in March
1999 and will expire for the Navy II partnership in January 2000. The Coso
partnerships believe that under the power purchase agreements each of the
three turbine generator units at each Coso project has its own ten-year
fixed energy price period. This issue is one of several currently in
dispute and subject to an ongoing lawsuit between, among others, the Coso
partnerships and Edison. See "Business--Legal Proceedings."
(c) After Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso partnerships adopted a new basis of accounting.
The purchase price was allocated to the portion of the assets and
liabilities purchased from CalEnergy based on their fair values, with the
amount of fair value of net assets in excess of the purchase price being
allocated to long-lived assets on a pro-rata basis.
62
(d) Includes capacity payments and capacity bonus payments paid to the Navy I
partnership under its power purchase agreement.
(e) For purposes of computing the ratio of earnings to fixed charges, fixed
charges consist of interest expense and amortization of debt issuance
costs. Earnings used in computing the ratio of earnings to fixed charges
consist of net income plus fixed charges.
(f) In order to complete the purchase of all of CalEnergy's interests in the
Coso projects, Caithness Acquisition arranged for short-term debt financing
in the principal amount of approximately $211.5 million. Caithness
Acquisition used a portion of the proceeds from the Series A notes offering
that it received from the Coso partnerships, together with funds from other
sources, to repay all amounts owed under this short-term debt facility. As
a result of "push down" accounting, the short-term debt has been reflected
in the financial statements of the Coso partnerships, and a portion thereof
was allocated to the Navy I partnership in the amount of $77.6 million.
(g) The decrease in the ratio of earnings to fixed charges for the one month
ended March 31, 1999 is primarily due to the amortization of debt issuance
costs of approximately $2.0 million related to the short-term debt
financing associated with Caithness Acquisition's purchase of all of
CalEnergy's interests in the Coso projects over the three-month estimated
life of the short-term debt.
63
BLM Partnership
Three Months Ended March 31, 1999
------------------------------------
Two Months
Three Months Ended One Month
Year Ended December 31, Ended February 28, Ended March
----------------------------------------------- March 31, 1999 31, 1999
1994 1995 1996 1997 1998 1998 (prior basis) (new basis)(b) Total
(In thousands, except ratio data)
Statement of Operations
Data:
Energy revenues........ $76,134 $ 86,596 $ 87,985 $ 88,929 $ 93,352 $21,592 $16,716 $3,434 $20,150
Capacity revenues
(a)................... 13,929 13,938 13,938 13,939 13,847 1,136 817 410 1,227
Interest and other
income................ 2,509 2,644 2,520 1,712 1,181 217 78 118 196
------- -------- -------- -------- -------- ------- ------- ------ -------
Total revenues....... 92,572 103,178 104,443 104,580 108,380 22,945 17,611 3,962 21,573
------- -------- -------- -------- -------- ------- ------- ------ -------
Plant operations....... 19,651 17,564 18,266 18,830 19,887 5,517 4,039 1,604 5,643
Royalty expense........ 9,346 9,684 7,820 10,106 10,492 2,101 1,592 347 1,939
Depreciation and
amortization.......... 12,292 13,170 13,931 14,257 14,308 3,642 2,550 1,175 3,725
------- -------- -------- -------- -------- ------- ------- ------ -------
Total cost of
operations.......... 41,289 40,418 40,017 43,193 44,687 11,242 8,181 3,126 11,307
------- -------- -------- -------- -------- ------- ------- ------ -------
Operating income....... 51,283 62,760 64,426 61,387 63,693 11,703 9,430 836 10,266
Interest expense....... 16,040 15,063 13,162 9,105 6,267 1,786 616 1,233 1,849
Cumulative effect of
accounting change..... -- -- -- -- 953 -- -- -- --
------- -------- -------- -------- -------- ------- ------- ------ -------
Net income............. $35,243 $ 47,697 $ 51,264 $ 52,282 $ 56,473 $ 9,917 $ 8,814 $ (397) $ 8,417
======= ======== ======== ======== ======== ======= ======= ====== =======
Ratio of earnings to
fixed charges (c)..... 3.2x 4.2x 4.9x 6.7x 10.2x 6.6x 15.3x 0.7x(e) 5.6x
As of December 31, As of As of
-------------------------------------------- March 31, March 31,
1994 1995 1996 1997 1998 1998 1999
(In thousands)
Balance Sheet Data:
Cash--unrestricted...... $ 31,584 $ 40,219 $ 13,166 $ 873 $ -- $ 15,382 $ 17,015
Cash and investments--
restricted............. 23,478 23,533 23,298 290 290 290 247
Total assets............ 298,893 305,106 269,318 224,912 228,087 236,843 223,739
Acquisition debt(d)..... -- -- -- -- -- -- 55,256
Project loan............ 155,661 137,748 105,990 76,654 37,958 76,654 37,958
Total liabilities....... 198,632 185,546 156,652 100,799 64,896 102,157 118,133
Total partners'
capital................ 100,261 119,560 112,666 124,113 163,191 134,686 105,606
- --------------------
(a) Includes capacity payments and capacity bonus payments paid to the BLM
partnership under its power purchase agreement.
(b) After Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso partnerships adopted a new basis of accounting.
The purchase price was allocated to the portion of the assets and
liabilities purchased from CalEnergy based on their fair values, with the
amount of fair value of net assets in excess of the purchase price being
allocated to long-lived assets on a pro-rata basis.
(c) For purposes of computing the ratio of earnings to fixed charges, fixed
charges consist of interest expense and amortization of debt issuance
costs. Earnings used in computing the ratio of earnings to fixed charges
consist of net income plus fixed charges.
(d) In order to complete the purchase of all of CalEnergy's interests in the
Coso projects, Caithness Acquisition arranged for short-term debt financing
in the principal amount of approximately $211.5 million. Caithness
Acquisition used a portion of the proceeds from the Series A notes offering
that it received from the Coso partnerships, together with funds from other
sources, to repay all amounts owed under this short-term debt facility. As
a result of "push down" accounting, the short-term debt has been reflected
in the financial statements of the Coso partnerships, and a portion thereof
was allocated to the BLM partnership in the amount of $55.3 million.
(e) The decrease in the ratio of earnings to fixed charges for the one month
ended March 31, 1999 is primarily due to the amortization of debt issuance
costs of approximately $1.4 million related to the short-term debt
financing associated with Caithness Acquisition's purchase of all of
CalEnergy's interests in the Coso projects over the three-month estimated
life of the short-term debt.
64
Navy II Partnership
Three Months Ended March 31, 1999
------------------------------------
Two Months
Three Months Ended One Month
Year Ended December 31, Ended February 28, Ended
---------------------------------------------- March 31, 1999 March 31, 1999
1994 1995 1996 1997 1998 1998 (prior basis) (new basis)(b) Total
(In thousands, except ratio data)
Statement of Operations
Data:
Energy revenues........ $81,210 $94,372 $101,108 $ 98,778 $105,546 $25,415 $16,687 $6,716 $23,403
Capacity revenues
(a)................... 14,008 14,018 14,018 14,018 14,018 1,234 822 412 1,234
Interest and other
income................ 3,072 3,040 3,174 2,187 1,799 319 150 156 306
------- ------- -------- -------- -------- ------- ------- ------ -------
Total revenues....... 98,290 111,430 118,300 114,983 121,363 26,968 17,659 7,284 24,943
------- ------- -------- -------- -------- ------- ------- ------ -------
Plant operations....... 15,893 15,179 13,371 13,146 15,508 4,356 3,195 1,293 4,488
Royalty expense........ 3,927 11,141 11,486 11,249 11,868 2,780 1,806 1,064 2,870
Depreciation and
amortization.......... 11,800 12,848 13,054 13,354 13,744 3,493 2,339 1,188 3,527
------- ------- -------- -------- -------- ------- ------- ------ -------
Total cost of
operations.......... 31,620 39,168 37,911 37,749 41,120 10,629 7,340 3,545 10,885
------- ------- -------- -------- -------- ------- ------- ------ -------
Operating income....... 66,670 72,262 80,389 77,234 80,243 16,339 10,319 3,739 14,058
Interest expense....... 14,736 13,868 12,149 10,532 8,122 2,235 953 1,792 2,745
Cumulative effect of
accounting change..... -- -- -- -- 1,664 -- -- -- --
------- ------- -------- -------- -------- ------- ------- ------ -------
Net income............. $51,934 $58,394 $ 68,240 $ 66,702 $ 70,457 $14,104 $ 9,366 $1,947 $11,313
======= ======= ======== ======== ======== ======= ======= ====== =======
Ratio of earnings to
fixed charges (c)..... 4.5x 5.2x 6.6x 7.3x 9.9x 7.3x 10.8x 2.1x(e) 5.1x
As of December 31, As of As of
-------------------------------------------- March 31, March 31,
1994 1995 1996 1997 1998 1998 1999
(In thousands)
Balance Sheet Data:
Cash--unrestricted..... $ 41,843 $ 44,721 $ 18,133 $ 1,148 $ 818 $ 19,965 $ 20,039
Cash and investments--
restricted............ 22,771 22,841 22,391 -- -- -- --
Total assets........... 309,212 307.537 270.522 226,949 218,965 243,895 230,653
Acquisition debt (d)... -- -- -- -- -- -- 78,634
Project loan........... 173,413 156,043 124,361 97,267 61,323 97,267 61,323
Total liabilities...... 184,051 167,455 144,430 101,536 65,304 103,723 148,261
Total partners'
capital............... 125,161 140,082 126,092 125,413 153,661 140,172 82,392
- --------------------
(a) Includes capacity payments and capacity bonus payments paid to the Navy II
partnership under its power purchase agreement.
(b) After Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso partnerships adopted a new basis of accounting.
The purchase price was allocated to the portion of the assets and
liabilities purchased from CalEnergy based on their fair values, with the
amount of fair value of net assets in excess of the purchase price being
allocated to long-lived assets on a pro-rata basis.
(c) For purposes of computing the ratio of earnings to fixed charges, fixed
charges consist of interest expense and amortization of debt issuance
costs. Earnings used in computing the ratio of earnings to fixed charges
consist of net income plus fixed charges.
(d) In order to complete the purchase all of CalEnergy's interests in the Coso
projects, Caithness Acquisition arranged for short-term debt financing in
the principal amount of approximately $211.5 million. Caithness Acquisition
used a portion of the proceeds from the Series A notes offering that it
received from the Coso partnerships, together with funds from other
sources, to repay all amounts owed under this short-term debt facility. As
a result of "push down" accounting, the short-term debt has been reflected
in the financial statements of the Coso partnerships, and a portion thereof
was allocated to the Navy II partnership in the amount of $78.6 million.
(e) The decrease in the ratio of earnings to fixed charges for the one month
ended March 31, 1999 is primarily due to the amortization of debt issuance
costs of approximately $2.0 million related to the short-term debt
financing associated with Caithness Acquisition's purchase of all of
CalEnergy's interests in the Coso projects over the three-month estimated
life of the short-term debt.
65
UNAUDITED PRO FORMA FINANCIAL DATA
The following unaudited pro forma statement of operations for each of the
Coso partnerships and the following unaudited combined pro forma statement of
operations of the Coso partnerships for the year ended December 31, 1998, and
for the three months ended March 31, 1999, give effect to (1) the completion of
the Series A notes offering and the application of the proceeds therefrom,
(2) Caithness Acquisition's purchase of all of CalEnergy's interests in the
Coso projects and (3) certain related adjustments, under the assumptions and
adjustments set forth in the notes accompanying the unaudited pro forma
statements of operations and unaudited combined statements of operations, and
assume that all such transactions occurred at the beginning of the periods
presented. The unaudited pro forma financial data set forth below is based on
the historical financial statements of the Coso partnerships.
The following unaudited pro forma balance sheet for each of the Coso
partnerships and the following unaudited combined pro forma balance sheet of
the Coso partnerships as of March 31, 1999, give effect to (1) the completion
of the Series A notes offering and the application of the proceeds therefrom
and (2) certain related adjustments, as if such transactions occurred on March
31, 1999. The unaudited pro forma financial data set forth below is based on
the historical financial statements of the Coso partnerships.
The unaudited combined pro forma financial data reflects the mathematical
summation of the Coso partnerships on a combined basis as of and for the three
months ended March 31, 1999 and for the year ended December 31, 1998. Since the
Coso partnerships are under common management and have jointly and severally
guaranteed all of our obligations under the Indenture and the senior secured
notes, such guarantees being secured by (1) a perfected, first priority lien on
substantially all of the assets of the Coso partnerships and (2) a perfected,
first priority pledge of all of the ownership interests in the Coso
partnerships, the combined pro forma financial information of the Coso
partnerships has been presented.
The unaudited combined pro forma financial data does not purport to represent
what the financial position or results of operations of the Coso partnerships
would have been had Caithness Acquisition's purchase of CalEnergy's interests
and the completion of the Series A notes offering occurred on the dates
specified below. Furthermore, the unaudited combined pro forma financial data
does not purport to reflect the financial position or results of operations of
the Coso partnerships as if they constituted a single entity or for any future
period or date. The unaudited combined pro forma financial information should
not be considered in isolation or as a substitute for the pro forma financial
information of each of the Coso partnerships on a stand-alone basis included
herein.
The pro forma adjustments reflected below are based upon currently available
information and certain assumptions that we believe are reasonable under the
circumstances. In our opinion, all adjustments have been made that are
necessary to present fairly the pro forma financial data.
The adjustments contained in the unaudited pro forma financial data do not
give effect to any non-recurring costs directly associated with the Caithness
Acquisition's purchase of CalEnergy's interests in the Coso projects and the
completion of the Series A notes offering. You should read the unaudited pro
forma financial data in conjunction with the historical financial statements of
the Coso partnerships, including the related notes thereto, and "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
included elsewhere in this prospectus.
66
THE NAVY I PARTNERSHIP (a)
Unaudited Pro Forma Statement of Operations
for the Navy I Partnership
for the Three Months Ended March 31, 1999
(In thousands)
Pro Forma
Two Months Ended One Month Ended ------------------------
February 28, 1999 March 31, 1999 Total Adjustments As Adjusted
(prior basis) (new basis)(b)
Energy revenues......... $8,098 $4,399 $12,497 $ -- $12,497
Capacity revenues (c)... 474 237 711 -- 711
Interest income......... 824 827 1,651 -- 1,651
------ ------ ------- ----- -------
Total revenues........ 9,396 5,463 14,859 -- 14,859
Plant operations........ 3,125 1,458 4,583 (274)(d) 4,309
Royalty expense......... 987 451 1,438 -- 1,438
Depreciation and
amortization........... 1,604 783 2,387 (55)(e) 2,332
------ ------ ------- ----- -------
Total operating
expenses............. 5,716 2,692 8,408 (329) 8,079
Operating income........ 3,680 2,771 6,451 329 6,780
Interest expense........ 663 1,630 2,293 1,104 (f) 3,397
------ ------ ------- ----- -------
Income from continuing
operations(g).......... $3,017 $1,141 $ 4,158 $(775) $ 3,383
====== ====== ======= ===== =======
- ---------------------
(a) Reflects the combined financial results of the Navy I partnership and CFP
II. The Navy I partnership and CFP II were first formed as separate
entities to facilitate the initial bank financing for the construction and
development of Navy I. Since the Navy I partnership and CFP II operate
under common ownership and management control, the historical financial
statements of the entities have been combined after elimination of
intercompany amounts related to the royalty arrangement. At the closing of
the Series A notes offering, CFP II was merged with and into the Navy I
partnership and the accrued royalty was extinguished. In addition, the
royalty will no longer accrue from and after Series A notes offering. See
Note 1 to Notes to Combining and Combined Financial Statements of Coso
Finance Partners and Coso Finance Partners II.
(b) After Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso partnerships adopted a new basis of accounting.
The purchase price was allocated to the portion of the assets and
liabilities purchased from CalEnergy based on their fair values, with the
amount of fair value of net assets in excess of the purchase price being
allocated to long-lived assets on a pro-rata basis.
(c) Includes capacity payments and capacity bonus payments paid to the Navy I
partnership under its power purchase agreement.
(d) Adjusts for a reduction in O&M and management committee fees of
approximately $274,000. The adjustment represents the difference between
the amounts previously expensed for O&M and management committee fees and
the amounts which are expected to be expensed based on the terms of the new
O&M and management committee fee agreements. See "Summary Descriptions of
Principal Agreements Relating to the Coso Projects" and "Certain
Relationships and Related Transactions--O&M Fees; Reduction in Fees" and
"--Management Committee Fees."
(e) Adjusts for a change in depreciation and amortization expense relating to
Caithness Acquisition's purchase of all of CalEnergy's interests in the
Navy I project. Calculated as if Caithness Acquisition's purchase had
occurred on January 1, 1999, depreciation decreased by approximately
$250,000 based on the lower carrying values of property, plant and
equipment, offset by an increase in amortization expense of approximately
$195,000 based on the higher carrying value of the power purchase
agreement. The carrying values resulted from the allocation of purchase
price to the portion of assets and liabilities acquired from CalEnergy
based on their fair values, with the amount of fair value of net assets
acquired in excess of the purchase price allocated to long lived assets on
a pro-rata basis.
(f) Adjusts for the elimination of historical interest expense due to the
application of a portion of the proceeds from the Series A notes offering
to repay the existing project debt and the acquisition debt, offset by the
interest expense relating to the new project notes and amortization of
deferred financing costs as if the Series A notes offering had occurred on
January 1, 1999. The interest expense related to the senior secured notes
is based on estimated indebtedness of approximately $29.0 million of senior
secured notes due 2001 assuming a rate of interest per annum of 6.80% and
of approximately $122.6 million of senior secured notes due 2009, assuming
a rate of interest per annum of 9.05%. The adjustment for amortization of
debt issuance costs of approximately $130,000 is based on estimated
underwriting discounts and commissions and offering expenses of $3.5
million, amortized over the terms of the related project notes.
(g) To retire the existing project debt, the Navy I partnership paid premiums
of approximately $2.2 million. These premiums are not included in income
before cumulative effect of accounting change on a pro forma basis because
the amounts will be recorded as an extraordinary item which is not a
component of income from continuing operations.
67
THE BLM PARTNERSHIP
Unaudited Pro Forma Statement of Operations
for the BLM Partnership
for the Three Months Ended March 31, 1999
(In thousands)
Two Months Ended One Month Pro forma
February 28, Ended ------------------------
1999 March 31, 1999 Total Adjustments As adjusted
(prior basis) (new basis)(b)
Energy revenues......... $16,716 $3,434 $20,150 $ -- $20,150
Capacity revenues(a).... 817 410 1,227 -- 1,227
Interest and other
income................. 78 118 196 -- 196
------- ------ ------- ----- -------
Total revenues...... 17,611 3,962 21,573 -- 21,573
Plant operations........ 4,039 1,604 5,643 (397)(c) 5,246
Royalty expense......... 1,592 347 1,939 -- 1,939
Depreciation and
amortization........... 2,550 1,175 3,725 (267)(d) 3,458
------- ------ ------- ----- -------
Total operating
expenses........... 8,181 3,126 11,307 (664) 10,643
Operating income........ 9,430 836 10,266 664 10,930
Interest expense........ 616 1,233 1,849 605 (e) 2,454
------- ------ ------- ----- -------
Income from continuing
operations(f).......... 8,814 (397) 8,417 59 8,476
======= ====== ======= ===== =======
- ---------------------
(a) Includes capacity payments and capacity bonus payments paid to the BLM
partnership under its power purchase agreement.
(b) After Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso partnerships adopted a new basis of accounting.
The purchase price was allocated to the portion of the assets and
liabilities purchased from CalEnergy based on their fair values, with the
amount of fair value of net assets in excess of the purchase price being
allocated to long-lived assets on a pro-rata basis.
(c) Adjusts for a reduction in O&M and management committee fees of
approximately $397,000. The adjustment represents the difference between
the amounts previously expensed for O&M and management committee fees and
the amounts which are expected to be expensed based on the terms of the new
O&M and management committee fee agreements.
(d) Adjusts for a change in depreciation and amortization expense due to
Caithness Acquisition's purchase of all of CalEnergy's interests in the BLM
project. Calculated as if Caithness Acquisition's purchase had occurred on
January 1, 1999, depreciation decreased by approximately $439,000, based on
the lower carrying values of property, plant and equipment, partially
offset by an increase in amortization expense of approximately $172,000
based on the higher carrying value of the power purchase agreement. The
carrying values resulted from the allocation of purchase price to the
portion of assets and liabilities acquired from CalEnergy based on their
fair values, with the amount of fair value of net assets acquired in excess
of the purchase price allocated to long lived assets on a pro-rata basis.
(e) Adjusts for the elimination of historical interest expense due to the
application of a portion of the use of proceeds from the Series A notes
offering to repay the existing project debt and the acquisition debt,
offset by the interest expense relating to the new project notes and
amortization of deferred financing costs as if the Series A notes offering
had occurred on January 1, 1999. The interest expense related to the senior
secured notes is based on estimated indebtedness of approximately $11.7
million of senior secured notes due 2001 assuming a rate of interest per
annum of 6.80% and of approximately $96.3 million of senior secured notes
due 2009 assuming a rate of interest per annum of 9.05%. The adjustment for
amortization of debt issuance costs of approximately $76,000 is based on
estimated underwriting discounts and commissions and offering expenses of
$2.5 million, amortized over the terms of the related project notes.
(f) To retire the existing project debt, the BLM partnership paid premiums of
approximately $1.7 million. These premiums are not included in income
before cumulative effect of accounting change on a pro forma basis because
the amounts will be recorded as an extraordinary item which is not a
component of income from continuing operations.
68
THE NAVY II PARTNERSHIP
Unaudited Pro Forma Statement of Operations
for the Navy II Partnership
for the Three Months Ended March 31, 1999
(In thousands)
Two Months
Ended One Month
February 28, Ended Pro Forma
1999 March 31, 1999 ------------------------
(prior basis) (new basis)(b) Total Adjustments As Adjusted
Energy revenues......... $16,687 $ 6,716 $23,403 $ -- $23,403
Capacity revenues (a)... 822 412 1,234 -- 1,234
Interest and other
income................. 150 156 306 -- 306
------- ------- ------- ----- -------
Total revenues........ 17,659 7,284 24,943 -- 24,943
Plant operations........ 3,195 1,293 4,488 (325)(c) 4,163
Royalty expense......... 1,806 1,064 2,870 -- 2,870
Depreciation and
amortization........... 2,339 1,188 3,527 -- (d) 3,527
------- ------- ------- ----- -------
Total operating
expenses............. 7,340 3,545 10,885 (325) 10,560
Operating income........ 10,319 3,739 14,058 325 14,383
Interest expense........ 953 1,792 2,745 539 (e) 3,284
------- ------- ------- ----- -------
Income from continuing
operations (f)......... $ 9,366 $ 1,947 $11,313 $(214) $11,099
======= ======= ======= ===== =======
- ---------------------
(a) Includes capacity payments and capacity bonus payments paid to the Navy II
partnership under its power purchase agreement.
(b) After Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso projects, the Coso partnerships adopted a new
basis of accounting. The purchase price was allocated to the portion of the
assets and liabilities purchased from CalEnergy based on their fair values,
with the amount of fair value of net assets in excess of the purchase price
being allocated to long-lived assets on a pro-rata basis.
(c) Adjusts for a reduction in O&M and management committee fees of
approximately $325,000. The adjustment represents the difference between
the amounts previously expensed for O&M and management fees and the amounts
which are expected to be expensed based on the terms of the new O&M and
management committee fee agreements.
(d) Adjusts for a change in depreciation and amortization expense due to
Caithness Acquisition's purchase of all of CalEnergy's interests in the
Navy II project. Calculated as if Caithness Acquisition's purchase had
occurred on January 1, 1999, depreciation decreased by approximately
$453,000, based on the lower carrying values of property, plant and
equipment, partially offset by an increase in amortization expense of
approximately $453,000 based on the higher carrying value of the power
purchase agreement. The carrying values resulted from the allocation of
purchase price to the portion of assets and liabilities acquired from
CalEnergy based on their fair values, with the amount of fair value of net
assets acquired in excess of the purchase price allocated to long lived
assets on a pro-rata basis.
(e) Adjusts for the elimination of historical interest expense due to the
application of a portion of the proceeds from the Series A notes offering
to repay the existing project debt and the acquisition debt, offset by the
interest expense relating to the new project notes and amortization of
deferred financing costs as if the Series A notes offering had occurred on
January 1, 1999. The interest expense related to the senior secured notes
is based on estimated indebtedness of approximately $69.4 million of senior
secured notes due 2001 assuming a rate of interest per annum of 6.80% and
of approximately $84.2 million of senior secured notes due 2009 assuming a
rate of interest per annum of 9.05%. The adjustment for amortization of
debt issuance costs of approximately $200,000 is based on estimated
underwriting discounts and commissions and offering expenses of $3.5
million, amortized over the terms of the related project notes.
(f) To retire the existing project debt, the Navy II partnership paid premiums
of approximately $2.0 million. These premiums are not included in income
before cumulative effect of accounting change on a pro forma basis because
the amounts will be recorded as an extraordinary item which is not a
component of income from continuing operations.
69
THE COSO PARTNERSHIPS
Unaudited Combined Pro Forma Statement of Operations(a)
for the Coso Partnerships
for the Three Months Ended March 31, 1999
(In thousands)
Two Months Ended One Month Ended Pro Forma
February 28, 1999 March 31, 1999 -------------------------
(prior basis) (new basis)(b) Total Adjustments As Adjusted
Energy revenues......... $41,501 $14,549 $56,050 $ -- $56,050
Capacity revenues (c)... 2,113 1,059 3,172 -- 3,172
Interest and other total
revenues income........ 1,052 1,101 2,153 -- 2,153
------- ------- ------- ------- -------
Total revenues...... 44,666 16,709 61,375 -- 61,375
Plant operations........ 10,359 4,355 14,714 (996)(d) 13,718
Royalty expense......... 4,385 1,862 6,247 -- 6,247
Depreciation and
amortization........... 6,493 3,146 9,639 (322)(e) 9,317
------- ------- ------- ------- -------
Total operating
expenses........... 21,237 9,363 30,600 (1,318) 29,282
Operating income........ 23,429 7,346 30,775 1,318 32,093
Interest expense........ 2,232 4,655 6,887 2,248 (f) 9,135
------- ------- ------- ------- -------
Income from continuing
operations (g)......... $21,197 $ 2,691 $23,888 $ (930) $22,958
======= ======= ======= ======= =======
- ---------------------
(a) Reflects the mathematical summation of financial information of the Coso
partnerships on a combined basis for the three months ended March 31, 1999.
These combined amounts are unaudited. The combined presentation does not
necessarily reflect the results of operations that would have occurred had
the Coso partnerships constituted a single entity during the same period.
Because the Coso partnerships are under common management and have jointly
and severally guaranteed all of our obligations under the Indenture and the
senior secured notes, such guarantees being secured by (1) a perfected,
first priority lien on substantially all of the assets of the Coso
partnerships and (2) a perfected, first priority pledge of all of the
ownership interests in the Coso partnerships, the unaudited combined
financial information of the Coso partnerships has been presented.
(b) After Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso partnerships adopted a new basis of accounting.
The purchase price was allocated to the portion of the assets and
liabilities purchased from CalEnergy based on their fair values, with the
amount of fair value of net assets in excess of the purchase price being
allocated to long-lived assets on a pro-rata basis.
(c) Includes capacity payments and capacity bonus payments paid to the Coso
partnerships on a combined basis under the power purchase agreements.
(d) Adjusts for a reduction in O&M and management committee fees of
approximately $274,000, $397,000 and $325,000 for the Navy I partnership,
the BLM partnership and the Navy II partnership, respectively. The
adjustment represents the difference between the amounts previously
expensed for O&M and management committee fees and the amounts which are
expected to be expensed based on the terms of the new O&M and management
committee agreements.
(e) Adjusts for a change in depreciation and amortization expense due to
Caithness Acquisition's purchase of all of CalEnergy's interests in the
Coso projects. Calculated as if Caithness Acquisition's purchase had
occurred on January 1, 1999, depreciation decreased by approximately
$250,000 for the Navy I partnership, $439,000 for the BLM partnership and
$453,000 for the Navy II partnership, based on the lower carrying values of
property, plant and equipment, offset or partially offset by an increase in
70
amortization expense of approximately $195,000 for the Navy I partnership,
$172,000 for the BLM partnership and $453,000 for the Navy II partnership,
based on the higher carrying values of the power purchase agreements. The
carrying values resulted from the allocation of purchase price to the
portion of assets and liabilities acquired from CalEnergy based on their
fair values, with the amount of fair value of net assets acquired in excess
of the purchase price allocated to long lived assets on a pro-rata basis.
(f) Adjusts for the elimination of historical interest expense due to the
application of a portion of the proceeds from the Series A notes offering
to repay the existing project debt and the acquisition debt, offset by the
interest expense relating to the new project notes and amortization of
deferred financing costs as if the Series A notes offering had occurred on
January 1, 1999. The interest expense related to the senior secured notes
is based on the following estimated indebtedness from the offering
assuming a rate of interest per annum on the senior secured notes due 2001
of 6.80% and a rate of interest on the senior secured notes due 2009 of
9.05%:
Senior Secured Senior Secured
Notes Due 2001 Notes Due 2009
(In thousands)
Navy I partnership......................... $ 29,000 $122,550
BLM partnership............................ 11,650 96,250
Navy II partnership........................ 69,350 84,200
-------- --------
$110,000 $303,000
======== ========
The adjustment for amortization of debt issuance costs of $130,000, $76,000
and $200,000 is based on estimated underwriting discounts and commissions
and offering expenses of $3.5 million, $2.5 million and $3.5 million for
the Navy I partnership, the BLM partnership and the Navy II partnership,
respectively, amortized over the terms of the related project notes.
(g) To retire the existing project debt, premiums were paid of approximately
$2.2 million, $1.7 million and $2.0 million for the Navy I partnership,
the BLM partnership and the Navy II partnership, respectively. These
premiums are not included in income before cumulative effect of accounting
change on a pro forma basis because the amounts will be recorded as an
extraordinary item which is not a component of income from continuing
operations.
71
THE NAVY I PARTNERSHIP (a)
Unaudited Pro Forma Statement of Operations
for the Navy I Partnership
for the Year Ended December 31, 1998
(In thousands)
Pro Forma
--------------------------
Actual Adjustments As Adjusted
Energy revenues............................ $39,580 $ -- $39,580
Capacity revenues (b)...................... 13,573 -- 13,573
Interest income............................ 585 -- 585
------- -------- -------
Total revenues........................... 53,738 -- 53,738
Plant operations........................... 13,298 (1,643)(c) 11,655
Royalty expense............................ 6,824 -- 6,824
Depreciation and amortization.............. 11,772 (416)(d) 11,356
------- -------- -------
Total operating expenses................. 31,894 (2,059) 29,835
Operating income........................... 21,844 2,059 23,903
Interest expense........................... 4,333 9,254 (e) 13,587
------- -------- -------
Income before cumulative effect of
accounting change(f)...................... $17,511 $ (7,195) $10,316
======= ======== =======
- ---------------------
(a) Reflects the combined financial results of the Navy I partnership and CFP
II. The Navy I partnership and CFP II were first formed as separate
entities to facilitate the initial bank financing for the construction and
development of Navy I. Since the Navy I partnership and CFP II operate
under common ownership and management control, the historical financial
statements of the entities have been combined after elimination of
intercompany amounts related to the royalty arrangement. At the closing of
the Series A notes offering, CFP II was merged with and into the Navy I
partnership and the accrued royalty was extinguished. In addition, the
royalty will no longer accrue from and after the Series A notes offering.
See Note 1 to Notes to Combining and Combined Financial Statements of Coso
Finance Partners and Coso Finance Partners II.
(b) Includes capacity payments and capacity bonus payments paid to the Navy I
partnership under its power purchase agreement.
(c) Adjusts for a reduction in O&M and management committee fees of
approximately $1.6 million. The adjustment represents the difference
between the amounts previously expensed for O&M and management committee
fees and the amounts which are expected to be expensed based on the terms
of the new O&M and management committee fee agreements. See "Summary
Descriptions of Principal Agreements Relating to the Coso Projects" and
"Certain Relationships and Related Transactions--O&M Fees; Reduction in
Fees" and "--Management Committee Fees."
(d) Adjusts for a change in depreciation and amortization expense relating to
Caithness Acquisition's purchase of all of CalEnergy's interests in the
Navy I project. Calculated as if Caithness Acquisition's purchase had
occurred on January 1, 1998, depreciation decreased by approximately $1.5
million based on the lower carrying values of property, plant and
equipment, offset by an increase in amortization expense of approximately
$1.1 million based on the higher carrying value of the power purchase
agreement. The carrying values resulted from the allocation of purchase
price to the portion of assets and liabilities acquired from CalEnergy
based on their fair values, with the amount of fair value of net assets
acquired in excess of the purchase price allocated to long lived assets on
a pro-rata basis.
(e) Adjusts for the elimination of historical interest expense due to the
application of a portion of the proceeds from the Series A notes offering
to repay the existing project debt offset by the interest expense relating
to the new project notes and amortization of deferred financing costs as if
the Series A notes offering had occurred on January 1, 1998. The interest
expense related to the senior secured notes is based on estimated
indebtedness of approximately $29.0 million of senior secured notes due
2001 assuming a rate of interest per annum of 6.80% and of approximately
$122.6 million of senior secured notes due 2009, assuming a rate of
interest per annum of 9.05%. The adjustment for amortization of debt
issuance costs of $520,000 is based on estimated underwriting discounts and
commissions and offering expenses of $3.5 million, amortized over the terms
of the related project notes.
(f) To retire the existing project debt, the Navy I partnership paid premiums
of approximately $2.2 million. These premiums are not included in income
before cumulative effect of accounting change on a pro forma basis because
the amounts will be recorded as an extraordinary item which is not a
component of income before cumulative effect of accounting change.
72
THE BLM PARTNERSHIP
Unaudited Pro Forma Statement of Operations
for the BLM Partnership
for the Year Ended December 31, 1998
(In thousands)
Pro Forma
-------------------------
Actual Adjustments As Adjusted
Energy revenues............................. $93,352 $ -- $93,352
Capacity revenues(a)........................ 13,847 -- 13,847
Interest and other income................... 1,181 -- 1,181
------- ------- -------
Total revenues.......................... 108,380 -- 108,380
Plant operations............................ 19,887 (2,382)(b) 17,505
Royalty expense............................. 10,492 -- 10,492
Depreciation and amortization............... 14,308 (1,651)(c) 12,657
------- ------- -------
Total operating expenses................ 44,687 (4,033) 40,654
Operating income............................ 63,693 4,033 67,726
Interest expense............................ 6,267 3,549 (d) 9,816
------- ------- -------
Income before cumulative effect of
accounting change(e)....................... $57,426 $ 484 $57,910
======= ======= =======
- ---------------------
(a) Includes capacity payments and capacity bonus payments paid to the BLM
partnership under its power purchase agreement.
(b) Adjusts for a reduction in O&M and management committee fees of
approximately $2.4 million. The adjustment represents the difference
between the amounts previously expensed for O&M and management committee
fees and the amounts which are expected to be expensed based on the terms
of the new O&M and management committee fee agreements.
(c) Adjusts for a change in depreciation and amortization expense due to
Caithness Acquisition's purchase of all of CalEnergy's interests in the BLM
project. Calculated as if Caithness Acquisition's purchase had occurred on
January 1, 1998, depreciation decreased by approximately $2.6 million,
based on the lower carrying values of property, plant and equipment,
partially offset by an increase in amortization expense of approximately
$900,000 based on the higher carrying value of the power purchase
agreement. The carrying values resulted from the allocation of purchase
price to the portion of assets and liabilities acquired from CalEnergy
based on their fair values, with the amount of fair value of net assets
acquired in excess of the purchase price allocated to long lived assets on
a pro-rata basis.
(d) Adjusts for the elimination of historical interest expense due to the
application of a portion of the use of proceeds from the Series A notes
offering to repay the existing project debt offset by the interest expense
relating to the new project notes and amortization of deferred financing
costs as if the Series A notes offering had occurred on January 1, 1998.
The interest expense related to the senior secured notes is based on
estimated indebtedness of approximately $11.7 million of senior secured
notes due 2001 assuming a rate of interest per annum of 6.80% and of
approximately $96.3 million of senior secured notes due 2009 assuming a
rate of interest per annum of 9.05%. The adjustment for amortization of
debt issuance costs of $305,000 is based on estimated underwriting
discounts and commissions and offering expenses of $2.5 million, amortized
over the terms of the related project notes.
(e) To retire the existing project debt, the BLM partnership paid premiums of
approximately $1.7 million. These premiums are not included in income
before cumulative effect of accounting change on a pro forma basis because
the amounts will be recorded as an extraordinary item which is not a
component of income before cumulative effect of accounting change.
73
THE NAVY II PARTNERSHIP
Unaudited Pro Forma Statement of Operations
for the Navy II Partnership
for the Year Ended December 31, 1998
(In thousands)
Pro Forma
-------------------------
Actual Adjustments As Adjusted
Energy revenues............................ $105,546 $ -- $105,546
Capacity revenues (a)...................... 14,018 -- 14,018
Interest and other income.................. 1,799 -- 1,799
-------- ------- --------
Total revenues........................... 121,363 -- 121,363
Plant operations........................... 15,508 (1,950)(b) 13,558
Royalty expense............................ 11,868 -- 11,868
Depreciation and amortization.............. 13,744 (230)(c) 13,514
-------- ------- --------
Total operating expenses................. 41,120 (2,180) 38,940
Operating income........................... 80,243 2,180 82,423
Interest expense........................... 8,122 5,015 (d) 13,137
-------- ------- --------
Income before cumulative effect of
accounting change (e)..................... $ 72,121 $(2,835) $ 69,286
======== ======= ========
- ---------------------
(a) Includes capacity payments and capacity bonus payments paid to the Navy II
partnership under its power purchase agreement.
(b) Adjusts for a reduction in O&M and management committee fees of
approximately $2.0 million. The adjustment represents the difference
between the amounts previously expensed for O&M and management fees and the
amounts which are expected to be expensed based on the terms of the new O&M
and management committee fee agreements.
(c) Adjusts for a change in depreciation and amortization expense due to
Caithness Acquisition's purchase of all of CalEnergy's interests in the
Navy II project. Calculated as if Caithness Acquisition's purchase had
occurred on January 1, 1998, depreciation decreased by approximately $2.7
million, based on the lower carrying values of property, plant and
equipment, partially offset by an increase in amortization expense of
approximately $2.5 million based on the higher carrying value of the power
purchase agreement. The carrying values resulted from the allocation of
purchase price to the portion of assets and liabilities acquired from
CalEnergy based on their fair values, with the amount of fair value of net
assets acquired in excess of the purchase price allocated to long lived
assets on a pro-rata basis.
(d) Adjusts for the elimination of historical interest expense due to the
application of a portion of the proceeds from the Series A notes offering
to repay the existing project debt offset by the interest expense relating
to the new project notes and amortization of deferred financing costs as if
the Series A notes offering had occurred on January 1, 1998. The interest
expense related to the senior secured notes is based on estimated
indebtedness of approximately $69.4 million of senior secured notes due
2001 assuming a rate of interest per annum of 6.80% and of approximately
$84.2 million of senior secured notes due 2009 assuming a rate of interest
per annum of 9.05%. The adjustment for amortization of debt issuance costs
of $798,000 is based on estimated underwriting discounts and commissions
and offering expenses of $3.5 million, amortized over the terms of the
related project notes.
(e) To retire the existing project debt, the Navy II partnership paid premiums
of approximately $2.0 million. These premiums are not included in income
before cumulative effect of accounting change on a pro forma basis because
the amounts will be recorded as an extraordinary item which is not a
component of income before cumulative effect of accounting change.
74
THE COSO PARTNERSHIPS
Unaudited Combined Pro Forma Statement of Operations(a)
for the Coso Partnerships
for the Year Ended December 31, 1998
(In thousands)
Pro Forma
--------------------------
Actual Adjustments As Adjusted
Energy revenues........................... $238,478 $ -- $238,478
Capacity revenues (b)..................... 41,438 -- 41,438
Interest and other total revenues income.. 3,565 -- 3,565
-------- -------- --------
Total revenues........................ 283,481 -- 283,481
Plant operations.......................... 48,693 (5,975)(c) 42,718
Royalty expense........................... 29,184 -- 29,184
Depreciation and amortization............. 39,824 (2,297)(d) 37,527
-------- -------- --------
Total operating expenses.............. 117,701 (8,272) 109,429
Operating income.......................... 165,780 8,272 174,052
Interest expense.......................... 18,722 17,818(e) 36,540
-------- -------- --------
Income before cumulative effect of
accounting change (f).................... $147,058 $ (9,546) $137,512
======== ======== ========
- ---------------------
(a) Reflects the mathematical summation of financial information of the Coso
partnerships on a combined basis for the year ended December 31, 1998.
These combined amounts are unaudited. The combined presentation does not
necessarily reflect the results of operations that would have occurred had
the Coso partnerships constituted a single entity during the same period.
Because the Coso partnerships are under common management and have jointly
and severally guaranteed all of our obligations under the Indenture and the
senior secured notes, such guarantees being secured by (1) a perfected,
first priority lien on substantially all of the assets of the Coso
partnerships and (2) a perfected, first priority pledge of all of the
ownership interests in the Coso partnerships, the unaudited combined
financial information of the Coso partnerships has been presented.
(b) Includes capacity payments and capacity bonus payments paid to the Coso
partnerships on a combined basis under the power purchase agreements.
(c) Adjusts for a reduction in O&M and management committee fees of
approximately $1.6 million, $2.4 million and $2.0 million for the Navy I
partnership, the BLM partnership and the Navy II partnership, respectively.
The adjustment represents the difference between the amounts previously
expensed for O&M and management committee fees and the amounts which are
expected to be expensed based on the terms of the new O&M and management
committee fee agreements.
(d) Adjusts for a change in depreciation and amortization expense due to
Caithness Acquisition's purchase of all of CalEnergy's interests in the
Coso projects. Calculated as if Caithness Acquisition's purchase had
occurred on January 1, 1998, depreciation decreased by approximately $1.5
million for the Navy I partnership, $2.6 million for the BLM partnership
and $2.7 million for the Navy II partnership, based on the lower carrying
values of property, plant and equipment, offset or partially offset by an
increase in amortization expense of approximately $1.1 million for the Navy
I partnership, $900,000 for the BLM partnership and $2.5 million for the
Navy II partnership, based on the higher carrying values of the power
purchase agreements. The carrying values resulted from the allocation of
purchase price to the portion of assets and liabilities acquired from
CalEnergy based on their fair values, with the amount of fair value of net
assets acquired in excess of the purchase price allocated to long lived
assets on a pro-rata basis.
75
(e) Adjusts for the elimination of historical interest expense due to the
application of a portion of the proceeds from the Series A notes offering
to repay the existing project debt offset by the interest expense relating
to the new project notes and amortization of deferred financing costs as
if the Series A notes offering had occurred on January 1, 1998. The
interest expense related to the senior secured notes is based on the
following estimated indebtedness from the offering assuming a rate of
interest per annum on the senior secured notes due 2001 of 6.80% and a
rate of interest on the senior secured notes due 2009 of 9.05%:
Senior Secured Senior Secured
Notes Due 2001 Notes Due 2009
(In thousands)
Navy I partnership......................... $ 29,000 $122,550
BLM partnership............................ 11,650 96,250
Navy II partnership........................ 69,350 84,200
-------- --------
$110,000 $303,000
======== ========
The adjustment for amortization of debt issuance costs of $520,000,
$305,000 and $798,000 is based on estimated underwriting discounts and
commissions and offering expenses of $3.5 million, $2.5 million and $3.5
million for the Navy I partnership, the BLM partnership and the Navy II
partnership, respectively, amortized over the terms of the related project
notes.
(f) To retire the existing project debt, premiums were paid of approximately
$2.2 million, $1.7 million and $2.0 million for the Navy I partnership,
the BLM partnership and the Navy II partnership, respectively. These
premiums are not included in income before cumulative effect of accounting
change on a pro forma basis because the amounts will be recorded as an
extraordinary item which is not a component of income before cumulative
effect of accounting change.
76
THE NAVY I PARTNERSHIP(a)
Unaudited Pro Forma Balance Sheet
for the Navy I Partnership
as of March 31, 1999
(In thousands)
Pro Forma
-----------------------------------
Adjustments
Actual(a) -------------------- As Adjusted
Assets
Cash........................... $ 6,397 $148,064(b) $ -- $ --
-- 2,189(c)
-- 18,347(d)
-- 133,925(e)
Restricted cash and
investments................... 7,808 18,347(d) -- 26,155
Accounts receivable............ 5,520 -- -- 5,520
Prepaids and other assets...... 185 -- -- 185
Amounts due to related
parties....................... 42 -- -- 42
Property, plant & equipment.... 158,367 -- -- 158,367
Investment..................... 4,114 -- -- 4,114
Power purchase agreement....... 14,573 -- -- 14,573
Deferred financing costs, net.. 1,320 3,486(b) 1,320(f) 3,486
-------- -------- -------- --------
$198,326 $169,897 $155,781 $212,442
======== ======== ======== ========
Liabilities and partners' capital
Accounts payable and accrued
liabilities................... $ 13,387 $ 1,538(e) $ -- $ 11,849
Amounts due to related
parties....................... -- -- -- --
Acquisition debt............... 77,610 77,610(e) -- --
Project loan................... 40,566 40,566(e) 151,550(b) 151,550
-------- -------- -------- --------
131,563 119,714 151,550 163,399
Partners' capital.............. 66,763 2,189(c) -- 49,043
14,211(e) --
1,320(f) --
-------- -------- -------- --------
$198,326 $137,434 $151,550 $212,442
======== ======== ======== ========
- ---------------------
(a) Reflects the combined financial results of the Navy I partnership and CFP
II. The Navy I partnership and CFP II were first formed as separate
entities to facilitate the initial bank financing for the construction and
development of Navy I. Since the Navy I partnership and CFP II operate
under common ownership and management control, the historical financial
statements of the entities have been combined after elimination of
intercompany amounts related to the royalty arrangement. At the closing of
the Series A notes offering, CFP II was merged with and into the Navy I
partnership and the accrued royalty was extinguished, in addition, the
royalty will no longer accrue from and after the Series A notes offering.
See Note 1 to Notes to Combining and Combined Financial Statements of Coso
Finance Partners and Coso Finance Partners II.
(b) Reflects the estimated net proceeds of $151.6 million from the Series A
notes offering, net of underwriting discounts and commissions and offering
expenses estimated to be approximately $3.5 million. These costs are being
amortized over the terms of the related debt.
(c) Reflects the estimated premiums to retire the existing project debt.
(d) Adjusts restricted cash for the Debt Service Reserve Account required by
the Series A notes offering.
(e) Adjusts for the payment of existing project debt of approximately $40.6
million and related accrued interest of approximately $891,000 and the
payment of the acquisition debt of approximately $77.6 million and related
accrued interest of approximately $647,000. Subsequent to the Series A
notes offering, distributions of approximately $21.0 million are expected
to be paid to the owners of the Navy I partnership other than beneficial
owners of Caithness Energy. The balance of the distributions expected to be
paid to the Navy I partners in excess of the Navy I partnership's pro forma
distributable cash of $14.2 million is expected to be paid from cash
generated from the Navy I partnership's operations after March 31, 1999 and
from equity contributions expected to be received from Caithness Energy and
its affiliates.
(f) Adjusts for the write off of deferred financing costs associated with the
acquisition debt.
77
THE BLM PARTNERSHIP
Unaudited Pro Forma Balance Sheet
for the BLM Partnership
as of March 31, 1999
(In thousands)
Pro Forma
--------------------------------
Adjustments As
Actual -------------------- Adjusted
Assets
Cash............................... $ 17,015 $105,418(a) -- $ --
-- 1,692(b)
-- 13,063(c)
-- 107,678(d)
Restricted cash and investments.... 247 13,063(c) -- 13,310
Accounts receivable................ 15,799 -- -- 15,799
Prepaids and other assets.......... 333 -- -- 333
Amounts due to related parties..... 304 -- -- 304
Property, plant & equipment........ 163,269 -- -- 163,269
Investment......................... 5,335 -- -- 5,335
Power purchase agreement........... 20,498 -- -- 20,498
Deferred financing costs, net...... 939 2,482(a) 939(e) 2,482
-------- -------- -------- --------
$223,739 $120,963 $123,372 $221,330
======== ======== ======== ========
Liabilities and partners' capital
Accounts payable and accrued
liabilities....................... $ 3,129 $ 1,289(d) $ -- $ 1,840
Amounts due to related parties..... 21,790 -- -- 21,790
Acquisition debt................... 55,256 55,256(d) -- --
Project loan....................... 37,958 37,958(d) 107,900(a) 107,900
-------- -------- -------- --------
118,133 94,503 107,900 131,530
Partners' capital.................. 105,606 1,692(b) -- 89,800
939(e) --
13,175(d) -- --
-------- -------- -------- --------
$223,739 $110,309 $107,900 $221,330
======== ======== ======== ========
- ---------------------
(a) Reflects the estimated net proceeds of $107.9 million from the Series A
notes offering, net of underwriting discounts and commissions and offering
expenses estimated to be $2.5 million. These costs are being amortized over
the term of the related debt.
(b) Reflects the estimated premiums to retire the existing project debt.
(c) Adjusts restricted cash for the Debt Service Reserve Account required by
the Series A notes offering.
(d) Adjusts for the payment of existing project debt of $38.0 million and
related accrued interest of approximately $829,000 and the payment of the
acquisition debt of $55.3 million and related accrued interest of
approximately $460,000. Subsequent to the Series A notes offering,
distributions of approximately $17.9 million are expected to be paid to the
owners of the BLM partnership other than beneficial owners of Caithness
Energy. The balance of the distributions expected to be paid to the BLM
partners in excess of the BLM partnership's pro forma distributable cash of
$13.2 million is expected to be paid from cash to be generated from the BLM
partnership's operations after March 31, 1999 and from equity contributions
expected to be received from Caithness Energy and its affiliates.
(e) Adjusts for the write off of deferred financing costs associated with the
acquisition debt.
78
THE NAVY II PARTNERSHIP
Unaudited Pro Forma Balance Sheet
for the Navy II Partnership
as of March 31, 1999
(In thousands)
Pro Forma
-------------------------------------
Adjustments
Actual --------------------- As Adjusted
Assets
Cash.......................... $ 20,039 $150,018 (a) -- $ --
-- 1,962 (b)
-- 18,590 (c)
-- 149,505 (d)
Restricted cash and
investments.................. -- 18,590 (c) -- 18,590
Accounts receivable........... 19,778 -- -- 19,778
Prepaids and other assets..... 294 -- -- 294
Amounts due to related
parties...................... 3,352 -- -- 3,352
Property, plant & equipment... 149,380 -- -- 149,380
Investment.................... 6,818 -- -- 6,818
Power purchase agreements .... 29,656 -- -- 29,656
Deferred financing costs,
net.......................... 1,336 3,532 (a) 1,336 (e) 3,532
-------- -------- -------- --------
$230,653 $172,140 $171,393 $231,400
======== ======== ======== ========
Liabilities and partners'
capital
Accounts payable and accrued
liabilities.................. $ 6,764 $ 1,981 (d) $ -- $ 4,783
Amounts due to related
parties...................... 1,540 -- -- 1,540
Acquisition debt.............. 78,634 78,634 (d) -- --
Project loan.................. 61,323 61,323 (d) 153,550 (a) 153,550
-------- -------- -------- --------
148,261 141,938 153,550 159,873
Partners' capital............. 82,392 1,962 (b) -- 71,527
1,336 (e) --
7,567 (d) --
-------- -------- -------- --------
$230,653 $152,803 $153,550 $231,400
======== ======== ======== ========
- ---------------------
(a) Reflects the estimated net proceeds of $153.5 million from the Series A
notes offering, net of underwriting discounts and commissions and offering
expenses estimated to be $3.5 million. These costs are being amortized over
the term of the related debt.
(b) Reflects the estimated premiums to retire the existing project debt.
(c) Adjusts restricted cash for the Debt Service Reserve Account required by
the Series A notes offering.
(d) Adjusts for the payment of existing project debt of $61.3 million and
related accrued interest of approximately $1,326,000 and the payment of the
acquisition debt of $78.6 million and related accrued interest of
approximately $655,000. Subsequent to the Series A notes offering,
distributions of approximately $35.3 million are expected to be paid to the
owners of the Navy II partnership other than beneficial owners of Caithness
Energy. The balance of the distributions expected to be paid to the Navy II
partners in excess of the Navy II partnership's pro forma distributable
cash of $7.6 million is expected to be paid from cash to be generated from
the Navy II partnership's operations after March 31, 1999 and from equity
contributions expected to be received from Caithness Energy and its
affiliates.
(e) Adjusts for the write off of deferred financing costs associated with the
acquisition debt.
79
THE COSO PARTNERSHIPS (a)
Unaudited Combined Pro Forma Balance Sheet
for the Coso Partnerships as of March 31, 1999
(In thousands)
Pro Forma
-----------------------------------
Adjustments
Actual(a) -------------------- As Adjusted
Assets
Cash............................ $ 43,451 $403,500(b) $ -- $ --
-- 5,843(c)
-- 50,000(d)
-- 391,108(e)
Restricted cash and
investments.................... 8,055 50,000(d) -- 58,055
Accounts receivable............. 41,097 -- -- 41,097
Prepaids and other assets....... 812 -- -- 812
Amounts due to related parties.. 3,698 -- -- 3,698
Property, plant & equipment..... 471,016 -- -- 471,016
Investment...................... 16,267 -- -- 16,267
Power purchase agreements....... 64,727 -- -- 64,727
Deferred financing costs, net... 3,595 9,500(b) 3,595(f) 9,500
-------- -------- -------- --------
$652,718 $463,000 $450,546 $665,172
======== ======== ======== ========
Liabilities and partners'
capital
Accounts payable and accrued
liabilities.................... $ 23,280 $ 4,808(e) $ -- $ 18,472
Amounts due to related parties.. 23,330 -- -- 23,330
Acquisition debt................ 211,500 211,500(e) -- --
Project loan.................... 139,847 139,847(e) 413,000(b) 413,000
-------- -------- -------- --------
397,957 356,155 413,000 454,802
Partners' capital............... 254,761 5,843(c) -- 210,370
34,953(e) --
3,595(f) --
-------- -------- -------- --------
$652,718 $400,546 $413,000 $665,172
======== ======== ======== ========
- ---------------------
(a) Reflects the mathematical summation of the Coso partnerships on a combined
basis as of December 31, 1998. These combined amounts are unaudited. The
combined presentation does not necessarily reflect the financial position
that would have occurred had the Coso partnerships constituted a single
entity as of March 31, 1999. Because the Coso partnerships are under common
management and jointly and severally guaranteed all of our obligations
under the Indenture and the senior secured notes, such guarantees being
secured by (1) a perfected, first priority lien on substantially all of the
assets of the Coso partnerships and (2) a perfected, first priority pledge
of all of the ownership interests in the Coso partnerships, the unaudited
combined pro forma balance sheet has been presented.
(b) Reflects the estimated net proceeds of $151.6 million for the Navy I
partnership, $107.9 million for the BLM partnership and $153.5 million for
the Navy II partnership from the Series A notes offering, net of
underwriting discounts and commissions and offering expenses estimated to
be $3.5 million for the Navy I partnership, $2.5 million for the BLM
partnership and $3.5 million for the Navy II partnership. These costs will
be amortized over the term of the related debt.
(c) Reflects the estimated premiums to retire the existing project debt.
80
(d) Adjusts restricted cash for the Debt Service Reserve Account required by
the Series A notes offering of approximately $18.3 million, $13.1 million
and $18.6 million for the Navy I partnership, the BLM partnership and the
Navy II partnership, respectively.
(e) Adjusts for the payment of existing project debt of $40.6 million and
related accrued interest of approximately $891,000 and the payment of the
acquisition debt of $77.6 million and related accrued interest of
approximately $647,000 for the Navy I partnership, $38.0 million and
related accrued interest of approximately $829,000 and the payment of the
acquisition debt of $55.3 million and related accrued interest of
approximately $460,000 for the BLM partnership and $61.3 million and
related accrued interest of approximately $1.3 million and the payment of
the acquisition debt of $78.6 million and related accrued interest of
approximately $655,000 for the Navy II partnership. Subsequent to the
offering, distributions of approximately $21.0 million for the Navy I
partnership, $17.9 million for the BLM partnership and $35.3 million for
the Navy II partnership are expected to be paid to the owners of these
partnerships other than beneficial owners of Caithness Energy. The balance
of the distributions expected to be paid to the owners of the Coso
partnerships in excess of the Coso partnerships' pro forma distributable
cash of $35.0 million is expected to be paid from cash to be generated from
the Coso partnerships' operations after March 31, 1999 and from equity
contributions expected to be received from Caithness Energy and its
affiliates.
(f) Adjusts for the write off of deferred financing costs associated with the
acquisition debt.
81
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis relates to the financial condition and
results of operations of each of the Coso partnerships. It should be read in
conjunction with "Selected Historical Financial and Operating Data" and the
financial statements of each of the Coso partnerships, including the notes
thereto, included elsewhere in this prospectus. Because we were only recently
formed, we have no financial history. Except for the historical financial
information contained herein, this prospectus contains certain forward-looking
statements that involve risks and uncertainties, such as statements of the Coso
partnerships' plans, objectives, expectations and intentions. The Coso
partnerships' actual financial results could differ materially from those
discussed here. Factors that could cause or contribute to such differences
include those discussed under the headings "Forward-Looking Statements" and
"Risk Factors" as well as those discussed elsewhere in this prospectus.
General
The Coso projects consist of three 80 MW geothermal power plants, which we
call Navy I, BLM and Navy II, and their transmission lines, wells, gathering
system and other related facilities. The Coso projects are located near one
another at the United States Naval Air Weapons Center at China Lake,
California. The Navy I partnership owns Navy I and its related facilities. The
BLM partnership owns BLM and its related facilities. The Navy II partnership
owns Navy II and its related facilities. Affiliates of Caithness Corporation
and CalEnergy formed the Coso partnerships in the 1980s to develop, construct,
own and operate the Coso projects. On February 25, 1999, Caithness Acquisition
purchased all of CalEnergy's interests in the Coso projects for $205.0 million
in cash, plus $5.0 million in contingency payments, plus the assumption of
CalEnergy's and its affiliates' share of debt outstanding at the Coso projects
which then totaled approximately $67.0 million. As of December 31, 1998, the
book values of CalEnergy's interests in the Navy I partnership, the BLM
partnership and the Navy II partnership purchased by Caithness Acquisition were
approximately $71.8 million, $75.3 million and $76.8 million, respectively.
Each Coso partnership sells 100% of the electrical energy generated at its
plant to Edison under a long-term Standard Offer No. 4 power purchase
agreement. Each power purchase agreement expires after the last maturity date
of the senior secured notes. Edison is one of the largest investor-owned
electric utilities in the United States. As of December 31, 1998, Edison
reported in its 1998 annual report total assets of $16.9 billion and operating
revenues of $8.8 billion. Edison is currently rated A1 by Moody's and A+ by
Standard & Poor's.
Each Coso partnership receives the following payments under its power
purchase agreement:
. Capacity payments for being able to produce electricity at certain
levels. Capacity payments are fixed throughout the life of each power
purchase agreement;
. Capacity bonus payments if the Coso partnership is able to produce above
a specified higher level. The maximum annual capacity bonus payment
available is also fixed throughout the life of each power purchase
agreement; and
. Energy payments which are based on the amount of electricity the Coso
partnership's plant actually produces.
Energy payments are fixed for the first ten years of firm operation under
each power purchase agreement. Firm operation was achieved for each Coso
partnership when Edison and that Coso
82
partnership agreed that each generating unit at that Coso partnership's plant
was a reliable source of generation and could reasonably be expected to operate
continuously at its effective rating. After the first ten years of firm
operation and until a Coso partnership's power purchase agreement expires,
Edison makes energy payments to the Coso partnership based on Edison's avoided
cost of energy. Edison's avoided cost of energy is Edison's cost to generate
electricity if Edison were to produce it itself or buy it from another power
producer rather than buy it from the relevant Coso partnership. See "Risk
Factors--Future energy payments paid by Edison to the Coso partnerships will
most likely be less than historical energy payments because they will be paid
based on Edison's avoided cost of energy." The power purchase agreement for the
Navy I partnership will expire in August 2011, the power purchase agreement for
the BLM partnership will expire in March 2019, and the power purchase agreement
for the Navy II partnership will expire in January 2010.
Edison has taken the position that the fixed energy price period expired in
August 1997 for the Navy I partnership and in March 1999 for the BLM
partnership, and will expire in January 2000 for the Navy II partnership. The
Coso partnerships believe that the power purchase agreements provide that each
of the three separate turbine generator units at each Coso project has its own
full ten-year fixed energy price period. This issue is one of several currently
in dispute and subject to an ongoing lawsuit between, among others, the Coso
partnerships and Edison. Without making any statement as to the outcome of this
or any other dispute with Edison, for purposes of this prospectus only,
including the financial information included herein, we have assumed that the
fixed energy price period expires ten years after the first of the three
turbine generator units at each respective Coso project established firm
operation. We believe that this assumption is conservative and reasonable for
purposes of this prospectus given that we cannot predict the outcome of this
issue. See "Risk Factors--The Coso partnerships and their managing partners are
currently involved in material litigation with Edison, their sole customer" and
"Business--Legal Proceedings."
The Coso partnerships have implemented and intend to expand a steam sharing
program which they established under a Coso Geothermal Exchange Agreement they
entered into in 1994. The purpose of the steam sharing program is to enhance
the management of the Coso geothermal resource and to optimize the resource's
overall benefits to the Coso partnerships by transferring steam among the Coso
projects. The Navy I partnership recorded steam transfer revenues from the Navy
II partnership and the BLM partnership of approximately $8.5 million for the
three months ended March 31, 1999, approximately $19.0 million for the year
ended December 31, 1998, approximately $11.1 million for the year ended
December 31, 1997 and approximately $4.5 million for the year ended December
31, 1996. The Navy II partnership recorded steam transfer revenues from the BLM
partnership of zero for the three months ended March 31, 1999, approximately
$292,000 for the year ended December 31, 1998, zero for the year ended December
31, 1997 and approximately $3.1 million for the year ended December 31, 1996.
The BLM partnership incurred steam transfer revenues in the aggregate to the
Navy I partnership and the Navy II partnership approximately $3.5 million for
the three months ended March 31, 1999, $13.5 million for the year ended
December 31, 1998, $6.0 million for the year ended December 31, 1997 and
$7.6 million for the year ended December 31, 1996, and the Navy II partnership
incurred to the Navy I partnership approximately $5.0 million for the three
months ended March 31, 1999, $5.5 million for the year ended December 31, 1998,
$5.1 million for the year ended December 31, 1997 and zero for the year ended
December 31, 1996. See "Business--Steam Sharing Program" and "Summary
Descriptions of Principal Agreements Relating to the Coso Projects--Steam
Sharing and Co-Tenancy Agreements."
83
For the three months ended March 31, 1999 and for the year ended December 31,
1998, Edison's average avoided cost of energy paid to the Navy I partnership
was 3.0c and 3.0c per kWh, respectively, which is substantially below the fixed
energy prices earned for the three months ended March 31, 1998 and for the year
ended December 31, 1998 by the BLM partnership and the Navy II partnership.
Edison is now making energy payments to the BLM partnership based on its
avoided cost of energy, which payments are likely to be substantially less than
the fixed energy prices the BLM partnership earned through February 1999.
Estimates of Edison's future avoided cost of energy vary significantly, and no
one can predict the likely level of avoided cost of energy prices following the
end of the fixed energy price period under the Navy II partnership's power
purchase agreement in January 2000. Edison's avoided cost of energy is
currently substantially below the fixed energy prices previously paid by Edison
during the fixed energy price periods under the power purchase agreement for
the Navy I partnership and the BLM partnership. We expect that Edison's avoided
cost of energy will remain so over at least the near term for the Navy I
partnership and the BLM partnership. The revenues generated by the Coso
partnerships will probably decline significantly after the expiration of the
fixed energy price period for the Navy II partnership. See "Risk Factors--
Future energy payments paid by Edison to the Coso partnerships will most likely
be less than historical energy payments because they will be paid based on
Edison's avoided cost of energy."
Capacity Utilization
For purposes of consistency in financial presentation, the plant capacity
factor for each of the Coso partnerships is based on a nominal capacity amount
of 80 MW (240 MW in the aggregate). The Coso partnerships have a gross
operating margin that allows for the production of electricity in excess of
their nominal capacity amounts. Utilization of this operating margin is based
upon a number of factors and can be expected to vary throughout the year under
normal operating conditions.
The following data includes the operating capacity factor, capacity and
electricity production (in kWh) for each Coso partnership on a stand-alone
basis:
Three Months Ended March 31, 1999
---------------------------------
Three Months Two Months One Month
Ended Ended Ended
Year Ended December 31, March 31, February 28, March 31, Total
----------------------- ------------ ------------ --------- -------
1996 1997 1998 1998 1999 1999 1999
Navy I Partnership
(stand-alone)
Operating capacity
factor(a)............ 112.1% 103.2% 94.6%(a) 83.0% 73.4%(c) 77.4%(c) 75.4%(c)
Capacity (MW)
(average)............ 89.92 82.55 75.63 (a) 66.39 58.69 (c) 61.90(c) 60.29(c)
kWh produced (000s)... 787,688 723,116 662,560 (a) 143,400 83,100 (c) 46,041(c) 129,141(c)
BLM Partnership (stand-
alone)
Operating capacity
factor............... 107.9% 99.6% 104.4%(b) 98.0% 109.8%(b) 112.0%(b) 110.9%(b)
Capacity (MW)
(average)............ 86.54 79.66 83.54 (b) 78.43 87.85 (b) 89.6(b) 88.72(b)
kWh produced (000s)... 758,115 697,794 731,767 (b) 169,400 124,400 (b) 66,656(b) 191,056(b)
Navy II Partnership
(stand-alone)
Operating capacity
factor............... 110.6% 108.9% 108.6% 109.9% 112.7%(d) 112.6%(d) 112.7%(d)
Capacity (MW)
(average)............ 88.73 87.08 86.83 88.33 90.18(d) 90.1 (d) 90.14(d)
kWh produced (000s)... 777,243 762,821 760,659 190,800 127,700(d) 67,018 (d) 194,718(d)
- ---------------------
(a) The reduction in the operating capacity factor is due to the transfer of
steam from Navy I to Navy II and indirectly to BLM under the steam sharing
program. See "Business-- Steam Sharing Program" and "Summary Description of
Principal Agreements Relating to the Coso Projects--Steam Exchange and Co-
Tenancy Agreements."
(b) The increase in the operating capacity factor is due to the transfer of
steam from Navy II to BLM under the steam sharing program. See "Business--
Steam Sharing Program."
(c) The reduction in the operating capacity factor is due to the shutdown of
one of Navy I's three turbine generator units, known as Unit 1. See
"Prospectus Summary--Recent Developments--Return to Service of Navy I Unit"
and "Business--Overview of the Coso Projects--Plants--Navy I."
(d) The increase in the operating capacity factor is due to the transfer of
steam from Navy I to Navy II under the steam sharing program. See
"Business--Steam Sharing Program."
84
Results of Operations for the Three Months Ended March 31, 1998 and the Three
Months Ended March 31, 1999
The following discussion sets forth the results of operations of the Coso
partnerships for the three months ended March 31, 1998 and 1999. Due to
Caithness Acquisition's purchase of all of CalEnergy's interests in the Coso
projects at the end of February 1999, we have disaggregated the results of
operations set forth in the tables below for the three months ended March 31,
1999 to show the results of operations for the two months ended February 28,
1999 and the results of operations for the one month ended March 31, 1999. See
"Business--Purchase of CalEnergy's Interests." We prepared this presentation
because the Coso partnerships adopted a new basis of accounting after Caithness
Acquisition purchased all of CalEnergy's interests in the Coso projects, and
this new basis of accounting is reflected below in the results of operations
for the one month ended March 31, 1999. We have also included a total for the
results of operations for the three months ended March 31, 1999.
Total Operating Revenues
Three Months Ended March 31, 1999
----------------------------------------------------
Three Months Two Months Ended One Month Ended
Ended March 31, February 28, March 31, Total
----------------- ----------------- ---------------- -----------------
1998 1999 1999 1999
$ c per kWh $ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
Navy I partnership...... $10,806 7.5c $ 8,572 10.3c $4,636 10.1c $13,208 10.2c
BLM partnership......... 22,728 13.4 17,533 14.1 3,844 5.8 21,377 11.2
Navy II partnership..... 26,649 14.0 17,509 13.7 7,128 10.6 24,637 12.7
Capacity and Capacity Bonus Revenues
Three Months Ended March 31, 1999
------------------------------------------------
Two Months
Three Months Ended Ended One Month Ended
March 31, February 28, March 31, Total
-------------------------------------- --------------- ----------------
1998 1999 1999 1999
$ c per kWh $ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
Navy I partnership...... $ 813 0.6c $ 474 0.6c $ 237 0.5c $ 711 0.6c
BLM partnership......... 1,136 0.7 817 0.7 410 0.6 1,227 0.6
Navy II partnership..... 1,234 0.7 822 0.6 412 0.6 1,234 0.6
Energy Revenues
Three Months Ended March 31, 1999
----------------------------------------------------
Three Months Two Months Ended One Month Ended
Ended March 31, February 28, March 31, Total
----------------- ----------------- ---------------- -----------------
1998 1999 1999 1999
$ c per kWh $ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
Navy I partnership...... $ 9,993 7.0c $ 8,098 9.7c $4,399 9.6c $12,497 9.7c
BLM partnership......... 21,592 12.8 16,716 13.4 3,434 5.2 20,150 10.6
Navy II partnership..... 25,415 13.3 16,687 13.1 6,716 10.0 23,403 12.0
Total operating revenues for the Navy I partnership, which consist of
capacity payments, capacity bonus payments and energy payments made by Edison,
increased to $13.2 million for the three months ended March 31, 1999, from
$10.8 million for the three months ended March 31, 1998, an increase of 22.2%.
The Navy I partnership's energy revenues increased to $12.5 million for the
85
three months ended March 31, 1999, from $10.0 million for the three months
ended March 31, 1998, an increase of 25%. This significant increase was due to
the Navy I partnership's ability to transfer geothermal steam to the BLM
partnership and the Navy II partnership, both of which were still receiving
higher fixed energy payments under their respective power purchase agreements.
For the three months ended March 31, 1999, the Navy I partnership recorded
steam transfer revenues of approximately $3.5 million from the BLM partnership
and $5.0 million from the Navy II partnership.
The BLM partnership's total operating revenues decreased to $21.4 million for
the three months ended March 31, 1999, from $22.7 million for the three months
ended March 31, 1998, a decrease of 5.9%. The BLM partnership's energy revenues
decreased to $20.1 million for the three months ended March 31, 1999, from
$21.6 million for the three months ended March 31, 1998, a decrease of 6.7%.
Total operating and energy revenues decreased despite an 12.8% increase in kWh
produced over the same period due to increased steam transfers from the Navy I
partnership. Also, the decrease in energy revenues is attributable to the
expiration of the fixed energy price period under the BLM partnership's power
purchase agreement in March 1999.
The Navy II partnership's total operating revenues decreased to $24.6 million
for the three months ended March 31, 1999, from $26.6 million for the three
months ended March 31, 1998, a decrease of 7.6%. The Navy II partnership's
energy revenues decreased to $23.4 million for the three months ended March 31,
1999, from $25.4 million for the three months ended March 31, 1998, a decrease
of 7.9%. Total operating and energy revenues decreased despite a 2.0% increase
in kWh produced over the same period due to increased steam transfers from the
Navy I partnership.
Interest and Other Income
Three Months Ended March 31, 1999
---------------------------------------
Three Months Ended Two Months Ended One Month Ended
March 31, February 28, March 31, Total
------------------ ---------------- --------------- ------
1998 1999 1999 1999
(In thousands)
Navy I partnership.. $136 $824 $827 $1,651
BLM partnership..... 217 78 118 196
Navy II
partnership........ 319 150 156 306
The Navy I partnership's interest and other income increased to $1.7 million
for the three months ended March 31, 1999, from $136,000 for the three months
ended March 31, 1998. The increase is attributable to the recording of a $1.6
million business loss insurance receivable during the three months ended March
31, 1999, in connection with the shutdown of one of Navy I's turbine generator
units. See "Business--Overview of the Coso Projects--Plants--Navy I." The BLM
partnership's interest income decreased to $196,000 for the three months ended
March 31, 1999, from $217,000 for the three months ended March 31, 1998, a
decrease of 9.7%. The Navy II partnership's interest income decreased to
$306,000 for the three months ended March 31, 1999, from $319,000 for the three
months ended March 31, 1998, a decrease of 4.1%. These two decreases were due
to a generally lower interest rate environment.
86
Plant Operations
Three Months Ended March 31, 1999
--------------------------------------------------
Three Months Ended Two Months Ended One Month Ended
March 31, February 28, March 31, Total
------------------ ----------------- ---------------- ----------------
1998 1999 1999 1999
$ c per kWh $ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
Navy I partnership...... $ 3,571 2.5c $3,125 3.8c $1,458 3.2c $4,583 3.5c
BLM partnership......... 5,517 3.3 4,039 3.2 1,604 2.4 5,643 3.0
Navy II partnership..... 4,356 2.3 3,195 2.5 1,293 1.9 4,488 2.3
The Navy I partnership's operating expenses, including operating and general
and administrative expenses, increased to $4.6 million for the three months
ended March 31, 1999, from $3.6 million for the three months ended March 31,
1998, an increase of 28.3%. The BLM partnership's operating expenses, including
operating and general and administrative expenses, increased to $5.6 million
for the three months ended March 31, 1999, from $5.5 million for the three
months ended March 31, 1998, an increase of 2.3%. The Navy II partnership's
operating expenses, including operating and general and administrative
expenses, increased to $4.5 million for the three months ended March 31, 1999,
from $4.4 million for the three months ended March 31, 1998, a 3.0% increase.
These increases in operating expenses were due primarily to legal expenses
incurred by each of the Coso partnerships in connection with the Edison
litigation described in "Business--Legal Proceedings." The Navy I partnership's
operating expenses, exclusive of these legal expenses, increased to $2.8
million for the three months ended March 31, 1999, from $2.4 million for the
three months ended March 31, 1998, an increase of 14.7%. This increase was
caused by an increase in maintenance, engineering and selling, general and
administrative costs. The BLM partnership's operating expenses, exclusive of
these legal expenses, decreased to $3.8 million for the three months ended
March 31, 1999, from $4.1 million for the three months ended March 31, 1998, a
decrease of 8.5%. This decrease was caused by a decrease in maintenance,
engineering and selling, general and administrative costs. The Navy II
partnership's operating expenses, exclusive of these legal expenses, decreased
to $2.5 million for the three months ended March 31, 1999, from $3.2 million
for the three months ended March 31, 1998, a decrease of 20.8%. This decrease
was caused by a decrease in maintenance, engineering and selling, general and
administrative costs.
Royalty Expenses
Three Months Ended March 31, 1999
------------------------------------------
Two Months
Three Months Ended Ended One Month Ended
March 31, February 28, March 31, Total
--------------------------------------------------- ----------
1998 1999 1999 1999
Navy I partnership.... $ 895 0.6c $ 987 1.2c $ 451 1.0c $1,438 1.1c
BLM partnership....... 2,101 1.2 1,592 1.3 347 0.5 1,939 1.0
Navy II partnership... 2,780 1.5 1,806 1.4 1,064 1.6 2,870 1.5
The Navy I partnership's royalty expense increased to $1.4 million for the
three months ended March 31, 1999, from $895,000 for the three month period
ended March 31, 1998, a 60.7% increase. This increase was due to the Navy I
partnership's increase in steam sharing revenues over the same period. The BLM
partnership's royalty expense decreased to $1.9 million for the three months
ended March 31, 1999, from $2.1 million for the three months ended March 31,
1998, a 7.7% decrease. This decrease was due to a decrease in revenues
generated by the BLM partnership over the period. The BLM partnership's royalty
expense for the three months ended March 31, 1999 includes
87
approximately $508,000 of royalties payable to Coso Land Company. The BLM
partnership's royalty expense for the three months ended March 31, 1998
included approximately $633,000 of royalties payable to Coso Land Company. Coso
Land Company is one of our affiliates. The accrued royalties payable by the BLM
partnership to Coso Land Company were $21.2 million as of March 31, 1999 and
$18.3 million as of March 31, 1998. No portion of the accrued royalties that
are payable to Coso Land Company has been paid. The royalties owed by the BLM
partnership to Coso Land Company are subordinated to all payments made under
the senior secured notes. The Navy II partnership's royalty expense increased
to $2.9 million for the three months ended March 31, 1999, from $2.8 million
for the three month period ended March 31, 1998, a 3.2% increase. This increase
was caused by an increase in the Navy II partnership's operating revenues over
the same period.
Depreciation and Amortization
Three Months Ended March 31, 1999
--------------------------------------------------
Three Months Ended Two Months Ended One Month Ended
March 31, February 28, March 31, Total
--------------------------------------- ---------------- ----------------
1998 1999 1999 1999
$ c per kWh $ c per kWh $ c per kWh $ c per kWh
Navy I partnership.... $ 2,957 2.1c $1,604 1.9c $ 783 1.7c $2,387 1.9c
BLM partnership....... 3,624 2.1 2,550 2.1 1,175 1.8 3,725 2.0
Navy II partnership... 3,493 1.8 2,339 1.8 1,188 1.8 3,527 1.8
The Navy I partnership's depreciation and amortization expenses decreased to
$2.4 million for the three months ended March 31, 1999, from $2.9 million for
the three months ended March 31, 1998, a decrease of 19.3%. This decrease was
primarily due to the cessation of depreciation expenses for certain wells which
became fully depreciated during these periods. The BLM partnership's
depreciation and amortization expenses increased to $3.7 million for the three
months ended March 31, 1999, from $3.6 million for the three months ended March
31, 1998, an increase of 2.8%. The Navy II partnership's depreciation and
amortization expenses increased to $3.5 million for the three months ended
March 31, 1999, from $3.5 million for the three months ended March 31, 1998, an
increase of 1.0%.
Interest Expense
Three Months Ended March 31, 1999
------------------------------------------------------
Three Months Ended Two Months Ended One Month Ended
March 31, February 28, March 31, Total
------------------------------------------------------------ ----------------
1998 1999 1999 1999
$ c per kWh $ c per kWh $ c per kWh $ c per kWh
Navy I partnership.... $ 1,124 0.8c $ 663 0.8c $1,630 3.5c $2,293 1.8c
BLM partnership....... 1,786 1.1 616 0.5 1,233 1.9 1,849 0.9
Navy II partnership... 2,235 1.2 953 0.8 1,792 2.7 2,745 1.4
The Navy I partnership's interest expense increased to $2.3 million for the
three months ended March 31, 1999, from $1.1 million for the three months ended
March 31, 1998, an increase of 104.0%. The BLM partnership's interest expense
remained consistent at $1.8 million for the three months ended March 31, 1999,
and $1.8 million for the three months ended March 31, 1998. The Navy II
partnership's interest expense increased to $2.7 million for the three months
ended March 31, 1999, from $2.2 million for the three months ended March 31,
1998, an increase of 22.8%. These increases were due to an increase in the
interest expense and amortization of debt issuance costs related to the
acquisition debt. Debt issuance costs related to the acquisition debt of
approximately $2.0 million for the Navy I partnership, $1.4 million for the BLM
partnership and $2.0 million for the Navy II partnership, are being amortized
over the estimated life of the acquisition debt of three months.
88
Net Income
Three Months Ended March 31, 1999
----------------------------------------------------
Three Months Ended Two Months Ended One Month Ended
March 31, February 28, March 31, Total
---------------------------------------- ----------------- -----------------
1998 1999 1999 1999
$ c per kWh $ c per kWh $ c per kWh $ c per kWh
Navy I partnership.... $ 2,395 1.7c $3,017 3.6c $1,141 2.5c $ 4,158 3.2c
BLM partnership....... 9,917 5.9 8,814 7.1 (397) 0.6 8,417 4.4
Navy II partnership... 14,104 7.4 9,366 7.3 1,947 2.9 11,313 5.8
The Navy I partnership's net income increased to $4.2 million for the three
months ended March 31, 1999, from $2.4 million for the three months ended March
31, 1998, an increase of 73.6%. This increase in net income was primarily due
to increases in the Navy I partnership's steam sharing revenues during this
period. The BLM partnership's net income decreased to $8.4 million for the
three months ended March 31, 1999, from $9.9 million for the three months ended
March 31, 1998, a decrease of 15.1%. The decrease in net income was caused by
the decrease in operating revenues during this period. The Navy II
partnership's net income decreased to $11.3 million for the three months ended
March 31, 1999, from $14.1 million for the three months ended March 31, 1998, a
decrease of 19.8%. The decrease in net income was primarily due to a decrease
in Navy II's operating revenues during this period.
89
Results of Operations for the Years Ended December 31, 1996, 1997 and 1998
Total Operating Revenues
Year Ended December 31,
--------------------------------------------------------
1996 1997 1998
$ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
Navy I partnership...... $118,206 15.0c $100,431 13.9c $ 53,153 8.0c
BLM partnership......... 101,923 13.4 102,868 14.7 107,199 14.6
Navy II partnership..... 115,126 14.8 112,796 14.8 119,564 15.7
Capacity and Capacity Bonus Revenues
Year Ended December 31,
-----------------------------------------------------
1996 1997 1998
$ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
Navy I partnership.... $14,266 1.8c $13,845 1.9c $13,573 2.0c
BLM partnership....... 13,938 1.8 13,939 2.0 13,847 1.9
Navy II partnership... 14,018 1.8 14,018 1.8 14,018 1.8
Energy Revenues
Year Ended December 31,
-------------------------------------------------------
1996 1997 1998
$ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
Navy I partnership.. $103,940 13.2c $86,586 12.0c $ 39,580 6.0c
BLM partnership..... 87,985 11.6 88,929 12.7 93,352 12.8
Navy II
partnership........ 101,108 13.0 98,778 12.9 105,546 13.9
Total operating revenues for the Navy I partnership, which consist of
capacity payments, capacity bonus payments and energy payments made by Edison,
decreased to $53.2 million for the year ended December 31, 1998, from $100.4
million in 1997, a decrease of 47.1%. The Navy I partnership's energy revenues
decreased to $39.6 million for the year ended December 31, 1998, from $86.6
million in 1997, a decrease of 54.3%. These decreases were attributable to the
expiration of the fixed energy price period under the Navy I partnership's
power purchase agreement and are the result of a full year of energy payments
based upon Edison's avoided cost of energy after the fixed energy price period
expired in August 1997. During the final year of its fixed energy price period,
the Navy I partnership received approximately 14.6c per kWh for energy
delivered. Under the avoided cost of energy formula, since August 1997, the
Navy I partnership has been receiving an average of approximately 3.0c per kWh
for energy delivered. This significant decrease in energy payments was
partially offset by the Navy I partnership's ability to transfer geothermal
steam to the BLM partnership and the Navy II partnership, both of which were
still receiving fixed energy payments under their respective power purchase
agreements through December 31, 1998. For the year ended December 31, 1998, as
a result of its transfers of steam under the steam sharing program, the Navy I
partnership received steam transfer payments of approximately $13.5 million
from the BLM partnership and $5.5 million from the Navy II partnership.
The BLM partnership's total operating revenues increased to $107.2 million
for the year ended December 31, 1998, from $102.9 million in 1997, an increase
of 4.2%. The BLM partnership's energy revenues increased to $93.4 million for
the year ended December 31, 1998, from
90
$88.9 million in 1997, an increase of 5.0%. These increases were due to a 1.0c
per kWh increase in the rate paid by Edison under the BLM partnership's power
purchase agreement. In addition, kWh produced increased, primarily due to
increased steam transfers from the Navy I partnership. However, the impact from
such increased production was offset by steam sharing payments paid by the BLM
partnership to the Navy I partnership.
The Navy II partnership's total operating revenues increased to $119.6
million for the year ended December 31, 1998, from $112.8 million in 1997, an
increase of 6.0%. The Navy II partnership's energy revenues increased to $105.5
million for the year ended December 31, 1998, from $98.8 million in 1997, an
increase of 6.9%. These increases were due primarily to an increase in the rate
paid by Edison under the Navy II partnership's power purchase agreement. The
Navy II partnership was paid 14.6c per kWh in 1998 for the energy component of
the electricity it sold to Edison, up from 13.6c per kWh in 1997.
Total operating revenues for the Navy I partnership decreased to $100.4
million for the year ended December 31, 1997, from $118.2 million in 1996, a
decrease of 15.0%. The Navy I partnership's energy revenues decreased to $86.6
million for the year ended December 31, 1997, from $103.9 million in 1996, a
decrease of 16.7%. These decreases were attributable to Edison's cessation of
energy payments based on the fixed energy price period under the Navy I
partnership's power purchase agreement and are the result of a partial year of
energy payments based upon Edison's avoided cost of energy, rather than the
fixed energy price, since August 1997. In 1997, prior to the end of the fixed
energy price period, the Navy I partnership received approximately 14.6c per
kWh for its energy production. Under the avoided cost of energy formula, the
Navy I partnership received an average of approximately 3.0c per kWh of energy
delivered. This drop in energy prices was partially offset by the Navy I
partnership's ability to transfer steam to the BLM partnership and the Navy II
partnership under the steam sharing program, both of which were still being
paid fixed energy prices under their respective power purchase agreements
during the remainder of 1997. For the year ended December 31, 1997, the Navy I
partnership received steam transfer payments of approximately $6.0 million from
the BLM partnership and approximately $5.1 million from the Navy II
partnership.
The BLM partnership's total operating revenues increased slightly to $102.9
million for the year ended December 31, 1997, from $101.9 million in 1996, an
increase of 0.9%. The BLM partnership's energy revenues increased slightly to
$88.9 million for the year ended December 31, 1997, from $88.0 million in 1996,
an increase of 1.1%. Total operating revenues and energy revenues increased
despite an 8.0% decrease in kWh produced due to a 1.0c per kWh increase in the
rate paid by Edison under the BLM partnership's power purchase agreement.
The Navy II partnership's total operating revenues decreased to $112.8
million for the year ended December 31, 1997, from $115.1 million in 1996, a
decrease of 2.0%. The Navy II partnership's energy revenues decreased to $98.8
million for the year ended December 31, 1997, from $101.1 million in 1996, a
decrease of 2.3%. The decreases in the Navy II partnership's total operating
revenues and energy revenues were due to a 1.9% decrease in kWh produced by the
Navy II partnership over the same period and increased steam sharing payments
to the Navy I partnership, partially offset by a 1.0c per kWh increase in the
rate paid by Edison under the Navy II partnership's power purchase agreement.
91
Interest Income
Year Ended December
31,
--------------------
1996 1997 1998
(in thousands)
Navy I partnership...................................... $3,286 $1,980 $ 585
BLM partnership......................................... 2,520 1,712 1,181
Navy II partnership..................................... 3,174 2,187 1,799
The Navy I partnership's interest income decreased to $585,000 for the year
ended December 31, 1998, from $2.0 million in 1997, a decrease of 70.5%. The
BLM partnership's interest income decreased to $1.2 million for the year ended
December 31, 1998, from $1.7 million in 1997, a decrease of 31.0%. The Navy II
partnership's interest income decreased to $1.8 million for the year ended
December 31, 1998, from $2.2 million in 1997, a decrease of 17.7%. These
decreases were due to the replacement of a cash funded debt service reserve
fund with a letter of credit in 1997 and to a generally lower interest rate
environment.
The Navy I partnership's interest income decreased to $2.0 million for the
year ended December 31, 1997, from $3.3 million in 1996, a decrease of 39.7%.
The BLM partnership's interest income decreased to $1.7 million for the year
ended December 31, 1997, from $2.5 million in 1996, a decrease of 32.1%. The
Navy II partnership's interest income decreased to $2.2 million for the year
ended December 31, 1997, from $3.2 million in 1996, a decrease of 31.1%. These
decreases were due to the replacement of a cash funded debt reserve fund with a
letter of credit in 1997.
Operating Expenses
Year Ended December 31,
-----------------------------------------------------
1996 1997 1998
$ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
Navy I partnership.... $11,763 1.5c $11,329 1.6c $13,298 2.0c
BLM partnership....... 18,266 2.4 18,830 2.7 19,887 2.7
Navy II partnership... 13,371 1.7 13,146 1.7 15,508 2.0
The Navy I partnership's operating expenses, including operating and general
and administrative expenses, increased to $13.3 million for the year ended
December 31, 1998, from $11.3 million in 1997, an increase of 17.4%. The BLM
partnership's operating expenses, including operating and general and
administrative expenses, increased to $19.9 million for the year ended December
31, 1998, from $18.8 million in 1997, an increase of 5.6%. The Navy II
partnership's operating expenses, including operating and general and
administrative expenses, increased to $15.5 million for the year ended December
31, 1998, from $13.1 million in 1997, an increase of 18.0%. These increases
were due primarily to legal expenses incurred by each of the Coso partnerships
in connection with the Edison litigation described in "Business--Legal
Proceedings." The Navy I partnership's operating expenses, exclusive of these
legal expenses, decreased to $10.3 million for the year ended December 31,
1998, from $11.3 million in 1997, a decrease of 8.8%. The BLM partnership's
operating expenses, exclusive of these legal expenses, decreased to $16.9
million for the year ended December 31, 1998, from $18.2 million in 1997, a
decrease of 6.9%. The Navy II partnership's operating expenses, exclusive of
these legal expenses, decreased to $12.6 million for the year ended December
31, 1998, from $13.1 million in 1997, a decrease of 4.5%. The decreases in
operating expenses, exclusive of the legal expenses incurred in connection with
the Edison litigation, were due in large part to a favorable property tax
appeal and settlement with Inyo County.
92
Following Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso partnerships retained FPL Operating and Coso
Operating Company to operate and maintain the Coso projects at an anticipated
combined cost savings of approximately $5.5 million per year from the amounts
paid to the prior operators. All O&M fees payable to FPL Operating and Coso
Operating Company, the two new operators, have been subordinated to all
payments to be made under the senior secured notes. See "Business--Operating
Strategy."
The Navy I partnership's operating expenses, exclusive of the legal expenses
incurred in connection with the Edison litigation, decreased slightly to $11.3
million for the year ended December 31, 1997, from $11.8 million in 1996, a
decrease of 3.7%. The BLM partnership's operating expenses, exclusive of these
legal expenses, decreased to $18.2 million for the year ended December 31,
1997, from $18.3 million in 1996, a decrease of 0.5%. The Navy II partnership's
operating expenses, exclusive of these legal expenses, decreased to $13.1
million for the year ended December 31, 1997, from $13.4 million in 1996, a
decrease of 1.7%.
Royalty Expenses
Year Ended December 31,
-----------------------------------------------------
1996 1997 1998
$ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
Navy I partnership.... $11,059 1.4c $ 9,849 1.4c $ 6,824 1.0c
BLM partnership....... 7,820 1.0 10,106 1.4 10,492 1.4
Navy II partnership... 11,486 1.5 11,249 1.5 11,868 1.6
The Navy I partnership's royalty expense decreased to $6.8 million for the
year ended December 31, 1998, from $9.8 million in 1997, a 30.7% decrease. This
decrease was due to the Navy I partnership's decrease in revenues over the same
period. The BLM partnership's royalty expense increased to $10.5 million for
the year ended December 31, 1998, from $10.1 million in 1997, a 3.8% increase.
This was due to the increased revenues generated by the BLM partnership over
the period. The BLM partnership's royalty expenses for the year ended December
31, 1998 includes $3.1 million of royalties payable to Coso Land Company. The
BLM partnership's royalty expenses for the year ended December 31, 1997
includes $3.2 million of royalties payable to Coso Land Company. Coso Land
Company is one of our affiliates. The royalties payable by the BLM partnership
to Coso Land Company were $20.7 million as of December 31, 1998 and $17.7
million as of December 31, 1997. No portion of the royalties that are payable
to Coso Land Company has been paid. The royalties owed by the BLM partnership
to the Coso Land Company are subordinated to all payments to be made under the
senior secured notes. The Navy II partnership's royalty expenses increased to
$11.9 million for the year ended December 31, 1998, from $11.2 million in 1997,
an increase of 5.5%. This increase was due to a similar increase in revenues
generated by the Navy II partnership.
The Navy I partnership's royalty expenses decreased to $9.8 million for the
year ended December 31, 1997, from $11.1 million in 1996, a 10.9% decrease.
This was due to the Navy I partnership's decrease in total operating revenues
in 1997. The BLM partnership's royalty expenses increased to $10.1 million for
the year ended December 31, 1997, from $7.8 million in 1996, a 29.2% increase.
This increase was due to the settlement with the Bureau of Land Management in
1996 over the calculation of past royalties. The Navy II partnership's royalty
expenses decreased to $11.2 million for the year ended December 31, 1997, from
$11.5 million in 1996, a 2.1% decrease. This decrease was caused by a similar
decrease in the Navy II partnership's total operating revenues in 1997.
93
Depreciation and Amortization
Year Ended December 31,
-----------------------------------------------------
1996 1997 1998
$ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
Navy I partnership.... $13,325 1.7c $12,814 1.8c $11,772 1.8c
BLM partnership....... 13,931 1.8 14,257 2.0 14,308 2.0
Navy II partnership... 13,054 1.7 13,354 1.8 13,744 1.8
The Navy I partnership's depreciation and amortization expenses decreased to
$11.8 million for the year ended December 31, 1998, from $12.8 million in 1997,
a decrease of 8.1%. This decrease was primarily due to the cessation of
depreciation expense for certain wells which became fully depreciated during
these periods. The BLM partnership's depreciation and amortization expenses
increased to $14.3 million for the year ended December 31, 1998, from $14.3
million for the year ended December 31, 1997, an increase of 0.4%. The Navy II
partnership's depreciation and amortization expenses increased to $13.7 million
for the year ended December 31, 1998, from $13.4 million in 1997, an increase
of 2.9%.
The Navy I partnership's depreciation and amortization expenses decreased to
$12.8 million for the year ended December 31, 1997, from $13.3 million in 1996,
a decrease of 3.8%. The BLM partnership's depreciation and amortization
expenses increased to $14.3 million for the year ended December 31, 1997, from
$13.9 million in 1996, an increase of 2.3%. The Navy II partnership's
depreciation and amortization expenses increased to $13.4 million for the year
ended December 31, 1997, from $13.1 million in 1996, an increase of 2.3%.
Interest Expense
Year Ended December 31,
----------------------------------------------------
1996 1997 1998
$ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
Navy I partnership...... $ 8,868 1.1c $ 6,260 0.9c $4,333 0.7c
BLM partnership......... 13,162 1.7 9,105 1.3 6,267 0.9
Navy II partnership..... 12,149 1.6 10,532 1.4 8,122 1.1
The Navy I partnership's interest expenses decreased to $4.3 million for the
year ended December 31, 1998, from $6.3 million in 1997, a decrease of 30.8%.
The BLM partnership's interest expenses decreased to $6.3 million for the year
ended December 31, 1998, from $9.1 million in 1997, a decrease of 31.2%. The
Navy II partnership's interest expenses decreased to $8.1 million for the year
ended December 31, 1998, from $10.5 million in 1997, a decrease of 22.9%. These
decreases were due to a decrease in the amounts owed under the then existing
project debt that was repaid at the closing of the Series A notes offering. See
"Prospectus Summary--Recent Developments."
The Navy I partnership's interest expenses decreased to $6.3 million for the
year ended December 31, 1997, from $8.9 million in 1996, a decrease of 29.4%.
The BLM partnership's interest expenses decreased to $9.1 million for the year
ended December 31, 1997, from $13.2 million in 1996, a decrease of 30.8%. The
Navy II partnership's interest expenses decreased to $10.5 million for the year
ended December 31, 1997, from $12.1 million in 1996, a decrease of 13.3%. These
94
decreases were due to a decrease in the amounts owed under the then existing
project debt that was repaid at the Series A notes offering. See "Prospectus
Summary--Recent Developments."
Net Income
Year Ended December 31,
-----------------------------------------------------
1996 1997 1998
$ c per kWh $ c per kWh $ c per kWh
(In thousands, except for per kWh data)
Navy I partnership.... $76,477 9.7c $62,159 8.6c $16,588 2.5c
BLM partnership....... 51,264 6.8 52,282 7.5 56,473 7.7
Navy II partnership... 68,240 8.8 66,702 8.7 70,457 9.3
The Navy I partnership's net income decreased significantly to $16.6 million
for the year ended December 31, 1998, from $62.2 million in 1997, a decrease of
73.3%. The Navy I partnership's net income decreased significantly to $62.2
million for the year ended December 31, 1997, from $76.5 million in 1996, a
decrease of 18.7%. The decreases in net income for these periods are due to the
expiration of the fixed energy price period under the Navy I partnership's
power purchase agreement in August 1997. See "Risk Factors--The Coso
partnerships and their managing partners are currently involved in material
litigation with Edison, their sole customer" and "Business--Legal Proceedings."
The BLM partnership's net income increased to $56.5 million for the year
ended December 31, 1998, from $52.3 million in 1997, an increase of 8.0%. The
BLM partnership's net income increased to $52.3 million for the year ended
December 31, 1997, from $51.3 million in 1996, an increase of 2.0%. The
increases in net income for these periods are due primarily to increases in the
BLM partnership's total operating revenues during these periods.
The Navy II partnership's net income increased to $70.5 million for the year
ended December 31, 1998, from $66.7 million in 1997, an increase of 5.6%. The
increase in net income for this period is due primarily to increases in the
Navy II partnership's total operating revenues during this period. The Navy II
partnership's net income decreased to $66.7 million for the year ended December
31, 1997, from $68.2 million in 1996, a decrease of 2.3%. The decrease in net
income for this period is due primarily to a decrease in the Navy II
partnership's total operating revenues during this period.
Liquidity and Capital Resources
Each of the Navy I partnership, the BLM partnership and the Navy II
partnership derive substantially all of its cash flow from Edison under its
power purchase agreement and from interest income earned on funds on deposit.
The Coso partnerships have historically used their cash primarily for capital
expenditures for power plant improvements, resource and development costs,
distributions to partners and payments with respect to their project debt.
95
The following table sets forth a summary of each Coso partnership's cash
flows for the three months ended March 31, 1998, the two months ended February
28, 1999, the month ended March 31, 1999 and the three months ended March 31,
1999:
Three Months Ended
March 31, 1999
Three ------------------------------
Months Two Months One Month
Ended Ended Ended
March 31, February 28, March 31,
1998 1999 1999 Total
(In thousands)
Navy I partnership (stand-alone)
Net cash flows from operating
activities......................... $ 7,804 $ 6,592 $2,665 $ 9,257
Net cash flows from investing
activities......................... (24) (538) (397) (935)
Net cash flows from financing
activities......................... (108) (1,926) 0 (1,926)
------- ------- ------ -------
Net change in cash.................. $ 7,672 $ 4,128 $2,268 $ 6,396
======= ======= ====== =======
Three Months Ended
March 31, 1999
Three ------------------------------
Months Two Months One Month
Ended Ended Ended
March 31, February 28, March 31,
1998 1999 1999 Total
(In thousands)
BLM partnership (stand-alone)
Net cash flows from operating
activities......................... $18,478 $10,367 $6,595 $16,962
Net cash flows from investing
activities......................... (3,556) 120 (294) (174)
Net cash flows from financing
activities......................... (413) 425 (198) 227
------- ------- ------ -------
Net change in cash.................. $14,509 $10,912 $6,103 $17,015
======= ======= ====== =======
Three Months Ended
March 31, 1999
Three ------------------------------
Months Two Months One Month
Ended Ended Ended
March 31, February 28, March 31,
1998 1999 1999 Total
(In thousands)
Navy II partnership (stand-alone)
Net cash flows from operating
activities......................... $19,352 $12,016 $6,265 $18,281
Net cash flows from investing
activities......................... (808) (1,126) (218) (1,344)
Net cash flows from financing
activities......................... 273 1,766 518 2,284
------- ------- ------ -------
Net change in cash.................. $18,817 $12,656 $6,565 $19,221
======= ======= ====== =======
The Navy I partnership's net cash flows from operating activities increased
from the three months ended March 31, 1998 to March 31, 1999 by approximately
$1.5 million, primarily due to an increase in revenues for the Navy I
partnership in 1999 as compared to 1998.
Cash flows from investing activities at the Navy I partnership decreased from
the three months ended March 31, 1998 to March 31, 1999 by $911,000, primarily
due to the increase in capital expenditures in 1999 as compared to 1998.
The BLM partnership's net cash flows from operating activities decreased from
the three months ended March 31, 1998 to March 31, 1999 by approximately $1.5
million, primarily due to a decrease in revenues for the BLM partnership in
1999 as compared to 1998.
96
Cash flows from investing activities at the BLM partnership increased from
the three months ended March 31, 1998 to March 31, 1999 by $3.4 million,
primarily due to the decrease in capital expenditures related to the steam
field.
The Navy II partnership's net cash flows from operating activities decreased
from the three months ended March 31, 1998 to March 31, 1999 by approximately
$1.1 million primarily due to a decrease in revenues for the Navy II
partnership in 1999 as compared to 1998.
Cash flows from investing activities at the Navy II partnership decreased
from the three months ended March 31, 1998 to March 31, 1999 by $536,000,
primarily due to the increase in capital expenditures related to the power
plant.
The Coso partnerships' cash flows from financing activities have fluctuated
primarily as a result of cash distributions made to their partners. See
"Certain Relationships and Related Transactions--Distributions to Caithness
Energy and CalEnergy."
The following table sets forth a summary of each Coso partnership's cash
flows for the years ended December 31, 1996, 1997 and 1998:
Year Ended December 31,
------------------------------
1996 1997 1998
(In thousands)
Navy I partnership (stand-alone)
Net cash flows from operating activities... $ 83,779 $ 88,540 $ 32,163
Net cash flows from investing activities... (3,149) 17,948 (7,728)
Net cash flows from financing activities... (109,999) (119,324) (27,323)
--------- --------- --------
Net change in cash......................... $ (29,369) $ (12,836) $ (2,888)
========= ========= ========
Year Ended December 31,
------------------------------
1996 1997 1998
(In thousands)
BLM partnership (stand-alone)
Net cash flows from operating activities... $ 64,335 $ 60,948 $ 75,520
Net cash flows from investing activities... (5,798) 19,280 (20,302)
Net cash flows from financing activities... (85,590) (92,521) (56,091)
--------- --------- --------
Net change in cash......................... $ (27,053) $ (12,293) $ (873)
========= ========= ========
Year Ended December 31,
------------------------------
1996 1997 1998
(In thousands)
Navy II partnership (stand-alone)
Net cash flows from operating activities... $ 74,611 $ 80,660 $ 84,762
Net cash flows from investing activities... (3,883) 14,399 (6,939)
Net cash flows from financing activities... (97,316) (112,044) (78,153)
--------- --------- --------
Net change in cash......................... $ (26,588) $ (16,985) $ (330)
========= ========= ========
The Navy I partnership's net cash flows from operating activities decreased
by approximately $56.4 million from 1997 to 1998. This decrease was primarily
due to a decrease in revenues for the Navy I partnership in 1998 in which the
Navy I partnership received a full year of energy payments from Edison based
upon Edison's avoided cost of energy. Edison has taken the position that the
fixed energy price period expired in August 1997 for the Navy I partnership and
in March 1999 for the
97
BLM partnership, and will expire in January 2000 for the Navy II partnership.
See "Risk Factors--The Coso partnerships and their managing partners are
currently involved in material litigation with Edison, their sole customer,"
"--General" and "Business--Legal Proceedings." The expiration of the fixed
energy price period for the BLM partnership and the Navy II partnership and the
concomitant switch to payments by Edison based upon its avoided cost of energy
is likely to have a material adverse effect on net cash flows from operating
activities of those two Coso partnerships as well. However, future cash flows
from operating activities generated from revenues under the Coso partnerships'
power purchase agreements, plus any subsidy payments that the Coso partnerships
may receive under AB1890 through 2001 are expected to be sufficient to fund
operating expenses, royalty expenses (including the Navy I partnership's
obligations to make payments to the Navy sinking fund), payments of interest
and principal on the senior secured notes and capital expenditures.
Cash flows from investing activities at the Navy I partnership decreased from
1997 to 1998 by approximately $25.7 million, primarily due to the release in
1997 of approximately $22.5 million, held in a debt service reserve fund, and
further decreased by an increase in capital expenditures in 1998 as compared to
1997. The increase from 1996 to 1997 in cash flows from investing activities of
approximately $21.1 million is due to the same factors.
Cash flows from investing activities at the BLM partnership decreased from
1997 to 1998 by approximately $39.6 million, primarily due to the release in
1997 of approximately $23.0 million held in a debt service reserve fund, and
further decreased by an increase in capital expenditures of $16.6 million in
1998 as compared to 1997. The increase in capital expenditures by the BLM
partnership in 1998 is due to the drilling of new wells and other capital
expenditures relating to the steam sharing program. The increase from 1996 to
1997 in cash flows from investing activities of approximately $25.1 million is
also due to the release in 1997 of the cash held in the debt service reserve
fund, further increased by a decrease in capital expenditures in 1997 as
compared to 1996 of approximately $2.3 million.
Cash flows from investing activities at the Navy II partnership decreased
from 1997 to 1998 by approximately $21.3 million, primarily due to the release
in 1997 of approximately $22.4 million held in a debt service reserve fund,
partially offset by a decrease in capital expenditures in 1998 as compared to
1997. The increase from 1996 to 1997 in cash flows from investing activities of
approximately $18.3 million is also due to the release in 1997 of the cash held
in the debt service reserve fund partially offset by an increase in capital
expenditures in 1997 as compared to 1996.
The increase in the Coso partnerships' cash flows from investing activities
in 1997, as compared to 1996, was due to the release of the debt service
reserve fund in February 1997, offset somewhat by higher capital expenditures
in 1997, as compared to 1996.
The Coso partnerships' cash flows from financing activities have fluctuated
primarily as a result of cash distributions made to their partners. See
"Certain Relationships and Related Transactions--Distributions to Caithness
Energy and CalEnergy."
A portion of the proceeds from the Series A notes offering was used to
initially fund a Debt Service Reserve Account in the amount of $50.0 million.
Amounts deposited in the Debt Service
98
Reserve Account will be available to pay principal of and interest on the
senior secured notes if we are not able to meet our obligations to make those
payments. See "Description of Series B Notes--Debt Service Reserve Account."
The amount of funds held in the Debt Service Reserve Account will increase or
decrease from time to time and will equal the amount of the scheduled principal
and interest payment due on the senior secured notes for the immediately
succeeding six months.
The Navy I partnership is obligated to pay the Navy the sum of $25.0 million
on or before December 31, 2009, the expiration date of the term of the Navy
Contract. Payment of the obligation will be made from an established sinking
fund to which the Navy I partnership has been making payments since 1987. As of
March 31, 1999, there was approximately $7.7 million on deposit in this sinking
fund, representing both sinking fund payments made by the Navy I partnership
and accrued interest thereon. The Navy I partnership intends to make aggregate
annual payments to this sinking fund of approximately $716,000 through 2009
with cash flows generated from operating activities. See "Business--Royalty and
Revenue-Sharing Arrangements--Navy I."
The Coso partnerships have established a Capital Expenditure Reserve Account
which will be funded semi-annually in accordance with each Coso partnership's
operating budget and schedules thereto approved by our independent engineer.
The Capital Expenditure Reserve Account is pledged as security for the senior
secured notes. See "Description of Series B Notes--Capital Expenditure Reserve
Account." We expect that capital expenditures of the Coso partnerships for the
balance of 1999 to be approximately $18.8 million, based on each Coso
partnership's operating budget.
Year 2000 Issue
The Year 2000 issue refers to the fact that certain management information
and operating systems use two-digit data fields which recognize dates using the
assumption that the first two digits are "19" (for example, the number 98 is
recognized as the year 1998). When the year 2000 occurs, these systems could
interpret the year 2000 as 1900, which, in turn, could result in system
failures or miscalculations. This could cause disruptions of operations at the
Coso projects and at Edison, their sole customer.
The Coso partnerships have implemented a comprehensive program to address the
potential impact of the Year 2000 issue. This program involves several stages,
including inventory and impact assessment, remediation, testing and
implementation. The inventory and impact assessment of the information
technology infrastructure, computer applications and computerized processes
embedded in certain operating equipment has been completed, and most of the
necessary modifications have been remediated, tested and implemented. However,
the testing and implementation of one particular system, the failure of which
would severely impair the operations of the Coso projects, has not been
completed but final testing and implementation is expected to be completed
during the second quarter of 1999. This program is expected to be completed
during the second quarter of 1999.
The Coso partnerships depend substantially for their operating revenues on
Edison's purchase of all electrical energy generated by the plants. If Edison
fails to fulfill its contractual obligations under the power purchase
agreements because it has failed to resolve its own Year 2000 issues, it could
have a material adverse effect on the Coso partnerships' revenues and ability
to make payments on their project notes and guarantees. The Coso partnerships
have contacted Edison. Edison indicated that its Year 2000 program will be
completed by December 31, 1999. Further, Edison has reported in its annual
report filed on Form 10-K for the year ended December 31, 1998, that its
informational and operational systems have been assessed, and detailed plans
have been developed to address
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modifications required to be completed, tested and operational by December 31,
1999. The Coso partnerships will continue to contact Edison in an effort to
minimize any potential Year 2000 compliance impact, however, it is not possible
to guarantee Edison's compliance. Edison and other third parties might fail to
resolve timely their own Year 2000 issues, or might experience delays or
changes in the estimated time it takes to fix these problems.
The total costs expended to date for the Year 2000 program has been minimal.
The Coso partnerships expect to incur a nominal amount in the future to make
their computer systems Year 2000 compliant.
The Coso partnerships' Year 2000 contingency planning is currently underway
to address risk scenarios at the operating level (such as generation and
transmission), as well as at the business level (such as procurement and
accounting) and include developing strategies for dealing with the most
reasonably likely worst case scenario concerning Year 2000-related processing
failures or malfunctions caused by internal systems that would include a
temporary disruption of service to Edison or the possible disruption of
electricity sales to Edison due to Edison's failure to resolve their own Year
2000 issues in a timely manner. Contingency plans are expected to be completed
by mid-1999, allowing the second half of 1999 for implementation of the
contingency plan.
Although we believe that we and the Coso partnerships have an effective
program in place to adequately address the Year 2000 issue in a timely manner,
failure of third parties upon whom the Coso partnerships' business relies could
result in disruption of the Coso partnerships' generation of revenues and
payments on their project notes. Accordingly, the amount of potential liability
and lost revenue cannot be reasonably estimated at this time. See "Risk
Factors--The Coso partnerships could be materially adversely affected by
unanticipated Year 2000 compliance problems."
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BUSINESS
The Coso Projects
The Coso projects consist of three 80 MW geothermal power plants, which we
call Navy I, BLM and Navy II, and their transmission lines, wells, gathering
system and other related facilities. The Coso projects are located near one
another in the Mojave Desert approximately 150 miles northeast of Los Angeles,
California, and have been generating electricity since the late 1980s. Unlike
fossil fuel-fired power plants, the Coso projects' power plants use geothermal
energy derived from the natural heat of the earth's interior to generate
electricity. Since geothermal power plants have no fossil fuel costs, we
believe our plants enjoy higher and more stable gross operating margins than
fossil fuel-fired power plants with similarly rated capacities.
The Navy I partnership owns Navy I and its related facilities, the BLM
partnership owns BLM and its related facilities and the Navy II partnership
owns Navy II and its related facilities. The Coso partnerships and their
affiliates own the exclusive right to explore, develop and use, currently
without any known interference from any other power developers, a portion of
the Coso Known Geothermal Resource Area. See "--The Coso Known Geothermal
Resource Area." Since 1991, the Coso partnerships have drilled 56 geothermal
wells, approximately 91% of which have contributed to the commercial production
of geothermal energy.
The geothermal power plants, each of which has three separate turbine
generator units, have consistently operated above their nominal capacities, and
the combined average capacity factor for the plants has exceeded 100%, for each
of the last six years. For the three months ended March 31, 1999, the plants
operated at a combined average capacity factor of approximately 99.3%.
The Coso partnerships sell 100% of the electrical energy generated at the
plants to Edison under three long-term Standard Offer No. 4 power purchase
agreements. Each power purchase agreement expires after the last maturity date
of the senior secured notes. Edison is one of the largest investor-owned
electric utilities in the United States. As of December 31, 1998, Edison
reported in its 1998 annual report total assets of $16.9 billion and operating
revenues of $8.8 billion. Edison was, as of the date of this prospectus, rated
A1 by Moody's and A+ by Standard & Poor's.
Under the power purchase agreements, the Coso partnerships receive the
following payments:
. Capacity payments for being able to produce electricity at certain
levels. Capacity payments are fixed throughout the lives of the power
purchase agreements;
. Capacity bonus payments if they are able to produce electricity above a
specified higher level. The maximum capacity bonus payment available is
also fixed throughout the lives of the power purchase agreements; and
. Energy payments which are based on the amount of electricity their
respective plants actually produce.
Energy payments are fixed for the first ten years of firm operation under the
power purchase agreements. Firm operation was achieved for each Coso
partnership when Edison and that Coso partnership under its power purchase
agreement agreed that each generating unit at a plant was a reliable source of
generation and could reasonably be expected to operate continuously at its
effective rating. After the first ten years of firm operation and until its
power purchase agreement expires, Edison makes energy payments to the Coso
partnership based on its avoided cost of energy. Edison's avoided cost of
energy is Edison's cost to generate electricity if Edison were to produce it
itself or
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buy it from another power producer rather than buy it from the relevant Coso
partnership. See "Risk Factors--Future energy payments paid by Edison to the
Coso partnerships will most likely be less than historical energy payments
because they will be paid based on Edison's avoided cost of energy."
Edison has taken the position that the fixed energy price period expired in
August 1997 for the Navy I partnership and in March 1999 for the BLM
partnership, and will expire in January 2000 for the Navy II partnership. The
Coso partnerships believe that the power purchase agreements provide that each
of the three separate turbine generator units at each Coso project has its own
full ten-year fixed energy price period. This issue is one of several currently
in dispute and subject to an ongoing lawsuit between, among others, the Coso
partnerships and Edison. Without making any statement on the outcome of this or
any other dispute with Edison, for purposes of this prospectus only, including
the historical and pro forma financial information included herein, we have
assumed that the fixed energy price period expires ten years after the first of
the three generator units at each respective Coso project established firm
operation. We believe that this assumption is conservative and reasonable for
purposes of this prospectus given that we cannot predict the outcome of this
issue. See "Risk Factors--The Coso partnerships and their managing partners are
currently involved in material litigation with Edison, their sole customer" and
"Business--Legal Proceedings."
The Edison power purchase agreements will expire:
. in August 2011 for the Navy I partnership;
. in March 2019 for the BLM partnership; and
. in January 2010 for the Navy II partnership.
As of March 31, 1999, the unaudited combined net book value of the property,
plant and equipment of the Coso partnerships was approximately $471.0 million,
including approximately $158.4 million at the Navy I partnership, $163.2
million at the BLM partnership and $149.4 million at the Navy II partnership.
AB1890 Energy Subsidy Payments
In addition to receiving payments under the power purchase agreements, the
Navy I partnership and the BLM partnership currently qualify for subsidy
payments from a special purpose state fund established under AB1890. The
California Energy Commission administers the fund. AB1890 provides in part for
subsidy payments from 1998 through 2001 to power generators using renewable
sources of energy, including geothermal energy, and who are being paid based on
an avoided cost of energy basis. The funds are distributed in the form of a
production incentive payment that subsidizes renewable energy producers when
prices paid for their electricity are below certain pre-determined target
prices. Under AB1890, the Navy I partnership and the BLM partnership are
expected to receive in the future subsidy payments for energy delivered to
Edison by the Navy I partnership or the BLM partnership, as the case may be, if
Edison's avoided cost of energy falls below 3.0c per kWh. This subsidy is
capped at 1.0c per kWh. The Navy II partnership should also qualify for these
subsidy payments through 2001 once the fixed energy price period under its
power purchase agreement expires.
The Navy I partnership has granted a lien in favor of the California Energy
Commission against any recovery that the Navy I partnership obtains against
Edison which relates to the issue of when the fixed energy price period expires
at its plant, as described above and under the heading
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"Business--Legal Proceedings." The lien will secure approximately $477,000 of
AB1890 funds to be paid by the California Energy Commission to the Navy I
partnership with respect to the disputed period in 1998. The Navy I partnership
has posted a bond in the same amount as additional security. We expect that the
BLM partnership may need to do the same this year with respect to AB1890
payments to be paid by the California Energy Commission to the BLM partnership
after March 1999. We estimate that the BLM partnership will need to secure
approximately $350,000 of AB1890 payments and to post a similar bond. See "Risk
Factors--The Coso partnerships and their managing partners are currently
involved in material litigation with Edison, their sole customer" and
"Business--Legal Proceedings."
Operating Strategy
The Coso partnerships seek to maximize cash flow at the Coso projects through
active management of the Coso projects' cost structure and the Coso geothermal
resource. As a result of Caithness Acquisition's purchase of all of CalEnergy's
interests in the Coso projects:
. The Coso partnerships have retained two new operators at the Coso
projects: FPL Operating and Coso Operating Company. FPL Operating
operates and maintains all three plants, the transmission lines and the
geothermal fields at the Coso projects under three short-term O&M
agreements. Coso Operating Company, which is one of our affiliates,
manages the geothermal resource, including well drilling, under three
additional O&M agreements. Also:
. FPL Operating and Coso Operating Company have retained substantially
the same employees who were employed by the prior operator.
Approximately 70% of the employees who currently work at the Coso
projects' sites have been employed there since 1992; and
. As a result of the change in operators and the restructuring of
operator fees, the aggregate annual fees to be paid by the Coso
partnerships to FPL Operating and Coso Operating Company have been
reduced from approximately $7.5 million, which had been paid to
CalEnergy, to approximately $2.0 million. Payment of these reduced
operator fees have been subordinated to all payments to be made under
the senior secured notes;
. Caithness Acquisition, which recently purchased the managing partners of
the Coso partnerships, has caused any management committee fees payable
by each Coso partnership to its partners to be subordinated to all
payments to be made under the senior secured notes;
. The Coso partnerships expect to reduce annual non-fee related costs at
the Coso projects, including insurance, maintenance and other costs, by
approximately $1.9 million. However, the pro forma financial data
included in this prospectus does not give effect to this cost savings;
and
. The Coso partnerships are expanding a steam sharing program they
previously implemented among the Coso projects to enhance the management,
and to optimize the overall use, of the Coso geothermal resource. As part
of this program, the Coso partnerships plan to conserve the geothermal
resource whenever possible by, among other things:
. Transferring steam between and among the Coso projects and from BLM
North, rather than drilling new wells at the Coso projects' sites
prematurely; and
. Expanding the flexible field-wide water reinjection program. See "--
Steam Sharing Program."
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The Coso projects qualify as Small Power QFs under PURPA and the rules and
regulations promulgated under PURPA by FERC. PURPA exempts the Coso projects
from certain federal and state regulations. The Coso projects must continue to
satisfy certain ownership and fuel-use standards to maintain their QF status.
Since their inception, the Coso projects have satisfied these standards and we
expect that they will continue to do so.
Purchase of CalEnergy Interests
In late 1998, CalEnergy announced that it was planning to merge with
MidAmerican Energy Holdings Company. As a consequence of the planned merger,
FERC required CalEnergy to divest itself of at least a portion of its
approximately 48% equity interest in the Coso projects if the Coso projects
were to continue to qualify as QFs under PURPA. Each Coso partnership is
required to operate and maintain its Coso project as a QF under its power
purchase agreement and under the Indenture. See "--Overview of the Independent
Power Industry."
On February 25, 1999, Caithness Acquisition purchased all of CalEnergy's
interests in the Coso projects. The purchase price consisted of $205.0 million
in cash, plus $5.0 million in contingent payments, plus the assumption of
CalEnergy's and its affiliates' share of debt outstanding at the Coso projects
which then totaled approximately $67.0 million. In order to complete the
purchase, Caithness Acquisition arranged for short-term debt financing in the
principal amount of approximately $211.5 million. Caithness Acquisition used a
portion of the proceeds from the Series A notes offering that it received from
the Coso partnerships, together with funds from other sources, to repay all
amounts owed under this short-term debt facility. See "Certain Relationships
and Related Transactions--Purchase of CalEnergy Interests."
As part of the purchase of CalEnergy's interests in the Coso projects,
Caithness Energy will be required to pay the contingent payment upon the
settlement, final judgment or other dismissal of the litigation with Edison
described under the heading "Business--Legal Proceedings." The amount of the
contingent payment will depend on the outcome of the litigation with Edison.
If, as a result of the Edison litigation, the Coso partnerships are required to
pay damages to Edison, then the amount of the contingent payment will be
reduced by $0.50 for each $1.00 of damages in excess of any amounts owed to or
received by the Coso partnerships from Edison. The amount owed to the Coso
partnerships by Edison will include any amounts in excess of $5.7 million
received by the Coso partnerships from Edison as a result of the dispute
regarding the escalation of the fixed price energy payment schedule for 1999
and 2000. In no event will the amount of the contingent payment be greater than
$5.0 million or will CalEnergy owe any payment to the Coso partnerships as a
result of any adjustments to the amount of the contingent payment.
In addition, the Coso partnerships and certain other affiliates of Caithness
Energy entered into a future revenue agreement with CalEnergy. This agreement
provides that the Coso partnerships and such affiliates will pay to CalEnergy
one-seventh of the gross revenues from the Coso projects or any expansions
thereof derived from certain energy-related arrangements with the U.S.
Government. This agreement does not apply to currently existing arrangements
that the Coso partnerships have with the U.S. Government or any extensions or
renewals of those existing arrangements. The term of this agreement will expire
on February 25, 2004, unless a new arrangement is entered into with the U.S.
Government, in which case the term will expire upon the expiration of that new
arrangement.
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The Sponsor
Caithness Energy, the principal operating subsidiary of Caithness
Corporation, is a developer and owner of independent power projects and is the
sponsor of the Coso projects. Since 1966, the current owners of Caithness
Corporation have been involved in the development of long-term investment
opportunities involving natural resources. Caithness Corporation is one of the
two original sponsors of the Coso projects and formed Caithness Energy in 1995
to consolidate its ownership of independent power projects.
Caithness Energy believes that it is currently the second largest owner of
geothermal power projects in the United States, based on the total electrical
generating capacity of its power projects. Through its controlled affiliates,
Caithness Energy owns interests in seven geothermal plants, including the Coso
projects, totaling 420 MW. Caithness Energy is also seeking to develop two
additional geothermal power projects with a total potential electrical
generating capacity of over 400 MW, and has interests in other operating power
generating facilities, including solar, wind and natural gas, totaling an
additional 400 MW.
Caithness Energy typically partners with strategic investors in its power
project investments. The largest such investors in the Coso projects currently
are:
. a subsidiary of FPL Energy, Inc., the independent power subsidiary of FPL
Group, Inc., which is the parent company of Florida Power & Light
Company, one of the largest investor-owned utilities in the United
States; and
. Dominion Energy, Inc., a subsidiary of Dominion Resources, Inc., which
also is a large investor-owned utility. See "--The Coso Partnerships."
The Coso partnerships and Coso Operating Company, one of the two existing
operators of the Coso Projects and our affiliate, have been negotiating with
FPL Operating and its affiliates to acquire all of the equity interests in the
Navy I partnership held by one of FPL Operating's affiliates and to terminate
the existing O&M agreements with FPL Operating. See "Prospectus Summary--Recent
Developments--Negotiations with FPL Operating and its Affiliates."
Caithness Energy is headquartered in New York City and has additional offices
in California, Colorado and Florida.
The Coso Partnerships
Affiliates of Caithness Energy and CalEnergy formed the Coso partnerships
during the 1980s to develop, own and operate Navy I, BLM and Navy II. The Navy
I partnership was formed in July 1987, the BLM partnership was formed in March
1988 and the Navy II partnership was formed in July 1989. The Coso partnerships
own and operate the Coso projects. See "--Overview of the Coso Projects--
Project History."
Each of the Coso partnerships has two general partners, a managing partner
and a non-managing partner. The managing partner of the Navy I partnership is
New CLOC Company, LLC, a Delaware limited liability company ("New CLOC"), the
managing partner of the BLM partnership is New CHIP Company, LLC, a Delaware
limited liability company ("New CHIP") and the managing partner of the Navy II
partnership is New CTC Company, LLC, a Delaware limited liability company ("New
CTC"). The non-managing partner of the Navy I partnership is ESCA LLC, a
Delaware limited liability company ("ESCA"), the non-managing partner of the
BLM partnership is Caithness
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Coso Holdings, LLC, a Delaware limited liability company ("CCH"), and the non-
managing partner of the Navy II partnership is Caithness Navy II Group, LLC, a
Delaware limited liability company ("Navy II Group").
ESCA, the non-managing partner of the Navy I partnership, is owned by
affiliates of Caithness Energy and by ESI Geothermal, Inc., a Florida
corporation ("ESI"). ESI is in turn indirectly wholly owned by FPL Energy, Inc.
CCH and Navy II Group are owned by Caithness Energy-controlled entities.
Dominion Energy, Inc. is a limited partner of a member of CCH and is a member
of Navy II Group.
Since Caithness Acquisition's purchase of all of CalEnergy's interests in the
Coso projects in February 1999, Caithness Energy has indirectly wholly owned
and controlled the managing partners of the BLM partnership and the Navy II
partnership. Caithness Energy and its affiliates also control CCH, the non-
managing partner of the BLM partnership, and Navy II Group, the non-managing
partner of the Navy II partnership. In addition, while Caithness Energy has
indirectly wholly owned and controlled the managing partner of the Navy I
partnership since February 1999, it does not wholly own and control ESCA, the
non-managing partner of the Navy I partnership. Caithness Energy, FPL Energy,
Inc. and their respective affiliates collectively own and control ESCA. See
"Management." Also see "Prospectus Summary--Recent Developments--Negotiations
with FPL Operating and its Affiliates."
The Issuer
We are a special purpose corporation and a wholly owned subsidiary of the
Coso partnerships. We were formed for the purpose of issuing the senior secured
notes for ourselves and on behalf of the Coso partnerships. The Coso
partnerships have guaranteed our obligations to repay the senior secured notes.
On May 28, 1999, the closing date of the Series A notes offering, we and the
Coso partnerships completed the following transactions:
. We sold $110,000,000 of our 6.80% Series A Senior Secured Notes due 2001
and $303,000,000 of our 9.05% Series A Senior Secured Notes due 2009 to
the initial purchaser of the Series A notes pursuant to a purchase
agreement, dated May 21, 1999, among the initial purchaser, the Coso
partnerships and us;
. We loaned all of the proceeds from the Series A notes offering to the
Coso partnerships; and
. The Coso partnerships, in turn, caused the net proceeds from the Series A
notes offering, together with cash on their balance sheets and funds from
other sources, to (1) retire all Coso project debt that existed prior to
the Series A notes offering, including the payment of accrued and unpaid
interest and premiums, of approximately $150.7 million, (2) initially
fund the Debt Service Reserve Account established under the Depositary
Agreement in the amount of $50.0 million, (3) repay approximately $216.9
million of short term debt, including accrued interest, incurred to
purchase all of CalEnergy's interests in the Coso projects and (4) make
distributions of the remaining balance to the owners of the Coso
partnerships other than the beneficial owners of Caithness Energy.
We have no other material assets, other than the loans we made to the Coso
partnerships, and do not conduct any business, other than issuing the senior
secured notes and making the loans to be Coso partnerships.
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Overview of the Independent Power Industry
The Coso projects are part of the growing domestic independent power
industry. Utilities in the United States have been the predominant producers of
electric power since the early 1900s. In 1978, however, Congress enacted PURPA,
which removed regulatory constraints relating to the production and sale of
electricity by certain non-utility power producers. PURPA requires electric
utilities to buy electricity from non-utility power producers that use
renewable energy sources, known as Small Power QFs, or that produce both
electric energy and useful thermal energy used for industrial, commercial,
heating or cooling purposes, known as Cogeneration QFs. This encouraged
companies other than electric utilities to enter the electric power production
market. Under PURPA, electric utilities are required to comply with state law
guidelines and, in general, must interconnect with and buy capacity and energy
offered by non-utility power producers meeting certain ownership and, in the
case of Cogeneration QFs, operating and efficiency standards, or, in the case
of Small Power QFs, fuel use criteria, established by FERC if there is a need
for such electricity and if it is priced at or below the utility's avoided cost
of energy at the time of the agreements.
According to the Edison Electric Institute, as of December 31, 1997 (the most
recent data available, non-utility power producers represented approximately
8.5% of the installed generating capacity in the United States, accounting for
approximately 11.8% of the total electric generation in 1997. Between December
31, 1993 and December 31, 1997, non-utility power producers represented
approximately 44.5% of the new installed generating capacity added in the
United States.
The Coso Known Geothermal Resource Area
The Coso projects are located in an area that has been designated as a Known
Geothermal Resources Area by the Bureau of Land Management pursuant to the
Geothermal Steam Act of 1970. The Bureau of Land Management designates an area
as a Known Geothermal Resource Area when it determines that a commercially
viable geothermal resource is likely to exist there. There are over 100 Known
Geothermal Resource Areas in the United States, most of which are located in
the western United States in tectonically active regions.
The Coso Known Geothermal Resource Area is located in Inyo County,
California, approximately 150 miles northeast of Los Angeles. The Coso
geothermal resource is a "liquid-dominated" hot water source contained within
the heterogeneous fractured granite rocks of the Coso mountains. We believe the
heat source for the Coso geothermal resource is a hot molten rock or "magma"
body located at a depth of six-to-seven miles beneath the surface of the field.
Geochemical studies indicate that the water in the Coso geothermal resource is
ancient water that has been there since the ice age or longer.
The Coso partnerships produce steam by drilling wells into the fracture
systems, which tap into these reservoirs of hot water. These fractures act as
the plumbing system within the geothermal resource, enabling hot fluids to
circulate from deep within the earth's crust to drillable depths. Fractured
systems of this type are common among geothermal systems throughout the world.
As is typical in these types of complex geothermal reservoirs, it is often
difficult to predict how well these new wells will perform, even when the new
wells are located in close proximity to each other. The geothermal consultant's
report prepared by GeothermEx, Inc., which is included in Exhibit C in this
prospectus, provides additional information regarding the Coso geothermal
resource.
The Coso geothermal resource, which is a "liquid-dominated" system, is
significantly different from a so-called "dry steam" system. Although a dry
steam system contains more extractable energy
107
per pound than does the mixture of steam and water from the Coso geothermal
resource, we believe that the liquid-dominated Coso geothermal resource offers
certain operating advantages. Production from geothermal systems over time
results in a net loss of steam or fluid from the reservoir and consequently, a
decrease in reservoir pressure within the system. The liquid portion of the
fluid withdrawn from a liquid dominated system can be injected back into the
reservoir at specific points, which provides a means of maintaining pressure
support in the reservoir. In dry steam fields, no significant liquid fraction
is available, and reservoir pressure maintenance may require the importation of
water from an external source. The Coso geothermal resource is also relatively
low in total dissolved solids as contrasted with other liquid-dominated
geothermal resources. This contributes to less maintenance on the wells and
pipes to eliminate the build up of dissolved solids, and results in longer well
life.
Geothermal Energy
Geothermal energy is:
. an established and generally sustainable source of energy that
releases significantly lower levels of emissions than result when
energy is generated by burning fossil fuels;
. derived from the natural heat of the earth when water comes
sufficiently close to hot molten rock to heat the water to
temperatures of 400 degrees Fahrenheit or more. The heated water then
ascends toward the surface of the earth where, if geological
conditions are suitable, it can be extracted for commercial use by
drilling geothermal wells; and
. a renewable source of energy so long as natural ground water flows
and reinjection of extracted geothermal fluids are adequate over the
long term to replenish the geothermal reservoir after geothermal
fluids have been withdrawn.
Compared to fossil fuel-fired power plants, geothermal energy facilities
typically have higher capital costs, primarily as a result of wellfield
development, but tend to have significantly lower variable operating costs.
Power Production Process
The physical facilities used for geothermal energy production are
substantially the same at Navy I, BLM and Navy II. The following diagram
illustrates the geothermal energy production process:
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[DIAGRAM APPEARS HERE]
The geothermal fluids produced at the wellhead consist of a mixture of hot
water and steam. The mixture flows from the wellhead through a gathering system
of insulated steel pipelines to high pressure separation vessels, or
separators. There, steam is separated from the water and is sent to a demister
in the power plant, where any remaining water droplets are removed. This
produces a stream of dry steam, which passes through the high pressure inlet of
a turbine generator, producing electricity. The hot water previously separated
from the steam at the high pressure separators is piped to low pressure
separators, where low pressure steam is separated from the water and sent to
the low pressure inlet of a turbine generator. The hot water remaining after
low pressure steam separation is injected back into the Coso geothermal
resource.
Steam exhausted from the steam turbine is passed to a surface condenser
consisting of an array of tubes through which cold water circulates. Moisture
in the steam leaving the turbine generators condenses on the tubes and, after
being cooled further in a cooling tower, is used to provide cold circulating
water for the condenser.
The primary atmospheric emission control system at each of the Coso projects
consists of surface condenser, non-condensable gas removal equipment and a gas
compressor unit. In the initial periods of operations at the Coso projects,
gases were mixed with hot water exiting the low pressure separators and
injected back into the Coso geothermal resource via injection wells. This
practice of gas injection has been replaced with surface hydrogen sulfide
abatement systems at each Coso project. The Coso partnerships installed a "Dow
Sulferox H\\2\\S" abatement system at BLM in 1992 and "LO-CAT II" abatement
systems at Navy I and Navy II in 1994. Both systems utilize a patented chemical
process which transforms hydrogen sulfide gas into elemental sulfur, which can
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then be sold. For certain legal proceedings relating to the installation of the
"Dow Sulferox H\\2\\S" abatement system, see "--Legal Proceedings."
All three plants are designed to operate 24 hours per day, every day of the
year. Each year, three of the turbine generators are shut down for
approximately two weeks for regular inspection, maintenance and repair. FPL
Operating, the operator of the plants, will attempt to schedule these shut-
downs during off-peak periods. Additionally, outages during weekends, which are
considered off-peak periods, are scheduled twice a year for each of the nine
units. You should read the independent engineer's report prepared by Sandwell
Engineering Inc. and included in Exhibit A of this prospectus for more
information about the plants. It has a description of the status of the current
operations at each plant and their ability to maintain current levels of
operations.
Overview of the Coso Projects
Project History
In December 1979, CalEnergy signed the Navy Contract. Under the Navy
Contract, the Navy granted to CalEnergy exclusive contractual rights to explore
for, develop and use a portion of the Coso Known Geothermal Resource Area
located at the United States Naval Air Weapons Center at China Lake,
California. In 1980, an affiliate of Caithness Corporation and CalEnergy formed
a joint venture partnership, which is known as China Lake Joint Venture, to
develop jointly the geothermal resources in this area, and the Navy Contract
was subsequently assigned to China Lake Joint Venture. In 1983 and 1984, China
Lake Joint Venture negotiated the power purchase agreements with Edison. See
"Summary Descriptions of Principal Agreements Relating to the Coso Projects--
Power Purchase Agreements." In April 1985, CalEnergy entered into an Offer to
Lease and Lease for Geothermal Resources with the Bureau of Land Management,
which we call the BLM lease. By assignment from CalEnergy of the BLM lease,
Coso Land Company, another joint venture entity formed by affiliates of
Caithness Corporation and CalEnergy, obtained a leasehold interest in land
adjacent to the Navy lands for geothermal exploration and development.
In 1986, China Lake Joint Venture directly assigned to the Navy I partnership
portions of its interests under the Navy Contract in connection with the
construction of Navy I. In 1988, China Lake Joint Venture assigned to the Navy
II partnership portions of its interests under the Navy Contract in connection
with the construction of Navy II. It also retained a residual interest in the
Navy Contract. In 1988, the BLM lease was assigned to the BLM partnership.
Also, in 1989, the BLM partnership and the Navy II partnership transferred
certain of their respective rights to the BLM/Navy II Transmission Line
described under "Transmission Lines" below to Coso Transmission Line Partners,
a California general partnership of which the BLM partnership and the Navy II
partnership are the general partners, in connection with the completion of Navy
II. Today, the rights under the Navy Contract are vested in the Navy I
partnership, the Navy II partnership and Coso Transmission Line Partners, with
the residual interest held by China Lake Joint Venture, and the rights under
the BLM lease are vested in the BLM partnership. See "--The Coso Partnerships"
and "--Purchase of CalEnergy's Interests."
Plants
Navy I. Navy I and its steam resource are located on the United States Naval
Weapons Center at China Lake. It commenced operations in 1987. As of April 1,
1999, geothermal steam for Navy I was produced using 42 production and
injection wells located within a radius of approximately
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3,000 feet of Navy I. Navy I consists of three separate turbine generators,
known as Units 1, 2 and 3, each with approximately 30 MW of electrical
generating capacity. Navy I's steam gathering and piping systems are cross-
connected to Navy II via metered transfers to allow steam to be transferred
from wells located on the real property covered by the LADWP leases to Navy I
and between Navy I and Navy II pursuant to the steam sharing program. See "--
Steam Sharing Program." Unit 1 at Navy I commenced firm operation in 1987, and
Units 2 and 3 at Navy I commenced firm operation during 1988. Navy I has an
aggregate gross electrical generating capacity of approximately 90 MW, and
operated at an average operating capacity factor of 94.6% in 1998, 103.2% in
1997 and 112.1% in 1996, based on a nameplate capacity of 80 MW.
In January 1999, one of Navy I's three turbine generator units, known as Unit
1, automatically shut down when the stator coils attached to it experienced a
ground fault. The stator coil was repaired, and Unit 1 was scheduled to return
to service in March 1999. However, electrical faults recurred during the start-
up testing stage of Unit 1's generators, and the Navy I partnership postponed
Unit 1's return to service while it repaired the unit. Unit 1 returned to
service prior to June 1, 1999, and is currently in service. The Navy I
partnership had filed a claim in connection with Unit 1's shutdown under its
business interruption and casualty insurance policies. It expects that any
losses resulting from this shutdown will be covered by insurance, subject to a
deductible of $500,000 for property damage and a 25-day deductible for business
interruption. The other two turbine generator units at Navy I and the three
generator units at BLM and Navy II are also currently in service.
BLM. BLM and its steam resource are located on Bureau of Land Management
property (other than the Bureau of Land Management property that is subject to
the LADWP leases), within the boundaries of the United States Naval Weapons
Center at China Lake. It commenced operations in 1989. BLM is comprised of
turbine generators located at two different power blocks: the BLM East site and
the BLM West site. The BLM East site is located approximately 1.3 miles east of
the BLM West site. As of April 1, 1999, geothermal steam for BLM was produced
using 36 production and injection wells located within a radius of
approximately 4,000 feet from either the BLM East or the BLM West site. BLM
consists of three separate turbine generators, known as Units 7, 8 and 9. Units
7 and 8 are located at the BLM East site, each with a generating capacity of
approximately 30 MW, while Unit 9 is located at the BLM West site, with a
generating capacity of approximately 30 MW. BLM's steam gathering and piping
systems are cross-connected to Navy II via metered transfers to allow steam to
be transferred between Navy II and BLM. See "--Steam Sharing Program." All
three units commenced firm operation during 1989. BLM has an aggregate gross
electrical generating capacity of approximately 90 MW, and operated at an
average operating capacity factor of 104.4% in 1998, 99.6% in 1997, and 107.9%
in 1996, based on a nameplate capacity of 80 MW.
Navy II. Navy II and its steam resource are located on the United States
Naval Weapons Center at China Lake. It commenced operations in 1989. As of
April 1, 1999, geothermal steam for Navy II was produced using 37 production
and injection wells located within a radius of approximately 6,000 feet of Navy
II. Navy II consists of three separate turbine generators, known as Units 4, 5
and 6, each with approximately 30 MW of electrical generating capacity. Navy
II's steam supply systems are cross-connected to Navy I's and BLM's steam
supply systems via metered transfers to allow steam to be transferred between
or among the plants pursuant to the steam sharing program. See "--Steam Sharing
Program." All three Navy II units commenced firm operation in 1990. Navy II has
an aggregate gross electrical capacity of approximately 90 MW, and operated at
an average operating capacity factor of 108.6% in 1998, 108.9% in 1997, and
110.6% in 1996, based on a nameplate capacity of 80 MW.
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Transmission Lines
The electricity generated by Navy I is conveyed over an approximately 28.8-
mile 115 kilovolt ("kV") transmission line on Navy and Bureau of Land
Management land that is connected to the Edison substation at Inyokern,
California. The Navy I partnership owns and uses this transmission line (the
"Navy I Transmission Line") and its related facilities. The electricity
generated by BLM and Navy II is conveyed over an approximately 28.8-mile 230 kV
transmission line on Navy and Bureau of Land Management land that is also
connected to the Edison substation at Inyokern, California (the "BLM/Navy II
Transmission Line"). Coso Transmission Line Partners owns the BLM/Navy II
Transmission Line and related facilities. FPL Operating maintains the Navy I
Transmission Line pursuant to an O&M agreement with Navy I and the BLM/Navy II
Transmission Line pursuant to O&M agreements with the BLM partnership and the
Navy II partnership.
BLM North
In 1997, LADWP assigned to Coso Land Company, one of our affiliates, all of
its rights and interests in three separate leases that it entered into with the
Bureau of Land Management, including the right to use certain wells and related
equipment located on the real property subject to these three leases. We call
these three leases the LADWP leases. Under the LADWP leases, Coso Land Company
has the right to drill for, extract, produce, remove, use, sell and dispose of
the geothermal resources located on BLM North. Coso Land Company originally
entered into the lease assignment with the LADWP to obtain access to additional
steam to supplement the steam available for transfer among the Coso projects'
plants under the steam sharing program. See "--Steam Sharing Program."
Coso Land Company currently allows the Coso partnerships to have access to
the geothermal resources underlying BLM North, although the Bureau of Land
Management has not formally consented to this arrangement. As of April 1, 1999,
the Coso partnerships were producing steam from two production wells located on
one of the LADWP leases and were injecting fluids into an injection well
located on a second LADWP lease. Another well located on the second LADWP lease
is capable of producing geothermal steam, but it has not been connected to the
Coso projects' gathering system. The third LADWP lease has no wells on it. The
currently-producing wells located at BLM North are cross-connected to Navy I
via metered transfers to allow steam to be transferred from these wells to
Navy I. Under the steam sharing program, the Coso partnerships supplement the
steam produced at BLM by transferring steam from the wells located at BLM North
to Navy I.
Coso Land Company has applied to the Bureau of Land Management for assignment
to each Coso partnership of an undivided one-third interest in the LADWP leases
as tenants-in-common. This assignment is subject to the consent of the Bureau
of Land Management. The Bureau of Land Management's consent has recently been
received but is subject to a requirement in the financing documents that
certain additional title documentation be delivered to it, and that delivery is
currently in process. Once this assignment becomes effective, the Coso
partnerships will assume all of Coso Land Company's obligations under the LADWP
leases and will reimburse Coso Land Company for the costs it incurred in
acquiring the LADWP leases. These costs were approximately $1.0 million. See
"Summary Description of Principal Agreements Relating to the Coso Projects--The
LADWP Leases."
The Coso partnerships' use of the geothermal resources at BLM North will be
governed by a co-tenancy agreement. Under the co-tenancy agreement, each Coso
partnership will have the right, subject to applicable consents, to use BLM
North for geothermal resource production and injection
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purposes if it determines, in its exercise of reasonable business judgment,
that it has insufficient steam economically available to it from other sources.
Power Sales
The Coso partnerships sell all of the electrical energy generated at the
plants to Edison under three substantially similar long-term Standard Offer No.
4 power purchase agreements. Under the power purchase agreements, the Coso
partnerships receive capacity payments for being able to produce electricity at
certain levels, capacity bonus payments if they are able to produce above a
specified higher level and energy payments based on the amount of electricity
their plants actually produce. The capacity and capacity bonus payment rates
are fixed throughout the lives of the power purchase agreements. Energy
payments are fixed for the first ten years of firm operation under the power
purchase agreements. After the ten-year fixed energy price period expires, the
Coso partnerships sell their electricity to Edison based on Edison's avoided
cost of energy. Edison's avoided cost of energy is Edison's cost to generate
electricity if Edison were to produce it itself or buy it from another power
producer rather than buy it from the Coso partnerships. See "--Power Sales--
Energy Payments" and "Business--Legal Proceedings."
The Navy I partnership's power purchase agreement expires in August 2011, the
BLM partnership's power purchase agreement expires in March 2019 and the Navy
II partnership's power purchase agreement expires in January 2010. See "Summary
Descriptions of Principal Agreements Relating to the Coso Projects--Power
Purchase Agreements."
Capacity and Capacity Bonus Payments
The Navy I partnership receives levelized firm capacity payments of $161.20
per kW year, the BLM partnership receives levelized firm capacity payments of
$175.00 per kW year and the Navy II partnership receives levelized firm
capacity payments of $176.00 per kW year. Contract capacity levels must be
maintained during the on-peak periods of each month of an approximately four-
month long period, which currently runs from June through September, in each
year, for specified on-peak hours, at a rate equal to at least an 80.0%
contract capacity factor. There is a 20.0% allowance for certain forced outages
during the periods in each month in order to prevent a reduction in contract
capacity. The power purchase agreement for the Navy I partnership specifies a
contract capacity of 75 MW. The power purchase agreements for the BLM
partnership and the Navy II partnership specify a contract capacity of 67.5 MW
each. If a plant maintains the required 80% contract capacity factor during the
applicable periods, the annual capacity payment will be equal to the product of
the capacity payment per kWh stated in the power purchase agreements and the
contract capacity.
A Coso partnership may also receive capacity bonus payments to the extent
that its plant's on-peak capacity performance exceeds 85.0% during on-peak
hours in the months of June through September. From January 1, 1994 through
December 31, 1998, the Coso partnerships have earned an average capacity bonus
of approximately 97.0% of the maximum capacity bonus possible.
Energy Payments
The energy price component for electricity delivered to Edison is subject to
a different pricing mechanism during the first ten years of each power purchase
agreement, as discussed above. Edison has taken the position that the fixed
energy price period expired in August 1997 for the Navy I partnership and in
March 1999 for the BLM partnership, and will expire in January 2000 for the
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Navy II partnership. The Coso partnerships believe that the power purchase
agreements provide that each of the three turbine generator units at each
respective Coso project has its own full ten-year fixed energy price period.
This issue is one of several currently in dispute and subject to an ongoing
lawsuit between, among others, the Coso partnerships and Edison. Without making
any statement on the outcome of this or any other dispute with Edison, for
purposes of this prospectus only, including the historical and pro forma
financial information included herein, we have assumed that the fixed energy
price period expires ten years after the first of the three turbine generator
units at each respective Coso project established firm operation. We believe
that this assumption is conservative and reasonable for purposes of this
prospectus given that we cannot predict the outcome of this issue. See "Risk
Factors--The Coso partnerships and their managing partners are currently
involved in material litigation with Edison, their sole customer" and "--Legal
Proceedings."
Although energy payments paid to the Navy I partnership and the BLM
partnership are based upon 100% of Edison's avoided cost of energy, the way in
which avoided cost of energy is calculated (currently based on a formula tied
to the price of natural gas) is changing pursuant to the restructuring of the
California electricity market. Under AB1890, the comprehensive restructuring
legislation enacted in California in September 1996, the California Public
Utilities Commission is required to calculate the short-term avoided cost of
energy for payments made to non-utility power generators, such as the Coso
projects, based on the clearing price paid by the California Power Exchange
when certain conditions are met. These conditions include that (1) the
California Public Utilities Commission has issued an order determining that the
California Power Exchange is "functioning properly" and (2) either:
(a) The fossil-fired generation units owned by the purchasing utility
(such as Edison, San Diego Gas & Electric Company or Pacific Gas &
Electric Company) are authorized to charge market-based rates and
the variable costs of such units are being recovered solely through
clearing prices being paid by the California Power Exchange or from
contracts with the ISO; or
(b) The purchasing utility has divested ninety percent of its gas-fired
generation facilities that were operated to meet load in 1994 and
1995.
Divestiture of such gas-fired generation facilities by Edison and the other two
large California utilities is expected to be complete by the end of 1999.
It is likely that within the next two or three years, pursuant to AB1890,
Edison's short-term avoided cost of energy will equal the then-prevailing
market clearing price for wholesale energy at the California Power Exchange.
Whether this pricing will be on an hourly basis, a daily or block average basis
(i.e., a daily average, daily off-peak or daily on-peak time period averages)
or some other variation has not been determined. The market clearing prices for
wholesale energy on the California Power Exchange have occasionally for brief
periods exceeded current energy prices paid by Edison under the power purchase
agreements based on its short-term avoided cost of energy. This has occurred
most often during high load conditions, warm weather and other daily or
seasonal peak periods. At other times, the market clearing prices have been
lower than Edison's short-term avoided cost of energy. No one can predict the
outcome of the final implementation of this change in computing short-term
avoided cost of energy, or the performance of California Power Exchange
clearing prices over time. For further information, see "Risk Factors--Future
energy payments paid by Edison to the Coso partnerships will most likely be
less than historical energy payments because they will be paid based on
Edison's avoided cost of energy," "Risk Factors--The operations of the Coso
projects could be adversely affected by an inability to comply with regulatory
standards" and "Regulation."
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The electric industry in California has changed dramatically as a result of
recent decisions by the California Public Utilities Commission and the
enactment of AB1890 in September 1996. The new California electric market
structure, including the ISO PX system, commenced operations on March 31, 1998.
The California Power Exchange, through which Edison is required to sell power
generated by QFs, is responsible for managing the transactions for all power
auctioned through, and purchased by, market participants except those bound by
contract. The complex grid operation, software, forecasting, bidding and market
clearing mechanism of the ISO PX system has a limited operating history. Many
elements of the new market structure present novel regulatory issues that have
not yet been resolved, as well as many practical issues of implementation such
as the development of systems, software and procedures for:
. the California Power Exchange, which provides the auction process to
match electricity supply and demand;
. the independent system operator, or ISO, which has operational control of
the transmission facilities of electrical utilities (including Edison);
and
. all of the market participants who will transact with the ISO PX system.
If the still-developing ISO PX system fails or does not operate as
anticipated, electricity generation, transmission and distribution in
California may be materially and adversely affected. Edison's business may also
be materially and adversely affected. Furthermore, since Edison's avoided cost
of energy ultimately will be tied to the clearing price of the California Power
Exchange, the ISO PX system's functionality will have a significant effect on
the Coso partnerships.
Steam Sharing Program
The Coso partnerships have previously implemented and intended to expand the
steam sharing program which they established among the Coso projects under a
Coso Geothermal Exchange Agreement they entered into in 1994. The purpose of
the steam sharing program is to enhance the management, and to optimize the
overall use, of the Coso geothermal resource. Pursuant to the steam sharing
program, the Coso partnerships constructed an inter-project steam supply and
water injection system which links the three Coso projects and BLM North
together via metered transfer lines through which the Coso partnerships
exchange steam and other geothermal resources with one another.
As part of the steam sharing program, the Coso partnerships plan to conserve
the geothermal resource whenever possible by, among other things, transferring
steam between and among the Coso projects and BLM North, rather than drilling
new wells at the Coso projects' sites prematurely, and expanding a flexible
field-wide water reinjection program. See "--Power Production Process." While
each of the Navy and the Bureau of Land Management has consented to the steam
sharing program, each has reserved the right, in its sole discretion, to
withdraw its consent to such transfers under certain circumstances. See "Risk
Factors--The Navy could terminate the Coso partnerships' rights to use the Coso
geothermal resource at any time" and "Summary Description of Principal
Agreements Relating to the Coso Projects--Steam Sharing and Co-Tenancy
Agreements."
In 1998, the Navy I partnership and the Navy II partnership paid aggregate
royalties to the Navy of approximately $5.6 million for steam transferred by
Navy I to Navy II and by Navy II to BLM under the steam sharing program from
geothermal resources located on the property on which Navy I or Navy II, as the
case may be, are situated. Of this amount, the Navy I partnership paid
approximately $1.4 million and the Navy II partnership paid approximately $4.2
million. The BLM
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partnership reimbursed the Navy II partnership approximately $1.4 million of
the royalties paid by Navy II partnership. The BLM partnership did not pay a
royalty for electricity generated by BLM for steam transferred from Navy
property and sold to Edison.
Operations and Maintenance
The operations and maintenance services for the Coso projects, including Navy
I, BLM and Navy II, the Navy I Transmission Line and the BLM/Navy II
Transmission Line, the wells, the gathering system and the other related
facilities, are performed by FPL Operating and Coso Operating Company on behalf
of the Coso partnerships pursuant to three separate O&M agreements with each of
FPL Operating and with Coso Operating Company, each dated February 25, 1999.
See "Summary Descriptions of Principal Agreements Relating to the Coso
Projects--O&M Fees; Reduction in Fees."
Until February 25, 1999, CalEnergy had been the exclusive operator of the
Coso projects. Since that date, FPL Operating, an indirect wholly owned
subsidiary of FPL Energy, Inc., has been operating and maintaining the Coso
projects' plants, the transmission lines and the geothermal fields under three
separate short-term O&M agreements. FPL Energy, Inc. is an indirect, wholly
owned subsidiary of FPL Group, Inc., the parent holding company of Florida
Power & Light Company, one of the largest investor-owned utilities in the
United States. FPL Energy, Inc. was formed in 1998 to consolidate operations of
the unregulated energy business sectors involved in domestic and international
power generation. Florida Power & Light Company operates plants in its electric
generating system with a combined capacity of approximately 15,500 MW. FPL
Operating currently operates 56 electric generating facilities in the United
States with a combined generating capacity of 3,933 MW. FPL Operating is
managed by the same central operating group that operates the majority of
Florida Power & Light Company's electric generating stations. The Coso
partnerships and Coso Operating Company have been negotiating with FPL
Operating and its affiliates to acquire all of the equity interests in the Navy
I partnership held by one of FPL Operating's affiliates and to terminate the
existing O&M agreement with FPL Operating. See "Prospectus Summary--Recent
Developments--Negotiating with FPL Operating and its Affiliates."
Coso Operating Company is a wholly owned subsidiary of Caithness Acquisition.
It was initially formed by CalEnergy to facilitate the transfer of operational
control of the Coso projects to Caithness Energy's affiliates. Since February
25, 1999, Coso Operating Company has been managing the geothermal resource,
including well drilling, under three additional fixed price O&M agreements. See
"Summary Descriptions of Principal Agreements Relating to the Coso Projects--
O&M Fees."
Royalty and Revenue-Sharing Arrangements
The Coso partnerships are required to make royalty payments to, and are
subject to other revenue-sharing arrangements with, the Navy, the Bureau of
Land Management and certain other persons.
Navy I
Under the Navy Contract, as a royalty for Unit 1 at Navy I, the Navy I
partnership is obligated to reimburse partially the Navy for electricity
supplied to it by Edison from electricity generated at Navy I. The
reimbursement payment is based upon a pricing formula included in the Navy
Contract. For the year ended December 31, 1998, the Navy I partnership
reimbursed the Navy approximately
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76.0% of the aggregate price paid by the Navy to Edison for electricity
supplied to it by Edison. The percentage rate of reimbursement changes
semiannually, but cannot exceed 95% of the price paid by the Navy to Edison, in
accordance with a weighted index based on the Consumer Price Index and price
indices for the oil industry, the electric power plant industry and the
construction industry.
In addition, with respect to Unit 1 at Navy I, the Navy I partnership is
obligated to pay the Navy the sum of $25.0 million on or before December 31,
2009, the expiration date of the term of the Navy Contract. Payment of this
obligation will be made from an established sinking fund to which the Navy I
partnership has been making payments since 1987. As of March 31, 1999, there
was approximately $7.8 million on deposit in this sinking fund, representing
both sinking fund payments made by the Navy I partnership and accrued interest
thereon. The Navy I partnership currently intends to make aggregate annual
payments to this sinking fund of approximately $716,000 through 2009. Amounts
currently on deposit in the sinking fund, along with future deposits in the
sinking fund and interest accruing thereon, are being, and will be, held in an
escrow account by a financial institution for the benefit of the Navy.
For Units 2 and 3 at Navy I, the Navy I partnership's royalty expense is a
fixed percentage of its electricity sales to Edison. The royalty expense is
15.0% of revenues received by the Navy I partnership through 2003 and will
increase to 20.0% from 2004 through 2009, the expiration date of the Navy
Contract. See "Summary Descriptions of Principal Agreements Relating to the
Coso Projects--The Navy Contract." In the year ended December 31, 1998, the
Navy I partnership paid aggregate royalties to the Navy of approximately $6.8
million, based on the current royalty rate of 15%.
BLM
The BLM partnership pays royalties to the Bureau of Land Management under the
BLM lease. The royalty rate is 10% of the value of the steam produced by the
BLM partnership. This royalty rate is fixed for the life of the BLM Lease. In
1998, the BLM partnership paid aggregate royalties of approximately $6.0
million to the Bureau of Land Management.
In addition to this royalty, the BLM partnership is obligated to pay a
royalty to Coso Land Company, a general partnership of which Caithness
Acquisition and another affiliate of Caithness Energy are the general partners,
in connection with the assignment of the BLM lease to the BLM partnership. See
"Certain Relationships and Related Transactions--Royalty to Coso Land Company."
Navy II
The Navy II partnership pays royalties to the Navy under the Navy Contract.
The Navy II partnership's royalty expense is a fixed percentage of its
electricity sales to Edison. The royalty rate is 10.0% of electricity sales to
Edison through 1999, and will increase to 18.0% from 2000 through 2004 and to
20.0% from 2005 through the end of the initial term. See "Summary Descriptions
of Principal Agreements Relating to the Coso Projects--The Navy Contract." For
the year ended December 31, 1998, the Navy II partnership paid aggregate
royalties of approximately $11.9 million to the Navy, based on the current
royalty rate of 10%.
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BLM North
Coso Land Company has applied to the Bureau of Land Management for assignment
to each Coso partnership of an undivided one-third interest in the LADWP leases
as a tenant-in-common. This assignment is subject to the consent of the Bureau
of Land Management. The Bureau of Land Management's consent has recently been
received but is subject to a requirement in the financing documents that
certain additional title documentation be delivered to it, and that delivery is
currently in process. Once this assignment becomes effective, the Coso
partnerships will be required to pay $8.00 per acre in rent and additional rent
to the Bureau of Land Management. When a leased property commences to produce
geothermal steam, the Coso partnerships will pay monthly royalties under the
LADWP leases of 10% of the amount or value of the steam produced, 5% of any by-
products and 5% of commercially demineralized water. The Bureau of Land
Management may establish minimum production levels and reduce the foregoing
royalties if necessary to encourage the greater recovery of leased resources,
or as otherwise justified. Until this assignment becomes effective, Coso Land
Company will be required to make the above payments to the Bureau of Land
Management. See "--Overview of the Coso Projects--BLM North" and "Summary
Descriptions of Principal Agreements Relating to the Coso Projects--The LADWP
Leases."
Insurance
The Coso partnerships currently maintain property, business interruption,
catastrophe and general liability for the Coso projects. The plants are insured
for $600.0 million per occurrence for general property damage (limited to
replacement costs) and $240.0 million per occurrence for business interruption,
subject to a $25,000 deductible for property damage (and a $250,000 deductible
for the turbine generator sets), with a 15-day deductible for business
interruption and a 25-day deductible for machinery breakdown and earthquake.
Catastrophic insurance (including earthquake and flood) is capped at $200.0
million for property damage, subject to a deductible of $2.5 million or 5.0% of
the loss, whichever is greater. Liability insurance coverage is $51.0 million
(occurrence based). Operators' extra expense (control of well) insurance is
$10.0 million per occurrence with a $25,000 deductible. The above policies were
issued by international and domestic carriers and syndicates with each company
rated A- or better by A.M. Best Co. Inc.
As part of the Series A notes offering, the Coso partnerships obtained title
insurance policies in the aggregate amount of $200.0 million in favor of the
Trustee. Primarily because of the nature of the rights obtained by one or more
of the Coso partnerships from the Navy and the Bureau of Land Management, the
insurance coverage afforded by these policies is narrower, and the exceptions
to coverage are broader, then those which are commonly provided to companies
that are engaged in activities similar to those of the Coso partnerships. No
one can assure you that the title insurer or its reinsurers will be willing or
able to satisfy any claims which may be made under those policies. Also, the
coverage amounts may not be sufficient to satisfy amounts outstanding under the
senior secured notes at any given time. See "Risk Factors--Although the Coso
partnerships currently maintain insurance, loss proceeds might not be enough to
satisfy our obligations under the Series B notes."
Employees
We do not have any employees, and neither do the Coso partnerships. All of
the employees who operate and maintain the Coso projects are currently employed
by FPL Operating and Coso Operating Company. FPL Operating and Coso Operating
Company have retained substantially the
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same employees previously employed by CalEnergy, the prior operator. As of May
1, 1999, FPL Operating employed 102 employees at the Coso projects, and Coso
Operating Company employed 15 employees at the Coso projects. Approximately 70%
of the employees who currently work at the Coso projects' sites have been
employed there since 1992.
None of FPL Operating's or Coso Operating Company's employees are covered by
any collective bargaining agreement. We believe that FPL Operating's and Coso
Operating Company's employee relations are good.
Environmental Matters
The Coso partnerships are subject to environmental laws and regulations at
the federal, state and local levels in connection with their development,
ownership and operation of the Coso projects. These environmental laws and
regulations generally require that a wide variety of permits and governmental
approvals be obtained to construct and operate an energy-producing facility.
The facility must then operate in compliance with the terms of these permits
and approvals. If the Coso partnerships fail to operate the facility in
compliance with applicable laws, permits and approvals, governmental agencies
could levy fines or curtail operations.
We believe that each of the Coso partnerships is in compliance in all
material respects with all applicable environmental regulatory requirements
applicable to its Coso project, and we believe that maintaining compliance with
current governmental requirements will not require a material increase in
capital expenditures or materially adversely affect that Coso partnership's
financial condition or results of operations. It is possible, however, that
future developments, such as more stringent requirements of environmental laws
and enforcement policies thereunder, could affect capital and other costs at
the Coso projects and the manner in which the Coso partnerships conduct their
business.
Legal Proceedings
Edison Litigation
On June 9, 1997, Edison filed a lawsuit in the Superior Court of Los Angeles
County (later transferred to Inyo County), California, against CalEnergy, the
Coso partnerships and the managing partners of the Coso partnerships--China
Lake Operating Company, now known as New CLOC; Coso Technology Corporation, now
known as New CTC; and Coso Hotsprings Intermountain Power, Inc., now known as
New CHIP. We collectively refer to the defendants in Edison's lawsuit as the
Coso Parties. In this lawsuit, Edison asserts breach of contract claims against
the Coso Parties that relate to the alleged surreptitious venting of certain
non-condensable gases from unmonitored reinjection wells located adjacent to
the plants. The Coso Parties have been vigorously defending themselves against
Edison's claims.
The events relating to Edison's breach of contract claims date back to the
late 1980's and mid-1990's, and focus on the plants' initial period of
operations. The plants had difficulty at that time achieving full compliance
with applicable air quality district regulations which, the Coso Parties
believe, was due in large part to defective equipment installed during the
construction of the plants, as more fully discussed below. As a result, the
Coso partnerships self-reported to the Great Basin Unified Air Pollution
Control District a series of instances of venting primarily from the plants,
and the Great Basin Unified Air Pollution Control District issued Notices of
Violations (which are the functional equivalent of an allegation, not an
adjudication of any violation). The Coso partnerships
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chose not to contest these Notices of Violations and paid the agreed-upon
fines. There was no formal finding that any environmental violations occurred.
Edison does not base its claims against the Coso Parties on this self-
reported venting. Rather, Edison alleges that CalEnergy, the prior operator of
the plants, surreptitiously vented hydrogen sulfide gas from unmonitored
reinjection wells in violation of applicable operating permits and
environmental laws and regulations. Edison alleges that the Coso partnerships
did not report some or all of these alleged violations and breached their
contractual obligations to comply with all applicable laws, rules and
regulations. Edison argues that a provision in the power purchase agreements
requiring the Coso partnerships to comply with applicable laws, rules and
regulations allows it to seek damages for any such failures. Edison also
asserts that the output of the plants would have been lower but for the alleged
surreptitious venting.
Originally, Edison sought to terminate the three power purchase agreements
with the Coso partnerships and to recover damages equal to the total amount
Edison had paid for electricity delivered by the Coso partnerships to Edison
since inception. In June 1998, the Coso partnerships obtained a ruling from the
trial court dismissing Edison's efforts to terminate the three power purchase
agreements. In addition, the trial court ruled that Edison could not recover
damages based on the total amount that Edison had paid to the Coso partnerships
for electricity delivered under the power purchase agreements. Edison's damage
theory is now limited to breach of contract damages for energy deliveries which
it believes were higher than they would have been had the alleged surreptitious
venting not occurred. Edison seeks damages spanning an extended period of time
based on the difference between the contract price it paid to the Coso
partnerships for the excess electricity they allegedly delivered and the spot
market price it would have paid for the amount of such excess electricity.
In October 1997, the Coso Parties filed a motion for summary judgment arguing
that Edison's claims were barred by the 1993 Settlement Agreement (as defined
below) and that the statute of limitations for Edison's claims had expired. In
June 1993, Mission Power Engineering Company, a California corporation, and The
Mission Group, a California corporation (collectively, the "Mission Entities"),
on behalf of themselves and their respective subsidiaries and affiliates,
including Edison, and CalEnergy and the Coso partnerships, for themselves and
on behalf of their respective subsidiaries and affiliates, entered into a
Settlement Agreement and Release dated June 9, 1993 (the "1993 Settlement
Agreement"). The Mission Entities were at that time, and still are, affiliates
of Edison. The 1993 Settlement Agreement resolved, among other things, certain
claims the Coso partnerships asserted against the Mission Entities for the
Mission Entities' alleged defective construction of the Coso projects.
Pursuant to three "turnkey" engineering procurement and construction
contracts entered into in the late 1980's, the Mission Entities had agreed to
construct Navy I, BLM and Navy II so that these plants operated in compliance
with all applicable laws, rules and regulations. The Coso partnerships' claims
against the Mission Entities related in significant part to the Mission
Entities' alleged breach of this contractual provision. The 1993 Settlement
Agreement also provided for mutual releases of claims, whether known or
unknown, arising out of or relating to the construction of the Coso projects.
The trial court denied the Coso Parties' motion for summary judgment, finding
that triable issues of fact existed. The Coso Parties also assert other
defenses, including, among others, that Edison's claims for damages are not
causally related to the alleged venting and do not state legally cognizable
claims.
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In September 1997, the Coso Parties filed a cross-complaint against Edison
and the Mission Entities. In its present form, the cross-complaint alleges,
among other things, breach of contract claims, violations of state law and of
decisions rendered by the California Public Utilities Commission, and that
Edison's lawsuit constitutes a breach of the 1993 Settlement Agreement. The
Coso partnerships have each asserted three separate breach of contract claims
against Edison under the power purchase agreements and are seeking damages in
excess of $125 million, exclusive of interest, accruing through the life of the
respective applicable contractual provisions. The three breach of contract
claims are as follows:
. First, Edison has refused to pay the forecasted energy prices as to each
of the three units at each respective Coso project--Navy I, BLM and Navy
II--for the full ten-year "First Period" under the power purchase
agreements. Edison has taken the position that the power purchase
agreements provide that, with respect to each Coso project, the First
Period expires ten years after the first unit for each respective Coso
project established firm operation. This would mean that the fixed energy
price period expired in August 1997 for the Navy I partnership and in
March 1999 for the BLM partnership, and will expire in January 2000 for
the Navy II partnership. The Coso partnerships argue, in contrast, that
the power purchase agreements provide that each of the three units at
each respective Coso project has its own full ten-year fixed energy price
period. This would mean, for example, that each of Units 1, 2 and 3 at
Navy I has its own separate ten-year fixed energy price period. Under
Edison's position, the fixed energy price periods for Units 2 and 3 at
Navy I end at the same time that Unit 1's fixed energy price period ends
because Unit 1 was the first unit at Navy I to establish firm operation;
accordingly, the fixed energy price periods for Units 2 and 3 are less
than ten years.
. Second, Edison has refused to accept the Coso partnerships' election of a
simultaneous purchase and sale arrangement under which Edison is
obligated to pay the full forecasted price for all energy produced by the
Coso projects, without deduction for power used by the plants and their
related operations, and to serve the Coso partnerships' power needs under
a tariff applicable to industrial customers. Instead of accepting the
Coso partnerships' election, Edison has paid the Coso partnerships for
only the net amount of electricity delivered to Edison.
. Third, Edison has refused to extend and escalate the price tables
included in the power purchase agreements for the full ten-year fixed
energy price period of forecasted prices. The Coso partnerships argue
that Edison attached the wrong price tables to the power purchase
agreements because the tables leave out the years 1999 and 2000.
While we strongly dispute Edison's positions and believe the Coso
partnerships' positions are the correct interpretations of the power purchase
agreements, we have assumed, for purposes of this prospectus only, including
the historical and pro forma financial information included herein, that (1)
the full ten-year period expires after the first of the three units at each
respective Coso project established firm capacity, (2) the Coso partnerships
cannot make the election of a simultaneous purchase and sale arrangement and
(3) the pricing tables included in the power purchase agreements are correct.
We believe that this assumption is conservative and reasonable for purposes of
this prospectus given that we cannot predict the outcome of this issue.
On September 9, 1997, the Coso partnerships filed a separate lawsuit in the
Superior Court of Inyo County, California, against Edison seeking restitution
and injunctive relief for unfair competition and false advertising. The unfair
competition claim raises a series of electric industry
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issues concerning Edison's alleged program of anti-competitive activities aimed
at QFs, such as the Coso projects, and at other competitors, including electric
service providers or "ESPs." The Coso partnerships have also alleged that
Edison willfully violated decisions and orders of the California Public
Utilities Commission, which includes a claim for punitive damages in an
unspecified amount.
In December 1997, the Superior Court consolidated Edison's and the Coso
partnerships' lawsuits into one proceeding. The parties to the consolidated
actions had been engaged in extensive discovery and motion practice, discovery
(other than expert discovery) was scheduled to be completed by December 31,
1999 and a trial date had been set for March 1, 2000.
However, these dates have been vacated, and no new dates have been set,
pursuant to a stipulation entered into by the parties and an order of the trial
court. In essence, Edison and the Coso Parties have agreed to a moratorium on
all ongoing activities in these lawsuits from March 29, 1999 to September 30,
1999, in order to explore the possibility of reaching a negotiated settlement.
Edison and the Coso Parties have agreed to attempt to mediate their disputes
and have scheduled a mediation session for the week of September 7, 1999,
before a former California supreme court justice. If the parties are unable to
reach a negotiated settlement by September 30, 1999, the lawsuits will continue
where they left off, and the court will probably set a trial date for late
spring or early summer of 2000.
Neither we, the Coso partnerships nor anyone else can predict at this time
whether Edison will prevail on its claims against any or all of the Coso
Parties or whether any or all of the Coso Parties will prevail on their claims
against Edison, in part because pre-trial discovery has not been completed and
is now subject to the moratorium and because of the complexity of the factual
and legal issues involved. Further, no one can give you any assurance that the
parties will be able to reach a negotiated settlement of the lawsuits and, if
they do, what the terms of such a settlement would be. It is possible that the
parties will be unable to reach a settlement and Edison could recover
significant damages. Edison has not yet provided the Coso Parties with any
calculation or estimate of its alleged damages but, if the parties are unable
to reach a negotiated settlement, the Coso Parties expect Edison to seek
damages in an amount which would be material to the financial condition and
results of operations of the Coso partnerships, either individually or taken as
a whole.
Dow litigation
In addition, the BLM partnership is currently involved in an arbitration
proceeding against Dow Chemical Company ("Dow"). The BLM partnership is seeking
to recover certain damages incurred by the BLM partnership prior to 1998 as a
result of problems associated with the installation by Dow in 1992 of a
hydrogen sulfide abatement system at BLM. See "--Power Production Process." The
arbitration proceeding is a result of a settlement agreement entered into
between the BLM partnership and Dow in 1997 in which Dow stipulated to the
issue of its liability based on negligent misrepresentation. Dow has not made
any claims against the BLM partnership in the arbitration proceeding.
Fuji litigation
In March 1998, China Lake Plant Services, Inc., one of our affiliates, and
the Coso partnerships filed a lawsuit in Superior Court of the State of
California, County of Orange (Case No. 791982), against Fuji Electric Co., Ltd.
and Fuji Electric Corporation of America for breach of warranty related to the
Coso partnerships' nine geothermal turbine rotors. The Coso partnerships sought
to
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recover repair costs and other damages totaling approximately $16.0 million
incurred as a result of vibrations alleged to have occurred during operations,
which resulted in cracking and one catastrophic failure. Fuji has not made any
counterclaims against the Coso partnerships. The lawsuit is scheduled for trial
in February 2000.
However, on June 23, 1999, the parties to the lawsuit entered into a
Settlement Agreement and Mutual Release which provides for the settlement of
the breach of warranty claims made against Fuji and releases of all parties
with respect to the subject matter of the lawsuit if the parties satisfy
several specific conditions. If these conditions are satisfied, the lawsuit
will be dismissed with prejudice. We cannot assure you that all of the specific
conditions will be satisfied and, therefore, that the lawsuit will not go to
trial as scheduled.
Except as otherwise described above, the Coso partnerships are currently
parties to various minor items of litigation, none of which, if determined
adversely, would be material to the financial condition and results of
operations of the Coso partnerships, either individually or taken as a whole.
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SUMMARY DESCRIPTIONS OF PRINCIPAL
AGREEMENTS RELATING TO THE COSO PROJECTS
The following is a summary of selected provisions of certain principal
agreements relating to the Coso projects. It is not a full statement of the
terms of those agreements. Accordingly, the following summaries are qualified
by reference to each of those agreements and are subject to the terms of the
full text of each of those agreements. You can obtain copies of these
agreements from us upon request (subject to possible confidentiality
restrictions). See "Available Information."
Power Purchase Agreements
In 1983 and 1984, China Lake Joint Venture negotiated three separate long-
term Standard Offer No. 4 power purchase agreements with Edison. Subsequently,
the first power purchase agreement was assigned to the Navy I partnership for
Navy I, the second power purchase agreement was assigned to the BLM partnership
for BLM and the third power purchase agreement was assigned to the Navy II
partnership for Navy II. Under the terms of the power purchase agreements, the
Coso partnerships have agreed to sell to Edison, and Edison has agreed to
purchase, the electrical output at Navy I, BLM and Navy II. The power purchase
agreement between each Coso partnership and Edison requires that the Coso
partnership maintain the QF status of its Coso project throughout the contract
term. Set forth below is a summary of certain terms and provisions contained in
each power purchase agreement.
General
Each power purchase agreement provides for the sale to Edison of, in the case
of Navy I, 75 MW of capacity and, in the case of each of BLM and Navy II, 67.5
MW of capacity. Each power purchase agreement also provides for the sale to
Edison of all energy delivered at the point of interconnection, with electrical
service required to operate the Coso projects being supplied by Edison.
Terms of the Power Purchase Agreements
The term of the Navy I partnership's power purchase agreement expires in
August 2011, the term of the BLM partnership's power purchase agreement expires
in March 2019 and the term of the Navy II partnership's power purchase
agreement expires in January 2010. Each power purchase agreement is subject to
earlier termination in accordance with its terms. Upon the expiration of its
term, each power purchase agreement will remain in effect until either party
terminates the agreement upon 90 days' prior written notice.
Generating Facility
Under the power purchase agreements, each Coso partnership must operate its
generating facility in accordance with applicable utility industry standards,
good engineering practices, and any and all laws, and maintain any necessary
governmental authorizations and permits. Each Coso partnership must also
reimburse Edison for any loss which Edison incurs as a result of the Coso
partnership's failure to maintain necessary governmental authorization and
permits.
Under the power purchase agreements, Edison must pay the Coso partnerships
capacity payments, capacity bonus payments and energy payments in accordance
with each plant's electrical energy output.
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Capacity Payments
A plant qualifies for an annual capacity payment by meeting specified
performance requirements on a monthly basis during an approximately four-month
long on-peak period, which currently runs during the months of June through
September of each year. The basic performance requirement is that the plant
deliver an average kWh output during specified on-peak hours of each month in
the on-peak period at a rate equal to at least an 80% contract capacity factor.
The "contract capacity factor" equals (1) a plant's actual electricity output,
measured in kWhs, during the hours of measurement, divided by (2) the product
obtained by multiplying the plant's "contract capacity," as stated in the power
purchase agreement applicable to such Coso project, by the number of hours in
the measurement period. If a Coso project maintains the required 80% contract
capacity factor during the applicable periods, the annual capacity payment will
be equal to the product of the capacity payment per kWh stated in its power
purchase agreement and the contract capacity.
Navy I has a contract capacity of 75 MW, and the Navy I partnership has a
capacity payment per kW year of $161.20 for an annual maximum capacity payment
of approximately $12.1 million. BLM has a contract capacity of 67.5 MW, and the
BLM partnership has a capacity payment per kW year of $175.00 for an annual
maximum capacity payment of approximately $11.8 million. Navy II has a contract
capacity of 67.5 MW, and the Navy II partnership has a capacity payment per kW
year of $176.00 for an annual maximum capacity payment of approximately
$11.9 million. Although capacity prices per kWh remain constant throughout the
life of each power purchase agreement, Edison disburses capacity payments on a
monthly basis in accordance with a tariff schedule filed with the California
Public Utilities Commission. Payments are made unevenly throughout the year,
and are weighted toward the on-peak periods; currently, approximately 65% of
the capacity payments received by the Coso partnerships from Edison are paid
with respect to on-peak months, and 35% with respect to non-peak months.
Except when caused by an uncontrollable event, if a Coso partnership does not
satisfy the performance requirement, it may be placed on probation for up to 15
months, and, if the Coso partnership cannot satisfy the performance requirement
during the probationary period, Edison may derate the contract capacity factor
to a capacity equal to the greater of (1) the capacity actually delivered
during the period when the performance requirement was not met or (2) the
capacity at which the Coso partnership is reasonably likely to meet the
performance requirement. However, if the Coso partnership's failure to meet the
performance requirement is due to a forced outage on the Edison system or a
request by Edison to cease or curtail delivery, then Edison must continue to
make the full capacity payments. If a Coso partnership's energy deliveries are
interrupted or reduced due to an uncontrollable event, Edison must continue to
make full capacity payments to the Coso partnership for 90 days from the
occurrence of the uncontrollable event.
Capacity Bonus Payments
Each Coso partnership is entitled to receive capacity bonus payments during
both on-peak and non-peak months by operating at a contract capacity factor of
between 85% and 100% during on-peak hours of each month. A plant qualifies for
capacity bonus payments with respect to on-peak months provided that the plant
operates at least at an 85% contract capacity factor during the on-peak hours
of the month, and qualifies with respect to non-peak months if performance
requirements for on-peak months have been satisfied and the plant also operates
at a contract capacity factor of at least 85% during on-peak hours of the non-
peak month.
Capacity bonus payments for each month increase with the level of kWh
delivered between the 85% and 100% contract capacity factor levels during the
month. The annual capacity bonus payment
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for each month is equal to a percentage based on the plant's on-peak contract
capacity factor (which percentage may not exceed 18% of one-twelfth of the
annual capacity payment).
Energy Payments
In addition to capacity and capacity bonus payments, Edison must make monthly
energy payments to each Coso partnership based on the amount of kWh of energy
delivered by each plant. The energy price component for electricity delivered
to Edison is subject to different pricing mechanisms for the first ten years of
firm operation under each power purchase agreement than are applicable during
the remaining term of each agreement. During the first ten years following the
commencement of firm operation, the energy price per kWh varies between so-
called on-peak and non-peak periods, but the average of these prices equals a
fixed price per kWh specified in the power purchase agreements. After the first
ten years of firm operation and until its power purchase agreement expires,
Edison makes or will make energy payments to a Coso partnership based on
Edison's avoided cost of energy.
Edison has taken the position that the fixed energy price period expired in
August 1997 for the Navy I partnership and in March 1999 for the BLM
partnership, and will expire in January 2000 for the Navy II partnership. The
Coso partnerships believe that the power purchase agreements provide that each
of the three separate turbine generator units at each Coso project has its own
full ten-year fixed energy price period. This issue is one of several currently
in dispute and subject to an ongoing lawsuit between, among others, the Coso
partnerships and Edison. Without making any statement on the outcome of this or
any other dispute with Edison, for purposes of this prospectus only, including
the historical and pro forma financial information included herein, we have
assumed that the fixed energy price period expires ten years after the first of
the three generator units at each respective Coso project established firm
operation. We believe that this assumption is conservative and reasonable for
purposes of this prospectus given that we cannot predict the outcome of this
issue. See "Risk Factors--The Coso partnerships and their managing partners are
currently involved in material litigation with Edison, their sole customer" and
"Business--Legal Proceedings."
After the expiration of the fixed energy price period under the power
purchase agreements, Edison's monthly energy payment equals the product of the
kWh purchased by Edison for each on-peak, mid-peak, and off-peak time period
and Edison's published avoided cost of energy by time of delivery for each time
period. Edison's published avoided cost of energy is currently based on a
formula tied to the price of natural gas. Under AB1890, however, the California
Public Utilities Commission is required to calculate short-term avoided energy
costs for payments made to nonutility power generators such as the Coso
projects based on the clearing price paid by the California Power Exchange when
certain conditions are met. These conditions are discussed under the headings
"Risk Factors--Future energy payments paid by Edison to the Coso partnerships
will most likely be less than historical energy payments because they will be
paid based on Edison's avoided cost of energy" and "Business--Power Sales--
Energy Payments."
Changes in Contract Capacity
Each Coso partnership may terminate its power purchase agreement or reduce
its contract capacity by giving Edison the prescribed notice. Upon such
reduction, the Coso partnership must refund Edison an amount of money equal to
the difference between (1) the accumulated capacity payments already paid by
Edison up to the time the notice is received and based on the original contract
term and (2) the total capacity payments which Edison would have paid based on
the Coso partnership's actual performance using the "adjusted capacity price,"
as well as interest at the current published Federal Reserve Board three months
prime commercial paper rate on such amount.
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Testing
At least once a year, at the request of Edison, each Coso partnership must,
at its own expense, demonstrate the ability of its plant to produce the
contract capacity for a reasonable period of time pursuant to mutually agreed
upon procedures.
Outages
Each Coso partnership must make all reasonable efforts to limit the outages
of its generating facility. Each Coso partnership must also make reasonable
efforts not to schedule routine maintenance in the months of June, July, August
and September, and in no event shall outages for scheduled maintenance exceed a
total of 30 peak hours during those months. Outage periods for scheduled
maintenance may not exceed 840 hours in any 12-month period. Each Coso
partnership may accumulate unused maintenance hours on a year-to-year basis up
to a maximum of 1,080 hours. This accrued time must be used consecutively and
only for major overhauls.
Curtailment
After the first ten years following the commencement of firm operation,
Edison is not required to accept or purchase, and may request that the Coso
partnership discontinue or reduce delivery of, energy during periods when such
purchases would result in Edison incurring costs greater than those which it
would incur if it instead generated energy from another of its sources or when
its system demand would require that its hydro-energy be spilled to reduce
generation. The power purchase agreements limit such curtailment to not more
than 300 hours annually during off-peak hours.
Uncontrollable Forces
Each party to the power purchase agreements is relieved from its obligations
under the relevant power purchase agreement (except for payment obligations)
when and to the extent that it is rendered wholly or partly unable to perform
its obligations by an uncontrollable force, provided that the nonperforming
party (1) gives the other party written notice describing the particulars of
the uncontrollable force within two weeks after the occurrence thereof, (2)
uses its best efforts to remedy its inability to perform, and (3) does not
suspend performance beyond the scope or duration required by the uncontrollable
force. If one of the Coso partnership's deliveries to Edison are interrupted or
reduced due to an uncontrollable force, Edison is required to continue capacity
payments for 90 days from the occurrence of the uncontrollable force. If a
party's ability to perform cannot be corrected when the uncontrollable force is
caused by the actions or inactions of legislative, judicial or regulatory
agencies, or other proper authority, the relevant power purchase agreement may
be amended to comply with the legal or regulatory change which caused the
nonperformance. If a loss of QF status occurs due to uncontrollable force and
the relevant Coso partnership fails to make the changes necessary to maintain
its Coso project's QF status, that Coso partnership will be required to
compensate Edison for any economic detriment incurred by it as a result of such
failure. "Uncontrollable Forces" include, but are not limited to, flood,
drought, earthquake, storm, fire, pestilence, natural catastrophes, war, riot,
strike, action or inaction of legislative, judicial or regulatory agencies or
any occurrence beyond the control of the parties that cannot be overcome by the
exercise of due diligence.
Indemnification
Under the relevant power purchase agreement each party has agreed to
indemnify and hold harmless the other party, its directors, officers, and
employees or agents from and against any loss,
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damage, claim, cost, charge, and associated costs and expenses, related to the
injury to or death of any person or damage to the property of a third party
arising out of the indemnifying party's construction, engineering, repair,
supervision, inspection, testing, protection, operation, maintenance,
replacement, reconstruction, use, or ownership of its facilities, other than
for liability resulting from the indemnified party's sole negligence or willful
misconduct. Each party is also responsible for claims brought by its
contractors or employees and is required to indemnify and hold harmless the
other party for any such costs.
Insurance
Under the power purchase agreements, each Coso partnership is obligated to
obtain and maintain specified insurance coverages. If the Coso partnership
fails to maintain the required insurance, it must indemnify Edison for any
liabilities to the extent the insurance would have covered those liabilities.
Interconnection
The interconnection facility is designed, installed, operated and maintained
pursuant to an Interconnection and Integration Facilities Agreement.
The Navy Contract
In December 1979, CalEnergy entered into the Navy Contract with the Navy. The
Navy Contract granted to CalEnergy exclusive contractual rights to explore,
develop and use certain of the geothermal resource located within the United
States Naval Air Weapons Center at China Lake, California. Those rights were
subsequently transferred to China Lake Joint Venture, and certain of those
rights were subsequently transferred from China Lake Joint Venture to the Coso
partnerships. The Navy Contract has been modified on a number of occasions to
provide for, among other things, the assignment of all of China Lake Joint
Venture's rights under the Navy Contract to the Navy I partnership with respect
to Navy I and to the Navy II partnership with respect to Navy II, the
assignment of rights to the BLM/Navy II Transmission Line to Coso Transmission
Line Partners and the approval by the Navy of the steam sharing program among
the Coso partnerships. China Lake Joint Venture holds a residual interest in
the Navy Contract. For more information, see "Business--Overview of the Coso
Projects--Project History" and "--Steam Sharing and Co-Tenancy Agreements."
The term of the Navy Contract is for thirty years, expiring in December 2009,
after the last maturity date of the Series B notes. The Navy has the unilateral
right to extend the term of the Navy Contract for a ten-year period by giving
written notice. The Navy requires United States congressional approval to
exercise its option to extend the term of the Navy Contract.
Rights and Obligations
Under the Navy Contract, the Navy I partnership and the Navy II partnership
enjoy, among other things, exclusive contractual rights to explore, develop and
use a portion of the Coso Known Geothermal Area in an area covering
approximately 3,520 acres. It is possible that these rights do not constitute
interests in real estate. See "Business--Insurance." The Navy I partnership and
Navy II partnership enjoy all rights to the payments set forth in the Navy
Contract, including all payments by
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Edison under the power purchase agreements, and termination payments in the
event the Navy exercises its right to terminate the Navy Contract prior to the
expiration of its term.
With respect to Unit 1 at Navy I, the Navy I partnership is obligated to pay
the Navy the sum of $25.0 million on or before December 31, 2009, the
expiration date of the term of the Navy Contract. Payment of this amount will
be made from an established sinking fund to which the Navy I partnership has
been making payments since 1987. As of March 31, 1999, there was approximately
$7.8 million on deposit in the sinking fund, representing both sinking fund
payments and accrued interest thereon. The Navy I partnership currently intends
to make aggregate annual payments to this sinking fund of approximately
$716,000 through 2009. See "Management's Discussion and Analysis of Financial
Condition and Result of Operations--Liquidity and Capital Resources."
Both the Navy I partnership and the Navy II partnership are required to pay
to the Navy royalties or the equivalent thereof, for electricity generated by
Units 2 and 3 at Navy I and the three units at Navy II. The percentage royalty
due to the Navy for Units 2 and 3 of Navy I is 15% of revenues received through
2003, 20% from 2004 through 2009, and, if the Navy elects to extend the term of
the Navy Contract, 22.0% thereafter. The percentage royalty due to the Navy for
Navy II is 10% of electricity sales through 1999, 18% from 2000 to 2004, 20%
from 2005 through 2010, and, if the Navy elects to extend the term of the Navy
Contract, 22.0% thereafter.
Termination
The Navy has the right to terminate the Navy Contract under circumstances
that include the convenience of the Navy. The Navy has the right to terminate
the contract at any time by giving the Navy I partnership or the Navy II
partnership, or both, as applicable, six months' prior written notice for
"reasons of national security, national defense preparedness, national
emergency, or for any reasons the Contracting Officer shall determine that such
termination is in the best interest of the U.S. Government."
Upon the expiration of the Navy Contract, title to the wells and casings will
revert to the Navy with no remuneration to the Navy I partnership or the Navy
II partnership. Title to all of the fixtures, facilities and equipment will
remain with the Navy I partnership and Navy II partnership. However, the Navy
has an option to purchase all of the above mentioned fixtures, facilities and
equipment (at a price to be determined), or the Navy may require that the Navy
I partnership and the Navy II partnership remove the fixtures, facilities and
equipment within a reasonable time after expiration of the Navy Contract, at no
cost to the Navy.
If the Navy were to terminate the Navy Contract, the Navy would be required
to pay the Navy I partnership or the Navy II partnership or both, as
applicable, for the unamortized portion of their exploratory investment and for
their investment in installed power plant facilities. There is a cap on the
amounts the Navy would be required to pay as compensation on such termination,
based on the nameplate capacity of the turbine generators. With respect to each
of the Navy I partnership and the Navy II partnership, for the first aggregate
25 MW, the cap is $2.7 million per MW, and for the next 25 MW (i.e., up to 50
MW), the cap is $2.5 million per MW. For 50 to 75 MW, the cap is $1.4 million
per MW for the Navy I partnership and $2.3 million per MW for the Navy II
partnership. For a total nameplate capacity of 75 MW for Navy I or Navy II, the
total cap in termination compensation would be $165.0 million for the Navy I
partnership and $187.5 million for the Navy II partnership. The total aggregate
termination compensation for the Navy I partnership and the Navy II partnership
would therefore be approximately $352.5 million. The Navy Contract does
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not provide for compensation to either the Navy I partnership or the Navy II
partnership for the loss of anticipated profits resulting from such termination
or to the BLM partnership for any detrimental effect on it from the termination
of the Navy Contract.
In addition to its right to terminate the Navy Contract, the Navy may, from
time to time, impose certain access and operational restrictions on the Navy I
partnership and the Navy II partnership for purposes of national security,
personnel safety, protection of property or protection of the environment, and
under certain circumstances may impose emission standards. The Navy has
periodically ordered all personnel at the Coso projects to evacuate the
facilities on several occasions. During evacuation periods, the operators
continue to operate the Coso projects via a remote station located at the
outskirts of the Navy base. This station currently utilizes rights of way that
CalEnergy originally obtained from the Bureau of Land Management. CalEnergy
recently assigned these rights of way to the Coso partnerships as tenants-in-
common with the approval of the Bureau of Land Management. See "Risk Factors--
The Navy could terminate the Coso partnerships' rights to use the Coso
geothermal resource at any time."
The BLM Lease
On April 29, 1985, CalEnergy and the Bureau of Land Management entered into
the BLM lease. Under the BLM lease, CalEnergy acquired a leasehold interest in
approximately 2,550 acres of land, including the contractual right to drill
for, extract, produce, remove, use, sell and dispose of the geothermal resource
thereon. The land is also located at the United States Naval Air Weapons Center
at China Lake. Through various assignments, effective May 1, 1988, the BLM
lease was assigned to the BLM partnership. The BLM Lease was recorded on May 9,
1988, as Instrument No. 88-2092, in the Official Records of Inyo County,
California, and the assignment to the BLM partnership was recorded on the same
date.
Coso Land Company intends to assign to the BLM partnership a leasehold
interest granted by the Bureau of Land Management in an additional parcel of
land (referred to as lease CA 11401) that is adjacent to the BLM lease. This
assignment is subject to the consent of the Bureau of Land Management. The
Bureau of Land Management's consent has recently been received but is subject
to a requirement in the financing documents that certain additional title
documentation be delivered to it, and that delivery is currently in process.
The leasehold interest will expire on November 17, 2002 unless extended by
production. In addition, Coso Land Company holds leasehold interests granted by
the Bureau of Land Management in certain additional leases from the Bureau of
Land Management. These additional leases are located within several miles of
the property covered by the BLM lease. These additional leases are not
currently producing any geothermal resources, are not expected to be needed for
the Coso projects and may be surrendered to the Bureau of Land Management or
allowed to expire.
The primary term of the BLM lease has expired. The BLM lease provides,
however, that the term of the BLM Lease will be extended automatically "so long
thereafter as geothermal steam is produced or utilized in commercial quantities
but shall in no event continue for more than forty (40) years after the end of
the primary term." This automatic extension due to the continuation of
production is termed being "held by production." Since the BLM lease is deemed
"held by production," the BLM lease has been automatically extended and the BLM
partnership continues to have rights under the BLM lease. The BLM partnership
also enjoys a preferential right of renewal of the BLM lease for an additional
40-year term if geothermal steam is being produced or utilized in commercial
quantities and the leased land is not needed for other purposes.
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Pursuant to the BLM lease, the Navy controls all activities on the surface of
the real property covered by the BLM lease. In addition, the BLM partnership
must comply with certain "Navy Constraints on Naval Weapon Center Lands." These
constraints include, among other things, certain security measures and
restrictions of access, the Navy's right to suspend operations if an imminent
threat to the environment is presented, permitting requirements, information
and data exchange, and the Navy's right of inspection. For related information,
see "--The Navy Contract." The Bureau of Land Management has retained the right
to grant easements and other rights of way to third parties with respect to the
leased property, so long as those rights do not create unnecessary or
unreasonable interference with the BLM partnership's activities or the
property.
The BLM partnership pays royalties to the Bureau of Land Management under the
BLM Lease. Royalties are 10% of the value of steam produced. This rate is fixed
for the life of the BLM Lease. The Bureau of Land Management has the right to
establish minimum and maximum production levels of steam after notice and a
hearing, and the right to reduce the royalty rate if necessary to encourage the
greater recovery of leased resources, or as otherwise justified.
BLM leases that are "held by production" or that are known to contain wells
capable of production of commercial qualities cannot be canceled without prior
notice and a hearing. BLM leases can also be terminated by operation of law, as
follows: (1) at the anniversary date, for failure to pay the full amount of the
annual rental by that date, and (2) at the end of the primary term, if there is
no production in commercial quantities, there is no producing well or actual
drilling operations are not being diligently prosecuted.
Upon termination of the BLM Lease, the BLM partnership is required to place
all wells in condition for suspension or abandonment, reclaim the land and,
within a reasonable time, remove all the equipment or improvements that the
Bureau of Land Management does not deem necessary for the preservation of
producible wells or protection of the environment.
O&M Agreements
O&M Agreements with FPL Operating
The Coso partnerships have entered into three separate O&M agreements with
FPL Operating. The initial term of these O&M agreements is for three years with
an automatic three year extension unless either party notifies the other party
at least 90 days prior to expiration that it does not intend to extend the term
of the O&M agreement. Except for certain services to be performed by Coso
Operating Company, the plant operation and maintenance services are performed
by FPL Operating pursuant to the O&M agreements. FPL Operating's O&M agreements
provide that FPL Operating will do all things necessary or advisable for the
proper operation and maintenance of the geothermal power facilities, the
interconnection to the transmission line, the geothermal wells and related
fluid handling, gathering and distribution systems and perform certain other
services specified in the O&M agreements. It will also operate and maintain the
Navy I Transmission Line and the BLM/Navy II Transmission Line.
FPL Operating's general duties include, among others:
. supervision of operations and maintenance at the plants, the
interconnection to the transmission lines, the wells and related fluid
handling, the gathering system and any and all technical and engineering
support required for such operations and maintenance;
. the purchase of all materials, supplies, consumables, parts, equipment,
vehicles, utilities and other items necessary to conduct normal
operations and maintenance;
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. scheduling all outages and maintenance shutdowns;
. contracting with third parties as may be necessary for the performance of
specialized services;
. maintaining safety and security programs;
. complying with applicable laws and obtaining and maintaining all
government permits, licenses and approvals required of FPL Operating in
connection with the operation of the Coso projects; and
. complying with all federal, state and local laws/ordinances and
regulations relating to industrial hygiene or releases to the
environment.
As compensation for such services, each Coso partnership has agreed to pay to
FPL Operating an annual fee of $134,000, $100,000 and $84,000 in the first,
second and third years, respectively, of the O&M agreements with FPL Operating
(or an aggregate of $402,000, $300,000 and $252,000, respectively). Adjustments
to the compensation may be made if a "Change of Conditions" occurs. A Change of
Conditions includes, among other things, modifications to the facility or the
power purchase agreements, directions from the Coso partnerships to perform
services different from, or in addition to, those originally contemplated, or
the occurrence of an uncontrollable event. In addition, each Coso partnership
has agreed to reimburse FPL Operating for all properly incurred costs and
expenses and reimburse FPL Operating for the performance incentive bonuses that
it pays its employees.
The Coso partnerships have the right under the O&M agreements with FPL
Operating to terminate those agreements upon six months' prior notice or under
certain circumstances, including the occurrence of a total or partial failure
of the geothermal wells and uncured defaults. FPL Operating also has the right
to terminate any of its O&M agreements with the Coso partnerships upon six
months' prior notice or under certain circumstances, including any material
uncured default by the relevant Coso partnership.
The Coso partnerships and Coso Operating Company have been negotiating with
FPL Operating and its affiliates to acquire all of the equity interests in the
Navy I partnership held by one of FPL Operating's affiliates and to terminate
the existing O&M agreements with FPL Operating. See "Prospectus Summary--Recent
Developments--Negotiating with FPL Operating and its Affiliates."
O&M Agreements with Coso Operating Company
The Coso partnerships have also entered into three field O&M agreements with
Coso Operating Company. The terms of these field O&M agreements expire on
December 31, 2009. Pursuant to these field O&M agreements, Coso Operating
Company provides certain services for the Coso projects, including among
others:
. exploring for new well sites, drilling new wells, and completing,
testing, and making available new wells for tie in to the resource
gathering systems of the Coso projects;
. drilling, testing, workover and repair work and making available new
wells to the disposal system;
. providing accounting, financial and tax services for the Coso
partnerships; and
. performing well workovers and related activities and all reservoir and
resource management related services and reservoir engineering and
geologic activities with respect to the field and sub-surface reservoir,
including:
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. scheduling and supervising well testing,
. well surveys,
. maintaining production data bases,
. reservoir modeling,
. identifying candidates for well workovers,
. acid jobs,
. providing reports on resource availability,
. declines,
. production projections,
. targeting new wells,
. providing three dimensional models of the reservoir,
. maintaining and distributing maps, and
. scheduling and supervising geologic geophysical and/or geochemical
surveys.
As compensation for such services, each Coso partnership has agreed to pay
Coso Operating Company an annual fee of $532,000, $400,000 and $334,000 in the
first, second and third years, respectively, of the O&M agreements with Coso
Operating Company (or an aggregate of $1.6 million, $1.2 million and $1.0
million, respectively). In addition, each Coso partnership has agreed to pay
all proper costs and expenses incurred by the Coso Operating Company and
reimburse Coso Operating Company for the performance incentive bonuses that
Coso Operating Company pays to its employees, as set forth in the O&M
agreements with Coso Operating Company.
The LADWP Leases
In 1997, LADWP assigned to Coso Land Company, one of our affiliates, all of
its rights and interests in certain wells and related equipment located at BLM
North. BLM North covers approximately 6,825 acres of land and is located
adjacent to the real property covered by the Navy Contract. Under the LADWP
leases, Coso Land Company has the right to drill for, extract, produce, remove,
use, sell and dispose of the geothermal resources located on BLM North. Coso
Land Company originally entered into the lease assignment with the LADWP to
obtain access to additional steam to supplement the steam available for
transfer among the Coso projects' plants under the steam sharing program.
Coso Land Company has applied to the Bureau of Land Management for assignment
to each Coso partnership of an undivided one-third interest in the LADWP leases
as a tenant-in-common. This assignment is subject to the consent of the Bureau
of Land Management. The Bureau of Land Management's consent has recently been
received but is subject to a requirement in the financing documents that
certain additional title documentation be delivered to it, and that delivery is
currently in process. Once this assignment becomes effective, the Coso
partnerships will assume all of Coso Land Company's obligations under the LADWP
leases and will reimburse Coso Land Company for the costs it incurred in
acquiring the LADWP leases. These costs were approximately $1.0 million.
The primary terms of two of the LADWP leases expire on December 24, 2002, and
the primary term of one of the LADWP leases expires on September 23, 2004. The
terms of the LADWP leases
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will be extended automatically "so long thereafter as geothermal steam is
produced or utilized in commercial quantities but shall in no event continue
for more than forty (40) years after the end of the primary term. This
automatic extension due to the continuation of production is termed being "held
by production." Coso Land Company enjoys, and after the effective date of the
assignment the Coso partnerships will enjoy, a preferential right of renewal of
the LADWP leases for an additional 40-year term so long as geothermal steam is
being produced or utilized in commercial quantities and the leased lands are
not needed for other purposes.
As of April 1, 1999, the Coso partnerships were producing steam from two
production wells located on one of the LADWP leases (referred to as LADWP lease
CA 11384) and were injecting fluids into an injection well located on a second
LADWP lease (referred to as LADWP lease CA 11385). Another well located on the
LADWP lease CA 11385 is capable of producing geothermal steam, but it has not
been connected to the Coso projects' gathering system. The Bureau of Land
Management has determined that LADWP lease CA 11384 is held by production.
LADWP lease CA 11385 should also be deemed "held by production" and, although
the Bureau of Land Management has not yet made that determination, we expect it
to be automatically extended as well, but we cannot assure you it will be.
Although the third LADWP lease (referred to as LADWP lease CA 11383) has no
wells on it. The Coso partnerships expect that they may produce steam in the
future from the property covered by the third LADWP lease.
Steam Sharing and Co-Tenancy Agreements
The Coso partnerships have implemented and intend to expand a steam sharing
program which they established under a Coso Geothermal Exchange Agreement,
which we call the steam sharing agreement, entered into by the Coso
partnerships in 1994 and amended in 1995. The purpose of the steam sharing
program is to enhance management of the Coso geothermal resource and to
optimize its overall benefits to the Coso partnerships. Pursuant to the steam
sharing agreement, the Coso partnerships constructed an inter-project steam
supply system which links the three Coso projects together via metered transfer
lines through which the Coso partnerships may exchange steam and other
geothermal resources with one another and thereby make optimum use of available
steam to maximum revenues at the Coso projects. As part of this program, the
Coso partnerships plan to conserve the geothermal resource whenever possible
by, among other things, (1) transferring steam between and among the Coso
projects and BLM North, rather than drilling new wells at the Coso projects'
sites prematurely, and (2) extending a flexible field-wide water reinjection
program.
The Coso partnerships' use of BLM North will be governed by a Cotenancy
Agreement that will provide for the shared ownership of the LADWP leases and
two rights of way granted by the Bureau of Land Management that pertain to (1)
an off-site location used for remote operation of the Coso projects when the
Navy orders evacuations of the plants and fields and (2) the telephone lines
used for the Coso projects. See "--The Navy Contract." Pursuant to this
agreement, the Coso partnerships will each hold, as tenants-in-common, an
undivided one-third working interest in the geothermal resources located at BLM
North. The Cotenancy Agreement will entitle each of the Coso partnerships,
subject to applicable consents, to use BLM North for geothermal resource
production and injection purposes if the Coso partnership determines, in its
exercise of its reasonable business judgment, that it has insufficient steam
economically available to it from other sources.
The steam sharing agreement requires that the Coso partnerships share equally
in the cost of the inter-project steam supply system and includes a formula
that is used to calculate the payments made between or among the Coso
partnerships. In addition, transfers of steam made pursuant to the steam
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sharing program generates royalties due by the Coso partnerships to the Navy
and the Bureau of Land Management. The formula for calculating the royalty due
to the Navy has been incorporated by modification into the Navy Contract and
has recently been amended to reflect the addition of the geothermal resources
located on land covered by the LADWP leases. The royalty due to the Bureau of
Land Management is governed by the underlying leases and an Agreement for the
Calculation of Minerals/Revenues that was entered into in 1994. Each of the
Navy and the Bureau of Land Management has provided the consents necessary for
transfers of steam between and among the Coso projects pursuant to the steam
sharing program, but it has, however, reserved the right to suspend, terminate
or withdraw its consent in its sole discretion under certain circumstances.
With respect to the use of the geothermal resources located under the land
covered by the LADWP leases, the Navy has currently consented only to use by
BLM of steam produced from those lands provided that any steam transferred from
property leased from the Bureau of Land Management to Navy I or Navy II must be
offset by transfers within the same month to BLM of steam from wells located on
property leased from the Navy. The reason for the Navy's limited consent is to
avoid the difficulties that arise by virtue of the fact that the energy price
paid to the Navy II partnership under its power purchase agreement remains
fixed rather than paid at Edison's avoided cost of energy. Once the fixed
energy price period at Navy II expires in January 2000, we anticipate that the
Navy will consent to additional transfers of steam between BLM North and the
Coso projects.
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REGULATION
Energy Regulation
PURPA
PURPA provides an electric generating project with rate and regulatory
incentives and exemptions if the project is a QF. There are two types of QFs:
Small Power QFs and Cogeneration QFs. Under PURPA, a power production facility
is a Small Power QF if (i) the facility satisfies certain maximum size
criteria, (ii) the primary energy source of the facility is biomass, waste,
renewable resources or any combination thereof, and 75% of the total energy
input is from these sources, and (iii) the facility is owned by a person not
primarily engaged in the generation or sale of electric power (other than
electric power solely from cogeneration facilities or small power production
facilities). The maximum size criteria, however, do not apply to a facility
that is an "eligible solar, wind, waste or geothermal facility," as defined in
Section 3(17)(E) of the Federal Power Act. A facility qualifies for this
exemption if: (1) it produces electric energy solely by the use, as a primary
energy input, of solar, wind, waste or geothermal resources; (2) an application
for certification or a notice of self-certification of qualifying status of the
facility was submitted to the FERC prior to December 31, 1994; and (3)
construction of the facility commenced prior to December 31, 1999. The Coso
projects have satisfied these requirements and thus are exempt from the size
limitation applicable to Small Power QFs.
Under PURPA, QFs receive two primary benefits. First, PURPA exempts QFs, such
as the Coso projects, from the definition of "electric utility company" under
the Public Utility Holding Company Act of 1935 ("PUHCA"), most provisions of
the Federal Power Act and certain state laws relating to financial,
organization and rate regulation of electric utilities. Second, the regulations
promulgated by FERC under PURPA require that (i) electric utilities purchase
electricity generated by QFs, construction of which commenced on or after
November 9, 1978, at a rate based on the purchasing utility's full "avoided
costs" and (ii) the utilities sell supplementary, back-up, maintenance and
interruptible power to QFs on a just and reasonable and nondiscriminatory
basis. FERC's regulations define "avoided costs" as the "incremental costs to
an electric utility of electric energy or capacity or both which, but for the
purchase from the qualifying facility or qualifying facilities, such utility
would generate itself or purchase from another source." Utilities may also
purchase power at prices other than avoided cost of energy pursuant to
negotiations as provided by FERC's regulations.
We expect that the Coso projects will continue to meet all of the criteria
required for certification as QFs under PURPA. If any Coso project were to fail
to meet such criteria, the Coso partnership that owns that Coso project may
become subject to regulation as a public utility company or its equivalent
under PUHCA and the Federal Power Act. Each Coso partnership has warranted to
Edison that it will maintain the QF status of its respective Coso project
throughout the term of the related power purchase agreement and each of the
Coso partnerships is required under the Indenture to maintain the QF status of
its respective Coso project.
As discussed under the heading "Risk Factors--The operations of the Coso
projects could be adversely affected by an inability to comply with regulatory
standards," it is possible, however, that (1) PURPA could be repealed or
amendments to PURPA could be enacted that substantially reduce the benefits
currently afforded QFs, or (2) the requirements for the Coso projects to
maintain their status as QFs could be made more burdensome. In such event,
operations at the Coso projects or compliance with the terms of the power
purchase agreements could be adversely affected, and the
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Coso partnerships' ability to make payments under their project notes and
guarantees, and our ability to make payments of principal, premium, if any,
and interest on the Series B notes when due, could be materially and adversely
affected.
PUHCA
PUHCA provides that any corporation, partnership or other entity or
organized group that owns, controls or holds power to vote 10% or more of the
outstanding voting securities of a "public utility company" (which is defined
to include an "electric utility company" or a "gas utility company") or a
company that is a "holding company" of a "public utility company" is subject
to registration with the SEC and to regulation under PUHCA, unless exempted by
SEC rule, regulation or order. An entity may also be deemed to be a holding
company if the SEC determines, after providing notice and an opportunity for a
hearing, that such entity exercises a controlling influence over the
management or policies of any public utility or holding company as to make it
necessary or appropriate in the public interest or for the protection of
investors or consumers that such entity be regulated as a holding company.
Unless an exemption is obtained, PUHCA requires registration for a holding
company of a public utility company, and requires a public utility holding
company to limit its utility operations to a single integrated utility system
and to divest any other operations not functionally related to the operation
of the utility system. In addition, a public utility company that is a
subsidiary of a registered holding company under PUHCA is subject to financial
and organizational regulation, including approval by the SEC of its financing
transactions.
The Energy Policy Act of 1992 (the "Policy Act") contains amendments to
PUHCA that may allow the Coso partnerships to operate their businesses without
becoming subject to PUHCA in the event that any Coso project loses its status
as a QF. Under the Policy Act, a company may be exempted from PUHCA if it is
engaged exclusively in the business of owning and/or operating one or more
facilities used for the generation of electric energy exclusively for sale at
wholesale and selling electric energy at wholesale. To qualify for such an
exemption, a company must apply to FERC for a determination of eligibility,
pursuant to implementing rules promulgated by FERC. However, since the power
purchase agreements require each Coso partnership to maintain the QF status of
its respective Coso project, obtaining this exemption would not eliminate the
need to amend or replace the power purchase agreements if the current QF
status is lost. Moreover, although the Policy Act and its implementing rules
provide certain exemptions from PUHCA, the Policy Act may also encourage
greater competition in wholesale electricity markets which could result in a
decline in long-term rates to be paid by electric utilities, including Edison.
Even if a Coso partnership obtained an exemption from PUHCA pursuant to the
Policy Act and implementing rules, in the event that QF status is revoked or
otherwise not maintainable, the applicable Coso partnership would be subject
to regulation as a "public utility" under the Federal Power Act, as described
below.
Federal Power Act
Under the Federal Power Act, FERC has exclusive rate-making jurisdiction
over wholesale sales of electricity and transmission in interstate commerce.
These rates may be based on a cost of service approach or may be determined
through competitive bidding or negotiation. If a Coso project loses its QF
status, the rates set forth in its power purchase agreement would have to be
filed with FERC and would be subject to review by FERC under the Federal Power
Act. Under FERC policy, the rates under those circumstances could be no higher
than Edison would have paid for energy had it not been required to purchase
from such Coso project under PURPA's mandatory purchase requirements, i.e.,
Edison's economy energy (incremental) cost during the period of non-compliance
with QF
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requirements, unless the applicable power purchase agreement otherwise provides
for alternative rates to apply in the event of such loss of QF status. The
power purchase agreements do not contain such a provision nor do they contain
provisions for a renegotiation of the rates to be paid for electric energy in
the event of loss of QF status.
The Federal Power Act and FERC's authority under the Federal Power Act
subject public utilities to various other requirements, including accounting
and record-keeping requirements; FERC approval requirements applicable to
activities such as selling, leasing or otherwise disposing of facilities; FERC
approval requirements for mergers, consolidations, acquisitions and the
issuance of securities; and certain restrictions regarding affiliations of
officers and directors. Certain of these requirements, however, are typically
waived by FERC for public utilities that do not serve captive retail customers,
for example, entities known as exempt wholesale generators, or EWGs.
Accordingly, if a Coso project were to lose its QF status, the related Coso
partnership may be able to obtain EWG status and FERC would likely extend the
same waivers of certain of these requirements to that Coso partnership.
State Regulation
The Coso projects, by virtue of being QFs, are exempt from California rate,
financial and organizational regulations that are applicable to public
utilities. QFs, however, are not exempt from the California regulatory
commission's general supervisory powers relating to environmental and safety
matters.
In the event the Coso projects were to lose their QF status, while they would
become subject to the Federal Power Act and, potentially, PUHCA regulation,
they would nonetheless continue to be exempt from public utility regulation
under state law. Under California law, ownership or operation of a facility
that produces power from other than a conventional power source, such as
geothermal energy, does not make a company a public utility. Similarly,
California law excludes from the definition of public utility a company that
has been determined by FERC to be an exempt wholesale generator under PUHCA.
Wheeling and lnterconnection
Under the Federal Power Act, FERC is authorized to regulate the rates, terms
and conditions for the transmission of electric energy in interstate commerce.
This has been interpreted to mean that FERC has jurisdiction to prescribe the
terms of and to set the rates contained in agreements for the transmission of
electric energy when the applicable transmission system is interconnected and
capable of transmitting energy across a state boundary, even if the utility has
no direct connection with another utility outside its state but is
interconnected with another utility that in turn has interstate connections
with other utilities.
FERC's authority under the Federal Power Act to require electric utilities to
provide transmission service to QFs and other wholesale electricity producers
has been significantly expanded by the Policy Act. Pursuant to the Policy Act,
the Coso partnerships may apply to FERC for an order requiring a utility to
provide transmission services in order to transmit power to a wholesale
purchaser. FERC may issue such an order if FERC determines that such order
would promote the economically efficient transmission and generation of
electricity, would be just and reasonable and not unduly discriminatory or
preferential and otherwise would be in the public interest, provided that the
reliability of the affected electric systems would not be unreasonably
impaired. In addition, in
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April 1996, FERC issued an order directing transmission-owning utilities that
are subject to FERC jurisdiction, including Edison, to file transmission
tariffs providing for non-discriminatory transmission service on terms
comparable to those the transmission owner imposed on itself. Edison has now
complied with this open access order (although operational control of the
majority of Edison's transmission facilities has now been turned over to the
ISO). In addition, the ISO has filed an open access tariff in compliance with
the FERC order. As a result, the Coso partnerships would be able to obtain
transmission service through the ISO (or through Edison's open access tariff,
if necessary), subject to availability, should electricity sales to another
purchaser be necessary or desirable. Thus, the Policy Act and FERC's open
access order have presumably enhanced the Coso partnerships' ability to obtain
transmission access necessary to sell electric energy or capacity to purchasers
other than Edison if a power purchase agreement is terminated. There can be no
assurance, however, that FERC would issue an order mandating transmission
service for the Coso partnerships or that the rates for open access or FERC-
ordered transmission service would be economical for the Coso partnerships.
California Deregulation
In September 1996, AB1890 was enacted to open electric generation in
California to competition while leaving in place the regulated system of power
transmission and distribution. Among the significant provisions of this
legislation are (1) electric rate relief or rate freezes, (2) public benefit
programs, (3) funding for the support of renewable generation and (4)
transition mechanisms for utilities to recover stranded costs that have become
uneconomic by the change in public utility law and the move to a competitive
market. AB1890 reaffirmed that stranded costs resulting from above-market power
purchase agreements which the California Public Utilities Commission had
previously authorized for collection in rates, including the power purchase
agreements, will be recoverable by the utility over the remaining terms of
those power purchase agreements.
An integral component of AB1890 is the formation of the California Power
Exchange and ISO. The California Power Exchange is intended to operate like an
open and transparent commodities market where power producers will compete to
sell their generation and the ISO is intended to be a private entity that
provides all market participants with non-discriminatory access to the
transmission system, while maintaining system security and reliability. The
California Power Exchange and ISO began operations on March 31, 1998. Since
that time, the California Power Exchange has expanded its clearing mechanisms
for day-ahead bidding, the only mechanism available at inception, to include an
hour-ahead mechanism, beginning in August 1998. Further expansions of
California Power Exchange clearing mechanisms are currently planned and
scheduled for introduction in the near future. The ISO is also in the process
of refining its operations and responding to market conditions such as the
recent price spikes for certain ancillary services. Other aspects of ISO PX
operations and services are in the process of implementation as well. As
discussed under the headings "Risk Factors--The operations of the Coso projects
could be adversely affected by an inability to comply with regulatory
standards," and "Risk Factors--Future energy payments paid by Edison to the
Coso partnerships will most likely be less than historical energy payments
because they will be paid based on Edison's avoided cost of energy," the new
market structure in California raises novel regulatory and implementation
issues, which the various regulatory agencies and market participants are still
in the process of resolving. The process of development of the ISO PX system
will have significant effects on the Coso partnerships, given that Edison is
currently required to sell QF power through the
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California Power Exchange, and that Edison's avoided cost of energy will be set
to equal the California Power Exchange clearing price in the next two or three
years.
In addition to actions taken by the California Legislature and regulation by
the California Public Utilities Commission, bills have been and are being
introduced into the United States Congress mandating the deregulation of the
electric utility industry on the state level, as discussed above under the
heading "Risk Factors--The operations of the Coso projects could be adversely
affected by an inability to comply with regulatory standards."
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MANAGEMENT
Funding Corp.
The following table sets forth the persons who currently serve as our
directors and executive officers as of June 30, 1999:
Name Age Position(s)
James D. Bishop, Sr. ... 65 Director, Chairman and Chief Executive Officer
Leslie J. Gelber........ 42 Director, President and Chief Operating Officer
James D. Bishop, Jr. ... 39 Director, Vice Chairman
Christopher T.
McCallion.............. 37 Director, Executive Vice President and Chief Financial Officer
Larry K. Carpenter...... 49 Director, Executive Vice President
James C. Sullivan....... 71 Director, Senior Vice President and Secretary
Mark A. Ferrucci........ 47 Director
David V. Casale......... 36 Vice President and Controller
Robert E. Tucker........ 46 Vice President
Barbara Bishop Gollan... 40 Vice President
James D. Bishop, Sr., Chairman, Chief Executive Officer and a Director of
Funding Corp. and of Caithness Energy, has served as a Director of Caithness
Corporation since its inception in 1975. Mr. Bishop served as Caithness
Corporation's President from its inception until December 1986 and as Chairman
of Caithness Corporation from January 1987 until the present. Mr. Bishop also
serves as a director for various other entities which engage in independent
power production and natural resource exploration and development. Mr. Bishop
holds a Master of Business Administration degree from Harvard Business School
and a Bachelor of Arts degree from Yale University. Mr. Bishop is the father of
James D. Bishop, Jr. and Barbara Bishop Gollan.
Leslie J. Gelber, President, Chief Operating Officer and a Director of
Funding Corp. and of Caithness Energy, has served as President and Chief
Operating Officer of Caithness Corporation since January 1999. Prior to joining
Caithness Corporation, Mr. Gelber served as President of Cogen Technologies,
Inc., which is also engaged in the field of independent power production, from
August 1998 until December 1998. From July 1993 to July 1998, Mr. Gelber served
as President of ESI Energy, Inc., the non-regulated independent power company
owned by FPL Group, Inc. Mr. Gelber holds a Master of Business Administration
degree from the University of Miami and holds a Bachelor of Arts degree in
Economics from Alfred University.
James D. Bishop, Jr., Vice Chairman and a Director of Funding Corp. and of
Caithness Energy, joined Caithness Corporation in 1988 and has served as
President and Chief Operating Officer of Caithness Corporation from November
1995 until December 1998. Mr. Bishop also serves on all of the boards of
directors and management committees of the entities and joint ventures
affiliated with Caithness Corporation. Mr. Bishop holds a Master of Business
Administration degree from the Kellogg Graduate School of Management at
Northwestern University and holds a Bachelor of Science degree from Trinity
College. Mr. Bishop is the son of James D. Bishop, Sr. and the brother of
Barbara Bishop Gollan.
141
Christopher T. McCallion, Executive Vice President, Chief Financial Officer
and a Director of Funding Corp. and of Caithness Energy, served as Vice
President and Controller of Caithness Corporation from July 1991 to November
1995, and has served as Executive Vice President and Chief Financial Officer of
Caithness Corporation since November 1995. Mr. McCallion holds a Bachelor of
Science degree from Seton Hall University.
Larry K. Carpenter, Executive Vice President and a Director of Funding Corp.
and of Caithness Energy, has served as an Executive Vice President of Caithness
Corporation since January 1999. Prior to joining Caithness Corporation, Mr.
Carpenter served as Vice President of Development at ESI Energy, Inc., the non-
regulated independent power company owned by FPL Group Inc., from 1985 to
December 1998. Mr. Carpenter holds a Bachelor of Science degree in Electrical
Engineering from the University of Florida.
James C. Sullivan, a Senior Vice President, Secretary and a Director of
Funding Corp. and of Caithness Energy, has served as Senior Vice President,
Secretary and a Director of Caithness Corporation since April 1996.
Mr. Sullivan attended Holy Cross Seminary at Notre Dame University, Indiana
University and the University of Tokyo before graduating from the State
University of California at Pasadena.
Mark A. Ferrucci, a Director of Funding Corp., has served as the independent
director of Funding Corp. since May 1999. Since 1997, Mr. Ferrucci has been an
employee of CT Corporation System, an independent company that provides
corporate and UCC services to businesses and law firms. From 1977 until 1992,
Mr. Ferrucci served as CT Corporation System's Assistant Secretary and as
Assistant Vice President of CT Corporation System from 1992 until the present.
David V. Casale, a Vice President and the Controller of Funding Corp. and of
Caithness Energy, joined Caithness Corporation in December 1991 and has served
as a Vice President and as its Controller since November 1995. Mr. Casale holds
a Bachelor of Arts degree from Adelphi University and is a Certified Public
Accountant.
Robert E. Tucker, a Vice President of Funding Corp. and of Caithness Energy,
joined Caithness Corporation in September 1990 and has served as a Senior Vice
President of Caithness Corporation since January 1993. Mr. Tucker holds a
Master of Science degree in Mechanical Engineering and a Bachelor of Science
degree in Mechanical Engineering from Purdue University.
Barbara Bishop Gollan, a Vice President of Funding Corp. and of Caithness
Energy, joined Caithness Corporation as Vice President in October 1990. Ms.
Gollan has authored and co-authored a number of technical papers on geothermal
systems, which were presented to the Geothermal Resources Council, the Geologic
Society of America and the Stanford Geothermal Workshop. Ms. Gollan holds a
Master of Science degree in Geology and Geochemistry from Stanford University
and holds a Bachelor of Arts degree from Amherst College. Ms. Gollan is the
daughter of Mr. James D. Bishop, Sr. and sister of James D. Bishop, Jr.
Our Board of Directors recently appointed Mr. Ferrucci as an independent
director. The unanimous affirmative vote of our Board of Directors (including
Mr. Ferrucci) is required before we can take certain actions, including, but
not limited to, (1) engaging in any business or activity other than issuing the
senior secured notes and making the related loans to the Coso partnerships,
(2) incurring any debt, or assuming or guaranteeing any debt of any other
entity, (3) dissolving or liquidating, (4) consolidating, merging or selling
all or substantially all of our assets or (5) instituting any bankruptcy or
insolvency proceedings.
142
None of our directors and executive officers receives any compensation from
us for his or her services, except that nominal compensation is paid in
consideration for Mr. Ferrucci's services.
The Coso Partnerships
Each of the Coso partnerships has two general partners, a managing partner
and a non-managing partner. Under the amended and restated partnership
agreement of each Coso partnership, the managing partner of the Coso
partnership is generally responsible for the management and control of the day-
to-day business and affairs of the Coso partnership and acts on behalf of the
Coso partnership. The managing partner of the Navy I partnership is New CLOC,
the managing partner of the BLM partnership is New CHIP and the managing
partner of the Navy II partnership is New CTC. See "Business--The Coso
Partnerships."
Each managing partner is a limited liability company which is managed by a
manager who is appointed by Caithness Acquisition, the sole member of each
managing partner. The manager is responsible for the ordinary course management
and operations by its Coso partnership of that partnership's Coso project.
Caithness Acquisition has appointed itself as the manager of each managing
partner. Caithness Acquisition has also appointed Mr. Ferrucci as the
independent manager of each managing partner. (In addition, each of the
managing members of the non-managing partners has appointed Mr. Ferrucci as the
independent manager of that non-managing partner.) The approval of the
independent manager is required before the managing partner (or the non-
managing partner, as the case may be) may take certain actions that do not
involve the ordinary course management and operations by the Coso partnerships
of the Coso projects, including, among others, (1) commencing any bankruptcy or
insolvency proceeding involving the managing partner, (2) incurring any debt in
the name of the managing partner for which it would be liable, (3) dissolving,
liquidating, consolidating or merging, or selling all or substantially all of
the assets of, its respective Coso partnership, or (4) engaging in any business
or activity other than acting as the managing partner of its respective Coso
partnership. Each managing partner also has its own officers, who are also our
officers, and who act on behalf of the managing partners of the Coso
partnerships.
Caithness Acquisition, a limited liability company, is the manager and sole
member of each of the managing partners. Caithness Energy, as the manager and
sole owner of Caithness Acquisition, has delegated its role as manager of
Caithness Acquisition to the Caithness Acquisition board of directors,
including the power to manage the managing partners of the Coso partnerships.
Each managing partner's officers are also the officers of Caithness
Acquisition. None of the persons acting on behalf of the Coso partnerships
receives any compensation from the Coso partnerships for his or her services,
except that nominal compensation is paid in consideration for Mr. Ferrucci's
services.
Caithness Energy is governed by a board of directors and not by its members.
Our directors, other than Mr. Ferrucci, also currently serve as members of the
board of directors of Caithness Energy. Under the limited liability company
agreement of Caithness Energy, Caithness Corporation is entitled to appoint a
number of members to the Board of Directors of Caithness Energy who hold, in
the aggregate, a majority of the votes of all members of such board of
directors. Caithness Corporation's present appointees are Messrs. Bishop, Sr.,
Bishop, Jr. and Sullivan. In addition, Messrs. Gelber, Carpenter and McCallion
serve as voting members of the board of directors of Caithness Energy pursuant
to their individual executive compensation agreements with Caithness Energy.
These six individuals, together with Mr. Ferrucci, serve as the Caithness
Acquisition board of directors.
143
Management Committees
Under the amended and restated partnership agreement of each Coso
partnership, the managing partner of the Coso partnership is subject to the
directives of a management committee which oversees the business operations of
the Coso partnership. The managing partner of a Coso partnership may not take
certain specific actions without the consent of the management committee of
that Coso partnership. However, the management committee may not direct the
managing partner of the Coso partnership to take any action over which the
independent manager has exclusive authority without the requisite approval of
the independent manager. The management committee of each Coso partnership
consists of four delegates, two of which are appointed by the managing partner
and two of which are appointed by the non-managing partner. Each partner may
substitute or change its own delegates.
Caithness Energy indirectly wholly owns and controls the managing partners of
the BLM partnership and the Navy II partnership. Caithness Energy and its
affiliates also control CCH, the non-managing partner of the BLM partnership,
and Navy II Group, the non-managing partner of the Navy II partnership.
Accordingly, Caithness Energy and its affiliates control the appointment of all
four delegates to the management committees of the BLM partnership and the Navy
II partnership.
While Caithness Energy indirectly wholly owns and controls the managing
partner of the Navy I partnership, it does not wholly own and control ESCA, the
non-managing partner of the Navy I partnership. Caithness Energy and its
affiliates and ESI collectively own and control ESCA. Caithness Energy and its
affiliates have the right to control the appointment of the two managing
partner delegates to the management committee of the Navy I partnership and,
under ESCA's limited liability company agreement, one of the two non-managing
partner delegates. In addition, under ESCA's limited liability company
agreement, ESI has the right to control the appointment of the second non-
managing partner delegate to the Navy I partnership's management committee, and
that delegate has the right to veto any decisions made by the other non-
managing partner delegate. Since decisions of the Navy I partnership's
management committee requires at least one vote from each partner of the Navy I
partnership, ESI has the right to veto any decisions made by that management
committee.
Under the amended and restated partnership agreements of the Coso
partnerships, each partner may appoint one delegate with multiple votes. The
names of the delegates appointed by affiliates of Caithness Energy and ESI to
the management committees of the Coso partnerships are set forth below.
Under the amended and restated partnership agreement of each Coso
partnership, the management committee must hold meetings on a quarterly basis
and on such other dates as may be called by any partner. A quorum of at least
three delegates must be present to convene a meeting and/or vote on a
management committee matter. Any action of the management committee must be
taken by a majority vote of the delegates comprising the quorum at the meeting,
but the vote must be composed of at least one affirmative vote by at least one
delegate of the managing partner and one delegate of the non-managing partner.
In lieu of meetings, actions may be taken without a meeting by written consent
or confirmed telephonic vote of at least three delegates.
The managing partner of a Coso partnership cannot make certain investment or
business decisions without the express consent of the management committee of
that Coso partnership. Those business decisions include, among others, those
regarding sale or lease of partnership assets, pledge of partnership assets,
execution or amendment of material contracts, engagement of outside
144
consultants, termination of the Coso partnerships and approval of budgets. In
addition, each Coso partnership's managing partner is required to prepare the
annual capital expenditure and annual operating budgets for that Coso
partnership and present it to the management committee for approval. If all or
part of the proposed budget is not approved by the management committee in a
timely fashion, the managing partner can retain an independent engineer to
review the proposed budget. If the independent engineer certifies that the
proposed budget is reasonably designed to permit the managing partner to
operate and maintain a project of the type owned by the Coso partnership and to
maximize revenues and net income, the proposed budget is deemed approved. If
the independent engineer does not so certify, the budget will be the same as in
the immediately preceding year, adjusted for inflation. Any controversies or
claims arising out of the amended and restated partnership agreements that
cannot be settled by agreement of the partners are to be settled by binding
arbitration.
As of April 1, 1999, the following persons were the members of the management
committee of each Coso partnership, as applicable. Each person has two votes on
each management committee on which he serves, except that Robert Tucker has
only one vote on the management committee of the Navy I partnership and Kenneth
P. Hoffman has only one vote on the management committee of the Navy I
partnership:
Name Age Partnership(s)
James D. Bishop, Jr. ... 39 Navy I partnership, BLM partnership, Navy II partnership
Robert Tucker........... 46 Navy I partnership, BLM partnership, Navy II partnership
Kenneth P. Hoffman...... 47 Navy I partnership
Certain information regarding Messrs. Bishop and Tucker is provided above
under "--Funding Corp."
Kenneth P. Hoffman was appointed to the management committee of the Navy I
partnership by ESI. Mr. Hoffman joined ESI Energy, Inc. in June 1989 and, since
1993, has been its Vice President of Business Management. Mr. Hoffman is
currently a Vice President of FPL Energy, Inc. Prior to joining ESI Energy,
Inc., Mr. Hoffman was employed by Florida Power & Light Company. Mr. Hoffman
holds a Master of Business Administration degree from Florida International
University and a Bachelor of Science degree from Rochester Institute of
Technology.
145
Management Committee Fees
The members of the management committees are not entitled to any direct
compensation from us or the Coso partnerships. However, each Coso partnership
previously paid to its two general partners annual management committee fees
for their participation on the management committee of that Coso partnership.
The following table sets forth, for the three months ended March 31, 1998 and
March 31, 1999, and for the years ended December 31, 1996, 1997 and 1998, the
total amount of management committee fees paid or payable by each of the Coso
partnerships to its partners:
Three Months Ended
March 31, 1999
------------------------------
Three
Months Two Months One Month
Year Ended December 31, Ended Ended Ended
-------------------------- March 31, February 28, March 31,
1996 1997 1998 1998 1999 1999 Total
Navy I Partnership
New CLOC.............. $ -- $ -- $ -- $ -- $ -- $12,000 $12,000
Predecessor of New
CLOC................. 143,000 143,000 147,000 55,000 25,000 -- 25,000
ESCA.................. 214,000 214,000 221,000 37,000 37,000 18,000 55,000
-------- -------- -------- ------- ------- ------- -------
$357,000 $357,000 $368,000 $92,000 $62,000 $30,000 $92,000
BLM Partnership
New CHIP.............. $ -- $ -- $ -- $ -- $ -- $12,000 $12,000
Predecessor of New
CHIP................. 145,000 145,000 148,000 56,000 25,000 -- 25,000
CCH................... 222,000 218,000 223,000 37,000 37,000 19,000 56,000
-------- -------- -------- ------- ------- ------- -------
$367,000 $363,000 $371,000 $93,000 $62,000 $31,000 $93,000
Navy II Partnership.....
New CTC............... $ -- $ -- $ -- $ -- $ -- $12,000 $12,000
Predecessor of New
CTC.................. 145,000 145,000 148,000 56,000 25,000 -- 25,000
Navy II Group......... 218,000 218,000 223,000 37,000 37,000 19,000 56,000
-------- -------- -------- ------- ------- ------- -------
$363,000 $363,000 $371,000 $93,000 $62,000 $31,000 $93,000
The Coso partnerships no longer pay management committee fees to their
managing partners. See "Certain Relationships and Related Transactions--
Management Committee Fees."
146
OWNERSHIP
Funding Corp.
As of June 30, 1999, our authorized capital stock consisted of 1,000 shares
of common stock, par value $0.01 per share, of which 300 shares were
outstanding. Our outstanding common stock is owned equally by the Coso
partnerships.
Coso Partnerships
Our directors and executive officers also act in similar capacities on behalf
of the managing partner of each Coso partnership and, except for Mr. Ferrucci,
on behalf of Caithness Acquisition and Caithness Energy. Several of these
directors and executive officers beneficially own securities of Caithness
Corporation. Caithness Corporation and its affiliates beneficially own all of
the member interests of Caithness Energy.
Caithness Energy is governed by a board of directors and not by its members.
Our directors, except for Mr. Ferrucci, also currently serve as the members of
the board of directors of Caithness Energy. Under the limited liability company
agreement of Caithness Energy, Caithness Corporation is entitled to appoint a
number of members who hold, in the aggregate, a majority of the votes of all
members of such board of directors. Caithness Corporation's current appointees
are Messrs. Bishop, Sr., Bishop, Jr. and Sullivan. In addition, Messrs. Gelber,
Carpenter and McCallion serve as voting members of the board of directors of
Caithness Energy pursuant to their individual executive compensation
agreements.
The following table sets forth, as of June 30, 1999, certain information
regarding the beneficial ownership of our voting securities and the beneficial
ownership of the voting securities of each of the Coso partnerships by:
(1) each person who is known by us and the Coso partnerships to
beneficially own 5% or more of our voting securities or 5% or more of
the voting securities of any Coso partnership,
(2) each of our directors and executive officers who also act in similar
capacities on behalf of the managing partner of each Coso partnership
and each of the delegates to the management committee of each Coso
partnership, and
(3) all of our directors and executive officers who also act in similar
capacities for the managing partnership of each Coso partnership and
all of the delegates to the management committee of each Coso
partnership as a group.
Beneficial ownership has been determined in accordance with Rule 13d-3 under
the Securities Exchange Act of 1934, as amended. Except as otherwise noted,
each person named below has an address in care of our principal executive
offices.
147
Beneficial Ownership of Funding Corp. and the Coso Partnerships
Percent Indirect Percent Indirect
Percent Indirect Beneficial Percent Indirect Beneficial
Name and Address Beneficial Ownership in the Beneficial Ownership in the
of Beneficial Ownership in Navy I Ownership in the Navy II
Owner Funding Corp. Partnership BLM Partnership Partnership
James D. Bishop,
Sr.(1)(2)............. 1.1% 1.8% -- 1.5%
Leslie J.
Gelber(1)(3).......... -- -- -- --
James D. Bishop,
Jr.(1)(4)............. 31.4% 28.9% 35.0% 30.4%
Christopher T.
McCallion(1)(3)....... -- -- -- --
Larry K.
Carpenter(1)(3)....... -- -- -- --
James C.
Sullivan(1)(5)........ 2.8% 2.6% 2.9% 2.8%
Mark A. Ferrucci....... -- -- -- --
David Casale(1)(3)..... -- -- -- --
Robert E.
Tucker(1)(3).......... -- -- -- --
Barbara Bishop
Gollan(1)(3)(6)....... -- -- -- --
Kenneth P. Hoffman..... -- -- -- --
c/o FPL Energy, Inc.
700 Universe Blvd.
Juno Beach, FL 33408
Dominion Energy,
Inc.(7)............... * -- 5.2% 6.3%
901 East Byrd Street
Richmond, VA 23219
ESI Geothermal,
Inc.(8)............... * 5.0% -- --
c/o FPL Energy, Inc.
700 Universe Blvd.
Juno Beach, FL 33408
Mojave Energy
Company(9)............ 6.2% 5.5% 7.6% 5.3%
c/o Davenport
Resources, Inc.
575 Lexington Avenue
New York, NY 10022
All directors,
executive officers and
management committee
delegates as a group.. 35.3% 33.3% 37.9% 34.6%
- ---------------------
* Less than 5.0%.
(1) The address of such person is c/o Caithness Coso Funding Corp., 1114 Avenue
of the Americas, 41st Floor, New York, New York 10036-7790.
(2) The beneficial ownership of James D. Bishop, Sr.'s interests is based upon
his ownership of shares of common stock of Mojave Power, Inc. and Mojave
Power II, Inc. which own, indirectly through various entities, general
partnership interests in the Navy I partnership and the Navy II
partnership. In addition to these interests, James D. Bishop, Sr. is the
beneficiary of The James D. Bishop Trust--1998 ("Bishop, Sr. Trust"), which
owns shares of common stock of Caithness Corporation. Caithness Corporation
owns, indirectly through various entities, general partnership interests in
the Navy I partnership, the BLM partnership and the Navy II partnership,
which collectively own all of the shares of common stock of Funding Corp.
The voting rights to the shares of common stock of Caithness Corporation
held by the Bishop, Sr. Trust have been transferred to The Caithness
Entities Voting Trust, the trustee of which is James D. Bishop, Jr. The
Bishop, Sr. Trust is irrevocable. James D. Bishop, Sr., therefore, does not
have voting or investment power over these shares of common stock of
Caithness Corporation.
148
(3) Owner of economic interests in the Coso partnerships through Caithness
Corporation's employee incentive plans, which economic interests are not
listed on this table. See "Certain Relationships and Related Transactions--
Interests of Management in Coso Projects."
(4) James D. Bishop, Jr. is: (i) the beneficiary of The James D. Bishop, Jr.
Irrevocable Trust--1996 (the "Bishop, Jr. Trust"), which owns shares of
common stock of Caithness Corporation, the voting rights of which have been
transferred to The Caithness Entities Voting Trust, the trustee of which is
James D. Bishop, Jr.; (ii) the owner of common stock of Caithness
Corporation and of Mojave Power, Inc.; and (iii) the trustee of The
Caithness Entities Voting Trust which possesses sole voting control over
the shares of common stock of Caithness Corporation held by the Bishop, Sr.
Trust, The Barbara Bishop Gollan Irrevocable Trust--1996 (the "Gollan
Trust"), The Elizabeth Bishop DeLuca Irrevocable Trust--1996 and The Linda
Bishop Fotiu Irrevocable Trust--1996. The interests listed in (i) and (ii)
above entitle James D. Bishop, Jr. to the following indirect beneficial
ownership interests: Funding Corp. (1.8%); Navy I partnership (1.4%); BLM
partnership (1.7%); and Navy II partnership (2.4%). James D. Bishop, Jr.
disclaims beneficial ownership of the interests listed in (iii) above.
(5) The beneficial ownership of James C. Sullivan's interests is based upon his
ownership of shares of common stock of Caithness Corporation which owns,
indirectly through various entities, general partnership interests in the
Navy I partnership, the BLM partnership and the Navy II partnership, and
his ownership of shares of common stock of Mojave Power, Inc. and Mojave
Power II, Inc. which own, indirectly through various entities, general
partnership interests in the Navy I partnership and the Navy II
partnership.
(6) Barbara Bishop Gollan is the beneficiary of the Gollan Trust, which owns
shares of common stock of Caithness Corporation. The voting rights to the
shares of common stock of Caithness Corporation held by the Gollan Trust
have been transferred to The Caithness Entities Voting Trust, the trustee
of which is James D. Bishop, Jr. The Gollan Trust is irrevocable. Barbara
Bishop Gollan, therefore, does not have voting or investment power over
these shares of common stock of Caithness Corporation.
(7) Dominion Energy, Inc. owns: (i) a limited liability company membership
interest in Caithness BLM Group, LP, a Delaware limited partnership, which
owns a limited liability company membership interest in CCH, which owns a
general partnership interest in the BLM partnership; and (ii) a limited
liability company membership interest in Navy II Group which owns a general
partnership interest in the Navy II partnership and a limited liability
company membership interest in CCH, which owns a general partnership
interest in the BLM partnership.
(8) ESI Geothermal, Inc. owns a limited liability company membership interest
in ESCA, which owns a general partnership interest in the Navy I
partnership.
(9) Mojave Energy Company owns limited liability company membership interests
in Caithness Power, LLC, which owns, indirectly through various entities,
general partnership interests in each of the Coso partnerships.
149
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
O&M Fees; Reduction in Fees
O&M Fees
Prior to February 25, 1999, the date that Caithness Acquisition purchased of
all of CalEnergy's interests in the Coso projects, CalEnergy and its affiliates
acted as the plant and field operator at the Coso projects. They also
maintained the Navy I Transmission Line and the BLM/Navy II Transmission Line.
Under the amended partnership agreements of the Coso partnerships, CalEnergy
was entitled to receive reimbursement of direct operating costs, reimbursement
of approved allocable general and administrative costs and payment of operator
fees in consideration for its services as the operator at the Coso projects.
The Coso partnerships paid CalEnergy the aggregate amounts of approximately
$7.5 million in each of 1998, 1997 and 1996 for such costs and fees. For the
first two months of the three month period ended March 31, 1999, the Coso
partnerships paid CalEnergy the aggregate amount of approximately $1.3 million
for such costs and fees.
In connection with Caithness Acquisition's purchase of all of CalEnergy's
interests in the Coso projects, each Coso partnership retained FPL Operating
and Coso Operating Company to operate its Coso project under separate O&M
agreements with each. FPL Operating is an affiliate of ESI, which is a member
of ESCA. Coso Operating Company is a wholly owned subsidiary of Caithness
Acquisition. For additional information regarding the operations and
maintenance services being performed by FPL Operating and Coso Operating
Company at the Coso projects, see "Business--O&M Agreements."
Under its O&M agreements with the Coso partnerships, FPL Operating operates
and maintains all three plants, the transmission lines and the geothermal
fields at the Coso projects. As compensation for such services, each Coso
partnership has agreed to pay FPL Operating an annual O&M fee of $134,000,
$100,000 and $84,000 in the first, second and third years, respectively, of the
term of its O&M agreements (or an aggregate of $402,000, $300,000 and $252,000,
respectively). In addition, each Coso partnership has agreed to pay to FPL
Operating all properly incurred costs and expenses and reimburse FPL Operating
for the performance incentive bonuses that it pays its employees, as set forth
in the O&M agreements. For the last month of the three month period ended March
31, 1999, the Coso partnerships paid FPL Operating the aggregate amount of
approximately $33,000 as its O&M fee. All fees payable to FPL Operating are
subordinated to all payments to be made under the senior secured notes.
Under its O&M agreements with the Coso partnerships, Coso Operating Company,
among other things, manages the geothermal resource, including well drilling,
at the Coso projects. As compensation for such services, each Coso partnership
has agreed to pay Coso Operating Company an annual O&M fee of $532,000,
$400,000 and $334,000 in the first, second and third years, respectively, of
the term of its O&M agreements (or an aggregate of $1.6 million, $1.2 million
and $1.0 million, respectively). In addition, each Coso partnership has agreed
to pay all properly incurred costs and expenses and reimburse Coso Operating
Company for the performance incentive bonuses that Coso Operating Company pays
to its employees, as set forth in the O&M agreements. As of the date hereof, no
O&M fees have been paid to Coso Operating Company. All fees payable to Coso
Operating Company are subordinated to all payments to be made under the senior
secured notes.
Reduction in Fees
As a result of Caithness Acquisition's purchase of all of CalEnergy's
interests in the Coso projects and the resulting change in plant and field
operators, annual operator fees and costs to be
150
paid by the Coso partnerships to FPL Operating and Coso Operating Company have
been reduced significantly from those previously paid to CalEnergy, the Coso
projects' prior operator, and, since the closing date of the Series A notes
offering, management committee fees previously payable to the managing partners
of the Coso partnerships have been eliminated. In connection with this
reduction in operator fees and the elimination of management committee fees
payable to the managing partners, ESCA, CCH and Navy II Group, the non-managing
partners of the Navy I partnership, the BLM partnership and the Navy II
partnership, respectively, consented to an additional payment in the aggregate
amount of $26.8 million to the managing partners of the Coso partnerships. For
more information regarding the elimination of the managing partner management
committee fees, see "--Management Committee Fees." This additional payment was
made simultaneously with the closing of the Series A notes offering equally by
each of the Coso partnerships. The aggregate amount of this payment represents
the present value of the share of the reduction in future operator fees and the
elimination of management committee fees payable to the managing partners of
the Coso partnerships that the non-managing partners of each Coso partnership
would have otherwise had to incur under their previous partnership and O&M
agreements. The managing partners of the Coso partnerships caused this
additional payment to be applied to repay the short-term debt their parent,
Caithness Acquisition, incurred in connection with its purchase of all of
CalEnergy's interests in the Coso projects. See "--Purchase of CalEnergy's
Interests."
Management Committee Fees
Each Coso partnership used to pay management committee fees to each of its
general partners in consideration for its participation on the management
committee of that Coso partnership. See "Management--Management Committee
Fees." Each of the general partners then distributed these management committee
fees to its own managing partner, which, in turn, distributed them, directly or
indirectly, to Caithness Energy or CalEnergy, as the case may be.
The following table sets forth, for the three months ended March 31, 1998 and
March 31, 1999, and for the years ended December 31, 1996, 1997 and 1998, the
total amount of management committee fees distributed or distributable to
Caithness Energy and CalEnergy, respectively, for those periods:
Three Months Ended March 31,
1999
------------------------------
Three Two One
Months Months Month
Year Ended December 31, Ended Ended Ended
-------------------------- March 31, February 28, March 31,
1996 1997 1998 1998 1999 1999 Total
Navy I Partnership
Caithness Energy....... $214,000 $214,000 $221,000 $55,000 $37,000 $30,000 $67,000
CalEnergy.............. 143,000 143,000 147,000 37,000 25,000 -- 25,000
-------- -------- -------- ------- ------- ------- -------
$357,000 $357,000 $368,000 $92,000 $62,000 $30,000 $92,000
BLM Partnership
Caithness Energy....... $222,000 $218,000 $223,000 $56,000 $37,000 $31,000 $68,000
CalEnergy.............. 145,000 145,000 148,000 37,000 25,000 -- 25,000
-------- -------- -------- ------- ------- ------- -------
$367,000 $363,000 $371,000 $93,000 $62,000 $31,000 $93,000
Navy II Partnership
Caithness Energy....... $218,000 $218,000 $223,000 $56,000 $37,000 $31,000 $68,000
CalEnergy.............. 145,000 145,000 148,000 37,000 25,000 -- 25,000
-------- -------- -------- ------- ------- ------- -------
$363,000 $363,000 $371,000 $93,000 $62,000 $31,000 $93,000
Affiliates of Caithness Energy have eliminated the payment of management
committee fees by the Coso partnerships to the Coso partnerships' managing
partners. After the closing of the Series A notes offering, the Coso
partnerships will pay management committee fees to their non-managing
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partners in the aggregate annual amount of $667,000. This aggregate amount will
be adjusted annually for inflation based on the Consumer Price Index. For a
discussion of certain matters relating to the elimination of management
committee fees payable to the managing partner of each Coso partnership, see
"--O&M Fees; Reduction in Fees."
Purchase of CalEnergy Interests
On February 25, 1999, Caithness Acquisition purchased all of CalEnergy's
interests in the Coso projects. The purchase price consisted of $205.0 million
in cash, plus $5.0 million in contingent payments, plus the assumption of
CalEnergy's and its affiliates' share of debt outstanding at the Coso projects
which then totaled approximately $67.0 million. In order to complete the
purchase, Caithness Acquisition borrowed on a short-term basis the aggregate
principal amount of $211.5 million from an affiliate of the initial purchaser
of the Series A notes. The initial purchaser's affiliate received customary
fees and reimbursement of its expenses in connection with its activities as the
arranger and lender of such short-term debt. Caithness Acquisition used a
portion of the proceeds from the Series A notes offering that it received from
the Coso partnerships, together funds from other sources, to repay all amounts
owing under this short-term debt facility. See "Business--Purchase of
CalEnergy's Interests."
As part of the purchase of CalEnergy's interests in the Coso projects,
Caithness Energy will be required to pay the contingent payment upon the
settlement, final judgment or other dismissal of the litigation with Edison. In
addition, the Coso partnerships and certain other affiliates of Caithness
Energy entered into a future revenue agreement with CalEnergy. This agreement
provides that the Coso partnerships and such affiliates will pay to CalEnergy
one-seventh of the gross revenues from the Coso projects or any expansions
thereof derived from certain energy-related arrangements with the U.S.
Government. For more information regarding these additional agreements, see
"Business--Purchase of CalEnergy's Interests."
Payments to Transmission Line Partners
Coso Transmission Line Partners, the owner of the BLM/Navy II Transmission
Line, charges the BLM partnership and the Navy II partnership for their use of
the BLM/Navy II Transmission Line. The charges are designed to ensure that Coso
Transmission Line Partners recovers its operating costs. Also, the BLM
partnership and the Navy II partnership pay for the purchase of items used by
Coso Transmission Line Partners for the BLM/Navy II Transmission Line. See
"Business--Overview of the Coso Projects--Transmission Lines." The following
table sets forth, for the three months ended March 31, 1998 and March 31, 1999,
and for the years ended December 31, 1996, 1997 and 1998, the total amount that
Coso Transmission Line Partners charged the BLM partnership and the Navy II
partnership for net operating costs (net of advances from the BLM partnership
or the Navy II partnership, as the case may be):
Three Months Ended March 31,
Year Ended December 31, 1999
-------------------------- ------------------------------
Three Months Two Months One Month
Ended Ended Ended
March 31, February 28, March 31,
1996 1997 1998 1998 1999 1999 Total
BLM Partnership......... $114,000 $112,000 $115,000 $42,000 $28,000 $15,000 $43,000
Navy II Partnership..... 126,000 127,000 127,000 49,000 $33,000 17,000 50,000
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Distributions to Caithness Energy and CalEnergy
The Coso partnerships have made cash distributions from operating cash flow
to its partners from time to time as determined by their respective management
committees. The Navy I partnership, the BLM partnership and the Navy II
partnership made aggregate cash distributions to Caithness Energy and its
affiliates of approximately $11.9 million, $9.0 million and $21.1 million,
respectively, in the year ended December 31, 1998, approximately $39.9 million,
$21.2 million and $33.7 million, respectively, in the year ended December 31,
1997, and approximately $39.2 million, $30.2 million and $41.1 million,
respectively, in the year ended December 31, 1996.
The Navy I partnership, the BLM partnership and the Navy II partnership made
additional aggregate cash distributions to CalEnergy and its affiliates of
approximately $10.3 million, $8.3 million and $21.1 million, respectively, in
the year ended December 31, 1998, approximately $34.5 million, $19.6 million
and $33.7 million, respectively, in the year ended December 31, 1997, and
approximately $34.0 million, $27.9 million and $41.1 million, respectively, in
the year ended December 31, 1996. The Coso partnerships have not made any cash
distributions to their partners for the three month period ended March 31,
1999. As a result of Caithness Acquisition's purchase of CalEnergy's interests
in the Coso projects, the Coso partnerships will no longer make any
distributions to CalEnergy other than as provided in the agreements it entered
into in connection with Caithness Acquisition's purchase of all of CalEnergy's
interests in the Coso projects. See "--Purchase of CalEnergy's Interests."
Interests of Management in Coso Projects
Leslie J. Gelber, a director and President and Chief Operating Officer of
Funding Corp., Christopher T. McCallion, a director and Executive Vice
President and Chief Financial Officer of Funding Corp., Larry K. Carpenter, a
director and Executive Vice President of Funding Corp., and certain other
executive officers of Funding Corp. have economic interests in the Coso
partnerships. These individuals are participants in incentive compensation
plans maintained by Caithness Corporation, of which Caithness Energy is the
principal operating subsidiary. Under these incentive compensation plans, these
individuals have been granted "units" in Caithness Energy. Under Caithness
Energy's limited liability company agreement, unit holders are entitled to
receive distributions of profits, losses and net cash flow made by Caithness
Energy to its unit holders which are derived by Caithness Energy from certain
of its independent power projects, including the Coso projects. In particular,
these individuals will receive in the aggregate approximately 23.0% of the
distributions of profits, losses and net cash flow made by Caithness Energy and
derived from the Coso partnerships.
Although unit holders of Caithness Energy have rights to economic
distributions only, Messrs. Gelber, Carpenter and McCallion also serve as
members of the board of directors of Caithness Energy pursuant to their
respective executive compensation arrangements. Caithness Energy is governed by
its board of directors, not by its members. Under the limited liability company
agreement of Caithness Energy, Caithness Corporation is entitled to appoint a
number of members to the Board of Directors of Caithness Energy who hold, in
the aggregate, a majority of the votes of all members of such board of
directors. Caithness Corporation's present appointees are Messrs. Bishop, Sr.,
Bishop, Jr. and Sullivan. The rights to distributions held by these individuals
are subject to restrictions on transfer as well as call rights in favor of
Caithness Corporation upon termination of such individual's employment.
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Royalty to Coso Land Company
Coso Land Company is a general partnership of which Caithness Acquisition and
one of our other affiliates are the general partners. In 1988, the BLM lease
was assigned to the BLM partnership. In connection with this assignment, the
BLM partnership agreed to pay to Coso Land Company a royalty equal to 5.0% of
the value of the steam produced by BLM on the real property covered by the BLM
lease and certain other lands. The royalty is subordinated to the payment of
all of the BLM partnership's other royalties, all debt service of the BLM
partnership and all operating costs of BLM. As of March 31, 1999, the total
accrued balance of the royalty payable to Coso Land Company was $21.2 million.
The following table sets forth, for the three months ended March 31, 1998 and
March 31, 1999, and for the years ended December 31, 1996, 1997 and 1998, the
amount of the royalty payable to Coso Land Company that accrued during such
periods:
Three Months Ended March 31,
1999
------------------------------------
Three
Months Three Months One Month
Year Ended December 31, Ended Ended Ended
- --------------------------- March 31, February 28, March 31,
1996 1997 1998 1998 1999 1999 Total
(In thousands)
$2,400 $3,200 $3,100 $629 $438 $70 $508
No portion of the royalty that has accrued to date has been paid. Payment of
this royalty will be permitted only to the extent that restricted payments may
be made from funds or deposits in the Distribution Account established under
the Depositary Agreement, and is subordinated to all payments under the senior
secured notes. See "Description of Series B Notes--Distribution Account."
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DESCRIPTION OF SERIES B NOTES
We issued the Series A notes under an Indenture (the "Indenture") among U.S.
Bank Trust National Association, as trustee, the Coso partnerships and us in a
private transaction that was not subject to the registration requirements of
the Securities Act. You can find the definitions of the terms used in this
description under the heading "Certain Definitions." The terms of the Indenture
apply to the Series A notes and the Series B notes to be issued in exchange for
the Series A notes pursuant to the exchange offer. Upon the issuance of the
Series B notes or the effectiveness of the shelf registration statement, the
Indenture will be subject to the Trust Indenture Act of 1939 (the "Trust
Indenture Act").
The following is a summary of the material provisions of the Indenture, the
registration rights agreement, the Depositary Agreement, the security
agreements and the pledge agreements. It does not restate those agreements in
their entirety. We urge you to read all of these agreements because they, and
not this description, define your rights as holders of the Series B notes.
Copies of the proposed form of Indenture and the other financing documents are
available as set forth below under "--Additional Information." Certain defined
terms used in this description but not defined below under "--Certain
Definitions" have the meanings assigned to them in the Indenture. Except as
otherwise indicated below, the following summary applies to both the Series A
notes and the Series B notes.
Brief Description of the Senior Secured Notes and Guarantees
The senior secured notes:
. are our general obligations;
. are secured by:
(1) a perfected, first priority pledge of the promissory notes (the
"Partnership Notes") evidencing each Coso partnership's obligations
to repay the loan by us to each Coso Partnership;
(2) a perfected, first priority lien on the funds in the Accounts under
the Depositary Agreement; and
(3) a perfected, first priority pledge of all of our outstanding
Capital Stock;
. are pari passu in right of payment to all of our senior borrowings;
. are senior in right of payment to any of our future subordinated
Indebtedness; and
. are unconditionally guaranteed by the Coso partnerships. The Guarantees,
in turn, are secured by:
(1) a perfected, first priority lien on substantially all assets of the
Coso partnerships; and
(2) a perfected, first priority pledge of the Equity Interests in the
Coso partnerships.
The senior secured notes are payable solely from payments to be made by the
Coso partnerships under the Partnership Notes and from other funds that may be
available from time to time in the Accounts held by the Depositary. The Coso
partnerships' obligations to make payments under the Partnership Notes are non-
recourse to the direct and indirect owners of the Coso partnerships (including
Caithness Energy, L.L.C.) except, in the case of the direct owners of the Coso
partnerships, with respect solely to recourse to those owners' ownership
interests in the Coso
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partnerships pledged to the Collateral Agent as security for the Guarantees.
None of ESCA LLC, a Delaware limited liability company, and New CLOC Company,
LLC, a Delaware limited liability company, the general partners of the Navy I
Partnership (collectively, the "Navy I Partners"), Caithness Coso Holdings,
LLC, a Delaware limited liability company, and New CHIP Company, LLC, a
Delaware limited liability company, the general partners of the BLM Partnership
(collectively the "BLM Partners") or Caithness Navy II Group, LLC, a Delaware
limited liability company, and New CTC Company, LLC, a Delaware limited
liability company, the general partners of the Navy II Partnership
(collectively the "Navy II Partners" and, together with the Navy I Partners and
the BLM Partners, the "Partners"), nor any of the direct or indirect owners of
the Partners or of the Issuer, will be obligated to contribute additional funds
if monies in the Accounts are insufficient for the payment of debt service in
respect of the senior secured notes. So long as the senior secured notes are
outstanding, distributions to the Partners from the Distribution Account will
constitute Restricted Payments under and as defined in the Indenture.
Principal, Maturity and Interest
The Indenture provides for the issuance by us of up to $450.0 million of
senior secured notes, of which $110.0 million of Series A notes due 2001 and
$303.0 million of Series A notes due 2009 were issued at the closing of the
Series A notes offering. We will issue all Series B notes in denominations of
$100,000 and integral multiples of $1,000 in excess thereof. The Series B notes
due 2001 will mature on December 15, 2001, and the Series B notes due 2009 will
mature on December 15, 2009.
Interest on the Series B notes due 2001 will accrue at the rate of 6.80% per
annum and will be payable semi-annually in arrears on December 15 and June 15,
commencing December 15, 1999. We will make each interest payment to the Holders
of record of the Series B notes due 2001 on the immediately preceding December
1 and June 1, as the case may be. Interest on the Series B notes due 2009 will
accrue at the rate of 9.05% per annum and will be payable semi-annually in
arrears on December 15 and June 15, commencing December 15, 1999. We will make
each interest payment to the Holders of record of the Series B notes due 2009
on the immediately preceding December 1 and June 1, as the case may be.
Interest on the Series B notes will accrue from the date of original issuance
of the Series A notes which have been exchanged for such Series B notes or, if
interest has already been paid, from the date it was most recently paid.
Interest will be computed on the basis of a 360-day year comprised of twelve
30-day months.
We will pay the principal of the Series B notes due 2001 in semi-annual
installments, commencing December 15, 1999, as follows:
Scheduled Payment Percentage of Principal
Date Amount Payable
----------------- -----------------------
December 15, 1999 47.8773%
June 15, 2000 11.0736%
December 15, 2000 16.4427%
June 15, 2001 10.1900%
December 15, 2001 14.4164%
We will pay the principal of the Series B notes due 2009 in semi-annual
installments, commencing June 15, 2002, as follows:
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Scheduled Payment Percentage of Principal
Date Amount Payable
----------------- -----------------------
June 15, 2002 2.8743%
December 15, 2002 4.3109%
June 15, 2003 3.6564%
December 15, 2003 5.4584%
June 15, 2004 4.1363%
December 15, 2004 6.2043%
June 15, 2005 4.6838%
December 15, 2005 7.0257%
June 15, 2006 5.0541%
December 15, 2006 7.5815%
June 15, 2007 6.2601%
December 15, 2007 9.3898%
June 15, 2008 6.4927%
December 15, 2008 9.7650%
June 15, 2009 6.8231%
December 15, 2009 10.2835%
Methods of Receiving Payments on the Series B Notes
If a Holder has given wire transfer instructions to us, we will pay all
principal, interest, premium, if any, and Liquidated Damages, if any, on that
Holder's Series B notes in accordance with those instructions. Otherwise, we
will make all payments of principal, interest, if any, and Liquidated Damages,
if any, on the Series B notes at the office or agency of the Paying Agent and
Registrar within the City and State of New York unless we elect to make
interest payments by check mailed to the Holders at their respective addresses
set forth in the register of Holders.
Paying Agent and Registrar for the Series B Notes
The Trustee will initially act as Paying Agent and Registrar. We may change
the Paying Agent or Registrar without prior notice to the Holders, and we or
any of our Subsidiaries may act as Paying Agent or Registrar.
Transfer and Exchange
A Holder may transfer or exchange Series B notes in accordance with the
Indenture. The Registrar and the Trustee may require a Holder, among other
things, to furnish appropriate endorsements and transfer documents, and we may
require a Holder to pay any taxes and fees required by law or permitted by the
Indenture. We are not required to transfer or exchange any Series B note
selected for redemption. Also, we are not required to transfer or exchange any
Series B note for a period of 15 days before a selection of Series B notes to
be redeemed.
We and the Trustee will treat the registered Holder of a Series B note as the
owner of the Series B note for all purposes.
Guarantees
The Coso partnerships have fully and unconditionally, jointly and severally
guaranteed our obligations under the Indenture and the senior secured notes.
The obligation of each Coso partnership under its Guarantee is limited so as
not to constitute a fraudulent conveyance under applicable law.
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See "Risk Factors--Federal and state statute allow courts, under specific
circumstances, to void guarantees and require noteholders to return payments
received from guarantors."
Under the Guarantees, the Coso partnerships each have agreed for the benefit
of the Trustee and the Collateral Agent to be bound by and to perform all of
their obligations under covenants contained in the Credit Agreements. The
failure of the Coso partnerships to perform those covenants will result in a
Guarantee Event of Default, after the expiration of any applicable grace
period.
Security
The senior secured notes are secured by:
(1) a perfected, first priority pledge of the Partnership Notes evidencing
each Coso partnership's obligation to repay the loan made to it by us;
(2) a perfected, first priority lien on the funds in the Accounts under the
Depositary Agreement; and
(3) a perfected, first priority pledge of all of our outstanding Capital
Stock.
We have entered into a pledge agreement (the "Note Pledge Agreement")
providing for the pledge by us to U.S. Bank Trust National Association, as
collateral agent (in such capacity, the "Collateral Agent") for the benefit of
the Trustee and the Holders of the senior secured notes, of the Partnership
Notes held by us. We have also entered into the Depositary Agreement. The
Depositary Agreement grants to U.S. Bank Trust National Association, as
depositary (in such capacity, the "Depositary") for the benefit of the Trustee
and the Holders of the senior secured notes, a perfected, first priority lien
on the funds in the Accounts. Each Coso partnership, in its capacity as one of
our owners, has entered into a pledge agreement (each, a "Partnership Pledge
Agreement" and, together with the Note Pledge Agreement, the "Issuer Pledge
Agreements"). These pledge agreements provide for the perfected, first priority
pledge by each Coso partnership to the Collateral Agent, for the benefit of the
Trustee and the Holders of the senior secured notes, of all of our Capital
Stock. In addition, each affiliate of the Coso partnerships or us that holds
material assets related to the Projects has provided a lien on such assets to
secure the senior secured notes.
The Guarantees are secured by:
(1) a perfected first priority lien on substantially all of the assets of
the Coso partnerships; and
(2) a perfected, first priority pledge of all of the general partner
interests in the Coso partnerships.
Each of the Coso partnerships has entered into a Deed of Trust and a Security
Agreement which provides for a perfected, first priority lien on the assets of
the Coso partnerships. The Partners have entered into one or more pledge
agreements (each, a "Partner Pledge Agreement" and, together with the Issuer
Pledge Agreements, the "Pledge Agreements") which provides for the perfected,
first priority pledge to the Collateral Agent for the benefit of the Trustee
and the Holders of the Series B notes of all of the respective general partner
interests of each of (i) the Navy I Partners in the Navy I Partnership, (ii)
the BLM Partners in the BLM Partnership and (iii) the Navy II Partners in the
Navy II Partnership. These pledges secure the payment and performance when due
of all of the Obligations under the Guarantees.
158
So long as no Event of Default has occurred and is continuing, and subject to
certain terms and conditions in the Indenture, the Credit Agreements and the
Security Documents, all revenues actually received by the Coso partnerships
will be allocated to the appropriate Accounts in the manner described under the
caption "Flow of Funds."
Upon the occurrence and during the continuance of an Event of Default:
(1) all of our rights and the rights of the Coso partnerships and the
Partners to exercise any voting or other consensual rights in respect
of the pledged Collateral will cease. All of these rights will become
vested in the Trustee, which, to the extent permitted by law, will have
the sole right to exercise these voting and other consensual rights;
(2) the Trustee may sell the pledged Collateral or any part thereof for the
benefit of the Trustee and the Holders in accordance with the terms of
the Security Documents; and
(3) the Trustee shall have all rights of a "secured party" under the
Uniform Commercial Code of the State of New York.
All funds distributed under the Security Documents and the Indenture and
received by the Trustee for the benefit of the Holders will be distributed by
the Trustee in accordance with the provisions of the Indenture.
The Trustee will determine the circumstances and manner in which it will
dispose of the Collateral, including whether to release all or any portion of
the Collateral from the Liens created by the Security Documents and whether to
foreclose on the Collateral following an Event of Default. Upon the full and
final payment and performance of all Obligations in respect of the Partnership
Notes, the Indenture, the Series B notes and the Security Documents will
terminate and the Collateral will be released.
Optional Redemption
The Series B notes due 2001 are not redeemable.
The Series B notes due 2009 are redeemable at our option at any time and from
time to time, in whole or in part, upon not less than 30 nor more than 60 days
notice to each Holder of Series B notes due 2009, at a redemption price equal
to the Make-Whole Price. "Make-Whole Price" means an amount equal to the
greater of (i) 100% of the principal amount of such Series B notes due 2009 and
(ii) as determined by a Reference Treasury Dealer, the sum of the present
values of the remaining scheduled payments of principal and interest thereon
discounted to the date of redemption on a semiannual basis (assuming a 360-day
year consisting of twelve 30-day months) at the Treasury Rate plus 50 basis
points, plus, in each case, accrued and unpaid interest thereon to the
Redemption Date. Unless we default in payment of the redemption price, on and
after the Redemption Date, interest will cease to accrue on the Series B notes
due 2009 or portions thereof called for redemption.
Mandatory Redemption
We will be required to redeem the Series B notes as described below. The
Series B notes will be subject to mandatory redemption, in whole or in part,
ratably among each series at a redemption price equal to the principal amount
of the Series B notes being redeemed plus accrued and unpaid interest to the
redemption date, upon:
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(1) the receipt of Loss Proceeds or Eminent Domain Proceeds by a Coso
partnership if the applicable Coso partnership determines that:
(a) the affected Project cannot be rebuilt, repaired or restored to
permit operations on a commercially reasonable basis, or the
applicable Coso partnership determines not to rebuild, repair or
restore the affected Project, in which case the amount of such Loss
Proceeds or Eminent Domain Proceeds shall be available for such
redemption, or
(b) only a portion of the affected Project is capable of being rebuilt,
repaired or restored, in which case, if excess proceeds exist after
such rebuild, repair or restoration, only the amount of such excess
Loss Proceeds or Eminent Domain Proceeds shall be made available
for such redemption;
(2) the receipt by the applicable Coso partnership of proceeds in
connection with a Title Event, in which case the amount of such Title
Event Proceeds shall be made available for such redemption, subject to
reduction by the costs expended in connection with collecting proceeds
upon the occurrence of such Title Event, and any additional reasonable
costs or expenses that the Coso partnerships will be subject to as a
result of the Title Event;
(3) the receipt by the Coso partnerships of net proceeds in excess of $5.0
million realized in connection with a Permitted Power Contract Buy-Out,
or $10.0 million, when aggregated with all previous Permitted Power
Contract Buy-Outs, in which case the amount of all proceeds associated
with such Permitted Power Contract Buy-Outs shall be made available for
such redemption, unless each of the Rating Agencies confirm that a
Rating Downgrade will not occur if no redemption is made with such
proceeds; and
(4) the receipt by the Coso partnerships of net proceeds received in
connection with a termination of the Navy Contract under Section
VIII(2) of the Navy Contract (P0004 Modification dated October 19,
1983).
Selection and Notice
If less than all of the Series B notes are to be redeemed at any time, the
Trustee will select Series B notes for redemption on a pro rata basis, unless
otherwise required by the principal national securities exchange, if any, on
which the Series B notes are listed; provided that no Series B notes of $1,000
or less shall be redeemed in part; and provided, further, that in the case of
redemption of the Series B notes due 2009 at our option, only Series B notes
due 2009 will be redeemed. We will mail notices of redemption by first class
mail at least 30 but not more than 60 days before the redemption date to each
Holder of Series B notes to be redeemed at its registered address. Notices of
redemption may not be conditional. If any Series B note is to be redeemed in
part only, the notice of redemption that relates to that Series B note shall
state the portion of the principal amount of the Series B note to be redeemed.
A new Series B note in principal amount equal to the unredeemed portion of the
partially redeemed Series B note will be issued in the name of the Holder of
the partially redeemed Series B note upon cancellation of the original Series B
note. Series B notes called for redemption will become due on the date fixed
for redemption. Unless we default in payment of the redemption price on and
after the redemption date, interest ceases to accrue on Series B notes or
portions of them called for redemption.
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Repurchase at the Option of Holders upon Change of Control
Upon the occurrence of a Change of Control, each Holder of Series B notes
will have the right to require us to repurchase all or any part (equal to
$1,000 or an integral multiple thereof) of such Holder's Series B notes
pursuant to the offer described below (the "Change of Control Offer") at an
offer price in cash equal to 101% of the aggregate principal amount thereof
plus accrued and unpaid interest and Liquidated Damages thereon, if any, to the
date of purchase (the "Change of Control Payment"). Within ten days following
any Change of Control, we will mail a notice to each Holder describing the
transaction or transactions that constitute the Change of Control and offering
to repurchase Series B notes on the date specified in such notice, which date
shall be no earlier than 30 days and no later than 60 days from the date such
notice is mailed (the "Change of Control Payment Date"), pursuant to the
procedures required by the Indenture and described in such notice. We will
comply with the requirements of Rule 14e-1 under the Exchange Act and any other
securities laws and regulations thereunder to the extent such laws and
regulations are applicable in connection with the repurchase of the Series B
notes as a result of a Change of Control.
On the Change of Control Payment Date, we will, to the extent lawful,
(1) accept for payment all Series B notes or portions thereof properly
tendered pursuant to the Change of Control Offer,
(2) deposit with the Paying Agent an amount equal to the Change of Control
Payment in respect of all Series B notes or portions thereof so
tendered, and
(3) deliver or cause to be delivered to the Trustee the Series B notes so
accepted together with an Officers' Certificate stating the aggregate
principal amount of Series B notes or portions thereof being purchased
by us.
The Paying Agent will promptly mail to each Holder of Series B notes so
tendered the Change of Control Payment for such Series B notes, and the Trustee
will promptly authenticate and mail (or cause to be transferred by book entry)
to each Holder a new Series B note equal in principal amount to any unpurchased
portion of the Series B notes surrendered, if any; provided that each such new
Series B note will be in a principal amount of $1,000 or an integral multiple
thereof. We will publicly announce the results of the Change of Control Offer
on or as soon as practicable after the Change of Control Payment Date.
The Change of Control provisions described above will be applicable whether
or not any other provisions of the Indenture are applicable. Except as
described above with respect to a Change of Control, the Indenture will not
contain provisions that permit the Holders of the Series B notes to require
that we repurchase or redeem the Series B notes in the event of a takeover,
recapitalization or similar transaction. Finally, our ability to pay cash to
the Holders of Series B notes upon a repurchase may be limited by our then
existing financial resources. See "Risk Factors--We may not have the funds
necessary to finance a change of control offer which may be required under the
Indenture."
We will not be required to make a Change of Control Offer upon a Change of
Control if a third party makes the Change of Control Offer in the manner, at
the times and otherwise in compliance with the requirements set forth in the
Indenture applicable to a Change of Control Offer made by us and purchases all
Series B notes validly tendered and not withdrawn under such Change of Control
Offer.
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The definition of Change of Control includes a phrase relating to the sale,
lease, transfer, conveyance or other disposition of "all or substantially all"
of our assets and the assets of the Coso partnerships taken as a whole.
Although there is a developing body of case law interpreting the phrase
"substantially all," there is no precise established definition of the phrase
under applicable law. Accordingly, the ability of a Holder of Series B notes to
require us to repurchase such Series B notes as a result of a sale, lease,
transfer, conveyance or other disposition of less than all of our assets and
the assets of the Coso partnerships taken as a whole to another Person or group
may be uncertain.
Ratings
Moody's has assigned the Series B notes due 2001 a rating of "Ba1" and the
Series B notes due 2009 a rating of "Ba2." S&P has assigned each of the Series
B notes due 2001 and the Series B notes due 2009 a rating of "BB." Duff &
Phelps has assigned the Series B notes due 2001 a rating of "BB+" and the
Series B notes due 2009 a rating of "BB." We cannot assure you that any of
these credit ratings will remain in effect for any period of time or that these
ratings will not be lowered, suspended or withdrawn entirely by Moody's, S&P or
Duff & Phelps, if, in their judgment, circumstances warrant a change. Any
lowering, suspension or withdrawal of any rating may have a material adverse
effect on the market price or marketability of the Series B notes.
Nature of Recourse on the Series B Notes
All payments of principal, interest, and premium, if any, and Liquidated
Damages, if any, on the Series B notes will be solely our obligations. Our
obligations to make those payments are secured by the liens described under "--
Security" and are guaranteed by the Coso partnerships. The Guarantees, in turn,
are secured by a perfected, first priority lien on substantially all of the
assets of the Coso partnerships, and the ownership interests in the Coso
partnerships. The Series B notes are payable solely from payments to be made by
the Coso partnerships under the Partnership Notes and from other funds that may
be available from time to time in the Accounts held by the Depositary. The Coso
partnerships' obligations to make payments under the Partnership Notes are non-
recourse to the direct and indirect owners of the Coso partnerships (including
Caithness Energy, L.L.C.) except, in the case of the Partners, with respect
solely to recourse to the Partner's ownership interests in the Coso
partnerships pledged to the Collateral Agent as security for the Guarantees.
Except for the Coso partnerships and the Partners (solely to the extent that
each Partner has pledged its ownership interests in the relevant Coso
partnership), neither our shareholders nor any Affiliate, incorporator,
officer, director or employee of theirs or of ours has guaranteed the payment
of the Series B notes or has any obligation with respect to the payment of the
Series B notes.
Flow of Funds
Depositary Agreement
Under the Depositary Agreement, the Collateral Agent, on behalf of the
Secured Parties, has appointed the Depositary as security agent for the Secured
Parties with respect to funds of the Coso partnerships in which the Depositary
has been granted a security interest. The Depositary will hold, invest and
disburse funds in which the Depositary and/or the Collateral Agent, on behalf
of the Secured Parties, has been granted a security interest. Neither we nor
any of the Coso partnerships has any right of withdrawal under any Account
except under the circumstances established under the Depositary Agreement.
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The Depositary Agreement Accounts
The Coso partnerships have established and created the following accounts
(collectively, the "Accounts") with the Depositary under the Depositary
Agreement and pledged these Accounts as security for the benefit of the
Depositary and the Collateral Agent acting on behalf of all the Secured
Parties:
(1) Revenue Account;
(2) Principal Account;
(3) Interest Account;
(4) Debt Service Reserve Account;
(5) Capital Expenditure Reserve Account;
(6) Operating and Maintenance Fees Account;
(7) Management Fees Account;
(8) Distribution Account;
(9) Distribution Suspense Account;
(10) Loss Proceeds Account; and
(11) Redemption Account.
All amounts deposited with the Depositary, at our written request and
direction, will be invested by the Depositary in Permitted Investments.
Revenue Account; Priority of Payments
All revenues or other proceeds actually received by the Coso partnerships or
otherwise derived from the ownership or operation of the Coso projects are
required to be paid into the Revenue Account. The Coso partnerships have
arranged for the direct payment of all such revenues into the Revenue Account,
and no Coso partnership has any right of withdrawal from the Revenue Account
except pursuant to the priority of payments set forth below.
The Revenue Account is funded from the following:
(1) all revenues and other proceeds actually received by the Coso
partnerships (including payments under the Power Purchase Agreements);
(2) to the extent amounts in the Debt Service Reserve Account equal the
Debt Service Reserve Required Balance, the income, if any, from the
investment of funds in such Account; and
(3) other amounts as required to be transferred to the Revenue Account from
any other Account pursuant to the Depositary Agreement.
Upon receipt of a certificate from the relevant Coso partnership (or its duly
authorized agent for such purposes) detailing the amounts to be paid, funds in
the Revenue Account shall be transferred via wire transfer by the Depositary in
the following priority:
First, as and when required, to pay the Coso partnerships' Operating and
Maintenance Costs, provided that, if the cumulative Operating and Maintenance
Costs of the Coso partnerships in any fiscal year exceed the projected
Operating and Maintenance Costs of the Coso partnerships in the
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applicable annual Operating Budget of the Coso partnerships by more than 25%,
then no amounts may be withdrawn on behalf of the Coso partnerships to pay non-
budgeted operating costs unless the Coso partnerships certify that (1) such
additional non-budgeted costs are reasonably designed to permit the Coso
partnerships to satisfy their obligations in respect of the Partnership Notes
and maximize their revenue and net income and (2) the Independent Engineer
certifies that the additional cost is prudent and reasonable.
Second, on a monthly basis, to the Depositary, the Trustee, any Permitted
Additional Senior Lender and the Collateral Agent any amounts then due and
payable to each of them as fees, costs and expenses; provided, however, that if
funds in the Revenue Account are insufficient on any date to make the payments
specified in this paragraph Second, distribution of funds shall be made ratably
to the specified recipients based on the respective amounts owed such
recipients;
Third, on a monthly basis, (1) to the Interest Account an amount which,
together with the amount then in such account, equals all of the interest due
or becoming due on the senior secured notes and, without duplication, the
Partnership Notes on the next succeeding Interest Payment Date; (2) to the
Principal Account an amount which, together with the amount then in such
account, equals all of the principal and premium, if any, and Liquidated
Damages, if any, due or becoming due on the senior secured notes and, without
duplication, the Partnership Notes on the next succeeding Principal Payment
Date; (3) to a sub-account within the Principal Account an amount which,
together with the amounts then in such sub-account, equals all of the principal
due or becoming due on any Permitted Indebtedness or other Permitted
Partnership Indebtedness other than such Indebtedness described in clause (4)
of the definition of Permitted Indebtedness within the succeeding six-month
period; and (4) to a sub-account within the Interest Account an amount which,
together with the amounts then in such sub-account, equals all of the interest
due or becoming due on any Permitted Indebtedness or other Permitted
Partnership Indebtedness other than such Indebtedness described in clause (4)
of the definition of Permitted Indebtedness within the succeeding six-month
period (except to the extent that Permitted Indebtedness or other Permitted
Partnership Indebtedness other than such Indebtedness described in clause (4)
of the definition of Permitted Indebtedness is otherwise available to pay such
interest); provided, however, that if monies in the Revenue Account are
insufficient on any date to make the transfers specified in this paragraph
Third, distribution of monies shall be made ratably to the specified Accounts
based on the respective amounts owed such Accounts;
Fourth, on a monthly basis, if the amount available to be drawn under the
Debt Service Reserve Letter of Credit is less than the Debt Service Reserve
Required Balance, to the Debt Service Reserve Account an amount as necessary to
fund the Debt Service Reserve Account so that the sum of the amount available
to be drawn under the Debt Service Reserve Letter of Credit plus the balance in
the Debt Service Reserve Account equals the Debt Service Reserve Required
Balance;
Fifth, on a monthly basis, to the Capital Expenditure Reserve Account, an
amount necessary to cause the balance thereof to be equal to the Capital
Expenditure Reserve Required Balance;
Sixth, on a monthly basis, to the Operating and Maintenance Fees Account, an
amount necessary for the payment of Operating and Maintenance Fees then due and
owing;
Seventh, on a monthly basis, to the Management Fees Account, an amount
necessary for the payment of Management Fees then due and owing;
Eighth, on a monthly basis, any remaining amounts to the Distribution
Account; and
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Ninth, any amounts in the Distribution Account which cannot be distributed
because of the failure to satisfy certain conditions to distributions, to the
Distribution Suspense Account.
Interest Account and Principal Account
Funds in the Interest Account and the Principal Account shall be utilized to
make payments of interest and Liquidated Damages, if any, principal and
premium, if any, on the Partnership Notes, the senior secured notes and any
outstanding Permitted Indebtedness or other Permitted Partnership Indebtedness
other than such Indebtedness described in clause (4) of the definition of
Permitted Indebtedness.
Debt Service Reserve Account
The Debt Service Reserve Account was initially funded from the proceeds of
the Series A notes offering in an amount that equaled the Debt Service Reserve
Required Balance as of May 28, 1999. We may replace funds held in the Debt
Service Reserve Account with a Debt Service Reserve Letter of Credit having a
stated amount equal to the amount being withdrawn from the Debt Service Reserve
Account. These deposits, in conjunction with the Debt Service Reserve Letter of
Credit, if any, will be available in the event the Revenue Account, the
Principal Account and the Interest Account lack sufficient funds on a Payment
Date to meet payments of principal, premium, if any, and interest on the senior
secured notes.
At any time that the sum of the amount available to be drawn under the Debt
Service Reserve Letter of Credit plus the amount then on deposit in the Debt
Service Reserve Account is less than the Debt Service Reserve Required Balance,
the Debt Service Reserve Account shall then accumulate cash deposits from, and
in the following order of priority:
(1) the Revenue Account, as provided above under the caption "Flow of
Funds--Revenue Account; Priority of Payments"; and
(2) net interest, if any, earned on amounts deposited in the Debt Service
Reserve Account; and
(3) amounts then on deposit in the Operating and Maintenance Fees Account
and the Management Fees Account (in equal amounts from each such
Account),
until the sum of the amount available to be drawn under the Debt Service
Reserve Letter of Credit plus the amount then on deposit in the Debt Service
Reserve Account equals the Debt Service Reserve Required Balance. Once the Debt
Service Reserve Required Balance is reached, interest income, if any, in excess
of such amount shall be transferred to the Revenue Account.
Capital Expenditure Reserve Account
The Capital Expenditure Reserve Account shall be funded in accordance with
the provisions set forth above under the caption "Flow of Funds--Revenue
Account; Priority of Payments" and in accordance with the Operating Budget and
schedules thereto approved by the Independent Engineer prior to the end of each
calendar year (and, in good faith, so as to implement even monthly
contributions) or with such variations from such Operating Budget and schedules
as the Coso partnerships certify to the Trustee are reasonable and necessary
and in accordance with prudent industry practice. Amounts on deposit in the
Capital Expenditure Reserve Account shall be used for Capital Expenditures to
be made in accordance with prudent industry practice and as may be required
pursuant to the terms of the Indenture and the Depositary Agreement.
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Operating and Maintenance Fees Account
Funds in the Operating and Maintenance Fees Account shall be used for the
payment of Operating and Maintenance Fees due and owing; provided that:
(1) the aggregate amount of all Operating and Maintenance Fees paid on
account of any twelve month period shall not exceed an amount equal to
$2.0 million plus the CPI Adjustment; and
(2) the payment of any Operating and Maintenance Fees due and owing in
excess of the amount permitted pursuant to clause (1) above shall be
subject to the prior satisfaction of the conditions set forth under the
caption "--Distribution Account."
In addition, funds in the Operating and Maintenance Fees Account shall be
transferred to the Debt Service Reserve Account under the circumstances
described in the second paragraph under the caption "Debt Service Reserve
Account."
Management Fees Account
Funds in the Management Fees Account shall be used for the payment of
Management Fees due and owing subject to:
(1) the prior satisfaction of the conditions set forth under the caption
"Distribution Account"; and
(2) compliance by the Coso partnerships with the covenant set forth under
the caption "Credit Agreements--Certain Covenants--Required Geothermal
Percentage."
In addition, funds in the Management Fees Account shall be transferred to the
Debt Service Reserve Account under the circumstances described in the second
paragraph under the caption "Debt Service Reserve Account."
Distribution Account
The Distribution Account receives funds transferred from the Revenue Account
after all other then required amounts have been paid as provided above under
the caption "Revenue Account; Priority of Payments." Restricted Payments may be
made only from and to the extent of funds on deposit in the Distribution
Account. Such distributions are subject to the prior satisfaction of the
following conditions:
(1) the amount then on deposit in the Principal Account shall be equal to
or greater than the aggregate payments of principal and premium, if
any, and Liquidated Damages, if any, due on the senior secured notes
and, without duplication, the Partnership Notes on the next succeeding
Principal Payment Date and on other Permitted Indebtedness and
Permitted Partnership Indebtedness (other than such Indebtedness
described in clause (4) of the definition of Permitted Indebtedness)
within the succeeding six-month period, and the amount then on deposit
in the Interest Account shall be equal to or greater than the aggregate
payments of interest due on the senior secured notes and (without
duplication) the Partnership Notes on the next succeeding Interest
Payment Date and on other Permitted Indebtedness and Permitted
Partnership Indebtedness (other than such Indebtedness described in
clause (4) of the definition of Permitted Indebtedness) within the
succeeding six-month period;
(2) the amount available to be drawn under the Debt Service Reserve Letter
of Credit plus the amount on deposit in the Debt Service Reserve
Account equals or exceeds the Debt Service Reserve Required Balance and
the amount on deposit in the Capital Expenditure Reserve Account equals
or exceeds the Capital Expenditure Reserve Required Balance;
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(3) no Default or Event of Default has occurred and is continuing;
(4) the Debt Service Coverage Ratio for the most recently ended four full
fiscal quarters for which internal financial statements are available
immediately preceding the date on which such distribution is to be made
(or in the case of any proposed distribution date prior to January 1,
2000, the Debt Service Coverage Ratio for the period commencing on May
1, 1999, and ending on the last date of the most recently ended month
for which internal financial statements are available immediately
preceding the date on which such distribution is to be made) is equal
to or greater than (a) 1.25 to 1 for any annual or interim period
ending prior to or as of December 30, 2001 or (b) 1.4 to 1 for any
annual or interim period ending after December 30, 2001, in either case
as certified by one of our authorized officers;
(5) the projected Debt Service Coverage Ratio for the next succeeding four
full fiscal quarters is equal to or greater than (a) 1.25 to 1 for any
annual or interim period ending prior to or as of December 30, 2001 or
(b) 1.4 to 1 for any annual or interim period ending after December 30,
2001, in either case as certified by one of our authorized officers;
(6) We provide to the Trustee an Officers' Certificate at the time of each
distribution stating that, based on customary assumptions, as of such
date, sufficient geothermal resources remain to operate the Projects at
contract capacity through the Final Maturity Date; and
(7) the Geothermal Engineer provides to the Trustee (a) a written
certificate at least annually stating that, for the period covered by
such certification, the wells then in operation are producing, in the
aggregate among the Projects, at least 105% of the steam necessary to
generate the energy projected for the comparable period in the
Independent Engineer's Base Case Projections and (b) during the
calendar year 2006, a report on the geothermal resource available as of
such date and whether sufficient geothermal resource remains to enable
the Projects, in the aggregate, to produce sufficient steam to generate
the energy projected in the Independent Engineer's Base Case
Projections through the maturity date of the Series B notes due 2009.
Distribution Suspense Account
Funds in the Distribution Account which may not be distributed because of a
failure to satisfy any conditions to distributions will be transferred to the
Distribution Suspense Account. Funds in the Distribution Suspense Account may
be transferred back to the Distribution Account and distributed when (1) all
conditions to distribution are satisfied and (2) no Default or Event of Default
has occurred and is continuing. At any time that funds in the Revenue Account
are not sufficient to pay any amounts which are due and payable and required to
be paid with proceeds of the Revenue Account, then funds in the Distribution
Suspense Account shall be transferred to the Revenue Account for distribution
as required.
Loss Proceeds Account
All Loss Proceeds and Eminent Domain Proceeds received by the Coso
partnerships shall be deposited in the Loss Proceeds Account subject to
disbursement for repair or replacement of the assets affected, or otherwise, as
follows:
The Depositary will apply the amounts in the Loss Proceeds Account to the
payment (or reimbursement to the extent the same have been paid or satisfied by
the relevant Coso partnership) of the costs of repair or replacement of the
relevant Project or any part thereof that has been affected
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due to an Event of Loss or Event of Eminent Domain upon the Depositary's
receipt of a complete and properly executed requisition from an authorized
officer of the relevant Coso partnership and approved by the Independent
Engineer; provided, however, that no such approval of the Independent Engineer
shall be required if less than $5.0 million in the aggregate for all Coso
projects affected by such occurrence is requested pursuant to such requisition
or requisitions in any fiscal year.
If the applicable Coso partnership determines that the affected Project is
not capable of being rebuilt or replaced to permit operation on a commercially
reasonable basis, or determines not to rebuild, repair or restore the affected
Project (or if the Loss Proceeds and Eminent Domain Proceeds, together with any
other amounts available to such Coso partnership for such rebuilding or
replacement, are not sufficient to permit such rebuilding or replacement), the
Depositary shall transfer the Loss Proceeds and Eminent Domain Proceeds to the
Collateral Agent for distribution to the Redemption Account in accordance with
the Indenture and the Depositary Agreement. The Depositary shall transfer the
Loss Proceeds and Eminent Domain Proceeds in excess of the cost of repairing or
replacing the affected Project to the Redemption Account in accordance with the
Indenture and the Depositary Agreement. If the applicable Coso partnership does
not rebuild or replace the affected Project, the Depositary shall transfer the
Loss Proceeds and Eminent Domain Proceeds to the Collateral Agent for
distribution to the Redemption Account in accordance with the Indenture and the
Depositary Agreement. See "--Mandatory Redemption."
All Title Event Proceeds received by the Coso partnerships, as applicable,
shall be deposited in the Loss Proceeds Account subject to disbursement in
connection with remedying such Title Event. Any Title Event Proceeds not so
expended shall be transferred to the Redemption Account.
Redemption Account
The Redemption Account will be funded from:
(1) certain proceeds received in connection with an Event of Loss, an Event
of Eminent Domain or a Title Event;
(2) certain proceeds realized in connection with a Permitted Power Contract
Buy-Out;
(3) proceeds received in connection with a termination of the Navy Contract
under Section VIII(2) thereof; and
(4) proceeds received as a result of the foreclosure or the Collateral
serving the obligations of the Coso partnerships following an Event of
Default under the Indenture.
All proceeds received in connection with an Event of Loss, Event of Eminent
Domain or a Title Event will be deposited in the Loss Proceeds Account and
proceeds will be transferred to the Redemption Account if not used to repair or
replace the affected Project or remediate the title deficiency, as permitted
under the Indenture, and shall be distributed to the Collateral Agent for
distribution after giving effect to the provisions of the Indenture, and the
Depositary Agreement with respect to such proceeds. See "--Mandatory
Redemption."
Investment of Monies
Amounts deposited in the Accounts under the Depositary Agreement, at our or
any of the Coso partnership's written request and direction, shall be invested
by the Depositary in Permitted Investments. Such investments shall generally
mature in such amounts and not later than such times
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as may be necessary to provide monies when needed to make payments from such
monies as provided in the Depositary Agreement. Net interest or gain received,
if any, from such investments shall be applied as provided in the Depositary
Agreement. Absent written instructions from us, the Depositary shall invest the
amounts held in the accounts and funds under the Depositary Agreement in
Permitted Investments described in clause (1) of such definition. So long as an
outstanding balance shall remain in any of the Accounts under the Depositary
Agreement, the Depositary shall provide us and the Coso partnerships with
monthly statements showing the amount of all receipts, the net investment
income or gain received and collected, all disbursements and the amount then
available in each such Account.
Certain Covenants
Actions with Respect to the Credit Agreements
We will enforce all of our rights under the Credit Agreements and the
Partnership Notes for the benefit of the Trustee and the Holders. We will not
grant any consents or waivers thereunder, amend or modify any provisions
thereof or otherwise modify the Credit Agreements or the Partnership Notes,
except as provided below. See "--Amendment of Credit Agreement and Partnership
Notes."
Limitations on Indebtedness
We may not create or incur or suffer to exist any Indebtedness other than
Permitted Indebtedness.
Limitations on Guarantees
We may not contingently or otherwise be or become liable in connection with
any guarantee, except for endorsements and similar obligations in the ordinary
course of business.
Liens
We may not directly or indirectly, create, incur, assume or suffer to exist
any Lien of any kind on any asset now owned or hereafter acquired, except
Permitted Liens described in clause (1) of the definition of Permitted Liens.
Restricted Payments
We may not make any Restricted Payments or direct any Restricted Payments to
be made on behalf of any Coso partnership except for payments permitted under
the Depositary Agreement as described under the caption "Flow of Funds."
Prohibitions on Other Obligations or Assignments
We may not assign any of our rights or obligations under any Financing
Document, and may not enter into additional contracts if it would be reasonably
expected to cause a Material Adverse Effect and except otherwise only as
contemplated under the Indenture, including entering into contracts in
connection with investments in Permitted Investments.
Prohibitions on Fundamental Changes
We may not enter into any transaction of merger or consolidation, change our
form of organization or our business, liquidate, wind-up or dissolve or
discontinue our business. We are also restricted from engaging in any business
other than in connection with the issuance of the senior secured notes, the
incurrence of Permitted Indebtedness and the performance of our obligations
under the Transaction Documents. We may not lease (as lessor) or sell,
transfer, assign, hypothecate, pledge or otherwise dispose of any of our
property or assets, except as may be contemplated by the Financing Documents.
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Additional Covenants
In addition to the covenants described above, the Indenture contains
covenants applicable to us regarding (1) maintenance of existence, (2) payment
of taxes, (3) maintenance of books and records, (4) compliance with laws, (5)
delivery to the Trustee and the Rating Agencies of compliance certificates and
of notices of Credit Agreement Events of Default and Guarantee Events of
Default, (6) delivery to the Trustee and the Rating Agencies of unaudited
quarterly reports for us and the Coso partnerships for the first three quarters
of each fiscal year containing condensed combined financial information and
audited annual reports for us and the Coso partnerships, and (7) delivery to
the Trustee of all other information required to be delivered pursuant to Rule
144A(d)(4) under the Securities Act in order to permit compliance by a Holder
with Rule 144A in connection with the resale of Series A notes.
Events of Default
Certain Events
The Indenture provides that the following events constitute Events of
Default:
(1) Failure to pay any principal, interest or other amounts owed on any
senior secured notes when the same becomes due and payable, whether by
scheduled maturity or required prepayment or redemption or by
acceleration or otherwise, and such failure continues for ten days or
more following the due date for payment;
(2) A Credit Agreement Event of Default or a Guarantee Event of Default has
occurred and is continuing;
(3) Any representation or warranty made by us in the Indenture or in any
other Financing Document, or any representation, warranty or statement
in any certificate, financial statement or other document furnished to
the Trustee or any other Person by us or on our behalf, proves to have
been untrue or misleading in any material respect as of the time made,
confirmed or furnished and the fact, event or circumstance that gave
rise to such inaccuracy has resulted in, or could reasonably be
expected to result in, a Material Adverse Effect and that fact, event
or circumstance continues uncured for 30 or more days from the date one
of our Responsible Officers receives notice thereof from the Trustee;
provided that, if we commence and diligently pursue efforts to cure
such fact, event or circumstance within such 30-day period and deliver
written notice to the Trustee thereof, we may continue to effect such
cure, and such misrepresentation shall not be deemed an Event of
Default for an additional 60 days so long as we are diligently pursuing
such cure;
(4) We fail to perform or observe any covenant or agreement contained in
the Indenture regarding maintenance of existence or restrictions on
Indebtedness, Liens, Restricted Payments, guarantees, disposition of
assets, amendments to the Credit Agreement or Partnership Notes or
taking of actions thereunder as directed by the Required Holders,
fundamental changes, or nature of business and such failure continues
uncured for 30 or more days from the date one of our Responsible
Officers receives notice thereof from the Trustee;
(5) We fail to perform or observe any of our covenants contained in the
Indenture (other than those contained in (4) above) and such failure
continues uncured for 30 or more days from the date one of our
Responsible Officers receives notice thereof from the Trustee of such
failure; provided that if we commence and diligently pursue efforts to
cure such default within such 30-day period, we may continue to effect
such cure of the default and such default will not be deemed an Event
of Default for an additional 90 days so long as we are diligently
pursuing such cure;
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(6) Certain events involving our bankruptcy, insolvency, receivership or
reorganization;
(7) Any Pledge Agreement ceases to be in full force and effect or there is
a Material Adverse Effect on the Lien purported to be granted in any
Issuer Pledge Agreement such that it ceases to be a valid and perfected
Lien in favor of the Collateral Agent for the benefit of the Secured
Parties on the Collateral described therein with the priority purported
to be created thereby; provided, however, that we have 10 days after
one of our Responsible Officers obtains actual knowledge thereof to
cure any such cessation, if curable, or to furnish to the Collateral
Agent all documents or instruments required to cure any such cessation,
if curable; or
(8) Any event of default under any of our Indebtedness which results in
Indebtedness in excess of $2.5 million becoming due and payable prior
to its stated maturity.
Control by Holders
The Holders of at least a majority in aggregate principal amount of
Outstanding Notes (the "Required Holders") will have the right to direct the
time, place and method of conducting any proceeding for any right or remedy
available to the Trustee or exercising any trust or power conferred on the
Trustee in the Indenture. The Required Holders, acting through the Trustee,
will have the right to direct the time, place and method for exercising any
right or remedy available to the Issuer under the Credit Agreements and the
Partnership Notes; provided that upon the occurrence of an Event of Default
related to failure to make payments on the senior secured notes, Holders of 25%
in aggregate principal amount of the Outstanding Notes have the right to cause
the acceleration of the Partnership Notes.
Subject to the above paragraph, if an Event of Default has occurred and is
continuing and as a result thereof or in connection therewith or pursuant to an
acceleration of the senior secured notes arising therefrom, payments on the
senior secured notes are not made when due, the Trustee is required to enforce
the Guarantees and the rights of the Holders thereunder.
Enforcement of Remedies
If one or more Events of Default have occurred and are continuing, then:
(a) in the case of an Event of Default described in clause (6) above under
"Certain Events," the entire principal amount of the Outstanding Notes,
all interest accrued and unpaid thereon, and all premium and other
amounts payable under the senior secured notes and the Indenture, if
any, will automatically become due and payable without presentment,
demand, protest or notice of any kind; or
(b) in the case of an Event of Default described in clause (2) (in
connection with a Credit Agreement Event of Default or a Guarantee
Event of Default) above under "Certain Events" relating to certain
events involving the bankruptcy, insolvency, receivership or
reorganization of any of the Coso partnerships, the entire principal
amount of the Outstanding Notes (on a pro rata basis), all interest
accrued and unpaid thereon, and all premium and other amounts payable
under the senior secured notes and the Indenture, if any, will
automatically become due and payable without presentment, demand,
protest or notice of any kind; or
(c) in the case of an Event of Default described in:
(i) clause (1) above under "Certain Events," upon the direction of the
Holders of no less than 25% in aggregate principal amount of the
Outstanding Notes, the Trustee will, by
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notice to us, declare the entire principal amount of the Outstanding
Notes, all interest accrued and unpaid thereon, and all premium and
other amounts payable under the senior secured notes and the
Indenture, if any, to be due and payable, or
(ii) clauses (2) (except as described in clause (b) above), (3), (4),
(5), (7) or (8) above under "Certain Events," upon the direction of
the Required Holders, the Trustee will, by notice to us, declare
the entire principal amount of the Outstanding Notes, all interest
accrued and unpaid thereon, and all premium and other amounts
payable under the senior secured notes and the Indenture, if any,
to be due and payable.
If an Event of Default occurs and is continuing and is known to the Trustee,
the Trustee will mail to each Holder notice of the Event of Default within 30
days after the occurrence thereof. Except in the case of an Event of Default
in payment of principal of or interest on any senior secured note, the Trustee
may withhold the notice to the Holders if the Trustee in good faith determines
that withholding the notice is in the interest of the Holders.
If an Event of Default relating to failure to pay amounts owed on the senior
secured notes has occurred and is continuing, the Trustee may declare the
principal amount of the Outstanding Notes, all interest accrued and unpaid
thereon, and all premium and other amounts payable under the senior secured
notes and the Indenture, if any, to be due and payable notwithstanding the
absence of direction from Holders of at least 25% in aggregate principal
amount of the Outstanding Notes directing the Trustee to accelerate the
maturity of the senior secured notes unless Holders of more than 75% in
aggregate principal amount of the Outstanding Notes direct the Trustee not to
accelerate the maturity of such senior secured notes, if in the good faith
exercise of its discretion the Trustee determines that such action is
necessary to protect the interests of the Holders.
If an Event of Default relating to a Credit Agreement Event of Default or a
Guarantee Event of Default (other than a Credit Agreement Event of Default
related to failure to pay the Partnership Notes or a Guarantee Event of
Default related to failure to make payments under the Guarantees) has occurred
and is continuing, the Trustee may declare the principal amount of the
Outstanding Notes, all interest accrued and unpaid thereon, and all premium
and other amounts payable under the senior secured notes and the Indenture, if
any, to be due and payable notwithstanding the absence of direction from the
Required Holders directing the Trustee to accelerate the maturity of such
amount of senior secured notes unless the Required Holders direct the Trustee
not to accelerate the maturity of such senior secured notes, if in the good
faith exercise of its discretion the Trustee determines that such action is
necessary to protect the interests of the Holders.
In addition, if one or more of the Events of Default referred to in clause
(c)(ii) immediately above has occurred and is continuing, the Trustee may
declare the entire principal amount of the senior secured notes Outstanding,
all interest accrued and unpaid thereon, and all premium and other amounts
payable under the senior secured notes and the Indenture, if any, to be due
and payable notwithstanding the absence of direction from the Required Holders
directing the Trustee to accelerate the maturity of the senior secured notes
unless the Required Holders direct the Trustee not to accelerate the maturity
of the senior secured notes, if in the good faith exercise of its discretion
the Trustee determines that such action is necessary to protect the interests
of the Holders.
In the case of any Event of Default occurring by reason of any willful
action or inaction taken or not taken by us or on our behalf with the
intention of avoiding payment of the premium that we would have had to pay if
we then had elected to redeem the Series A notes due 2009 or the Series B
Notes due 2009 pursuant to the optional redemption provisions of the
Indenture, a premium equal to
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the then applicable Treasury Rate shall also become and be immediately due and
payable to the extent permitted by law upon the acceleration of the Series A
notes due 2009 or the Series B Notes due 2009. If an Event of Default occurs at
a time when the Series A notes due 2001 or the Series B notes due 2001 are
outstanding by reason of any willful action (or inaction) taken (or not taken)
by us or on our behalf with the intention of avoiding the prohibition on
redemption of the Series A notes due 2001 or any Series B notes due 2001, then
a premium equal to the then applicable Treasury Rate shall also become and be
immediately due and payable to the extent permitted by law upon the
acceleration of the Series A notes due 2001 or the Series B notes due 2001.
At any time after the principal of the senior secured notes has become due
and payable upon a declared acceleration, and before any judgment or decree for
the payment of the money so due, or any portion thereof, has been entered, the
Holders of not less than a majority in aggregate principal amount of the
Outstanding Notes, by written notice to us and the Trustee, shall rescind and
annul such declaration and its consequences if:
(1) there has been paid to or deposited with the Trustee a sum sufficient
to pay:
(a) all overdue interest on the senior secured notes,
(b) the principal of and premium, if any, on any senior secured notes
that have become due (including overdue principal) other than by
such declaration of acceleration and interest thereon at the
respective rates provided in the senior secured notes for overdue
principal,
(c) to the extent that payment of such interest is lawful, interest
upon overdue interest at the respective rates provided in the
senior secured notes for overdue interest, and
(d) all sums paid or advanced by the Trustee and the reasonable
compensation, expenses, disbursements, and advances of the Trustee,
its agents and counsel, and
(e) all Events of Default, other than the nonpayment of the principal
of the senior secured notes and the Partnership Notes that has
become due solely by such acceleration, have been cured or waived
in accordance with the Indenture.
(2) If an Event of Default relating to failure to pay amounts owed on the
senior secured notes has occurred and is continuing and an acceleration
has occurred, the Trustee may (as the Holders of 25% in aggregate
principal amount of the Outstanding Notes request) direct the
Collateral Agent to take possession of all Collateral.
(3) If an Event of Default relating to a Credit Agreement Event of Default
or a Guarantee Event of Default (other than a Credit Agreement Event of
Default related to failure to pay the Partnership Notes or a Guarantee
Event of Default related to failure to pay amounts owed on the senior
secured notes) has occurred and is continuing and an acceleration has
occurred, the Trustee may (as the Required Holders request) direct the
Collateral Agent to take possession of all Collateral.
(4) If an Event of Default other than those referred to in clauses (2) and
(3) above has occurred and is continuing and an acceleration has
occurred, the Trustee may (as the Required Holders request) direct the
Collateral Agent to take possession of all Collateral; or
(5) If one or more Guarantee Events of Default shall have occurred and be
continuing under a Guarantee, the Trustee may (as the Required Holders
request) direct the Collateral Agent to take possession of all
Collateral.
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Application of Monies Collected by Trustee
Any monies collected or to be applied by the Trustee after an Event of
Default in respect of the senior secured notes will be applied to amounts owed
with respect to all senior secured notes and all other Senior Indebtedness on a
pro rata basis and, in respect of senior secured notes of a series, will be
applied ratably to the Holders of senior secured notes in the following order
from time to time, on the date or dates fixed by the Trustee:
(1) first, to the payment of all amounts due to the Trustee or any
predecessor Trustee under the Indenture;
(2) second, (A) in case the unpaid principal amount of the Outstanding
Notes or other outstanding Senior Indebtedness has not become due, to
the payment of any overdue interest, (B) in case the unpaid principal
amount of a portion of the Outstanding Notes or other outstanding
Senior Indebtedness has become due, first to the payment of accrued
interest on all Outstanding Notes and all other Senior Indebtedness for
overdue principal, premium, if any, and overdue interest, and next to
the payment of the overdue principal on all senior secured notes and
all other Senior Indebtedness or (C) in case the unpaid principal
amount of all the Outstanding Notes and all other Senior Indebtedness
has become due, first to the payment of the whole amount then due and
unpaid upon the Outstanding Notes and all other Senior Indebtedness for
principal, premium, if any, and interest, together with interest for
overdue principal, premium, if any, and overdue interest; and
(3) third, in case the unpaid principal amount of all the Outstanding Notes
and all other Senior Indebtedness has become due, and all of the
outstanding principal, premium, if any, interest and other amounts owed
in connection with the senior secured notes and all other Senior
Indebtedness have been fully paid, any surplus then remaining will be
paid to us, or to whomsoever may be lawfully entitled to receive the
same, or as a court of competent jurisdiction may direct.
Amendments and Supplements
We, the Coso partnerships, the Trustee and the Collateral Agent may amend or
supplement the Indenture or execute a waiver without the consent of the
Holders:
. to add additional covenants of ours;
. to surrender rights conferred upon us, or to confer additional benefits
upon the Holders;
. to increase the assets securing our obligations under the Indenture;
. the issuance of Additional Notes on the conditions described herein;
. for any purpose not inconsistent with the terms of the Indenture or to
cure any ambiguity, defect or inconsistency;
. to comply with requirements of the SEC in order to effect or maintain
the qualification of this Indenture under the Trust Indenture Act; or
. to reflect any amendments required by a Rating Agency in circumstances
where confirmation of the Ratings is required or permitted under the
Indenture.
The Indenture may be otherwise amended or supplemented by us, the Coso
partnerships, the Trustee and the Collateral Agent with the consent of Holders
of not less than a majority in aggregate
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principal amount of the senior secured notes then Outstanding; provided that no
such amendment or supplement may, without the consent of all Holders of
Outstanding Notes, modify:
. the principal, premium and interest payable upon the Series B notes,
. the dates on which interest or principal on any Series B notes is paid,
. the dates of maturity of any Series B notes, or
. the procedures for amendment by a supplemental indenture.
Notwithstanding the foregoing, the provisions in the Indenture relating to a
Change of Control and the related definitions as used therein may be amended by
the Holders of at least a majority in aggregate principal amount of the
Outstanding Notes.
Additional Senior Secured Notes
In the event we incur Permitted Indebtedness in the form of Additional Notes,
whether issued pursuant to the Indenture or a separate indenture, the Holders
of the senior secured notes and the holders of Additional Notes shall be
treated as one class for all purposes (including voting with respect to the
exercise of remedies in the event of an Event of Default). Notwithstanding
anything to the contrary in the Indenture, we and the Trustee may amend the
Indenture or enter into an intercreditor agreement to implement such treatment.
Amendment of Credit Agreement and Partnership Notes
We and the Trustee may, without the consent of or notice to the Series B note
Holders, consent to any amendment or modification of any Credit Agreement or
the Partnership Notes
. as permitted by the provisions of the Credit Agreements, the Partnership
Notes or the Indenture,
. to cure any ambiguity, defect or inconsistency,
. to add additional rights in favor of us, or
. in connection with any amendment to the Credit Agreements or Partnership
Notes where such amendment is required by a Rating Agency in
circumstances where confirmation of the Ratings are required or
permitted under the Indenture or the Credit Agreements.
Except as described above, neither we nor the Trustee shall consent to any
other amendment or modification of the Credit Agreements or the Partnership
Notes or grant any waiver or consent thereunder without the consent of the
Required Holders. An amendment to the Credit Agreements or to the Partnership
Notes which changes the amounts of payments due thereunder, the Person to whom
such payments are to be made or the dates on which such payments are to be made
shall not be made without the unanimous consent of the Holders.
Satisfaction and Discharge of the Indenture; Defeasance
We may terminate the Indenture and the Guarantees by delivering all
Outstanding Notes to the Trustee for cancellation and by paying all other sums
payable under the Indenture.
Legal and covenant defeasance shall be permitted upon terms and conditions
customary for transactions of this nature.
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Trustee
There shall at all times be a Trustee under the Indenture, which shall be a
corporation having either (1) a combined capital and surplus of at least $500.0
million, or (2) having a combined capital and surplus of at least $100.0
million and being a wholly owned subsidiary of a corporation having a combined
capital and surplus of at least $500.0 million in each case subject to
supervision or examination by a Federal or State or District of Columbia
authority and having a corporate trust office in New York, New York, to the
extent there is such an institution eligible and willing to serve. We agreed to
indemnify and hold harmless the Trustee in connection with the performance of
its duties under the Indenture, except for liability which results from the
negligence, bad faith or willful misconduct of the Trustee.
The Trustee may resign at any time by giving written notice thereof to us.
The Trustee may be removed at any time by act of the Required Holders,
delivered to the Trustee and to us. We will give notice of each resignation and
removal of the Trustee and each appointment of a successor Trustee to all
Holders.
Information Available to Holders
Pursuant to the Indenture, so long as any senior secured notes are
outstanding, we and the Coso partnerships will furnish to the Holders of Series
B notes:
(1) all quarterly and annual financial information that would be required
to be contained in a filing with the SEC on Forms 10-Q and 10-K if we
and each Coso partnership were required to file such Forms, including a
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" and, with respect to the annual information
only, a report thereon by our and each Coso partnership's certified
independent accountants, and
(2) all current reports that would be required to be filed with the SEC on
Form 8-K if we and the Coso Partnerships were required to file such
reports, in each case within the time periods specified in the SEC's
rules and regulations.
In addition, for so long as any senior secured notes remain outstanding, we and
the Coso partnerships will furnish to the Holders and to securities analysts
and prospective investors, upon their request, the information required to be
delivered pursuant to Rule 144A(d)(4) under the Securities Act.
Agent Relationship
Each Coso partnership has designated us as its agent under the Indenture for
the sole purpose of (i) issuing the Series B notes to the extent of each such
Coso partnership's obligations thereunder and (ii) otherwise carrying out each
Coso partnership's obligations and duties and exercising each Coso
partnership's rights and privileges under the Indenture. Each Coso partnership
will indemnify us against all claims arising in connection with our performance
of its obligations.
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Description of Credit Agreements
Pursuant to Credit Agreements between each Coso partnerships and us (the
"Credit Agreements"), (i) the Coso partnerships issued the Partnership Notes to
us at the closing of the Series A notes offering, and (ii) the Coso
partnerships agreed to make payments under the Partnership Notes in amounts
which are sufficient to enable us to pay scheduled principal of and interest on
the Series B notes.
The Coso partnerships have absolutely and unconditionally agreed to make
payments under the Partnership Notes in scheduled installments and to pay
interest, in arrears, on the unpaid principal amount of each installment. If
the proceeds received from our issuance of Additional Notes are loaned to the
Coso partnerships, then additional Partnership Notes having a principal amount
equal to the amount of such proceeds so loaned to the Coso partnerships will be
issued by the Coso partnerships and such principal shall be payable in
scheduled installments which correspond to the repayment of principal of such
Additional Notes.
Optional Prepayment
Optional prepayment of the Partnership Notes shall not be permitted except in
connection with the defeasance of the Senior secured notes or the optional
redemption of the Series A notes due 2009 and the Series B notes due 2009.
Mandatory Prepayment
The Coso partnerships are required to prepay the Partnership Notes with
proceeds received by the Coso partnerships in connection with an Event of Loss,
a Title Event, an Event of Eminent Domain, a Permitted Power Contract Buy-Out
or a termination of the Navy Contract under Section VIII(2) of the Navy
Contract to the extent set forth in "Description of Series B Notes --Mandatory
Redemption."
Certain Covenants
Set forth below are certain covenants of the Coso partnerships contained in
the Credit Agreements.
Events of Loss. If any Event of Loss or Event of Eminent Domain occurs and
the cost of repairing, restoring, replacing or rebuilding (collectively,
"Reconstructing") is $5.0 million or less, and if, in the reasonable judgment
of the managing partner of the relevant Coso partnership, to Reconstruct would
be prudent and consistent with such Coso partnership's obligations to maintain
such Project, then such Coso partnership shall, at its own expense and whether
or not such damage, destruction or loss is covered by an insurance policy, with
reasonable promptness, Reconstruct the same. If there are Loss Proceeds or
Eminent Domain Proceeds (from insurance or otherwise) available as a result of
such damage, destruction or loss in the amount of $5.0 million or less, then
said Loss Proceeds or Eminent Domain Proceeds shall be available to such Coso
partnership for application pursuant to the provisions described under "Loss
Proceeds Account."
If an Event of Loss or an Event of Eminent Domain occurs and the Loss
Proceeds or Eminent Domain Proceeds are greater than $5.0 million but less than
the total amount outstanding under the Partnership Note (the "Partnership Note
Balance") such Coso partnership shall have the option to Reconstruct the
Project, or any part thereof, upon the satisfaction of certain conditions. If
such Coso partnership fails to exercise such option, the Coso partnership shall
apply the Loss Proceeds or Eminent Domain Proceeds to prepay amounts
outstanding under the Partnership Note as described in "Mandatory Prepayment."
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If an Event of Loss or an Event of Eminent Domain occurs and the Loss
Proceeds or Eminent Domain Proceeds are equal to or exceed the Partnership Note
Balance, then the Coso partnership shall apply those Loss Proceeds or Eminent
Domain Proceeds to prepay amounts outstanding under the Partnership Note, as
described in "Mandatory Prepayment," unless such Coso partnership obtains a
determination form the Rating Agencies that the credit rating of the senior
secured notes that had been in effect immediately before the Event of Loss or
Event of Eminent Domain will not be adversely affected by applying those Loss
Proceeds or Eminent Domain Proceeds to Reconstruction of the Project.
Reporting Requirements. Each of the Coso partnerships shall provide to us:
. all quarterly and annual financial information that would be required to
be contained in a filing with the SEC on Forms 10-Q and 10-K if the Coso
partnerships were required to file such Forms, including a "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and, with respect to the annual information only, a report
thereon by the Coso partnerships' certified independent accountants;
. all current reports that would be required to be filed with the SEC on
Form 8-K if the Coso partnerships were required to file such reports, in
each case within the time periods specified in the SEC's rules and
regulations;
. all other information in respect of the Coso partnerships requested by
us to enable us to meet our obligations under the Indenture;
. copies of material notices; and
. written notice of any Credit Agreement Event of Default under the Credit
Agreement or any event or condition that could reasonably be expected to
result in a Material Adverse Effect. To the extent that the information
provided pursuant to the preceding sentence includes financial
statements of each of the Coso partnerships, the Coso partnerships also
shall provide to us combined financial statements.
Sale of Assets. Except as contemplated by the Transaction Documents, none of
the Coso partnerships shall sell, lease (as lessor) or transfer (as transferor)
any property or assets material to the operation of the Projects except for
fair value in the ordinary course of business to the extent that such property
is no longer useful or necessary in connection with the operation of the
Projects.
Ownership of Coso Partnerships. None of the Navy I Partners, Navy II Partners
or the BLM Partners shall sell, transfer or convey any partnership interests
held by such Partner in the Navy I partnership, Navy II partnership or the BLM
partnership, respectively, unless:
(1) such sale, transfer or conveyance would not result in any change in the
relevant Project's status as a Qualifying Facility; and
(2) the Person to whom such partnership interests are sold, transferred or
conveyed enters into a pledge agreement providing for the perfected,
first priority pledge to the Collateral Agent for the benefit of the
Trustee and the Holders of the senior secured notes of all such
partnership interests.
Insurance. The Coso partnerships shall maintain or cause to be maintained
insurance as is generally carried by companies engaged in similar businesses
and owning similar properties in the same general areas and financed in a
similar manner. The Coso partnerships shall maintain business interruption
insurance, casualty insurance, including flood and earthquake coverage, and
primary and
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excess liability insurance, as well as customary worker's compensation and
automobile insurance. The Coso partnerships shall not reduce or cancel such
insurance coverages (or permit any such coverages to be reduced or canceled) if
an independent insurance consultant determines that such reduction or
cancellation would not be reasonable under the circumstances and the insurance
coverages sought to be reduced or canceled are available on commercially
reasonable terms or that another level of coverage greater than that proposed
by the Coso partnerships is available on commercially reasonable terms (in
which case such coverage may be reduced to the higher of such available
levels).
QF Status. The Coso partnerships shall operate and maintain the Coso projects
as QFs unless the failure to so operate and maintain such Projects as QFs would
not cause or result in (1) a breach of the power purchase agreements that the
Coso partnerships are party to or (2) an adverse effect on the revenues to be
received under such power purchase agreements.
Governmental Approvals; Title. Each of the Coso partnerships shall at all
times (1) obtain and maintain in full force and effect all material
Governmental Approvals and other consents and approvals required at any time in
connection with its business and (2) preserve and maintain good and valid title
to its properties and assets (subject to no liens other than Permitted Liens),
except in each case where the failure to do so in clause (1) or (2) could not
reasonably be expected to have a Material Adverse Effect.
Nature of Business. None of the Coso partnerships shall engage in any
business other than their existing businesses.
Compliance with Laws. Each of the Coso partnerships shall comply with all
applicable laws, except where non-compliance could not reasonably be expected
to have a Material Adverse Effect.
Prohibition on Fundamental Changes. None of the Coso partnerships shall enter
into any transaction of merger or consolidation, change its form of
organization or its business, liquidate or dissolve itself (or suffer any
liquidation or dissolution); provided that any Coso partnership shall be able
to merge with or into any other Coso partnership so long as no Default or Event
of Default exists or will occur as a result thereof and subject to the
satisfaction of other customary conditions. None of the Coso partnerships shall
purchase or otherwise acquire all or substantially all of the assets of any
other Person, except for the purchase or acquisition by any of the Coso
partnerships of the partnership interests or assets related to the other
Project.
Revenue Account. Each of the Coso partnerships shall take all actions as may
be necessary to cause all revenues of the Coso partnerships to be deposited in
the Revenue Account to the extent required by the Depositary Agreement.
Transactions with Affiliates. Except as provided in or with respect to
Project Documents which currently exist, none of the Coso partnerships shall
make any payment to, or sell, lease, transfer or otherwise dispose of any of
its properties or assets to, or purchase any property or assets from, or enter
into or make or amend any transaction, contract, agreement, understanding,
loan, advance or guarantee with, or for the benefit of, any Affiliate (each, an
"Affiliate Transaction"), unless:
(1) such Affiliate Transaction is on terms that are no less favorable to
the relevant Coso partnership than those that would have been obtained
in a comparable transaction by such Coso partnership with an unrelated
Person; and
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(2) the relevant Coso partnership delivers to the Trustee:
. with respect to any Affiliate Transaction or series of related
Affiliate Transactions involving aggregate consideration in excess
of $1.0 million, a resolution of the general partner of such Coso
partnership set forth in an Officers' Certificate certifying that
such Affiliate Transaction complies with this covenant and that such
Affiliate Transaction has been approved by a each of the Partners of
the Coso partnership; and
. with respect to any Affiliate Transaction or series of related
Affiliate Transactions involving aggregate consideration in excess
of $5.0 million, an opinion as to the fairness to the Holders of
such Affiliate Transaction from a financial point of view issued by
an investment banking firm of national standing.
The following items shall not be deemed to be Affiliate Transactions and,
therefore, will not be subject to the provisions of the prior paragraph:
(1) transactions between or among the Coso partnerships and us;
(2) payment of any Operating and Maintenance Fees or Management Fees,
provided that such payment is made in accordance with the provisions in
clauses (7) and (8) set forth under the caption "Flow of Funds--Revenue
Account; Priority of Payments;" and
(3) Restricted Payments that are permitted by the provisions of the
Depositary Agreement described below under the caption "--Restricted
Payments."
Restricted Payments. None of the Coso partnerships shall make any Restricted
Payments, except as permitted under the Depositary Agreement and described
under the caption "Flow of Funds."
Exercise of Rights Under Project Documents. None of the Coso partnerships
shall exercise, or fail to exercise, their rights under the Project Documents
in a manner which could reasonably be expected to result in a Material Adverse
Effect.
Amendments to Contracts. None of the Coso partnerships shall terminate,
amend, replace or modify, or permit to be terminated, amended, replaced or
modified, (other than immaterial amendments or modifications as certified by
the Coso partnerships) any of the Project Documents to which it is a party
unless:
. such Coso partnership certifies that such termination, amendment,
replacement or modification could not reasonably be expected to have a
Material Adverse Effect; and
. in the case of any amendment, termination or modification of a Power
Purchase Agreement which affects the revenues derived by any of the Coso
partnerships by more than $5.0 million, or $10.0 million when aggregated
with all previous amendments or modifications, the Coso partnerships
provide a letter from each of the Rating Agencies confirming that such
amendment, termination or modification will not result in a Rating
Downgrade after giving effect to any mandatory redemption of senior
secured notes required to be made in connection with any such amendment,
modification or termination pursuant to a Permitted Power Contract Buy-
Out.
Limitations on Indebtedness/Liens. None of the Coso partnerships shall create
or incur or suffer to exist any Indebtedness other than Permitted Partnership
Indebtedness. None of the Coso partnerships shall grant, create, incur or
suffer to exist any Liens upon any of its properties, except for Permitted
Liens.
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Operating Budget. If, during any fiscal year, any Coso partnership (1)
exceeds its Operating Budget by more than 25% or (2) expends 75% or less of its
Operating Budget, then in either case such Coso partnership shall cause the
Independent Engineer to certify that the expenditures were reasonably designed
to permit such Coso partnership to operate and maintain a facility of that type
and to maximize its revenue and net income.
Required Geothermal Percentage. Each Coso partnership shall use its best
efforts to maintain in cooperation with the other Coso partnerships, the
minimum geothermal resource required to produce, in the aggregate among all of
the Projects, at least 105% of the steam necessary to generate the energy
projected in the Independent Engineer's Base Case Projections. In addition:
(a) The Coso partnerships shall cause the Geothermal Engineer to deliver,
not more than 30 days after October 31 of each year, a certificate
setting forth the Actual Geothermal Percentage for the Projects
measured as of October 31 of such year.
(b) If as of October 31 in any year the Geothermal Engineer shall determine
that the Actual Geothermal Percentage for the Projects is less than
105%, then:
. the Coso partnerships shall develop a plan of corrective action to
achieve an Actual Geothermal Percentage of at least 105%, which plan
shall be approved by the Geothermal Engineer, and the Coso
partnerships shall diligently implement such approved plan; and
. no payment of Management Fees or any Restricted Payment shall be
made until such time as the Geothermal Engineer shall determine that
the Actual Geothermal Percentage for the Projects is at least equal
to 105%.
(c) The Coso partnerships shall cause the Geothermal Engineer to deliver,
during the calendar year 2006, a report on the geothermal resource
available as of such date and whether sufficient geothermal resource
remains to enable the Projects, in the aggregate, to produce sufficient
steam to generate the energy projected in the Independent Engineer's
Base Case Projections through the maturity date of the Series A notes
due 2009 and the Series B notes due 2009.
Books and Records. The Coso partnerships shall maintain their books and
records and give us, the Trustee, the Collateral Agent and the Independent
Engineer inspection rights at reasonable times and upon reasonable prior
notice.
Additional Project Documents. The Coso partnerships shall perform and observe
their respective covenants and obligations under all of the Project Documents
in all material respects, except where the failure to do so could not
reasonably be expected to result in a Material Adverse Effect. The Coso
partnerships shall not be permitted to enter into any Additional Project
Documents if entering into such document would result in a Material Adverse
Effect; provided that the Coso partnerships shall be permitted to enter into
agreements for the purchase by such Coso partnerships of electricity so long as
(1) such agreements with respect to each Coso partnership do not provide for
payments in excess of $10.0 million per year by such Coso partnership and (2)
prior to entering into any such agreement the relevant Coso partnership
delivers an officer's certificate to the Trustee certifying that the proposed
agreement is on arms-length terms.
Additional Covenants. In addition to the covenants described above, the
Credit Agreements also contain covenants of the Coso partnerships regarding:
. maintenance of existence,
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. payment of taxes and claims unless being contested in good faith; and
. preservation and maintenance of Liens on the Collateral and the priority
thereof.
Events of Default.
Certain Events
The following events constitute Credit Agreement Events of Default under each
Credit Agreement:
(1) the failure by any of the Coso partnerships to pay or cause to be paid
any principal of, premium, if any, or interest, fees or any other
obligations on its Partnership Note for ten or more days after the same
becomes due and payable, whether by scheduled maturity or required
prepayment or by acceleration or otherwise;
(2) any representation or warranty made by any Coso partnership under its
Credit Agreement shall prove to have been untrue or misleading in any
material respect as of the time made, confirmed or furnished and the
fact, event or circumstance that gave rise to such inaccuracy could
reasonably be expected to result in a Material Adverse Effect and such
fact, event or circumstance shall continue to be uncured for 30 or more
days from the date a Responsible Officer of such Coso Partnership
receives notice thereof from the Trustee; provided that if such Coso
partnership commences efforts to cure such fact, event or circumstance
within such 30-day period, such Coso partnership may continue to effect
such cure and such misrepresentation shall not be deemed a Credit
Agreement Event of Default for an additional 60 days so long as such
Coso partnership is diligently pursuing such cure;
(3) the failure by any of the Coso partnerships to perform or observe any
covenant under its Credit Agreement relating to maintenance of
existence, restrictions on Indebtedness, Permitted Liens, Restricted
Payments, guarantees, disposition of assets, maintenance of insurance,
amendments to the Project Documents, fundamental changes, or nature of
business and such failure shall continue uncured for 30 or more days
after a Responsible Officer of either of such Coso partnership receives
notice thereof from the Trustee;
(4) the failure by any of the Credit Parties to perform or observe any of
the other covenants under the Credit Agreement or in the other
Financing Documents the Credit Parties are party to (other than such
failures described in clause (1) or (3) above or (13) below) and such
failure shall continue uncured for 30 or more days after a Responsible
Officer of the Credit Parties receives notice thereof from the Trustee;
provided that if the Credit Parties commence efforts to cure such
default within such 30-day period, the Credit Parties may continue to
effect such cure of the default and such default shall not be deemed a
Credit Agreement Event of Default for an additional 90 days so long as
the Credit Parties are diligently pursuing such cure;
(5) certain events involving the bankruptcy, insolvency, receivership or
reorganization of any of the Coso partnerships;
(6) the entry of one or more final and non-appealable judgment or judgments
for the payment of money in excess of $2.5 million (exclusive of
judgment amounts fully covered by insurance or indemnity) against any
of the Coso partnerships, which remain unpaid or unstayed for a period
of 90 or more consecutive days after the entry thereof;
(7) any event of default under any Permitted Partnership Indebtedness
(other than Subordinated Indebtedness) that results in Permitted
Partnership Indebtedness in excess of $2.5 million becoming due and
payable prior to its stated maturity;
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(8) the Coso partnerships fail to perform any of their respective payment
obligations under their respective guarantees for 10 or more days
after the same becomes due and payable;
(9) any Governmental Approval required for the operation of a Project
owned by the Coso partnerships is revoked, terminated, withdrawn or
ceases to be in full force and effect if such revocation, termination,
withdrawal or cessation could reasonably be expected to have a
Material Adverse Effect and such revocation, termination, withdrawal
or cessation is not cured within 60 days following the occurrence
thereof;
(10) any Project Document ceases to be valid and binding and in full force
and effect prior to its stated maturity date other than as a result of
an amendment, termination or Permitted Power Contract Buy-Out
permitted under the Credit Agreement or any third party thereto fails
to perform its material obligations thereunder or makes any material
misrepresentation thereunder and such event results in a Material
Adverse Effect; provided that no such event shall be a Credit
Agreement Event of Default if within 180 days from the occurrence of
any such event, (a) the third party resumes performance or cures such
misrepresentation or (b) the applicable Coso partnership enters into
an Additional Project Document in replacement thereof, as permitted
under the Credit Agreement;
(11) the failure of the Coso partnerships or any other party to perform or
observe any of its covenants or obligations contained in any of the
Project Documents to which it is a party if such failure shall result
in the termination of such Project Document or otherwise result in a
Material Adverse Effect; provided, however, that such event shall not
be a Credit Agreement Event of Default if within 180 days from the
occurrence of any such event, the failure is cured or the Coso
partnerships enter into an Additional Project Document in replacement
thereof as permitted under the Credit Agreement;
(12) any of the Security Documents ceases to be effective or any Lien
granted therein ceases to be a valid and perfected Lien in favor of
the Collateral Agent on the Collateral described therein with the
priority purported to be created thereby; provided, however, that the
Credit Party party to any such Security Document shall have 10 days
after a Responsible Officer of the applicable Credit Party obtains
knowledge thereof to cure any such cessation or to furnish to the
Trustee, the Collateral Agent or the Depositary all documents or
instruments required to cure any such cessation;
(13) in the case of a determination by the Geothermal Engineer that the
Actual Geothermal Percentage is less than 105% (as set forth in the
annual certificate required pursuant to the covenant under the caption
"--Description of Credit Agreements--Certain Covenants --Required
Geothermal Percentage"), any:
. failure by the Coso partnerships (a) to prepare a plan approved by
the Geothermal Engineer within 90 days of such certification to
achieve an Actual Geothermal Percentage of at least 105%, (b) to
diligently implement such plan and (c) to achieve an Actual
Geothermal Percentage of at least 105% within a reasonable period
of time thereafter as determined in the sole discretion of the
Geothermal Engineer or
. determination by the Geothermal Engineer or the Coso partnerships
that achieving an Actual Geothermal Percentage of at least 105% is
not reasonably feasible; or
(14) an Event of Default described under clauses (3), (4), (5), (6), (7) or
(8) of "Certain Events" of the summary of the Event of Default
provisions of the Indenture occurs. See "--Indenture--Events of
Default."
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Enforcement of Remedies
If one or more Credit Agreement Events of Default under any Credit Agreement
have occurred and are continuing, then:
(1) in the case of a Credit Agreement Event of Default under a Credit
Agreement described in clause (5) above, the entire outstanding
principal amount of all Partnership Notes, all interest accrued and
unpaid thereon, and all premium and other amounts payable under the
Partnership Notes and the Credit Agreements, if any, will automatically
become due and payable without presentment, demand, protest or notice
of any kind; or
(2) in the case of a Credit Agreement Event of Default described in:
. clause (1) and (8) above, upon the direction of the Holders of no
less than 25% in aggregate principal amount of the Outstanding
Notes, we will declare the outstanding principal amount of the
Partnership Notes and all interest accrued and unpaid thereon, and
all premium and other amounts payable under the Credit Agreements,
if any, to be due and payable; or
. clauses (2), (3), (4), (6), (7), (9), (10), (11), (12), (13) and
(14) above, upon the direction of the Required Holders, we will
declare the outstanding principal amount of the Partnership Notes
and all interest accrued and unpaid thereon, and all premium and
other amounts payable under the Credit Agreements, if any, to be due
and payable.
Additional Information
Anyone who receives this prospectus may obtain a copy of the Indenture, the
Depositary Agreement, the Pledge Agreements and other Financing Documents
without charge by writing to Caithness Coso Funding Corp., 1114 Avenue of the
Americas, 41st Floor, New York, New York 10036-7790, Attention: Secretary.
Book-Entry, Delivery and Form
The Series B notes will initially be represented by one or more Series B
notes in registered, global form (collectively, the "Global Series B Notes").
The Global Series B Note will be deposited upon issuance with the Trustee as
custodian for The Depository Trust Company ("DTC"), in New York, New York, and
registered in the name of DTC or its nominee, in each case for credit to an
account of a direct or indirect participant in DTC as described below.
Except as set forth below, the Global Series B Notes may be transferred, in
whole and not in part, only to another nominee of DTC or to a successor of DTC
or its nominee. Beneficial interests in the Global Series B Notes may not be
exchanged for Series B notes in certificated form except in the limited
circumstances described below. See "--Exchange of Book-Entry Notes for
Certificated Notes." Except in the limited circumstances described below,
owners of beneficial interests in the Global Series B Notes will not be
entitled to receive physical delivery of Certificated Notes (as defined below).
In addition, transfers of beneficial interests in the Global Series B Notes
will be subject to the applicable rules and procedures of DTC and its direct or
indirect participants (including, if applicable, those of Euroclear and Cedel),
which may change from time to time.
The Trustee is acting as Paying Agent and Registrar. The Series B notes may
be presented for registration of transfer and exchange at the offices of the
Registrar.
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Depository Procedures
The following description of the operations and procedures of DTC, Euroclear
and Cedel are provided solely as a matter of convenience. These operations and
procedures are solely within the control of the respective settlement systems
and are subject to changes by them from time to time. We take no responsibility
for these operations and procedures and urges investors to contact the system
or their participants directly to discuss these matters.
DTC has advised us that DTC is a limited-purpose trust company created to
hold securities for its participating organizations (collectively, the
"Participants") and to facilitate the clearance and settlement of transactions
in those securities between the Participants through electronic book-entry
changes in accounts of the Participants. The Participants include securities
brokers and dealers (including the initial purchaser), banks, trust companies,
clearing corporations and certain other organizations. Access to DTC's system
is also available to other entities such as banks, brokers, dealers and trust
companies that clear through or maintain a custodial relationship with a
Participant, either directly or indirectly (collectively, the "Indirect
Participants"). Persons who are not Participants may beneficially own
securities held by or on behalf of DTC only through the Participants or the
Indirect Participants. The ownership interests in, and transfers of ownership
interests in, each security held by or on behalf of DTC are recorded on the
records of the Participants and the Indirect Participants.
DTC has also advised us that, pursuant to procedures established by it, (i)
upon deposit of the Global Series B Notes, DTC will credit the accounts of
Participants designated by the Trustee with portions of the principal amount of
the Global Series B Notes and (ii) ownership of such interests in the Global
Series B Notes will be shown on, and the transfer of ownership thereof will be
effected only through, records maintained by DTC (with respect to the
Participants) or by the Participants and the Indirect Participants (with
respect to other owners of beneficial interests in the Global Series B Notes).
Investors in the Global Series B Note may hold their interests therein
directly through DTC, if they are Participants in such system, or indirectly
through organizations (including Euroclear and CEDEL) which are Participants in
such system. Euroclear and Cedel will hold interests in the Global Series B
Notes on behalf of their participants through customers' securities accounts in
their respective names on the books of their respective depositories, which are
Morgan Guaranty Trust Company of New York, Brussels office, as operator of
Euroclear, and Citibank, N.A., as operator of Cedel. All interests in a Global
Series B Note, including those held through Euroclear or Cedel, may be subject
to the procedures and requirements of DTC. Those interests held through
Euroclear or Cedel may also be subject to the procedures and requirements of
such systems. The laws of some states require that certain persons take
physical delivery in definitive form of securities that they own. Consequently,
the ability to transfer beneficial interests in a Global Series B Note to such
persons may be limited to that extent. Because DTC can act only on behalf of
the Participants, which in turn act on behalf of the Indirect Participants and
certain banks, the ability of a person having beneficial interests in a Global
Series B Note to pledge such interests to persons or entities that do not
participate in the DTC system, or otherwise take actions in respect of such
interests, may be affected by the lack of a physical certificate evidencing
such interests. For certain other restrictions on the transferability of the
Series B Notes, see "--Exchange of Book-Entry Series B Notes for Certified
Series B Notes."
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Except as described below, owners of interests in the Global Series B Notes
will not have Series B Notes registered in their names, will not receive
physical delivery of Series B Notes in certificated form and will not be
considered the registered owners or holders thereof under the Indenture for any
purpose.
Payments in respect of the principal of, and premium, if any, and interest on
a Global Series B Note registered in the name of DTC or its nominee will be
payable to DTC or its nominee in its capacity as the registered holder under
the Indenture. Under the terms of the Indenture, we and the Trustee will treat
the persons in whose names the Series B Notes, including the Global Series B
Notes, are registered as the owners thereof for the purpose of receiving such
payments and for any and all other purposes whatsoever. Consequently, neither
we, the Trustee nor any agent of ours or the Trustee has or will have any
responsibility or liability for (i) any aspect of DTC's records or any
Participant's or Indirect Participant's records relating to or payments made on
account of beneficial ownership interests in the Global Series B Notes, or for
maintaining, supervising or reviewing any of DTC's records or any Participant's
or Indirect Participant's records relating to the beneficial ownership
interests in the Global Series B Notes, or (ii) any other matter relating to
the actions and practices of DTC or any of the Participants or the Indirect
Participants.
DTC has advised us that its current practice, upon receipt of any payment in
respect of securities such as the Series B Notes (including principal and
interest), is to credit the accounts of the relevant Participants with the
payment on the payment date, in amounts proportionate to their respective
holdings in the principal amount of beneficial interests in the relevant
security as shown on the records of DTC unless DTC has reason to believe it
will not receive payment on such payment date. Payments by the Participants and
the Indirect Participants to the beneficial owners of the Series B Notes will
be governed by standing instructions and customary practices and will not be
the responsibility of DTC, the Trustee or us. Neither we nor the Trustee will
be liable for any delay by DTC or any of the Participants in identifying the
beneficial owners of the Series B Notes, and we and the Trustee may
conclusively rely on and will be protected in relying on instructions from DTC
or its nominee as the registered owner of the Global Series B Notes for all
purposes.
Except for trades involving only Euroclear and Cedel participants, interests
in the Global Series B Notes are expected to be eligible to trade in DTC's Same
Day Funds Settlement System and secondary market trading activity in such
interests will, therefore, settle in immediately available funds, subject in
all cases to the rules and procedures of DTC and the Participants. See "--Same
Day Settlement and Payment." Transfers between Participants in DTC will be
affected in accordance with DTC's procedures and will be settled in same day
funds, and transfers between participants in Euroclear and Cedel will be
effected in the ordinary way in accordance with their respective rules and
operating procedures.
Subject to compliance with the transfer restrictions applicable to the senior
secured notes described herein, cross-market transfers between the Participants
in DTC, on the one hand, and Euroclear or Cedel participants, on the other
hand, will be effected through DTC in accordance with DTC's rules on behalf of
Euroclear or Cedel, as the case may be, by its respective depositary; however,
such cross-market transactions will require delivery of instructions to
Euroclear or Cedel, as the case may be, by the counterparty in such system in
accordance with the rules and procedures and within the established deadlines
(Brussels time) of such system. Euroclear or Cedel, as the case may be, will,
if the transaction meets its settlement requirements, deliver instructions to
its respective depositary to take action to effect final settlement on its
behalf by delivering or receiving interests in the relevant Global Series B
Note in DTC, and making or receiving payment in accordance with
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normal procedures for same-day funds settlement applicable to DTC. Euroclear
participants and Cedel participants may not deliver instructions directly to
the depositories for Euroclear or Cedel.
DTC has advised us that it will take any action permitted to be taken by a
Holder of Series B Notes only at the direction of one or more Participants to
whose account DTC has credited the interests in the Global Series B Notes and
only in respect of such portion of the aggregate principal amount of the Series
B Notes as to which such Participant or Participants has or have given such
direction. However, if any of the events described under "--Exchange of Book
Entry Series B Notes for Certificated Series B Notes" occurs, DTC reserves the
right to exchange the Global Series B Notes for legended Series B Notes in
certificated form and to distribute such Series B Notes to its Participants.
Although DTC, Euroclear and Cedel have agreed to the foregoing procedures to
facilitate transfers of interests in the Global Series B Notes among
Participants in DTC, Euroclear and Cedel, they are under no obligation to
perform or to continue to perform such procedures, and such procedures may be
discontinued at any time. Neither we nor the Trustee nor any agent of ours or
the Trustee will have any responsibility for the performance by DTC, Euroclear
an Cedel or their participants or indirect participants of their respective
obligations under the rules and procedures governing their respective
operations.
Exchange of Book-Entry Notes for Certificated Notes
The Global Series B Note is exchangeable for definitive Series B Notes in
registered certificated form ("Certificated Notes") if (i) DTC (x) notifies us
that it is unwilling or unable to continue as depository for the Global Series
B Notes and we thereupon fail to appoint a successor depository or (y) has
ceased to be a clearing agency registered under the Exchange Act, (ii) we, at
our option, notify the Trustee in writing that we elect to cause the issuance
of the Certificated Notes or (iii) there shall have occurred and be continuing
a Default or an Event of Default with respect to the Series B Notes. In
addition, beneficial interests in a Global Note may be exchanged for
Certificated Notes upon request but only upon prior written notice given to the
Trustee by or on behalf of DTC in accordance with the Indenture. In all cases,
Certificated Notes delivered in exchange for any Global Series B Note or
beneficial interests in the Global Series B Note will be registered in the
names, and issued in any approved denominations, requested by or on behalf of
DTC (in accordance with its customary procedures).
Same Day Settlement and Payment
The Indenture requires that payments made in respect of the Series B notes
represented by the Global Series B Notes (including principal, premium, if any,
and interest) be made by wire transfer of immediately available funds to the
accounts specified by the Global Series B Note Holder. With respect to Series B
notes in certificated form, we will make all payments of principal, premium, if
any, and interest by wire transfer of immediately available funds to the
accounts specified by the Holders thereof or, if no such account is specified,
by mailing a check to each such Holder's registered address. The Series B notes
represented by the Global Series B Notes are expected to trade in the
Depository's Same-Day Funds Settlement System, and any permitted secondary
market trading activity in such senior secured notes will, therefore, be
required by the Depository to be settled in immediately available funds. We
expect that secondary trading in any Certificated Notes will also be settled in
immediately available funds.
Because of time zone differences, the securities account of a Euroclear or
Cedel participant purchasing an interest in a Global Series B Note from a
Participant in DTC will be credited, and any
187
such crediting will be reported to the relevant Euroclear or Cedel participant,
during the securities settlement processing day (which must be a business day
for Euroclear and Cedel) immediately following the settlement date of DTC. DTC
has advised the Issuer that cash received in Euroclear or Cedel as a result of
sales of interests in a Global Series B Note by or through a Euroclear or Cedel
participant to a Participant in DTC will be received with value on the
settlement date of DTC but will be available in the relevant Euroclear or Cedel
cash account only as of the business day for Euroclear or Cedel following DTC's
settlement date.
Registration Rights; Liquidated Damages
The following is a summary of the material provisions of the registration
rights agreement. It does not purport to be complete and is subject to, and is
qualified entirely by, all of the provisions of the registration right
agreement. We urge you to read the registration rights agreement in its
entirety because it, and not this description, defines your registration rights
as Holders of the Series B notes. See "--Additional Information."
The Issuer, the Coso partnerships and the Initial Purchaser entered into the
registration rights agreement pursuant to which we and the Coso partnerships
agreed to file with the SEC the exchange offer registration statement on an
appropriate form under the Securities Act with respect to an offer to exchange
the Series A notes.
If:
(1) We and the Coso partnerships are not
(a) required to file the exchange offer registration statement; or
(b) permitted to consummate the exchange offer because the exchange
offer is not permitted by applicable law or SEC policy; or
(2) any Holder of Transfer Restricted Securities notifies us prior to the
20th day following consummation of the exchange offer that:
(a) it is prohibited by law or SEC policy from participating in the
exchange offer; or
(b) that it may not resell the Series B notes acquired by it in the
exchange offer to the public without delivering a prospectus and
the prospectus contained in the exchange offer registration
statement is not appropriate or available for such resales; or
(c) that it is a broker-dealer and owns Series A notes acquired
directly from us or one of our affiliates,
then we and the Coso partnerships will file with the SEC a shelf registration
statement to cover resales of Transfer Restricted Securities by the Holders
thereof who satisfy certain conditions relating to the provision of information
in connection with the shelf registration statement.
We and the Coso partnerships will use their best efforts to cause the
applicable registration statement to be declared effective as promptly as
possible by the SEC. For purposes of the preceding, "Transfer Restricted
Securities" means each Series A note until the earliest to occur of:
(1) the date on which such Series A note has been exchanged by a Person
other than a broker-dealer for a Series B note in the exchange offer;
(2) following the exchange by a broker-dealer in the exchange offer of a
Series A note for a Series B note, the date on which such Series B note
is sold to a purchaser who receives from such broker-dealer on or prior
to the date of such sale a copy of the prospectus contained in the
exchange offer registration statement;
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(3) the date on which such Series A note has been effectively registered
under the Securities Act and disposed of in accordance with the shelf
registration statement; or
(4) the date on which such Series A note is distributed to the public
pursuant to Rule 144 under the Securities Act.
The registration rights agreement provides:
(1) we and the Coso partnerships will file an exchange offer registration
statement with the SEC on or prior to 90 days after the closing of the
Series A notes offering;
(2) we and the Coso partnerships will use our and their best efforts to
have the exchange offer registration statement declared effective by
the SEC on or prior to 180 days after the closing of the Series A notes
offering;
(3) unless the exchange offer would not be permitted by applicable law or
Commission policy, we and the Coso partnerships will
(a) commence the exchange offer; and
(b) use our and their best efforts to issue on or prior to 30 business
days, or longer, if required by the federal securities laws, after
the date on which the exchange offer registration statement is
declared effective by the SEC, Series B notes in exchange for all
Series A notes tendered prior thereto in the exchange offer; and
(4) if obligated to file the shelf registration statement, we and the Coso
partnerships will use our and their best efforts to file the shelf
registration statement with the SEC on or prior to 45 days after such
filing obligation arises and to cause the shelf registration statement
to be declared effective by the SEC on or prior to 90 days after such
obligation arises.
If:
(1) we and the Coso partnerships fail to file any of the registration
statements required by the registration rights agreement on or before
the date specified for such filing; or
(2) any of such registration statements is not declared effective by the
SEC on or prior to the date specified for such effectiveness (the
"Effectiveness Target Date"); or
(3) we and the Coso partnerships fail to consummate the Exchange Offer
within 30 business days of the Effectiveness Target Date with respect
to the exchange offer registration statement; or
(4) the shelf registration statement or the exchange offer registration
statement is declared effective but thereafter ceases to be effective
or usable in connection with resales of Transfer Restricted Securities
during the periods specified in the registration rights agreement (each
such event referred to in clauses (1) through (4) above, a
"Registration Default"),
then we and the Coso partnerships will pay liquidated damages ("Liquidated
Damages") to each Holder of senior secured notes, with respect to the first 90-
day period immediately following the occurrence of the first Registration
Default in an amount equal to $.05 per week per $1,000 principal amount of
senior secured notes held by such Holder.
The amount of the Liquidated Damages will increase by an additional $.05 per
week per $1,000 principal amount of senior secured notes with respect to each
subsequent 90-day period until all Registration Defaults have been cured, up to
a maximum amount of Liquidated Damages for all Registration Defaults of $.25
per week per $1,000 principal amount of senior secured notes.
189
All accrued Liquidated Damages will be paid by us and the Coso partnerships
on each Damages Payment Date to the Series B Global Note Holder by wire
transfer of immediately available funds or by federal funds check and to
Holders of Certificated Notes by wire transfer to the accounts specified by
them or by mailing checks to their registered addresses if no such accounts
have been specified.
Following the cure of all Registration Defaults, the accrual of Liquidated
Damages will cease.
Holders of Series A notes will be required to make certain representations to
us (as described in the registration rights agreement) in order to participate
in the exchange offer and will be required to deliver certain information to be
used in connection with the shelf registration statement and to provide
comments on the shelf registration statement within the time periods set forth
in the registration rights agreement in order to have their senior secured
notes included in the shelf registration statement and benefit from the
provisions regarding Liquidated Damages set forth above. By acquiring Transfer
Restricted Securities, a Holder will be deemed to have agreed to indemnify us
and the Coso partnerships against certain losses arising out of information
furnished by such Holder in writing for inclusion in any shelf registration
statement. Holders of senior secured notes will also be required to suspend
their use of the prospectus included in the shelf registration statement under
certain circumstances upon receipt of written notice to that effect from us.
Certain Definitions
Certain terms defined below are summaries of terms defined in, and are
defined more specifically in, the Project Documents and the Financing
Documents. Such summaries do not purport to be complete and are subject to, and
are qualified in their entirety by reference to, all of the provisions of the
Project Documents and the Financing Documents.
"Accounts" means the accounts established under the Depositary Agreement.
"Actual Geothermal Percentage" means a percentage calculated by dividing the
geothermal resource available at the wellhead or pursuant to a contract for
such geothermal resource by the resource that would be required to meet the
production level necessary to generate the energy projected in the Independent
Engineer's Base Case Projections.
"Additional Notes" means additional senior secured notes, other than the
senior secured notes, having the same final maturity and amortization as the
Series B notes due 2001 or the Series B notes due 2009, as the case may be,
except as amortization may be increased pro rata across all payments to reflect
such shorter term, if any.
"Additional Project Document" means:
(1) any contract or undertaking relating to the purchase or sale of
electricity from the Projects entered into by any of the Coso
partnerships after the closing of the Series A notes offering;
(2) any consent or security instrument entered into by any of the Coso
partnerships or any other relevant party in connection with an
Additional Project Document; or
(3) any contract or undertaking to which we or any Coso partnership is a
party entered into after the closing of the Series A notes offering,
relating to (i) the supply, procurement or transportation of
consumables or other supplies to the Projects, or (ii) the design,
190
construction, operation or maintenance of the Projects; in each case
which is material to the applicable Project.
"Affiliate" of any specified Person means any other Person directly or
indirectly controlling or controlled by or under direct or indirect common
control with such specified Person. For purposes of this definition,
"control," as used with respect to any Person, shall mean the possession,
directly or indirectly, of the power to direct or cause the direction of the
management or policies of such Person, whether through the ownership of voting
securities, by agreement or otherwise; provided that beneficial ownership of
10% or more of the Voting Stock of a Person shall be deemed to be control. For
purposes of this definition, the terms "controlling," "controlled by" and
"under common control with" shall have correlative meanings.
"Approved Related Party" with respect to any Change of Control means:
(1) any direct or indirect controlling stockholder or 80% (or more) owned
Subsidiary of Caithness Energy, L.L.C.; or
(2) any trust, corporation, partnership or other entity, the beneficiaries,
stockholders, members, partners, owners or Persons beneficially holding
an 80% or more controlling interest of which consist of Caithness
Energy, L.L.C. and/or such other Persons referred to in the immediately
preceding clause (1).
"BLM Partners" means Caithness Coso Holdings, LLC, a Delaware limited
liability company, and New CHIP Company, LLC, a Delaware limited liability
company, the general partners of the BLM Partnership.
"BLM Partnership" means Coso Energy Developers, a California general
partnership.
"BLM Project" means, collectively, BLM East, which consists of two 30 MW
turbine generators, and BLM West, which consists of one 30 MW turbine
generator.
"Capital Expenditure Reserve Account" means the account of such name created
under the Depositary Agreement.
"Capital Expenditure Reserve Required Balance" means an amount equal to the
aggregate Capital Expenditures budgeted for the Projects for the next
succeeding twelve-month period (a) as approved by the Independent Engineer and
delivered to the Trustee at least annually and (b) as adjusted by management
and set forth in an Officers' Certificate delivered to the Trustee six months
following each budget approved by the Independent Engineer.
"Capital Expenditures" means Major Maintenance, any expenses incurred in
connection with the development and implementation of any plan for the
drilling and maintenance of additional geothermal wells for the Projects and
any other expenses that are capitalized on the balance sheet and qualify as
capital expenditures of the relevant Coso partnership in accordance with GAAP.
"Capital Stock" means:
(1) in the case of a corporation, corporate stock;
(2) in the case of an association or business entity, any and all shares,
interests, participations, rights or other equivalents (however
designated) of corporate stock;
(3) in the case of a partnership or limited liability company, partnership
or membership interests (whether general or limited); and
(4) any other interest or participation that confers on a Person the right
to receive a share of the profits and losses of, or distributions of
assets of, the issuing Person.
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"Change of Control" means the occurrence of any of the following:
(1) the direct or indirect sale, transfer, conveyance or other disposition
(other than by way of merger or consolidation), in one or a series of
related transactions, of all or substantially all of the properties or
assets of the Issuer and the Coso partnerships taken as a whole to any
"person" (as that term is used in Section 13(d)(3) of the Exchange Act)
other than Caithness Energy, L.L.C. or an Approved Related Party;
(2) the adoption of a plan relating to the liquidation or dissolution of
the Issuer or any of the Coso partnerships; or
(3) the first day on which Caithness Energy, L.L.C. ceases to own, directly
or indirectly, (a) 50% or more of the total voting power of the Voting
Stock of the Issuer and of each of the Coso partnerships and (b) 25% or
more of the total economic ownership interests in the Issuer and each
of the Coso Partnerships.
"Collateral" means all collateral pledged, or in respect of which a lien is
granted, pursuant to the Indenture and the Security Documents.
"Collateral Agent" means U.S. Bank Trust National Association, as collateral
agent for the benefit of the Secured Parties, together with its successors and
assigns.
"Comparable Treasury Issue" means the United States Treasury security
selected by a Reference Treasury Dealer as having a maturity comparable to the
Remaining Average Life of the Series A notes due 2009 or the Series B notes
2009 to be redeemed that would be utilized, at the time of selection and in
accordance with customary financial practice, in pricing new issues of
corporate debt securities of comparable maturity to the Remaining Average Life
of such notes.
"Comparable Treasury Price" means, with respect to any date of redemption,
(i) the average of the bid and asked prices for the Comparable Treasury Issue
(expressed in each case as a percentage of its principal amount) on the third
business day preceding such date of redemption, as set forth in the daily
statistical release (or any successor release) published by the Federal Reserve
Bank of New York and designated "Composite 3:30 p.m. Quotations for U.S.
Government Securities," or (ii) if such release (or any successor release) is
not published or does not contain such prices on such business day, (A) the
average of the Reference Treasury Dealer Quotations, or (B) if the Trustee
obtains fewer than three such Reference Treasury Dealer Quotations, the average
of all such Reference Treasury Dealer Quotations.
"CPI Adjustment" means an amount equal to (i) $2.0 million plus the amount of
all previous annual adjustments made pursuant to this definition multiplied by
(ii) the percentage change from the previous year in the annual average
consumer price index as published by the Bureau of Labor Statistics of the
United States Department of Labor in the "Consumer Price Index for All Urban
Consumers, 1982-84 = 100, All Cities, % change past year' under the column Yr.
Avg."'; provided that for purposes of calculating the CPI Adjustment, the most
recently ended calendar year prior to the date of determination shall be used;
and provided, further, the CPI Adjustment for the twelve months ended December
30, 1999, shall be zero. If the Bureau of Labor Statistics shall no longer
publish such statistics, or if the Bureau of Labor Statistics shall no longer
maintain any statistics on the purchasing power of the consumer dollar,
comparable statistics published by a reasonable financial periodical or
recognized authority mutual agreed upon by the Issuer and the Trustee shall be
used to determine the CPI Adjustment.
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"Credit Agreement" means, individually, (1) that certain Credit Agreement
dated as of May 28, 1999, between Navy I Partnership, as borrower, and us, as
lender, (2) that certain Credit Agreement dated as of May 28, 1999, between BLM
Partnership, as borrower, and us, as lender, or (3) that certain Credit
Agreement dated as of May 28, 1999, between Navy II Partnership, as borrower,
and us, as lender.
"Credit Agreement Event of Default" means a Credit Agreement Event of Default
as defined in the Credit Agreement.
"Credit Parties" means each of the Coso partnerships, each of the Partners
and each affiliate of the Coso Partnerships or the Partners that is a party to
any Security Document.
"Custodian" means, initially, the Trustee, and its successors and assigns or
any other custodian performing similar functions.
"Debt Service Coverage Ratio" means for any period, without duplication, the
ratio of (i) (A) the sum of all revenues (including interest and fee income,
but excluding any insurance proceeds and all other similar non-recurring
receipts in an aggregate amount in excess of $2.0 million in any twelve-month
period) of the Coso partnerships for such period, minus (B) the aggregate
amount of Operating and Maintenance Costs of the Coso partnerships for such
period, minus (C) all Capital Expenditures during such period, to (ii) the sum
of (A) all principal, premium (if any) and interest payable with respect to
Permitted Indebtedness outstanding (other than Subordinated Indebtedness) for
such period, plus (B) the aggregate amount of overdue principal, premium (if
any) and interest payments owed with respect to Permitted Indebtedness
outstanding (other than Subordinated Indebtedness) from previous periods; all
as determined on a cash basis in accordance with GAAP.
"Debt Service Reserve Account" means the account of such name created under
the Depositary Agreement.
"Debt Service Reserve Letter of Credit" one or more irrevocable, direct pay
letters of credit issued by the Debt Service Reserve LOC Provider in favor of
the Depositary where the account party is not the Issuer and/or Coso
partnerships.
"Debt Service Reserve LOC Provider" means the commercial bank(s) or financial
institution(s) issuing the Debt Service Reserve Letter of Credit, which
institution shall be rated not less than A by S&P and A2 by Moody's.
"Debt Service Reserve Required Balance" means, on the closing date of the
Series A notes offering, $50.0 million, and thereafter an amount equal to the
aggregate amount of the principal and interest due on the Series B notes on the
next succeeding semi-annual scheduled payment date.
"Deeds of Trust" means (i) that certain Deed of Trust, Assignment of Rents,
Fixture Filing and Security Agreement dated as of May 28, 1999, executed by
Navy I Partnership in favor of the trustee thereunder and the Collateral Agent
as beneficiary, (ii) that certain Deed of Trust, Assignment of Rents, Fixture
Filing and Security Agreement dated as of May 28, 1999, executed by BLM
Partnership in favor of the trustee thereunder and the Collateral Agent as
beneficiary, (iii) that certain Deed of Trust, Assignment of Rents, Fixture
Filing and Security Agreement dated as of May 28, 1999, executed by Navy II
Partnership in favor of the trustee thereunder and the Collateral Agent as
beneficiary, (iv) that certain Deed of Trust, Assignment of Rents, Fixture
Filing and Security
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Agreement dated as of May 28, 1999, executed by Coso Transmission Line Partners
in favor of the trustee thereunder and the Collateral Agent as beneficiary, (v)
that certain Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement dated as of May 28, 1999, executed by China Lake Joint Venture in
favor of the trustee thereunder and Collateral Agent as beneficiary, (vi) that
certain Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement dated as of May 28, 1999, executed by Coso Land Company in favor of
the trustee thereunder and the Collateral Agent as beneficiary and (vii) any
other deed of trust entered into by any Credit Party in favor of the trustee
thereunder and the Collateral Agent as beneficiary.
"Default" means an event or condition that, with the giving of notice, lapse
of time or failure to satisfy certain specified conditions, or any combination
thereof, would become a Credit Agreement Event of Default or an Event of
Default.
"Depositary" means U.S. Bank Trust National Association, as depositary under
the Depositary Agreement.
"Depositary Agreement" means the Deposit and Disbursement Agreement, dated as
of May 28, 1999, between the Issuer, the Collateral Agent, the Depositary and
the Coso partnerships.
"Distribution Account" means the account of such name created under the
Depositary Agreement.
"Distribution Suspense Account" means the account of such name created under
the Depositary Agreement.
"Duff & Phelps" means Duff & Phelps Credit Rating Company.
"Eminent Domain Proceeds" means all amounts and proceeds (including
instruments) received by a Coso partnership in respect of any Event of Eminent
Domain, after deducting all reasonable expenses incurred in litigating,
arbitrating, compromising, settling or consenting to the settlement of any
claims against the appropriate Governmental Authority (exclusive of any
termination by the Navy of the Navy Contract pursuant to the terms thereof).
"Equity Interests" means Capital Stock and all warrants, options or other
rights to acquire Capital Stock (but excluding any debt security that is
convertible into, or exchangeable for, Capital Stock).
"Event of Default" means the occurrence of an event of default under the
Indenture.
"Event of Eminent Domain" means any compulsory transfer or taking or transfer
under threat of compulsory transfer or taking of any material part of the
Collateral or the Coso projects by any Governmental Authority, but excluding
any termination of the Navy Contract.
"Event of Loss" means an event which causes all or a portion of a Project to
be damaged, destroyed or rendered unfit for normal use for any reason
whatsoever, other than an Event of Eminent Domain or a Title Event.
"Final Maturity Date" means the latest stated maturity date of any series of
the senior secured notes.
"Financing Documents" means, collectively, the Credit Agreement, the
Guarantees, the Indenture, the Partnership Notes, the Depositary Agreement, the
Security Documents and the senior secured notes.
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"GAAP" means generally accepted accounting principles set forth in the
opinions and pronouncements of the Accounting Principles Board of the American
Institute of Certified Public Accountants and statements and pronouncements of
the Financial Accounting Standards Board or in such other statements by such
other entity as have been approved by a significant segment of the accounting
profession, which are in effect from time to time.
"Geothermal Engineer" means GeothermEx Inc., or another widely recognized
geothermal engineer retained as a geothermal engineer by us.
"Geothermal Engineer's Report" means a geothermal engineer's report, dated
May 1999, prepared by the Geothermal Engineer and attached to this prospectus
as Exhibit C.
"Governmental Approvals" means all governmental approvals, authorizations,
consents, decrees, permits, waivers, privileges and filings with all
Governmental Authorities required to be obtained for the construction,
operation and maintenance of a Project.
"Governmental Authority" means the government of any federal, state,
municipal or other political subdivision in which the Projects are located, and
any other government or political subdivision thereof exercising jurisdiction
over the Projects or any party to any of the Project Documents, including all
agencies and instrumentalities of such governments and political subdivisions.
"Guarantee Event of Default" means an Event of Default under and as defined
in a Guarantee.
"Indebtedness" of any Person means, at any date, without duplication:
(1) all obligations of such Person for borrowed money;
(2) all obligations of such Person evidenced by senior secured notes,
debentures, notes or other similar instruments (excluding "deposit
only" endorsements on checks payable to the order of such Person);
(3) all obligations of such Person to pay the deferred purchase price of
property or services (except accounts payable and similar obligations
arising in the ordinary course of business shall not be included
herein);
(4) all obligations of such Person as lessee under capital leases to the
extent required to be capitalized on the books of such Person in
accordance with GAAP; and
(5) all obligations of others of the type referred to in clause (1) through
(4) above guaranteed by such Person, whether or not secured by a lien
or other security interest on any asset of such Person;
provided that "Indebtedness" shall exclude obligations of the Coso
partnerships to the California Energy Commission and liens securing such
obligations to the extent that such obligations and liens do not exceed the
dollar amounts paid to, or to be paid, the Coso partnerships pursuant to
AB1890.
"Independent Engineer" means Sandwell Engineering Inc. or another widely
recognized independent engineering firm or engineer retained as independent
engineer by the Issuer.
"Independent Engineer's Base Case Projections" means the base case
projections prepared by the Independent Engineer and included in the
Independent Engineer's Report.
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"Independent Engineer's Report" means the Independent Engineer's Report,
dated May 20, 1999, prepared by Sandwell Engineering Inc. and attached to this
prospectus as Exhibit A.
"Initial Purchaser" means Donaldson, Lufkin & Jenrette Securities
Corporation.
"Interest Account" means the account of such name created under the
Depositary Agreement.
"Interest Payment Date" means each December 15 and June 15, commencing
December 15, 1999, and concluding on the Final Maturity Date.
"Lien" means any mortgage, pledge, hypothecation, assignment, mandatory
deposit arrangement with any Person owning Indebtedness of such Person,
encumbrance, lien (statutory or other), preference, priority or other security
agreement of any kind or nature whatsoever which has the substantial effect of
constituting a security interest, including, without limitation, any
conditional sale or other title retention agreement, any financing lease having
substantially the same effect as any of the foregoing and the filing of any
financing statement or similar instrument under the Uniform Commercial Code or
comparable law of any jurisdiction, domestic or foreign.
"Loss Proceeds" means all net proceeds from an Event of Loss received by a
Coso partnership, including, without limitation, insurance proceeds or other
amounts actually received, except proceeds of delayed opening or business
interruption insurance, on account of an event which causes all or a
substantial portion of the relevant Project to be damaged, destroyed or
rendered unfit for normal use.
"Loss Proceeds Account" means the account of such name created under the
Depositary Agreement.
"Major Maintenance" means labor, materials and other direct expenses for any
overhaul of or major maintenance procedure for any Project (including major
maintenance such as turbine overhauls) which requires significant disassembly
or shutdown of the relevant Project pursuant to manufacturers' guidelines or
recommendations, engineering or operating considerations or the requirements of
any applicable legal requirement; provided that such expenses are capitalized
on the balance sheet of the relevant Coso partnership and not expensed on the
statement of operations of the relevant Partnership, all in accordance with
GAAP.
"Management Fees" means fees paid to the Partners or their representatives
pursuant to the partnership agreements of the Coso partnerships as determined
by the management committee of each of the Coso partnerships.
"Management Fees Account" means the Account of such name created under the
Depositary Agreement.
"Material Adverse Effect" means a material adverse effect on:
(1) our financial position or results of operation and that of the Coso
partnerships, taken as a whole;
(2) the Collateral or the validity or priority of the Liens on the
Collateral;
(3) our ability to perform our material obligations under the Indenture,
the senior secured notes or any of the Financing Documents to which we
are a party;
(4) the ability of the Trustee to enforce any of our payment obligations
under the Indenture or the senior secured notes; or
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(5) the ability of the Coso partnerships to perform any of their material
obligations under their respective Partnership Notes or the Financing
Documents to which they are a party.
"Moody's" means Moody's Investors Service, Inc., a corporation organized and
existing under the laws of the State of Delaware, its successors and assigns.
"Navy Contract" means the Original Service Contract N62474-79-C-5382, between
U. S. Naval Weapons Center and California Energy Company, Inc., as Contractor,
as amended and assigned.
"Navy I Partners" means ESCA LLC, a Delaware limited liability company, and
New CLOC Company, LLC, a Delaware limited liability company, the general
partners of the Navy I Partnership.
"Navy I Partnership" means Coso Finance Partners, a California general
partnership.
"Navy I Project" means the ownership, development and operation of the
turbine generators and associated geothermal resource wells operated by the
Navy I Partnership on a portion of the lands described in Exhibit A of the Navy
Contract; and the Navy I Partnership's ownership and operation of the 115kV
transmission line to the Edison substation at Inyokern, California.
"Navy II Partners" means Caithness Navy II Group, LLC., a Delaware limited
liability company, and New CTC Company, LLC, a Delaware limited liability
company, the general partners of the Navy II Partnership.
"Navy II Partnership" means Coso Power Developers, a California general
partnership.
"Navy II Project" means the ownership, development and operation of the
turbine generators and associated geothermal resource wells operated by the
Navy II Partnership on a portion of the lands described in Exhibit A of the
Navy Contract.
"Obligations" means any principal, interest, penalties, fees,
indemnifications, reimbursements, damages and other liabilities payable under
the documentation governing any Indebtedness.
"Operating and Maintenance Costs" means, for any periods, all amounts
disbursed by or on behalf of the Coso partnerships for operation, maintenance
(excluding, after the first Interest Payment Date, Capital Expenditures),
administration, repair, or improvement of their Projects, including, without
limitation, premiums on insurance policies, property and other taxes, payments
under the relevant operating and maintenance agreements, leases, royalty and
other land use agreements and fees, expenses and any other payments required
under the Project Documents (excluding the Operating and Maintenance Fees and
the Management Fees).
"Operating and Maintenance Fees" means fees payable to FPL Energy Operating
Services, Inc. and Coso Operating Company, LLC or any successor operators with
respect to the field and plant operations and maintenance agreements.
"Operating and Maintenance Fees Account" means the Account of such name
created under the Depositary Agreement.
"Operating Budget" means a budget of Operating and Maintenance Costs and
Capital Expenditures with respect to the Coso partnerships and the Coso
projects for any given fiscal year, or part thereof, and prepared in good faith
on the basis of estimated requirements, showing such costs by category for such
fiscal year.
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"Outstanding Notes" means, as of the time in question, all senior secured
notes authenticated and delivered under the Indenture, except (i) senior
secured notes theretofore canceled or required to be canceled under the
Indenture; (ii) senior secured notes for which provision for payment shall have
been made in accordance with the Indenture; and (iii) senior secured notes in
substitution for which other senior secured notes have been authenticated and
delivered pursuant to the Indenture.
"Partners" means, collectively, the Navy I Partners, the BLM Partners and the
Navy II Partners.
"Payment Date" means any Interest Payment Date or Principal Payment Date.
"Permitted Additional Senior Lender" shall mean a holder of any Permitted
Indebtedness of the Issuer (other than the senior secured notes and Permitted
Indebtedness described in clause (4) or (5) of the definition of Permitted
Indebtedness) or of any Permitted Partnership Indebtedness of any Coso
partnership described in clause (1) of the definition of Permitted Partnership
Indebtedness (other than Permitted Indebtedness described in clause (4) or (5)
of the definition of Permitted Indebtedness), or any agent, depositary,
collateral agent, security trustee or similar such party acting on behalf of
any such holder or holders.
"Permitted Indebtedness" means:
(1) the senior secured notes;
(2) Indebtedness incurred to finance the making of capital improvements to
the Projects required to maintain compliance with applicable law or
anticipated changes therein; provided that no such Indebtedness may be
incurred unless at the time of such incurrence (i) no Default or Event
of Default has occurred and is continuing, (ii) the Independent
Engineer confirms as reasonable a certification by the Issuer
(containing customary qualifications) that the proposed capital
improvements are reasonably expected to enable such Project to comply
with applicable or anticipated legal requirements, (iii) the
calculations of the Issuer demonstrate that, after giving effect to the
incurrence of such Indebtedness, the minimum projected Debt Service
Coverage Ratio of the Issuer (x) for the next four consecutive fiscal
quarters, commencing with the quarter in which such Indebtedness is
incurred, taken as one annual period, and (y) for each subsequent
fiscal year through the Final Maturity Date, will not be less than 1.25
to 1 and (iv) the Rating Agencies confirm that the incurrence of such
Indebtedness will not result in a Rating Downgrade;
(3) Indebtedness incurred to finance the making of capital improvements to
the Projects not required by applicable law so long as after giving
effect to the incurrence of such Indebtedness (i) no Default or Event
of Default has occurred and is continuing, (ii) the calculations of the
Issuer that demonstrate, after giving effect to the incurrence of such
Indebtedness, the minimum projected Debt Service Coverage Ratio (x) for
the next four consecutive fiscal quarters, commencing with the quarter
in which such Indebtedness is incurred, taken as one annual period, and
(y) for each subsequent fiscal year through the Final Maturity Date, in
each case will not be less than (A) 1.3 to 1 if the Indebtedness is on
or before December 30, 2001, or (B) 1.5 to 1 if the Indebtedness is
after December 30, 2001, and (iii) each of the Rating Agencies confirm
that the incurrence of such Indebtedness will not result in a Rating
Downgrade;
(4) (x) Subordinated Indebtedness accrued or incurred by BLM to Coso Land
Company constituting royalty payments pursuant to an agreement
regarding royalties between such parties as in effect on the closing
date of the Series A notes offering, (y) Subordinated
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Indebtedness (other than as specified in subclause (x) of this clause
(y) of this definition of Permitted Indebtedness) from Affiliates in an
amount not to exceed $20.0 million or (z) any other Subordinated
Indebtedness so long as each of the Rating Agencies confirm that the
incurrence of such Subordinated Indebtedness will not result in a Rating
Downgrade, and in the case of both (x) and (y), which amounts shall be
used to finance capital, operating or other costs with respect to the
Projects; provided that all payments of principal of, and premium, if
any, and interest on, any such Subordinated Indebtedness shall
constitute a Restricted Payment under the Indenture; and
(5) Indebtedness not otherwise described under clauses (1) through (4)
hereof incurred solely for working capital and operational needs of the
Projects which, when aggregated with the then outstanding principal
balance of Indebtedness of one or more of the Coso partnerships
permitted pursuant to clause (6) of the definition of Permitted
Partnership Indebtedness (but without duplication of amounts), does not
exceed $5.0 million at any time outstanding.
"Permitted Investments" means an Investment in any of the following:
(1) direct obligations of the Department of the Treasury of the United
States of America;
(2) obligations, representing full faith and credit of the United States of
America, of any of the following federal agencies: Export-Import Bank,
Farmers Home Administration, General Services Administration, U.S.
Maritime Administration, Small Business Administration, Government
National Mortgage Association (GNMA), U.S. Department of Housing &
Urban Development (PHA's) and Federal Housing Administration;
(3) obligations issued or fully guaranteed by any state of the United
States of America or any political subdivision of any such state or any
public instrumentality thereof and, at the time of the acquisition,
having one of the two highest ratings obtainable from either S&P or
Moody's;
(4) certificates of deposit and eurodollar time deposits, bankers'
acceptances and overnight bank deposits, in each case with any domestic
or foreign commercial bank having capital and surplus in excess of
$250.0 million;
(5) notes, bonds, collateralized mortgage obligations or other evidences of
indebtedness rated "AAA" by S&P and "Aaa" by Moody's issued by the
Federal Home Loan Bank, the Federal National Mortgage Association or
the Federal Home Loan Mortgage Corporation;
(6) commercial paper rated in any one of the two highest rating categories
by Moody's or S&P;
(7) investment agreements with banks (foreign and domestic),
broker/dealers, and other financial institutions rated at the time of
bid in any one of the three highest rating categories by Moody's and
S&P;
(8) repurchase agreements with banks (foreign and domestic),
broker/dealers, and other financial institutions rated at the time of
bid in any one of the three highest rating categories by Moody's and
S&P, provided, (a) collateral is limited to the securities specified in
clauses (1) through (5) above, (b) the margin levels for collateral
must be maintained at a minimum of 102% including principal and
interest, (c) the Trustee shall have a first perfected security
interest in the collateral, (d) the collateral will be delivered to a
third party custodian, designated by us, acting for the benefit of the
Trustee and all fees and expenses related to collateral custody will be
our responsibility, (e) the collateral must have been or will be
acquired at the market price and marked to market weekly and collateral
level shortfalls cured within 24 hours, (f) unlimited right of
substitution of collateral is allowed provided that substitution
collateral must be permitted collateral substituted at a current market
price and substitution fees of the custodian shall be paid by us;
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(9) asset-backed securities having the highest rating obtainable from
either S&P or Moody's;
(10) forward purchase agreements delivering securities specified in clauses
(1) and (6) above with banks (foreign and domestic), broker/dealers,
and other financial institutions maintaining a long-term rating on the
day of bid no lower than investment grade by both S&P and Moody's
(such rating may be at either the parent or subsidiary level); and
(11) money market funds rated "AAAm" or "AAAm-G" or better by S&P and other
financial funds investing exclusively in investments of the types
described in clauses (1) through this clause (11) of this definition.
"Permitted Lien" means, collectively:
(1) Liens to secure Indebtedness described in clauses (1), (2) and (3) of
the definition of Permitted Indebtedness and described in clauses (1),
(2), (3) and (4) of the definition of Permitted Partnership
Indebtedness;
(2) mechanic's, workmen's, materialmen's, supplier's, construction or other
like Liens arising in the ordinary course of business that, in each
case, have not become the subject of foreclosure or any other action or
proceeding;
(3) servitudes, easements, rights-of-way, restrictions, minor defects or
irregularities in title and such other encumbrances or charges against
real property or interests therein as are of a nature generally
existing with respect to properties of a similar character and which do
not in any material way interfere with the use thereof in the business
of the Coso partnerships; and
(4) other Liens incidental to the conduct of the Coso partnerships'
business or the ownership of properties and assets which were not
incurred in connection with the borrowing of money or the obtaining of
advances or credit (other than vendor's liens for accounts payable in
the ordinary course of business), and which do not in the aggregate
materially impair the use thereof in the operation of their business.
"Permitted Partnership Indebtedness" means:
(1) proceeds of Permitted Indebtedness loaned to any Coso partnerships by
the Issuer or, incurred by a Coso partnership;
(2) guarantees by one or more of the Coso partnerships of Permitted
Indebtedness;
(3) the Guarantees;
(4) the Partnership Notes;
(5) Indebtedness of one Coso partnership to another Coso partnership; and
(6) Indebtedness of one or more of the Coso partnerships not otherwise
described under clauses (1) through (5) hereof incurred solely for
working capital and operational needs of the Projects which, when
aggregated with the then outstanding principal balance of Indebtedness
of the Issuer permitted pursuant to clause (5) of the definition of
Permitted Indebtedness (but without duplication of amounts), does not
exceed $5.0 million at any time outstanding.
"Permitted Power Contract Buy-Out" means the termination of a Power Purchase
Agreement or the negotiated reduction of capacity and/or energy or the rates
related thereto to be sold under a Power Purchase Agreement other than pursuant
to such agreement's terms and the payment by Southern California Edison made in
connection therewith.
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"Person" means any individual, sole proprietorship, corporation, partnership,
joint venture, limited liability partnership, limited liability corporation,
trust, unincorporated association, institution, Governmental Authority or any
other entity.
"Principal Account" means the Account of such name created under the
Depositary Agreement.
"Principal Payment Date" when used with respect to any senior secured note
means the date on which all or a portion of the principal of such senior
secured note becomes due and payable as provided therein or in the Indenture,
whether on a scheduled date for payment of principal at a Redemption Date, the
Final Maturity Date, a date of declaration of acceleration, or otherwise.
"Project Documents" means, individually and collectively, all material
existing agreements and documents which relate to all or any portion of one or
more of the Projects.
"Rating" means the rating of the senior secured notes by the Rating Agencies.
"Rating Agency" means any of Moody's, S&P and Duff & Phelps.
"Rating Downgrade" means a lowering by the Rating Agencies of the then
current credit ratings of the senior secured notes.
"Redemption Account" means the account of such name created under the
Depositary Agreement.
"Redemption Date" means the date on which Issuer redeems or shall redeem any
senior secured notes in accordance with the Indenture.
"Reference Treasury Dealer" means any nationally recognized primary U.S.
government securities dealer in New York City selected by the Issuer.
"Reference Treasury Dealer Quotations" means, with respect to each Reference
Treasury Dealer and any date of redemption, the average, as determined by the
Trustee, of the bid and asked prices for the Comparable Treasury Issue
(expressed in each case as a percentage of its principal amount) quoted in
writing to the Trustee by such Reference Treasury Dealer at 5:00 p.m. on the
third business day preceding such date of redemption.
"Remaining Average Life" means, with respect to any Series A notes due 2009
and Series B notes due 2009, the principal of which is to be redeemed (the
"Called Principal"), the number of years (calculated to the nearest one-twelfth
year) obtained by dividing:
(1) such Called Principal into
(2) the sum of the products obtained by multiplying:
(a) the principal component of each Remaining Scheduled Payment (as
defined below) with respect to such Called Principal by
(b) the number of years (calculated to the nearest one-twelfth year)
that will elapse between the date on which such Called Principal is
to be redeemed (the "Settlement Date") and the scheduled due date
of such Remaining Scheduled Payment.
For purposes of this definition, the term "Remaining Scheduled Payments" means,
with respect to the Called Principal of any Series A notes due 2009 and Series
B notes due 2009, all payments of
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such Called Principal and interest thereon that would be due after the
Settlement Date with respect to such Called Principal if no payment of such
Called Principal were made prior to its scheduled due date.
"Required Holders" means, at any time, Persons that at such time hold at
least a majority in aggregate principal amount of the Outstanding Notes.
"Responsible Officer" means, with respect to knowledge of any default under
the Indenture or the Credit Agreement, the chief executive officer, president,
chief financial officer, general counsel, principal accounting officer,
treasurer, or any vice president of the Issuer or a Coso partnership, as
applicable, or other officer of such corporation who in the normal performance
of his or her operational duties would have knowledge of the subject matter
relating to such default.
"Restricted Payment" means, with respect to any Person:
(1) the declaration and payment of distributions or dividends, the issuance
of Equity Interests in such Person or any other payment in respect of
any Equity Interests made in cash, property, obligations or other
notes;
(2) any payment of the principal of or interest on any Subordinated
Indebtedness;
(3) the making of any loans or advances to any Affiliate (other than
Permitted Indebtedness);
provided, however, that "Restricted Payment" shall not include payments under
any of the Project Documents for services rendered.
"Revenue Account" means the account of such name created under the Depositary
Agreement.
"S&P" means Standard & Poor's Rating Group Corporation, a corporation
organized and existing under the laws of the State of New York, its successors
and assigns.
"Secured Parties" means the Trustee, the Collateral Agent, the Depositary,
any Permitted Additional Senior Lender or any other Person that becomes a
Secured Party under any Financing Document.
"Security Agreements" means (1) that certain Security Agreement dated as of
May 28, 1999, executed by Navy I Partnership in favor of the Collateral Agent,
(2) that certain Security Agreement dated as of May 28, 1999, executed by BLM
Partnership in favor of the Collateral Agent and (3) that certain Security
Agreement dated as of May 28, 1999, executed by Navy II Partnership in favor of
the Collateral Agent.
"Security Documents" means, collectively, the Depositary Agreement, the Deeds
of Trust, the Security Agreements, the Pledge Agreements and any other document
providing for any lien, pledge, encumbrance, mortgage or security interest on
(i) any or all of the assets of the Coso partnerships, the Issuer, the
ownership interests thereof or (ii) the assets constituting or related to the
Projects.
"Senior Indebtedness" means all of the Permitted Indebtedness of Issuer and
the Coso partnerships other than the Subordinated Indebtedness.
"Subordinated Indebtedness" means Indebtedness (and the note or other
instrument evidencing the same) which has been subordinated, on terms and
conditions substantially the same as those permitted under the Indenture, to
the prior payment of amounts owing under the Indenture and the senior secured
notes and the repayment of which shall be made only from Restricted Payments.
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"Title Event" means the existence of any defect of title or lien or
encumbrance on a Project (other than certain permitted liens) in effect on the
closing date of the Series A notes offering that entitles the Collateral Agent
to make a claim under the policy or policies of title insurance required
pursuant to the Financing Documents.
"Title Event Proceeds" means all amounts and proceeds (including instruments)
in respect of any Title Event.
"Transaction Documents" means the Project Documents and the Financing
Documents.
"Treasury Rate" means, with respect to any date of redemption, the rate per
annum equal to the semi-annual equivalent yield to maturity of the Comparable
Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed
as a percentage of its principal amount) equal to the Comparable Treasury Price
for such date of redemption.
"Trustee" means the party named as such above until a successor replaces it
in accordance with the applicable provisions of this Indenture and thereafter
means the successor serving hereunder.
"Voting Stock" of any Person as of any date means the Capital Stock of such
Person that is at the time entitled to vote in the election of the Board of
Directors or otherwise entitled to vote in the determination of the management
of such Person.
203
MATERIAL FEDERAL INCOME TAX CONSEQUENCES
OF THE EXCHANGE OFFER
The exchange of Series A notes for Series B notes pursuant to the exchange
offer should not be treated as a taxable transaction for U.S. federal income
tax purposes because the Series B notes will not be considered to differ
materially from the Series A notes. Rather, any Series B notes you receive
should be treated as a continuation of your investment in the Series A notes.
As a result, you should bear no material U.S. federal income tax consequences
due to the exchange, and you should have the same adjusted issue price,
adjusted basis and holding period in the Series B notes as you had in the
Series A notes immediately prior to the exchange.
You should consult your own tax advisor concerning the consequences of your
exchange of Series A notes for Series B notes, including the tax consequences
under, state, local, foreign or other tax laws, and the possible effects on you
of changes in U.S. federal or other tax laws.
204
PLAN OF DISTRIBUTION
Each broker-dealer that receives Series B notes for its own account as a
result of this exchange offer, sometimes referred to a as participating broker,
must acknowledge that it will deliver a prospectus in connection with any
resale of such Series B notes. This prospectus, as it may be periodically
amended or supplemented, may be used by a participating broker in connection
with any resale of the Series B notes received in exchange for Series A notes
where the Series A notes were acquired as a result of market-making activities
or other trading activities. For a period of 180 days from the completion of
the exchange offer, or a shorter period if all Series B notes have been
disposed of by the participating brokers, we will make this prospectus, as
amended or supplemented, available to any participating broker for use in
connection with the resale of the Series B notes. Until this period ends, we
will send a reasonable number of additional copies of this prospectus and any
amendment or supplement to this prospectus to any participating broker that
requests such documents in the letter of transmittal.
We will not receive any proceeds from the sale of Series B notes by broker-
dealers. Series B notes received by any participating broker may be sold
periodically, in one or more transactions in the over-the-counter market, in
negotiated transactions, through the writing of options on the Series B notes,
or a combination of such methods of resale provided that the Series B notes are
sold at market prices prevailing at the time of resale, at prices related to
such market prices or negotiated prices. Any resale of Series B notes may be
made directly to purchasers or to or through broker-dealers who may receive
compensation in the form of commissions or concessions from a broker-dealer
and/or purchasers of the Series B notes. Any participating broker that resells
the Series B notes that were received by it for its own account pursuant to
this exchange offer and any broker dealer that participates in the distribution
of Series B notes may be deemed to be an underwriter within the meaning of the
Securities Act. Any profit on the resale of Series B notes and any commissions
or concessions received by any such persons may be deemed to be underwriting
compensation under the Securities Act. The letter of transmittal states that by
acknowledging that it will deliver, and by delivering a prospectus as required,
a participating broker will not be deemed to admit that it is an underwriter
within the meaning of the Securities Act.
We will pay all the expenses incident to this exchange offer, which shall not
include the expense of any holder in connection with resales of the Series B
notes. We have agreed to indemnify holders of the Series B notes, including
participating brokers, against certain liabilities, including liabilities under
the Securities Act.
LEGAL MATTERS
Reed Smith Shaw & McClay LLP will opine on the validity of the Series B notes
for us, and, together with Riordan & McKinzie, A Professional Law Corporation,
will opine on the validity of the Guarantees for the Coso partnerships.
CHANGE IN INDEPENDENT ACCOUNTANTS
Since 1991, Caithness Energy and CalEnergy, the two former co-sponsors of the
Coso projects, had engaged PricewaterhouseCoopers LLP to audit the financial
statements of the Coso partnerships. On February 25, 1999, Caithness
Acquisition, Caithness Energy's wholly owned subsidiary, purchased all of
CalEnergy's interests in the Coso projects, and Caithness Energy engaged KPMG
LLP, its own independent certified public accountants, to audit the financial
statements of the Coso partnerships in the
205
future, rather than to continue to have PricewaterhouseCoopers LLP audit those
financial statements. In connection with the audits of the financial statements
of Coso Finance Partners and Coso Finance Partners II, Coso Energy Developers
and Coso Power Developers for each of the two years in the period ended
December 31, 1998 and through February 25, 1999, (i) Caithness Energy had no
disagreements with PricewaterhouseCoopers LLP on any matter of accounting
principles or practices, financial statement disclosure or auditing scope or
procedure, which disagreements if not resolved to the satisfaction of
PricewaterhouseCoopers LLP would have caused them to make reference thereto in
their reports on the financial statements for such years, and (ii) the reports
of PricewaterhouseCoopers LLP on the Coso partnerships did not contain any
adverse opinion or disclaimer of opinion, and were not modified as to
uncertainty, audit scope or accounting principles except for the reference to
the Coso partnerships' adoption in 1998 of Statement of Position No. 98-5,
"Reporting on the Costs of Start-up Activities."
EXPERTS
The balance sheet of Caithness Coso Funding Corp. as of April 22, 1999, has
been included herein and in this prospectus in reliance upon the report of KPMG
LLP, independent certified public accountants, appearing elsewhere herein, and
upon the authority of said firm as experts in accounting and auditing.
The combining and combined financial statements of Coso Finance Partners and
Coso Finance Partners II and the financial statements of Coso Energy Developers
and Coso Power Developers as of December 31, 1998 and 1997 and for each of the
three years in the period ended December 31, 1998, included in this prospectus,
have been included in reliance on the reports of PricewaterhouseCoopers LLP,
independent accountants, given on the authority of said firm as experts in
auditing and accounting.
Sandwell Engineering Inc. has prepared the independent engineer's report
dated May 20, 1999, appearing in Exhibit A to this prospectus. You should read
it in its entirety for additional information about the Coso projects and the
other matters addressed in it. We included the independent engineer's report in
this prospectus in reliance on the conclusions expressed therein by Sandwell
Engineering Inc. and upon that firm's experience in preparing independent
engineer's reports for independent power projects.
Henwood Energy Services, Inc. has prepared the energy markets consultant's
report dated May 20, 1999 appearing in Exhibit B to this prospectus. You should
read it in its entirety for additional information about certain industry and
regulatory matters affecting the sales of electricity by the Coso projects and
the related matters addressed in it. We included the energy markets
consultant's report in this prospectus in reliance on the conclusions expressed
therein by Henwood Energy Services, Inc. and upon that firm's experience in
providing business advisory and other services and market forecasts in
electricity and gas to international firms and public authorities.
GeothermEx, Inc. has prepared the geothermal consultant's report dated May
1999, appearing in Exhibit C to this prospectus. You should read it in its
entirety for additional information about the sufficiency of the geothermal
resources available for use and for conversion to electrical power and the
related matters addressed in it. As we indicated above, we have omitted from
Exhibit C of this prospectus Appendices A through F of the geothermal
consultant's report. Appendices A through F include the production histories
for Navy I, BLM and Navy II production wells and the injection
206
histories for Navy I, BLM and Navy II injection wells. You can obtain copies of
Appendices A through F of the geothermal consultant's report from us upon
request. See "Available Information."
We included the geothermal consultant's report in this prospectus in reliance
on the conclusions expressed therein by GeothermEx, Inc. and upon that firm's
experience in preparing consultant's reports for geothermal projects.
AVAILABLE INFORMATION
Upon effectiveness of the registration statement of which this prospectus is
a part, we and the Coso partnerships will be subject to the informational
requirements of the Securities Exchange Act, and in accordance therewith we
file reports, proxy and information statements and other information with the
SEC. You can inspect and copy these reports, proxy and information statements
and other information at:
. the public reference facilities maintained by the commission at 450
Fifth Street, N.W., Washington, DC 20549, and
. the regional offices of the SEC located at:
. 500 West Madison Street, Room 1400, Chicago, Illinois 60606, and
. 7 World Trade Center, 13th Floor, New York, New York 10048.
You also can obtain copies of these materials from the public reference
section of the commission at 450 Fifth Street, N.W., Washington, DC 20549 at
prescribed rates. You can obtain electronic filings made through the electronic
data gathering, analysis and retrieval system at the SEC's web site,
http://www.sec.gov.
Whether or not required by the rules and regulations of the SEC, so long as
any Series B notes are outstanding, we will furnish to the holders of Series B
notes, within the time periods specified in the SEC's rules and regulations:
. all quarterly and annual financial information that would be required to
be contained in a filing with the SEC on Forms 10-Q and 10-K if we were
required to file such forms, including a "Management's Discussion and
Analysis of Financial Condition and Results of Operation" and, with
respect to the annual information only, a report thereon by our and the
Coso partnerships' certified independent accountants; and
. all current reports that would be required to be filed with the SEC on
Form 8-K if we were required to file such reports.
In addition, we have agreed that, for so long as any senior secured notes
remain outstanding, we will furnish to the holders and to securities analysts
and prospective investors, upon their request, the information required to be
delivered pursuant to Rule 144A(d)(4) under the Securities Act.
207
INDEX TO FINANCIAL STATEMENTS
Caithness Coso Funding Corp.
Independent Auditor's Report............................................. F-2
Balance sheet at April 22, 1999.......................................... F-3
Note to balance sheet.................................................... F-4
Coso Finance Partners and Coso Finance Partners II--Combining and Combined
Financial Statements
Report of independent accountants........................................ F-5
Combining and combined balance sheets at December 31, 1997 and 1998...... F-6
Combining and combined statements of operations for each of the three
years in the period ended December 31, 1998............................. F-7
Combining and combined statements of partners' capital for each of the
three years in the period ended December 31, 1998....................... F-8
Combining and combined statements of cash flows for each of the three
years in the period ended December 31, 1998............................. F-9
Notes to combining and combined financial statements..................... F-10
Coso Energy Developers--Financial Statements
Report of independent accountants........................................ F-18
Balance sheets at December 31, 1997 and 1998............................. F-19
Statements of operations for each of the three years in the period ended
December 31, 1998....................................................... F-20
Statements of partners' capital for each of the three years in the period
ended December 31, 1998................................................. F-21
Statements of cash flows for each of the three years in the period ended
December 31, 1998....................................................... F-22
Notes to financial statements............................................ F-23
Coso Power Developers--Financial Statements
Report of independent accountants........................................ F-31
Balance sheets at December 31, 1997 and 1998............................. F-32
Statements of operations for each of the three years in the period ended
December 31, 1998....................................................... F-33
Statements of partners' capital for each of the three years in the period
ended December 31, 1998................................................. F-34
Statements of cash flows for each of the three years in the period ended
December 31, 1998....................................................... F-35
Notes to financial statements............................................ F-36
Coso Finance Partners and Coso Finance Partners II
Unaudited condensed balance sheets at December 31, 1998 and March 31,
1999.................................................................... F-43
Unaudited condensed statements of operations for the three months ended
March 31, 1998, the two months ended February 28, 1999 and the one month
ended March 31, 1999 ......................... ......................... F-44
Unaudited condensed statements of cash flows for the three months ended
March 31, 1998, the two months ended February 28, 1999 and the one month
ended March 31, 1999 ................................................... F-45
Notes to the unaudited condensed financial statements.................... F-46
Coso Energy Developers
Unaudited condensed balance sheets at December 31, 1998 and March 31,
1999.................................................................... F-47
Unaudited condensed statements of operations for the three months ended
March 31, 1998, the two months ended February 28, 1999 and the one month
ended March 31, 1999 ......................... ......................... F-48
Unaudited condensed statements of cash flows for the three months ended
March 31, 1998, the two months ended February 28, 1999 and the one month
ended March 31, 1999 ................................................... F-49
Notes to the unaudited condensed financial statements.................... F-50
Coso Power Developers
Unaudited condensed balance sheets at December 31, 1998 and March 31,
1999.................................................................... F-51
Unaudited condensed statements of operations for the three months ended
March 31, 1998, the two months ended February 28, 1999 and the one month
ended March 31, 1999 ................................................... F-52
Unaudited condensed statements of cash flows for the three months ended
March 31, 1998, the two months ended February 28, 1999 and the one month
ended March 31, 1999 ......................... ......................... F-53
Notes to the unaudited condensed financial statements.................... F-54
F-1
INDEPENDENT AUDITOR'S REPORT
The Board of Directors
Caithness Coso Funding Corp.:
We have audited the accompanying balance sheet of Caithness Coso Funding
Corp. as of April 22, 1999. This balance sheet is the responsibility of the
Company's management. Our responsibility is to express an opinion on this
balance sheet based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the balance sheet is free of material
misstatement. An audit of a balance sheet includes examining, on a test basis,
evidence supporting the amounts and disclosures in that balance sheet. An audit
of a balance sheet also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
balance sheet presentation. We believe that our audit of the balance sheet
provides a reasonable basis for our opinion.
In our opinion, the balance sheet referred to above presents fairly, in all
material respects, the financial position of Caithness Coso Funding Corp. as of
April 22, 1999, in conformity with generally accepted accounting principles.
KPMG LLP
New York, NY
April 23, 1999
F-2
CAITHNESS COSO FUNDING CORP.
BALANCE SHEET
AS OF APRIL 22, 1999
Current asset:
Cash................................................................. $ 3
===
Stockholder's equity:
Common stock ($0.01 par value; 1,000 shares authorized; 300 issued
and outstanding).................................................... $ 3
Additional paid-in capital........................................... --
---
Total stockholders' equity............................................. $ 3
===
See accompanying note to balance sheet.
F-3
CAITHNESS COSO FUNDING CORP.
NOTE TO BALANCE SHEET
APRIL 22, 1999
(1) General
Caithness Coso Funding Corp. (Funding Corp.) was incorporated on April 22,
1999, in Delaware. Funding Corp. is a special purpose corporation that has been
recently formed for the purpose of issuing senior secured notes on behalf of
Coso Finance Partners, Coso Energy Developers and Coso Power Developers (the
Coso partnerships), affiliates of Funding Corp. If Funding Corp. completes the
offering of the senior secured notes, Funding Corp. will loan all of the
proceeds from the offering to the Coso partnerships, and the Coso partnerships
will guarantee, on a senior secured basis, repayment of the senior secured
notes.
Funding Corp. has no material assets other than the loans that will be made
to the Coso partnerships. Also, Funding Corp. does not conduct any business,
other than issuing the senior secured notes and making the loans to the Coso
partnerships.
F-4
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners of Coso Finance Partners
and Coso Finance Partners II
In our opinion, the accompanying combining and combined balance sheets and
the related combining and combined statements of operations, of partners'
capital and of cash flows present fairly, in all material respects, the
combining and combined financial position of Coso Finance Partners and Coso
Finance Partners II at December 31, 1997 and 1998, and the combining and
combined results of their operations and their cash flows for each of the three
years in the period ended December 31, 1998, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Partnerships' management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with generally accepted
auditing standards which require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management,
and evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for the opinion expressed above.
As discussed in Note 2 to the combining and combined financial statements,
the Partnerships adopted in 1998 Statement of Position No. 98-5, "Reporting on
the Costs of Start-Up Activities."
/s/ PricewaterhouseCoopers LLP
San Francisco, California
February 12, 1999
F-5
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
COMBINING AND COMBINED BALANCE SHEETS
(Dollars in thousands)
December 31, 1998
------------------------------------------
December 31, Coso Coso
1997 Finance Finance
Combined Partners Partners II Eliminations Combined
Assets
Cash.................... $ 2,888 $ -- $ -- $ -- $ --
Restricted cash and
investments (Note 5)... 6,479 7,524 -- -- 7,524
Accounts receivable..... 4,234 5,404 -- -- 5,404
Prepaid expenses and
other assets........... 863 426 -- -- 426
Amounts due from related
parties, net (Note 7).. 4,211 3,782 8,748 (8,748) 3,782
Property, plant and
equipment, net (Note
4)..................... 186,392 180,380 -- -- 180,380
Transfer to related
party (Note 1)......... -- -- 11,995 (11,995) --
Advances to China Lake
Plant Services, Inc.... 3,967 4,139 -- -- 4,139
Deferred financing
costs, net............. 356 233 -- -- 233
-------- -------- ------- -------- --------
$209,390 $201,888 $20,743 $(20,743) $201,888
======== ======== ======= ======== ========
Liabilities and
Partners' Capital
Accounts payable and
accrued liabilities.... $ 793 $ 2,581 $ -- $ -- $ 2,581
Navy sinking fund and
royalties payable
(Note 5)............... $ 7,363 8,808 -- -- 8,808
Amounts due to related
parties (Note 7)....... -- 8,748 -- (8,748) --
Transfer from related
party (Note 1)......... -- 11,995 -- (11,995) --
Project loan (Note 6)... 45,666 40,566 -- -- 40,566
-------- -------- ------- -------- --------
53,822 72,698 -- (20,743) 51,955
Partners' capital....... 155,568 129,190 20,743 -- 149,933
-------- -------- ------- -------- --------
$209,390 $201,888 $20,743 $(20,743) $201,888
======== ======== ======= ======== ========
The accompanying notes are an integral part of the combining and combined
financial statements.
F-6
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
COMBINING AND COMBINED STATEMENTS OF OPERATIONS
(Dollars in thousands)
For the years
ended December For the year ended December 31, 1998
31, -------------------------------------------
----------------- Coso Coso
1996 1997 Finance Finance
Combined Combined Partners Partners II Eliminations Combined
Revenue
Sales of electricity.... $118,206 $100,431 $53,153 $ -- $ -- $53,153
Royalty................. -- -- -- 493 (493) --
Interest income......... 3,286 1,980 585 -- -- 585
-------- -------- ------- ----- ----- -------
121,492 102,411 53,738 493 (493) 53,738
-------- -------- ------- ----- ----- -------
Expenses
Plant operations (Note
7)..................... 11,763 11,329 13,298 -- -- 13,298
Royalty expense (Note
5)..................... 11,059 9,849 7,317 -- (493) 6,824
Depreciation and
amortization........... 13,325 12,814 11,124 648 -- 11,772
Interest expense........ 8,868 6,260 4,333 -- -- 4,333
-------- -------- ------- ----- ----- -------
45,015 40,252 36,072 648 (493) 36,227
-------- -------- ------- ----- ----- -------
Income (loss) before
cumulative
effect of accounting
change................. 76,477 62,159 17,666 (155) -- 17,511
Cumulative effect of
accounting change (Note
2)..................... -- -- (923) -- -- (923)
-------- -------- ------- ----- ----- -------
Net income (loss)....... $ 76,477 $ 62,159 $16,743 $(155) $ -- $16,588
======== ======== ======= ===== ===== =======
The accompanying notes are an integral part of the combining and combined
financial statements.
F-7
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
COMBINING AND COMBINED STATEMENTS OF PARTNERS' CAPITAL
(Dollars in thousands)
Coso Finance Partners Coso Finance Partners II
---------------------------------- ---------------------------------
China Lake
ESCA China Lake ESCA II Geothermal
Limited Operating Limited Management
Partnership Company, Inc. Total Partnership Company, Inc. Total Combined
Balance at December 31,
1995................... $ 74,985 $ 69,251 $144,236 $11,000 $9,345 $20,345 $164,581
Net income.............. 40,790 35,311 76,101 202 174 376 76,477
Distributions to
partners(1)............ (39,249) (33,975) (73,224) -- -- -- (73,224)
-------- -------- -------- ------- ------ ------- --------
Balance at December 31,
1996................... 76,526 70,587 147,113 11,202 9,519 20,721 167,834
Net income.............. 33,222 28,760 61,982 95 82 177 62,159
Distributions to
partners(1)............ (39,892) (34,533) (74,425) -- -- -- (74,425)
-------- -------- -------- ------- ------ ------- --------
Balance at December 31,
1997................... 69,856 64,814 134,670 11,297 9,601 20,898 155,568
Net income (loss)....... 8,974 7,769 16,743 (83) (72) (155) 16,588
Distributions to
partners............... (11,912) (10,311) (22,223) -- -- -- (22,223)
-------- -------- -------- ------- ------ ------- --------
Balance at December 31,
1998................... $ 66,918 $ 62,272 $129,190 $11,214 $9,529 $20,743 $149,933
======== ======== ======== ======= ====== ======= ========
- ---------------------
(1) Distributions of $14,394 to ESCA Limited Partnership and $12,461 to China
Lake Operating Company, Inc. were declared and paid on January 2, 1996.
Distributions of $16,761 to ESCA Limited Partnership and $14,509 to China
Lake Operating Company, Inc. were declared on December 31, 1996 and paid
on December 31, 1996 and January 2, 1997, respectively.
The accompanying notes are in integral part of the combining and combined
financial statements.
F-8
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
COMBINING AND COMBINED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
For the years ended
December 31, For the year ended December 31, 1998
-------------------- -------------------------------------------
Coso
1996 1997 Finance Coso Finance
Combined Combined Partners Partners II Combined
Cash flows from
operating activities
Net income............. $ 76,477 $ 62,159 $ 16,743 $ (155) $ 16,588
Adjustments to
reconcile net income
to net cash flows from
operating activities:
Depreciation and
amortization........ 13,325 12,814 11,124 648 11,772
Amortization of
deferred financing
costs............... 287 190 123 -- 123
Cumulative effect of
accounting change... -- -- 923 -- 923
Additional advances
to China Lake Plant
Services, Inc....... (201) (239) (172) -- (172)
Decrease (increase)
in accounts
receivable.......... (679) 13,987 (1,170) -- (1,170)
Decrease (increase)
in prepaid expenses
and other assets.... (738) 476 437 -- 437
Increase (decrease)
in accounts payable
and accrued
liabilities......... (3,705) 2,346 3,233 -- 3,233
Decrease (increase)
in amounts due from
related parties,
net................. (987) (3,193) 922 (493) 429
--------- --------- ------------- ---------- -------------
Net cash flows from
operating
activities........ 83,779 88,540 32,163 -- 32,163
--------- --------- ------------- ---------- -------------
Cash flows from
investing activities
Additions to power
plant and transmission
line.................. (499) (736) (266) -- (266)
Additions to wells and
resource development
costs................. (1,795) (3,853) (6,417) -- (6,417)
Decrease (increase) in
restricted cash....... (855) 22,537 (1,045) -- (1,045)
--------- --------- ------------- ---------- -------------
Net cash flows from
investing
activities........ (3,149) 17,948 (7,728) -- (7,728)
--------- --------- ------------- ---------- -------------
Cash flows from
financing activities
Distributions to
partners.............. (58,715) (88,934) (22,223) -- (22,223)
Repayment of project
financing loans....... (51,284) (30,390) (5,100) -- (5,100)
--------- --------- ------------- ---------- -------------
Net cash flows from
financing
activities........ (109,999) (119,324) (27,323) -- (27,323)
--------- --------- ------------- ---------- -------------
Net change in cash..... (29,369) (12,836) (2,888) -- (2,888)
Cash at beginning of
year.................. 45,093 15,724 2,888 -- 2,888
--------- --------- ------------- ---------- -------------
Cash at end of year.... $ 15,724 $ 2,888 $ -- $ -- $ --
========= ========= ============= ========== =============
Supplemental cash flow
disclosure
Interest paid.......... $ 13,849 $ 6,070 $ 4,210 $ -- $ 4,210
The accompanying notes are an integral part of the combining and combined
financial statements.
F-9
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO COMBINING AND COMBINED FINANCIAL STATEMENTS
(Dollars in thousands)
1. The Partnership and Business of Coso Finance Partners and Coso Finance
Partners II
Coso Finance Partners (CFP or the Partnership) and Coso Finance Partners II
(CFP II) were formed on July 7, 1987, in connection with refinancing the
construction of a 30 net megawatt (NMW) geothermal power plant constructed on
behalf of China Lake Joint Venture (CLJV) on land at the China Lake Naval Air
Weapons Station, Coso Hot Springs, China Lake, California, and financing the
expansion of that power plant from 30 net megawatt (NMW) to approximately
80NMW. CFP and CFP II (collectively, the Partnerships) are general partnerships
between China Lake Operating Company (CLOC), a Delaware corporation, and ESCA
Limited Partnership (ESCA), and China Lake Geothermal Management Company
(CLGMC), a Delaware corporation, and ESCA II Limited Partnership (ESCA II),
respectively. ESCA is a California limited partnership between Caithness
Geothermal 1980, Ltd., Caithness Power, L.L.C., and ESI Geothermal, Inc. (a
subsidiary of FPL Group, Inc.). ESCA II is a California limited partnership
between Caithness Geothermal 1980, Ltd., Mojave Power II, Inc. and ESI
Geothermal II, Inc. (a subsidiary of FPL Group, Inc.).
CFP was formed to acquire the assets and assume the liabilities of CLJV
insofar as they related to the first turbine generator set of the power plant
and the related geothermal resources. CFP II acquired the assets and assumed
the liabilities of CLJV insofar as they related to the second and third turbine
generator sets together with the related geothermal resources. The three
turbine generators that comprise the power plant have the capacity to produce
an aggregate of approximately 80NMW. CFP and CFP II were formed as separate
entities in order to facilitate bank financing of the completed power plant and
power plants under construction, respectively. In 1988, CFP II assigned its
assets and liabilities to CFP in exchange for a royalty of 5% of the value of
the steam produced. The "Transfer to/from related party" in the combined and
individual balance sheets represents the unamortized book value of development
costs incurred by CFP II. Such amounts are being amortized by both parties over
30 years on a straight line basis.
The Partnerships sell all electricity produced to Southern California Edison
(Edison) under a 24-year power purchase contract expiring in 2011. Under the
terms of this contract, Edison makes payments to CFP as follows:
. Contractual payments for energy delivered, which payments escalate at an
average rate of approximately 7.6% for the first ten years after the date
of firm operation (scheduled energy price period). After the scheduled
energy price period for each unit, the energy payment adjusts to the
actual avoided energy cost experienced by Edison. In August 1997, the
initial unit of the Partnerships completed the ten-year period. At that
time, Edison ceased paying the scheduled energy rates for all three
units. CFP is currently in litigation over this issue (see Note 8). For
the years ended December 31, 1997 and 1998, Edison's average avoided cost
of energy was 3.28 and 2.95 cents per kwh, respectively. Estimates of
Edison's future avoided cost of energy vary substantially from year to
year. The Partnerships cannot predict the likely level of avoided cost of
energy prices under the 24-year power purchase contract and, accordingly,
the revenues generated by the Partnerships could fluctuate significantly;
. Capacity payments which remain fixed over the life of the contract to the
extent that actual energy delivered exceeds minimum levels of the plant
capacity defined in the contract; and
F-10
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO COMBINING AND COMBINED FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
. Bonus payments to the extent that actual energy delivered exceeds 85% of
the plant capacity stated in the contract. In 1996, 1997 and 1998, the
bonus payments aggregated $2,266, $1,805 and $1,510, respectively.
CalEnergy Company, Inc. (CalEnergy) served as the operator, maintaining the
Partnerships' accounting records and operating the CFP plant on a day-to-day
basis, until February 1, 1999 when Coso Operating Company LLC (COC), a Delaware
limited liability company, became operator pursuant to certain operations and
maintenance agreements with CLOC, the managing general partner (see Note 9).
COC and CLOC are wholly-owned subsidiaries of CalEnergy.
At formation, and as amended, the terms of the partnership agreements
provided that distributable cash flow before "payout" was allocated 10% to CLOC
as managing partner and 90% in proportion to the remaining sums necessary to be
distributed to each partner to achieve payout. "Payout" occurred in June 1996
and was defined as the point at which each partner had received aggregate cash
distributions from the 90% allocation in amounts equal to their accumulated
cash contributions plus amounts equal to 10% simple interest on the cash
contributions. For purposes of allocating net income to partners' capital
accounts, profits and losses are allocated based on the aforementioned
percentages. For income tax purposes, certain deductions and credits are
subject to special allocations as defined in the partnership agreements. Cash
flow after "payout" is allocated 53.6% and 46.4% to ESCA/ESCA II and
CLOC/CLGMC, respectively.
Since the Partnerships operate under common ownership and management control,
the financial statements of the Partnerships have been combined after
elimination of intercompany amounts.
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
2. Summary of Significant Accounting Policies
Recognition of Revenue
Operating revenues are recognized as income during the period in which
electricity is delivered to Edison. Revenue was recognized based on the payment
rates scheduled in CFP's power purchase contract with Edison until August 1997.
After August 1997, revenue is recognized based on Edison's avoided energy cost.
Fixed Assets and Depreciation
The costs of major additions and betterments are capitalized, while
replacements, maintenance and repairs which do not improve or extend the life
of the respective assets are expensed currently.
Depreciation of the operating power plant and transmission line is computed
on the straight line method over their estimated useful life of 30 years and,
for significant additions, the remainder of the 30-year life from the plant's
commencement of operations.
F-11
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO COMBINING AND COMBINED FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
The Partnerships review long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. An impairment loss would be recognized whenever evidence exists
that the carrying value is not recoverable.
In April 1998, the Accounting Standards Executive Committee issued Statement
of Position (SOP) No. 98-5, "Reporting on the Costs of Start-Up Activities."
SOP No. 98-5 requires that, at the effective date of adoption, costs of start-
up activities previously capitalized be expensed and reported as a cumulative
effect of a change in accounting principle, and further requires that such
costs subsequent to adoption be expensed as incurred. CFP adopted this standard
in 1998 and expensed applicable unamortized costs previously capitalized in
connection with the start-up of CFP. The cumulative effect of the change in
accounting principle was $923.
Wells and Resource Development Costs
The Partnerships follow the full cost method of accounting for costs incurred
in connection with the exploration and development of geothermal resources. All
such costs, which include dry hole costs, the cost of drilling and equipping
production wells, and administrative and interest costs directly attributable
to the project, are capitalized and amortized over their estimated useful lives
when production commences. The estimated useful lives of production wells are
ten years each; exploration costs and development costs, other than production
wells, are amortized over 30 years and, for significant additions, the
remainder of the 30-year life from the plant's commencement of operations.
Deferred Well Rework Costs
Well rework costs are deferred and amortized over the estimated period
between reworks. These deferred costs of $57 and $9 at December 31, 1997 and
1998, respectively, are included in prepaid expenses and other assets.
Currently, both production and injection rework costs are amortized over twelve
months.
Deferred Plant Overhaul Costs
Plant overhaul costs are deferred and amortized over the estimated period
between overhauls. These deferred costs of $296 and $109 at December 31, 1997
and 1998, respectively, are included in prepaid expenses and other assets.
Currently, plant overhauls are amortized over three to four years from the
point of completion.
Advances to China Lake Plant Services, Inc.
China Lake Plant Services, Inc. (CLPSI) is a wholly-owned subsidiary of
CalEnergy. CLPSI purchases, stores and distributes spare parts to CFP and two
other affiliated operating ventures. Also, certain other facilities utilized by
all three operating ventures are held by CLPSI. CFP's advances to CLPSI
represent funds advanced for the purchase of spare parts inventory and other
assets. Spare parts inventory held by CLPSI on behalf of CFP is valued at the
lower of cost or market.
F-12
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO COMBINING AND COMBINED FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
Deferred Financing Costs
Deferred financing costs consist of loan fees and are amortized over the term
of the related financing using the effective interest method. Accumulated
amortization at December 31, 1997 and 1998 was $1,795 and $1,918, respectively.
Income Taxes
There is no provision for income taxes since those taxes are the
responsibility of the partners.
Restricted Cash and Investments
As of December 31, 1997 and 1998, all of the Partnerships' investments were
classified as held-to-maturity and reported at amortized cost. The restricted
cash and investments balance represents primarily a sinking fund related to a
lump sum royalty payment of $25,000 to be paid to the Navy in 2009 (see Note
5). This account is comprised of various mortgage-backed securities with
maturities ranging from 1999 through 2005. The carrying amount of restricted
cash and investments at December 31, 1997 and 1998 approximated fair value,
which is based on quoted market prices as provided by the financial institution
which holds the investments. Also included in restricted cash are various Bank
of America certificates of deposits totaling $142 at both December 31, 1997 and
1998. These deposits have maturities of greater than three months.
Cash Flows
For purposes of the combined statements of cash flows, the Partnerships
consider all money market instruments purchased with an initial maturity of
three months or less to be cash equivalents.
3. Interest Rate Swap Agreement
In January 1993, CFP entered into a five-year deposit interest rate swap
agreement which, until certain investments were liquidated in February 1997
(see Note 6), effectively converted notional deposit balances from a variable
rate to a fixed rate. Under the agreement, which matured on January 11, 1998,
CFP made payments to the counterparty each January 11 and July 11 at variable
rates based on LIBOR, reset and compounded every three months, and in return
received payments based on a fixed rate of 6.34%. The effective LIBOR rate
ranged from 5.5313% to 5.8125% during 1997 and was 5.7500% at December 31, 1997
and at January 11, 1998, the termination date. The counterparty to this
agreement was a large international financial institution. The carrying amount
of the interest rate swap at December 31, 1997, was $50 (payable to CFP), which
approximated its fair value. The fair value was based on the estimated amount
that CFP would have received to terminate the swap agreement at that date as
provided by the financial institution which was the counterparty to the swap.
F-13
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO COMBINING AND COMBINED FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
4. Property, Plant and Equipment
Property, plant and equipment are comprised of the following:
December 31,
--------------------
1997 1998
Power plant and gathering system..................... $ 175,024 $ 173,927
Transmission line.................................... 6,515 6,515
Wells and resource development costs................. 112,057 118,474
--------- ---------
293,596 298,916
Less accumulated amortization and depreciation....... (107,204) (118,536)
--------- ---------
$ 186,392 $ 180,380
========= =========
5. Royalty Expense
Royalty expense is summarized as follows:
1996 1997 1998
Unit 1............................................... $ 3,269 $3,437 $3,114
Units 2 and 3........................................ 7,790 6,412 3,710
------- ------ ------
$11,059 $9,849 $6,824
======= ====== ======
The power plant is located on land owned by the U.S. Navy. Under the terms of
a 30-year contract with the U.S. Navy to develop geothermal energy on its
lands, for the first turbine only, CFP pays the Navy's monthly Edison bill for
specified quantities of electricity and, in return, is reimbursed at a set rate
for such quantities of electricity. During 1996, 1997 and 1998, CFP was
reimbursed for approximately 76%, 75% and 76%, respectively, of the amount of
the Navy's Edison bills paid by CFP. The fee payable for the second and third
turbines increased from 10% of related revenues to 15% in December 1998 and
will increase to 20% in December 2003.
In addition, CFP is required to pay the Navy $25,000 in December 2009, the
date the contract expires. The payment is secured by funds placed on deposit
monthly, which funds plus accrued interest will aggregate $25,000. Currently,
the monthly amount to be deposited is $50.
6. Project Loan
The project loan is as follows:
December 31,
---------------
1997 1998
Project loan with a weighted average interest rate of
8.76% and 8.79%, respectively, at December 31, 1997 and
1998 with scheduled repayments through December 2001.... $45,666 $40,566
The project loan is a loan from Coso Funding Corp. (Funding Corp.). Funding
Corp. is a single-purpose corporation formed to issue notes for its own account
and as an agent acting on behalf of
F-14
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO COMBINING AND COMBINED FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
CFP, Coso Energy Developers (CED) and Coso Power Developers (CPD), collectively
the "Joint Ventures." Pursuant to separate credit agreements executed between
Funding Corp. and each joint venture on December 16, 1992, the proceeds from
Funding Corp.'s note offering were loaned to the Joint Ventures.
The CFP project loan is collateralized by, among other things, the power
plant, geothermal resource, letters of credit, pledge of contracts and an
assignment of all Joint Ventures' revenues which will be applied against the
payment of obligations of each joint venture, including the project loans. Each
joint venture's assets collateralize only its own project loan, and are not
cross-collateralized with assets pledged under other joint ventures' credit
agreements. The project loan is non-recourse to any partner in CFP and Funding
Corp. shall solely look to such Partnership's pledged assets for satisfaction
of such project loan. However, the Partnership, after satisfying a series of
its own obligations, has agreed to advance support loans to the extent of its
available cash flow and, under certain conditions its letters of credit, to CED
or CPD in the event such other joint venture's revenues are insufficient to
meet scheduled principal and interest on its separate project loan from Funding
Corp.
Until February 1997 the Partnership maintained a debt service fund which was
legally restricted as to its use and which required the maintenance of a
specific balance. The fund, comprised of investments of U.S. government and
corporate debt and various mortgage-backed securities with maturities from 1997
through 2024, was required by the terms and conditions of the project financing
and was maintained by First Trust of California in its capacity as the trustee
for the project lender. The securities comprising the fund were categorized as
held-to-maturity and valued at amortized cost. In February 1997 the project
lenders allowed the Partnership to replace the cash and investment balance in
the debt service fund with irrevocable letters of credit. The fund was then
liquidated and the resulting proceeds were distributed. Proceeds from the sale
of these securities approximated their carrying value plus interest accrued
through the date of sale.
The annual project loan repayments are summarized as follows:
1999.............................................................. $ 9,784
2000.............................................................. 4,267
2001.............................................................. 26,515
-------
$40,566
=======
Based on quoted market rates of the Funding Corp. notes, the fair value of
the project loan as of December 31, 1997 and 1998 was approximately $49,130 and
$43,063, respectively.
F-15
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO COMBINING AND COMBINED FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
7. Related Party Transactions
CalEnergy, as operator, is reimbursed monthly for non-third-party costs
incurred on behalf of CFP. These costs are comprised principally of approved
direct CalEnergy operating costs of the CFP geothermal facility, allocable
general and administration costs, and operator fees and were as follows:
1996 1997 1998
Operating costs...................................... $2,943 $3,192 $2,748
General and administration costs..................... 1,702 1,702 1,742
Operator fees........................................ 491 491 420
Both CalEnergy and ESCA are reimbursed at approved amounts for their
respective costs incurred in relation to the CFP Management Committee. The
management committee fees paid were:
1996 1997 1998
ESCA........................................................ $214 $214 $221
CalEnergy................................................... 143 143 147
CFP is charged by CLPSI for both its inventory usage and its portion of the
expenses of operating CLPSI. The charges to CFP from CLPSI in 1996, 1997 and
1998 were approximately $421, $486 and $532, respectively.
During 1994, the Joint Ventures entered into steam sharing agreements under
which the ventures may transfer steam, with the resulting incremental revenue
and royalty expense shared equally by the ventures. In the second half of 1995,
interconnection facilities between the plants were completed and the transfer
of steam commenced. CFP steam sharing revenue, net of royalties and other
related costs, amounted to $4,898, $10,345 and $17,556 in 1996, 1997 and 1998,
respectively.
The amounts due to (from) related parties as of December 31, 1997 and 1998
consist of the following:
December 31,
----------------
1997 1998
Due (from) to CalEnergy................................. $ (7) $ 378
Due from CPD for steam sharing.......................... (1,704) (1,902)
Due from CED for steam sharing.......................... (2,500) (2,258)
------- -------
$(4,211) $(3,782)
======= =======
The December 31, 1997 and 1998 due (from) to CalEnergy balances relate to the
venture reimbursing CalEnergy for the costs of operating the plant. This amount
fluctuated in concert with the timing of billings and incurring of costs.
In addition, as of December 31, 1997 and 1998 the accrued unpaid royalty due
to CFP II from CFP aggregated $8,255 and $8,748, respectively.
F-16
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO COMBINING AND COMBINED FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
8. Commitments and Contingencies
On June 9, 1997, Edison filed a complaint alleging breach of the power
purchase agreements (SO4 Agreements) between Edison and the Joint Ventures as a
result of alleged improper venting of certain noncondensible gases at the Coso
geothermal energy project. In the complaint, Edison seeks unspecified damages,
including the refund of certain amounts previously paid under the SO4
Agreements, and termination of the SO4 Agreements. In September 1997, the Joint
Ventures and CalEnergy filed a cross-complaint against Edison and its
affiliates, The Mission Group and Mission Power Engineering Company, alleging,
among other things, that Edison's lawsuit violates the 1993 settlement
agreement which settled certain litigation arising from the construction of
certain units at the Coso geothermal project by Edison affiliates. In addition,
the Joint Ventures filed a separate complaint against Edison alleging breach of
the SO4 Agreements, unfair business practices, slander and various other tort
and contract claims. The actions were effectively consolidated in December
1997. As a result of certain procedural actions by the parties and a November
1997 court order, Edison filed an amended complaint on December 16, 1997 and
the Joint Ventures amended their cross-complaint. In addition, the court has
struck Edison's request to terminate the SO4 Agreements and obtain a refund of
all funds paid to the Joint Ventures. The litigation is in its early procedural
stages and the pleadings have not been settled. The Joint Ventures believe that
its claims and defenses are meritorious and that they will prevail if the
matter is ultimately heard on its merits. The Joint Ventures intend to
vigorously defend this action and prosecute all available conterclaims against
Edison.
9. Subsequent Event
On January 25, 1999, CalEnergy agreed to sell its indirect interests in CFP
and CFP II to Caithness Acquisition Company LLC (Caithness), an affiliate of
ESCA and ESCA II. Upon completion of the sale, COC, Caithness or its designee
will become the operator of CFP and CFP II.
F-17
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners of Coso Energy Developers
In our opinion, the accompanying balance sheets and the related statements of
operations, of partners' capital and of cash flows present fairly, in all
material respects, the financial position of Coso Energy Developers at December
31, 1997 and 1998, and the results of its operations and its cash flows for
each of the three years in the period ended December 31, 1998, in conformity
with generally accepted accounting principles. These financial statements are
the responsibility of the Partnership's management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with generally accepted
auditing standards which require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management,
and evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for the opinion expressed above.
As discussed in Note 2 to the financial statements, the Partnership adopted
in 1998 Statement of Position No. 98-5, "Reporting on the Costs of Start-Up
Activities."
/s/ PricewaterhouseCoopers LLP
San Francisco, California
February 12, 1999
F-18
COSO ENERGY DEVELOPERS
BALANCE SHEETS
(Dollars in thousands)
December 31,
-----------------
1997 1998
Assets
Cash......................................................... $ 873 $ --
Restricted cash and investments (Note 5)..................... 290 290
Accounts receivable.......................................... 18,763 19,835
Prepaid expenses and other assets............................ 1,518 1,526
Property, plant and equipment, net (Note 4).................. 197,709 201,600
Investment in Coso Transmission Line Partners................ 3,222 3,107
Advances to China Lake Plant Services, Inc................... 2,213 1,567
Deferred financing costs, net................................ 324 162
-------- --------
$224,912 $228,087
======== ========
Liabilities and Partners' Capital
Accounts payable and accrued liabilities..................... $ 3,563 $ 3,314
Amounts due to related parties, net (Note 6)................. 20,582 23,624
Project loan (Note 5)........................................ 76,654 37,958
-------- --------
100,799 64,896
Partners' capital............................................ 124,113 163,191
-------- --------
$224,912 $228,087
======== ========
The accompanying notes are an integral part of these financial statements.
F-19
COSO ENERGY DEVELOPERS
STATEMENTS OF OPERATIONS
(Dollars in thousands)
For the years ended
December 31,
--------------------------
1996 1997 1998
Revenue
Sales of electricity.............................. $101,923 $102,868 $107,199
Interest and other income......................... 2,520 1,712 1,181
-------- -------- --------
104,443 104,580 108,380
-------- -------- --------
Expenses
Plant operations (Note 6)......................... 18,266 18,830 19,887
Royalty expense (Note 6).......................... 7,820 10,106 10,492
Depreciation and amortization..................... 13,931 14,257 14,308
Interest expense.................................. 13,162 9,105 6,267
-------- -------- --------
53,179 52,298 50,954
-------- -------- --------
Income before cumulative effect of accounting
change........................................... 51,264 52,282 57,426
Cumulative effect of accounting change (Note 2)... -- -- (953)
-------- -------- --------
Net income........................................ $ 51,264 $ 52,282 $ 56,473
======== ======== ========
The accompanying notes are an integral part of these financial statements.
F-20
COSO ENERGY DEVELOPERS
STATEMENTS OF PARTNERS' CAPITAL
(Dollars in thousands)
Caithness Coso
Coso Hotsprings
Holdings, Intermountain
L.P. Power, Inc. Total
Balance, December 31, 1995................... $ 65,208 $ 54,352 $119,560
Distributions to partners(1)................. (30,242) (27,916) (58,158)
Net income................................... 26,657 24,607 51,264
-------- -------- --------
Balance, December 31, 1996................... 61,623 51,043 112,666
Distributions to partners(1)................. (21,234) (19,601) (40,835)
Net income................................... 27,187 25,095 52,282
-------- -------- --------
Balance, December 31, 1997................... 67,576 56,537 124,113
Distributions to partners.................... (9,046) (8,349) (17,395)
Net income................................... 29,366 27,107 56,473
-------- -------- --------
Balance, December 31, 1998................... $ 87,896 $ 75,295 $163,191
======== ======== ========
- ---------------------
(1) Distributions of $12,793 to Caithness Coso Holdings, L.P. and $11,808 to
Coso Hotsprings Intermountain Power, Inc. were declared and paid on January
2, 1996. Distributions of $13,332 to Caithness Coso Holdings, L.P. and
$12,307 to Coso Hotsprings Intermountain Power, Inc. were declared on
December 31, 1996 and paid on December 31, 1996 and January 2, 1997,
respectively.
The accompanying notes are an integral part of these financial statements.
F-21
COSO ENERGY DEVELOPERS
STATEMENTS OF CASH FLOWS
(Dollars in thousands)
For the years ended
December 31,
----------------------------
1996 1997 1998
Cash flows from operating activities
Net income...................................... $ 51,264 $ 52,282 $ 56,473
Adjustments to reconcile net income to net cash
flows from operating activities:
Depreciation and amortization................. 13,931 14,257 14,308
Amortization of deferred financing costs...... 296 240 160
Cumulative effect of accounting change........ -- -- 953
Equity in losses of Coso Transmission Line
Partners..................................... 113 111 115
Additional charges from (advances to) China
Lake Plant Services, Inc. ................... 404 (57) 646
Increase in accounts receivable, prepaid
expenses and other assets.................... (212) (1,718) (1,080)
Increase (decrease) in accounts payable and
accrued liabilities.......................... (6,355) 853 903
Increase (decrease) in amounts due to related
parties...................................... 4,894 (5,020) 3,042
-------- -------- --------
Net cash flows from operating activities.... 64,335 60,948 75,520
-------- -------- --------
Cash flows from investing activities
Additions to power plant and transmission line.. (669) (2,196) (3,460)
Additions to wells and resource development
costs.......................................... (5,364) (1,532) (16,842)
Decrease in restricted cash..................... 235 23,008 --
-------- -------- --------
Net cash flows from investing activities.... (5,798) 19,280 (20,302)
-------- -------- --------
Cash flows from financing activities
Repayment of CalEnergy promissory note.......... (7,981) (10,043) --
Distributions to partners....................... (45,851) (53,142) (17,395)
Repayment of project financing loans............ (31,758) (29,336) (38,696)
-------- -------- --------
Net cash flows from financing activities.... (85,590) (92,521) (56,091)
-------- -------- --------
Net change in cash.............................. (27,053) (12,293) (873)
Cash at beginning of year....................... 40,219 13,166 873
-------- -------- --------
Cash at end of year............................. $ 13,166 $ 873 $ --
======== ======== ========
Supplemental cash flow disclosure
Interest paid................................... $ 15,991 $ 19,570 $ 6,105
The accompanying notes are an integral part of these financial statements.
F-22
COSO ENERGY DEVELOPERS
NOTES TO FINANCIAL STATEMENTS
(Dollars in thousands)
1. The Partnership and Business of Coso Energy Developers
Coso Energy Developers (CED or Partnership) was formed on March 31, 1988, in
connection with financing the construction of a geothermal power plant on land
leased from the U.S. Bureau of Land Management (BLM) at Coso Hot Springs, China
Lake, California. CED is a general partnership between Coso Hotsprings
Intermountain Power, Inc. (CHIP), a Delaware corporation, and Caithness Coso
Holdings, L.P. (CCH). CCH is a California general partnership.
The primary BLM geothermal lease has a primary term of 10 years (1998) and
thereafter is subject to automatic extension until October 31, 2035, so long as
geothermal steam is commercially produced. In addition, the lease may be
extended to 2075 at the option of the BLM. The BLM is paid a royalty of 10% of
the value of steam produced. Coso Land Company (CLC), the original leaseholder,
retained a 5% overriding royalty interest based on the value of the steam
produced. CLC is a joint venture between CalEnergy Company, Inc. (CalEnergy)
and an affiliate of CCH.
The Partnership sells all electricity produced to Southern California Edison
(Edison) under a 30-year power purchase contract which expires in 2019. Under
the terms of the contract, Edison makes payments to CED as follows:
. Contractual payments for energy delivered, which payments escalate at an
average rate of approximately 7.6% for the first ten years after the date
of firm operation (scheduled energy price period). The scheduled energy
price period for each unit extends until at least March 1999, after which
the energy payment for at least Unit 4 adjusts to the actual avoided
energy cost experienced by Edison at that time. For the year ended
December 31, 1998, Edison's average avoided cost of energy was 2.95 cents
per kwh which is substantially below the contract energy prices earned
for the year ended December 31, 1998. Estimates of Edison's future
avoided cost of energy vary substantially from year to year. The
Partnership cannot predict the likely level of avoided cost of energy
prices under the 30-year power purchase contract at the expiration of the
scheduled energy price period. The revenues generated by the Partnership
could decline significantly after the expiration of the scheduled energy
price period;
. Capacity payments which remain fixed over the life of the contract to the
extent that actual energy delivered exceeds minimum levels of the plant
capacity defined in the contract; and
. Bonus payments to the extent that actual energy delivered exceeds 85% of
the plant capacity stated in the contract. In 1996, 1997, and 1998, the
bonus payments aggregated $2,228, $2,177 and $2,124, respectively.
CalEnergy served as the operator, maintaining the Partnership's accounting
records and operating the CED plant on a day-to-day basis, until February 1,
1999, when Coso Operating Company LLC (COC), a Delaware limited liability
company, became the operator pursuant to certain operations and maintenance
agreements with CHIP, the managing general partner of CED (see Note 8). COC and
CHIP or wholly owned subsidiaries of CalEnergy.
At formation, and as subsequently amended, the partnership agreement provided
that distributable cash flow before "payout" was allocated 3.81% to CHIP as
managing partner and
F-23
COSO ENERGY DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
96.19% allocated in proportion to the remaining sums necessary to be
distributed to each partner to achieve payout. "Payout" was defined as the
point at which each partner had received aggregate cash distributions from the
96.19% allocation in amounts equal to their accumulated capital contributions.
Cash flow after "payout," which occurred in June 1994, is allocated 48% to CHIP
and 52% to CCH. For purposes of allocating net income to partners' capital
accounts, profits and losses are allocated based on the aforementioned capital
percentages. For income tax purposes, certain deductions and credits are
subject to special allocations as defined in the partnership agreement.
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
2. Summary of Significant Accounting Policies
Recognition of Revenue
Operating revenues are recognized as income during the period in which
electricity is delivered to Edison. Revenue is recognized based on the payment
rates scheduled in CED's power purchase contract with Edison.
Fixed Assets and Depreciation
The costs of major additions and betterments are capitalized, while
replacements, maintenance and repairs which do not improve or extend the life
of the respective assets are expensed currently.
Depreciation of the power plant and transmission line is computed on the
straight line method over their estimated useful life of 30 years and, for
significant additions, the remainder of the 30-year life from the plant's
commencement of operations.
The Partnership reviews long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. An impairment loss would be recognized whenever evidence exists
that the carrying value is not recoverable.
In April 1998, the Accounting Standards Executive Committee issued Statement
of Position (SOP) No. 98-5, "Reporting on the Costs of Start-up Activities."
SOP No. 98-5 requires that, at the effective date of adoption, costs of start-
up activities previously capitalized be expensed and reported as a cumulative
effect of a change in accounting principle, and further requires that such
costs subsequent to adoption be expensed as incurred. CED adopted this standard
in 1998 and expensed applicable unamortized costs previously capitalized in
connection with the start-up of CED. The cumulative effect of the change in
accounting principle was $953.
Wells and Resource Development Costs
CED follows the full cost method of accounting for costs incurred in
connection with the exploration and development of geothermal resources. All
such costs, which include dry hole costs,
F-24
COSO ENERGY DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
the cost of drilling and equipping production wells, and administrative and
interest costs directly attributable to the project are capitalized and
amortized over their estimated useful lives when production commences. The
estimated useful lives of production wells are ten years each; exploration
costs and development costs, other than production wells, are amortized over 30
years and, for significant additions, the remainder of the 30-year life from
the plant's commencement of operations.
Deferred Well Rework Costs
Well rework costs are deferred and amortized over the estimated period
between reworks. These deferred costs of $399 and $669 at December 31, 1997 and
1998, respectively, are included in prepaid expenses and other assets.
Currently, both production and injection rework costs are amortized over twelve
months.
Deferred Plant Overhaul Costs
Plant overhaul costs are deferred and amortized over the estimated period
between overhauls. These deferred costs of $537 and $502 at December 31, 1997
and 1998, respectively, are included in prepaid expenses and other assets.
Currently, plant overhauls are amortized over three years from the point of
completion.
Investment in Coso Transmission Line Partners
Coso Transmission Line Partners (CTLP) is a partnership, between CED and Coso
Power Developers (CPD), which owns the transmission line and facilities
connecting the power plants owned by CED and CPD to the transmission line,
owned by Edison, at Inyokern, California, located 28 miles south of the plants.
CTLP charges CED and CPD for the use of the transmission line. These charges
are recorded by CED as operating expenses and reflected as a reduction in CED's
investment in CTLP.
Advances to China Lake Plant Services, Inc.
China Lake Plant Services, Inc. (CLPSI) is a wholly-owned subsidiary of
CalEnergy. CLPSI purchases, stores and distributes spare parts to CED and two
other affiliated operating ventures. Also, certain other facilities utilized by
all three operating ventures are held by CLPSI. CED's advances to CLPSI
represent funds advanced for the purchase of spare parts inventory and other
assets. Spare parts inventory held by CLPSI on behalf of CED is valued at the
lower of cost or market.
Deferred Financing Costs
Deferred financing costs consist of loan fees and are amortized over the term
of the related financing using the effective interest method. Accumulated
amortization at December 31, 1997 and 1998 was $1,685 and $1,845, respectively.
Income Taxes
There is no provision for income taxes since those taxes are the
responsibility of the partners.
F-25
COSO ENERGY DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
Restricted Cash and Investments
As of December 31, 1997 and 1998, all of the Partnership's investments were
classified as held-to-maturity and reported at amortized cost. Included in
restricted cash are various Bank of America certificates of deposit totaling
$290 at December 31, 1997 and 1998. These deposits have maturities of greater
than three months.
Cash Flows
For purposes of the statements of cash flows, CED considers all money market
instruments purchased with an initial maturity of three months or less to be
cash equivalents.
3. Interest Rate Swap Agreement
In January 1993, CED entered into a five-year deposit interest rate swap
agreement which, until certain investments were liquidated in February 1997
(see Note 5), effectively converted notional deposit balances from a variable
rate to a fixed rate. Under the agreement, which matured on January 11, 1998,
CED made payments to the counterparty each January 11 and July 11 at variable
rates based on LIBOR, reset and compounded every three months, and in return
received payments based on a fixed rate of 6.34%. The effective LIBOR rate
ranged from 5.5313% to 5.8125% during 1997 and was 5.7500% at December 31, 1997
and at January 11, 1998, the termination date. The counterparty to this
agreement was a large international financial institution. The carrying amount
of the interest rate swap at December 31, 1997, was $42 (payable to CED), which
approximated its fair value. The fair value was based on the estimated amount
that CED would have received to terminate the swap agreement at that date as
provided by the financial institution which was the counterparty to the swap.
4. Property, Plant and Equipment
Property, plant and equipment are comprised of the following:
December 31,
-------------------
1997 1998
Power plant and gathering system...................... $162,372 $ 164,335
Transmission line..................................... 11,353 10,201
Wells and resource development costs.................. 120,562 137,404
-------- ---------
294,287 311,940
Less accumulated depreciation and amortization........ (96,578) (110,340)
-------- ---------
$197,709 $ 201,600
======== =========
The transmission line costs represent the Partnership's share of the costs of
construction of transmission lines from Inyokern to the Edison substation at
Kramer and from Kramer to the Edison substation at Victorville.
F-26
COSO ENERGY DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
5. Project Loan
The project loan is as follows:
December 31,
---------------
1997 1998
Project loan with a weighted average interest rate of 8.63%
and 8.73%, respectively, at December 31, 1997 and 1998
with scheduled repayments through December 2001........... $76,654 $37,958
The project loan is a loan from Coso Funding Corp. (Funding Corp.). Funding
Corp. is a single-purpose corporation formed to issue notes for its own account
and as an agent acting on behalf of CED, Coso Finance Partners (CFP) and CPD,
collectively the "Partnerships." Pursuant to separate credit agreements
executed between Funding Corp. and each partnership on December 16, 1992, the
proceeds from Funding Corp.'s note offering were loaned to the Partnerships.
The CED project loan is collateralized by, among other things, the power
plant, geothermal resource, letters of credit, pledge of contracts and an
assignment of all Partnerships' revenues which will be applied against the
payment of obligations of each partnership, including the project loans. Each
partnership's assets collateralize only its own project loan, and are not
cross-collateralized with assets pledged under other partnership's credit
agreements. The project loan is non-recourse to any partner in CED and Funding
Corp. shall solely look to such Partnership's pledged assets for satisfaction
of such project loan. However, the Partnership, after satisfying a series of
its own obligations, has agreed to advance support loans to the extent of its
available cash flow and, under certain conditions its letters of credit, to CFP
or CPD in the event such other partnership's revenues are insufficient to meet
scheduled principal and interest on its separate project loan from Funding
Corp.
Until February 1997 the Partnership maintained a debt service fund which was
legally restricted as to its use and which required the maintenance of a
specific balance. The fund, comprised of investments of U.S. government and
corporate debt and various mortgage-backed securities with maturities from 1997
through 2024, was required by the terms and conditions of the project financing
and was maintained by First Trust of California in its capacity as the trustee
for the project lender. The securities comprising the fund were categorized as
held-to-maturity and valued at amortized cost. In February 1997 the project
lenders allowed the Partnership to replace the cash and investment balance in
the debt service fund with irrevocable letters of credit. The fund was then
liquidated and the resulting proceeds were (i) used to retire the promissory
note due CalEnergy and (ii) distributed to the partners. Proceeds from the sale
of these securities approximated their carrying value plus interest accrued
through the date of sale.
The annual project loan repayments are summarized as follows:
1999............................................................... $15,658
2000............................................................... 2,472
2001............................................................... 19,828
-------
$37,958
=======
F-27
COSO ENERGY DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
Based on quoted market rates of the Funding Corp. notes, the fair value of
the project loan as of December 31, 1997 and 1998 was approximately $81,018 and
$39,980, respectively.
6. Related Party Transactions
CalEnergy, as operator, is reimbursed monthly for non-third-party costs
incurred on behalf of CED. These costs are comprised principally of approved
direct CalEnergy operating costs of the CED geothermal facility, allocable
general and administration costs, and operator fees and were as follows:
1996 1997 1998
Operating costs...................................... $4,204 $3,905 $3,728
General and administration costs..................... 2,125 2,125 2,173
Operator fees........................................ 731 731 727
Both CCH and CalEnergy are reimbursed at approved amounts for their
respective costs incurred in relation to the CED Management Committee. The
management committee fees paid were:
1996 1997 1998
CCH......................................................... $222 $218 $223
CalEnergy................................................... 145 145 148
As indicated in Note 1, CLC is entitled to a royalty of 5% of the value of
the steam used by CED to produce the electricity sold to Edison. The royalty
due CLC for the years ended December 31, 1996, 1997 and 1998 was $2,432, $3,176
and $3,057, respectively. This royalty will be paid when CED has repaid its
project loan.
In addition, as described in Note 2, CED is charged for its use of the
transmission line owned by CTLP. The amount of such net charges was $114, $112
and $115 for the years ended December 31, 1996, 1997 and 1998, respectively.
CED is charged by CLPSI for both its inventory usage and its portion of the
expenses of operating CLPSI. The 1996, 1997, and 1998 costs charged to CED from
CLPSI were approximately $974, $606 and $1,350, respectively.
During 1994, the three Coso operating ventures (CED, CPD and CFP) entered
into steam sharing agreements under which the ventures may transfer steam, with
the resulting incremental revenue and royalty expense shared equally by the
ventures. In the second half of 1995, interconnection facilities between the
plants were completed and the transfer of steam commenced. CED steam sharing
revenue, net of royalties and other related costs, amounted to $8,464, $1,584
and $6,430 in 1996, 1997 and 1998, respectively.
F-28
COSO ENERGY DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
The amounts due to (from) related parties at December 31, 1997 and 1998
consist of the following:
December 31,
----------------
1997 1998
Due to CPD for steam sharing............................. $ 561 $ 259
Due to CFP for steam sharing............................. 2,500 2,258
Due to CalEnergy......................................... 121 702
CLC...................................................... 17,660 20,699
Loan to CLC
Principal.............................................. (141) (141)
Accrued interest....................................... (119) (153)
------- -------
$20,582 $23,624
======= =======
On December 16, 1992, CED paid $1,531 of principal and all accrued interest
through December 16, 1992 on the promissory note due CalEnergy. A new
promissory note was then signed on December 16, 1992 for the remaining
principal balance. This note bore a fixed interest rate of 12.5%, compounded
semi-annually, and was payable on or before March 19, 2002. The previous note
was signed March 19, 1991 as a result of the partners' arbitration settlement
and accrued interest at a rate defined as the lowest average interest rate
actually charged by the previous project loan lender on any of the Coso
ventures' debt, which was 5.4% through December 16, 1992. Interest on the note
was $2,659 and $250 in 1996 and 1997, respectively. CED made principal payments
on the note of $7,981 during 1996. In January 1997, CED made a principal
payment of $6,442 from funds provided by the partners and in February 1997, the
note and accrued interest were repaid in full.
Additionally, on December 16, 1992, CED retired CLC's promissory note due
CalEnergy, resulting in the loan from CED to CLC of $141. Interest has been
accrued on this loan at 12.5%. Interest on the note was $26 , $29 and $34 in
1996, 1997 and 1998, respectively.
The December 31, 1997 and 1998 due to CalEnergy balances relate to the
venture reimbursing CalEnergy for the costs of operating the plant. This amount
fluctuated in concert with the timing of billings and incurring of costs.
7. Commitments and Contingencies
On June 9, 1997, Edison filed a complaint alleging breach of the power
purchase agreements (SO4 Agreements) between Edison and the Partnerships as a
result of alleged improper venting of certain noncondensible gases at the Coso
geothermal energy project. In the complaint, Edison seeks unspecified damages,
including the refund of certain amounts previously paid under the SO4
Agreements, and termination of the SO4 Agreements. In September 1997, the
Partnerships and CalEnergy filed a cross-complaint against Edison and its
affiliates, The Mission Group and Mission Power Engineering Company, alleging,
among other things, that Edison's lawsuit violates the 1993 settlement
agreement which settled certain litigation arising from the construction of
certain units at the Coso geothermal project by Edison affiliates. In addition,
the Partnerships filed a separate complaint against Edison alleging breach of
the SO4 Agreements, unfair business practices, slander
F-29
COSO ENERGY DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
and various other tort and contract claims. The actions were effectively
consolidated in December 1997. As a result of certain procedural actions by the
parties and a November 1997 court order, Edison filed an amended complaint on
December 16, 1997 and the Partnerships amended their cross-complaint. In
addition, the court has struck Edison's request to terminate the SO4 Agreements
and obtain a refund of all funds paid to the Joint Ventures. The litigation is
in its early procedural stages and the pleadings have not been settled. The
Partnerships believe that its claims and defenses are meritorious and that they
will prevail if the matter is ultimately heard on its merits. The Partnerships
intend to vigorously defend this action and prosecute all available
counterclaims against Edison.
8. Subsequent Event
On January 25, 1999, CalEnergy agreed to sell its indirect interest in CED to
Caithness Acquisition Company LLC (Caithness), an affiliate of CCH. Upon
completion of the sale, COC, Caithness or its designee will become the operator
of CED.
F-30
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners of Coso Power Developers
In our opinion, the accompanying balance sheets and the related statements of
operations, of partners' capital and of cash flows present fairly, in all
material respects, the financial position of Coso Power Developers at December
31, 1997 and 1998, and the results of its operations and its cash flows for
each of the three years in the period ended December 31, 1998, in conformity
with generally accepted accounting principles. These financial statements are
the responsibility of the Partnership's management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with generally accepted
auditing standards which require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management,
and evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for the opinion expressed above.
As discussed in Note 2 to the financial statements, the Partnership adopted
in 1998 Statement of Position No. 98-5, "Reporting on the Costs of Start-Up
Activities."
/s/ PricewaterhouseCoopers LLP
San Francisco, California
February 12, 1999
F-31
COSO POWER DEVELOPERS
BALANCE SHEETS
(Dollars in thousands)
December 31,
-----------------
1997 1998
Assets
Cash......................................................... $ 1,148 $ 818
Accounts receivable.......................................... 17,873 19,656
Prepaid expenses and other assets............................ 1,592 694
Amounts due from related parties, net (Note 6)............... 1,778 2,848
Property, plant and equipment, net (Note 4).................. 198,483 188,862
Investment in Coso Transmission Line Partners................ 3,929 3,802
Advances to China Lake Plant Services, Inc................... 1,743 2,086
Deferred financing costs, net................................ 403 199
-------- --------
$226,949 $218,965
======== ========
Liabilities and Partners' Capital
Accounts payable and accrued liabilities..................... $ 4,269 $ 3,981
Project loan (Note 5)........................................ 97,267 61,323
-------- --------
101,536 65,304
Partners' capital............................................ 125,413 153,661
-------- --------
$226,949 $218,965
======== ========
The accompanying notes are an integral part of these financial statements.
F-32
COSO POWER DEVELOPERS
STATEMENTS OF OPERATIONS
(Dollars in thousands)
For the years ended
December 31,
--------------------------
1996 1997 1998
Revenue
Sales of electricity.............................. $115,126 $112,796 $119,564
Interest and other income......................... 3,174 2,187 1,799
-------- -------- --------
118,300 114,983 121,363
-------- -------- --------
Expenses
Plant operations (Note 6)......................... 13,371 13,146 15,508
Royalty expense................................... 11,486 11,249 11,868
Depreciation and amortization..................... 13,054 13,354 13,744
Interest expense.................................. 12,149 10,532 8,122
-------- -------- --------
50,060 48,281 49,242
-------- -------- --------
Income before cumulative effect of accounting
change........................................... 68,240 66,702 72,121
Cumulative effect of accounting change (Note 2)... -- -- (1,664)
-------- -------- --------
Net income........................................ $ 68,240 $ 66,702 $ 70,457
======== ======== ========
The accompanying notes are an integral part of these financial statements.
F-33
COSO POWER DEVELOPERS
STATEMENTS OF PARTNERS' CAPITAL
(Dollars in thousands)
Caithness Coso
Navy II Technology
Group L.P. Corporation Total
Balance, December 31, 1995................. $ 70,041.0 $ 70,041.0 $140,082.0
Distributions to partners(1)............... (41,115.0) (41,115.0) (82,230.0)
Net income................................. 34,120.0 34,120.0 68,240.0
---------- ---------- ----------
Balance, December 31, 1996................. 63,046.0 63,046.0 126,092.0
Distributions to partners(1)............... (33,690.5) (33,690.5) (67,381.0)
Net income................................. 33,351.0 33,351.0 66,702.0
---------- ---------- ----------
Balance, December 31, 1997................. 62,706.5 62,706.5 125,413.0
Distributions to partners.................. (21,104.5) (21,104.5) (42,209.0)
Net income................................. 35,228.5 35,228.5 70,457.0
---------- ---------- ----------
Balance, December 31, 1998................. $ 76,830.5 $ 76,830.5 $153,661.0
========== ========== ==========
- ---------------------
(1) Distributions of $13,769 to Caithness Navy II Group L.P. and $13,769 to
Coso Technology Corporation were declared and paid on January 2, 1996.
Distributions of $16,596 to Caithness Navy II Group L.P. and $16,596 to
Coso Technology Corporation were declared on December 31, 1996 and paid on
December 31, 1996 and January 2, 1997, respectively.
The accompanying notes are an integral part of these financial statements.
F-34
COSO POWER DEVELOPERS
STATEMENTS OF CASH FLOWS
(Dollars in thousands)
For the years ended
December 31,
-----------------------------
1996 1997 1998
Cash flows from operating activities
Net income...................................... $ 68,240 $ 66,702 $ 70,457
Adjustments to reconcile net income to net cash
flows from operating activities:
Depreciation and amortization................. 13,054 13,354 13,744
Amortization of deferred financing costs...... 326 271 204
Cumulative effect of accounting change........ -- -- 1,664
Equity in loss of Coso Transmission Line
Partners..................................... 126 127 127
Additional charges from (advances to) China
Lake Plant Services, Inc..................... (198) 503 (343)
Decrease (increase) in accounts receivable,
prepaid expenses and other assets............ 172 (948) (885)
Increase (decrease) in accounts payable and
accrued liabilities.......................... (7,939) 796 864
Decrease (increase) in amounts due from
related parties.............................. 830 (145) (1,070)
-------- --------- --------
Net cash flows from operating activities.... 74,611 80,660 84,762
-------- --------- --------
Cash flows from investing activities
Additions to power plant and transmission line.. (2,930) (269) (1,411)
Additions to wells and resource development
costs.......................................... (1,403) (7,723) (5,528)
Decrease in restricted cash..................... 450 22,391 --
-------- --------- --------
Net cash flows from investing activities.... (3,883) 14,399 (6,939)
-------- --------- --------
Cash flows from financing activities
Distributions to partners....................... (65,634) (83,977) (42,209)
Repayment of project financing loans............ (31,682) (27,094) (35,944)
Repayment of CalEnergy promissory note.......... -- (973) --
-------- --------- --------
Net cash flows from financing activities.... (97,316) (112,044) (78,153)
-------- --------- --------
Net change in cash.............................. (26,588) (16,985) (330)
Cash at beginning of year....................... 44,721 18,133 1,148
-------- --------- --------
Cash at end of year............................. $ 18,133 $ 1,148 $ 818
======== ========= ========
Supplemental cash flow disclosure
Interest paid................................... $ 18,394 $ 10,877 $ 7,918
The accompanying notes are an integral part of these financial statements.
F-35
COSO POWER DEVELOPERS
NOTES TO FINANCIAL STATEMENTS
(Dollars in thousands)
1. The Partnership and Business of Coso Power Developers
Coso Power Developers (CPD or Partnership) was formed on July 31, 1989, in
connection with financing the construction of a geothermal power plant on land
at the China Lake Naval Air Weapons Station at Coso Hot Springs, China Lake,
California. CPD is a general partnership between Coso Technology Corporation
(CTC), a Delaware corporation, and Caithness Navy II Group L.P. (CNIIG), a New
Jersey limited partnership.
The power plant is located on land owned by the U.S. Navy. Under the terms of
a 30-year contract with the U.S. Navy to develop geothermal energy on its land,
CPD will pay a royalty to the Navy which was initially 4% of revenues, is
currently 10% of revenues, and increases to 20% of revenues after 15 years. The
Navy contract expires in 2009; the Navy has an option to extend it to 2019.
The Partnership sells all electricity produced to Southern California Edison
(Edison) under a 20-year power purchase contract for the Navy II plant expiring
in 2010. Under the terms of the contract, Edison makes payments to CPD as
follows:
. Contractual payments for energy delivered, which payments escalate at an
average rate of approximately 7.6% for the first ten years after the date
of firm operation (scheduled energy price period). The scheduled energy
price period for each unit extends until at least January 2000, after
which the energy payment for at least Unit 7 adjusts to the actual
avoided energy cost experienced by Edison at that time. For the year
ended December 31, 1998, Edison's average avoided cost of energy was 2.95
cents per kwh which is substantially below the contract energy prices
earned for the year ended December 31, 1998. Estimates of Edison's future
avoided cost of energy vary substantially from year to year. The
Partnership cannot predict the likely level of avoided cost of energy
prices under the 20-year power purchase contract at the expiration of the
scheduled energy price period. The revenues generated by the Partnership
could decline significantly after the expiration of the scheduled energy
price period;
. Capacity payments which remain fixed over the life of the contract to the
extent that actual energy delivered exceeds minimum levels of the plant
capacity defined in the contract; and
. Bonus payments to the extent that actual energy delivered exceeds 85% of
the plant capacity stated in the contract. In 1996, 1997 and 1998, the
bonus payments aggregated $2,255, $2,236, and $2,242, respectively.
CalEnergy Company, Inc. (CalEnergy) served as the operator, maintaining the
Partnership's accounting records and operating the CPD plant on a day-to-day
basis, until February 1, 1999, when Coso Operating Company LLC (COC), a
Delaware limited liability company, became operator pursuant to certain
operations and maintenance agreements with CTC, the managing general partner of
CPD (see Note 8). COC and CTC are wholly-owned subsidiaries of CalEnergy.
At formation, and as subsequently amended, the partnership agreement provides
that cash flows before and after "payout" which has occurred, are allocated 50%
each to CTC and CNIIG. "Payout" is defined as the point at which each partner
has received aggregate cash distributions in
F-36
COSO POWER DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
an amount equal to their accumulated capital contributions. For purposes of
allocating net income to partners' capital accounts and for income tax
purposes, profits and losses are allocated based on the aforementioned capital
percentages.
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
2. Summary of Significant Accounting Policies
Recognition of Revenue
Operating revenues are recognized as income during the period in which
electricity is delivered to Edison. Revenue is recognized based on the payment
rates scheduled in CPD's power purchase contract with Edison.
Fixed Assets and Depreciation
The costs of major additions and betterments are capitalized, while
replacements, maintenance and repairs which do not improve or extend the life
of the respective assets are expensed currently.
Depreciation of the power plant and transmission line is computed on the
straight line method over their estimated useful life of 30 years and, for
significant additions, the remainder of the 30-year life from the plant's
commencement of operations.
The Partnership reviews long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. An impairment loss would be recognized whenever evidence exists
that the carrying value is not recoverable.
In April 1998, the Accounting Standards Executive Committee issued Statement
of Position (SOP) No. 98-5, "Reporting on the Costs of Start-Up Activities."
SOP No. 98-5 requires that, at the effective date of adoption, costs of start-
up activities previously capitalized be expensed and reported as a cumulative
effect of a change in accounting principle, and further requires that such
costs subsequent to adoption be expensed as incurred. CPD adopted this standard
in 1998 and expensed applicable unamortized costs previously capitalized in
connection with the start-up of CPD. The cumulative effect of the change in
accounting principle was $1,664.
Wells and Resource Development Costs
CPD follows the full cost method of accounting for costs incurred in
connection with the exploration and development of geothermal resources. All
such costs, which include dry hole costs, the costs of drilling and equipping
production wells, and administrative and interest costs directly attributable
to the project, are capitalized and amortized over their estimated useful lives
when production commences. The estimated useful lives of production wells are
ten years each; exploration
F-37
COSO POWER DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
costs and development costs, other than production wells, are amortized over 30
years and, for significant additions, the remainder of the 30-year life from
the plant's commencement of operations.
Deferred Well Rework Costs
Well rework costs are deferred and amortized over the estimated period
between reworks. These deferred costs of $1,029 and $83 at December 31, 1997
and 1998, respectively, are included in prepaid expenses and other assets.
Currently, both production and injection rework costs are amortized over twelve
months.
Deferred Plant Overhaul Costs
Plant overhaul costs are deferred and amortized over the estimated period
between overhauls. These deferred costs of $0 and $176 at December 31, 1997 and
1998, respectively, are included in prepaid expenses and other assets.
Currently, plant overhauls are amortized over three years from the point of
completion.
Investment in Coso Transmission Line Partners
Coso Transmission Line Partners (CTLP) is a partnership, between CPD and Coso
Energy Developers (CED), which owns the transmission line and facilities
connecting the power plants owned by CPD and CED to the transmission line,
owned by Edison, at Inyokern, California, located 28 miles south of the plants.
CTLP charges CPD and CED for the use of the transmission line at amounts
designed to ensure that CTLP recovers its operating costs. These charges are
recorded by CPD as operating expenses and reflected as a reduction in CPD's
investment in CTLP.
Advances to China Lake Plant Services, Inc.
China Lake Plant Services, Inc. (CLPSI) is a wholly-owned subsidiary of
CalEnergy. CLPSI purchases, stores and distributes spare parts to CPD and two
other affiliated operating ventures. Also, certain other facilities utilized by
all three operating ventures are held by CLPSI. CPD's advances to CLPSI
represent funds advanced for the purchase of spare parts inventory and other
assets. Spare parts inventory held by CLPSI on behalf of CPD is valued at the
lower of cost or market.
Deferred Financing Costs
Deferred financing costs consist of loan fees and are amortized over the term
of the related financing using the effective interest method. Accumulated
amortization at December 31, 1997 and 1998 was $1,823 and $2,027, respectively.
Income Taxes
There is no provision for income taxes since those taxes are the
responsibility of the partners.
F-38
COSO POWER DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
Cash Flows
For purposes of the statements of cash flows, CPD considers all money market
instruments purchased with an initial maturity of three months or less to be
cash equivalents.
3. Interest Rate Swap Agreement
In January 1993, CPD entered into a five-year deposit interest rate swap
agreement which, until certain investments were liquidated in February 1997
(see Note 5), effectively converted notional deposit balances from a variable
rate to a fixed rate. Under the agreement, which matured on January 11, 1998,
CPD made payments to the counterparty each January 11 and July 11 at variable
rates based on LIBOR, reset and compounded every three months, and in return
received payments based on a fixed rate of 6.34%. The effective LIBOR rate
ranged from 5.5313% to 5.8125% during 1997 and was 5.7500% at December 31, 1997
and at January 11, 1998, the termination date. The counterparty to this
agreement was a large international financial institution. The carrying amount
of the interest rate swap at December 31, 1997, was $41 (payable to CPD), which
approximated its fair value. The fair value was based on the estimated amount
that CPD would have received to terminate the swap at that date as provided by
the financial institution which was the counterparty to the swap.
4. Property, Plant and Equipment
Property, plant and equipment are comprised of the following:
December 31,
------------------
1997 1998
Power plant and gathering system......................... $165,708 $164,952
Transmission line........................................ 9,484 8,332
Wells and resource development costs..................... 108,977 114,505
-------- --------
284,169 287,789
Less accumulated depreciation and amortization........... (85,686) (98,927)
-------- --------
$198,483 $188,862
======== ========
The transmission line costs represent the costs of construction of
transmission lines from Inyokern to the Edison substation at Kramer and from
Kramer to the Edison substation at Victorville.
5. Project Loan
The project loan is as follows:
December 31,
---------------
1997 1998
Project loan with a weighted average interest rate of 8.61%
and 8.65%, respectively, at December 31, 1997 and 1998
with scheduled repayments through December 2001........... $97,267 $61,323
The project loan is a loan from Coso Funding Corp. (Funding Corp.). Funding
Corp. is a single-purpose corporation formed to issue notes for its own account
and as an agent acting on behalf of
F-39
COSO POWER DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
CPD, Coso Finance Partners (CFP) and CED, collectively the "Partnerships."
Pursuant to separate credit agreements executed between Funding Corp. and each
partnership on December 16, 1992, the proceeds from Funding Corp.'s note
offering were loaned to the Partnerships.
The CPD project loan is collateralized by, among other things, the power
plant, geothermal resource, letters of credit, pledge of contracts and an
assignment of all Partnerships' revenues which will be applied against the
payment of obligations of each partnership, including the project loans. Each
partnership's assets collateralize only its own project loan, and are not
cross-collateralized with assets pledged under other partnership's credit
agreements. The project loan is non-recourse to any partner in CPD and Funding
Corp. shall solely look to such Partnership's pledged assets for satisfaction
of such project loan. However, the Partnership, after satisfying a series of
its own obligations, has agreed to advance support loans to the extent of its
available cash flow and, under certain conditions its letters of credit, to CFP
or CED in the event such other partnership's revenues are insufficient to meet
scheduled principal and interest on its separate project loan from Funding
Corp.
Until February 1997 the Partnership maintained a debt service fund which was
legally restricted as to its use and which required the maintenance of a
specific balance. The fund, comprised of investments of U.S. government and
corporate debt and various mortgage-backed securities with maturities from 1997
through 2024, was required by the terms and conditions of the project financing
and was maintained by First Trust of California in its capacity as the trustee
for the project lender. The securities comprising the fund were categorized as
held-to-maturity and valued at amortized cost. In February 1997 the project
lenders allowed the Partnership to replace the cash and investment balance in
the debt service fund with irrevocable letters of credit. The fund was then
liquidated and the resulting proceeds were (i) used to retire the promissory
note due CalEnergy and (ii) distributed to the partners. Proceeds from the sale
of these securities approximated their carrying value plus interest accrued
through the date of sale.
The annual project loan repayments are summarized as follows:
1999............................................................... $39,322
2000............................................................... 1,828
2001............................................................... 20,173
-------
$61,323
=======
Based on quoted market rates of the Funding Corp. notes, the fair value of
the project loan as of December 31, 1997 and 1998 was approximately $102,495
and $63,912, respectively.
F-40
COSO POWER DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
6. Related Party Transactions
CalEnergy, as operator, is reimbursed monthly for non-third-party costs
incurred on behalf of CPD. These costs are comprised principally of approved
direct CalEnergy operating costs of the CPD geothermal facility, allocable
general and administration costs and operator fees and were as follows:
1996 1997 1998
Operating costs...................................... $3,076 $3,312 $3,026
General and administration costs..................... 1,911 1,911 1,955
Operator fees........................................ 517 517 513
Both CalEnergy and CNIIG are reimbursed at approved amounts for their
respective costs incurred in relation to the CPD Management Committee. The
management committee fees paid were:
1996 1997 1998
CNIIG....................................................... $218 $218 $223
CalEnergy................................................... 145 145 148
As discussed in Note 2, CPD is charged for its use of the transmission line
owned by CTLP. The amount of such net charges was $126, $127 and $127 for the
years ended December 31, 1996, 1997 and 1998, respectively.
CPD is charged by CLPSI for both its inventory usage and its portion of the
expenses of operating CLPSI. The charges to CPD from CLPSI in 1996, 1997 and
1998 were approximately $381, $1,227 and $361, respectively.
During 1994, the three Coso operating ventures (CPD, CED and CFP) entered
into steam sharing agreements under which the ventures may transfer steam, with
the resulting incremental revenue and royalty expense shared equally by the
ventures. In the second half of 1995, interconnection facilities between the
plants were completed and the transfer of steam commenced. CPD steam sharing
revenue, net of royalties and other related costs, amounted to $3,566, $1,750
and $342 in 1996, 1997 and 1998, respectively.
The amounts due to (from) related parties at December 31, 1997 and 1998
consist of the following:
December 31,
----------------
1997 1998
Due from CalEnergy........................................ $ (42) $(1,241)
Due from CED for steam sharing............................ (561) (259)
Due to CFP for steam sharing.............................. 1,704 1,902
Loan to China Lake Joint Venture
Principal............................................... (1,562) (1,562)
Accrued interest........................................ (1,317) (1,688)
------- -------
$(1,778) $(2,848)
======= =======
On December 16, 1992, CPD signed a promissory note with CalEnergy for $973,
which represents the principal on the previous promissory note of $869 plus
accrued interest through December 16, 1992, of $104. This note bore a fixed
interest rate of 12.5%, compounded semi-
F-41
COSO POWER DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
annually, and was payable on or before March 19, 2002. The previous note was
signed March 19, 1991 as a result of the partners' arbitration settlement and
accrued interest at a rate defined as the lowest average interest rate actually
charged by the previous project loan lender on any of the Coso ventures' debt,
which was 5.4% through December 16, 1992. During February 1997, this note and
accrued interest were paid in full. Interest on the note was $181 and $27 in
1996 and 1997, respectively.
Additionally, on December 16, 1992, CPD retired China Lake Joint Venture's
(CLJV) promissory note due CalEnergy, resulting in the loan from CPD to CLJV of
$1,562 at December 31, 1992. CLJV is an affiliated venture. Interest has been
accrued on this loan at 12.5%. Interest on the loan was $291, $329 and $371 in
1996, 1997 and 1998, respectively.
The December 31, 1997 and 1998 due from CalEnergy balances relate to the
venture reimbursing CalEnergy for the costs of operating the plant. This amount
fluctuated in concert with the timing of billings and incurring of costs.
7. Commitments and Contingencies
On June 9, 1997, Edison filed a complaint alleging breach of the power
purchase agreements (SO4 Agreements) between Edison and the Partnerships as a
result of alleged improper venting of certain noncondensible gases at the Coso
geothermal energy project. In the complaint, Edison seeks unspecified damages,
including the refund of certain amounts previously paid under the SO4
Agreements, and termination of the SO4 Agreements. In September 1997, the
Partnerships and CalEnergy filed a cross-complaint against Edison and its
affiliates, The Mission Group and Mission Power Engineering Company, alleging,
among other things, that Edison's lawsuit violates the 1993 settlement
agreement which settled certain litigation arising from the construction of
certain units at the Coso geothermal project by Edison affiliates. In addition,
the Partnerships filed a separate complaint against Edison alleging breach of
the SO4 Agreements, unfair business practices, slander and various other tort
and contract claims. The actions were effectively consolidated in December
1997. As a result of certain procedural actions by the parties and a November
1997 court order, Edison filed an amended complaint on December 16, 1997 and
the Partnerships amended their cross-complaint. In addition, the court has
struck Edison's request to terminate the SO4 Agreements and obtain a refund of
all funds paid to the Joint Ventures. The litigation is in its early procedural
stages and the pleadings have not been settled. The Partnerships believe that
its claims and defenses are meritorious and that they will prevail if the
matter is ultimately heard on its merits. The Partnerships intend to vigorously
defend this action and prosecute all available counterclaims against Edison.
8. Subsequent Event
On January 25, 1999, CalEnergy agreed to sell its indirect interest in CPD to
Caithness Acquisition Company LLC (Caithness), an affiliate of CNIIG. Upon
completion of the sale, COC, Caithness or its designee will become the operator
of CPD.
F-42
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
UNAUDITED CONDENSED COMBINED BALANCE SHEETS
(Dollars in thousands)
December 31, March 31,
1998 1999
(Note) (New basis)
Assets
Cash................................................... $ -- $ 6,397
Restricted cash and investments........................ 7,524 7,808
Accounts receivable.................................... 5,404 5,520
Prepaids and other assets.............................. 426 185
Amounts due to related parties......................... 3,782 42
Property, plant and equipment.......................... 180,380 158,367
Power purchase agreement............................... -- 14,573
Advances to China Lake Plant Services, Inc. ........... 4,139 4,114
Deferred financing costs, net.......................... 233 1,320
-------- --------
$201,888 $198,326
======== ========
Liabilities and Partners' Capital
Accounts payable and accrued liabilities............... $ 11,389 $ 13,387
Acquisition debt....................................... -- 77,610
Project loan........................................... 40,566 40,566
-------- --------
51,955 131,563
Partners' capital...................................... 149,933 66,763
-------- --------
$201,888 $198,326
======== ========
Note: The condensed combined balance sheet at December 31, 1998 has been
derived from the audited financial statements at that date but does not
include all of the information and footnotes required by generally
accepted accounting principles for complete financial statements.
See accompanying notes to the unaudited condensed combined financial
statements.
F-43
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
UNAUDITED CONDENSED COMBINED STATEMENTS OF OPERATIONS
(Dollars in thousands)
Three months Two months
ended ended One month
March 31, February 28, ended March
1998 1999 31, 1999
(New basis)
Revenue
Sales of electricity...................... $10,806 $8,572 $4,636
Interest and other income................. 136 824 827
------- ------ ------
10,942 9,396 5,463
------- ------ ------
Expenses
Plant operations.......................... 3,571 3,125 1,458
Royalty expense........................... 895 987 451
Depreciation and amortization............. 2,957 1,604 783
Interest expense.......................... 1,124 663 1,630
------- ------ ------
8,547 6,379 4,322
------- ------ ------
Net income................................ $ 2,395 $3,017 $1,141
======= ====== ======
See accompanying notes to the unaudited condensed combined financial
statements.
F-44
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
UNAUDITED CONDENSED COMBINED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
Three months Two months
Ended Ended One month
March 31, February 28, Ended March
1998 1999 31, 1999
(New basis)
Net cash provided by operating
activities............................ $7,804 $ 6,592 $2,665
Net cash used by investing activities.. (24) (538) (397)
Net cash provided (used) by financing
activities............................ (108) (1,926) --
------ ------- ------
Net change in cash and cash
equivalents........................... $7,672 $ 4,128 $2,268
====== ======= ======
See accompanying notes to the unaudited condensed combined financial
statements.
F-45
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO THE UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS
1. Basis of presentation
The accompanying unaudited condensed combined financial statements have been
prepared in accordance with generally accepted accounting principles for
interim financial information. Accordingly, certain information and footnote
disclosures normally included in financial statements prepared in accordance
with generally accepted accounting principles have been condensed or omitted
pursuant to such rules. Management believes that the disclosures are adequate
to make the information presented not misleading when read in conjunction with
the combined financial statements and the notes thereto included in the audited
financial statements for the year ended December 31, 1998.
The financial information herein presented reflects all adjustments,
consisting only of normal recurring adjustments, which are, in the opinion of
management, necessary for a fair statement of the results for interim periods
presented. The results for the interim periods are not necessarily indicative
of results to be expected for the full year. Coso Finance Partners and Coso
Finance Partners II (collectively, CFP) has experienced significant quarterly
fluctuations in operating results and it expects that these fluctuations in
energy revenues, expenses and net income will continue.
2. Acquisition of CalEnergy's interest in the Coso Partnerships
On February 25, 1999, Caithness Acquisition Company, LLC (Caithness
Acquisition), a wholly owned subsidiary of Caithness Energy LLC, purchased all
of CalEnergy Company, Inc.'s (CalEnergy) interests in CFP and its affiliated
partnerships, Coso Power Developers and Coso Energy Developers (collectively,
the Coso Partnerships) for a total purchase price of $205 million in cash, plus
up to $5 million in contingent payments, and the assumption of CalEnergy's
share of debt outstanding at the Coso Partnerships which then totaled
approximately $68.7 million. The acquisition was accounted for under the
purchase method, whereby the purchase price is allocated to the underlying
assets and liabilities based upon their estimated fair market values. The total
cash purchase price allocated to CFP was approximately $62.1 million. No
goodwill was recorded as a result of the purchase.
In order to complete the purchase, Caithness Acquisition arranged for short-
term debt financing in the principal amount of approximately $211.5 million.
Caithness Acquisition will use a portion of the proceeds from an anticipated
offering of senior secured notes that it will receive from the Coso
partnerships, together with funds from other sources, to repay all amounts owed
under this short-term debt facility. As a result of "push-down" accounting, a
pro rata portion of the short-term debt has been reflected in the financial
statements of CFP as of February 25, 1999.
The following unaudited pro forma financial information for the three months
ended March 31, 1998 and 1999 present the combined results of operations of CFP
as if the acquisition had occurred as of January 1, 1999, after giving effect
to certain adjustments including amortization of intangible assets, reduced
depreciation and operating expense and increased interest expense. The pro
forma financial information does not necessarily reflect the results of
operations that would have occurred had the acquisition been completed on
January 1, 1999.
Three Months Ended
-------------------
March 31, March 31,
1998 1999
--------- ---------
Total revenues........................................ $10,942 $14,859
======= =======
Net income............................................ $(1,008) $ 1,875
======= =======
F-46
COSO ENERGY DEVELOPERS
UNAUDITED CONDENSED BALANCE SHEETS
(Dollars in thousands)
December 31, March 31,
1998 1999
(Note) (New basis)
Assets
Cash................................................... $ -- $ 17,015
Restricted cash and investments........................ 290 247
Accounts receivable.................................... 19,835 15,799
Prepaids and other assets.............................. 1,526 333
Amounts due from related parties....................... -- 304
Property, plant and equipment.......................... 201,600 163,269
Power purchase agreement............................... -- 20,498
Investment in Coso Transmission Line Partners.......... 3,107 3,930
Advances to China Lake Plant Services, Inc. ........... 1,567 1,405
Deferred financing costs, net.......................... 162 939
-------- --------
$228,087 $223,739
======== ========
Liabilities and Partners' Capital
Accounts payable and accrued liabilities............... $ 3,314 $ 3,129
Amounts due to related parties......................... 23,624 21,790
Acquisition debt....................................... -- 55,256
Project loan........................................... 37,958 37,958
-------- --------
64,896 118,133
Partners' capital...................................... 163,191 105,606
-------- --------
$228,087 $223,739
======== ========
Note: The condensed balance sheet at December 31, 1998 has been derived from
the audited financial statements at that date but does not include all of
the information and footnotes required by generally accepted accounting
principles for complete financial statements.
See accompanying notes to the unaudited condensed financial statements.
F-47
COSO ENERGY DEVELOPERS
UNAUDITED CONDENSED STATEMENTS OF OPERATIONS
(Dollars in thousands)
Three months Two months
ended ended One month
March 31, February 28, ended March
1998 1999 31, 1999
(New basis)
Revenue
Sales of electricity...................... $22,728 $17,533 $3,844
Interest and other income................. 217 78 118
------- ------- ------
22,945 17,611 3,962
------- ------- ------
Expenses
Plant operations.......................... 5,517 4,039 1,604
Royalty expense........................... 2,101 1,592 347
Depreciation and amortization............. 3,624 2,550 1,175
Interest expense.......................... 1,786 616 1,233
------- ------- ------
13,028 8,797 4,359
------- ------- ------
Net income................................ $ 9,917 $ 8,814 $ (397)
======= ======= ======
See accompanying notes to the unaudited condensed financial statements.
F-48
COSO ENERGY DEVELOPERS
UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
Two months
Three months Ended One month
Ended March 31, February 28, Ended March 31,
1998 1999 1999
(New basis)
Net cash provided by operating
activities...................... $18,478 $10,367 $6,595
Net cash provided (used) by
investing activities............ (3,556) 120 (294)
Net cash provided (used) by
financing activities............ (413) 425 (198)
------- ------- ------
Net change in cash and cash
equivalents..................... $14,509 $10,912 $6,103
======= ======= ======
See accompanying notes to the unaudited condensed financial statements.
F-49
COSO ENERGY DEVELOPERS
NOTES TO THE UNAUDITED CONDENSED FINANCIAL STATEMENTS
1. Basis of presentation
The accompanying unaudited condensed financial statements have been prepared
in accordance with generally accepted accounting principles for interim
financial information. Accordingly, certain information and footnote
disclosures normally included in financial statements prepared in accordance
with generally accepted accounting principles have been condensed or omitted
pursuant to such rules. Management believes that the disclosures are adequate
to make the information presented not misleading when read in conjunction with
the financial statements and the notes thereto included in the audited
financial statements for the year ended December 31, 1998.
The financial information herein presented reflects all adjustments,
consisting only of normal recurring adjustments, which are, in the opinion of
management, necessary for a fair statement of the results for interim periods
presented. The results for the interim periods are not necessarily indicative
of results to be expected for the full year. Coso Energy Developers (CED) has
experienced significant quarterly fluctuations in operating results and it
expects that these fluctuations in energy revenues, expenses and net income
will continue.
2. Acquisition of CalEnergy's interest in the Coso Partnerships
On February 25, 1999, Caithness Acquisition Company, LLC (Caithness
Acquisition) a wholly owned subsidiary of Caithness Energy, LLC purchased all
of CalEnergy Company, Inc.'s (CalEnergy) interests in CED and its affiliated
partnerships, Coso Power Developers and Coso Finance Partners and Coso Finance
Partners II (collectively, the Coso partnerships) for a total purchase price of
$205 million in cash, plus up to $5 million in contingent payments and the
assumption of CalEnergy's share of debt outstanding at the Coso partnerships
which then totaled approximately $68.7 million. The acquisition was accounted
for under the purchase method, whereby the purchase price is allocated to the
underlying assets and liabilities based upon their estimated fair market
values. The total purchase price allocated to CED was approximately $68.8
million. No goodwill was recorded as a result of the purchase.
In order to complete the purchase, Caithness Acquisition arranged for short-
term debt financing in the principal amount of approximately $211.5 million.
Caithness Acquisition will use a portion of the proceeds from an anticipated
offering of senior secured notes that it will receive from the Coso
partnerships, together with funds from other sources, to repay all amounts owed
under this short-term debt facility. As a result of "push down" accounting, a
pro rata portion of the short-term debt has been reflected in the financial
statements of CED as of February 25, 1999.
The following unaudited pro forma financial information for the three months
ended March 31, 1998 and 1999 present the combined results of operations of CED
as if the acquisition had occurred as of January 1, 1999, after giving effect
to certain adjustments including amortization of intangible assets, reduced
depreciation and operating expense and increased interest expense. The pro
forma financial information does not necessarily reflect the results of
operations that would have occurred had the acquisition been completed on
January 1, 1999.
Three Months Ended
-------------------
March 31, March 31,
1998 1999
--------- ---------
Total revenues........................................ $22,945 $21,573
======= =======
Net income............................................ $ 8,029 $ 7,223
======= =======
F-50
COSO POWER DEVELOPERS
UNAUDITED CONDENSED BALANCE SHEETS
(Dollars in thousands)
December 31, March 31,
1998 1999
(Note) (New basis)
Assets
Cash................................................... $ 818 $ 20,039
Accounts receivable.................................... 19,656 19,778
Prepaids and other assets.............................. 694 294
Amounts due to related parties......................... 2,848 3,352
Property, plant and equipment.......................... 188,862 149,380
Power purchase agreement............................... -- 29,656
Investment in Coso Transmission Line Partners.......... 3,802 4,791
Advances to China Lake Plant Services, Inc. ........... 2,086 2,027
Deferred financing costs, net.......................... 199 1,336
-------- --------
$218,965 $230,653
======== ========
Liabilities and Partners' Capital
Accounts payable and accrued liabilities............... $ 3,981 $ 6,764
Amounts due to related parties......................... -- 1,540
Acquisition debt....................................... -- 78,634
Project loan........................................... 61,323 61,323
-------- --------
65,304 148,261
Partners' capital...................................... 153,661 82,392
-------- --------
$218,965 $230,653
======== ========
Note: The condensed balance sheet at December 31, 1998 has been derived from
the audited financial statements at that date but does not include all of
the information and footnotes required by generally accepted accounting
principles for complete financial statements.
See accompanying notes to the unaudited condensed financial statements.
F-51
COSO POWER DEVELOPERS
UNAUDITED CONDENSED STATEMENTS OF OPERATIONS
(Dollars in thousands)
Three months Two months
ended ended One month
March 31, February 28, ended March
1998 1999 31, 1999
(New basis)
Revenue
Sales of electricity...................... $26,649 $17,509 $7,128
Interest and other income................. 319 150 156
------- ------- ------
26,968 17,659 7,284
------- ------- ------
Expenses
Plant operations.......................... 4,356 3,195 1,293
Royalty expense........................... 2,780 1,806 1,064
Depreciation and amortization............. 3,493 2,339 1,188
Interest expense.......................... 2,235 953 1,792
------- ------- ------
12,864 8,293 5,337
------- ------- ------
Net income................................ $14,104 $ 9,366 $1,947
======= ======= ======
See accompanying notes to the unaudited condensed financial statements.
F-52
COSO POWER DEVELOPERS
UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
Three months Two months One month
Ended March 31, Ended February 28, Ended March 31,
1998 1999 1999
(New basis)
Net cash provided by
operating activities...... $19,352 $12,016 $6,265
Net cash used by investing
activities................ (808) (1,126) (218)
Net cash provided by
financing activities...... 273 1,766 518
------- ------- ------
Net change in cash and cash
equivalents............... $18,817 $12,656 $6,565
======= ======= ======
See accompanying notes to the unaudited condensed financial statements.
F-53
COSO POWER DEVELOPERS
NOTES TO THE UNAUDITED CONDENSED FINANCIAL STATEMENTS
1. Basis of presentation
The accompanying unaudited condensed financial statements have been prepared
in accordance with generally accepted accounting principles for interim
financial information. Accordingly, certain information and footnote
disclosures normally included in financial statements prepared in accordance
with generally accepted accounting principles have been condensed or omitted
pursuant to such rules. Management believes that the disclosures are adequate
to make the information presented not misleading when read in conjunction with
the financial statements and the notes thereto included in the audited
financial statements for the year ended December 31, 1998.
The financial information herein presented reflects all adjustments,
consisting only of normal recurring adjustments, which are, in the opinion of
management, necessary for a fair statement of the results for interim periods
presented. The results for the interim periods are not necessarily indicative
of results to be expected for the full year. Coso Power Developers (CPD) has
experienced significant quarterly fluctuations in operating results and it
expects that these fluctuations in energy revenues, expenses and net income
will continue.
2. Acquisition of CalEnergy's interest in the Coso Partnerships
On February 25, 1999, Caithness Acquisition Company, LLC (Caithness
Acquisition) a wholly owned subsidiary of Caithness Energy, LLC purchased all
of CalEnergy Company, Inc.'s (CalEnergy) interests in CPD and its affiliated
partnerships, Coso Energy Developers and Coso Finance Partners and Coso Finance
Partners II (collectively, the Coso partnerships) for a total purchase price of
$205 million in cash, plus up to $5.0 million in contingent payments, and the
assumption of CalEnergy's share of debt outstanding at the Coso partnerships
which then totaled approximately $68.7 million. The acquisition was accounted
for under the purchase method, whereby the purchase price is allocated to the
underlying assets and liabilities based upon their estimated fair market
values. The total purchase price allocated to CPD was approximately $74.8
million. No goodwill was recorded as a result of the purchase.
In order to complete the purchase, Caithness Acquisition arranged for short-
term debt financing in the principal amount of approximately $211.5 million.
Caithness Acquisition will use a portion of the proceeds from an anticipated
offering of senior secured notes that it will receive from the Coso
partnerships, together with funds from other sources, to repay all amounts owed
under this short-term debt facility. As a result of "push down" accounting, a
pro rata portion of the short-term debt has been reflected in the financial
statements of CPD as of February 25, 1999.
The following unaudited pro forma financial information for the three months
ended March 31, 1998 and 1999 present the results of operations of CPD as if
the acquisition had occurred as of January 1, 1999, after giving effect to
certain adjustments including amortization of intangible assets, reduced
depreciation and operating expense and increased interest expense. The pro
forma financial information does not necessarily reflect the results of
operations that would have occurred had the acquisition been completed on
January 1, 1999.
Three Months Ended
-------------------
March 31, March 31,
1998 1999
--------- ---------
Total revenues........................................ $26,968 $24,943
======= =======
Net income............................................ $10,788 $ 8,992
======= =======
F-54
Exhibit A
Coso Geothermal Projects
Independent Engineer's Report
Caithness Coso
Funding Corp.
New York, New York
20 May 1999
[Logo of Sandwell]
Project 263105
Coso Geothermal Projects
Independent Engineer's Report
For
Caithness Coso Funding Corp.
New York, New York
20 May 1999
Prepared by: /s/ R. G. Low
----------------------------------------
Richard G. Low, P.Eng.
Approved by: /s/ Dick A. Davis
----------------------------------------
Dick A. Davis, P.E.
1
TABLE OF CONTENTS
1. Executive Summary And Conclusions
2. Scope Of Services By Sandwell
3. Coso Facilities Overview
3.1 General
3.2 Description of Equipment and Operation.
. Navy I
. Navy II
. BLM
3.3 Steam Gathering Systems
3.4 Turbine-Generator Failures, Unit 1 Generator Failures, And Remedial
Actions.
3.5 Dow Sulferox H2S Abatement Systems.
4. Management and Organization.
4.1 General
4.2 Safety
4.3 Training
4.4 Maintenance
4.5 Spares Inventory
4.6 Review of FPLEOSI as Operator
5. Overview of Power Purchase Agreements.
6. Permitting and Environmental Compliance (Not included at this time)
7. Comments on 1999 O&M Financial Projections and Capital Expenditure Forecast.
8. Assessment of Financial Projections.
8.1 General
8.2 Revenues
8.3 Operating And Maintenance Expenses
8.4 Capital Expenditures
APPENDICES
Appendix A - Principal Considerations And Assumptions
Appendix B - Documents Reviewed
Appendix C - Financial Projections
2
1.0 EXECUTIVE SUMMARY AND CONCLUSIONS
1.1 Executive summary
Sandwell Engineering Inc. (Sandwell) has prepared this report as an
independent engineer's review of the Coso Geothermal Projects, namely
Navy I, Navy II, and BLM ("the plants" or "the facilities"), in
connection with the financing of the plants and for inclusion in the
offering circular therefor. Sandwell has been associated with the Coso
Projects as independent engineer for ten years, and this report
therefore reflects information gathered over that period of time, in
addition to information provided by Caithness Energy L.L.C.
(Caithness) and by FPL Energy Operating Services, Inc. ("FPLEOSI" or
"FPL Operating") specifically for the report.
The Coso Geothermal Projects consist of three separate, but
interlinked, geothermal power projects located at the Naval Weapons
Center in Inyo County, California. Nine turbine generator units (three
for each project) produce a total net rated electrical power
generation of approximately 240 MW using geothermal steam derived from
deep production wells drilled in the geothermal resource known as the
Coso Known Geothermal Resources Area (KGRA). The steam gathering
systems for all three projects are linked together so that optimum use
may be made of the available steam.
The power plants and wellfields are operated by FPL Operating under
separate Operation and Maintenance (O&M) agreements with the owners of
each project (the Partnerships). The geothermal resource is maintained
by Coso Operating Company, Inc, an affiliate of Caithness Energy.
Electrical power generated by the plants is sold to Southern
California Edison (SCE) under three separate 30-year California
Standard Offer No. 4 power purchase agreements. After an initial ten-
year fixed price period expires, the electricity is sold to SCE at a
much lower "Avoided Cost of Energy" rate. SCE has taken the position
that the ten-year fixed price periods expired for Navy I in August
1997, for BLM in March 1999 and for Navy II in January 2000.
FPL Operating and Caithness maintain all permits and approvals
required for current operation of the plants.
The geothermal steam from the resource contains small quantities of
hydrogen sulfide. In order to meet the conditions of the Air Quality
Permits, hydrogen sulfide abatement equipment is required. Normal
operation of the facilities therefore also includes operation of
hydrogen sulfide abatement equipment at each power plant that
processes the hydrogen sulfide into elemental sulfur, which can be
sold. At Navy I and Navy II LO-CAT II primary abatement equipment
units are used. At the BLM plants Dow Sulferox equipment is installed;
the Sulferox units have had an unsatisfactory record in terms of
operational reliability, and the high consumption, and therefore cost,
of the treatment chemicals consumed. Recent modifications, and an
agreement reached with Dow, have improved the operation, and reduced
the operating and maintenance costs to a satisfactory level.
3
The modifications to the Dow Sulferox systems were required, and the
decision to proceed with the modifications was reasonable, and
prudent.
Eight of the nine turbine generator units were designed and
manufactured by Fuji Electric. The ninth unit (and the first to be
operated at the projects) is of Mitsubishi design and manufacture.
After four years of operation, cracks were detected in one of the Fuji
turbine rotors, and similar faults have since occurred in two other
rotors in Coso project Fuji turbines, in one case causing a blade to
become detached, which damaged other parts of the turbine. After
extensive investigations, modifications designed to avoid the problems
have been made to four of the nine turbine rotors, and will be made to
the remainder as they undergo scheduled overhauls. The modifications
appear to have been successful, in that no cracking or other defects
in the modified rotors have been reported to us. We therefore conclude
that these modifications are an acceptable means of preventing the
cracking as previously detected. We understand that the Partnerships
are in litigation with Fuji regarding the cause and responsibility for
the failures.
The modifications to the Fuji turbine rotors have apparently been
successful in overcoming the cracking previously experienced, and may
reasonably be expected to prevent future similar failures.
The Mitsubishi turbine generator recently suffered an electrical
ground fault in the generator. The generator is being rewound, using a
modification designed to avoid recurrence of the fault. It is reported
that the repaired generator is scheduled to return to service in 5 - 9
weeks. The repair to the Mitsubishi Unit 1generator stator was
necessary, and the decision to incorporate modifications was
reasonable and prudent.
Sandwell's review has included commenting on the 1999 O&M pro forma
and capital expenditure forecasts for the plants and an assessment of
the eleven-year financial projections provided by Caithness Energy.
1.2 Conclusions
On the basis of our review of the plant, of the information provided
to us, and the assumptions set forth in this report, we are of the
opinion that:
. The current operations and maintenance practices employed by FLP
Operating as operator for the plants are reasonable for operation
and maintenance of plants of this type, to maintain compliance with
all relevant environmental and other permits and approvals
required, and to produce the predicted revenues and cash flow of
the plants.
. FPL Operating, as operator, has the geothermal plant operating
experience and resources necessary to operate the plants so as to
produce the predicted revenues and cash flow of the plants.
. The 1999 operating and maintenance financial projections and
capital expenditures forecasts proposed by or on behalf of the Coso
4
partnerships for the plants are consistent with the operation and
maintenance needs of the plants, are prudent, and are reasonably
designed to produce the predicted revenues and cash flow of the
plants.
. If the plants, including power plants, wellfields and gathering
systems are maintained and operated in accordance with current
practices, and if the quality and quantity of the geothermal
resources for the plants are as projected by Caithness Coso Funding
Corporation, then the eleven year financial projections of
operating and maintenance expenditures, and of capital
expenditures, for the plants, (provided by or on behalf of
Caithness Coso Funding Corporation), are consistent with the
operation and maintenance needs of the plants. Based on these
operating assumptions, the projected revenues and cash flows of the
plants, as shown in the financial projections, are reasonable.
. All major permits and approvals required from federal, state and
local agencies for current operation of the plants have been
obtained, and all required environmental reporting is being carried
out.
. The management organization for operation of the Coso projects is
acceptable. The attention given to safety matters, and the safety
programs being implemented, are reasonable and acceptable. The
training and certification program for plant operators and
maintenance staff is acceptable.
. Assuming interest rates of 6.80% for the senior secured notes due
2001 and 9.05% for the senior secured notes due 2009, then the
debt service coverage ratios ("DSCR") will be:
For the period through 2001:
Navy I : Minimum DSCR 1.32
Average DSCR 1.32
Navy II: Minimum DSCR 1.32
Average DSCR 1.34
BLM: Minimum DSCR 1.28
Average DSCR 1.32
For the period from 2002 to 2009:
Navy I Minimum DSCR 1.50
Average DSCR 1.58
Navy II Minimum DSCR 1.53
Average DSCR 1.59
BLM: Minimum DSCR 1.49
Average DSCR 1.58
5
2. SCOPE OF SERVICES BY SANDWELL
Sandwell Engineering Inc. (Sandwell) has performed an independent
engineer's review of the Coso Geothermal Projects: Navy I, Navy II, and BLM
(the facilities). Sandwell is familiar with the technical and financial
aspects of these projects, having served as independent engineer for the
banks that initially provided construction financing for the projects in
1988, having provided an independent engineers review which was included in
the 1992 financing offering circular for Coso Funding Corporation, and
having performed annual technical and budget reviews of the projects for
ten years, to date. In preparing this report, Sandwell has obtained
information from project files and contract documents gathered over ten
years, from discussions with facility operating, maintenance, and
administrative staff, and from information and documents provided by
Caithness Energy L.L.C. (Caithness) and by FPL Energy Operating Services,
Inc. (FPLEOSI).
The scope of this review is as listed below:
. Coso Facilities overview, including:
. Description of equipment and operations
. Description of the steam gathering system
. Turbine generator failures and remedial actions
. Dow Sulferox H2S abatement systems
. Management and organization, including comments on:
. Safety
. Training
. Operating procedures
. Maintenance
. Spares inventory
. Review of FPLEOSI as operator
. Overview of power purchase agreements
. Permitting and environmental compliance
. Comments on 1999 O&M and capital expenditure budgets
. Assessment of financial projections (review of existing data provided by
Caithness).
In the preparation of this report and the opinions that follow, Sandwell
has made certain assumptions with respect to conditions which may exist or
events which may occur in the future. A listing of assumptions and
documentation relied upon by Sandwell in the preparation of this report are
given in Appendix A.
6
3. COSO FACILITIES OVERVIEW
3.1 General
The Coso Geothermal Projects consist of three separate, but
interlinked, geothermal power projects located at the U.S. Naval
Weapons Center in Inyo County, California. The three projects are
identified as Navy I, Navy II and BLM (Bureau of Land Management).
Information on the equipment and other details of each project are set
out below, but, to summarize, the three projects use a total of nine
turbine generator units to produce a net rated electrical power
generation of approximately 240 MW from high temperature geothermal
brines derived from deep production wells drilled into the geothermal
resource on which the projects are situated, which is identified as
the Coso Known Geothermal Resources Area (KGRA).
The three projects were originally operated independently, with each
project's geothermal resource feeding steam only to the generators in
that project's power block(s). In 1995 inter-project steam transfer
lines were installed which allow sharing of the resources to make
optimum use of the available steam to maximize the project revenues.
The electrical power generated by the projects is conveyed by separate
115 kV (for Navy I) and 230 kV (for Navy II and BLM) transmission
lines, approximately 28.86 miles long, to the Southern California
Edison (SCE) substation at Inyokern, California. The power generated
is purchased by SCE under long term contracts.
The power generating plants and the geothermal resource wellfields are
operated and maintained by FPL Energy Operating Services, Inc.
(FPLEOSI). Operation of the three projects as a single interlinked
group brings the benefits of economies of scale in provision of
maintenance and operating staff, and in using a common inventory of
spare parts. Responsibility for the geothermal resource is carried by
Coso Operating Company, Inc. an affiliate of Caithness Energy, who
carries out the drilling of new wells and maintenance of existing
wells.
Normal operation of the power plants for all three projects is carried
out by operators in a centralized control room located at the Navy II
power plant. A distributed control system allows all normal power
plant operations to be monitored and controlled from this point.
Local control equipment at each power plant can be used to maintain
operation in the event of a failure of the central system.
Figure 3-1 is a map that shows the location of the Coso geothermal
projects. Figure 3-2 is a more detailed map that indicates the
project boundaries and the power plant and well pad locations.
7
Regional Geothermal Activity
============================
[MAP APPEARS HERE]
Fig. 3-1
8
[Figure 3-2 map]
9
3.2 Description of equipment and operation
Navy I
------
The Navy I facility is located on the U.S. Naval Weapons Center at
China Lake and the steam resource is also located on Naval Weapons
Center property, being part of the Coso KGRA. Exploration of the
resource and utilization of its energy are secured under a 30-year
contract with the Navy (terminating in 2009, but with an option for
the Navy to extend the contract for an additional 10 years), and in
return the Navy receives royalty payments and discounted power.
The Navy I power block comprises three separate turbine generator
sets, Coso Units 1,2 and 3. The combined generating capacity of the
three units is approximately 80 megawatts (MW).
The geothermal production wells tap the geothermal resource, which is
a fractured formation of rocks heated by the heat of the earth's
interior. High-pressure water flowing through the rock formations
becomes a mixture of high temperature brine and steam as it travels up
the well bores. Pressure generated in the resource forces the mixture
to flow through the production wells into the steam gathering systems.
The brine, and the steam, from the Coso KGRA contain silica, carbonate
compounds, some metals, carbon dioxide and hydrogen sulfide. The
geothermal resource is a renewable source of energy, so long as
natural ground water flows and reinjection of extracted brine are
adequate to replenish the fluids withdrawn.
A mixture of brine and steam, under pressure from the geothermal
reservoir, is obtained at the wellhead. Piping systems transport the
two-phase flow to separators where the brine is separated from the
steam. Brine that does not flash into steam is collected and
injected back into the resource through injection wells. Returning
this water helps to maintain the characteristics of the resource for
continued power production. Two flows of steam leave the separators,
one at high pressure (approx. 90 psia) and one at low pressure
(approx. 20 psia). These relatively low steam pressures (and
temperatures) allow the use of standard wall carbon steel pipe. The
steam expands through the turbines, which drive generators to produce
electrical power. The steam gathering, and brine piping systems
associated with Navy I have metered cross-connections to the Navy II
system which allow steam and brine to be transferred between the
projects.
The Coso Unit 1 turbine generator was manufactured by Mitsubishi, and
the turbine is a single-cylinder type with high and low pressure
inlets. Coso Units 2 and 3 turbine generators, of Fuji Electric
manufacture, also have dual inlets. These units are similar in type
and configuration to Coso Units 4 through 9 located at Navy II and
BLM.
The exhaust steam from each turbine unit flows to a horizontal shell-
and-tube type surface condenser. Condenser vacuum is maintained by a
system containing steam-jet ejectors together with electrically driven
Nash vacuum pumps. There is an additional, all steam-jet ejector as a
back-up system. The noncondensible gases drawn off by the vacuum
pumps are comprised mostly of carbon dioxide but include small
quantities of hydrogen sulfide, which is carried out of the resource
with the brine and steam. Hydrogen sulfide is an environmentally
regulated substance, and the concentrations of the gas are such that
it cannot be released to
10
the atmosphere under normal operating conditions without violating
environmental permit limits. A hydrogen sulfide abatement system is
therefore required. During the early years of plant operation the
gases were compressed and reinjected into the resource along with the
brine. However, over time the gas concentrations in the steam began to
increase, reducing condenser vacuum and power generation efficiency. A
LO-CAT II abatement system was installed to treat the noncondensible
gases by a process that converts the hydrogen sulfide to elemental
sulfur, which can be sold for industrial or agricultural use. This
hydrogen sulfide abatement system is now well proven and reliable. To
ensure that permit violations do not occur in the event of a failure,
or during LO-CAT overhauls, a batch-processing abatement system, known
as the Hondo system, is also installed, and provides adequate
abatement backup. The noncondensible gas Roots blowers and TVC
compressors are also still in place and are maintained to allow
reinjection of the noncondensible gases, if necessary.
A four-cell Hamon cooling tower of mechanical draft evaporative
cooling type supplies cooling water for the surface condenser on each
unit. Condensate from the surface condenser supplies make-up water
for the cooling system, and for other plant uses.
Excess condensate is mixed with the spent brine and reinjected into
the geothermal resource.
The cooling towers are equipped with fire-protection systems fed from
a plant firemain. Diesel-driven fire pumps, supplied from a firewater
pond, provide safety system backup during plant shutdowns. The plant
fire protection systems are adequate and in line with normal practice
for this type of facility.
Navy II
-------
The Navy II facility is located on the U.S. Naval Weapons Center at
China Lake, and the steam resource is also located on the Naval
Weapons Center property. Exploration of the resource and utilization
of its energy are secured under a 30-year contract with the Navy
(terminating in 2009, but with an option for the Navy to extend the
contract for an additional 10 years), and in return, the Navy receives
royalty payments and discounted power.
The Navy II power block comprises three separate turbine generator
sets, Coso Units 4, 5 and 6. The combined nominal generating capacity
of the three units is approximately 80 MW.
Coso Units 4, 5 and 6 turbine generators are Fuji Electric units
similar to Units 2 and 3 described above. The wellfield steam
gathering system is also similar to that described for Navy I. The
steam supply systems are cross-connected with the Navy I and BLM steam
systems via metered transfer lines to allow optimum use to be made of
the available steam.
The auxiliary plant and systems for the Navy II power block are
similar to those already described for Navy I. Hydrogen sulfide
abatement is provided by a LO-CAT II unit with ample capacity to
process all the hydrogen sulfide produced when all three Units are
operating at full power output. A second, smaller, LO-CAT II unit
provides additional stand-by abatement capacity, and provides adequate
back-up
11
capacity. A back up Hondo abatement system was formerly
installed, but has now been moved to provide additional back-up
capacity at Navy I. The noncondensible gas system Roots blowers are
still in place and are maintained, but the TVC compressors at Navy II
have been removed.
As mentioned above, the central control room, from where the operation
of the Navy I, Navy II and BLM power plants is monitored and
controlled, is located at Navy II.
The plant fire protection systems are adequate and in line with normal
practice for this type of facility.
BLM
---
The BLM facility and steam resource are located on U.S. Bureau of Land
Management (BLM) property, within the boundaries of the U.S. Naval
Weapons Center at China Lake. The steam resource is part of the Coso
KGRA. Exploration of the resource and utilization of its energy is
secured under a 40-year lease with BLM (terminating in 2025), and in
return BLM receives royalty payments. Some additional steam
resources, located on property to the West and North of the Navy I and
Navy II projects, also form part of the available BLM geothermal
resource, and are designated as BLM North. Steam from BLM North will
be fed into the Navy I or Navy II gathering systems, and will be
considered to "pass-through" the Navy I and Navy II systems to
generate power in the BLM generating units.
The BLM power generating facilities comprise three separate turbine
generator sets, Coso Units 7, 8 and 9. The combined generating
capacity of the three units is approximately 80 NMW. Units 7 and 8 are
located on one power block designated BLM East, while Unit 9 is
located on a separate power block designated BLM West, located
approximately 1.3 miles west of BLM East.
Coso Units 7, 8 and 9 turbine generators are Fuji Electric units
similar to the Navy I and Navy II Fuji machines described above. The
wellfield steam supply system, and brine systems, are also similar to
those described for Units 2 through 6, and are linked to Navy II via a
metered transfer line.
The auxiliary plant and systems for the BLM East and West power blocks
are similar to those already described for Navy I and Navy II. Dow
Sulferox units provide hydrogen sulfide abatement at both plants.
These units perform the same function as the LO-CAT II equipment at
Navy I and Navy II, converting the hydrogen sulfide gas to elemental
sulfur. (Additional information about the Sulferox systems is given in
Section 3.5 below.) A back up Hondo abatement system is installed at
BLM East.
The plant fire protection systems are adequate and in line with normal
practice for this type of facility.
3.3 Description of the steam gathering system.
Steam from the production geothermal wells associated with each
project is transported by piping systems to the power plants, where it
is used to power the steam turbine generators which produce
electricity. Fig. 3-2 gives an indication of
12
the number of wells and the relative locations of the wells and power
plants. The extensive piping systems and associated equipment is known
as the steam gathering system.
The mixture of brine and steam obtained at each wellhead, under
pressure from the geothermal reservoir, is controlled by wellhead
valves. The two-phase flow of brine and steam is transported via a
piping system to a separator vessel located, in most cases, close to
the wellpad. In the separator vessel some of the hot brine flashes to
steam. The brine that does not flash to steam is collected in a
retention pond, and is eventually pumped back into the resource
through injection wells.
Steam is used at two pressures, approximately 90 psia and 20 psia.
The two pressures allow for most efficient use of all the available
steam, since some wells produce steam and brine at relatively low
pressure and temperature. Steam is transported from the separators to
the power plant turbines through insulated and metal-jacketed carbon
steel pipes. Since the steam pressures and temperatures are
relatively low, carbon steel standard wall pipe can be used.
The steam gathering systems for Navy I and Navy II have a metered
cross-connection which allows for interchange of steam between the
projects, and there is a similar metered cross-connection between
Navy II and BLM. Steam produced from East Flank Navy I wells is fed
into the Navy II gathering system, due to the geographical locations
of the wells and the piping systems. Similarly, steam from the future
BLM North production wells will be tied into the Navy I gathering
system.
The brine and steam from the resource carry silica and carbonates that
can cause scaling in the piping systems. A number of different
methods have been used to remove scale, including passing a "pig" (a
cleaning device) through the piping system, and "hydroblasting" which
removes the scale with high pressure water jets. Acidification of the
liquid phase (i.e. the brine) has been tested at Coso as a means of
mitigating scaling, and FPLEOSI plans to continue using this method of
scale control. Acidification for scale control has been successfully
used at other geothermal projects and it is reasonable to expect that
it will be successful at Coso. Other parts of the gathering system
also require regular maintenance, including the valves at wellheads,
and elsewhere in the piping systems, separator vessels (which tend to
corrode due to the corrosive/erosive action of the brine and steam),
and the instrumentation and control equipment necessary to monitor and
control the gathering system operation.
From observation of the gathering system and wellpads, it is our
opinion that the system is well maintained and in line with the normal
practices of the industry. Wellheads and valves are painted, there are
very few steam leaks, and the insulation and jacketing on the piping
systems is in good repair.
3.4 Turbine generator rotor failures, Unit 1 generator failures, and
remedial actions.
During a normal scheduled overhaul of the Fuji turbine generator Unit
9 in the spring of 1993 (when the unit and the rotor had been in
service for 4 years), cracks were found in the rotor blade roots and
wheel steeples at the second from the last (L-2) stage. Evaluations
by various parties led to consensus that corrosion fatigue was
involved, but there was uncertainty as to the exact cause. It was
agreed that
13
the corrosive, high sulfur, geothermal steam environment was probably
a factor, and that blade resonance was also probably involved. This
rotor was repaired and rebuilt to the original Fuji design.
During routine overhaul of Unit 8 in the spring of 1997, similar blade
root and wheel steeple cracking was found in the L-1 and L-2 stages of
the rotor. At this time, this rotor had been in service for 8 years.
The Partnerships made the decision to repair this rotor incorporating
modifications to the design which had been evolved in conjunction with
TurboCare, a specialist turbine repair company. Modifications
included replacing the turbine blades in these two stages with
titanium blades incorporating a modified root designed to reduce peak
stresses and increase fatigue life, shrouding the L-2 blades to reduce
resonance, tuning the diaphragms to reduce blade resonance stimulus,
and repairing the rotor wheels with 12 - chrome material for better
corrosion resistance.
In March 1998 a failure occurred in Unit 9, when a blade from the L-2
stage was thrown off during operation and caused damage to other parts
of the turbine. It should be noted that this rotor was not the same
one that had previously shown cracking after service in Unit 9, as the
spare rotor had been installed at that time. It was determined that
the failure had occurred due to the same type of cracking as had been
found previously. This rotor was rebuilt, incorporating the
modifications already described, and the Partnerships made the
decision to rebuild all the Fuji rotors to the modified design as
scheduled overhauls took place. To date, three rotors have been
rebuilt and installed, one is being modified and will be returned to
Coso as the current spare in early April 1999, and five rotors remain
to be modified in the future. The modifications appear to have been
successful, in that no cracking or other defects in the modified
rotors have been reported to us.
The schedule for modification of the remaining five Fuji rotors is as
follows:
Unit 4: May 1999
Unit 6: October 1999
Unit 3: January 2000
Unit 7: May 2000
Unit 8: October 2000
The costs of these modifications (approximately $1,350,000 per rotor)
have been included in the eleven-year financial projections.
Sandwell has observed and monitored these rotor failures, and the
proposed and implemented solutions, since 1993. In our opinion, the
management and staff at Coso have handled this matter in an exemplary
manner throughout, showing a high level of engineering expertise while
making management decisions designed to maintain operation of the
plant and maximize revenues. We conclude that these modifications are
an acceptable means of preventing the cracking as previously reported.
In our opinion, these modifications were required to minimize the
possibility of future rotor failures, and the decision by the
Partnerships to modify all the Fuji rotors was reasonable and prudent.
We understand that the Partnerships are in litigation with Fuji, the
rotor designers and manufacturers, claiming costs associated with the
failures and the modifications as warranty items. Fuji has not made
any counter-claim, and the financial forecasts reviewed have not
included any amounts that may be received from Fuji in the future.
14
A completely separate failure, affecting the Mitsubishi Unit 1
generator, occurred on 3 January 1999, when a stator coil ground fault
caused the unit to shut down automatically. It was subsequently
determined that the wedges holding the stator coils had loosened,
allowing the coils to move slightly, penetrating the coils' insulation
and eventually causing the ground fault. This unit had been in
service since 1987, and has been regularly inspected and overhauled.
Reports of the last overhaul inspection in 1995 had noted no damage or
other significant findings. The stator has been rewound by a reputable
repair shop incorporating modifications designed to prevent
recurrence of the wedge loosening. This repair was necessary, and the
decision to incorporate modifications was reasonable and prudent.
Unit 1 was scheduled to return to service on 23 March 1999, but latest
reports indicate that electrical faults recurred during start-up of
the generator. As it appeared the electrical faults that occurred
during start-up after the repair may have been due to faulty
workmanship by the repairer, the Partnerships chose to use a different
repair shop to carry out the latest repairs to the generator. It is
anticipated that the generator will be back in service in 5 - 9 weeks.
In our opinion, this duration is reasonable for this type of repair.
It is reported that the equipment repairs and any additional downtime
will be fully insured, the insurance deductibles (25 days business
interruption, and $500,000 for the equipment) having already been
satisfied for this incident, so there will not be any further impact
on project revenues. In our opinion this failure could not have been
foreseen, nor prevented, by the operators, and the subsequent actions
and decisions by Coso management and staff have been designed to
minimize the potential loss of revenues involved.
3.5 Dow Sulferox H2S abatement systems.
The BLM East and BLM West units were modified at the direction of Dow
Chemical, and per Coso Operating Company's technical specification.
The modified units were placed back into service at the beginning of
the first quarter of 1999. Currently, the units are operating as
expected with less operator intervention and less maintenance than
before the modifications were made. Longer-term operations are needed
to fully determine the benefits of the modifications.
The modifications were intended to mitigate poor operating
efficiencies related to each unit that included:
. High chemical consumption
. Low equipment availability
. High pluggage rates
. Poor process controllability
The modifications to both units included installation of:
. Redesigned sparged contactor vessels
. Redesigned stack mist eliminators
. Improved chemical storage facilities
. Upgraded control systems and logic
. Backup capabilities to the old pipeline contactor vessels and
separators
. Improved continuous emissions monitoring (CEM) systems
15
Remaining remedial work includes plant cleanup of chemical over spray
from previous operations. Future consumption and costs of the
chemicals are fixed under an agreement with Dow Chemicals Company.
In our opinion these modifications to the Sulferox units were required
to improve the efficiency of operation and reduce cost. The decision
to proceed with the modifications was reasonable and prudent.
16
4.0 MANAGEMENT AND ORGANIZATION
4.1 General
The Coso projects were formerly operated and maintained by CalEnergy
Company Inc. (CECI) under O&M Agreements with China Lake Operating
Company (CLOC), Coso Technology Corporation (CTC) and Coso Hotsprings
Intermountain Power (CHIP), the Managing General Partners of the Navy
I, Navy II and BLM plants, respectively. CECI also operated and
maintained the 230 kV and 115 kV transmission lines, and was
responsible for maintenance of the geothermal resource, including
drilling of new wells, well workovers, etc.
From 26 February 1999, CECI ceased to be the operator of the projects,
and FPL Energy Operating Services, Inc. (FPLEOSI) assumed that role.
Amended and Restated O&M Agreements between FPLEOSI and the Managing
General Partners, now known as New CLOC, New CTC and New CHIP, were
implemented. FPLEOSI also took over operation of the transmission
lines. Under the new arrangements, Coso Operating Company, Inc, an
affiliate of Caithness Energy became responsible for maintenance of
the geothermal resource.
Most of the Coso projects operating, maintenance and management staff
transferred from CECI to FPLEOSI when the transition of ownership and
operating company occurred. It was reported that the CECI Coso
Projects General Manager will become the Production Manager in the
FPLE organization, reporting to FPLEOSI's Plant General Manager, who
will have responsibilities for other geothermal plants in addition to
Coso. FPLEOSI's West Region organization operates out of a regional
office in Livermore, California, with responsibility for all
operations of the FPL Energy geothermal plants in the region. In our
opinion, the proposed management organization for operation of the
Coso Projects is typical for facilities of this type and is
acceptable.
From conversations with FPLEOSI's Coso management, it appears that
significant change in the organization and staffing of the projects is
unlikely in the short term. In the future, FPLEOSI will seek to
improve the efficiency and profitability of the projects, as it has
done with the other FPLEOSI geothermal plants. FPLEOSI resources and
staff expertise are available to assist in efficient operation of the
projects.
4.2 Safety
CECI had an established safety program for the projects, which was
based on a Safety Manual and safety procedures which were considered
to be consistent with general industry practices. However in the
first quarter of 1998 the number of OSHA Recordable Injuries increased
sharply, compared to comparable statistics for the previous three
years, and this led CECI management to implement the "Coso Safety
Recovery Plan", which addressed the causes of the accidents that had
occurred and also sought to increase the general safety awareness of
the staff. This plan included daily tailgate safety meetings, Job
Safety Analyses and documented pre-job safety planning for high-risk
and new jobs, an increased number of formal safety meetings, increased
safety training, etc. These actions were an indication of the high
priority given to safety by CECI's local management.
17
The same management, operating, maintenance and support personnel are
continuing to operate the projects under FPLEOSI management direction,
and it is anticipated that the existing emphasis on proper safety
procedures and safety awareness will also continue, and will even be
enhanced by additional input from FPLEOSI. FPLEOSI management makes
safety a priority and has initiated an aggressive safety policy
designated the "Safety 2000 Program". The stated objective of this
plan is to achieve zero injuries by the year 2000. In 1997, the six
plants operated by FPLEOSI had 13 OSHA Recordable Injuries (with
contractors included); in 1998 the same six plants reduced the number
of recordable injuries to eight, a 38% improvement.
The attention given to safety matters, the safety programs being
implemented, and the results achieved to date, appear to be in line
with the standards normally found in the power industry and are
acceptable.
4.3 Training
CECI had, for several years, actively supported a program for training
and certification of operators and maintenance personnel at the
projects. The comprehensive program provides training materials,
testing and certification for five classifications of operators. This
training and certification program appears to be similar to those
normally found in the power industry and is acceptable.
FPLEOSI has not announced any proposed changes to the training and
certification procedures. FPLEOSI management has stated a general
commitment, to develop a multi-functional, team-driven and flexible
work force where employees are well-trained, involved, engaged and
accountable to meet and/or exceed plant performance objectives. It
therefore appears probable that the established training programs will
be continued, and may be enhanced, by FPLEOSI. If, as implied,
"cross-training" of staff takes place in the future, this can be
expected to improve the overall productivity of the personnel.
4.4 Maintenance
At present, as under the former CECI management, maintenance
activities are under the direction of a Maintenance Manager, and a
staff of qualified technicians performs normal maintenance activities.
Maintenance activities for the projects are scheduled and recorded
using a computerized system that produces detailed work orders for
planned and requested plant maintenance and repair activities, and is
also linked to the spare parts inventory and procurement system.
Specialized maintenance and repairs, such as turbine generator
overhauls, are performed by outside contractors, assisted by CECI
staff. Major equipment overhauls are scheduled by the Maintenance
Manager (with management approval) to ensure maximum availability
during periods of peak power demand. The normal practice has been to
schedule major turnarounds of one or more turbine generator units,
together with associated maintenance and cleaning of associated
auxiliary equipment and systems, in the spring of each year, in
preparation for the summer peak demand period. These major
turnarounds are generally scheduled to last ten to twelve days. As
mentioned in 3.4 above, the need to preclude possible Fuji turbine
rotor failures has required some additional major unit turnarounds to
be scheduled in 1998 and 1999. Short two to three day outages of
additional units, for
18
minor repairs, are usually also scheduled during the same pre-peak
periods. The availability of the plants has historically been very
high, demonstrating the effectiveness of the maintenance and overhaul
scheduling practices.
It is not anticipated that any immediate changes in these procedures
will be made by FPLEOSI. In the long term, it appears that the
availability of additional resources from within FPLEOSI is likely to
further improve the reliability and availability of the plant.
Sandwell's independent engineer's reviews of the plants, wellfields
and transmission lines during numerous site visits over ten years have
consistently reported the facilities to be clean and well maintained
and in line with the general standards of the industry.
4.5 Spares Inventory
Availability of spare parts and materials needed for maintenance and
repairs is reported to be satisfactory. Review of the spare parts
Inventory Catalog dated 2 March 1999 showed an acceptable inventory
level in line with what we would expect for facilities of this type.
The spare parts are properly stored and catalogued for quick retrieval
when required. Agreements with some material suppliers (notably the
well-casing supplier) to hold certain quantities of materials in stock
have allowed inventory levels at the projects to be reduced, with a
corresponding reduction in cost.
A single extra Fuji turbine rotor has been held as a common spare for
the eight Fuji units. Due to the plans for modification of the
turbine rotors (as described in 3.4 above) as each unmodified rotor is
changed out for a modified one, in accordance with the planned outage
schedule, the unmodified rotor becomes the spare, and may not be
immediately available while the modifications are carried out in the
turbine specialist's workshop. This period is not expected to exceed
seventy days, and although five rotors remain to be modified, the
probability of any significant loss of revenue for this cause is low,
in our opinion.
4.6 Review of FPLEOSI as operator
In preparing this report Sandwell has reviewed information supplied by
FPLEOSI and has also interviewed FPLEOSI management staff. FPL Energy
Operating Services was formed in 1997 to provide operating and
maintenance (O&M) services for generating plants owned by FPL Energy.
FPLEOSI is part of Florida Power & Light's Power Generation Business
Unit, which gives FPLEOSI access to the processes, skills and
experience of the parent company's many years of experience on
operation and maintenance of power generating plants. FPL Energy has
been associated with the Coso Projects from their inception, as one of
the partners in ownership of the Navy I project. FPLEOSI already
successfully operates five other geothermal power generation projects
in California and Nevada (Brady Units 1 & 2, Calistoga, Green Ridge,
East Mesa, and Posdef), and has a stated commitment to maximize the
profitability of each project in a safe and environmentally sound
manner. FPLEOSI's West Regional Office in Livermore, California,
provides support in resources and talents which can be shared among
the Western facilities. This regional concept should provide savings
for all the
19
facilities involved, by having team members functionally accountable
across several sites, providing the optimum level of service to each
plant, on an "as needed" basis.
In a document entitled "FPL Energy Operating Services Performance
Story" it is stated that:"FPLEOSI focuses on the objectives of
safety, environmental, operational excellence, and economic value in
providing its O&M services. Safety is a priority of FPLEOSI
management, which pursues an aggressive safety policy. Responsible
environmental stewardship aims at increasing the value of each project
by minimizing the incidence of Notices of Violation. Operational
excellence focuses on continuous improvement of the skills, knowledge
and competencies of each individual member of the staff, so as to
improve the overall productivity of the workforce. The economic value
of each project is maximized by finding ways to continuously improve
the total cost performance and availability of each generating unit;
results quoted for the six FPLEOSI West Region geothermal plants in
1997 and 1998 indicate significant reductions in O&M costs and "best-
in-class" availability performance since FPLEOSI took over the
operation of the plants."
20
5.0 OVERVIEW OF POWER PURCHASE AGREEMENTS, ETC.
Power Purchase Agreements
The Coso partnerships sell 100% of their net electrical energy to SCE
pursuant to three separate 30-year California Standard Offer No. 4
power purchase agreements. Each Power Purchase Agreement is
independent of the others, and the performance requirements included
in one such agreement apply only to the facilities owned by the Coso
partnership which is a party to that Agreement. Under these Power
Purchase Agreements, the Coso partnerships receive capacity payments
for being able to produce electricity at certain levels, capacity
bonus payments if they are able to produce above a specified higher
level and energy payments based on the amount of electricity they
actually produce. The capacity and capacity bonus payment rates are
fixed throughout the terms of the Power Purchase Agreements and the
energy payments are fixed for the first ten years of the Power
Purchase Agreements.
After the ten-year fixed price period expires, the Coso partnerships
sell electricity to SCE based on SCE's "Avoided Cost of Energy", or
SCE's cost to generate electricity if SCE were to produce it itself or
buy it from another power producer rather than buy it from the Coso
partnerships. SCE has taken the position that the fixed energy price
period under the Power Purchase Agreements expired in August 1997 at
Navy I and March 1999 at BLM. The fixed energy price period at Navy II
will expire in early 2000. The Power Purchase Agreements for Navy I,
BLM and Navy II expire in August 2011, March 2019 and January 2010,
respectively.
Subsidy payments
In addition to these contracted payments, the Coso Projects qualify
for subsidy payments legislated under California Assembly Bill 1890
("AB1890") because geothermal energy has been classified as a
renewable source of energy. AB1890 provides for these payments through
the end of 2001.
Capacity payments
The Coso projects also qualify for Capacity payments. A plant
qualifies for an annual capacity payment by meeting specified
performance requirements on a monthly basis during an approximately
four-month long on-peak period, which currently runs during the months
of June through September of each year. The basic performance
requirement is that the Plant deliver an average kWh output during
specified on-peak hours of each month in the on-peak period at a rate
equal to at least an 80% Contract Capacity Factor. The "Contract
Capacity Factor" equals (1) a Plant's actual electricity output,
measured in kWhs, during the hours of measurement, divided by (2) the
product obtained by multiplying the Plant's "Contract Capacity," as
stated in the SO4 Agreement applicable to such Plant, by the number of
hours in the measurement period. If a Plant maintains the required 80%
Contract Capacity Factor during the applicable periods, the annual
capacity payment will be equal to the product of the capacity payment
per kWh stated in the SO4 Agreement and the Contract Capacity.
21
The Navy I Plant has a Contract Capacity of 75 MW, and a capacity
payment per kW year of $161.20, for an annual maximum capacity payment
of $12,090,000. The BLM Plant and the Navy II Plant each have a
Contract Capacity of 67.5 MW, and capacity payments per kW year of
$175.00 and $176.00, respectively, yielding annual maximum capacity
payments of $11,812,500 and $11,880,000, respectively. Although
capacity prices per kWh remain constant throughout the life of each
SO4 Agreement, capacity payments are disbursed by SCE on a monthly
basis in accordance with a tariff schedule filed with the CPUC.
Payments are made unevenly throughout the year, and are weighted
toward the on-peak periods; currently, approximately 84% of the
capacity payments received by the Partnerships from SCE are paid in
respect of on-peak months, and approximately 16% in respect of non-
peak months. As of the end of the 1992 on-peak season, each of the
Plants earned, for the first time, the maximum capacity payments
available under its respective SO4 Agreement for the on-peak months
and has continued to earn the maximum capacity payment in each year up
to and including 1998.
Capacity bonus payments
Each Partnership is entitled to receive capacity bonus payments during
both on-peak and non-peak months by operating at a Contract Capacity
Factor of between 85% and 100% during on-peak hours of each month. A
Plant qualifies for capacity bonus payments in respect of on-peak
months provided the Plant operates at least at an 85% Contract
Capacity Factor during the on-peak hours of the month, and qualifies
in respect of non-peak months if performance requirements for on-peak
months have been satisfied and the Plant also operates at a Contract
Capacity Factor of at least 85% during on-peak hours of the non-peak
month. Capacity bonus payments for each month increase with the level
of kWhs delivered between the 85% and 100% Contract Capacity Factor
levels during the month. The annual capacity bonus payment for each
month is equal to a percentage based on the Plant's on-peak Contract
Capacity Factor (which percentage may not exceed 18% of the annual
capacity payment). All the plants have received the maximum capacity
bonus payments since 1992, except for Navy I in 1998. In 1998, Navy I
did not receive the maximum bonus because overall project performance
was optimized by diverting steam to those projects which were still
operating on the ten-year fixed energy price agreements. Once the
ten-year fixed energy price agreement period has expired for all the
projects, it is projected that all the plants will receive the maximum
capacity bonus during the eleven-year period through 2009.
Energy payments
The energy price component for all electricity delivered to SCE is
subject to a different pricing mechanism during the first 10 years of
each SO4 Agreement than is applicable during the remaining term of
each agreement. During the first 10 years following the commencement
of firm power delivery, the energy price per kWh varies between so-
called "on-peak" and "non-peak" periods, but the average of these
prices equals a fixed price per kWh specified in the SO4 Agreements.
SCE has taken the position that this period ended in August 1997 for
the Navy I Partnership, and will end in March 1999 for the BLM
Partnership and January 2000 for the Navy II Partnership. Based on
CPUC precedent and the circumstances surrounding the execution of the
Navy II and the BLM Partnerships' SO4
22
Agreements, management of the Partnerships believes that the energy
prices in 1999 and 2000 will be at least 14.6 cents per kWh, but not
more than 15.6 cents per kWh and 16.6 cents per kWh, respectively.
After the initial 10-year period under each SO4 agreement expires, the
energy price paid for electricity delivered under the agreement will
be based upon SCE's short-run Avoided Cost, which is currently
determined and published from time to time by the CPUC.
23
6.0 PERMITTING AND ENVIRONMENTAL COMPLIANCE
Sandwell has reviewed copies of the major permits and approvals
required from federal, state and local agencies for current operation
of the facilities. Copies of relevant permits and approvals have been
in Sandwell's files during our ten years or involvement with the
projects as independent engineer, and we have recently received updated
lists and copies from FPLEOSI.
The U.S. Naval Air Weapons Station (NAWS) and the U.S. Bureau of Land
Management (BLM) have issued permits to the Partnerships for the
projects, including Utilization Permits for the design, construction
and operation of the Projects and Geothermal Drilling Permits for the
geothermal wells drilled. Representatives of NAWS and BLM have
verbally represented to us that the projects have all the permits
required for current operations, that all the permits are currently in
force, and that they are not aware of any violations or defaults.
State and local air quality regulations affecting the projects are
administered by the Great Basin Unified Air Pollution Control District
(GBUAPCD). GBUAPCD has issued to each project the Authorities to
Construct (ATOs) and Permits to Operate (PTOs) for equipment (including
two above-ground gasoline storage tanks )producing emissions to the
atmosphere. Air monitoring under the permits is performed
automatically with the use of remote data gathering systems. The
projects self-report to GBUAPCD any instances of emissions exceeding
the permit limits. A Title V operating permit application for the
projects was submitted to GBUAPCD in May 1996, and effectively
functions as the operating permit pending final action by GBUAPCD.
Representatives of GBUAPCD have verbally represented to us that no
other air quality permits are required for the current operations of
the projects.
Certain air permit violations have occurred at the projects, and the
GBUAPCD issues Notices of Violation (NOVs) when GBUAPCD rules or permit
violations occur. Our experience has been that the majority of NOVs in
recent years have been related to equipment failures or operator errors
which result in venting of hydrogen sulfide to the atmosphere. A
single equipment breakdown incident may not result in issue of an NOV,
but if more than three breakdowns in a single category of equipment
occur within a twelve month period an NOV will be issued. Not all
violations result in action by the GBUAPCD, and not all NOVs result in
the levy of fines. NOVs issued within the last two years, and fines
levied, have been as follows:
Project NOVs Fines ($)
------- ------ ---------
1997: Navy I 4 8,000
Navy II 7 24,000
BLM 12 38,000
1998: Navy I 5 34,000
Navy II 1 3,000
BLM 9 11,000
24
Water quality at the projects is under the regulatory control of the
Lahontan Regional Water Quality Control Board (LRWQCB). Waste
Discharge Requirement Permits (WDRs) for the projects were issued and
are reported by FPLEOSI to cover all current waste discharge
activities. FPLEOSI has also reported that a national pollution
discharge elimination system (NPDES) permit is not required because
there are no discharges into navigable waters. Representatives of
LRWQCB have verbally represented to us that the projects have all the
permits that are required for current operations, that all the permits
are currently in force and that they are not aware of any violations
or defaults.
The projects generate hazardous wastes and must obtain a hazardous
waste generator identification number from the U.S. Environmental
Protection Agency (EPA). This number has been obtained and we believe
that all hazardous wastes continue to be handled, stored and disposed
of in accordance with regulations.
In Sandwell's opinion, all the appropriate regulatory approvals and
permits for current operation of the facilities are in place. We also
believe that all required environmental reporting is being carried
out.
Sandwell is not aware of any other existing or potential environmental
hazards which might impact future operation or profitability of the
facilities. It is not anticipated that the number of NOVs will
increase in the future, unless significant changes occur in the permit
requirements. If proper operation and maintenance of the hydrogen
sulfide abatement systems continues, and the facilities continue to be
operated in compliance with normal industry practices, there should
not be any environmental deficiencies or limitations.
25
7.0 COMMENTS ON 1999 O&M FINANCIAL PROJECTIONS AND CAPITAL
EXPENDITURE FORECAST
Sandwell has reviewed the Coso 1999 financial projections for operating and
maintenance expenses of each project, and for the three projects combined.
A comparison of major line items was also made with the CECI budgets
reviewed in October 1998 and the actual expenditures in 1998 and 1997. The
financial projection figures are consistent with the known costs of plant
operation and maintenance and reflect the best available information. The
documents reviewed are listed in Appendix B.
Sandwell has also reviewed the 1999 Capital Expenditure Forecast dated
3/16/99, and has compared this to the projects' budget capital expenditure
figures reviewed in October 1998. The expenditures proposed reflect major
overhaul schedules and the costs of turbine generator rotor repairs. The
documents reviewed are listed in Appendix B.
We find that the operating and maintenance financial projections and the
capital expenditure forecasts proposed by FPLEOSI and Caithness Energy are
consistent with the operation and maintenance needs of the facilities, are
prudent, and are reasonably designed to produce the predicted revenues and
cash flows of the facilities.
26
8.0 ASSESSMENT OF FINANCIAL PROJECTIONS
8.1 General
Sandwell reviewed the financial projections model provided by
Caithness, which contains an eleven-year projection, beginning in
1999, of revenues, expenses, initial and long-term expenditures,
royalties, capital additions, and cash flows. The financial model
predicts the financial performance of each project and consolidates
the results to measure aggregate debt service coverage. A copy of the
document reviewed is included in Appendix C.
Assumptions on which the financial model is based include information
related to the quantity and quality of the geothermal resources for
the facilities and the predicted decline in resource availability's
from different parts of the wellfields.
8.2 Power availability and production
The steam produced by the geothermal resource associated with each
project is shared between the projects to make optimum use of the
available steam and to achieve projected overall project revenues.
From the information provided by Caithness, the projected annual
average power available for each project over eleven years from 1999,
based on optimum sharing of the available steam and the projected
average annual power delivered by each project, are as shown in Table
8-1. The general trend is for the project power available to decline
over time, due to the corresponding decline in the geothermal
resource. This trend may be reversed for short periods, on individual
projects, when additional steam-producing wells are brought on line,
or when the amounts of steam transferred between projects are changed
to optimize performance. On the basis of the information given by
Caithness regarding the quality and quantity of steam from the
resource, in our opinion, the assumptions made concerning the
projections of power available and power delivered are reasonable.
Table 8-1
Year Project Power Available (MW) Project Power Delivered (MW)
- ------------------------------------------------------------------------------------------------------------------------
Navy I Navy II BLM Total Navy I Navy II BLM Total
- ------------------------------------------------------------------------------------------------------------------------
1999 94.26 81.75 96.97 272.98 89.05 88.84 88.86 266.75
- ------------------------------------------------------------------------------------------------------------------------
2000 91.45 80.44 96.84 268.72 88.09 89.52 86.91 264.52
- ------------------------------------------------------------------------------------------------------------------------
2001 88.80 78.34 100.43 267.56 90.07 88.15 86.38 264.60
- ------------------------------------------------------------------------------------------------------------------------
2002 86.30 77.60 103.52 267.41 90.07 88.21 86.04 264.31
- ------------------------------------------------------------------------------------------------------------------------
2003 83.93 81.55 102.58 268.06 90.07 88.32 86.59 264.98
- ------------------------------------------------------------------------------------------------------------------------
2004 81.69 77.81 108.00 267.50 89.05 86.89 86.07 262.02
- ------------------------------------------------------------------------------------------------------------------------
2005 79.57 74.40 114.01 267.98 88.09 88.32 86.53 262.94
- ------------------------------------------------------------------------------------------------------------------------
2006 77.56 71.27 118.32 267.15 90.07 88.24 85.84 264.14
- ------------------------------------------------------------------------------------------------------------------------
2007 75.64 68.39 118.19 262.22 90.07 85.23 83.86 259.16
- ------------------------------------------------------------------------------------------------------------------------
2008 73.82 65.74 112.91 252.47 90.07 80.55 78.90 249.52
- ------------------------------------------------------------------------------------------------------------------------
2009 72.08 63.29 108.10 243.47 87.18 74.36 79.08 240.63
- ------------------------------------------------------------------------------------------------------------------------
27
8.3 Revenues
The projected revenues for each project are based upon the resource
availability information provided by Caithness and by Geothermex, the
independent geothermal engineer, and the power purchase agreements
with Southern California Edison Company, which purchases all the power
generated by the projects. Geothermex, in their report, express the
opinion that the projections of resource availability and projected
revenues are reasonable. Henwood Energy Services prepared the
forecasts of future electric energy prices used in the financial
projections. Henwood's forecasts considered the base case and also two
alternate cases, namely the "Low Gas Case" (using a gas price 10%
lower than for the base case) and the "Low Gas Case 2" (using a gas
price 15% lower than for the base case). The lower gas prices would
result in correspondingly lower electrical energy prices. The
financial projections model was used to project figures for the base
case and also in performing a sensitivity analysis to examine the
ability to maintain debt coverage levels under the two low gas cases.
The financial projections for the three cases are summarized in
Appendix C to this report.
Additional factors used in arriving at the net revenues include
revenue generated by steam "shared " from the other projects. The
components of revenue, as mentioned in Section 5.0 above, include
Capacity Payments and Capacity Bonus payments, in addition to the
Energy Payments. The net revenues for each project, projected over
eleven years from 1999, have been calculated by Caithness, and are
shown in Table 8-2 below (for the base case). In our opinion the
assumptions made in projecting these net revenues are reasonable.
Table 8-2
Year Net Annual Revenue ($000s)
- ----------------------------------------------------------------------------------------------------------
Navy I Navy II BLM
- ----------------------------------------------------------------------------------------------------------
1999 51,629 123,341 47,459
- ----------------------------------------------------------------------------------------------------------
2000 43,881 40,885 33,917
- ----------------------------------------------------------------------------------------------------------
2001 43,683 37,255 35,771
- ----------------------------------------------------------------------------------------------------------
2002 45,088 38,974 38,149
- ----------------------------------------------------------------------------------------------------------
2003 46,241 41,052 39,886
- ----------------------------------------------------------------------------------------------------------
2004 47,267 40,965 41,268
- ----------------------------------------------------------------------------------------------------------
2005 48,661 42,752 44,694
- ----------------------------------------------------------------------------------------------------------
2006 49,672 42,803 47,069
- ----------------------------------------------------------------------------------------------------------
2007 49,536 41,710 48,083
- ----------------------------------------------------------------------------------------------------------
2008 49,234 39,699 48,027
- ----------------------------------------------------------------------------------------------------------
2009 49,830 39,011 47,429
- ----------------------------------------------------------------------------------------------------------
28
8.4 Operating and maintenance expenses
FPLEOSI is now operator of the projects under O&M agreements with each
project owner. The previous operator, CECI, had prepared operating
and maintenance budgets for 1999, which were reviewed by Sandwell, as
independent engineer, in October 1998. As indicated in Section 7
above, these budgets have been subsequently revised, and Sandwell has
again reviewed the revised budgets.
The eleven-year financial model includes projected operating and
maintenance expense figures for each project. Sandwell has reviewed
these figures and believes them to be reasonable, on the basis of past
experience with the projects, and the stated intentions of FPLEOSI to
continue with improvements to the efficiency and profitability of
operation. FPLEOSI's record in maximizing the profitability of other
similar geothermal generating plants supports the belief that the
projections are reasonable.
A significant additional expense in operating these facilities is the
royalty payments payable to the U.S. Navy and to BLM for use of the
geothermal resources.
8.5 Capital expenditures
The eleven-year financial model includes projected capital
expenditures for each project. Items include projected expenditures
for plant overhauls, resource well drilling, workovers, etc. Sandwell
has reviewed these projected expenditures and believes them to be
reasonable, on the basis of past experience with the projects and
reported actual expenditures in past years. The schedule for the
capital expenditures over the eleven-year period also appears to be
reasonable, based on past experience and the ongoing planned schedules
of plant overhauls, well drilling and workovers.
8.6 Escalation
Where relevant, expenses in the eleven-year financial projections have
been escalated at an assumed rate of 3.0 percent.
8.7 Cash flow
The financial projections prepared by Caithness includes projections
of cash flow for each project over eleven years from 1999. Total
projected operating expenses, royalty payments, capital expenses,
etc., are subtracted from the project operating income to determine
the cash flow available for debt service. The minimum and average
debt service coverage ratios for each project from 1999 to 2009 are as
follows:
For the period through 2001:
Navy I: Minimum DSCR 1.32
Average DSCR 1.32
29
Navy II: Minimum DSCR 1.32
Average DSCR 1.34
BLM: Minimum DSCR 1.28
Average DSCR 1.32
For the period from 2002 to 2009:
Navy I: Minimum DSCR 1.50
Average DSCR 1.58
Navy II: Minimum DSCR 1.53
Average DSCR 1.59
BLM: Minimum DSCR 1.49
Average DSCR 1.58
The cash flow projections for each project are included in the
financial projections in Appendix C.
30
APPENDIX A
PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS
In the preparation of this report and the opinions given, Sandwell has made
certain assumptions with respect to conditions which may exist or events which
may occur in the future. While we believe these assumptions to be reasonable
and customary for the purposes of this report, they are dependent upon future
events, and actual conditions may differ from those assumed. In addition, we
have used and relied upon certain information provided to us by sources which we
believe to be reliable. We believe the use of such information and assumptions
is reasonable for the purposes of our report. However, some assumptions may
vary significantly due to unanticipated events and circumstances. To the extent
that actual future conditions differ from those assumed herein, or provided to
us by others, the actual results will vary from those forecast. This report
summarizes our work up to the date of this report. Thus, changed conditions
occurring or becoming known after such date could affect the material presented
to the extent of such changes.
Opinions of financial evaluations, technical, and economic analyses, and
utilitarian considerations of operations and maintenance costs prepared by
Sandwell herein are made on the basis of our experience and qualifications and
represent our best judgment as experienced and qualified professional engineers.
It is recognized, however, that Sandwell does not have control over the quality
or quantity of the geothermal resource or over the cost of labor, material,
equipment, or services furnished by others or over market conditions or
contractors' and vendors' methods of determining their prices, and that
Sandwell's evaluation of future facility operations and maintenance or work to
be performed must, of necessity, be speculative. Accordingly, Sandwell does not
guarantee that actual costs will not vary from the opinions and evaluations we
have prepared herein.
In preparation of this report, we have reviewed work prepared by others and have
not prepared any original engineering products. We have reviewed certain
documents for engineering issues and their possible impact on commercial issues.
We have not addressed legal or regulatory issues associated with the projects,
nor the impact of legal or regulatory issues on commercial issues. In the
course of ten years' association with the Coso projects as independent
engineers, we have regularly visually inspected all units on all three
projects, all well pads, all gathering and injection pipelines and the
electrical transmission lines. We have done no form of investigation,
inspecting or testing to ascertain the existence of latent problems, flaws, or
defects. Although our most recent site inspection did not identify any
problems, flaws, or defects, any statements made in this report relating to the
physical condition of the facilities is totally based upon a review of
information contained in our files gathered over ten years, and upon visual
observations made during visits to the site of the facilities. Visits have been
made by one or more professional engineers with experience in a wide variety of
electrical power generation projects.
The principal conditions and assumptions made by us in developing the
conclusions and the principal information provided to us by others include the
following:
1. As Independent Engineer, we have made no determination as to the validity
and enforceability of any contract, agreement, rule, or regulation
applicable to the facilities or their operations. However, for the purposes
of this report, since these are operating facilities, we have assumed that
all such contracts, agreements, rules, and regulations are
31
fully enforceable in accordance with their terms and that all parties will
continue to comply with the provisions of their respective agreements.
2. Certain information used in performing our review, specifically that
related to the quantity and quality of the geothermal resources for the
facilities, was provided by others and relied upon by us. We have relied
upon the analyses and projections of geothermal resources provided to us,
and believe the use of such information is reasonable for the purposes of
this report. In particular, we have relied upon the predictions by
Geothermex that the corrosive and scaling nature of the steam from the
resource will not deteriorate.
3. The operator will continue to maintain the facilities in accordance with
good engineering practice, will continue to make all required renewals and
replacements in a timely manner, and will continue to operate the equipment
in a manner consistent with equipment manufacturers' recommendations and
the normal practices of the industry.
4. The operator will continue to employ qualified and competent personnel who
will properly operate and maintain the equipment in accordance with the
manufacturers' recommendations and generally accepted engineering practice
for the industry, and will generally operate the facilities in a sound and
businesslike manner.
32
APPENDIX B
DOCUMENTS REVIEWED
Documents reviewed by Sandwell while preparing this report included:
1. Permits, etc:
Great Basin Unified Pollution Control Permits:
Listing of current permits for Navy I, Navy II and BLM
California Regional Water Quality Board - Lahonton Region:
Listing of current Board Orders for Navy I, Navy II and BLM
California Energy Commission :
Listing of current Orders and Decisions for Navy I, Navy II and BLM
Federal Energy Regulatory Commission:
Recertification orders for Navy I, Navy II and BLM
2. Drawings:
Coso Operating Company - Coso Geothermal Project
Gathering, Injection and transfer systems.
Coso Operating Company.
Drawing showing Navy contract lands and Coso KGRA leases
3. Coso Operating Company - Operating Expenses
Actual and budget figures for 1997 and 1998
Budget and pro forma figures for 1999
4. Coso 1999 Budget - Account Summary by Departments
5. Coso 1999 Capital Expenditures Forecast
6. Coso Monthly Status Reports to January 1999.
7. 1998/1999 preliminary Outage Schedule dated 6/23/98.
8. Coso 1999 Drilling Plan dated 7/28/98
9. Amended and Restated O&M Agreements for Navy I, Navy II and BLM.
10. Assignment and Assumption Agreements for Plants, Wellfields and
Transmission Lines.(Effective 1 February 1999)
11. Coso Projects - Inventory of Spare Parts - 2 March 1999.
33
12. Coso Safety Recovery Plan Memorandum - 5 May 1998
13. TurboCare report "Redesign of Coso BLM Unit 8 Stage 5 and Stage 6 Blades
for CalEnergy." Draft dated 5 January 1998.
14. Progress reports (to 8 March 1999) and preliminary insurance report (21
January 1999) on Unit 1 stator failure.
15. Document: FPL Energy Operating Services Performance Story.
16. Sandwell Independent Engineer's Report on the Coso Geothermal Projects
26 August 1992.
34
APPENDIX C
FINANCIAL PROJECTIONS
35
Caithness Coso Funding Corp.
Consolidated Base Case Projected Operating Results
($ in thousands)
May-Dec Year Ended December 31,
------------------------------------------------------------------------
1999 2000 2001 2002 2003 2004
Contract Capacity 210 210 210 210 210 210
Net Plant Output (MWh) 1,579,903 2,323,352 2,324,010 2,321,842 2,327,803 2,295,820
Capacity Payment ($/kWyr)
Navy I $161.20 $161.20 $161.20 $161.20 $161.20 $161.20
BLM $175.00 $175.00 $175.00 $175.00 $175.00 $175.00
Navy II $176.00 $176.00 $176.00 $176.00 $176.00 $176.00
Average Capacity Factor (based on 240 MW) 111.1% 110.2% 110.2% 110.1% 110.4% 109.2%
Average Energy Payment ($/MWh) $68.01 $32.65 $31.80 $34.20 $36.25 $37.76
Revenue
Capacity Revenue $37,909 $42,830 $42,803 $42,808 $42,806 $42,815
Energy Revenue 107,445 75,852 73,906 79,403 84,372 86,686
--------- --------- --------- --------- --------- ---------
Gross Electric Revenue 145,354 118,682 116,709 122,211 127,178 129,500
Royalty Payments 15,703 13,040 12,300 12,774 13,424 15,364
Operating & Maintenance Expense
Operations 4,024 6,032 5,990 5,947 5,902 6,079
Maintenance & Engineering 3,842 5,569 5,527 5,483 5,439 5,602
Coso Services and G&A 3,788 5,491 5,448 5,405 5,360 5,521
Subordinated O&M Fees 1,600 1,500 1,250 1,250 1,250 1,250
Audit & Legal 3,150 2,417 989 1,019 1,049 1,081
Insurance 907 1,211 1,248 1,157 1,191 1,227
Property Tax 1,221 2,560 1,810 1,572 1,303 1,317
SCE Transmission Line Fee 544 816 816 816 816 816
Other 593 1,416 1,433 1,448 1,464 1,481
Depreciation Expense 25,689 36,199 36,808 37,254 36,707 35,589
--------- --------- --------- --------- --------- ---------
Total Expense 45,358 63,211 61,319 61,351 60,482 59,963
--------- --------- --------- --------- --------- ---------
Operating Income 84,293 42,432 43,090 48,086 53,272 54,174
Interest Expense 19,548 30,906 28,881 27,027 24,950 22,385
Interest Income 4,147 3,733 3,723 3,876 4,066 4,102
--------- --------- --------- --------- --------- ---------
Net Income $68,892 $15,259 $17,932 $24,935 $32,387 $35,891
========= ========= ========= ========= ========= =========
EBITDA (1) 114,129 82,364 83,621 89,217 94,045 93,865
Capital Expenditures 18,814 8,466 11,822 17,285 15,356 13,024
Changes in Working Capital (702) 5,792 1,168 221 289 624
Cash Flow Available for Debt Service 96,213 81,190 74,217 73,403 80,227 82,715
Annual Debt Service
Principal Outstanding (end of year) 360,335 330,067 303,000 281,229 253,611 222,279
Interest Expense 19,548 30,906 28,881 27,027 24,950 22,385
Principal Repayment 52,665 30,268 27,067 21,771 27,618 31,332
Total Annual Debt Service 72,213 61,174 55,948 48,798 52,568 53,717
Debt Service Reserve Balance (end of year) 34,313 30,108 26,379 28,763 29,708 30,704
Major Maintenance Reserve Balance (end of year) 8,466 11,822 17,285 15,356 13,024 14,386
Navy Sinking Fund Balance (end of year) 8,420 9,679 11,012 12,426 13,925 15,513
Unrestricted Cash Balance (end of year) 3,000 3,000 3,000 3,000 3,000 3,000
Debt Service Coverage Ratio 1.33x 1.33x 1.33x 1.50x 1.53x 1.54x
Average Debt Service Coverage through 2001 1.33x
Average Debt Service Coverage Ratio from 2002 through 2009 1.59x
May-Dec Year Ended December 31,
---------------------------------------------------------------------------
2005 2006 2007 2008 2009
Contract Capacity 210 210 210 210 210
Net Plant Output (MWh) 2,309,576 2,320,129 2,276,478 2,191,802 2,113,680
Capacity Payment ($/kWyr)
Navy I $161.20 $161.20 $161.20 $161.20 $161.20
BLM $175.00 $175.00 $175.00 $175.00 $175.00
Navy II $176.00 $176.00 $176.00 $176.00 $176.00
Average Capacity Factor (based on 240 MW) 109.6% 110.1% 108.0% 104.0% 100.3%
Average Energy Payment ($/MWh) $40.39 $41.70 $42.43 $43.03 $44.34
Revenue
Capacity Revenue $42,811 $42,794 $42,745 $42,646 $42,556
Energy Revenue 93,295 96,750 96,585 94,314 93,714
--------- --------- --------- --------- ---------
Gross Electric Revenue 136,106 139,544 139,329 136,960 136,270
Royalty Payments 16,643 17,330 17,680 17,677 17,144
Operating & Maintenance Expense
Operations 6,261 6,449 6,643 6,842 7,047
Maintenance & Engineering 5,770 5,943 6,121 6,305 6,494
Coso Services and G&A 5,686 5,857 6,033 6,214 6,400
Subordinated O&M Fees 1,250 1,250 1,250 1,250 1,250
Audit & Legal 1,113 1,147 1,181 1,217 1,253
Insurance 1,264 1,302 1,341 1,381 1,422
Property Tax 1,392 1,433 1,435 1,413 1,407
SCE Transmission Line Fee 816 816 816 816 816
Other 1,498 1,515 1,533 1,551 1,111
Depreciation Expense 35,372 35,061 34,938 34,512 32,217
--------- --------- --------- --------- ---------
Total Expense 60,422 60,773 61,290 61,500 59,418
--------- --------- --------- --------- ---------
Operating Income 59,041 61,440 60,359 57,783 59,708
Interest Expense 19,474 16,212 12,582 8,259 3,755
Interest Income 4,347 4,504 4,370 4,359 4,424
--------- --------- --------- --------- ---------
Net Income $43,914 $49,732 $52,146 $53,884 $60,376
========= ========= ========= ========= =========
EBITDA (1) 98,760 101,005 99,666 96,654 96,349
Capital Expenditures 14,386 15,532 4,666 4,403 4,535
Changes in Working Capital 81 483 946 1,219 546
Cash Flow Available for Debt Service 85,706 87,207 97,196 94,720 93,610
Annual Debt Service
Principal Outstanding (end of year) 186,799 148,513 101,094 51,833 0
Interest Expense 19,474 16,212 12,582 8,259 3,755
Principal Repayment 35,480 38,286 47,419 49,261 51,833
Total Annual Debt Service 54,954 54,498 60,001 57,520 55,588
Debt Service Reserve Balance (end of year) 30,732 34,313 33,272 32,569 0
Major Maintenance Reserve Balance (end of year) 15,532 4,666 4,403 4,535 0
Navy Sinking Fund Balance (end of year) 17,197 18,982 20,874 22,879 25,000
Unrestricted Cash Balance (end of year) 3,000 3,000 3,000 3,000 3,000
Debt Service Coverage Ratio 1.56x 1.60x 1.62x 1.65x 1.68x
(1) EBITDA is defined as net income plus interest expense plus depreciation
expense.
Caithness Coso Funding Corp.
Consolidated Low Gas Case 1 Projected Operating Results
($ in thousands)
May-Dec Year Ended December 31,
------------------------------------------------------------------------
1999 2000 2001 2002 2003 2004
Contract Capacity 210 210 210 210 210 210
Net Plant Output (MWh) 1,579,903 2,323,352 2,324,010 2,321,842 2,327,803 2,295,820
Capacity Payment ($/kWyr)
Navy I $ 161.20 $ 161.20 $ 161.20 $ 161.20 $ 161.20 $ 161.20
BLM $ 175.00 $ 175.00 $ 175.00 $ 175.00 $ 175.00 $ 175.00
Navy II $ 176.00 $ 176.00 $ 176.00 $ 176.00 $ 176.00 $ 176.00
Average Capacity Factor (based on 240 MW) 111.1% 110.2% 110.2% 110.1% 110.4% 109.2%
Average Energy Payment ($/MWh) $ 68.01 $ 32.08 $ 31.00 $ 32.22 $ 33.71 $ 35.18
Revenue
Capacity Revenue $ 37,909 $ 42,830 $ 42,803 $ 42,808 $ 42,806 $ 42,815
Energy Revenue 107,445 74,542 72,048 74,812 78,470 80,775
--------- --------- --------- --------- --------- ---------
Gross Electric Revenue 145,354 117,372 114,851 117,620 121,277 123,590
Royalty Payments 15,703 12,897 12,095 12,266 12,772 14,620
Operating & Maintenance Expense
Operations 4,024 6,032 5,990 5,947 5,902 6,079
Maintenance & Engineering 3,842 5,569 5,527 5,483 5,439 5,602
Coso Services and G&A 3,788 5,491 5,448 5,405 5,360 5,521
Subordinated O&M Fees 1,600 1,500 1,250 1,250 1,250 1,250
Audit & Legal 3,150 2,417 989 1,019 1,049 1,081
Insurance 907 1,211 1,248 1,157 1,191 1,227
Property Tax 1,221 2,560 1,810 1,572 1,303 1,319
SCE Transmission Line Fee 544 816 816 816 816 816
Other 593 1,416 1,433 1,448 1,464 1,481
Depreciation Expense 25,689 36,199 36,808 37,254 36,707 35,589
--------- --------- --------- --------- --------- ---------
Total Expense 45,358 63,211 61,319 61,351 60,482 59,964
--------- --------- --------- --------- --------- ---------
Operating Income 84,293 41,265 41,437 44,004 48,023 49,006
Interest Expense 19,548 30,906 28,881 27,027 24,950 22,385
Interest Income 4,147 3,731 3,699 3,817 3,989 4,027
--------- --------- --------- --------- --------- ---------
Net Income $ 68,892 $ 14,089 $ 16,255 $ 20,793 $ 27,062 $ 30,648
========= ========= ========= ========= ========= =========
EBITDA (1) 114,129 81,194 81,944 85,074 88,719 88,622
Capital Expenditures 18,814 8,466 11,822 17,285 15,356 13,024
Changes in Working Capital (702) 5,958 1,238 568 455 625
Cash Flow Available for Debt Service 96,213 80,187 72,610 69,607 75,068 77,472
Annual Debt Service
Principal Outstanding (end of year) 360,335 330,067 303,000 281,229 253,611 222,279
Interest Expense 19,548 30,906 28,881 27,027 24,950 22,385
Principal Repayment 52,665 30,268 27,067 21,771 27,618 31,332
Total Annual Debt Service 72,213 61,174 55,948 48,798 52,568 53,717
Debt Service Reserve Balance (end of year) 34,603 30,108 26,379 28,763 29,708 30,704
Major Maintenance Reserve Balance (end of year) 8,466 11,822 17,285 15,356 13,024 14,386
Navy Sinking Fund Balance (end of year) 8,420 9,679 11,012 12,426 13,925 15,513
Unrestricted Cash Balance (end of year) 3,000 3,000 3,000 3,000 3,000 3,000
Debt Service Coverage Ratio 1.33x 1.31x 1.30x 1.43x 1.43x 1.44x
Average Debt Service Coverage through 2001 1.31x
Average Debt Service Coverage Ratio from 2002 through 2009 1.49x
May-Dec Year Ended December 31,
-----------------------------------------------------------
2005 2006 2007 2008 2009
Contract Capacity 210 210 210 210 210
Net Plant Output (MWh) 2,309,576 2,320,129 2,276,478 2,191,802 2,113,680
Capacity Payment ($/kWyr)
Navy I $ 161.20 $ 161.20 $ 161.20 $ 161.20 $ 161.20
BLM $ 175.00 $ 175.00 $ 175.00 $ 175.00 $ 175.00
Navy II $ 176.0 $ 176.00 $ 176.00 $ 176.00 $ 176.00
Average Capacity Factor (based on 240 MW) 109.6% 110.1% 108.0% 104.0% 100.3%
Average Energy Payment ($/MWh) $ 37.79 $ 38.89 $ 39.95 $ 40.11 $ 40.96
Revenue
Capacity Revenue $ 42,811 $ 42,794 $ 42,745 $ 42,646 $ 42,556
Energy Revenue 87,286 90,228 90,937 87,911 86,578
--------- --------- --------- --------- ---------
Gross Electric Revenue 130,098 133,022 133,682 130,558 129,134
Royalty Payments 15,867 16,462 16,907 16,755 16,114
Operating & Maintenance Expense
Operations 6,261 6,449 6,643 6,842 7,047
Maintenance & Engineering 5,770 5,943 6,121 6,305 6,494
Coso Services and G&A 5,686 5,857 6,033 6,214 6,400
Subordinated O&M Fees 1,250 1,250 1,250 1,250 1,250
Audit & Legal 1,113 1,147 1,181 1,217 1,253
Insurance 1,264 1,302 1,341 1,381 1,422
Property Tax 1,395 1,433 1,443 1,412 1,399
SCE Transmission Line Fee 816 816 816 816 816
Other 1,498 1,515 1,533 1,551 1,111
Depreciation Expense 35,372 35,061 34,938 34,512 32,217
--------- --------- --------- --------- ---------
Total Expense 60,425 60,773 61,299 61,500 59,410
--------- --------- --------- --------- ---------
Operating Income 53,805 55,788 55,476 52,303 53,610
Interest Expense 19,474 16,212 12,582 8,259 3,755
Interest Income 4,271 4,421 4,299 4,279 4,335
--------- --------- --------- --------- ---------
Net Income $ 38,602 $ 43,997 $ 47,192 $ 48,324 $ 54,190
========= ========= ========= ========= =========
EBITDA (1) 93,448 95,271 94,712 91,094 90,162
Capital Expenditures 14,386 15,532 4,666 4,403 4,535
Changes in Working Capital 94 548 835 1,314 639
Cash Flow Available for Debt Service 80,406 81,537 92,131 89,256 87,516
Annual Debt Service
Principal Outstanding (end of year) 186,799 148,513 101,094 51,833 0
Interest Expense 19,474 16,212 12,582 8,259 3,755
Principal Repayment 35,480 38,286 47,419 49,261 51,833
Total Annual Debt Service 54,954 54,498 60,001 57,520 55,588
Debt Service Reserve Balance (end of year) 30,732 34,313 33,272 32,569 0
Major Maintenance Reserve Balance (end of year) 15,532 4,666 4,403 4,535 0
Navy Sinking Fund Balance (end of year) 17,197 18,982 20,874 22,879 25,000
Unrestricted Cash Balance (end of year) 3,000 3,000 3,000 3,000 3,000
Debt Service Coverage Ratio 1.46x 1.50x 1.54x 1.55x 1.57x
Average Debt Service Coverage through 2001
Average Debt Service Coverage Ratio from 2002 through 2009
(1) EBITDA is defined as net income plus interest expense plus depreciation
expense.
Caithness Coso Funding Corp.
Consolidated Low Gas Case 2 Projected Operating Results
($ in thousands)
May-Dec Year Ended December 31,
-------------------------------------------------------------------------
1999 2000 2001 2002 2003 2004
Contract Capacity 210 210 210 210 210 210
Net Plant Output (MWh) 1,579,903 2,323,352 2,324,010 2,321,842 2,327,803 2,295,820
Capacity Payment ($/kWyr)
Navy I $161.20 $161.20 $161.20 $161.20 $161.20 $161.20
BLM $175.00 $175.00 $175.00 $175.00 $175.00 $175.00
Navy II $176.00 $176.00 $176.00 $176.00 $176.00 $176.00
Average Capacity Factor (based on 240 MW) 111.1% 110.2% 110.2% 110.1% 110.4% 109.2%
Average Energy Payment ($/MWh) $68.01 $32.03 $30.76 $31.66 $33.06 $34.29
Revenue
Capacity Revenue $37,909 $42,830 $42,803 $42,808 $42,806 $42,815
Energy Revenue 107,445 74,409 71,496 73,498 76,953 78,734
--------- --------- --------- --------- --------- ---------
Gross Electric Revenue 145,354 117,239 114,299 116,306 119,759 121,548
Royalty Payments 15,703 12,879 12,032 12,124 12,604 14,375
Operating & Maintenance Expense
Operations 4,024 6,032 5,990 5,947 5,902 6,079
Maintenance & Engineering 3,842 5,569 5,527 5,483 5,439 5,602
Coso Services and G&A 3,788 5,491 5,448 5,405 5,360 5,521
Subordinated O&M Fees 1,600 1,500 1,250 1,250 1,250 1,250
Audit & Legal 3,150 2,417 989 1,019 1,049 1,081
Insurance 907 1,211 1,248 1,157 1,191 1,227
Property Tax 1,221 2,560 1,810 1,572 1,303 1,313
SCE Transmission Line Fee 544 816 816 816 816 816
Other 593 1,416 1,433 1,448 1,464 1,481
Depreciation Expense 25,689 36,199 36,808 37,254 36,707 35,589
--------- --------- --------- --------- --------- ---------
Total Expense 45,358 63,211 61,319 61,351 60,482 59,959
--------- --------- --------- --------- --------- ---------
Operating Income 84,293 41,149 40,949 42,831 46,673 47,215
Interest Expense 19,548 30,906 28,881 27,027 24,950 22,385
Interest Income 4,147 3,730 3,692 3,800 3,969 4,000
--------- --------- --------- --------- --------- ---------
Net Income $68,892 $13,973 $15,760 $19,603 $25,692 $28,831
========= ========= ========= ========= ========= =========
EBITDA (1) 114,129 81,079 81,448 83,885 87,349 86,805
Capital Expenditures 18,814 8,466 11,822 17,285 15,356 13,024
Changes in Working Capital (702) 5,975 1,291 664 481 692
Cash Flow Available for Debt Service 96,213 80,088 72,168 68,514 73,724 75,722
Annual Debt Service
Principal Outstanding (end of year) 360,335 330,067 303,000 281,229 253,611 222,279
Interest Expense 19,548 30,906 28,881 27,027 24,950 22,385
Principal Repayment 52,665 30,268 27,067 21,771 27,618 31,332
Total Annual Debt Service 72,213 61,174 55,948 48,798 52,568 53,717
Debt Service Reserve Balance (end of year) 34,633 30,108 26,379 28,763 29,708 30,704
Major Maintenance Reserve Balance (end of year) 8,466 11,822 17,285 15,356 13,024 14,386
Navy Sinking Fund Balance (end of year) 8,420 9,679 11,012 12,426 13,925 15,513
Unrestricted Cash Balance (end of year) 3,000 3,000 3,000 3,000 3,000 3,000
Debt Service Coverage Ratio 1.33x 1.31x 1.29x 1.40x 1.40x 1.41x
Average Debt Service Coverage through 2001 1.31x
Average Debt Service Coverage Ratio from 2002 through 2009 1.45x
May-Dec Year Ended December 31,
---------------------------------------------------------
2005 2006 2007 2008 2009
Contract Capacity 210 210 210 210 210
Net Plant Output (MWh) 2,309,576 2,320,129 2,276,478 2,191,802 2,113,680
Capacity Payment ($/kWyr)
Navy I $161.20 $161.20 $161.20 $161.20 $161.20
BLM $175.00 $175.00 $175.00 $175.00 $175.00
Navy II $176.00 $176.00 $176.00 $176.00 $176.00
Average Capacity Factor (based on 240 MW) 109.6% 110.1% 108.0% 104.0% 100.3%
Average Energy Payment ($/MWh) $36.57 $37.20 $37.85 $38.80 $39.48
Revenue
Capacity Revenue $42,811 $42,794 $42,745 $42,646 $42,556
Energy Revenue 84,454 86,318 86,174 85,031 83,456
--------- --------- --------- --------- ---------
Gross Electric Revenue 127,266 129,112 128,919 127,678 126,012
Royalty Payments 15,496 15,956 16,246 16,353 15,699
Operating & Maintenance Expense
Operations 6,261 6,449 6,643 6,842 7,047
Maintenance & Engineering 5,770 5,943 6,121 6,305 6,494
Coso Services and G&A 5,686 5,857 6,033 6,214 6,400
Subordinated O&M Fees 1,250 1,250 1,250 1,250 1,250
Audit & Legal 1,113 1,147 1,181 1,217 1,253
Insurance 1,264 1,302 1,341 1,381 1,422
Property Tax 1,382 1,408 1,410 1,399 1,383
SCE Transmission Line Fee 816 816 816 816 816
Other 1,498 1,515 1,533 1,551 1,111
Depreciation Expense 35,372 35,061 34,938 34,512 32,217
--------- --------- --------- --------- ---------
Total Expense 60,412 60,748 61,265 61,486 59,393
--------- --------- --------- --------- ---------
Operating Income 51,358 52,408 51,408 49,839 50,920
Interest Expense 19,474 16,212 12,582 8,259 3,755
Interest Income 4,235 4,372 4,239 4,243 4,295
--------- --------- --------- --------- ---------
Net Income $36,119 $40,568 $43,065 $45,824 $51,460
========= ========= ========= ========= =========
EBITDA (1) 90,965 91,841 90,585 88,594 87,432
Capital Expenditures 14,386 15,532 4,666 4,403 4,535
Changes in Working Capital 194 684 943 1,076 670
Cash Flow Available for Debt Service 78,023 78,244 88,112 86,517 84,817
Annual Debt Service
Principal Outstanding (end of year) 186,799 148,513 101,094 51,833 0
Interest Expense 19,474 16,212 12,582 8,259 3,755
Principal Repayment 35,480 38,286 47,419 49,261 51,833
Total Annual Debt Service 54,954 54,498 60,001 57,520 55,588
Debt Service Reserve Balance (end of year) 30,732 34,313 33,272 32,569 0
Major Maintenance Reserve Balance (end of year) 15,532 4,666 4,403 4,535 0
Navy Sinking Fund Balance (end of year) 17,197 18,982 20,874 22,879 25,000
Unrestricted Cash Balance (end of year) 3,000 3,000 3,000 3,000 3,000
Debt Service Coverage Ratio 1.42x 1.44x 1.47x 1.50x 1.53x
Average Debt Service Coverage through 2001
Average Debt Service Coverage Ratio from 2002 through 2009
(1) EBITDA is defined as net income plus interest expense plus depreciation
expense.
EXHIBIT B
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND
PRICE FORECAST
1999 - 2009
Prepared for:
Caithness Coso Funding Corp.
Date Submitted:
May 20, 1999
Prepared by:
Henwood Energy Services, Inc.
2710 Gateway Oaks Way, Suite 300N
Sacramento, CA 95833
http://www.hesinet.com
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND
PRICE FORECAST
1999 - 2009
Prepared for:
Caithness Coso Funding Corp.
Date Submitted:
May 20, 1999
Prepared by:
[Logo of HESI]
Henwood Energy Services, Inc.
2710 Gateway Oaks Way, Suite 300 North
Sacramento, CA 95833
(916) 569-0985 - Phone
(916) 569-0999 - Fax
http://www.hesinet.com
----------------------
Contact:
Keith Durand, Project Manager
PROPRIETARY AND CONFIDENTIAL
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
TABLE OF CONTENTS
- -----------------
SECTION PAGE
- ------- ----
EXECUTIVE SUMMARY ES-1
- ------------------------------------------------------------------------------------------------
1 THE U.S. ELECTRIC POWER MARKET 1-1
1.1 Introduction 1-1
1.2 Federal Legislative and Regulatory Initiatives 1-1
1.2.1 Public Utility Regulatory Policies Act - 1978 1-1
1.2.2 Energy Policy Act - 1992 1-1
1.2.3 FERC Order 888 - 1996 1-2
1.3 California Legislative Initiatives 1-2
1.3.1 Assembly Bill 1890 1-2
2 THE CALIFORNIA WHOLESALE POWER MARKET 2-1
- ------------------------------------------------------------------------------------------------
2.1 The Market 1998 and Beyond 2-1
2.1.1 Market Size 2-2
2.1.2 Diversity of Energy Supply 2-2
2.1.3 California Investor Owned Utilities 2-3
2.1.4 Treatment of Qualifying Facilities (QFs) 2-4
2.2 California Municipal Utilities and Authorities 2-4
2.3 System Reliability 2-5
2.4 The California PX 2-5
2.4.1 California PX Prices 2-6
2.4.2 Short Run Avoided Costs 2-7
2.5 PX Prices as a Measure of Avoided Cost 2-9
3 SOUTHERN CALIFORNIA MCP FORECAST: KEY ASSUMPTIONS AND METHODOLOGY 3-1
- ------------------------------------------------------------------------------------------------
3.1 Modeling Methodology and Techniques 3-1
3.2 Assumptions Regarding the California Market Transition Period 3-2
3.3 Key Assumptions for Modeling the WSCC Power Market 3-3
3.3.1 Forecast Horizon 3-3
3.3.2 Market Structure 3-3
3.3.3 Existing Resource Base 3-3
3.3.4 Resource Retirements 3-3
3.3.5 Generic Resource Additions 3-4
3.3.6 Loads 3-4
3.3.7 Load Shape 3-5
3.3.8 Load Growth 3-5
- --------------------------------------------------------------------------------
(C)1999 Henwood Energy Services, Inc. May 20, 1999
i
PROPRIETARY AND CONFIDENTIAL
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
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3.3.9 Inflation 3-5
3.3.10 Fuel Prices 3-5
3.3.11 Natural Gas 3-5
3.3.12 Operations & Maintenance 3-16
3.3.13 Property Taxes 3-16
3.3.14 Insurance 3-16
3.3.15 Other Costs 3-16
3.4 WSCC Transmission System Configuration 3-17
3.5 Hydro Power 3-17
3.5.1 Median Year Case 3-17
3.5.2 Transactions 3-18
4 SOUTHERN CALIFORNIA MCP FORECAST : RESULTS 4-1
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4.1 Base Case Southern California MCP Forecast, 2000-2009 4-1
4.2 Sensitivity Cases 4-2
4.2.1 Low Gas Price Case 1 4-2
4.2.2 Low Gas Price Case 2 4-3
5 THE PROJECT AND THE CALIFORNIA MARKET 5-1
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5.1 Market Analysis Results 5-1
5.2 Southern California MCP Forecast and the Market Position of the Project 5-5
6 THE RENEWABLE RESOURCE FUNDING PROGRAM 6-1
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LIST OF TABLES
--------------
TABLE 2-1 1997 NET SYSTEM POWER (ELECTRIC GENERATION) 2-3
TABLE 2-2 MONTHLY AVERAGE CALIFORNIA PX PRICES - APRIL 1998 TO
JANUARY 1999 ($/MWH) 2-7
TABLE 2-3 SCE ANNUAL AVERAGE SHORT-RUN AVOIDED COSTS OF ENERGY 2-9
TABLE 3-1 GENERIC RESOURCE CHARACTERISTICS (1996 DOLLARS) 3-4
TABLE 3-2 PROJECTED GAS COMMODITY PRICE GROWTH BY PRODUCER
BASIN (AVERAGE ANNUAL REAL PERCENT CHANGE) 3-10
TABLE 3-3 HESI BASE CASE SAN JUAN AND ALBERTA COMMODITY
PRICE FORECAST $98/MMBTU 3-11
TABLE 3-4 HESI BASE CASE NATURAL GAS CITY-GATE PRICE FORECAST $1998/MMBTU 3-15
TABLE 4-1 BASE CASE SOUTHERN CALIFORNIA MCP FORECAST 2000 -
2009 $/MWH 4-2
TABLE 4-2 MCP FORECAST UNDER THE LOW GAS PRICE CASE 1 4-3
TABLE 4-3 MCP FORECAST UNDER THE LOW GAS PRICE CASE 2 4-4
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ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
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TABLE 5-1 AVERAGE OPERATING COSTS BY PLANT TYPE IN THE WSCC
FROM PROSYM MODEL SIMULATION IN 2005 5-2
TABLE 5-2 MCP FREQUENCY ANALYSIS IN SOUTHERN CALIFORNIA
TRANSMISSION AREA, 2005 5-6
TABLE 6-1 AB 1890 ACCOUNTS - TOTAL FUNDING ALLOCATIONS BY
TECHNOLOGY $MILLIONS 6-1
TABLE 6-2 EXISTING RENEWABLE RESOURCE ACCOUNT - ALLOCATIONS BY
TIER $MILLIONS 6-2
TABLE 6-3 NEW RENEWABLE RESOURCE ACCOUNT - ALLOCATIONS BY YEAR, $MILLIONS 6-4
LIST OF FIGURES
---------------
FIGURE 2-1 CALIFORNIA PX DAILY PRICES - HIGH, LOW AND AVERAGE 2-8
FIGURE 3-1 ALBERTA GAS COMMODITY PRICE FORECASTS 3-7
FIGURE 3-2 SAN JUAN GAS COMMODITY PRICE FORECASTS 3-8
FIGURE 3-3 ACTUAL AND ESTIMATED MONTHLY GAS PRICE VARIATION AT
TOPOCK 3-12
FIGURE 3-4 WSCC TRANSMISSION SYSTEM CONFIGURATION 3-17
FIGURE 5-1 BASE CASE ANNUAL AVERAGE MCP AND PROJECT OPERATING
COSTS 5-3
FIGURE 5-2 BASE CASE ANNUAL OFF-PEAK MCP AND PROJECT OPERATING
COSTS 5-4
FIGURE 5-3 LOW GAS PRICE CASE 2 ANNUAL OFF-PEAK MCP AND PROJECT OPERATING COSTS 5-5
LIST OF APPENDICES
------------------
A Southern California Base Case MCP Forecast
B Southern California Low Gas case 1 MCP Forecast
C Southern California Low Gas case 2 MCP Forecast
D Southern California Edison SRAC Price and Tier 3 Renewable Energy Subsidy
Forecast
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PROPRIETARY AND CONFIDENTIAL
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND PRICE FORECAST
1999 - 2009
EXECUTIVE SUMMARY
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Caithness Coso Funding Corp. has retained Henwood Energy Services, Inc (HESI) to
provide a detailed assessment of the Coso Project (hereafter the "Project"). The
Project is an existing geothermal power plant located in southern California. It
has a take-or-pay Purchase Power Agreement (PPA) that requires it to operate
continuously.
In HESI's opinion, such an assessment includes consideration of the important
regulatory developments and power market fundamentals that influence the
southern California market, in addition to a forecast of wholesale power prices
over the long term. While the PPA ensures that the Project has a guaranteed
market for its output, thus lessening competitive issues in the future, HESI has
briefly examined the cost competitiveness of the Project with respect to other
generators operating in the Southern California market.
The analysis and conclusions presented here are based upon assumptions developed
and tested by HESI and the power price forecast is derived from HESI's
proprietary Electric Market Simulation System (EMSS) software. The assessment
and forecast contained in this report are presented in both quantitative and
qualitative fashion as listed below:
1. A brief discussion of the key regulatory and market developments that affect
the California wholesale electricity market.
2. A detailed description of the key assumptions used in assessing the market
and utilized as EMSS inputs.
3. Average monthly time-of-day market clearing prices (MCP) in the Southern
California transmission area for the years 2000 to 2009.
4. Two alternative MCP forecasts that assume low gas prices and which are
designed to assess the Projects' sensitivity to changes in power prices over
the long-term.
5. Estimates of Southern California Edison monthly SRAC prices between 1999 and
2001 using the current Transition Period formula.
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1999 - 2009
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6. A specific competitive assessment of the Project on a stand-alone basis
using the Southern California MCP forecast and Project cost estimates
provided by the Project Operator.
7. An assessment of the Project within the context of the competitive market
and how the Project compares with other generators.
8. An assessment and estimate of renewable energy subsidy payments available
from the California government.
Based on our analyses, the report's major conclusions are summarized below:
1. HESI's MCP forecast indicates that the Southern California annual average
power price will increase from $26.9/MWh in 2000 to $44.3/MWh by 2009 -
which translates into an average annual rate of increase of about 5.7
percent over that period (inflation is included in all prices and is equal
to 3 percent per year).
2. However, there are three distinct periods of price movement. Between 2000
and 2002, the "Transition Period" in California, prices increase at an
annual average rate of 12.6 percent. During this period, prices bid into the
California Power Exchange (PX) reflect short run marginal fuel costs because
most utility-owned generators receive payments for capacity from "Must-Run"
contracts, if in California, or through traditional tariffs, if outside of
California.
3. After the Transition Period ends in March 2002, the PX should cease to
behave as a marginal cost pool. This change is reflected in the forecast.
The average MCP increases from $34.1/MWh in 2002 to $40.4/MWh by 2005 - an
average rate of increase of about 5.7 percent per year. Price increases in
this period reflect attempts by generators in California to recover at least
a portion of fixed capacity costs through market sales.
4. Beyond 2005, prices are forecast to increase gradually but steadily, about
2.3 percent per year, which is less than the inflation rate. The growth rate
during the 2005 to 2009 period is influenced largely by the introduction
into the generation market of high efficiency gas-fired combined cycle
plants. These plants are frequently on the margin. That is, they establish
the market-clearing price, and thus are in a position to
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ELECTRICITY MARKET AND PRICE FORECAST
1999 - 2009
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push power prices down gradually over time as they replace less efficient
thermal generation plants.
5. Based on HESI's long-run natural gas price forecast (described in Section
3.3.11 below) and a 3 percent annual inflation rate, we estimate Southern
California Edison SRAC prices of $31.3/MWh for the remaining months of 1999
(May - December), $32.4/MWh in 2000 and $33.4/MWh in 2001. These prices are
higher than HESI's forecast of power prices on the California Power Exchange
during the same period.
6. We expect the Project to be a low cost producer in all years of the study.
According to data provided by the Project Operator, the annual average
operating cost in 2005 is $10.83/MWh. About 70 percent of the electricity
produced in the Western Systems Coordinating Council (WSCC) in 2005 - the
first year of full competition, is generated from units with higher costs.
Of all the generation in the region, only hydro and wind generators have
lower operating costs (hydro and wind power account for about 24 and 1
percent, respectively, of all electric generation in California).
7. The Project's annual average operating costs are 69 percent below annual
Southern California power prices, averaged over all years of the forecast.
In fact, the Projects' operating costs are significantly below even the off-
peak MCP in all forecast years.
8. The low-cost relationship between the MCP forecast and Project operating
costs continues in the Low Gas Price sensitivity cases. Under the worst-case
scenario, Low Gas Price Case 2, the Project's operating costs are, on
average, 58 percent below off-peak prices.
9. We estimate that the Southern California MCP will be greater than or equal
to $19.7/MWh in 96 percent of all hours in 2005. This means that the
Project, with an average operating cost of $10.8/MWh, will be below the MCP
in each of those hours and, in the absence of a PPA, would be dispatched
accordingly.
10. The Project is eligible for AB 1890 sponsored renewable energy subsidies
under Tier 3 of the Existing Renewable Energy category. However, based on
client and HESI assumptions, the Transition Period SRAC price exceeds 3.0
cents per kWh (the floor price guaranteed by
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ELECTRICITY MARKET AND PRICE FORECAST
1999 - 2009
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AB 1890) during most months of 2000 and 2001. Consequently, although subsidy
funds are available, SRAC prices are forecast to be sufficiently high that
Tier 3 producers will not require a subsidy in most months. In the event
that future SRAC prices are lower than forecast here, HESI believes that the
AB 1890 program has ample funds to ensure that Tier 3 producers receive the
minimum of 3.0 cents per kWh until the end of 2001
11. HESI has reviewed the methodology and assumptions used by Caithness to
estimate AB 1890 subsidy payments. We believe their assumptions to be
reasonable and their methodology and calculations consistent with and
similar to HESI's own procedures.
The Report is organized as follows. Section 1 presents a brief overview of the
important federal and California regulatory initiatives that affect electric
power generation. The key features of the California power market, including the
Power Exchange and the SRAC Transition Formula, are described in Section 2.
Section 3 contains a discussion of the assumptions and methodology incorporated
into HESI's forecast of power prices in the Southern California market. The Base
Case and Low Gas Price Case forecast results are presented in Section 4. The
Project's competitive position within the California power market is analyzed in
Section 5. Last, Section 6 presents a brief overview of the AB 1890 sponsored
renewable energy subsidy programs and an estimate of subsidy payments applicable
to the Project.
The MCP forecasts by month and time of day are shown in Appendix A through C.
Appendix D contains SRAC price forecasts and renewable energy subsidy estimates
by month between 1999 to 2001.
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THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND PRICE FORECAST
1999 - 2009
1 THE U.S. ELECTRIC POWER MARKET
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1.1 INTRODUCTION
The U.S. electric power industry is undergoing a profound transformation. The
industry is evolving from a vertically integrated and cost-regulated monopoly to
one that is market-based with competitive prices. The transition began with the
passing of the Public Utility Regulatory Policies Act (PURPA) in 1978, which
made it possible for non-utility generators to enter the wholesale power market.
As a result, non-utility capacity additions grew 54 percent from 1990 to 1996
while utility capacity additions during the same period grew only 2 percent. The
deregulation process is likely to continue at the state level far into the next
decade.
1.2 FEDERAL LEGISLATIVE AND REGULATORY INITIATIVES
This section briefly discusses the major federal legislation and regulation that
established a framework for electric power industry deregulation and set the
stage for further legislative initiatives at the state level.
1.2.1 Public Utility Regulatory Policies Act - 1978
PURPA is one of five bills signed into law on November 9, 1978, as part of the
National Energy Act. It is the only one remaining in force. Enacted to combat
the "energy crisis," and the perceived shortage of petroleum and natural gas,
PURPA requires utilities to buy power from non-utility generating facilities
that use renewable energy sources or "cogeneration," i.e. the use of steam both
for heat and to generate electricity. The Act stipulates that electric utilities
must interconnect with and buy, at the utilities' avoided cost, the capacity and
energy offered by any non-utility facility ("Qualifying Facility") meeting
certain ownership, operating and efficiency criteria established by the Federal
Energy Regulatory Commission (FERC).
1.2.2 Energy Policy Act - 1992
The Energy Policy Act of 1992 (EPACT) opened access to transmission networks and
exempted certain non-utilities from the restrictions of the Public Utility
Holding Company Act of 1935 (PUHCA). EPACT therefore has made it even easier for
non-utility generators to enter the wholesale market for electricity.
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The Act also created a new category of power producers, called exempt wholesale
generators (EWGs). By exempting them from PUHCA regulation, the law eliminated a
major barrier for utility-affiliated and nonaffiliated power producers wanting
to compete to build new non-rate-based power plants. EWGs differ from PURPA QFs
in two ways. First, they are not required to meet PURPA's utility ownership,
cogeneration, or renewable fuels limitations. Second, utilities are not required
to purchase power from EWGs.
In addition to giving EWGs and QFs access to distant wholesale markets, EPACT
provides transmission-dependent utilities the ability to shop for wholesale
power supplies, thus releasing them - mostly municipals and rural cooperatives -
- - from their dependency on surrounding investor-owned utilities for wholesale
power requirements. The transmission provisions of EPACT have led to a
nationwide open-access electric power transmission grid for wholesale
transactions.
1.2.3 FERC Order 888 - 1996
With the passage of EPACT, Congress opened the door to wholesale competition in
the electric utility industry by authorizing FERC to establish regulations to
provide open access to the nation's transmission system. FERC's subsequent
rules, issued in April 1996 as Order 888, is designed to increase wholesale
competition in the nation's transmission system, remedy undue discrimination in
transmission, and establish standards for stranded cost recovery. A companion
ruling, Order 889, requires utilities to establish electronic systems to share
information about available transmission capacity.
1.3 CALIFORNIA LEGISLATIVE INITIATIVES
1.3.1 Assembly Bill 1890
The legislation that introduced electric power deregulation to California is
Assembly Bill 1890 (AB 1890). The Bill, which was passed in September 1996,
established a number of goals, including:
. An immediate 10 percent rate reduction for residential and small commercial
users.
. A new power market structure with an Oversight Board (OB), an Independent
System Operator (ISO) and a PX.
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. Limits the amount of costs (e.g. stranded assets) that are recoverable in the
transition to a deregulated market.
. Preserves public programs supporting energy efficiency, research &
development and low-income households.
. Provides approximately $540 million in subsidies to support renewable energy
programs, including geothermal power generation, such as the Project.
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ELECTRICITY MARKET AND PRICE FORECAST
1999 - 2009
2 THE CALIFORNIA WHOLESALE POWER MARKET
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AB 1890 established a four-year Transition Period between January 1998 and March
2002 during which the California power market would undergo the transition from
a regulated to a competitive industry. The ISO and PX were scheduled to commence
operations on January 1, 1998 but technical problems delayed their start until
March 31, 1998. At the end of the Transition Period, most of the protections
afforded California's investor owned-utilities (IOUs) for past uneconomic
investments and power contracts will be removed. It is anticipated that,
eventually, municipal utilities will also permit their retail customers to enter
into direct supply agreements with competitive power suppliers.
2.1 THE MARKET 1998 AND BEYOND
With deregulation, a steadily increasing percentage of customers will be allowed
to purchase power in an open market. Customers will have direct access to
generators. No longer restricted to buying power only from their local utility
company, they can freely select the power arrangement that suits their
preferences.
On March 31, 1998, the PX began operating the Day-ahead energy market, a
wholesale market-clearing auction into which PX participants bid energy supply
and demand for each of the next day's 24 hours. On the same date, the ISO took
control of the electric grid, and began operating a complementary set of
competitive auctions. The ISO relies on these auctions to manage transmission
line congestion, to procure a portion of the needed ancillary services (for
reliability purposes), and to balance physical generation with load in real
time.
During the Transition Period, utilities are afforded the opportunity to recover
certain "stranded costs" for generation-related investments. These costs had
been previously authorized by the CPUC for inclusion in rates, but are not
likely to be recoverable through the prices that emerge in the competitive
market. The mechanism for this cost recovery is an unavoidable Competition
Transition Charge (CTC) assessed against all customers served by the
distribution system of California IOUs.
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2.1.1 Market Size
California's electric power market is very large, with a summer peak demand of
53,217 MW and total power consumption of 275,876 GWh in 1997. The average retail
cost of electricity is about 9.5 cents/kWh. Electric sales by California
utilities equaled $21.75 billion in 1997. According to the WSCC, peak demand for
electricity is forecast to reach 58,305 MW by 2007 - a growth rate of about 1.0
percent per year between 1997 and 2007. /1/
Electricity sales by California's three largest IOU's - PG&E, SCE, and SDG&E,
equaled about 169,045 GWh in 1997, or approximately 74 percent of California's
statewide energy consumption. /2/
2.1.2 Diversity of Energy Supply
During the 1970s, over two-thirds of California's electricity was generated from
oil and natural gas. This decade, however, California has developed a more
diverse resource mix of electricity generation. As Table 2-1 shows, over half of
the state's 258,801 GWh of electricity production is now met with non-fossil
fuel sources. Further, over 11 percent of power generation is fueled by
renewable energy, mainly geothermal, small hydro and biomass (but excluding
large hydro).
California leads in developing new generation technologies. It has 40 percent of
the world's geothermal power plants, 30 percent of the installed wind capacity,
and 90 percent of the world's solar generation. The state also leads the nation
in the amount of electricity supplied by non-utility generators.
Table 2-1 also shows that just over 32 percent of electricity generation is
supplied by natural gas. Because of its cheap price and clean-burning
characteristics, natural gas has become California's fuel of choice,
particularly for electricity generation. According to the California Energy
Commission, natural gas will account for 38 percent of energy used for power
generation by 2009.
- ---------------------------------
/1/ Peak demand forecast from "WSCC 1998 Information Summary," Western Systems
Coordinating Council.
/2/ Electricity consumption and revenue data from the California Energy
Commission..
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ELECTRICITY MARKET AND PRICE FORECAST
1999 - 2009
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Table 2-1
1997 Net System Power
(Electric Generation)
Fuel Type GWh Percent of Total
- ----------------------------------------------------------------
Hydroelectric* 61,718 24.4%
- ----------------------------------------------------------------
Nuclear 36,741 14.5%
- ----------------------------------------------------------------
Coal* 51,543 20.3%
- ----------------------------------------------------------------
Oil 173 0.1%
- ----------------------------------------------------------------
Natural Gas* 81,256 32.1%
- ----------------------------------------------------------------
Geothermal 11,950 4.7%
- ----------------------------------------------------------------
Organic Waste 5,701 2.3%
- ----------------------------------------------------------------
Wind 2,739 1.1%
- ----------------------------------------------------------------
Solar 810 0.3%
- ----------------------------------------------------------------
Other 896 0.4%
- ----------------------------------------------------------------
Total 253,526 100.0%
- ----------------------------------------------------------------
*Includes out of state imports.
Source: California Energy Facts, California Energy Commission
Natural gas pipeline capacity into California stood at about 8 Bcf/day in 1996.
Between 1990 and 1996, interstate pipeline capacity into California increased by
65 percent. The major sources of new capacity during this period were the
Mojave, El Paso and Tuscarora pipelines. /3/
2.1.3 California Investor Owned Utilities
As California's utility market moves toward free competition, over 17,800 MW of
generating assets owned by IOUs have been sold, or will be in the near future.
However, despite this divestiture of generation resources, the IOUs are expected
to retain ownership and control of substantial nuclear, QF, and hydropower
generation in California and jointly owned thermal coal-fired generation outside
of California.
The IOUs also buy and sell power from each other, as well as engage in
transactions with other utilities in California and the surrounding Western
states. Each has assumed responsibility for matching load and resources to
- ---------------------------------
/3/ Deliverability on the Interstate Natural Gas Pipeline System, Energy
Information Administration , May 1998.
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maintain frequency, and matching scheduled and actual flows at the tie points by
which utilities are connected to other power producers. Because of their
obligation to serve within their service territories, they also developed
generation and demand forecasts, operated generating plants, and entered into
long-term procurement contracts for the fuel used to generate electricity. They
also participated in short- and long-term bilateral contracts for electric power
in order to meet changes in demand and demand growth, respectively.
2.1.4 Treatment of Qualifying Facilities (QFs)
With the exception of those with fixed price contracts, most other California
QFs are currently compensated under a Transition Formula that calculates the
Short Run Avoid Cost (SRAC) of each of California's three major IOUs. This
formula links changes in utility SRAC directly to changes in the price of
natural gas. However, the formula approach to estimating utility avoided costs
is unlikely to last much longer. The California Public Utilities Commission
(CPUC), which has the regulatory authority to determine SRAC, in Decision 96-12-
028, stated its intention to change the formula to one based on the California
PX price once certain conditions are satisfied. These conditions are that the PX
is functioning properly and that either the IOUs have divested 90 percent of
their gas-fired fossil generation, or the fossil-fired generation units owned
directly or indirectly by the IOUs are recovering all of their going forward
costs from PX based prices. HESI believes these conditions will be met by the
beginning of 2000.
2.2 CALIFORNIA MUNICIPAL UTILITIES AND AUTHORITIES
While it is anticipated that municipal utilities and other governmental
authorities will participate in the PX and ISO, there is no regulatory
requirement for them to do so. The largest municipal utilities are the Los
Angeles Department of Water and Power (LADWP) and the Sacramento Municipal
Utility District (SMUD), which in combination own or control over 15,000 MW of
generating resources. To date, they have not announced plans regarding their
participation nor have they submitted their transmission resources to ISO
control. The Imperial Irrigation District has also not as yet announced plans to
relinquish its transmission system to ISO control.
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2.3 SYSTEM RELIABILITY
The ISO is the entity responsible for the security and operating reliability of
the statewide electric grid. In this function, the ISO will adhere to the North
American Electric Reliability Council (NERC) and Western Systems Coordinating
Council (WSCC) standards for reliable operation.
In the near term, the new market is designed to accommodate this centralized,
third-party control structure through the combined use of two mechanisms. One is
the ISO-conducted, competitive auction for eligible ancillary services, such as
operating (spinning and non-spinning) reserve, replacement reserve, and
regulation capacity that can be controlled electronically by the ISO.
The other mechanism available to the ISO for procurement of generating services
is the use of long-term contracts with generating facilities that are designated
as "reliability Must-Run" facilities. A Must-Run facility refers to an IOU
generation plant that has a contract with the ISO for the purposes of
maintaining system reliability. These contracts provide for a capacity payment
to the owners during all, or part, of the Transition Period.
As with the ancillary service auction, the ISO will use reliability Must-Run
contracts to obtain operating reserve, replacement reserve, "black start"
capability, voltage support, and regulation capacity. The prices established in
these must-run contracts are unrelated to PX market prices. Instead, they are
based on the actual costs of the generating units under contract. Most of the
IOU-owned generators in California were declared must-run by their owners. The
ISO will examine each must-run contract during the Transition and retain those
required for system reliability. The ISO's use of must-run contracts through the
Transition Period was authorized by AB 1890. Service procured under must-run
contracts will be replaced by those procured competitively after the end of the
AB 1890-specified Transition Period.
2.4 THE CALIFORNIA PX
The PX is responsible for managing the transactions for all power auctioned
through, and purchased by, market participants except those bound by contract.
It was mandated by AB 1890 and set-up as a private,
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non-profit corporation subject to regulation by FERC. The different auctions
include the Day-ahead Market, Hour-ahead Market, Real-time Market, and an
Ancillary Services Market.
The Day-ahead Market is the most forward-looking of the scheduled markets, and
is the largest in terms of total volume. It will give participants the
opportunity to buy and sell energy for each hour of the 24-hour trading day on a
day-ahead basis.
The Hour-ahead Market is also a forward-looking, scheduled market, but its scale
is much smaller in terms of both ahead-time and total volume. It will give
participants the opportunity to adjust their schedules two hours before the hour
of operation.
The Real-time Market is dramatically different from the scheduled Day-ahead and
Hour-ahead markets, in that it is not forward-looking. Rather, it seeks to
balance the real-time differences actually experienced between scheduled and
metered values for load and generation.
2.4.1 California PX Prices
Actual monthly average California PX prices are shown in Table 2-2 below. While
monthly average prices reveal some of the variation in power prices that
occurred in 1998, a truer depiction of the actual variability in prices day to
day, and even within a day, are displayed in Figure 2-1. The Figure shows actual
high, low and average prices in the California PX Day-ahead market throughout
1998 and for the first two weeks of January 1999. The average daily price is
highlighted in bold and the high/low range for the day is depicted by the length
of the gray-shaded vertical line.
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Table 2-2
Monthly Average California PX Prices-
April 1998 to January 1999
($/MWh)
Month On-Peak Off-Peak Average
- --------------------------------------------------------------
April, 1998 26.84 18.55 22.60
- --------------------------------------------------------------
May 17.37 6.92 11.49
- --------------------------------------------------------------
June 16.97 7.43 12.09
- --------------------------------------------------------------
July 40.61 24.39 32.42
- --------------------------------------------------------------
August 54.27 27.38 39.53
- --------------------------------------------------------------
September 42.18 26.19 34.01
- --------------------------------------------------------------
October 30.81 22.91 26.65
- --------------------------------------------------------------
November 29.45 22.50 25.74
- --------------------------------------------------------------
December 33.50 24.87 29.13
- --------------------------------------------------------------
January, 1999 24.78 17.81 20.96
- --------------------------------------------------------------
Note: On-peak is defined as the weekday hours between the 7:00 A.M. and
11:00 P.M. Off-peak consists of the hours between 11:00 P.M. and 7:00
A.M. on weekdays and all hours during weekends and holidays.
2.4.2 Short Run Avoided Costs
All QFs are compensated on the basis of the SRAC of the IOU purchasing the
power. The Project currently receives payment under the SRAC "Transition
Formula" for Southern California Edison (SCE). This "formulaic" SRAC is a linear
function of the price of natural gas as measured at the "California Border."
Table 2-3 presents a forecast of the annual average SRAC price, as computed
pursuant to the existing SRAC Transition Formula for SCE. The gas prices
(southern California border prices) used to make this calculation are the same
as the long term gas price forecast used in the HESI model to produce the Base
Case MCP forecast.
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Figure 2-1
California PX Daily Prices - High, Low and Average
(GRAPHIC APPEARS HERE)
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1999 - 2009
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Table 2-3
SCE Annual Average
Short-Run Avoided Costs of Energy
Price of Gas SCE SRAC
YEAR ($/MMBtu) ($/MWh)
- ---------------------------------------------------------------
1999 2.39 29.5
- ---------------------------------------------------------------
2000 2.49 32.4
- ---------------------------------------------------------------
2001 2.59 33.4
- ---------------------------------------------------------------
Note: The SRAC prices shown are weighted averages with the weights based
on the number of hours in each "time-of use" period as defined by Southern
California Edison. The 1999 estimate consists of actual values to April
and forecast values thereafter.
While HESI has estimated SCE SRAC prices through 2001, we believe, however, that
competitive-based PX pricing will replace the SRAC as early as the beginning of
2000. Appendix D shows monthly time of day SRAC estimates for the same time
period. Also in Appendix D are revised monthly SRAC price estimates using a more
up-to-date short-term monthly gas price forecast.
2.5 PX PRICES AS A MEASURE OF AVOIDED COST
The SRAC Transition Formula is expected to be in effect until several conditions
are met. One condition is the divestiture by California IOUs of their California
fossil-fired generation, a process expected to be completed in the next twelve
months. The other is a determination by the CPUC that the PX market is
"functioning properly." Currently, PX operations are being gradually phased in.
Once complete, the CPUC will likely wait several more months before determining
whether the PX is functioning properly - a determination which could be subject
to several more months of regulatory delay. However, if PX market prices are
substantially below Transition Period SRAC prices, utilities will be motivated
to seek a change in SRAC pricing more quickly. PX prices have been substantially
lower than SRAC prices for the most part. HESI's MCP forecasts support the
notion that annual average PX prices will likely continue to be lower than SRAC
prices throughout the Transition Period. Given the above considerations, the
change from the Transition Formula pricing to PX pricing should occur at the
beginning of 2000.
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1999 - 2009
3 SOUTHERN CALIFORNIA MCP FORECAST: KEY ASSUMPTIONS AND METHODOLOGY
- -------------------------------------------------------------------------------
3.1 MODELING METHODOLOGY AND TECHNIQUES
To develop a forecast of market clearing prices for the Southern California
Transmission Area, simulation of the entire Western Systems Coordinating Council
(WSCC) electrical system was required. Such a simulation requires a vast amount
of data regarding power plants, fuel prices, transmission capability and
constraints, and customer demands.
HESI utilizes its proprietary Electric Market Simulation System (EMSS) and its
MULTISYM(TM) production cost model to simulate the operation of the WSCC. EMSS
is a sophisticated application of relational database technology, which operates
in conjunction with a state-of-the-art, multi-area, chronological, production
simulation model. It is used to manage the tens of thousands of individual data
points necessary to properly characterize the WSCC electric system for the
forecast.
The types of data managed by the EMSS database include the data necessary to
correctly consider the configuration of the regional transmission system. This
includes:
. individual power plant characteristics;
. transmission line interconnections, ratings, losses, and wheeling rates;
. forecasts of resource additions and fuel costs; and
. forecasts of loads for each utility in the region.
MULTISYM(TM) simulates the operation of the individual generators, utilities and
control areas (also referred to as transmission areas) within the region, taking
into consideration various system and operational constraints. Output from the
simulation is generated in hourly, station-level detail and provided in database
format. This data may then be aggregated and sorted for any level of aggregation
required by the user.
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3.2 ASSUMPTIONS REGARDING THE CALIFORNIA MARKET TRANSITION PERIOD
It is assumed during the Transition Period that the market will consist of a
limited number of generators that will be required to operate competitively in
the market. AB 1890-mandated regulatory Must-Take generation and regulatory
Must-Run contracts provide for the continuation of capacity payments through the
Transition Period. Must-Take includes power from QF resources, nuclear units,
and existing purchase power agreements that have minimum-take provisions. Must-
Take units not subject to competition are scheduled with the ISO on a must-take
basis. Must-Take units owned by municipal and public power agencies are assumed
to continue operating as they did in the past.
Units identified on the ISO's Must-Run contract list will end up with one of
three types of Must-Run contracts - A, B, or C. This study assumes that most
Must-Run contracts will be Must-Run "B". This type of contract allows generators
to cover their fixed costs of operation through a payment by the ISO. Those
units that do not sign the "B" contract and remain on an "A" contract will
generally be those that are must-run or follow load, such as hydroelectric.
There will also be few Must-Run "C" contracts. These contracts require that the
units be dedicated to the ISO in exchange for full cost recovery, but do not
allow the unit to bid independently into the market. The ISO has the right to
terminate any Must-Run contract it deems unnecessary on 90-days notice.
Since a majority of the generating units both inside and outside of California
will generally continue to bid to the PX just above their variable cost of
production until the end of the AB 1890 specified Transition Period, we assume
that the PX closely resembles a variable cost pool in the near term. At the end
of the Transition Period, fixed costs will also be recovered through the PX.
Thus, a relatively small number of units will be exposed to full competition
during the Transition Period.
We have forecasted the Must-Run contracts to impact the market through the end
of 2001 by putting downward pressure on PX prices. The Must-Run contract
payments cover much of the generators' costs by allowing fixed costs to be
recovered through the ISO. Thus, these generators will not require higher PX
prices to recover their fixed costs. When the contracts terminate during, or at
the end of, the Transition Period, all generators will be required to recover
their costs through normal,
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competitive trading activities. The model takes into account the phasing out of
the Must-Run contracts in the Transition Period, resulting in an increase in PX
prices.
3.3 KEY ASSUMPTIONS FOR MODELING THE WSCC POWER MARKET
3.3.1 Forecast Horizon
The forecast period covers a twenty-year period beginning January 1, 2000 and
ending December 31, 2009.
3.3.2 Market Structure
It is assumed that all generators in the WSCC, except a few in California that
were not declared Must-Run, receive some payment for capacity through 2001, the
end of the Transition Period specified in AB 1890. From 2002 through 2009 there
are no capacity payments to the California generators. We assume non-California
generators will continue to operate with regulated tariffs and capacity payments
from 2002 through 2004. We believe the market will become fully competitive by
2005 and, from that point forward, all generators will need to recover capacity
costs through the market.
3.3.3 Existing Resource Base
All existing generation units within the WSCC are included in the analysis.
HESI's database contains information regarding all such units and their
performance characteristics. This data has been updated to reflect the most
recent filings made by utilities regarding their resources. Much of this data
was taken from the "OE-411" and is current as of January 1, 1997. Generation
resource data were also supplemented by a review of specific utility resource
plan filings and reports generated by state agencies. Existing resources are
assumed to continue operating through the forecast horizon, except for those
resources that have specific retirement dates or assumed retirements.
3.3.4 Resource Retirements
We have conservatively estimated the retirements to be only those publicly
announced, except in the case of the nuclear units. Recent CPUC decisions on
rate recovery allow California utilities to recover investments in nuclear
plants on an accelerated schedule. Investments in Diablo Canyon and Palo Verde
will therefore be fully recovered by the end of 2001 and San Onofre by the end
of 2003. After this special rate treatment
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period ends, these plants must compete individually. All costs will have to be
recovered in the competitive energy market. HESI believes that Diablo Canyon and
San Onofre will not be competitive in the new environment and so will be shut
down shortly after their investments are recovered, in 2001 and 2003
respectively. Palo Verde is assumed to operate throughout the forecast period.
3.3.5 Generic Resource Additions
HESI believes that gas-fired combined cycle units (CC) and gas-fired combustion
turbines (CT) will be added as needed to meet the projected increase in customer
demand over the forecast period. HESI's analysis assumes that generation
resources will be added over the forecast period in a 3 CC MWs to 1 CT MW ratio
for all trans-areas.
Table 3-1 lists the cost and performance assumptions for these resources.
Table 3-1
Generic Resource Characteristics (1996 dollars)
Combustion
Unit Characteristic Turbine Combined Cycle
- --------------------------------------------------------------------------
Capacity (MW) 120 240
- --------------------------------------------------------------------------
Heat Rate (Btu/kWh) 11,000 7,100
- --------------------------------------------------------------------------
Fixed O&M ($/kW- year) 3.00 10.00
- --------------------------------------------------------------------------
Variable O&M (dollars/MWh) 4.00 2.00
- --------------------------------------------------------------------------
Forced Outage Rate (%) 0.00 2.00
- --------------------------------------------------------------------------
Maintenance Outage Rate (%) 4.00 4.00
- --------------------------------------------------------------------------
3.3.6 Loads
HESI is using the latest available data to project future customer demand and
energy requirements. This data was filed electronically by the utilities with
the Federal Energy Regulatory Commission (FERC) early in 1997, and represents
each utility's most recent recorded historic loads and their most recent load
forecast data. HESI has used data approved by the California Energy Commission
in its 1996 Electricity Report for the California utilities.
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3.3.7 Load Shape
The load shape is based on recent historic load data filed with the FERC by
utilities which reflects their complete hourly loads over calendar years 1993
through 1996. HESI has used these load shapes to create a load shape consistent
with the load forecasts provided by utilities. These "synthetic" load shapes are
used to project the shapes of future utility loads based on the load growth data
described in section below.
3.3.8 Load Growth
Based on the load forecasts filed with the FERC in 1996 under Form 714 and on
more recent information filed to state regulatory agencies, including California
ER96, peak demand and energy requirements for the entire WSCC are expected to
both grow at less than 2 percent per year through the study.
3.3.9 Inflation
General inflation drives a number of cost elements that underlie power market
prices, including operations and maintenance (O&M) costs and the cost of new
resource additions. General inflation is combined with expectations of real
price escalation in order to forecast future fuel prices. For this study
inflation was assumed to be 3.0 percent per year.
3.3.10 Fuel Prices
There are two principal fuels that drive electricity prices in the WSCC region -
- - natural gas and coal.
3.3.11 Natural Gas
Introduction
- ------------
Gas-fired generators are dispatched according to the cost of natural gas at the
burner-tip. HESI models gas burner-tip prices as the sum of the commodity
price - the cost of gas at a particular producing area, and all relevant
transportation charges involved in transporting it from the supply basin to the
generation plant.
Two of the major natural gas producing areas that supply natural gas to power
generators in the WSCC are the Western Canada Sedimentary Basin (WCSB), which is
located mainly in Alberta, Canada and the San Juan Basin, situated mainly in New
Mexico.
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Although generators within the WSCC sometimes use gas from other basins, HESI
assumes that only one gas basin will set the key marginal gas price for each
generator. Generating stations in New Mexico, Southern Nevada, Arizona, and
Southern California are supported by the San Juan Basin. The WSCB basin is
assumed to supply generating stations within Alberta and British Columbia.
Alberta also supplies electric generators located in Washington, Oregon, Idaho,
Montana, Wyoming, Utah, Northern Nevada, and Northern California.
The HESI methodology assumes therefore that the burner-tip gas price for each
gas-fired generation plant will depend mainly on its location relative to the
supply basins that are accessible to it and the cost of shipping gas from those
basins to the plant. The commodity and transportation components of natural gas
burner-tip prices are forecast separately and then added together to derive the
prices paid by generation plants appropriate to their geographic location. A
description of commodity and transportation cost forecast methodology is
presented in more detail below.
Gas Commodity Price Forecast Methodology
- ----------------------------------------
HESI utilizes a "Delphi" approach to forecasting gas commodity prices. That is,
HESI collects various recent expert forecasts of Alberta and San Juan commodity
prices and generally takes the simple average as the Base Case forecast.
The expert sources for the Alberta commodity price forecast are the "Natural Gas
Market Outlook" by the California Energy Commission (CEC), "Annual Energy
Outlook 1998 with Projections to 2020" by the Energy Information Administration
(EIA), and "Natural Gas: Review of 1997 and Outlook to 2005", from Natural
Resources Canada (NRCan)./4/ The NRCan report itself contains a survey of
Alberta commodity gas prices from various sources. The prices in the NRCAN
survey, combined with the CEC forecast, constitute the consensus from which the
HESI Base Case forecast is derived for the years 1998 to 2005.
- --------------------
/4/"Natural Gas Market Outlook," California Energy Commission, June 1998;
"Natural Gas: Review of 1997 and Outlook to 2005," Natural Gas Division, Natural
Resources Canada, May 1998; "Annual Energy Outlook 1998 with Projections to
2020," Energy Information Administration, Department of Energy, December 1997.
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Figure 3-1 shows the Alberta commodity price forecasts contained in the NRCan
report between 1999 and 2005, the CEC forecast, and the HESI Base Case forecast
derived from these sources./5/ From 2006 onward, the HESI Base Case forecast in
2005 is escalated according to the average of growth rates of the CEC's Alberta
commodity price forecast and the EIA's average Canadian import gas price
forecast. The EIA's forecast is therefore not directly shown in Figure 3-1, but
appears indirectly as a contributor to the projected growth rate of the HESI
forecast.
Figure 3-1
Alberta Gas Commodity Price Forecasts
[GRAPH APPEARS HERE]
The sources for the San Juan commodity price forecast are again the CEC's
"Natural Gas Market Outlook" and the EIA's "Annual Energy Outlook. The HESI Base
Case forecast is derived by averaging the CEC
- -------------------
/5/In Figure 3.1, ARC refers to the ARC Financial Corporation, a Calgary-based
oil and gas investment advisor. PIRA is the PIRA Energy Group, a New York-based
petroleum industry research firm and CERI is the Canadian Energy Research
Institute.
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1999-2009
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and EIA forecasts in all years between 1998 and 2020./6/ These forecasts are
shown in Figure 3-2.
Figure 3-2
San Juan Gas Commodity Price Forecasts
[GRAPH APPEARS HERE]
Factors Affecting Future Gas Commodity Prices
- ---------------------------------------------
Natural Gas consumers in California and other Western states have enjoyed
relatively inexpensive natural gas commodity prices for a number of years. The
main reasons have been intense competition among gas producers to maintain or
expand market share and slower than anticipated demand growth in California.
Although both Alberta and the San Juan areas are major suppliers of natural gas
to the WSCC, both regions currently suffer from a lack of take-away capacity.
Consequently, producer prices, or netbacks, have been relatively weak compared
to prices received by producers in other producing regions, particularly the
Louisiana and Anadarko producing regions, which have access to large markets in
the Midwest and the Eastern U.S. However, most forecasters expect this situation
to change in the near future, particularly in Alberta's case, due to pipeline
capacity expansions that are either in-progress or
- --------------------
/6/ The CEC forecast shown is actually the current actual San Juan price
escalated according to the forecast annual average real growth rate contained in
the CEC forecast.
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planned over the next few years. As a result, expert opinion, such as the CEC,
the EIA and NRCan, expect commodity prices in these regions to increase at rates
that are above price rises projected for most other producer basins.
Accordingly, the HESI Base Case forecast assumes that Alberta and San Juan based
gas commodity prices will increase over the long term at average annual real
rates of 1.8 and 1.6 percent respectively. In comparison, the consensus opinion
is that Gulf Coast prices will increase, on average, in the range of 1 percent
per year over the long term. The following sections discuss developments in the
Alberta and San Juan producing regions that are likely to impact on gas prices
paid by generation plants in the WSCC.
Pipeline capacity in the San Juan basin was developed in the late 1980s to serve
the California market. However, the expected growth in demand never really
materialized. As a result, the region has suffered from excess capacity.
Currently, producers are attempting to expand deliverability eastward. According
to the EIA, the two major intestate pipelines in the area, Transwestern and El
Paso Natural Gas, are expanding facilities which would allow them to direct more
production to the market centers in Southwestern Texas, which would then allow
San Juan producers access to Midwest and Northeast markets./7/
Although TransCanada Pipeline, the major pipeline link between Canadian
producers and eastern U.S. markets, has increased domestic deliverability the
last few years, significant constraints still prevent Alberta producers from
fully accessing these markets. However, a number of projects are planned that
will greatly improve export capability. The most notable of these is the
Alliance project, which would tie Alberta and British Columbia producers
directly to the Chicago market. Also, Great Lakes Gas Transmission and Iroquois
Transmission plan to expand their systems in the Midwest and the Northeast
respectively. Finally, Foothills Pipe Line Ltd. and the Northern Border Pipeline
have obtained approval to expand export capability at the Montana border./8/
- --------------------
/7/"Deliverability on the Inter-state Natural Gas Pipeline System," Department
of Energy, Energy Information Administration, May 1998, page 125.
/8/IBID, page 126-127.
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Implications for the WSCC Region
- --------------------------------
Although the planned pipeline capacity expansions in the San Juan and Alberta
producing regions do not directly affect the volumes flowing to California and
other Western U.S. states, the impact will nonetheless be significant. This is
because generation plants in the WSCC will face greater competition for Alberta
and San Juan produced natural gas from bidders in other market regions.
The Alberta commodity price is therefore expected to rise towards prices in U.S.
markets as Alberta supply becomes more tightly linked to prices in the U.S. For
example, the EIA long term forecast expects Canadian import prices to increase
at about 1.5 percent per year in real terms from 1998 to 2020, while Gulf Coast
prices are projected to increase at only 0.8 percent real over the same period.
Similarly, Southwest prices, which include San Juan, increase at about 1.0
percent per year, somewhat above the U.S. wellhead average price forecast by the
EIA.
Following a similar analysis, the CEC expects both San Juan and Alberta
commodity prices to increase at 2 percent per year in constant dollars. In
comparison, prices in the Gulf Coast and Rocky Mountain regions increase at
about 1 percent per year. Table 3-2 shows projected commodity price growth rates
from the CEC and EIA source documents and the HESI Base Case growth rates,
which, as described, are derived from these projections. The HESI gas commodity
price forecast is shown for selected years in Table 3-3 on the accompanying
page.
Table 3-2
Projected Gas Commodity Price Growth by Producer Basin
(Average Annual Real Percent Change)
CEC EIA HESI Base
Producing Region 1999 - 2019 1998 - 2020 1999 - 2009
- --------------------------------------------------------------------------------------
Henry Hub (Gulf Coast) 1.3% 0.8% NA
- --------------------------------------------------------------------------------------
Rocky Mountain 1.0% 1.5% NA
- --------------------------------------------------------------------------------------
Permian (SW Texas) 1.9% 1.0% NA
- --------------------------------------------------------------------------------------
Anadarko (mid-continent) 1.9% 0.8% NA
- --------------------------------------------------------------------------------------
San Juan (New Mexico) 2.0% 1.0% 1.6%
- --------------------------------------------------------------------------------------
Alberta (Canadian Imports) 2.0% 1.5% 1.8%
- --------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
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Table 3-3
HESI Base Case San Juan and Alberta
Commodity Price Forecast
$98/MMBtu
San Juan Alberta
- -----------------------------------------------
1999 2.17 1.50
- -----------------------------------------------
2000 2.20 1.57
- -----------------------------------------------
2001 2.22 1.63
- -----------------------------------------------
2002 2.24 1.68
- -----------------------------------------------
2003 2.27 1.70
- -----------------------------------------------
2004 2.30 1.74
- -----------------------------------------------
2005 2.33 1.78
- -----------------------------------------------
2010 2.54 1.94
- -----------------------------------------------
2015 2.74 2.03
- -----------------------------------------------
2009 2.86 2.11
- -----------------------------------------------
The Estimation of Monthly Natural Gas Prices
- --------------------------------------------
HESI converts the Base Case annual average forecast of gas commodity prices to
monthly prices using a set of estimated monthly (seasonal) factors. These
factors are held constant throughout the forecast. The monthly factors are
derived from historical monthly average 30-day spot prices reported in the
Weekly Gas Price Index and published by Natural Gas Intelligence. In particular,
HESI estimates a set of "normalized" monthly factors that attempt to portray
typical or normal variation in gas prices. The annual San Juan commodity gas
price is converted to monthly prices using estimated monthly variation at
Topock - which represents the market pricing point for most natural gas
purchases in Southern California, Arizona, and Southern Nevada. Alberta-based
annual commodity prices are converted to monthly prices using estimated monthly
variation at Malin - a major pricing point for gas purchases in Northern
California, Oregon, and Northern Nevada.
The details of the estimation procedure are discussed with reference to Figure
3-3 below, which shows actual and estimated monthly variation in gas spot
prices, in ratio form, at Topock. Ratio form is defined here as the average of
actual monthly prices relative to the annual average price for all similar
months, using historical data from January 1991 and October 1998. In other
words, the January actual price shown in Figure 1-3 represents the average of
all January to annual ratios between 1991 and 1998. The ratios
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therefore represent the typical or average variation in monthly prices relative
to the annual average price observed at Topock over the last eight years.
Figure 3-3
Actual and Estimated Monthly Gas Price Variation at Topock
[GRAPH APPEARS HERE]
As a final step, the observed average variation is smoothed according to a
polynomial curve that is fitted by least squares regression. The smoothed
monthly factors are then adjusted slightly so that their average is equal to
unity. As the chart shows, in the case of Topock, most of the adjustment is
added to the January estimate - since the fitted line underestimates actual
variation in this month. An identical procedure is applied to the forecast of
annual average Alberta prices using historical monthly price variation at Malin.
Gas Transportation Price Methodology
- ------------------------------------
Pipeline transportation costs are added to basin prices to determine city-gate
gas prices. The city-gate is defined as the point of delivery from inter-state
transmission pipelines to Local Distribution Company (LDC)
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systems. Transportation costs can potentially consist of both inter-state
transmission charges and LDC costs. However, for most generators, city-gate
prices are the relevant marginal gas costs used to "dispatch" their electric
systems, either because the generation owners receive service directly from
pipelines or pay only nominal additional charges to an LDC. In other areas,
additional charges for intra-state or LDC transportation must be added to yield
the dispatch price of gas.
The forecasts of inter-state transportation costs in the HESI model reflect
historic differences between city-gate prices and commodity prices from the
respective gas supply basins. Additionally, the monthly price profile of the
referenced city-gate is used to approximate the monthly variation in gas
transportation costs arising from fluctuations in shipper volumes.
Local Distribution Company Charges
- ----------------------------------
The key generators receiving LDC gas transportation service are California's
electric generators. Thus, for these generators, LDC charges, based on LDC
tariffs, are added to the California border price./9/ Generators situated in
Northern California are assumed to purchase gas at prices equivalent to the
Northern California border price and generators situated in Southern California
purchase gas at prices that reflect the Southern California border. The Alberta
commodity price plus transportation costs to Malin, Oregon, (located just north
of the California border) constitutes the Northern California border price. The
San Juan commodity price plus transportation to Topock (south of Needles,
California near the California-Arizona border) represents the Southern
California border price.
The LDC charges are based upon estimates of actual 1996 charges and are held
constant in real dollars at these levels through the study horizon.
Historically, with the majority of generation owned by utilities, much of the
fixed cost of gas transportation would be included in fixed cost components of
electric retail customer rates, resulting in only a small portion of such gas
transportation being recognized in daily and hourly generation dispatch
decisions. This practice tended to reduce the assumed marginal generation cost
for an individual generation unit dispatch decision. In a competitive market,
buyers and sellers will determine what costs can be recovered and so generators
will not be able to rely upon
- --------------------
/9/The California border price is similar in some respects to a city-gate price
in that it represents the price of natural gas at a point where an inter-state
transmission line connects to an LDC distribution pipeline.
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regulated rates to automatically recover fixed costs of gas transportation.
Therefore, the full cost of gas transportation will need to be recovered from
energy sales, or generators will face the possibility of under-recovery of gas
transportation costs, which cannot be sustained on a long-term basis. This
change is expected to have some upward pressure on market clearing prices and is
reflected in the HESI market clearing price model.
Total Gas Costs
- ---------------
Table 3-4 summarizes much of this section's discussion. It shows the
relationship between generator location, producer basin and the city-gate. For
example, for generators in the Northwest, excluding the Seattle area, the
referenced basin is Alberta and the city-gate price consists of the Alberta
commodity price plus inter-state transportation costs to the market hub at
Stanfield, Oregon. In the case of generators located in the service territory of
Southern California Edison, the burner-tip price consists of the San Juan
commodity price, inter-state transportation costs from the San Juan producer
region basin to the Southern California border, near Topock, and finally LDC
charges on the SCE transmission system from Topock to the burner-tip.
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1999 - 2009
- --------------------------------------------------------------------------------
Table 3-4
HESI Base Case Natural Gas City-Gate Price Forecast
$1998/MMBtu
Generation PNW- North South
Location Alberta B.C. Coastal PNW NV NV PG&E
- -----------------------------------------------------------------------------------------
Commodity
Basin WCSB WCSB WCSB WCSB WCSB San Juan WCSB
- -----------------------------------------------------------------------------------------
Referenced
Market PGE
Hub/City- City-
gate AECO-C Sumas Sumas Stanfield Malin South NV gate
- -----------------------------------------------------------------------------------------
1999 1.50 1.71 1.71 1.80 1.97 2.33 2.15
- -----------------------------------------------------------------------------------------
2000 1.57 1.78 1.78 1.87 2.04 2.36 2.22
- -----------------------------------------------------------------------------------------
2001 1.63 1.84 1.84 1.93 2.10 2.38 2.28
- -----------------------------------------------------------------------------------------
2002 1.68 1.89 1.89 1.98 2.15 2.40 2.33
- -----------------------------------------------------------------------------------------
2003 1.70 1.91 1.91 2.00 2.17 2.43 2.35
- -----------------------------------------------------------------------------------------
2004 1.74 1.95 1.95 2.04 2.21 2.46 2.39
- -----------------------------------------------------------------------------------------
2005 1.77 1.98 1.98 2.07 2.24 2.49 2.42
- -----------------------------------------------------------------------------------------
2010 1.94 2.15 2.15 2.24 2.41 2.70 2.59
- -----------------------------------------------------------------------------------------
2015 2.03 2.24 2.24 2.33 2.50 2.90 2.68
- -----------------------------------------------------------------------------------------
2020 2.18 2.39 2.39 2.48 2.65 3.13 2.83
- -----------------------------------------------------------------------------------------
Generation Rocky Mt
Location SCE Coolwater SDGE AZ/NM Rocky Mt -Colo.
- -----------------------------------------------------------------------------------------------
Commodity San San San San
Basin Juan Juan Juan Juan WCSB San Juan
- -----------------------------------------------------------------------------------------------
Referenced
Market SCE SCE SCE
Hub/City- City- City- City-
gate gate gate gate AZ/NM Opal Denver
- -----------------------------------------------------------------------------------------------
1999 2.32 2.32 2.32 2.31 1.78 2.17
- -----------------------------------------------------------------------------------------------
2000 2.35 2.35 2.35 2.34 1.85 2.20
- -----------------------------------------------------------------------------------------------
2001 2.37 2.37 2.37 2.36 1.91 2.22
- -----------------------------------------------------------------------------------------------
2002 2.39 2.39 2.39 2.38 1.96 2.24
- -----------------------------------------------------------------------------------------------
2003 2.42 2.42 2.42 2.41 1.98 2.27
- -----------------------------------------------------------------------------------------------
2004 2.45 2.45 2.45 2.44 2.02 2.30
- -----------------------------------------------------------------------------------------------
2005 2.48 2.48 2.48 2.47 2.05 2.33
- -----------------------------------------------------------------------------------------------
2010 2.69 2.69 2.69 2.68 2.22 2.54
- -----------------------------------------------------------------------------------------------
2015 2.89 2.89 2.89 2.88 2.31 2.74
- -----------------------------------------------------------------------------------------------
2020 3.12 3.12 3.12 3.11 2.46 2.97
- -----------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------
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1999-2009
- --------------------------------------------------------------------------------
Coal
- ----
HESI bases its coal prices on historic power plant specific coal price data
extracted from the "Form 423's" utilities regularly file with the FERC. The Form
423 data include historic consumption as well as both spot and average
(transportation and so-called fixed fees included) prices. Given the competitive
nature of fuel supply markets and the current pricing of coal relative to gas,
HESI expects no coal price escalation through the forecast period. HESI used
spot coal prices to simulate the economic operation of coal plants. Spot prices
are historically about 77 percent of average prices.
3.3.12 Operations & Maintenance
Power plant specific non-fuel O&M costs are reported by utilities in annual
reports to the FERC in a number of separate accounts. HESI averages these data
for the 1991 through 1995 time periods (normalized for constant year dollars) to
develop average starting O&M costs. The amounts in these various accounts are
then allocated between fixed and variable O&M. To derive a unit's fixed O&M
cost, the total O&M cost is decreased by the variable O&M cost component. Both
fixed and variable O&M costs are assumed to escalate with inflation.
3.3.13 Property Taxes
Property taxes are set by local jurisdiction and so vary throughout the WSCC. In
California they are 1.09 percent of remaining generation station book value. In
other jurisdictions, the rates range from 0.4 percent to approximately 4
percent. For purposes of establishing the property tax component of going
forward costs, jurisdictional tax rates will be used.
3.3.14 Insurance
Insurance is calculated as 0.2 percent of the remaining, undepreciated book
value of the power plant.
3.3.15 Other Costs
In addition to fuel costs, a power plant operator experiences other costs
associated with the on-going business of producing power. These costs include
O&M, property taxes and insurance. For the most part, these costs can be avoided
if a facility is "mothballed" or retired, and thus are included in power plant
bids when performing competitive market analysis.
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1999-2009
- -------------------------------------------------------------------------------
3.4 WSCC TRANSMISSION SYSTEM CONFIGURATION
In order to perform a study of the Southern California market prices likely to
result from the PX, the operation of the transmission system in the entire WSCC
region must be modeled. The transmission system configuration for this study is
shown in Figure 3-4. This characterization reflects the zones proposed by the
California IOUs in their PX applications to FERC.
Figure 3-4
WSCC Transmission System Configuration
[GRAPHIC APPEARS HERE]
3.5 HYDRO POWER
3.5.1 Median Year Case
HESI utilized average or median hydro conditions depending on the WSCC sub-
region and the data available. The sources for these data follow.
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1999-2009
- -------------------------------------------------------------------------------
Pacific Northwest (PNW) Hydro Data
- ----------------------------------
The hydroelectric generation in the PNW accounts for almost half of the hydro
generation in the entire WSCC. HESI used the Bonneville Power Administration's
(BPA) 1996 Pacific Northwest Loads and Resources Study to update hydroelectric
data in the PNW. HESI calculated monthly capacity and energy values for each
hydroelectric station in the PNW based on this data, choosing the median
conditions from a recorded database of 50 years.
Hydro Data for Other Regions
- ----------------------------
Hydro data for the other regions come from a number of sources and are updated
periodically by HESI.
The WSCC Coordinated Bulk Power Supply Program document was used for the
majority of the plant capacity data for plants outside the Northwest. This
document is the WSCC's response to the Department of Energy's Form OE-411. It
includes summer and winter capacity ratings for all of the existing hydro and
thermal resources in the WSCC.
The McGraw Hill Electrical World Directory of Electric Utilities (The
"Bluebook") was the source of hydro plant energy data in a number of the WSCC
regions.
3.5.2 Transactions
HESI incorporates known firm, contracted power transactions into its model, as
reported by the WSCC in the annual FERC Form OE-411 Filing. The transactions are
reflected in the load requirements of the buying and selling utilities, in
transactions between regions, and by adjusting the transmission capacity. Any
remaining transmission capacity is used to facilitate additional power
transactions between regions.
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4 SOUTHERN CALIFORNIA MCP FORECAST: RESULTS
- -------------------------------------------------------------------------------
The following sections summarize the model results from the Base Case and the
two Low Gas price sensitivity cases. Gas prices are sensitized due to the fact
that gas-burning generators are the marginal cost producers and therefore a
major influence on the MCP in California. Any additional baseload capacity must
therefore be a low cost producer and a price taker. Additional intermediate
capacity will need to be flexible enough to accommodate hourly load
fluctuations. The gas-fired combined-cycle and combustion turbines are the most
flexible technologies to meet these needs cost-effectively. The role of these
units and the impact of gas prices in setting wholesale power prices will
increase over time, making gas the ideal input to vary for sensitivity. To test
this sensitivity two gas price downside cases are developed as described in the
sections below.
4.1 BASE CASE SOUTHERN CALIFORNIA MCP FORECAST, 2000 - 2009
The Base Case annual average MCP forecast for the Southern California
transmission area is presented in Table 4-1.
The annual average MCP increases at an annual average of 12.6 percent per year
between 2000 to 2002. This is the Transition Period during which most market
players bid selling prices into the market which reflect their short run
marginal costs. During this period, most IOU-owned generators receive payments
for capacity from the ISO Must-Run contracts, if in California, or through
traditional tariffs, if outside of California. The capacity payments cease for
most ISO-contracted Must-Run generators by the end of 2001.
After the AB 1890 Transition Period ends in March 2002, the power pool should
cease to behave as a marginal cost pool. We believe California generators will
begin to recover some, though not all, of their fixed costs through their sales
through the PX. However, they will continue to compete with out-of-state
generators that continue to receive capacity payments through their regulated
rates and may continue to bid as if the PX was a marginal cost pool. This change
is reflected in the average annual MCP increasing from $34.13/MWh in 2002 to
$40.35/MWh by
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1999-2009
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2005. From 2002 to 2005, California generators are exposed to the competitive
market, but their out-of-state competitors continue to receive capacity
payments. The average power price increases at an annual average rate of 5.7
percent during this period.
Table 4-1
Base Case Southern California MCP Forecast
2000 - 2009
$/MWh
Average On-Peak Off-Peak
- -------------------------------------------------
2000 26.93 32.74 21.64
- -------------------------------------------------
2001 28.60 34.62 23.14
- -------------------------------------------------
2002 34.13 41.32 27.60
- -------------------------------------------------
2003 36.17 44.00 29.05
- -------------------------------------------------
2004 37.67 45.53 30.54
- -------------------------------------------------
2005 40.35 49.05 32.45
- -------------------------------------------------
2006 41.63 51.28 32.86
- -------------------------------------------------
2007 42.37 52.20 33.44
- -------------------------------------------------
2008 43.01 52.82 34.09
- -------------------------------------------------
2009 44.27 54.75 34.75
- -------------------------------------------------
HESI assumes that the entire WSCC will be competitive starting in 2005 and that
the bidding behavior of generators reflects their efforts to recover fixed costs
through sales to the PX. The MCP increases slowly but steadily from $40.35/MWh
in 2005 to $44.27/MWh by 2009 - an average rate of increase of 2.3 percent per
year, which is less than the rate of inflation.
4.2 SENSITIVITY CASES
4.2.1 Low Gas Price Case 1
In the Low Gas Case 1, the gas price decreases each year until it is 10 percent
below the Base Case gas price. It is then held constant at 10 percent below the
Base Case gas price in all remaining years of the analysis. This low gas
scenario, while unlikely, could occur if there was an oversupply of gas, for
which there was no market, followed by a lengthy
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1999-2009
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period of recovery and market demand. The MCP forecast under this assumption is
shown in Table 4-2.
Table 4-2
MCP Forecast under the Low Gas Price Case 1
Base Case Low Gas 1
Sample Annual Average Annual Average Percent Below Base
Year MCP $/MWh MCP $/MWh Case Price
- -------------------------------------------------------------------------
2000 26.93 25.86 -3.9%
- -------------------------------------------------------------------------
2001 28.60 27.14 -5.1%
- -------------------------------------------------------------------------
2002 34.13 32.15 -5.8%
- -------------------------------------------------------------------------
2003 36.17 33.64 -7.0%
- -------------------------------------------------------------------------
2004 37.67 35.11 -6.8%
- -------------------------------------------------------------------------
2005 40.35 37.75 -6.4%
- -------------------------------------------------------------------------
2009 44.27 40.91 -7.6%
- -------------------------------------------------------------------------
4.2.2 Low Gas Price Case 2
In the Low Gas Case 2, the Base Case gas price forecast is reduced each year
until it is 15 percent below the Base Case forecast gas price. The Low Gas 2
gas price is then held at a constant 15 percent below the Base Case gas price
for the remaining years of the forecast. This scenario also requires an
oversupply of gas or a dramatic decline in demand followed by a lengthy period
of recovery. The results of this scenario are shown in Table 4-3.
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1999-2009
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Table 4-3
MCP Forecast Under the Low Gas Price Case 2
Base Case Low Gas 2 Percent
Sample Annual Ave Annual Ave Below Base
Year MCP $/MWh MCP $/MWh Case Prices
------------------------------------------------------
2000 26.93 25.65 -4.7%
- ------------------------------------------------------
2001 28.60 26.85 -6.1%
- ------------------------------------------------------
2002 34.13 31.59 -7.4%
- ------------------------------------------------------
2003 36.17 32.99 -8.8%
- ------------------------------------------------------
2004 37.67 34.22 -9.2%
- ------------------------------------------------------
2005 40.35 36.53 -9.5%
- ------------------------------------------------------
2009 44.51 39.44 -10.9%
- ------------------------------------------------------
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5 THE PROJECT AND THE CALIFORNIA MARKET
- -------------------------------------------------------------------------------
5.1 Market Analysis Results
This section presents an analysis of the Project and its position in the
competitive California market. It consists of two sets of comparisons: 1) a
comparison of unit operating cost estimates provided by the Project and
operating costs of other types of generation; 2) a comparison of the Project's
operating costs and forecasted Southern California power prices. The latter set
of comparisons were performed using the Base Case and Low Gas Price cases.
The Project is expected to be a very low cost producer in all years of the
study. Table 5-1 lists the average operating costs projected in 2005 for several
categories of generators in the WSCC region, including the Project. We selected
the year 2005 for this analysis as it is the first year in which a fully
competitive market is assumed. According to data provided by the Project
Operator, the average operating cost of the Project in 2005 is $10.8/MWh.
Therefore, we estimate that about 70 percent of the electricity produced in the
WSCC in 2005 will be generated from units with higher costs, a strong indication
that the Project would be dispatched as baseload if the Project was operating
without a PPA. Of all the generation in the region, only hydroelectric and wind
generators have lower operating costs.
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1999-2009
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Table 5-1
Average Operating Costs by Plant Type in the
WSCC from PROSYM Model Simulation in 2005/10/
Electricity Generation Average Operating Cost
Plant Type (GWh) ($/MWh)/1/
- ---------------------------------------------------------------------------------
Internal Combustion Engines 62 62.22
- ---------------------------------------------------------------------------------
Gas Turbine 26,177 39.94
- ---------------------------------------------------------------------------------
Geothermal/2/ 18,890 37.49
- ---------------------------------------------------------------------------------
Gas/Cogeneration 21,917 26.85
- ---------------------------------------------------------------------------------
Gas/Combined Cycle 151,804 25.41
- ---------------------------------------------------------------------------------
Other Renewable/3/ 6,737 23.29
- ---------------------------------------------------------------------------------
Steam Plants 335,527 18.21
- ---------------------------------------------------------------------------------
Nuclear 35,885 13.33
- ---------------------------------------------------------------------------------
The Project/4/ 2,310 10.83
- ---------------------------------------------------------------------------------
Wind 3,435 10.45
- ---------------------------------------------------------------------------------
Hydroelectric 246,434 4.91/5/
- ---------------------------------------------------------------------------------
Total 846,867
- ---------------------------------------------------------------------------------
[1] Cost based on fuel and variable O&M in nominal dollars.
[2] The operating costs of the Geothermal category reflect the fact that many of
the utility-owned geothermal facilities have long term steam contracts with
steam suppliers.
[3] Includes solar, biomass, and other renewable.
[4] Based on cost and production estimates provided by the Project Operator.
[5] Cost based on average aggregated operating expenses of hydroelectric
facilities in the WSCC as reported to FERC on FERC Form 1.
Project operating costs are compared to the Base Case annual average MCP in the
Figure 5-1 below. Inflation of 3 percent per year is embedded in both the price
and cost projections.
- ---------------------
/10/ The table displays operating cost by plant-type for various plant
categories in the Prosym simulation results. The values shown are for the
simulation year 2005 and are stated in nominal dollars. These values
reflect expenses for fuel and variable operation and maintenance only. They
do not include costs associated with fixed operation and maintenance, the
inclusion of which would increase overall costs for some plants
substantially. For example, inclusion of fixed operation and maintenance in
the nuclear category would increase the cost reported in the Table from
$13.33/MWh to $34.00/MWh. In as much as it is presently unclear what
portion of fixed costs will be recovered in the competitive market and
under what conditions, the Table should be viewed as a conservative
representation of the operational costs of these plants.
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1999-2009
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Figure 5-1
Base Case Annual Average MCP and Project Operating Costs
[GRAPHIC APPEARS HERE]
As Figure 5-1 shows, Project operating costs are expected to be well below
HESI's Base Case average annual MCP forecast. In fact, over the 2000 to 2009
period, Project costs are, on average, 69 percent below Southern California
power prices.
Figure 5-2 below compares Project operating costs to the Base Case off-peak
power price forecast. Although off-peak prices are about 25 percent below
average annual power prices, the Project is still very competitive. Project
costs are, on average, 62 percent below Southern California off-peak annual
power prices.
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1999-2009
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Figure 5-2
Base Case Annual Off-Peak MCP and Project Operating Costs
[GRAPHIC APPEARS HERE]
The last analysis compares Project operating costs to off-peak prices in the Low
Gas Price 2 Case, which is the worst-case scenario. Off-peak power prices are
about 27 percent below Base Case average annual power prices. The comparison is
shown in Figure 5-3 below. In this case, Project costs are, on average, 58
percent below off-peak prices.
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1999-2009
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Figure 5-3
Low Gas Price Case 2 Annual Off-Peak MCP
and Project Operating Costs
[GRAPHIC APPEARS HERE]
5.2 SOUTHERN CALIFORNIA MCP FORECAST AND THE MARKET POSITION OF THE PROJECT
For an additional perspective of the relative position of the Project in the
market, a table summarizing the frequency of the Southern California power price
forecast is developed. This approach captures more of the hour by hour price
variability than the preceding results. First, the hourly price results from the
Base Case year 2005 are ranked from highest to lowest. From this, the frequency
of price levels (i.e. the percentage of hours in which the price is at, or
above, a given level) is developed. The analysis for 2005 indicates that in 96
percent of the hours the power price is greater than, or equal to, $19.7/MWh.
This means that the Project, with an average operating cost of $10.8/MWh will
be below the average annual MCP more than 96 percent of the time.
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1999-2009
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Table 5-2
MCP Frequency Analysis in
Southern California Transmission Area, 2005
Minimum MCP
% of Time $/MWh
---------------------------
70 31.45
---------------------------
75 28.24
---------------------------
80 26.27
---------------------------
85 24.50
---------------------------
90 22.98
---------------------------
95 21.22
---------------------------
96 19.69
---------------------------
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1999-2009
6 THE RENEWABLE RESOURCE FUNDING PROGRAM
- -------------------------------------------------------------------------------
AB 1890 established a $540 million fund to promote and develop renewable energy
projects and directed the CEC to administer and distribute the funds. In
response, the CEC established four separate accounts to deliver these funds over
the period January 1, 1998 to January 1, 2002. Each account has been allocated a
fixed percentage of the total fund and a different distribution mechanism is
used for each account. The four accounts and the amount of funds allocated to
each are shown in Table 6-1.
Table 6-1
AB 1890 Accounts - Total Funding
Allocations by Technology
$Millions
Technology $Millions
----------------------------------------------------------
Existing Technologies 243
----------------------------------------------------------
New Technologies 162
----------------------------------------------------------
Emerging Technologies 54
----------------------------------------------------------
Consumer-Side 81
----------------------------------------------------------
Total 540
----------------------------------------------------------
Source: Policy Report on AB 1890 Renewables Funding, Report to the Legislature,
California Energy Commission, March 1998.
The "existing" and "new" categories are the most important, accounting for 75%
of the total fund disbursement. Further, these accounts are applicable to the
majority of active or economically feasible renewable energy projects in
California. The distinction between an existing and a new technology is a matter
of vintage. An existing technology refers to a facility that started operation
prior to September 23, 1996 and a new technology means a facility that started
generation on or after September 26, 1996 but before January 1, 2002. The
Project is eligible for funding under the Existing Renewable Resource category.
Existing facilities that are substantially refurbished on or after September 23,
1996 can apply for funding from the new technology category.
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1999-2009
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However, the non-refurbished portion of the facility cannot exceed 20% of the
refurbished facility's total value.
The "emerging" category is restricted to projects using small wind turbines of
10 kW or less, fuel cell technology and solar power - both photovoltaic and
solar thermal. A total of $54 million has been allocated to the emerging
technology account - $10.5 million of which became available on March 20 on a
first-come, first-served basis.
The consumer-side account is designed to promote customer participation in the
renewable energy market. This fund has been allocated $81 million in total,
which in turn is divided between two sub-accounts: a customer credit account -
which has been allotted most of the consumer-side funds, and secondly a consumer
information account.
Existing Renewable
- ------------------
The Existing Renewable Resource Account was designed to help maintain existing
renewable technologies during the first four years of the electric industry
restructuring. The total amount of funds allocated to the existing renewable
account is $243 million, which is divided among three tiers.
Existing technologies are assigned to a tier according to their cost
characteristics and potential for further cost efficiencies. Tier 1 contains
biomass and solar thermal technologies and is allocated 25% of the total
existing renewable account. Wind generation is placed in Tier 2 and is allocated
13% of the total. Tier 3 is allocated 7% of the existing renewable fund total
and consists of geothermal, small hydro, digester gas, and municipal solid waste
and landfill gas technologies.
Table 6-2
Existing Renewable Resource Account - Allocations by Tier
$Millions
Tier 1 Tier 3
Biomass, Solar, Tier 2 Geothermal, Small
Thermal Wind Hydro, Other Total
- ---------------------------------------------------------------------
$135 $70.2 $37.8 $243
- ---------------------------------------------------------------------
Source: Policy Report on AB 1890 Renewables Funding, Report to the Legislature,
California Energy Commission, March 1998, page ES-8.
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1999-2009
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The amount of funds available annually to each tier declines over the four year
period. The CEC structured the funding in this manner because they expect
renewable generation facilities to become more cost efficient over time.
Therefore, less financial help is required in order to compete in an unregulated
market.
The subsidy is distributed monthly to renewable suppliers through a simple cents
per kWh payment. However, the calculation of the subsidy is more complicated -it
is based on the lowest of three possible calculations: 1) the difference between
a Target Price and the market clearing price (the SRAC specific to each IOU is
used as a proxy for the market clearing price at present), 2) a pre-determined
cents per kWh price cap and 3) a funds adjusted price - which ensures that the
amount disbursed does not exceed the amount of funds available. The CEC
designated Target Price and Price Cap for Existing Renewable Resource Tier 3
facilities are 3.0 cents and 1.0 cents per kWh respectively. Between January and
December of 1998, the SRAC price applicable to Southern California Edison varied
from 2.7 to 3.1 cents per kWh. The average subsidy paid to eligible generators
was about 0.21 cents per kWh.
Of the $37.80 million targeted for eligible existing Tier 3 generation, $12.15
million was scheduled for disbursement in 1998, $10.80 million is planned for
1999, $8.10 million in 2000 and $6.75 in 2001. However, only $8.32 million was
actually paid out in 1998, leaving a $3.83 million surplus that can be used to
supplement funds allocated to future years. It appears therefore that additional
geothermal generation could financially benefit from the program without
adversely affecting the subsidy paid to current Tier 3 generators. However, as
shown in Appendix D, SRAC prices are forecast to be above the Target Price of
3.0 cents per kWh in all, or almost all, months in 2000 and 2001, depending upon
gas price levels. This situation is not exceptional. During 1998, a Tier 3
subsidy was not paid in six of the twelve months because the calculated SRAC
exceeded the target price.
In the event that future SRAC prices are lower than forecast here, HESI believes
that the AB 1890 program has ample funds to ensure that Tier 3 producers receive
the minimum of 3.0 cents per kWh until the end of 2001. It is important to note
that if PX-based pricing replaces the Transition Formula before March 2002, as
we expect, then the likelihood of positive Tier 3 subsidy payments is much
higher because PX prices are more likely to be below the Target Price than
formula-based SRAC prices.
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New Renewable Resource Account
- ------------------------------
The New Renewable Resources Account contains $162 million to support new
renewable power generation projects. According to the legislation, "new" in this
context means a renewable energy facility located in California that became
operational on or after September 23, 1996, but prior to January 1, 2002. As
Table 6-3 shows, the proportion of total funds devoted to new technologies
increases from $32.4 million in 1998 to $48.6 million by 2001. However, eligible
facilities receive subsidy payments over a 5 year period commencing when the
facility comes on-line - though funding will terminate at the end of 2006, or
five years after the last winning project begins operation.
Table 6-3
New Renewable Resource Account - Allocations by Year,
$Millions
1998 1999 2000 2001 Total
- ----------------------------------------------------------
$32.4 $37.8 $43.2 $48.6 $162
- ----------------------------------------------------------
Source: Policy Report on AB 1890 Renewables Funding, Report to the Legislature,
California Energy Commission, March 1998, page 33.
The full $162 million allocated to new renewable energy technologies was
disbursed in a single auction held in July of this year. Auction participants
were required to submit "bids" - a cents per kWh subsidy, and an estimate of
project generation over a 5 year period (however, acceptable bids were capped at
1.5 cents per kWh). The fund was then allocated from lowest to highest bidder
until it was exhausted. Winners will receive a payment for renewable electric
generation produced and sold in the first five years of project operation.
According to California Energy Commission records, 55 out of 56 bids,
representing 600 MW, divided up the $162 million allotment. The average bid was
1.2 cents per kilowatt hour. The winning bids consisted of approximately 300 MW
of wind; 157 MW of geothermal; 70 MW of landfill gas; 12 MW of biomass; 1
megawatt of digester gas; and 1 megawatt of small hydro.
- -------------------------------------------------------------------------------
(C)1999 Henwood Energy Services, Inc. May 20, 1999
6-4
PROPRIETARY AND CONFIDENTIAL
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
- -------------------------------------------------------------------------------
Emerging Renewables Account
- ---------------------------
The purpose of the emerging renewable subsidy program is to reduce the cost to
consumers of certain renewable energy generation equipment. Four types of
renewable power generation are eligible for these funds: small wind turbines of
10 kW or less, fuel cells that convert renewable fuels such as methane gas into
electric power, and solar power - both photovoltaic (PV) and solar thermal. The
first $10.5 million of the total $54 million allocated to this fund became
available March 20, 1998 from the CEC on a first-come, first-served basis.
The delivery mechanism for this Account is a cash rebate equal to 50 percent of
the purchase price or $3,000 per kW, whichever is less, of the cost of an
eligible power generating system. In order to receive the rebate, the system
must offset some or all of the electric power used by the consumer; have a full,
five-year guarantee; and be installed by an appropriately licensed contractor.
Most importantly, the system must be connected to local power lines. Remote,
self-contained systems that are not grid-connected do not qualify. The offer is
good only for systems installed in the service territories of the State's
largest three investor-owned utilities -- PG&E, SCE and SDG&E.
Consumer-Side Incentives
- ------------------------
The consumer-side account is designed to promote customer participation in the
renewable energy market. This account was allocated $81 million, or 15% of the
total fund. These funds in turn have been allocated to two sub-accounts - a
customer credit account, which has most of the allotted funds, and secondly to a
consumer information account.
The customer credit account provides "credits" to consumers who purchase CEC-
registered renewable power that satisfy certain eligibility criteria. Through
this program, residential and small commercial customers' electric power bill
who purchase renewable energy will automatically be credited up to 1.5 cents for
every kilowatt-hour of renewable electric power they consume up to the total
fund amount of $75.6 million. Funds for customer credits were distributed in
early 1998. For at least the first two years, payments to some customers have a
ceiling of $1,000 per year per customer.
As of early September, the CEC has not disbursed any monies under this program,
even though a number of power providers have obtained CEC registered status and
therefore are in a position to grant subsidies to
- -------------------------------------------------------------------------------
(C)1999 Henwood Energy Services, Inc. May 20, 1999
6-5
PROPRIETARY AND CONFIDENTIAL
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
- -------------------------------------------------------------------------------
consumers. The reason is largely due to the delay in getting deregulation
underway. The CEC expects that the first set of customer power bills eligible
for a rebate will begin coming in within a few weeks.
- -------------------------------------------------------------------------------
(C)1999 Henwood Energy Services, Inc. May 20, 1999
6-6
Appendix A - Southern California Base Case MCP Forecast
------------------------------------------------------------------------------------------------------------
Base Case Forecast TRANSAREA MARKET CLEARING PRICES BY MONTH AND PERIOD
------------------------------------------------------------------------------------------------------------
TransArea Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec ANN
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 33.98 30.20 31.34 27.80 28.50 27.54 33.86 38.70 37.04 34.87 34.39 34.26 32.74
2000 Off-Peak 26.49 21.35 20.95 18.39 15.20 13.77 19.14 21.44 23.77 25.43 26.94 26.72 21.64
Average 30.06 25.57 25.89 22.87 21.53 20.33 26.14 29.65 30.09 29.92 30.49 30.31 26.93
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 35.00 33.47 29.82 28.51 35.25 31.96 34.96 40.14 39.25 34.42 35.95 36.45 34.62
2001 Off-Peak 27.50 25.42 22.83 18.99 16.26 14.12 19.63 25.56 24.98 25.79 28.95 27.64 23.14
Average 31.07 29.25 26.16 23.52 25.30 22.62 26.93 32.50 31.78 29.90 32.28 31.84 28.60
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 43.58 39.64 33.81 33.54 34.02 32.63 42.49 49.05 49.17 45.78 45.96 45.83 41.32
2002 Off-Peak 32.12 29.60 26.68 22.42 20.01 17.67 24.03 31.47 30.41 30.44 33.37 32.90 27.60
Average 37.57 34.38 30.07 27.72 26.67 24.79 32.82 39.84 39.35 37.74 39.37 39.06 34.13
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 45.90 41.15 35.38 36.08 35.18 33.82 46.01 53.05 51.85 52.12 48.17 48.87 44.00
2003 Off-Peak 34.82 31.82 26.65 23.50 20.70 18.82 25.26 32.09 31.76 32.50 35.68 35.11 29.05
Average 40.09 36.27 30.80 29.49 27.59 25.96 35.13 42.07 41.33 41.84 41.63 41.66 36.17
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 48.56 41.34 37.70 35.34 37.80 35.88 47.22 57.83 54.94 48.39 51.30 49.48 45.53
2004 Off-Peak 35.11 29.80 27.80 25.93 22.83 21.39 28.26 32.45 32.95 34.84 37.52 37.36 30.54
Average 41.51 35.29 32.51 30.41 29.95 28.29 37.28 44.52 43.43 41.29 44.09 43.12 37.67
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 52.99 49.47 39.39 38.89 42.36 38.48 51.34 61.54 57.64 52.36 51.11 52.72 49.05
2005 Off-Peak 37.11 32.63 29.19 26.77 24.25 22.26 29.39 37.33 34.56 35.55 42.09 38.12 32.45
Average 44.67 40.65 34.04 32.55 32.86 29.99 39.83 48.85 45.55 43.55 46.39 45.06 40.35
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 55.79 49.21 47.35 39.05 41.66 40.94 51.36 63.51 58.02 55.14 56.52 56.28 51.28
2006 Off-Peak 36.88 33.89 29.20 27.52 25.24 23.01 31.41 37.72 35.15 36.72 38.36 39.05 32.86
Average 45.88 41.18 37.84 33.01 33.06 31.55 40.90 49.99 46.05 45.48 47.01 47.25 41.63
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 55.63 55.93 41.53 40.41 47.11 41.60 53.91 59.56 57.56 56.55 59.33 57.31 52.20
2007 Off-Peak 38.13 33.73 30.64 29.19 25.72 23.64 30.28 37.34 36.57 35.61 39.97 40.28 33.44
Average 46.45 44.30 35.82 34.53 35.90 32.20 41.53 47.91 46.57 45.58 49.19 48.38 42.37
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 59.34 46.42 46.56 43.88 48.11 42.04 57.14 60.81 58.34 56.33 56.12 57.80 52.82
2008 Off-Peak 38.37 31.45 31.13 30.04 28.01 24.18 32.70 38.28 36.68 36.10 41.04 40.72 34.09
Average 48.34 38.58 38.47 36.63 37.57 32.69 44.33 49.00 47.00 45.72 48.23 48.85 43.01
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 58.73 60.97 43.20 44.66 48.33 46.51 55.87 62.62 60.61 56.56 60.22 59.13 54.75
2009 Off-Peak 38.25 34.49 32.31 30.00 28.45 25.59 34.91 38.63 35.84 38.30 38.81 41.08 34.75
Average 48.00 47.10 37.49 36.98 37.91 35.55 44.89 50.05 47.64 46.99 49.01 49.67 44.27
------------------------------------------------------------------------------------------------------------
Appendix B - Southern California Low Gas Case 1 MCP Forecast
- ---------------------------------------------------------------------------------------------------
Low Gas Price Case 1 MARKET CLEARING PRICES FOR SOUTHERN CALIFORNIA TRANSMISSION AREA
- ---------------------------------------------------------------------------------------------------
Year Period Jan Feb Mar Apr May Jun
- ---------------------------------------------------------------------------------------------------
2000 On-Peak 32.79 28.76 29.36 26.06 27.03 30.19
Off-Peak 25.53 17.93 20.22 17.72 14.66 13.39
Average 28.98 23.08 24.57 21.69 20.55 21.39
- ---------------------------------------------------------------------------------------------------
2001 On-Peak 34.44 31.05 30.96 26.93 29.35 31.86
Off-Peak 25.96 24.26 21.29 18.29 15.71 13.78
Average 30.00 27.49 25.89 22.41 22.20 22.39
- ---------------------------------------------------------------------------------------------------
2002 On-Peak 41.22 37.13 31.80 31.32 30.68 30.51
Off-Peak 31.00 28.21 24.89 21.23 18.92 17.12
Average 35.87 32.45 28.17 26.03 24.51 23.50
- ---------------------------------------------------------------------------------------------------
2003 On-Peak 43.32 39.85 32.59 32.43 32.40 32.20
Off-Peak 31.49 29.80 25.10 22.46 19.72 17.91
Average 37.12 34.59 28.66 27.21 25.75 24.71
- ---------------------------------------------------------------------------------------------------
2004 On-Peak 46.80 35.80 34.24 33.63 36.27 34.63
Off-Peak 32.91 28.11 25.87 24.32 21.57 20.22
Average 39.52 31.77 29.85 28.75 28.57 27.08
- ---------------------------------------------------------------------------------------------------
2005 On-Peak 50.18 46.56 36.48 35.16 41.80 36.62
Off-Peak 34.50 30.16 26.87 25.07 22.94 21.06
Average 41.96 37.97 31.44 29.88 31.91 28.47
- ---------------------------------------------------------------------------------------------------
2006 On-Peak 52.43 45.50 44.44 36.06 39.63 37.72
Off-Peak 34.11 31.81 27.10 25.71 23.88 21.74
Average 42.83 38.33 35.35 30.64 31.37 29.36
- ---------------------------------------------------------------------------------------------------
2007 On-Peak 52.10 46.96 39.47 39.35 42.57 38.14
Off-Peak 35.59 30.82 28.64 26.75 24.17 22.26
Average 43.45 38.50 33.79 32.75 32.93 29.83
- ---------------------------------------------------------------------------------------------------
2008 On-Peak 54.84 43.43 41.56 38.71 42.43 40.66
Off-Peak 35.61 29.59 28.93 28.01 26.36 22.84
Average 44.76 36.18 34.94 33.11 34.00 31.33
- ---------------------------------------------------------------------------------------------------
2009 On-Peak 55.12 50.26 41.09 40.07 44.24 41.73
Off-Peak 35.12 31.93 29.96 28.05 26.56 24.16
Average 44.63 40.66 35.26 33.78 34.97 32.53
- ---------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------
Low Gas Price Case 1 MARKET CLEARING PRICES FOR SOUTHERN CALIFORNIA TRANSMISSION AREA
- ---------------------------------------------------------------------------------------------------
Year Jul Aug Sep Oct Nov Dec ANN
- ---------------------------------------------------------------------------------------------------
2000 33.94 37.40 35.85 32.58 32.72 33.60 31.72
18.39 20.76 23.02 23.57 25.62 25.38 20.55
25.79 28.68 29.13 27.86 29.01 29.29 25.86
- ---------------------------------------------------------------------------------------------------
2001 33.19 38.21 37.98 34.09 33.04 34.54 32.99
18.78 23.65 23.32 22.59 27.75 26.62 21.83
25.64 30.58 30.30 28.06 30.27 30.39 27.14
- ---------------------------------------------------------------------------------------------------
2002 41.16 46.69 45.94 42.95 43.56 42.92 38.85
23.16 28.91 28.41 29.13 30.96 30.88 26.07
31.73 37.37 36.76 35.71 36.96 36.61 32.15
- ---------------------------------------------------------------------------------------------------
2003 43.29 49.50 48.66 44.27 46.83 43.62 40.76
23.86 30.00 29.38 30.35 33.32 32.70 27.17
33.10 39.28 38.56 36.98 39.75 37.90 33.64
- ---------------------------------------------------------------------------------------------------
2004 45.16 51.54 49.49 45.52 47.63 46.66 42.34
26.46 30.59 30.65 32.55 34.79 34.15 28.53
35.36 40.56 39.62 38.72 40.91 40.10 35.11
- ---------------------------------------------------------------------------------------------------
2005 45.74 58.59 55.87 47.53 46.84 50.47 46.01
27.67 34.99 32.40 32.83 39.37 35.07 30.25
36.27 46.22 43.58 39.82 42.93 42.40 37.75
- ---------------------------------------------------------------------------------------------------
2006 47.76 60.79 55.73 49.50 50.53 52.63 47.77
29.23 35.41 32.38 34.50 35.66 36.67 30.69
38.04 47.48 43.51 41.64 42.75 44.26 38.83
- ---------------------------------------------------------------------------------------------------
2007 50.06 58.50 55.47 56.13 63.31 52.51 49.57
28.52 35.25 33.89 33.30 36.88 37.28 31.13
38.77 46.32 44.17 44.16 49.47 44.53 39.91
- ---------------------------------------------------------------------------------------------------
2008 52.55 58.89 57.12 53.57 51.78 53.95 49.19
30.40 35.37 34.42 33.50 38.39 37.81 31.80
40.94 46.56 45.23 43.05 44.77 45.49 40.08
- ---------------------------------------------------------------------------------------------------
2009 53.26 60.50 55.93 52.86 55.89 54.05 50.44
32.27 35.82 33.29 35.34 36.35 37.94 32.25
42.25 47.56 44.07 43.68 45.66 45.60 40.91
- ---------------------------------------------------------------------------------------------------
Appendix C - Southern California Low Gas Case 2 MCP Forecast
------------------------------------------------------------------------------------------------------------
Low Gas Price Case 2 TRANSAREA MARKET CLEARING PRICES BY MONTH AND PERIOD
------------------------------------------------------------------------------------------------------------
TransArea Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec ANN
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 32.67 29.48 27.70 25.86 27.06 27.53 33.46 37.00 35.61 32.55 34.17 32.34 31.30
2000 Off-Peak 25.46 17.81 20.09 17.68 14.76 13.40 18.36 20.64 22.75 23.49 25.63 25.70 20.51
Average 28.89 23.37 23.71 21.57 20.61 20.13 25.55 28.42 28.88 27.80 29.70 28.86 25.65
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 33.14 31.55 30.57 26.63 30.85 30.77 32.77 38.42 36.86 32.44 33.21 33.25 32.55
2001 Off-Peak 25.63 24.06 21.26 18.08 15.59 13.70 18.89 24.03 23.11 22.24 27.39 26.12 21.67
Average 29.20 27.62 25.69 22.15 22.85 21.83 25.49 30.88 29.66 27.10 30.16 29.51 26.85
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 40.05 35.96 31.54 30.42 30.10 29.53 40.58 45.77 46.59 42.14 42.20 42.88 38.17
2002 Off-Peak 30.25 27.53 24.54 20.81 18.87 16.84 22.70 28.63 28.10 28.05 30.67 30.24 25.60
Average 34.92 31.54 27.87 25.39 24.21 22.89 31.21 36.79 36.90 34.75 36.16 36.26 31.59
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 42.65 38.98 32.44 32.10 31.86 31.27 42.31 49.99 47.28 42.77 43.68 43.89 39.96
2003 Off-Peak 31.14 28.93 24.83 21.61 19.46 17.62 23.56 29.48 28.74 29.80 32.98 31.81 26.66
Average 36.62 33.71 28.45 26.61 25.36 24.12 32.48 39.24 37.57 35.97 38.08 37.56 32.99
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 45.46 35.25 33.26 32.30 34.35 32.15 43.73 54.52 48.62 45.01 45.29 44.64 41.28
2004 Off-Peak 31.70 27.26 25.20 23.48 20.95 19.75 25.90 29.74 29.74 31.64 34.18 33.83 27.80
Average 38.25 31.06 29.04 27.68 27.32 25.66 34.38 41.53 38.74 38.00 39.47 38.97 34.22
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 48.84 43.85 34.98 35.39 39.33 33.70 45.04 55.26 55.19 46.99 45.64 48.85 44.45
2005 Off-Peak 32.85 28.76 25.93 24.30 22.25 20.54 26.72 33.89 30.99 31.88 39.67 34.14 29.34
Average 40.46 35.95 30.24 29.59 30.38 26.81 35.44 44.06 42.52 39.07 42.51 41.14 36.53
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 49.39 43.93 39.68 34.87 38.23 36.11 45.88 58.22 53.08 47.57 48.01 50.64 45.51
2006 Off-Peak 32.56 30.62 26.20 24.52 22.98 21.18 28.30 34.40 31.42 33.00 33.90 35.23 29.54
Average 40.57 36.96 32.61 29.45 30.24 28.29 36.66 45.73 41.74 39.93 40.62 42.56 37.14
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 50.03 44.97 39.80 35.84 43.80 35.74 47.27 57.40 51.45 49.66 52.25 50.08 46.56
2007 Off-Peak 34.14 29.91 27.17 25.73 23.39 21.51 27.47 33.76 32.39 32.33 35.42 34.96 29.86
Average 41.70 37.08 33.18 30.54 33.10 28.29 36.89 45.00 41.47 40.57 43.44 42.15 37.81
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 53.37 40.60 41.82 42.26 40.41 38.21 49.36 56.11 55.55 55.12 49.50 51.66 47.91
2008 Off-Peak 33.79 28.24 27.56 26.74 25.33 21.93 29.59 34.08 33.23 32.20 36.69 36.23 30.50
Average 43.11 34.13 34.35 34.13 32.51 29.69 39.00 44.57 43.86 43.11 42.79 43.58 38.78
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 51.85 46.58 41.60 37.87 43.43 41.47 49.32 57.57 55.22 50.18 54.84 53.74 48.67
2009 Off-Peak 34.32 30.64 28.76 26.67 25.26 23.08 31.11 34.51 32.73 34.21 34.34 36.77 31.06
Average 42.66 38.23 34.87 32.00 33.90 31.84 39.77 45.48 43.44 41.81 44.11 44.84 39.44
------------------------------------------------------------------------------------------------------------
Appendix Table D.1
Southern California Edison SRAC Prices by Month and Time-of-Day, 1999-2001
Cents per kWh
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
1999
On Peak 4.212 4.254 4.334 4.451
Mid Peak 3.342 3.090 2.953 3.026 3.596 2.989 2.987 3.197 3.225 3.938 4.100 4.171
Off Peak 2.604 2.375 2.202 2.264 2.802 2.520 2.545 2.593 2.663 2.987 3.208 3.161
Super-Off 2.129 1.968 1.881 1.927 2.290 2.508 2.611 2.656
Average 2.743 2.536 2.424 2.483 2.952 2.956 2.985 3.041 3.123 3.231 3.365 3.423
Tier 3 Subsidy 0.257 0.464 0.576 0.517 0.048 0.044 0.015 0.000 0.000 0.000 0.000 0.000
2000
On Peak 4.358 4.401 4.485 4.607
Mid Peak 4.161 3.903 3.809 3.748 3.721 3.093 3.091 3.308 3.338 4.076 4.247 4.320
Off Peak 3.241 2.999 2.841 2.804 2.899 2.607 2.633 2.683 2.756 3.092 3.323 3.273
Super-Off 2.650 2.486 2.426 2.387 2.370 2.596 2.704 2.751
Average 3.415 3.203 3.126 3.076 3.054 3.058 3.088 3.147 3.232 3.345 3.485 3.545
Tier 3 Subsidy 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2001
On Peak 4.494 4.541 4.626 4.754
Mid Peak 4.294 4.026 3.929 3.866 3.838 3.190 3.188 3.412 3.444 4.207 4.384 4.461
Off Peak 3.345 3.094 2.929 2.893 2.989 2.689 2.717 2.768 2.844 3.191 3.430 3.380
Super-Off 2.735 2.564 2.502 2.462 2.444 2.679 2.792 2.841
Average 3.524 3.304 3.224 3.173 3.149 3.153 3.186 3.246 3.336 3.452 3.598 3.661 3.334
Tier 3 Subsidy 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
Note: Forecast based on HESI Base Case long term gas price forecast at Topock with 3% inflation per year.
See Table 2.3 for annual average SRAC values.
SRAC prices from January to April 1999 are actual.
Appendix Table D.2
Southern California Edison SRAC Prices by Month and Time-of-Day, 1999 - 2001
Cents per kWh
Jan Feb Mar Apr May Jun Jul
1999
On Peak 3.657 3.693
Mid Peak 3.342 3.090 2.953 3.026 3.123 2.596 2.594
Off Peak 2.604 2.375 2.202 2.264 2.433 2.188 2.210
Super-Off 2.129 1.968 1.881 1.927 1.989
Average 2.743 2.536 2.424 2.483 2.563 2.566 2.592
Tier 3 Subsidy 0.257 0.464 0.576 0.517 0.437 0.434 0.408
2000
On Peak 4.253 4.296
Mid Peak 4.027 3.808 3.717 3.658 3.631 3.018 3.017
Off Peak 3.137 2.926 2.772 2.737 2.829 2.544 2.570
Super-Off 2.565 2.425 2.367 2.330 2.312
Average 3.305 3.125 3.050 3.002 2.980 2.984 3.015
Tier 3 Subsidy 0.000 0.000 0.000 0.000 0.020 0.016 0.000
2001
On Peak 4.354 4.399
Mid Peak 4.126 3.900 3.807 3.746 3.718 3.090 3.089
Off Peak 3.214 2.997 2.838 2.803 2.896 2.605 2.632
Super-Off 2.628 2.484 2.424 2.385 2.368
Average 3.386 3.201 3.124 3.074 3.051 3.055 3.087
Tier 3 Subsidy 0.000 0.000 0.000 0.000 0.000 0.000 0.000
Aug Sep Oct Nov Dec
1999
On Peak 3.759 3.857
Mid Peak 2.773 2.794 3.408 3.544 3.616
Off Peak 2.249 2.307 2.585 2.773 2.740
Super-Off 2.170 2.257 2.303
Average 2.638 2.706 2.797 2.908 2.967
Tier 3 Subsidy 0.362 0.294 0.203 0.092 0.033
2000
On Peak 4.377 4.496
Mid Peak 3.229 3.257 3.977 4.142 4.229
Off Peak 2.619 2.690 3.016 3.240 3.205
Super-Off 2.532 2.638 2.693
Average 3.072 3.155 3.263 3.399 3.470
Tier 3 Subsidy 0.000 0.000 0.000 0.000 0.000
2001
On Peak 4.482 4.604
Mid Peak 3.306 3.336 4.073 4.243 4.333
Off Peak 2.682 2.754 3.090 3.320 3.284
Super-Off 2.594 2.702 2.760
Average 3.145 3.231 3.343 3.482 3.556
Tier 3 Subsidy 0.000 0.000 0.000 0.000 0.000
Note: Forecast based on HESI short-term gas price forecast at Topock.
SRAC prices from January to April 1999 are actual.
EXHIBIT C
[GeothermEx, Inc. Letterhead]
INDEPENDENT REVIEW OF STEAM SUPPLY
AND RESOURCE-RELATED CAPITAL AND OPERATING COSTS
COSO GEOTHERMAL FIELD
for
CAITHNESS COSO FUNDING CORPORATION
New York, New York
by
GeothermEx, Inc.
Richmond, California
MAY 1999
[GeothermEx, Inc. Letterhead]
CONTENTS
EXECUTIVE SUMMARY...................................................iv
1. INTRODUCTION....................................................1-1
2. STEAM SUPPLY....................................................2-1
2.1 Introduction..............................................2-1
2.2 Production................................................2-2
2.3 Injection.................................................2-7
2.4 Gases in Steam............................................2-8
3. CAPITAL AND OPERATING COSTS.....................................3-1
Tables
Figures
Appendices
Appendix A: Production Histories for Navy I Production Wells
Appendix B: Production Histories for Navy II Production Wells
Appendix C: Production Histories for BLM Production Wells
Appendix D: Injection Histories for Navy I Injection Wells
Appendix E: Injection Histories for Navy II Injection Wells
Appendix F: Injection Histories for BLM Injection Wells
ii
[GeothermEx, Inc. Letterhead]
ILLUSTRATIONS
Table
- -----
2.1 H2S in Steam at Coso Wells
3.1 Summary of Drilling, Gathering Systems and Workover Costs for the Coso
Geothermal Project in Caithness financial projections
Figure
- ------
1.1 Location of the Coso geothermal field, California
1.2 Well location map, Coso geothermal field
2.1 Coso MW forecast from Caithness financial projections
2.2 Megawatts per well vs. time, Navy I
2.3 Megawatts per well vs. time, Navy II
2.4 Megawatts per well vs. time, BLM
2.5 Total NCG/steam vs. time, Navy II well 15-17RD
2.6 H2S/steam vs. time, Navy II well 15-17RD
2.7 Comparison of Caithness and GeothermEx MW forecasts
3.1 Planned drilling costs at Coso from Caithness financial projections
3.2 Planned gathering system costs at Coso from Caithness financial
projections
3.3 Planned workover costs at Coso from Caithness financial projections
iii
[GeothermEx, Inc. Letterhead]
EXECUTIVE SUMMARY
GeothermEx has been requested by Caithness Coso Funding Corporation
("Caithness") to conduct a due diligence review of the geothermal resource at
the Coso Geothermal Field. This review has been conducted in connection with
the re-financing of Caithness' recent acquisition of the Coso assets from
CalEnergy Company, Inc. (CECI). The work by GeothermEx has consisted of:
. a review of the status of the steam supply from the geothermal field;
. a review of resource-related capital and operating costs; and
. an assessment of the reasonableness of the forecasts of power production
and resource-related costs as contained in Caithness' financial
projections.
GeothermEx has acted as the independent geothermal engineer for the Coso
projects (Navy I, Navy II, and BLM) since their initial financing in the late
1980s. Since 1993, GeothermEx has provided an annual independent assessment of
the resource supply as a requirement of CECI's bond issue; the last such
evaluation was prepared in June 1998.
Based upon this review, we have reached the following main conclusions:
. The resource data supplied to us by Caithness appear reasonable based
on our long familiarity with the Coso projects.
iv
[GeothermEx, Inc. Letterhead]
. The Coso geothermal reservoir has supplied steam to the installed
plants for more than 10 years and has proven to be one of the most
reliable geothermal reservoirs in the United States.
. Geothermal energy reserves at Coso are more than sufficient to
support the existing plants for 30 years. However, as in all geothermal
fields, make-up well drilling will be necessary to maintain power
output.
. Development of leaseholds adjacent to the Caithness acreage is
unlikely, and the possibility of any impact of offsetting development
on the performance of the Caithness resource is remote.
. The financial projections by Caithness show a combined generation
capacity of about 264 net megawatts until year 2006 and declining
thereafter. The forecasts of the generation decline trend after year
2006 made by Caithness are reasonable and very similar to the
GeothermEx forecasts.
. The well drilling and workover programs assumed in Caithness's
financial projections are reasonable and should result in steam supply
sufficient to maintain the generation capacity forecast in Caithness's
financial projections.
. Resource-related capital and operating costs assumed in Caithness's
financial projections are reasonable and consistent with the historical
trend and industry practice.
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In conducting the current review, GeothermEx has relied on resource and cost
data supplied by Caithness; these data appear reasonable based on our long
familiarity with the Coso projects. We have had numerous phone conversations
with members of Caithness' technical and managerial staff to clarify questions
relating to the data and to ensure that no significant resource issues have been
overlooked.
The Coso reservoir has been operated profitably for more than 10 years, and has
proven to be one of the most reliable geothermal reservoirs in the United
States. In our previous assessments of the resource, we have repeatedly
confirmed that the geothermal energy reserves at Coso are more than sufficient
to support the three existing power plants for 30 years. However, in all
geothermal fields, well productivity declines with time due to declines in
reservoir pressure; generation capacity is maintained by drilling "make-up"
wells to compensate for declining well productivity. Any decline in generation
capacity at Coso will not be caused by a shortage of reserves, but by the
economics of make-up well drilling in relation to the power price.
The financial projections presented by Caithness show the combined power
generation at the Coso projects to be approximately 264 net megawatts (NMW)
until 2006, declining thereafter at a rate of about 3.7% per year. The nearly
constant generation level during 1999-2006 is to be maintained by make-up well
drilling to compensate for declines in well productivity. After 2006, no make-
up wells will be drilled, and therefore, generation will decline. We have
forecast declines in steam supply based on decline curve analysis, a method that
extrapolates the past trends in well productivity decline into the future.
Caithness has conducted a similar decline curve analysis, which we have reviewed
herein.
Caithness has assumed a harmonic decline trend in its analysis. This is a
reasonable assumption. Geothermal wells in "two-phase" reservoirs (that is,
reservoirs containing both hot water and
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steam) such as Coso often exhibit exponential declines in capacity during their
first few years of operation, but later make a transition to a harmonic decline.
Unlike exponential decline, where the decline rate remains constant with time,
harmonic decline implies that the decline rate itself declines with time.
GeothermEx's review of historical well capacities indicates that the wells at
Coso are currently exhibiting harmonic declines. Also, there is still some spare
capacity above the electromechanical limit of the plants. This spare capacity
should allow a plateau of constant output for a year or so without drilling
additional geothermal production wells, provided existing wells are maintained
in good mechanical condition, which has generally been the case historically.
After 2006, the annual decline rate used in the financial projections is about
3.7% (harmonic). This is close to the decline rate of 4.1% (harmonic) starting
in 2006 estimated by GeothermEx. The forecasts of generation decline trend
after 2006 made by Caithness and GeothermEx differ by less than 5% throughout
the 13-year period of declining generation.
Resource-related costs reviewed herein include those related to drilling new
wells, connecting them to the gathering system (for wells drilled on pads with
existing production wells) or extending the gathering system (for wells drilled
on new pads) and working over existing wells. All projected costs are based on
1999 dollars and are escalated at 3% per year.
The historical drilling expenditures from 1995 to 1998 were in the range of $12
million to $15 million per year, with the exception of 1996, when drilling
expenditures were about $2 million. Going forward, the financial projections
include $6.5 million in drilling funds for 1999, about $4 million in 2000, $7
million in 2001, $10.5 million in 2002, and $7.5 to $8.5 million in 2003 - 2006.
No drilling is planned after 2006.
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The cost assumed in the financial projections for drilling a new well is $2.75
million in 1999, except for a BLM well to be drilled this year (see discussion
below). Based on documents provided by Caithness, a total of six new wells were
drilled in 1997 and 1998, with an average cost of $2.73 million and an average
depth of approximately 9,000 feet. Considering that the average depths of
future wells will be similar, the estimate of $2.75 million per well is
reasonable. The average productivity of these wells was approximately 8 MW
(gross); this includes the highly productive East Flank well 38B-9. Without
38B-9, the average productivity was approximately 5 MW (gross). Caithness has
reasonably assumed an average 1999 productivity of 5.6 MW for new wells. The
financial projections do not include any decline in the expected capacity of
make-up wells; it remains at 5.6 MW throughout the project life. Realistically,
this amount should be expected to decline according to the decline rate assigned
to each area of the field; as few make-up wells are planned and the decline rate
in well productivity is very small, the difference between the projections with
and without declining the capacity of make-up wells is not significant.
Several production wells were redrilled in 1997 and 1998, at an average cost of
$1.3 million, an average depth of 6,000 feet, and an average productivity of 3.2
MW (gross). No funds are allocated in the financial projections for production
well redrills, as Caithness does not plan to redrill any existing production
wells. However, Caithness reports that there is about $1.5 million per year in
the O&M section of the budget, which will be used for well clean-outs and other
well maintenance. Production well workovers are discussed below. Two
injection well redrills are planned for 1999, and one injection well redrill per
year is planned for years 2000 to 2006. The cost of injection well redrills in
1999 dollars is $1.2 million per well, which is reasonable.
In 1999, the drilling costs include injection well redrills in the BLM and Navy
II areas ($1.2 million each), a purchase of new drill pipe ($150,000, allocated
unequally between Navy II and BLM), drilling a slim exploration well in BLM
North ($400,000), deepening the existing BLM
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North well 43-7 ($726,000) and drilling BLM North well 43A-7 ($2.9 million). The
last is planned to a total depth of 10,000 feet, which is deeper than other
planned wells at Coso, and accounts for its slightly greater cost.
One injection well redrill and one BLM production well (43B-7) are planned for
2000. A total of 15 new wells are planned from 1999 through 2006, which
equates to nearly 11 MW per year, using Caithness' assumption of no decline in
the capacity of make-up wells. As indicated by drilling data provided by
Caithness, six new wells were drilled in the last two years. Therefore, we
would expect that two to three make-up wells would be needed each year to
maintain production, unless the make-up wells have a higher-than-average
capacity which is expected under Caithness' plans to drill in the East Flank
area, a relatively undrilled portion of the resource that should prove more
productive.
In addition to the cost of drilling a well, there are costs associated with
connecting the well to the gathering system. In the case where a new well is
drilled from a pad with existing production wells, the connection cost is
assumed by Caithness to be $500,000; these are "pad pipelines," which are
charged to the appropriate project. For wells drilled on new pads in the BLM
North and East Flank areas, additional expenses will be incurred to extend the
steam gathering pipelines; these are "trunk lines," which are shared equally
between the projects. There are also expenses associated with low-pressure (LP)
steam separation equipment included in this category in 1999. We have not
independently estimated the costs of pipelines or LP separation equipment. The
well connection costs are on the conservative side.
The assumptions page of the financial projections indicates a 1999 workover cost
of $700,000 per well; however, discussion with Caithness revealed that $700,000
is budgeted for each unit, which is adequate for two to three workovers each
year. This is escalated at 3% per year. Workovers
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are assumed to be needed throughout the life of the project. The workover costs
and frequencies are reasonable.
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1. INTRODUCTION
GeothermEx has been requested by Caithness Coso Funding Corporation
("Caithness") to conduct a due diligence review of the geothermal resource at
the Coso Geothermal Field. This review has been conducted in connection with
the re-financing of Caithness' recent acquisition of the Coso assets from
CalEnergy Company, Inc. (CECI). The work by GeothermEx has consisted of:
. a review of the status of the steam supply from the geothermal field;
. a review of resource-related capital and operating costs; and
. an assessment of the reasonableness of the forecasts of power production
and resource-related costs contained in the financial projections
prepared by Caithness.
The Coso Geothermal Field is located about 150 miles northeast of Los Angeles in
Inyo County, California (figure 1.1). Caithness recently took over operation of
the field from CECI, and is the operator of three geothermal projects in the
field: Navy I, Navy II, and BLM. Because Caithness has been a partner of CECI
in the development and operation of the Coso field, Caithness's staff has long
familiarity with this field. In addition, Caithness has retained most of the
CECI employees who ran the Coso project.
Each of the three projects consist of three turbine-generator units and
associated wells, pipelines and other surface facilities. For the purposes of
assessing the available steam supply from the wells, the Navy I, Navy II, and
BLM projects each have megawatt (MW) capacities of 80 MW. However, each project
has plant facilities physically capable of generating about 90 net megawatts
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(NMW) if sufficient steam is available from the wells, representing a total
installed plant capacity of about 270 NMW. The capacity expressed in NMW is net
of the power used by the plant facilities themselves ("parasitic power"). The
Navy I and Navy II projects have single plant sites containing three turbine-
generator units each. The BLM project has two plant sites: BLM East, with two
turbine-generator units; and BLM West, with one turbine-generator unit. Figure
1.2 shows the three project areas with their respective plant sites and well
locations.
The first turbine-generator unit at Navy I came on line in July 1987, and the
second and third units at Navy I came on line in December 1988. All three
units of the Navy II power plant came on line in December 1989. The BLM East
plant came on line in December 1988, and the BLM West plant came on line in
August 1989. Since the plants came on line, make-up wells have been drilled to
maintain or increase production, and the power plants have been modified to
improve the efficiency of steam use. This has allowed the output of the plants
to rise each year through 1996. The average fieldwide output over the past
three years has been 260 NMW, including down time for plant maintenance. This
represents a plant capacity factor of 96%, based on the electromechanical limit
of 270 NMW, and 108% based on 240 MW.
GeothermEx has acted as the independent geothermal engineer for the Coso
projects (Navy I, Navy II, and BLM) since their initial financing in the late
1980s. Since 1993, GeothermEx has provided independent annual evaluations of
the resource supply for CalEnergy; the last such evaluation was prepared in June
1998.
In conducting the current review, GeothermEx has relied on resource and cost
data supplied by Caithness. This data appear reasonable based on our long
familiarity with the Coso projects. We have had numerous phone conversations
with members of Caithness' technical and managerial staff to clarify questions
relating to the data and to ensure that no significant resource issues have
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been overlooked. Our review has focused on the geothermal resource and the
operation of the wellfield; considerations pertaining to the plants have not
been covered in this review.
Our review of the present and projected steam supply is described in detail in
Chapter 2. Our review of present and projected capital costs for drilling and
pipeline construction, as well as operating costs for workovers is presented in
Chapter 3.
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2. STEAM SUPPLY
2.1 Introduction
------------
The geothermal reservoir at Coso consists of a fractured body of granitic rock
with temperatures in the reservoir ranging from about 400(degrees) to
650(degrees)F. Since the early 1980s, approximately 150 wells have been drilled
in the field, ranging in depth from 1,300 feet to 13,000 feet. About 57% of
these wells have been commercially productive, another 18% have been used for
injection, and the remaining 25% have been non-commercial. Of these 150 wells,
56 were drilled from 1991 through 1998, during which time the drilling success
rate has been considerably higher. Of the 56 wells drilled in this period, only
five have been non-productive, and the others have been used for production (33
wells) or injection (18 wells), indicating a drilling success rate of 91%.
The Coso reservoir has been operated at capacity and profitability for more than
10 years, and has proven to be one of the most reliable geothermal reservoirs in
the United States. In our previous assessments of the resource, we have
repeatedly confirmed that the geothermal energy reserves at Coso are more than
sufficient to support the three existing power plants for 30 years. However, in
all geothermal fields, well productivity declines with time due to declines in
reservoir pressure; generation capacity is maintained by drilling "make-up"
wells to compensate for declining well productivity. Any decline in generation
capacity at Coso will not be caused by a shortage of reserves, but by the
economics of make-up well drilling in relation to the power price.
There are two productive areas: the main reservoir, consisting of the western
portions of the Navy I and Navy II areas and the northern portion of the BLM
area; and the "East Flank," located in the eastern portion of the Navy I and
Navy II areas. The main reservoir was the first part of the field to be
developed and has the greatest concentration of wells, as can be seen in figure
1.2. The
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East Flank was developed later and was tied into the plants in 1994. There are
pipelines allowing transfer of steam between projects, which allows flexibility
in making use of available steam anywhere in the field. To date, each project
has relied primarily on steam from wells within its own boundaries and has
consistently maintained a steam supply in excess of that required for nominal
generation. Leases offsetting the Caithness acreage do not appear to have
significant resource potential. It is unlikely that development of these
offsetting leases will occur, so the risk of any impact from offsetting
development on the performance of the Caithness leases is negligible.
Within the main reservoir, the hottest temperatures are located at BLM West.
However, the flow capacity of the reservoir rock (that is, the ability of the
rock to transmit fluids) generally increases from BLM West northward (toward
Navy II and Navy I) and eastward (toward BLM East). The resource is generally
deeper at BLM and becomes progressively shallower to the north; on the East
Flank, the reservoir is hotter and deeper, similar to the reservoir at BLM West.
2.2 Production
----------
Most of the wells at Coso produce a mixture of steam and boiling water. The
steam is separated from the water and used to generate electricity at the
plants. The separated water is returned to the reservoir by injection wells.
The steam at the power plants is condensed to water (or "condensate") downstream
of the turbines, and a portion of this condensate is also injected. Because
some of the condensate is lost to evaporation in the cooling towers, not all of
the mass from the production wells is returned to the reservoir. To some
extent, this loss of mass is replaced by a natural inflow of groundwater (or
"recharge"). However, as is commonly the case in geothermal projects using this
type of plant technology, the rate of recharge at Coso has been less than the
rate of mass lost to evaporation.
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As a result, reservoir pressures have decreased, and the flow rates of most of
the wells have declined. In addition, lower pressures have induced boiling in
the reservoir, resulting in the formation of a vapor zone (or "steam cap") in
the upper portions of the reservoir. As a consequence, many of the wells have
produced higher proportions of steam over time, and some wells have "dried out"
completely (that is, they have begun producing dry steam). These changes in the
geothermal reservoir are not unusual or unique to Coso, and additional drilling
and optimizing the location of injection has successfully compensated for them
in the past. Still, some decline in steam production is to be expected and is
considered normal for a development of this type.
The Caithness financial projections shows combined power generation at the Coso
projects maintaining a level of about 264 MW through 2006 and declining about
3.7% per year thereafter (figure 2.1). Production is to be maintained by
drilling make-up wells until 2006. The decline occurring thereafter reflects
the anticipated gradual decrease in the amount of steam available from the
wells.
Decline rates are determined by analyzing the historical behavior of the project
wells. The field operator has evaluated the capacity of each of the wells on a
quarterly basis since the projects started up; the capacities represent each
well's best consistent performance during the evaluation period. Because the
performance of individual wells is affected by the flow from other wells in the
gathering system, flow rates from each well have varied in the course of routine
operations. For instance, taking one well off line for maintenance work can
cause higher flow rates from other wells that share the same pipeline. The
variation in the flow rates of individual wells is illustrated in plots of
actual performance at Navy I, Navy II, and BLM (Appendices A, B, and C,
respectively).
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In its annual reports on the Coso project, GeothermEx has used essentially the
same methodology in estimating well capacities based on recent performance.
Although estimates for individual wells have differed, GeothermEx's annual
assessments of resource supply for each project (based on the sum of individual
well capacities) have consistently matched the field operator's estimates within
a few megawatts. For this reason, GeothermEx feels that operator's historical
well capacity estimates are a reasonable basis for decline curve analysis, and
have used them for that purpose in this study. The estimates for each well were
summed for each of the three projects. These sums were then divided by the by
the number of wells to achieve an estimate of average megawatt capacity per well
for each project. This averaged megawatt capacity was then plotted versus time.
The plots for Navy I, Navy II, and BLM are shown in figures 2.2 through 2.4.
Geothermal wells in "two-phase" reservoirs (that is, reservoirs containing both
hot water and steam) often exhibit exponential declines in capacity during their
first few years of operation, but later make a transition to a harmonic decline.
Unlike exponential decline, where the decline rate remains constant with time,
harmonic decline implies that the decline rate itself declines with time. In
each case, the projects showed initial exponential declines in the range of 20
to 30% per year, followed by a transition to harmonic decline rates starting in
early 1992.
Figure 2.2 shows the historical average megawatt capacity for wells in the Navy
I area. In mid-1995, the average capacity of Navy I wells actually rose,
apparently reflecting the effects of drying out of several wells in the
shallower portion of the reservoir. Another increase in average capacity
occurred in 1998, when new East Flank wells were tied into the gathering system.
As shown in figure 2.2, the decline rate in productivity of the Navy I wells
since January 1992 can be approximately fitted to a 3.4% initial harmonic trend.
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At Navy II (figure 2.3), the data since 1992 can be approximately matched by a
harmonic decline rate starting at 6.4%. At BLM (figure 2.4), well productivity
decline since 1995 can be matched approximately to a 16% initial harmonic
decline rate. It should be noted that between 1992 and mid-1995, the decline
rate at BLM was gentler. The cause of the steepened decline since mid-1995 is
not certain, but appears to be related to breakthrough of water from certain
injection wells to offsetting production wells in the BLM West area. The
configuration of injection wells in BLM West has been changed since 1992, and
the decline rate appears to be moderating.
The fieldwide transition from high exponential rates to moderate harmonic
decline rates in 1992 may represent an increase in the amount of recharge in
response to the decline in reservoir pressure. This hypothesis is consistent
with changes in the chemistry of produced steam over time. As part of the
current review, GeothermEx has investigated trends in the concentrations of
hydrogen sulfide (H2S) and total non-condensible gas (NCG) in Coso steam. These
trends are discussed in section 2.4, but in the context of productivity decline
curves, it is interesting to note that a large proportion of the Coso wells
showed an initial steep decline in the concentrations of H2S and total NCG,
followed by a transition to much more gradual declines or steady concentrations.
Figures 2.5 and 2.6 show the typical pattern in H2S and NCG concentrations from
a representative well at Navy II. The timing of this fieldwide transition in
gas concentrations coincides with the start of harmonic declines in well
capacities in 1992. This suggests that the transition reflects the same
underlying reservoir process, that is, the depletion of the fluids initially
present in the reservoir and the onset of production of a greater proportion of
recharge fluid with relatively low gas concentrations from surrounding areas.
For the purposes of this review, GeothermEx has used the estimated well
capacities based on its assessment of June 1998 as the starting point for its
forecast of power generation. To convert the gross capacities to net megawatts,
GeothermEx has assumed parasitic loads to be 10% of the
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gross megawatt output, which is consistent with the historic performance of the
Coso plants. GeothermEx has also assumed a plant capacity factor of 96% to allow
for plant down time, based on the ratio of the field's average net megawatt
output for the past three years (260 NMW) to the electromechanical limit of the
plants after parasitic loads (270 NMW). The plant capacity factor is
approximately 108% if the average net megawatts produced is compared to the
rated capacity of the plants (240 MW). With these adjustments, the combined net
megawatt capacity of the Coso projects as of mid-1996 was 273.5 NMW. This
represents a spare capacity of 11 NMW over the field's actual output of 262.5
NMW in 1996.
This amount of spare capacity should allow a plateau of constant output for a
year or so, provided existing wells are maintained in good mechanical condition
which has generally been the case historically. New wells planned for the
future will be drilled in relatively undeveloped portions of the reservoir, such
as the BLM North area (located west of Navy I and Navy II on acreage formerly
leased to the Los Angeles Department of Water and Power) and the northern
portion of the East Flank. As discussed further in Chapter 3, the projected
drilling costs in the financial projections are sufficient to drill two wells
per year from 1999 to 2006.
Figure 2.7 shows a comparison of GeothermEx's power generation forecast based on
decline curve analysis with the power generation forecast in the financial
projections. GeothermEx's forecast of power generation assumes a 4.1% harmonic
decline starting in 2006. The choice of this decline rate is explained below.
As discussed earlier, the current decline trends of Navy I and Navy II wells
could be approximately fitted to harmonic decline trends of 3.4% and 6.4%,
respectively, starting in January 1992. Similarly, the decline trend of the BLM
wells could be fitted to a harmonic decline trend of 16% starting in mid-1995.
However, since the decline rate itself declines with time in the case of
harmonic decline, these rates would be considerably lower by 2006.
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We estimate harmonic decline rates (as of January, 2006) of 2.4%, 3.5% and 6.4%
for Navy I, Navy II and BLM, respectively. Since these plants all have
approximately the same net generation, it is reasonable to estimate an
arithmetic average decline rate, which is 4.1%. In figure 2.7, the trend
according to GeothermEx's forecast is compared to that of Caithness, which lies
essentially parallel to and within 1 to 5% of GeothermEx's forecast. This
similarity between the two forecasts is remarkable considering that Caithness's
forecast was based on separate estimates of decline rates from six sub-areas
within the Coso field (Navy I West, Navy I East, Navy II West, Navy II East, BLM
East and West, and BLM North) compared to decline trend estimates for three sub-
areas into which the field was divided (Navy I, Navy II and BLM) in preparing
GeothermEx's forecast. We believe that Caithness's forecast is reasonable
because it is very similar to our independent forecast.
2.3 Injection
---------
The Coso projects currently have spare injection capacity to dispose of produced
water and steam condensate. Several injection wells are idle or under-utilized,
particularly at Navy I where many of the production wells have dried out. Plots
of individual injection well histories for the Navy I, Navy II, and BLM projects
are included in Appendices D, E, and F, respectively. Wellhead pressures on
active injectors are generally less than 150 pounds per square inch gauge
(psig). Some of the wellhead pressures in the plots show higher values when
injection rates are low or zero. This is because some injection wells fill with
a column of vapor (steam and NCG) when the rate of injection gets too low. In
this vapor-filled condition, these wells show pressures at the wellhead which
reflect the high pressures of the reservoir. However, once injection is started
again with a high-pressure pump, wellhead pressures typically fall, and the
wells again become capable of taking injection water.
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Some injection wells (particularly on Navy II and BLM) have been affected by the
formation of silica scale. Produced water is treated with sulfuric acid at
several locations in the field to control this scale in surface pipelines and in
injection wells. There has also been some success in using hydrofluoric acid
stimulations to restore the injectivity of wells that have been damaged by
silica scale. In the event of a sudden mechanical problem in an injection well,
it is possible to divert injection water through temporary lines to idle
injection wells until the problem well can be repaired or replaced.
The new low-pressure steam separation systems present some possibility of
silica-scaling in the separators, injection lines and injection wells, because
the low-pressure steam separation results in considerable over-saturation of
silica. To mitigate this scaling, the operator has been testing acidification
of the liquid phase and plans to use this method to control silica scale.
Acidification for scale control has been successfully used at other geothermal
projects, and it is reasonable to expect that it will be successful at Coso.
Properly controlled addition of acid should not result in undue corrosion, and
should provide a significant level of protection to the injection wells.
However, we cannot predict just what the remaining scaling effect on the
injection wells will turn out to be, or the frequency of re-drills or workovers
that could be needed to relieve the effects of downhole scale deposition.
2.4 Gases in Steam
--------------
Historical trends of the hydrogen sulfide (H2S) and the total non-condensible
gases (NCG) in steam have been examined by comparing measurements done since
June 1996 with graphs and detailed tabulations that were compiled in 1997. Gas
concentration trends bear a relationship to reservoir processes, and the H2S
component is of particular interest because releases of H2S to the
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atmosphere are regulated by the government and so H2S must be removed from the
other gases that are released.
Table 2.1 is a summary of the H2S concentration at mid-year at each well, from
1990 through 1998. The status of the H2S trend (stable, decreasing, increasing)
as of mid-1998 is indicated, along with an abbreviated description of the
overall trend during the production history of the well. Total NCG content in
steam is not separately tabulated, but trends of total NCG tend to correlate
closely with trends of H2S.
As of June 1998, nearly all wells had stable or nearly stable gas
concentrations. H2S was decreasing or possibly decreasing at 16 wells, and
possibly increasing at only three wells. Gases at BLM East and BLM West wells
remained particularly stable with one well decreasing and three possibly
decreasing. Most Navy I wells were stable, with three decreasing and three
possibly increasing, but none changing rapidly. At Navy II wells, the gases
were stable in about 2/3 of the cases, and decreasing in about 1/3 of the cases.
The highest concentrations of H2S occur in BLM West, and in the wells on the
East Flank.
The currently stable and decreasing gas concentrations follow earlier
instabilities and transient conditions. By 1996, it was established that most
wells with high initial NCG concentrations had shown rapid decreases in these
concentrations; then, commonly in 1991 or 1992 (1992-3 in the BLM areas), there
was a distinct break in slope to stable conditions or a more gentle and linear
decline trend.
In summary, current trends of gases in Coso steam are either stable of gently
decreasing, and it is unlikely that there will be any significant increase in
the concentrations of H2S or total NCG in Coso steam in the future.
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3. CAPITAL AND OPERATING COSTS
Resource-related costs reviewed herein include those related to drilling new
wells, connecting them to the gathering system (for wells drilled on pads with
existing production wells) or extending the gathering system (for wells drilled
on new pads) and working over existing wells. Figures 3.1, 3.2 and 3.3 show the
costs in these three categories as provided by Caithness, including both
historical data from 1995 through 1998 and projections for 1999 through 2009.
Also included in either the drilling or gathering system costs are the costs of
building low-pressure separators to enable the use of low-pressure steam.
Projected costs for the three projects are summarized in table 3.1. All
projected costs are based on 1999 dollars and are escalated at 3% per year.
As illustrated in figure 3.1, historical drilling expenditures from 1995 to 1998
were in the range of $12 million to $15 million per year, with the exception of
1996, when drilling expenditures were about $2 million. Going forward, the
financial projections include $6.5 million in drilling funds for 1999, about $4
million in 2000, $7 million in 2001, $10.5 million in 2002, and $7.5 to $8.5
million in 2003 - 2006. No drilling is planned after 2006. The number of new
wells to be drilled each year and injection well redrills, which together make
up the drilling costs, are included in table 3.1.
The cost assumed in the financial projections for drilling a new well is $2.75
million in 1999, except for a BLM well to be drilled this year (see discussion
below). Based on documents provided by Caithness, a total of six new wells were
drilled in 1997 and 1998, with an average cost of $2.73 million and an average
depth of approximately 9,000 feet. Considering that the average depths of
future wells will be similar, the estimate of $2.75 million per well is
reasonable. The average productivity of these wells was approximately 8 MW
(gross); this includes the highly
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productive East Flank well 38B-9. Without 38B-9, the average productivity was
approximately 5 MW (gross). Caithness has reasonably assumed an average 1999
productivity of 5.6 MW for new wells. The financial projections do not include
any decline in the expected capacity of make-up wells; it remains at 5.6 MW
throughout the project life. While this amount should be expected to decline
according to the decline rate assigned to each area of the field (see Chapter
2), as few make-up wells are planned and the decline rate in well productivity
is very small, the difference between the projections with and without declining
the make-up wells is not significant.
Several production wells were redrilled in 1997 and 1998, at an average cost of
$1.3 million, an average depth of 6,000 feet, and an average productivity of 3.2
MW (gross). No funds are allocated in the financial projections for production
well redrills, as Caithness does not plan to redrill any existing production
wells. However, Caithness reports that there is about $1.5 million per year in
the O&M section of the budget, which will be used for well clean-outs and other
well maintenance. Production well workovers are discussed below. One
injection well redrill per year is planned, with a 1999 cost of $1.2 million per
well, which is reasonable.
In 1999, the drilling costs include an injection well redrill in the BLM and
Navy II areas ($1.2 million each), a purchase of new drill pipe ($150,000,
allocated unequally between Navy II and BLM), drilling a slim exploration well
in BLM North ($400,000), deepening of the existing BLM North well 43-7
($726,000) and drilling BLM North well 43A-7 ($2.9 million). The last is
planned to a total depth of 10,000 feet, which is deeper than other planned
wells at Coso, and accounts for its slightly greater cost.
One injection well redrill and one BLM production well (43B-7) are planned for
2000 (table 3.1). A total of 15 new wells are planned from 1999 through 2006,
which equates to nearly 11 MW per year, using Caithness' assumption of no
decline in the capacity of make-up wells. As indicated by
3-2
[GeothermEx, Inc. Letterhead]
drilling data provided by Caithness, which are reflected in the costs in figure
3.1, six new wells were drilled in the last two years. Therefore, we would
expect that two to three make-up wells would be needed each year to maintain
production, unless the make-up wells have a higher-than-average capacity which
is expected under Caithness' plan to drill in the East Flank area.
In addition to the cost of drilling a well, there are costs associated with
connecting the well to the gathering system. In the case where a new well is
drilled from a pad with existing production wells, the connection cost is
assumed by Caithness to be $500,000; these are "pad pipelines," which are
charged to the appropriate project. For wells drilled on new pads in the BLM
North and East Flank areas, additional expenses will be incurred to extend the
steam gathering pipelines as indicated in table 3.1; these are "trunk lines,"
which are shared equally between the projects. There are also expenses
associated with additions or modifications to the steam separation equipment
included in this category in 1999 and 2006. The projected gathering system
costs are included in table 3.1 and figure 3.2. We have not independently
estimated the costs of pipelines or LP separation equipment. The well
connection costs are on the conservative side.
The assumptions page of the financial projections indicates a 1999 workover cost
of $700,000 per well; however, discussion with Caithness revealed that $700,000
is budgeted for each unit, which is adequate for approximately two workovers
each year. This is escalated at 3% per year. The workover costs and
frequencies are reasonable. Workovers are assumed to be needed throughout the
life of the project; the escalation of workover costs is shown in table 3.1 and
figure 3.3.
3-3
Table 2.1: H2S in Steam at Coso Wells
H2S in Steam (parts per million by weight - ppmw) /a/
---------------------------------------------------------- Status
June June June June June June June June June June Historical
Well No. 1990 1991 1992 1993 1994 1995 1996 1997 1998 1998 /b/ Trend to mid-96 /c/
- --------- ------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---------------
Navy 1
- ------------------------------------------------------------------------
66-6 30 insuff insuff
68-6 200 200 135 130 S-D insuff
78-6 130 110 110 110 110 110 110 105 100 S s
78A-6 50 40 40 100 170 170 150 160 S d-i(6/92)
78B-6 110 90 90 100 90 105 S s
43-7 340 insuff
52-7 90 60 45 80 150 170 180 185 185 S d-i(6/93)
52A-7 110 140 130 150 190 195 220 225 I? i-s
52B-7 160 140 140 140 140 175 180 S-I d-s
61-7 40 30 25 80 130 140 150 160 180 I d-i(6/92)
61A-7 45 55 80 110 150 170 170 180 180 I? i
63-7 70 70 70 60 65 75 85 90 95 S s
63A-7 40 40 25 25 50 50 50 60 90 I? d-i(6/92)
63B-7 40 30 55 60 65 100 I s
66-7 250 200 175 175 150 140 115 D d
66A-7 50 80 100 120 120 55 S? i
71-7 70 110 125 150 160 180 175 175 180 S i
71A-7 100 120 130 150 190 200 200 215 215 S i-s
71B-7 80 80 100 100 95 130 S? d-i(6/93)
73-7 20 20 20 120 90 90 90 90 90 S s-(jump 6/92)
73A-7 50 65 75 75 80 90 100 90 100 S i
75-7 225 150 125 120 120 120 120 105 95 D? d-s(6/92)
75A-7 200 140 125 115 115 110 110 95 85 D? d-s(6/92)
75B-7 100 100 100 100 100 100 85 75 D s
76-7 170 120 110 110 100 100 110 90 40 D d-s(6/91)
76A-7 75 75 75 100 100 S? s (irreg.)
76B-7 140 110 100 110 110 100 100 95 110 S d-s
77-7 150 100 100 100 100 100 90 80 85 S-D d-s(6/91)
78-7 300 200 175 150 125 125 125 125 165 S? d-s(6/91)
87-7 100 75 75 75 50 45 50 S d-s(6/92)
87A-7 100 100 100 100 125 S s
15A-8 225 125 100 100 90 90 90 80 80 S d-s(3/92)
16A-8RD 125 140 130 120 110 115 120 100 90 S-D d-s(6/93)
24-8 100 120 125 125 125 120 95 100 S s
47-8 130 100 80 80 80 90 S d-s
47A-8RD 150 150 100 95 95 105 115 S d-s
34A-9 1050 1050 insuff
38-9 500 1000 1000 500 S? insuff
38A-9 630 insuff insuff
Navy 2
- ------------------------------------------------------------------------
78-7 300 200 175 150 125 125 125 insuff d-s(6/91)
22-16 1400 1000 900 850 800 800 S d
51-16 600 600 600 570 530 D? irregular
51A-16 900 850 600 720 630 S insuff. data
64-16 600 450 400 240 D? insuff. data
83A-16 700 500 400 350 450 325 S? d
83B-16 325 250 225 320 140 D d
Page 1 of 3
Table 2.1: H2S in Steam at Coso Wells
---------------------------------------------------------------------------------------------
H2S in Steam (parts per million by weight - ppmw) /a/
---------------------------------------------------------- Status
June June June June June June June June June June Historical
Well No. 1990 1991 1992 1993 1994 1995 1996 1997 1998 1998 /b/ Trend to mid-96 /c/
- --------- ------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---------------
15-17RD 430 300 260 230 210 200 180 140 175 S d-s(12/91)
15A-17RD 350 290 250 210 170 190 210 170 160 S-D d-s(3/94)
37-17 150 120 150 140 120 115 120 S s-d
37A-17 200 110 110 90 80 70 80 70 80 S d-s(6/91)
37B-17 175 125 140 150 140 100 S? s
58A-18 210 insuff
58B-18 290 insuff
63-18RD 375 240 170 150 130 100 100 95 120 S d-s(12/91)
63A-18 500 300 180 180 180 130 140 105 S d-s(6/92)
63B-18 200 150 110 100 100 100 insuff d-s(6/92)
65-18 650 430 400 375 320 330 350 325 235 D? d-s(12/91)
65A-18 900 500 450 500 375 375 375 360 270 D? d-s(6/92)
72-18 175 80 50 45 45 insuff d-s(6/92)
72A-18 175 100 70 50 60 80 95 25 D? d-s(6/92)
72B-18 200 100 75 60 60 60 60 85 45 D? d-s(6/92)
72C-18 200 100 80 70 75 65 65 120 75 S d-s(6/92)
73-18RD 400 150 100 100 80 80 80 65 60 S d-s(6/92)
73A-18 400 200 180 175 160 150 150 130 S d-s(12/91)
76-18 900 600 400 350 350 300 250 400 200 S-D d-s(6/92)
76A-18 650 400 350 300 270 240 200 320 140 D d-s(6/91)
81-18 170 125 100 100 100 100 100 90 110 S d-s(6/92)
81A-18RD 70 insuff
- ------------------------------------------------------------------------
BLM East
- ------------------------------------------------------------------------
16-20 60 55 50 50 40 35 S d-s(6/93)
16A-20 600 650 500 520 510 510 500 S d-s(6/94)
16B-20 175 200 225 250 210 235 S s
24-20 150 150 150 150 150 125 125 125 S s
24A-20 150 100 100 90 80 70 insuff d-s(6/93)
24B-20 80 60 45 50 65 85 60 S? s
32-20 220 140 125 110 100 100 100 100 125 S d-s(6/93)
32A-20 150 80 25 25 25 25 20 20 S d-s(12/92)
34-20 150 110 110 75 60 60 60 insuff d-s(6/93)
34A-20 110 80 60 40 60 50 60 insuff d-s(6/92)
35-20 150 160 150 50 50 40 40 40 S d-s(6/93)
35A-20 100 60 20 20 d-s(12/91)
35A-20RD 40 25 25 10 D? insuff
35B-20 35 25 25 25 25 20 20 5 D? s
- ------------------------------------------------------------------------
Page 2 of 3
Table 2.1: H2S in Steam at Coso Wells
H2S in Steam (parts per million by weight - ppmw) /a/
------------------------------------------------------------------ Status
June June June June June June June June June June Historical
Well No. 1990 1991 1992 1993 1994 1995 1996 1997 1998 1998 /b/ Trend to mid-96 /c/
- --------- ------ ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------------
BLM West
- --------------------------------------------------------------------------------
23-19RD 1050 850 750 700 700 930 830 S d-s(5/94)
33-19 1400 1000 900 800 600 600 600 620 500 S-D d-s?(6/94)
72A-19RD 400 500 500 S
72B-19 500 430 340 D insuff
73-19 1200 900 300 400 700 500 400 410 370 D d(irreg.)
74-19 900 700 600 350 350 400 450 600 580 S? d-s(6/93)
74A-19 500 325 300 275 260 250 250 230 250 S d-s(6/91)
74B-19RD 400 300 270 250 250 250 250 230 270 S d-s(6/91)
81-19 800 700 600 500 425 425 475 580 570 S? d-s(6/93)
81A-19RD 100 30 40 40 40 160 I? d-s(6/93)
81B-19 150 150 S?
33A-19 1300 1200 S?
33B-19 410 310 D?
- --------------------------------------------------------------------------------
Notes:(a) H2S concentration in bold italics is the highest level.
H2S concentration in bold is the lowest level.
(b) Status June 1998 D = decreasing
S = stable
I = increasing
? = no data or very uncertain
Combined symbols indicate uncertain
condition; e.g.,
S-D = stable or decreasing
(c) Historical Trend d = decreasing
(shown only if there s = stable
is a distinct pattern) i = increasing
d-s = decreasing then stable
d-s (date) = strong decrease followed by
gentle decrease or stable; date
indicates approximate break in slope
d-i (date) = decreasing, followed by
increase; date indicates start of increase
Table 3.1: Summary of Drilling, Gathering System and Workover Costs for the
Coso Geothermal Project in Caithness pro forma
Drilling Gathering System Workover
--------------------------------------------------------------------------
Cost Cost Budget
Year Project Summary ($1,000s) Summary ($1,000s) ($1,000s)
========================================================================================================================
1999 Navy I 1/3 of each: East Flank LP
system; 43-7 trunk line; safety
None 0 platforms 1,248 700
-----------------------------------------------------------------------------------------------------------------
Navy II 1/3 of each: East Flank LP
Injection well redrill; system; 43-7 trunk line; safety
1/5 of drill pipe costs 1,225 platforms 1,248 700
-----------------------------------------------------------------------------------------------------------------
BLM deepen 43-7; drill 1/3 of each: East Flank LP
43A-7; injection well system; 43-7 trunk line; safety
redrill; slim platforms, plus BLM LP
exploration hole; 4/5 system; tie-in 43-7, 43A-7 and
of drill pipe costs 5,351 46-19RD 3,248 700
- ------------------------------------------------------------------------------------------------------------------------
2000 Navy I None 0 None 0 721
-----------------------------------------------------------------------------------------------------------------
Navy II Injection well redrill 1,224 None 0 721
-----------------------------------------------------------------------------------------------------------------
BLM Drill well 43B-7 2,918 Tie-in well 43B-7 531 721
- ------------------------------------------------------------------------------------------------------------------------
2001 Navy I Injection well redrill 1,249 None 0 743
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 743
-----------------------------------------------------------------------------------------------------------------
BLM Tie-in 43C-7 and 45-7; 45-7
Drill 43C-7 and 45-7 6,010 pad pipeline 1,639 743
- ------------------------------------------------------------------------------------------------------------------------
2002 Navy I None 0 1/3 Navy II/BLM trunk line 563 765
-----------------------------------------------------------------------------------------------------------------
Navy II Drill 22A-16 and 1/3 Navy II/BLM trunk line plus
22B-16 6,190 tie-in 22A-16 and 22B-16 1,688 765
-----------------------------------------------------------------------------------------------------------------
BLM Injection well redrill; 1/3 Navy II/BLM trunk line plus
drill well 46A-7 4,369 tie-in 46A-7 1,126 765
- ------------------------------------------------------------------------------------------------------------------------
Page 1 of 4
Drilling Gathering System Workover
--------------------------------------------------------------------------
Cost Cost Budget
Year Project Summary ($1,000s) Summary ($1,000s) ($1,000s)
========================================================================================================================
2003 Navy I None 0 1/3 Navy I/Navy II trunk line 386 788
-----------------------------------------------------------------------------------------------------------------
Navy II Injection well redrill 1,299 1/3 Navy I/Navy II trunk line 386 788
-----------------------------------------------------------------------------------------------------------------
BLM 1/3 Navy I/Navy II trunk line
Drill 66A-6 and plus tie-in 66A-6 and 66B-6;
66B-6 6,376 66-6 pad pipeline 2,415 788
- ------------------------------------------------------------------------------------------------------------------------
2004 Navy I Drill 38C-9; injection
well redrill 4,635 Tie-in 38C-9 597 812
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 812
-----------------------------------------------------------------------------------------------------------------
BLM Drill 66B-6 3,284 Tie-in 66B-6 597 812
- ------------------------------------------------------------------------------------------------------------------------
2005 Navy I None 0 None 0 836
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 836
-----------------------------------------------------------------------------------------------------------------
BLM Injection well redrill; Tie-in 48-7 and 48B-7; 48-7
drill 48-7 and 48B-7 8,143 pad pipeline 1,845 836
- ------------------------------------------------------------------------------------------------------------------------
2006 Navy I None 0 Separator modifications 950 861
-----------------------------------------------------------------------------------------------------------------
Navy II Injection well redrill 1,406 None 0 861
-----------------------------------------------------------------------------------------------------------------
BLM Drill 48B-7 and Tie-in 48B-7 and 88A-1; 88-1
88A-1 6,967 pad pipeline 2,438 861
- ------------------------------------------------------------------------------------------------------------------------
2007 Navy I None 0 None 0 887
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 887
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 887
- ------------------------------------------------------------------------------------------------------------------------
2008 Navy I None 0 None 0 913
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 913
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 913
- ------------------------------------------------------------------------------------------------------------------------
Page 2 of 4
Drilling Gathering System Workover
--------------------------------------------------------------------------
Cost Cost Budget
Year Project Summary ($1,000s) Summary ($1,000s) ($1,000s)
========================================================================================================================
2009 Navy I None 0 None 0 941
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 941
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 941
- ------------------------------------------------------------------------------------------------------------------------
2010 Navy I None 0 None 0 969
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 969
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 969
- ------------------------------------------------------------------------------------------------------------------------
2011 Navy I None 0 None 0 998
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 998
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 998
- ------------------------------------------------------------------------------------------------------------------------
2012 Navy I None 0 None 0 1,028
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 1,028
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 1,028
- ------------------------------------------------------------------------------------------------------------------------
2013 Navy I None 0 None 0 1,059
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 1,059
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 1,059
- ------------------------------------------------------------------------------------------------------------------------
2014 Navy I None 0 None 0 1,091
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 1,091
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 1,091
- ------------------------------------------------------------------------------------------------------------------------
2015 Navy I None 0 None 0 1,123
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 1,123
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 1,123
- ------------------------------------------------------------------------------------------------------------------------
Page 3 of 4
Drilling Gathering System Workover
--------------------------------------------------------------------------
Cost Cost Budget
Year Project Summary ($1,000s) Summary ($1,000s) ($1,000s)
========================================================================================================================
2016 Navy I None 0 None 0 1,157
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 1,157
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 1,157
- ------------------------------------------------------------------------------------------------------------------------
2017 Navy I None 0 None 0 1,192
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 1,192
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 1,192
- ------------------------------------------------------------------------------------------------------------------------
2018 Navy I None 0 None 0 1,228
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 1,228
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 1,228
- ------------------------------------------------------------------------------------------------------------------------
2019 Navy I None 0 None 0 1,264
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 1,264
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 1,264
- -----------------=======================================================================================================
Page 4 of 4
Figure 1.1: Location of Coso geothermal field
[MAP APPEARS HERE]
1999, GeothermEx, Inc.
Figure 1.2: Well location map, Coso geothermal field
[MAP APPEARS HERE]
1999, GeothermEx, Inc.
Figure 2.1: Coso MW forecast from Caithness financial projections
[GRAPH APPEARS HERE]
1999, GeothermEx, Inc.
Figure 2.2: Megawatts per well vs. time, Navy I
[GRAPH APPEARS HERE]
1999, GeothermEx, Inc.
Figure 2.3: Megawatts per well vs. time, Navy II
[GRAPH APPEARS HERE]
1999, GeothermEx, Inc.
Figure 2.4: Megawatts per well vs. time, BLM
[GRAPH APPEARS HERE]
1999, GeothermEx, Inc.
Figure 2.5:
Total NCG/Steam Vs. Time - Navy II Well 15-17RD
[GRAPH APPEARS HERE]
Date
Figure 2.6:
H2S/Steam Vs. Time - Navy II Well 15-17RD
[GRAPH APPEARS HERE]
Date
Figure 2.7: Comparison of Caithness and GeothermEx MW forecasts
[GRAPH APPEARS HERE]
1999, GeothermEx, Inc.
Figure 3.1: Planned drilling costs at Coso from Caithness financial projections
[GRAPH APPEARS HERE]
1999, GeothermEx, Inc.
Figure 3.2: Planned gathering system costs at Coso from Caithness financial
projections
[GRAPH APPEARS HERE]
Figure 3.3: Planned workover costs at Coso from Caithness financial projections
[GRAPH APPEARS HERE]
1999, GeothermEx, Inc.
APPENDICES A THROUGH F
OF
GEOTHERMAL
CONSULTANT'S REPORT
APPENDICES A THROUGH F OF THE GEOTHERMAL CONSULTANT'S REPORT HAVE BEEN OMITTED
FROM THIS PROSPECTUS. YOU CAN OBTAIN COPIES OF THESE APPENDICES FROM US UPON
REQUEST.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
, 1999
Until , 1999, all dealers that effect transactions in the Series B notes,
whether or nor participating in this exchange offer, may be required to deliver
a prospectus. This is in addition to the dealer(s) obligation to deliver a
prospectus when acting as underwriters and with respect to their unsold
allotments or subscriptions.
Caithness Coso Funding Corp.
$110,000,000
6.80% Series B Senior Secured Notes due 2001
$303,000,000
9.05% Series B Senior Secured Notes due 2009
-----------------------
PROSPECTUS
-----------------------
Exchange Agent:
U.S. Bank Trust National Association
185 East Fifth Street
St. Paul, Minnesota 55101
- --------------------------------------------------------------------------------
We have not authorized any dealer, salesperson or other person to give you
written information other than this prospectus or to make representations as to
matters not stated in this prospectus. You must not rely on unauthorized
information. This prospectus is not an offer to sell the securities or our
solicitation of your offer to buy the securities in any jurisdiction where that
would not be permitted or legal. Neither the delivery of this prospectus nor
any sales made hereunder after the date of this prospectus shall create an
implication that the information contained herein or the affairs of Caithness
Energy, L.L.C., Caithness Coso Funding Corp., Coso Finance Partners, Coso
Energy Developers or Coso Power Developers have not changed since the date
hereof.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
Item 20. Indemnification of Directors and Officers
Pursuant to Section 102(b)(7) of the Delaware General Corporations Law,
Article IX of the Certificate of Incorporation for Funding Corp. (the
"Certificate of Incorporation") provides that no director of Funding Corp.
shall be liable to Funding Corp. or its stockholders for monetary damages for a
breach of fiduciary duty as a director, except to the extent that exculpation
from liability is not permitted under the Delaware General Corporation Law as
in effect at the time such liability is determined.
Article X of the Certificate of Incorporation further provides that Funding
Corp. shall, to the fullest extent permitted under the laws of the State of
Delaware, indemnify, and upon request, advance expenses to its directors and
officers against liabilities that may arise by reason of their status or
service as directors, officers, trustees, partners, employees, or agents of the
Corporation. Officers and directors shall be indemnified against expenses
(including attorney's fees and expenses), judgments, fines, penalties, and
amounts paid in settlement incurred in connection with the investigation,
preparation, and defense of such actions, suits, proceedings, or claims.
However, Funding Corp. will not be required to indemnify or advance expenses to
any person in connection with such actions, suits, proceedings or claims when
the action, suit, proceeding or claim was initiated by or on behalf of the
officer or director seeking indemnity.
Article XIV of the general partnership agreement of each of Coso Power
Developers, Coso Finance Partners and Coso Energy Developers (collectively, the
"General Partnership Agreements") empower each such partnership to indemnify
and hold harmless its managing partner, and the officers, directors,
shareholders, and agents of its managing partner ("Indemnitees") from and
against any and all losses, claims, demands, costs, damages, judgments, fines,
settlements and expenses (including attorney's fees and disbursements) arising
out of or incidental to the business of each partnership provided that
Indemnitee's conduct did not constitute fraud, willful misconduct, or gross
negligence. Article XIV of each of the General Partnership Agreements also
provides that the managing partner, in its capacity as such, or its officers,
directors, shareholders, employees, or agents will not be held liable to their
respective partnership or other partners of such partnership for any expense,
loss, or liability suffered by such partnership or other partners of such
partnership in connection with that partnership's activities, provided that the
managing partner or its affiliates acted in good faith and without gross
negligence and had previously determined that such a course of conduct was in
the best interests of the partnership.
The foregoing discussion of the Certificate of Incorporation, Bylaws, the
General Partnership Agreements, and Delaware law is not intended to be
exhaustive and is qualified in its entirety by the Certificate of
Incorporation, Bylaws, the General Partnership Agreements and the relevant
provisions of Delaware Corporation Law.
II-1
Item 21. Exhibits and Financial Statement Schedules.
Exhibit
Number Description
------- -----------
3.1 Certificate of Incorporation of Caithness Coso Funding Corp.
3.2 Bylaws of Caithness Coso Funding Corp.
3.3* Third Amended and Restated Partnership Agreement of Coso Finance
Partners, dated as of May 28, 1999.
3.4* Third Amended and Restated Partnership Agreement of Coso Energy
Developers, dated as of May 28, 1999.
3.5* Third Amended and Restated Partnership Agreement of Coso Power
Developers, dated as of May 28, 1999.
4.1 Indenture, dated as of May 28, 1999, among Caithness Coso Funding
Corp., Coso Finance Partners, Coso Energy Developers, Coso Power
Developers, and U.S. Bank Trust National Association as trustee and as
collateral agent.
4.2 Specimen Series B notes (included in Exhibit 4.1).
4.3 Notation of Guarantee, dated as of May 28, 1999, of Coso Finance
Partners.
4.4 Notation of Guarantee, dated as of May 28, 1999, of Coso Energy
Developers.
4.5 Notation of Guarantee, dated as of May 28, 1999, of Coso Power
Developers.
4.6 Registration Rights Agreement, dated as of May 28, 1999, by and among
Caithness Coso Funding Corp., Coso Finance Partners, Coso Energy
Developers, Coso Power Developers, and Donaldson, Lufkin & Jenrette
Securities Corporation.
5.1* Opinion of Riordan & McKinzie, A Professional Law Corporation.
5.2* Opinion of Reed Smith Shaw & McClay LLP.
10.1 Deposit and Disbursement Agreement, dated as of May 28, 1999, among
Caithness Coso Funding Corp., Coso Finance Partners, Coso Energy
Developers, Coso Power Developers, and U.S. Bank Trust National
Association, as collateral agent, as trustee, and as depositary.
10.2 Credit Agreement, dated as of May 28, 1999, between Caithness Coso
Funding Corp. and Coso Finance Partners.
10.3 Promissory Note due 2001 of Coso Finance Partners in favor of
Caithness Coso Funding Corp.
10.4 Promissory Note due 2009 of Coso Finance Partners in favor of
Caithness Coso Funding Corp.
10.5 Credit Agreement, dated as of May 28, 1999, between Caithness Coso
Funding Corp. and Coso Energy Developers.
10.6 Promissory Note due 2001 of Coso Energy Developers in favor of
Caithness Coso Funding Corp.
10.7 Promissory Note due 2009 of Coso Energy Developers in favor of
Caithness Coso Funding Corp.
10.8 Credit Agreement, dated as of May 28, 1999, between Caithness Coso
Funding Corp. and Coso Power Developers.
10.9 Promissory Note due 2001 of Coso Power Developers in favor of
Caithness Coso Funding Corp.
10.10 Promissory Note due 2009 of Coso Power Developers in favor of
Caithness Coso Funding Corp.
10.11 Purchase Agreement, dated as of May 21, 1999, by and among Caithness
Coso Funding Corp., as issuer, Coso Finance Partners, Coso Energy
Developers and Coso Power Developers, as guarantors, and Donaldson,
Lufkin & Jenrette Securities Corporation, as initial purchaser.
II-2
Exhibit
Number Description
------- -----------
10.12 Security Agreement, dated as of May 28, 1999, executed by and among
Caithness Coso Funding Corp. in favor of U.S. Bank Trust National
Association, as collateral agent.
10.13 Security Agreement, dated as of May 28, 1999, executed by and among
Coso Finance Partners in favor of U.S. Bank Trust National
Association, as collateral agent.
10.14 Security Agreement, dated as of May 28, 1999, executed by Coso Energy
Developers in favor of U.S. Bank Trust National Association, as
collateral agent.
10.15 Security Agreement, dated as of May 28, 1999, executed by Coso Power
Developers in favor of U.S. Bank Trust National Association, as
collateral agent.
10.16 Reserved.
10.17 Reserved.
10.18* Security Agreement (Navy I project permits), dated as of May 28, 1999,
executed by Coso Operating Company LLC in favor of U.S. Bank Trust
National Association, as collateral agent.
10.19 Security Agreement (BLM project permits), dated as of May 28, 1999,
executed by Coso Operating Company LLC in favor of U.S. Bank Trust
National Association, as collateral agent.
10.20 Security Agreement (Navy II project permits), dated as of May 28,
1999, executed by Coso Operating Company LLC in favor of U.S. Bank
Trust National Association, as collateral agent.
10.21 Security Agreement (Navy I project permits), dated as of May 28, 1999,
executed by FPL Energy Operating Services, Inc., in favor of U.S. Bank
Trust National Association, as collateral agent.
10.22 Security Agreement (BLM project permits), dated as of May 28, 1999,
executed by FPL Energy Operating Services, Inc., in favor of U.S. Bank
Trust National Association, as collateral agent.
10.23 Security Agreement (Navy II project permits), dated as of May 28,
1999, executed by FPL Energy Operating Services, Inc., in favor of
U.S. Bank Trust National Association, as collateral agent.
10.24 Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Finance Partners
in favor of U.S. Bank Trust National Association, as trustee, and as
beneficiary.
10.25 Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Energy
Developers in favor of U.S. Bank Trust National Association, as
trustee, and as beneficiary.
10.26 Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Power Developers
in favor of U.S. Bank Trust National Association, as trustee, and as
beneficiary.
10.27 Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Transmission
Line Partners in favor of U.S. Bank Trust National Association, as
trustee, and as beneficiary.
10.28 Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by China Lake Joint
Venture in favor of U.S. Bank Trust National Association, as trustee,
and as beneficiary.
10.29 Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Land Company in
favor of U.S. Bank Trust National Association, as trustee, and as
beneficiary.
II-3
Exhibit
Number Description
------- -----------
10.30 Stock Pledge Agreement, dated as of May 28, 1999, by Coso Finance
Partners, Coso Energy Developers and Coso Power Developers in favor of
U.S. Bank Trust National Association, as collateral agent.
10.31 Partnership Interest Pledge Agreement (Navy I), dated as of May 28,
1999, by ESCA, LLC and New CLOC Company, LLC, in favor of U.S. Bank
Trust National Association, as collateral agent.
10.32 Partnership Interest Pledge Agreement (BLM), dated as of May 28, 1999,
by Caithness Coso Holdings, LLC and New CHIP Company, LLC, in favor of
U.S. Bank Trust National Association, as collateral agent.
10.33 Partnership Interest Pledge Agreement (Navy II), dated as of May 28,
1999, by Caithness Navy II Group, LLC and New CTC Company, LLC, in
favor of U.S. Bank Trust National Association, as collateral agent.
10.34 Partnership Interest Pledge Agreement (CTLP), dated as of May 28,
1999, by Coso Energy Developers and Coso Power Developers, in favor of
U.S. Bank Trust National Association, as collateral agent.
10.35 Partnership Interest Pledge Agreement (CLJV), dated as of May 28,
1999, by Caithness Acquisition Company, LLC and Caithness Geothermal
1980 Ltd., L.P., in favor of U.S. Bank Trust National Association, as
collateral agent.
10.36 Partnership Interest Pledge Agreement (CLC), dated as of May 28, 1999,
by Caithness Acquisition Company, LLC and Caithness Geothermal 1980
Ltd., L.P., in favor of U.S. Bank Trust National Association, as
collateral agent.
10.37 Promissory Notes Security Agreement, dated as of May 28, 1999, by
Caithness Coso Funding Corp., in favor of U.S. Bank Trust National
Association, as collateral agent.
10.38 Original Service Contract N62474-79-C-5382, dated December 6, 1979,
between U.S. Naval Weapons Center and California Energy Company, Inc.,
Contractor (the "Navy Contract"), including all amendments thereto.
10.39 Escrow Agreement, dated December 16, 1992, as amended, by and among
Coso Finance Partners, Bank of America and the Navy.
10.40 Offer to Lease and Lease for Geothermal Resources, Serial No. 11402,
dated April 29, 1985 but effective May 1, 1985, from the United States
of America, acting through the Bureau of Land Management, to
California Energy Company, Inc.; as assigned by Assignment Affecting
Record Title to Geothermal Resources Lease, dated June 24, 1985, but
effective July 1, 1985 from California Energy Company, Inc. to Coso
Land Company; as assigned by Assignment of Record Title Interest in a
Lease for Oil and Gas or Geothermal Resources, dated April 20, 1988,
but effective May 1, 1988 from Coso Land Company to Coso Geothermal
Company; as assigned by Assignment of Record Title Interest in a Lease
for Oil and Gas or Geothermal Resources dated April 20, 1988 but
effective
May 1, 1988 from Coso Geothermal Company to Coso Energy Developers.
10.41 Geothermal Resources Lease, Serial No. CA-11383, by and between the
United States of America, acting through the Bureau of Land
Management, and the LADWP, effective as of January 1, 1988; as
assigned by Lease Assignment Agreement by and between LADWP and Coso
Land Company , dated September 10, 1997; as assigned by Assignment of
Record Title Interest in Lease for Oil and Gas or Geothermal
Resources, by and between the United States of America, acting through
the Bureau of Land Management, and Coso Land Company, effective
January 1, 1998; and as extended by extension of primary term of CACA-
11383 to September 23, 2004.
II-4
Exhibit
Number Description
------- -----------
10.42 Geothermal Resources Lease, Serial No. CA-11384, by and between the
United States of America, acting through the Bureau of Land
Management, and the LADWP, effective as of February 1, 1982; as
assigned by Lease Assignment Agreement by and between LADWP and Coso
Land Company, dated September 10, 1997; as assigned by Assignment of
Record Title Interest in a Lease for Oil and Gas or Geothermal
Resources (CACA-11384), by and between the United States of America,
acting through the Bureau of Land Management, and Coso Land Company,
effective as of January 1, 1998; and as extended by extension of
primary term of CACA-11385 to December 24, 2002.
10.43 Geothermal Resources Lease, Serial No. CA-11385, by and between the
United States of America, acting through the Bureau of Land
Management, and the LADWP, effective as of February 1, 1982; as
assigned by Lease Assignment Agreement by and between LADWP and Coso
Land Company, dated September 10, 1997; as assigned by Assignment of
Record Title Interest in a Lease for Oil and Gas or Geothermal
Resources (CACA-11385) by and between the United States of America,
acting through the Bureau of Land Management, and Coso Land Company,
effective as of January 1, 1998; and as extended by extension of
primary term of CACA-11385 to December 24, 2002.
10.44 License for Electric Power Plant Site Utilizing Geothermal Resources
between the United States of America, Licensor, through the Bureau of
Land Management, and Coso Energy Developers, Licensee, Serial No. CACA
22512, dated March 8, 1989 (expires 3/8/19).
10.45 License for Electric Power Plant Site Utilizing Geothermal Resources
between the United States of America, acting through the Bureau of
Land Management, and Coso Energy Developers, Licensee, Serial No.
25690, dated 12/29/1989 (expires 12/28/19).
10.46 Right of Way CA-18885 by and between the United States of America,
acting through the Bureau of Land Management, and California Energy
Company, Inc., dated May 7, 1986 (telephone cable) (expires 5/7/16).
10.47 Right of Way CA-13510 by and between the United States of America,
acting through the Bureau of Land Management, and California Energy
Company, Inc., dated April 12, 1984 (Coso office site) (expires
4/12/14).
10.48 Agreement of Transfer and Assignment (Navy I Transmission Line), dated
July 14, 1987, among China Lake Joint Venture and Coso Finance
Partners.
10.49 Agreement of Transfer and Assignment (Navy II Transmission Line),
dated July 31, 1989, among Coso Power Developers and Coso Transmission
Line Partners.
10.50 Agreement of Transfer and Assignment (BLM Transmission Line), dated
July 31, 1989, among Coso Energy Developers and Coso Transmission Line
Partners.
10.51 Agreement Regarding Overriding Royalty (CLC Royalty), dated May 5,
1988, between Coso Energy Developers and Coso Land Company.
10.52 Coso Geothermal Exchange Agreement, dated January 11, 1994, by and
among Coso Finance Partners, Coso Energy Developers, Coso Power
Developers, and California Energy Company, Inc.
10.53 Amendment to Coso Geothermal Exchange Agreement, dated April 12, 1995,
by and among Coso Finance Partners, Coso Energy Developers, Coso Power
Developers, and California Energy Company, Inc.
10.54 Reserved.
10.55 Operation and Maintenance Agreement (Navy I Project), dated May 28,
1999, by and among FPL Energy Operating Services, Inc. and Coso
Operating Company, LLC and New CLOC Company, LLC.
II-5
Exhibit
Number Description
------- -----------
10.56 Operation and Maintenance Agreement (BLM Project), dated May 28, 1999,
by and among FPL Energy Operating Services, Inc. and Coso Operating
Company, LLC and New CHIP Company, LLC.
10.57 Operation and Maintenance Agreement (Navy II Project), dated May 28,
1999, by and among FPL Energy Operating Services, Inc. and Coso
Operating Company, LLC and New CTC Company, LLC.
10.58 Field Operation and Maintenance Agreement (Navy I), dated February 25,
1999, between Coso Operating Company, LLC and New CLOC Company, LLC.
10.59 Field Operations and Maintenance Agreement (Navy II), dated February
25, 1999, between Coso Operating Company, LLC and New CTC Company,
LLC.
10.60 Field Operations and Maintenance Agreement (BLM), dated February 25,
1999, between Coso Operating Company, LLC and New CHIP Company, LLC.
10.61 Purchase Agreement, dated as of January 16, 1999, by and among
Caithness Energy, L.L.C., Caithness Acquisition Company, LLC, and
California Energy Company, Inc.
10.62 Agreement Concerning Consideration, dated as of February 25, 1999, by
and among Caithness Energy, L.L.C., Caithness Acquisition Company,
L.L.C., New CLOC Company, LLC, New CHIP Company, LLC, New CTC Company,
LLC, and CalEnergy Company, Inc.
10.63 Future Revenue Agreement, dated February 25, 1999, by and between
Caithness Energy, L.L.C., Caithness Acquisition Company, LLC, New CTC
Company, LLC, New CLOC Company, LLC, New CHIP Company, LLC, Coso
Finance Partners, Coso Energy Developers, Coso Power Developers, and
California Energy Company, Inc.
10.64 Acknowledgment and Agreement--Release, dated January 16, 1999,
executed by Caithness Resources, Inc., Caithness Corporation,
Caithness Power, L.L.C., James Bishop Sr.,and Caithness CEA
Geothermal, L.P. (appended to Exhibit 10.61).
10.65 Acknowledgment and Agreement--Indemnity, dated May 28, 1999, executed
by Coso Finance Partners, New CLOC Company, LLC, ESCA, LLC, Coso
Energy Developers, New CHIP Company, LLC, Caithness Coso Holdings,
LLC, Coso Power Developers, New CTC Company, LLC, and Caithness Navy
II Group, LLC.
10.66 Acknowledgment and Agreement--Release, dated May 28, 1999, executed by
Coso Finance Partners, New CLOC Company, LLC, ESCA, LLC, Coso Energy
Developers, New CHIP Company, LLC, Caithness Coso Holdings, LLC, Coso
Power Developers, New CTC Company, LLC, and Caithness Navy II Group,
LLC.
10.67 Acknowledgment and Agreement--Indemnity, dated January 16, 1999,
executed by Caithness Resources, Inc., Caithness Corporation,
Caithness Power, L.L.C., China Lake Operating Company, Coso Technology
Corporation and Coso Hotsprings Intermountain Power (appended to
Exhibit 10.61).
10.68 Power Purchase Agreement (modified Standard Offer No.4) (Navy I),
dated as of June 4, 1984, as amended, by and between Southern
California Edison Company and Coso Finance Partners (as assignee of
China Lake Joint Venture).
10.69 Power Purchase Agreement (modified Standard Offer No.4) (BLM), dated
as of February 1, 1985, by and between Southern California Edison
Company and Coso Energy Developers (as assignee of China Lake Joint
Venture).
10.70 Power Purchase Agreement (modified Standard Offer No.4) (Navy II),
dated as of February 1, 1985, by and between Southern California
Edison Company and Coso Power Developers (as assignee of China Lake
Joint Venture).
10.71 Reserved.
II-6
Exhibit
Number Description
------- -----------
10.72 Interconnection and Integration Facilities Agreement (BLM project),
dated December 15, 1988, between Southern California Edison Company
and Coso Energy Developers (as assignee of China Lake Joint Venture).
10.73 Interconnection and Integration Facilities Agreement (Navy II
project), dated December 15, 1988, between Southern California Edison
Company and Coso Power Developers (as assignee of China Lake Joint
Venture).
10.74 Operating Fee Subordination Agreement (Navy I), dated as of May 28,
1999, by and among FPL Energy Operating Services, Inc., and U.S. Bank
Trust National Association, as collateral agent.
10.75 Operating Fee Subordination Agreement (BLM), dated as of May 28, 1999,
by and among FPL Energy Operating Services, Inc., and U.S. Bank Trust
National Association, as collateral agent.
10.76 Operating Fee Subordination Agreement (Navy II), dated as of May 28,
1999, by and among FPL Energy Operating Services, Inc., and U.S. Bank
Trust National Association, as collateral agent.
10.77 Operating Fee Subordination Agreement (Navy I), dated as of May 28,
1999, by and among Coso Operating Company, LLC, and U.S. Bank Trust
National Association, as collateral agent.
10.78 Operating Fee Subordination Agreement (BLM), dated as of May 28, 1999,
by and among Coso Operating Company, LLC, and U.S. Bank Trust National
Association, as collateral agent.
10.79 Operating Fee Subordination Agreement (Navy II), dated as of May 28,
1999, by and among Coso Operating Company, LLC, and U.S. Bank Trust
National Association, as collateral agent.
10.80 Management Fee Subordination Agreement (Navy I), dated as of May 28,
1999, by and among ESCA, LLC, New CLOC Company, LLC, Coso Finance
Partners, and U.S. Bank Trust National Association, as collateral
agent.
10.81 Management Fee Subordination Agreement (BLM), dated as of May 28,
1999, by and among Caithness Coso Holdings, LLC, New CHIP Company,
LLC, Coso Energy Developers, and U.S. Bank Trust National Association,
as collateral agent.
10.82 Management Fee Subordination Agreement (Navy II), dated as of May 28,
1999, by and among Caithness Navy II Group, LLC, New CTC Company, LLC,
Coso Power Developers, and U.S. Bank Trust National Association, as
collateral agent.
10.83 Cotenancy Agreement, dated as of May 28, 1999, by and among Coso
Finance Partners, Coso Energy Developers, and Coso Power Developers.
10.84 Acquisition Agreement, dated as of May 28, 1999, among Coso Land
Company, Coso Finance Partners, Coso Energy Developers, Coso Power
Developers, and Coso Operating Company, LLC.
10.85 Assignment and Assumption Agreement, dated as of May 28, 1999, by and
among MidAmerican Energy Holdings Company as successor-in-interest to
Cal Energy Company, Inc., Coso Energy Developers, Coso Power
Developers and Coso Finance Partners.
12.1 Statement regarding computation of Coso Finance Partners ratio of
earnings to fixed charges.
12.2 Statement regarding computation of Coso Energy Developers ratio of
earnings to fixed charges.
12.3 Statement regarding computation of Coso Power Developers ratio of
earnings to fixed charges.
21.1 Subsidiaries of Caithness Coso Funding Corp., Coso Finance Partners,
Coso Energy Developers, and Coso Power Developers.
23.1 Consent of KPMG LLP, Independent Auditors.
23.2 Consent of PricewaterhouseCoopers LLP, Independent Auditors.
23.3 Consent of Sandwell Engineering Inc.
23.4 Consent of Henwood Energy Services, Inc.
II-7
Exhibit
Number Description
------- -----------
23.5 Consent of GeothermEx, Inc.
23.6 Consent of Riordan & McKinzie, A Professional Law Corporation
(included in Exhibit 5.1).
23.7 Consent of Reed Smith Shaw & McClay LLP (included in Exhibit 5.2).
24.1 Powers of Attorney (included on pages II-9, II-11, II-13 and II-15).
25.1 Form T-1 Statement of Eligibility and Qualification of U.S. Bank Trust
National Association as Trustee.
27.1 Financial Data Schedule--Caithness Coso Funding Corp.
27.2 Financial Data Schedule--Coso Finance Partners.
27.3 Financial Data Schedule--Coso Energy Developers.
27.4 Financial Data Schedule--Coso Power Developers.
99.1* Form of Letter of Transmittal.
99.2* Form of Notice of Guaranteed Delivery.
99.3* Letter to Brokers, Dealers, Commercial Banks, Trust Companies and
Other Nominees.
99.4* Letter to Clients.
- ---------------------
* To be filed by amendment.
Item 22. Undertakings
The undersigned Registrant hereby undertakes as follows:
1. That, insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors, officers and
controlling persons of the registrant pursuant to the foregoing provisions,
or otherwise, the registrant has been advised that in the opinion of the
Securities and Exchange Commission such indemnification is against public
policy as expressed in the Act, and is, therefore, unenforceable. In the
event that a claim for indemnification against such liabilities (other than
the payment by the registrant of expenses incurred by the payment of a
director, officer, or controlling person of the registrant in the successful
defense of any action, suit or proceeding) is asserted by such director,
officer, or controlling person in connection with the securities being
registered, the registrant will, unless in the opinion of its counsel the
matter has been settled by controlling precedent, submit to a court of
appropriate jurisdiction the question whether such indemnification by it is
against public policy as expressed in the Act and will be governed by the
final adjudication of such issue.
2. To respond to requests for information that is incorporated by reference
into the prospectus pursuant to Item 4, 10(b), 11, or 13 of this form,
within one business day of receipt of such requests, and to send the
incorporated documents by first class mail or other equally prompt means.
This includes information contained in documents filed subsequent to the
effective date of the registration statement through the date of responding
to the request.
3. To supply by means of a post-effective amendment all information concerning
a transaction, and the company being acquired involved therein, that was not
the subject of and included in the registration statement when it became
effective.
II-8
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
undersigned Registrant has duly caused this Registration Statement on Form S-4
to be signed on behalf of the undersigned thereunto duly authorized, in the
City of New York, on July 27, 1999.
Caithness Coso Funding Corp.,
a Delaware corporation
/s/ James D. Bishop, Sr.
By: _________________________________
James D. Bishop, Sr.
Chairman and Chief Executive
Officer
POWER OF ATTORNEY
Each of the undersigned hereby constitutes and appoints Leslie J. Gelber,
James D. Bishop, Jr. and Christopher T. McCallion as his/her true and lawful
attorneys-in-fact and agents, jointly and severally, with full power of
substitution and re-substitution, for and in his stead, in any and all
capacities, to sign on his behalf this registration statement on Form S-4 (the
"Registration Statement") and to execute any amendments thereto (including
post-effective amendments) that may be required in connection with the
Registration Statement, and to file the same, with all exhibits thereto, and
all other documents in connection therewith, with the Securities and Exchange
Commission and granting unto said attorneys-in-fact and agents, jointly and
severally, the full power and authority to do and perform each and every act
and thing necessary or advisable to all intents and purposes as he might or
could do in person, hereby ratifying and confirming all that said attorneys-in-
fact and agents, jointly and severally, or his substitute or substitutes, may
lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, this registration
statement has been signed by the following persons in the capacities and on the
dates indicated.
Signature Title Date
--------- ----- ----
/s/ James D. Bishop, Sr. Director, Chairman and Chief July 27, 1999
____________________________________ Executive Officer
James D. Bishop, Sr. (Principal Executive
Officer)
/s/ Christopher T. McCallion Director, Executive Vice July 27, 1999
____________________________________ President and Chief
Christopher T. McCallion Financial Officer
(Principal Accounting
Officer)
/s/ Leslie J. Gelber Director, President and July 27, 1999
____________________________________ Chief Operating Officer
Leslie J. Gelber
/s/ James D. Bishop, Jr. Director July 27, 1999
____________________________________
James D. Bishop, Jr.
II-9
Signature Title Date
--------- ----- ----
/s/ Larry K. Carpenter Director July 27, 1999
____________________________________
Larry K. Carpenter
/s/ James C. Sullivan Director July 27, 1999
____________________________________
James C. Sullivan
/s/ Mark A. Ferrucci Director July 27, 1999
____________________________________
Mark A. Ferrucci
II-10
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
undersigned Registrant has duly caused this Registration Statement on Form S-4
to be signed on behalf of the undersigned thereunto duly authorized, in the
City of New York, July 27, 1999.
Coso Finance Partners,
a California general partnership
By: New CLOC Company, LLC,
its Managing General Partner
/s/ Christopher T.
McCallion
By: ______________________________
Christopher T. McCallion
Executive Vice President
POWER OF ATTORNEY
Each of the undersigned hereby constitutes and appoints Leslie J. Gelber,
James D. Bishop, Jr. and Christopher T. McCallion as his/her true and lawful
attorneys-in-fact and agents, jointly and severally, with full power of
substitution and re-substitution, for and in his stead, in any and all
capacities, to sign on his behalf this registration statement on Form S-4 (the
"Registration Statement") and to execute any amendments thereto (including
post-effective amendments) that may be required in connection with the
Registration Statement, and to file the same, with all exhibits thereto, and
all other documents in connection therewith, with the Securities and Exchange
Commission and granting unto said attorneys-in-fact and agents, jointly and
severally, the full power and authority to do and perform each and every act
and thing necessary or advisable to all intents and purposes as he might or
could do in person, hereby ratifying and confirming all that said attorneys-in-
fact and agents, jointly and severally, or his substitute or substitutes, may
lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, this registration
statement has been signed by the following persons in the capacities and on the
dates indicated.
Signature Title Date
--------- ----- ----
/s/ James D. Bishop, Sr. Chief Executive Officer of July 27, 1999
____________________________________ New CLOC Company, LLC, as
James D. Bishop, Sr. Managing General Partner of
Registrant (Principal
Executive Officer);
Director of Caithness
Acquisition Company, LLC,
as Manager of New CLOC
Company, LLC, as Managing
General Partner of
Registrant
II-11
Signature Title Date
--------- ----- ----
/s/ Christopher T. McCallion Executive Vice President and July 27, 1999
____________________________________ Chief Financial Officer of
Christopher T. McCallion New CLOC Company, LLC, as
Managing General Partner of
Registrant (Principal
Financial Officer and
Principal Accounting
Officer); Director of
Caithness Acquisition
Company, LLC, as Manager of
New CLOC Company, LLC, as
Managing General Partner of
Registrant
/s/ Leslie Gelber President and Chief July 27, 1999
____________________________________ Operating Officer of New
Leslie Gelber CLOC Company, LLC, as
Managing General Partner of
Registrant; Director of
Caithness Acquisition
Company, LLC, as Manager of
New CLOC Company, LLC, as
Managing General Partner of
Registrant
/s/ James D. Bishop, Jr. Director of Caithness July 27, 1999
____________________________________ Acquisition Company, LLC,
James D. Bishop, Jr. as Manager of New CLOC
Company, LLC, as Managing
General Partner of
Registrant
/s/ Larry K. Carpenter Director of Caithness July 27, 1999
____________________________________ Acquisition Company, LLC,
Larry K. Carpenter as Manager of New CLOC
Company, LLC, as Managing
General Partner of
Registrant
/s/ James C. Sullivan Director of Caithness July 27, 1999
____________________________________ Acquisition Company, LLC,
James C. Sullivan as Manager of New CLOC
Company, LLC, as Managing
General Partner of
Registrant
/s/ Mark A. Ferrucci Independent Manager of New July 27, 1999
____________________________________ CLOC Company, LLC, as
Mark A. Ferrucci Managing General Partner of
Registrant
II-12
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
undersigned Registrant has duly caused this Registration Statement on Form S-4
to be signed on behalf of the undersigned thereunto duly authorized, in the
City of New York, on July 27, 1999.
Coso Energy Developers,
a California general partnership
By: New CHIP Company, LLC,
its Managing General Partner
/s/ Christopher T.
McCallion
By: ______________________________
Christopher T. McCallion
Executive Vice President
POWER OF ATTORNEY
Each of the undersigned hereby constitutes and appoints Leslie J. Gelber,
James D. Bishop, Jr. and Christopher T. McCallion as his/her true and lawful
attorneys-in-fact and agents, jointly and severally, with full power of
substitution and re-substitution, for and in his stead, in any and all
capacities, to sign on his behalf this registration statement on Form S-4 (the
"Registration Statement") and to execute any amendments thereto (including
post-effective amendments) that may be required in connection with the
Registration Statement, and to file the same, with all exhibits thereto, and
all other documents in connection therewith, with the Securities and Exchange
Commission and granting unto said attorneys-in-fact and agents, jointly and
severally, the full power and authority to do and perform each and every act
and thing necessary or advisable to all intents and purposes as he might or
could do in person, hereby ratifying and confirming all that said attorneys-in-
fact and agents, jointly and severally, or his substitute or substitutes, may
lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, this registration
statement has been signed by the following persons in the capacities and on the
dates indicated.
Signature Title Date
--------- ----- ----
/s/ James D. Bishop, Sr. Chief Executive Officer of July 27, 1999
____________________________________ New CHIP Company, LLC, as
James D. Bishop, Sr. Managing General Partner of
Registrant (Principal
Executive Officer);
Director of Caithness
Acquisition Company, LLC,
as Manager of New CHIP
Company, LLC, as Managing
General Partner of
Registrant
II-13
Signature Title Date
--------- ----- ----
/s/ Christopher T. McCallion Executive Vice President and July 27, 1999
____________________________________ Chief Financial Officer of
Christopher T. McCallion New CHIP Company, LLC, as
Managing General Partner of
Registrant (Principal
Financial Officer and
Principal Accounting
Officer); Director of
Caithness Acquisition
Company, LLC, as Manager of
New CHIP Company, LLC, as
Managing General Partner of
Registrant
/s/ Leslie Gelber President and Chief July 27, 1999
____________________________________ Operating Officer of New
Leslie Gelber CHIP Company, LLC, as
Managing General Partner of
Registrant; Director of
Caithness Acquisition
Company, LLC, as Manager of
New CHIP Company, LLC, as
Managing General Partner of
Registrant
/s/ James D. Bishop, Jr. Director of Caithness July 27, 1999
____________________________________ Acquisition Company, LLC,
James D. Bishop, Jr. as Manager of New CHIP
Company, LLC, as Managing
General Partner of
Registrant
/s/ Larry K. Carpenter Director of Caithness July 27, 1999
____________________________________ Acquisition Company, LLC,
Larry K. Carpenter as Manager of New CHIP
Company, LLC, as Managing
General Partner of
Registrant
/s/ James C. Sullivan Director of Caithness July 27, 1999
____________________________________ Acquisition Company, LLC,
James C. Sullivan as Manager of New CHIP
Company, LLC, as Managing
General Partner of
Registrant
/s/ Mark A. Ferrucci Independent Manager of New July 27, 1999
____________________________________ CHIP Company, LLC, as
Mark A. Ferrucci Managing General Partner of
Registrant
II-14
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
undersigned Registrant has duly caused this Registration Statement on Form S-4
to be signed on behalf of the undersigned thereunto duly authorized, in the
City of New York, on July 27, 1999.
Coso Power Developers,
a California general partnership
By: New CTC Company, LLC,
its Managing General Partner
/s/ Christopher T.
McCallion
By: ______________________________
Christopher T. McCallion
Executive Vice President
POWER OF ATTORNEY
Each of the undersigned hereby constitutes and appoints Leslie J. Gelber,
James D. Bishop, Jr. and Christopher T. McCallion as his/her true and lawful
attorneys-in-fact and agents, jointly and severally, with full power of
substitution and re-substitution, for and in his stead, in any and all
capacities, to sign on his behalf this registration statement on Form S-4 (the
"Registration Statement") and to execute any amendments thereto (including
post-effective amendments) that may be required in connection with the
Registration Statement, and to file the same, with all exhibits thereto, and
all other documents in connection therewith, with the Securities and Exchange
Commission and granting unto said attorneys-in-fact and agents, jointly and
severally, the full power and authority to do and perform each and every act
and thing necessary or advisable to all intents and purposes as he might or
could do in person, hereby ratifying and confirming all that said attorneys-in-
fact and agents, jointly and severally, or his substitute or substitutes, may
lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, this registration
statement has been signed by the following persons in the capacities and on the
dates indicated.
Signature Title Date
--------- ----- ----
/s/ James D. Bishop, Sr. Chief Executive Officer of July 27, 1999
____________________________________ New CTC Company, LLC, as
James D. Bishop, Sr. Managing General Partner of
Registrant (Principal
Executive Officer);
Director of Caithness
Acquisition Company, LLC,
as Manager of New CTC
Company, LLC, as Managing
General Partner of
Registrant
II-15
Signature Title Date
--------- ----- ----
/s/ Christopher T. McCallion Executive Vice President and July 27, 1999
____________________________________ Chief Financial Officer of
Christopher T. McCallion New CTC Company, LLC, as
Managing General Partner of
Registrant ( Principal
Financial Officer and
Principal Accounting
Officer); Director of
Caithness Acquisition
Company, LLC, as Manager of
New CTC Company, LLC, as
Managing General Partner of
Registrant
/s/ Leslie Gelber President and Chief July 27, 1999
____________________________________ Operating Officer of New
Leslie Gelber CTC Company, LLC, as
Managing General Partner;
Director of Caithness
Acquisition Company, LLC,
as Manager of New CTC
Company, LLC, as Managing
General Partner of
Registrant
/s/ James D. Bishop, Jr. Director of Caithness July 27, 1999
____________________________________ Acquisition Company, LLC,
James D. Bishop, Jr. as Manager of New CTC
Company, LLC, as Managing
General Partner of
Registrant
/s/ Larry K. Carpenter Director of Caithness July 27, 1999
____________________________________ Acquisition Company, LLC,
Larry K. Carpenter as Manager of New CTC
Company, LLC, as Managing
General Partner of
Registrant
/s/ James C. Sullivan Director of Caithness July 27, 1999
____________________________________ Acquisition Company, LLC,
James C. Sullivan as Manager of New CTC
Company, LLC, as Managing
General Partner of
Registrant
/s/ Mark A. Ferrucci Independent Manager of New July 27, 1999
____________________________________ CTC Company, LLC, as
Mark A. Ferrucci Managing General Partner of
Registrant
II-16
INDEX TO EXHIBITS
Exhibit
Number Description
------- -----------
3.1 Certificate of Incorporation of Caithness Coso Funding Corp.
3.2 Bylaws of Caithness Coso Funding Corp.
3.3* Third Amended and Restated Partnership Agreement of Coso Finance
Partners, dated as of May 28, 1999.
3.4* Third Amended and Restated Partnership Agreement of Coso Energy
Developers, dated as of May 28, 1999.
3.5* Third Amended and Restated Partnership Agreement of Coso Power
Developers, dated as of May 28, 1999.
4.1 Indenture, dated as of May 28, 1999, among Caithness Coso Funding
Corp., Coso Finance Partners, Coso Energy Developers, Coso Power
Developers, and U.S. Bank Trust National Association as trustee and as
collateral agent.
4.2 Specimen Series B notes (included in Exhibit 4.1).
4.3 Notation of Guarantee, dated as of May 28, 1999, of Coso Finance
Partners.
4.4 Notation of Guarantee, dated as of May 28, 1999, of Coso Energy
Developers.
4.5 Notation of Guarantee, dated as of May 28, 1999, of Coso Power
Developers.
4.6 Registration Rights Agreement, dated as of May 28, 1999, by and among
Caithness Coso Funding Corp., Coso Finance Partners, Coso Energy
Developers, Coso Power Developers, and Donaldson, Lufkin & Jenrette
Securities Corporation.
5.1* Opinion of Riordan & McKinzie, A Professional Law Corporation.
5.2* Opinion of Reed Smith Shaw & McClay LLP.
10.1 Deposit and Disbursement Agreement, dated as of May 28, 1999, among
Caithness Coso Funding Corp., Coso Finance Partners, Coso Energy
Developers, Coso Power Developers, and U.S. Bank Trust National
Association, as collateral agent, as trustee, and as depositary.
10.2 Credit Agreement, dated as of May 28, 1999, between Caithness Coso
Funding Corp. and Coso Finance Partners.
10.3 Promissory Note due 2001 of Coso Finance Partners in favor of
Caithness Coso Funding Corp.
10.4 Promissory Note due 2009 of Coso Finance Partners in favor of
Caithness Coso Funding Corp.
10.5 Credit Agreement, dated as of May 28, 1999, between Caithness Coso
Funding Corp. and Coso Energy Developers.
10.6 Promissory Note due 2001 of Coso Energy Developers in favor of
Caithness Coso Funding Corp.
10.7 Promissory Note due 2009 of Coso Energy Developers in favor of
Caithness Coso Funding Corp.
10.8 Credit Agreement, dated as of May 28, 1999, between Caithness Coso
Funding Corp. and Coso Power Developers.
10.9 Promissory Note due 2001 of Coso Power Developers in favor of
Caithness Coso Funding Corp.
10.10 Promissory Note due 2009 of Coso Power Developers in favor of
Caithness Coso Funding Corp.
10.11 Purchase Agreement, dated as of May 21, 1999, by and among Caithness
Coso Funding Corp., as issuer, Coso Finance Partners, Coso Energy
Developers and Coso Power Developers, as guarantors, and Donaldson,
Lufkin & Jenrette Securities Corporation, as initial purchaser.
Exhibit
Number Description
------- -----------
10.12 Security Agreement, dated as of May 28, 1999, executed by and among
Caithness Coso Funding Corp. in favor of U.S. Bank Trust National
Association, as collateral agent.
10.13 Security Agreement, dated as of May 28, 1999, executed by and among
Coso Finance Partners in favor of U.S. Bank Trust National
Association, as collateral agent.
10.14 Security Agreement, dated as of May 28, 1999, executed by Coso Energy
Developers in favor of U.S. Bank Trust National Association, as
collateral agent.
10.15 Security Agreement, dated as of May 28, 1999, executed by Coso Power
Developers in favor of U.S. Bank Trust National Association, as
collateral agent.
10.16 Reserved.
10.17 Reserved.
10.18* Security Agreement (Navy I project permits), dated as of May 28, 1999,
executed by Coso Operating Company LLC in favor of U.S. Bank Trust
National Association, as collateral agent.
10.19 Security Agreement (BLM project permits), dated as of May 28, 1999,
executed by Coso Operating Company LLC in favor of U.S. Bank Trust
National Association, as collateral agent.
10.20 Security Agreement (Navy II project permits), dated as of May 28,
1999, executed by Coso Operating Company LLC in favor of U.S. Bank
Trust National Association, as collateral agent.
10.21 Security Agreement (Navy I project permits), dated as of May 28, 1999,
executed by FPL Energy Operating Services, Inc., in favor of U.S. Bank
Trust National Association, as collateral agent.
10.22 Security Agreement (BLM project permits), dated as of May 28, 1999,
executed by FPL Energy Operating Services, Inc., in favor of U.S. Bank
Trust National Association, as collateral agent.
10.23 Security Agreement (Navy II project permits), dated as of May 28,
1999, executed by FPL Energy Operating Services, Inc., in favor of
U.S. Bank Trust National Association, as collateral agent.
10.24 Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Finance Partners
in favor of U.S. Bank Trust National Association, as trustee, and as
beneficiary.
10.25 Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Energy
Developers in favor of U.S. Bank Trust National Association, as
trustee, and as beneficiary.
10.26 Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Power Developers
in favor of U.S. Bank Trust National Association, as trustee, and as
beneficiary.
10.27 Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Transmission
Line Partners in favor of U.S. Bank Trust National Association, as
trustee, and as beneficiary.
10.28 Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by China Lake Joint
Venture in favor of U.S. Bank Trust National Association, as trustee,
and as beneficiary.
10.29 Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Land Company in
favor of U.S. Bank Trust National Association, as trustee, and as
beneficiary.
Exhibit
Number Description
------- -----------
10.30 Stock Pledge Agreement, dated as of May 28, 1999, by Coso Finance
Partners, Coso Energy Developers and Coso Power Developers in favor of
U.S. Bank Trust National Association, as collateral agent.
10.31 Partnership Interest Pledge Agreement (Navy I), dated as of May 28,
1999, by ESCA, LLC and New CLOC Company, LLC, in favor of U.S. Bank
Trust National Association, as collateral agent.
10.32 Partnership Interest Pledge Agreement (BLM), dated as of May 28, 1999,
by Caithness Coso Holdings, LLC and New CHIP Company, LLC, in favor of
U.S. Bank Trust National Association, as collateral agent.
10.33 Partnership Interest Pledge Agreement (Navy II), dated as of May 28,
1999, by Caithness Navy II Group, LLC and New CTC Company, LLC, in
favor of U.S. Bank Trust National Association, as collateral agent.
10.34 Partnership Interest Pledge Agreement (CTLP), dated as of May 28,
1999, by Coso Energy Developers and Coso Power Developers, in favor of
U.S. Bank Trust National Association, as collateral agent.
10.35 Partnership Interest Pledge Agreement (CLJV), dated as of May 28,
1999, by Caithness Acquisition Company, LLC and Caithness Geothermal
1980 Ltd., L.P., in favor of U.S. Bank Trust National Association, as
collateral agent.
10.36 Partnership Interest Pledge Agreement (CLC), dated as of May 28, 1999,
by Caithness Acquisition Company, LLC and Caithness Geothermal 1980
Ltd., L.P., in favor of U.S. Bank Trust National Association, as
collateral agent.
10.37 Promissory Notes Security Agreement, dated as of May 28, 1999, by
Caithness Coso Funding Corp., in favor of U.S. Bank Trust National
Association, as collateral agent.
10.38 Original Service Contract N62474-79-C-5382, dated December 6, 1979,
between U.S. Naval Weapons Center and California Energy Company, Inc.,
Contractor (the "Navy Contract"), including all amendments thereto.
10.39 Escrow Agreement, dated December 16, 1992, as amended, by and among
Coso Finance Partners, Bank of America and the Navy.
10.40 Offer to Lease and Lease for Geothermal Resources, Serial No. 11402,
dated April 29, 1985 but effective May 1, 1985, from the United States
of America, acting through the Bureau of Land Management, to
California Energy Company, Inc.; as assigned by Assignment Affecting
Record Title to Geothermal Resources Lease, dated June 24, 1985, but
effective July 1, 1985 from California Energy Company, Inc. to Coso
Land Company; as assigned by Assignment of Record Title Interest in a
Lease for Oil and Gas or Geothermal Resources, dated April 20, 1988,
but effective May 1, 1988 from Coso Land Company to Coso Geothermal
Company; as assigned by Assignment of Record Title Interest in a Lease
for Oil and Gas or Geothermal Resources dated April 20, 1988 but
effective
May 1, 1988 from Coso Geothermal Company to Coso Energy Developers.
10.41 Geothermal Resources Lease, Serial No. CA-11383, by and between the
United States of America, acting through the Bureau of Land
Management, and the LADWP, effective as of January 1, 1988; as
assigned by Lease Assignment Agreement by and between LADWP and Coso
Land Company , dated September 10, 1997; as assigned by Assignment of
Record Title Interest in Lease for Oil and Gas or Geothermal
Resources, by and between the United States of America, acting through
the Bureau of Land Management, and Coso Land Company, effective
January 1, 1998; and as extended by extension of primary term of CACA-
11383 to September 23, 2004.
Exhibit
Number Description
------- -----------
10.42 Geothermal Resources Lease, Serial No. CA-11384, by and between the
United States of America, acting through the Bureau of Land
Management, and the LADWP, effective as of February 1, 1982; as
assigned by Lease Assignment Agreement by and between LADWP and Coso
Land Company, dated September 10, 1997; as assigned by Assignment of
Record Title Interest in a Lease for Oil and Gas or Geothermal
Resources (CACA-11384), by and between the United States of America,
acting through the Bureau of Land Management, and Coso Land Company,
effective as of January 1, 1998; and as extended by extension of
primary term of CACA-11385 to December 24, 2002.
10.43 Geothermal Resources Lease, Serial No. CA-11385, by and between the
United States of America, acting through the Bureau of Land
Management, and the LADWP, effective as of February 1, 1982; as
assigned by Lease Assignment Agreement by and between LADWP and Coso
Land Company, dated September 10, 1997; as assigned by Assignment of
Record Title Interest in a Lease for Oil and Gas or Geothermal
Resources (CACA-11385) by and between the United States of America,
acting through the Bureau of Land Management, and Coso Land Company,
effective as of January 1, 1998; and as extended by extension of
primary term of CACA-11385 to December 24, 2002.
10.44 License for Electric Power Plant Site Utilizing Geothermal Resources
between the United States of America, Licensor, through the Bureau of
Land Management, and Coso Energy Developers, Licensee, Serial No. CACA
22512, dated March 8, 1989 (expires 3/8/19).
10.45 License for Electric Power Plant Site Utilizing Geothermal Resources
between the United States of America, acting through the Bureau of
Land Management, and Coso Energy Developers, Licensee, Serial No.
25690, dated 12/29/1989 (expires 12/28/19).
10.46 Right of Way CA-18885 by and between the United States of America,
acting through the Bureau of Land Management, and California Energy
Company, Inc., dated May 7, 1986 (telephone cable) (expires 5/7/16).
10.47 Right of Way CA-13510 by and between the United States of America,
acting through the Bureau of Land Management, and California Energy
Company, Inc., dated April 12, 1984 (Coso office site) (expires
4/12/14).
10.48 Agreement of Transfer and Assignment (Navy I Transmission Line), dated
July 14, 1987, among China Lake Joint Venture and Coso Finance
Partners.
10.49 Agreement of Transfer and Assignment (Navy II Transmission Line),
dated July 31, 1989, among Coso Power Developers and Coso Transmission
Line Partners.
10.50 Agreement of Transfer and Assignment (BLM Transmission Line), dated
July 31, 1989, among Coso Energy Developers and Coso Transmission Line
Partners.
10.51 Agreement Regarding Overriding Royalty (CLC Royalty), dated May 5,
1988, between Coso Energy Developers and Coso Land Company.
10.52 Coso Geothermal Exchange Agreement, dated January 11, 1994, by and
among Coso Finance Partners, Coso Energy Developers, Coso Power
Developers, and California Energy Company, Inc.
10.53 Amendment to Coso Geothermal Exchange Agreement, dated April 12, 1995,
by and among Coso Finance Partners, Coso Energy Developers, Coso Power
Developers, and California Energy Company, Inc.
10.54 Reserved.
10.55 Operation and Maintenance Agreement (Navy I Project), dated May 28,
1999, by and among FPL Energy Operating Services, Inc. and Coso
Operating Company, LLC and New CLOC Company, LLC.
Exhibit
Number Description
------- -----------
10.56 Operation and Maintenance Agreement (BLM Project), dated May 28, 1999,
by and among FPL Energy Operating Services, Inc. and Coso Operating
Company, LLC and New CHIP Company, LLC.
10.57 Operation and Maintenance Agreement (Navy II Project), dated May 28,
1999, by and among FPL Energy Operating Services, Inc. and Coso
Operating Company, LLC and New CTC Company, LLC.
10.58 Field Operation and Maintenance Agreement (Navy I), dated February 25,
1999, between Coso Operating Company, LLC and New CLOC Company, LLC.
10.59 Field Operations and Maintenance Agreement (Navy II), dated February
25, 1999, between Coso Operating Company, LLC and New CTC Company,
LLC.
10.60 Field Operations and Maintenance Agreement (BLM), dated February 25,
1999, between Coso Operating Company, LLC and New CHIP Company, LLC.
10.61 Purchase Agreement, dated as of January 16, 1999, by and among
Caithness Energy, L.L.C., Caithness Acquisition Company, LLC, and
California Energy Company, Inc.
10.62 Agreement Concerning Consideration, dated as of February 25, 1999, by
and among Caithness Energy, L.L.C., Caithness Acquisition Company,
L.L.C., New CLOC Company, LLC, New CHIP Company, LLC, New CTC Company,
LLC, and CalEnergy Company, Inc.
10.63 Future Revenue Agreement, dated February 25, 1999, by and between
Caithness Energy, L.L.C., Caithness Acquisition Company, LLC, New CTC
Company, LLC, New CLOC Company, LLC, New CHIP Company, LLC, Coso
Finance Partners, Coso Energy Developers, Coso Power Developers, and
California Energy Company, Inc.
10.64 Acknowledgment and Agreement--Release, dated January 16, 1999,
executed by Caithness Resources, Inc., Caithness Corporation,
Caithness Power, L.L.C., James Bishop Sr., and Caithness CEA
Geothermal, L.P. (appended to Exhibit 10.61).
10.65 Acknowledgment and Agreement--Indemnity, dated May 28, 1999, executed
by Coso Finance Partners, New CLOC Company, LLC, ESCA, LLC, Coso
Energy Developers, New CHIP Company, LLC, Caithness Coso Holdings,
LLC, Coso Power Developers, New CTC Company, LLC, and Caithness Navy
II Group, LLC.
10.66 Acknowledgment and Agreement--Release, dated May 28, 1999, executed by
Coso Finance Partners, New CLOC Company, LLC, ESCA, LLC, Coso Energy
Developers, New CHIP Company, LLC, Caithness Coso Holdings, LLC, Coso
Power Developers, New CTC Company, LLC, and Caithness Navy II Group,
LLC.
10.67 Acknowledgment and Agreement--Indemnity, dated January 16, 1999,
executed by Caithness Resources, Inc., Caithness Corporation,
Caithness Power, L.L.C., China Lake Operating Company, Coso Technology
Corporation and Coso Hotsprings Intermountain Power (appended to
Exhibit 10.61).
10.68 Power Purchase Agreement (modified Standard Offer No.4) (Navy I),
dated as of June 4, 1984, as amended, by and between Southern
California Edison Company and Coso Finance Partners (as assignee of
China Lake Joint Venture).
10.69 Power Purchase Agreement (modified Standard Offer No.4) (BLM), dated
as of February 1, 1985, by and between Southern California Edison
Company and Coso Energy Developers (as assignee of China Lake Joint
Venture).
10.70 Power Purchase Agreement (modified Standard Offer No.4) (Navy II),
dated as of February 1, 1985, by and between Southern California
Edison Company and Coso Power Developers (as assignee of China Lake
Joint Venture).
10.71 Reserved.
Exhibit
Number Description
------- -----------
10.72 Interconnection and Integration Facilities Agreement (BLM project),
dated December 15, 1988, between Southern California Edison Company
and Coso Energy Developers (as assignee of China Lake Joint Venture).
10.73 Interconnection and Integration Facilities Agreement (Navy II
project), dated December 15, 1988, between Southern California Edison
Company and Coso Power Developers (as assignee of China Lake Joint
Venture).
10.74 Operating Fee Subordination Agreement (Navy I), dated as of May 28,
1999, by and among FPL Energy Operating Services, Inc., and U.S. Bank
Trust National Association, as collateral agent.
10.75 Operating Fee Subordination Agreement (BLM), dated as of May 28, 1999,
by and among FPL Energy Operating Services, Inc., and U.S. Bank Trust
National Association, as collateral agent.
10.76 Operating Fee Subordination Agreement (Navy II), dated as of May 28,
1999, by and among FPL Energy Operating Services, Inc., and U.S. Bank
Trust National Association, as collateral agent.
10.77 Operating Fee Subordination Agreement (Navy I), dated as of May 28,
1999, by and among Coso Operating Company, LLC, and U.S. Bank Trust
National Association, as collateral agent.
10.78 Operating Fee Subordination Agreement (BLM), dated as of May 28, 1999,
by and among Coso Operating Company, LLC, and U.S. Bank Trust National
Association, as collateral agent.
10.79 Operating Fee Subordination Agreement (Navy II), dated as of May 28,
1999, by and among Coso Operating Company, LLC, and U.S. Bank Trust
National Association, as collateral agent.
10.80 Management Fee Subordination Agreement (Navy I), dated as of May 28,
1999, by and among ESCA, LLC, New CLOC Company, LLC, Coso Finance
Partners, and U.S. Bank Trust National Association, as collateral
agent.
10.81 Management Fee Subordination Agreement (BLM), dated as of May 28,
1999, by and among Caithness Coso Holdings, LLC, New CHIP Company,
LLC, Coso Energy Developers, and U.S. Bank Trust National Association,
as collateral agent.
10.82 Management Fee Subordination Agreement (Navy II), dated as of May 28,
1999, by and among Caithness Navy II Group, LLC, New CTC Company, LLC,
Coso Power Developers, and U.S. Bank Trust National Association, as
collateral agent.
10.83 Cotenancy Agreement, dated as of May 28, 1999, by and among Coso
Finance Partners, Coso Energy Developers, and Coso Power Developers.
10.84 Acquisition Agreement, dated as of May 28, 1999, among Coso Land
Company, Coso Finance Partners, Coso Energy Developers, Coso Power
Developers, and Coso Operating Company, LLC.
10.85 Assignment and Assumption Agreement, dated as of May 28, 1999, by and
among MidAmerican Energy Holdings Company as successor-in-interest to
Cal Energy Company, Inc., Coso Energy Developers, Coso Power
Developers and Coso Finance Partners.
12.1 Statement regarding computation of Coso Finance Partners ratio of
earnings to fixed charges.
12.2 Statement regarding computation of Coso Energy Developers ratio of
earnings to fixed charges.
12.3 Statement regarding computation of Coso Power Developers ratio of
earnings to fixed charges.
21.1 Subsidiaries of Caithness Coso Funding Corp., Coso Finance Partners,
Coso Energy Developers, and Coso Power Developers.
23.1 Consent of KPMG LLP, Independent Auditors.
23.2 Consent of PricewaterhouseCoopers LLP, Independent Auditors.
23.3 Consent of Sandwell Engineering Inc.
23.4 Consent of Henwood Energy Services, Inc.
Exhibit
Number Description
------- -----------
23.5 Consent of GeothermEx, Inc.
23.6 Consent of Riordan & McKinzie, A Professional Law Corporation
(included in Exhibit 5.1).
23.7 Consent of Reed Smith Shaw & McClay LLP (included in Exhibit 5.2).
24.1 Powers of Attorney (included on pages II-9, II-11, II-13 and II-15).
25.1 Form T-1 Statement of Eligibility and Qualification of U.S. Bank Trust
National Association as Trustee.
27.1 Financial Data Schedule--Caithness Coso Funding Corp.
27.2 Financial Data Schedule--Coso Finance Partners.
27.3 Financial Data Schedule--Coso Energy Developers.
27.4 Financial Data Schedule--Coso Power Developers.
99.1* Form of Letter of Transmittal.
99.2* Form of Notice of Guaranteed Delivery.
99.3* Letter to Brokers, Dealers, Commercial Banks, Trust Companies and
Other Nominees.
99.4* Letter to Clients.
- ---------------------
* To be filed by amendment.