================================================================================
ORMAT GEOTHERMAL PLANTS
INDEPENDENT TECHNICAL REVIEW
J.O. 1002111
FEBRUARY 8, 2004
Copyright 2003
Stone & Webster Management Consultants, Inc.
Denver, Colorado
================================================================================
TABLE OF CONTENTS
================================================================================
SECTION 1.0 ................................................................. 1
EXECUTIVE SUMMARY ........................................................ 1
1.1 Introduction ................................................... 1
1.2 Conclusions .................................................... 5
SECTION 2.0 ................................................................. 8
FACILITIES DESCRIPTION ................................................... 8
2.1 Mammoth ........................................................ 8
2.2 Ormesa ......................................................... 10
2.3 Brady And Desert Peak .......................................... 12
2.4 Steamboat ...................................................... 14
SECTION 3.0 ................................................................. 16
OPERATIONS AND MAINTENANCE ............................................... 16
3.1 Mammoth ........................................................ 16
3.2 Ormesa ......................................................... 17
3.3 Brady And Desert Peak .......................................... 19
3.4 Steamboat ...................................................... 20
SECTION 4.0 ................................................................. 21
ENVIRONMENTAL ASSESSMENT ................................................. 21
4.1 Mammoth ........................................................ 21
4.2 Ormesa ......................................................... 22
4.3 Brady And Desert Peak .......................................... 24
4.4 Steamboat ...................................................... 26
SECTION 5.0 ................................................................. 28
CONTRACTS AND AGREEMENTS ................................................. 28
5.1 Mammoth ........................................................ 28
5.2 Ormesa ......................................................... 29
5.4 Steamboat ...................................................... 32
5.5 Projects Interconnection Agreements ............................ 35
SECTION 6.0 ................................................................. 37
FINANCIAL PROJECTIONS .................................................... 37
6.1 Revenues ....................................................... 37
6.2 Operating Expenses ............................................. 39
6.3 Major Maintenance And Capital Expenditures ..................... 39
6.4 Sensitivity Analysis ........................................... 39
- --------------------------------------------------------------------------------
Page i
ATTACHMENTS
================================================================================
ATTACHMENT I - DOCUMENTS REVIEWED
ATTACHMENT II - FINANCIAL PROJECTIONS
- --------------------------------------------------------------------------------
Page ii
================================================================================
LEGAL NOTICE
This document was prepared by Stone & Webster Management Consultants, Inc.
(Stone & Webster) solely for the benefit of Lehman Brothers or another
Lehman Brothers entity and its assignees and transferees. Neither Stone &
Webster, nor its parent corporation, or its or their affiliates, nor
Lehman Brothers, nor any person acting in their behalf (a) makes any
warranty, expressed or implied, with respect to the use of any information
or methods disclosed in this document, or (b) assumes any liability with
respect to the use of any information or methods disclosed in this
document.
Any recipient of this document, by their acceptance or use of this
document, releases Stone & Webster, its parent corporation, and its and
their affiliates, and Lehman Brothers and its assignees and transferees
from any liability for direct, indirect, consequential or special loss or
damage whether arising in contract, warranty, express or implied, tort or
otherwise, and irrespective of fault, negligence, and strict liability.
================================================================================
- --------------------------------------------------------------------------------
Page iii
================================================================================
SECTION 1.0
EXECUTIVE SUMMARY
1.1 INTRODUCTION
Ormat Funding Corp. (Ormat) is planning to finance, through a 144A bond
offering, the geothermal plants (Projects) located in Nevada and California
described in this report, some of which will be acquired with the proceeds of
the 144A bond offering. This report has been prepared at the request of Lehman
Brothers, book-running lead manager for the 144A bond offering. The California
Projects included in this financing are Mammoth-Pacific L.P. (Mammoth), which
includes the geothermal plants Mammoth I/II (G1 and G2) and Pacific Lighting
Energy Services I (G3), and Ormesa, LLC (Ormesa), which includes the geothermal
plants OG I, OG IE, OG IH (collectively OG I Units), OG II, GEM 2 and GEM 3. The
Nevada geothermal plants included in this financing are Brady Power Partners'
(BPP) Brady and Desert Peak 1, Steamboat Geothermal LLC's Steamboat 1/1A, and
Steamboat Development Corp.'s Steamboat 2 and 3. The proceeds of the 144A bond
financing will also be used for the construction of the Galena plant, which is
an expansion of the Steamboat Project.
The major Project participants in this transaction are Ormat Funding Corp.,
Southern California Edison (SCE), Sierra Pacific Power Company (SPPC), and the
Imperial Irrigation District (IID).
Ormat Funding Corp. was formed to develop, construct, and acquire, through
certain direct and indirect subsidiaries, and geothermal power projects located
in the United States. Ormat Funding Corp. is wholly owned by Ormat Nevada, Inc.,
a Delaware corporation whose ultimate parent company is Ormat Industries Ltd.
(ORMAT). ORMAT employs over 600 people, and is, or has been, involved in various
aspects of over 700 MW of geothermal power plants.
SCE is wholly-owned by Edison International, but is separate from the other
Edison International companies, which are not regulated by the California Public
Utilities Commission. SCE serves over 4.2 million customers over a 50,000 square
mile area in southern California. SCE is the power off-taker of the energy and
capacity from the Mammoth and Ormesa Projects.
SPPC, together with Nevada Power Company, is part of Sierra Pacific Resources,
an investor-owned holding company. SPPC serves customers in northern Nevada and
northeastern California. Sierra Pacific Resources provides electricity to
960,000 customers and natural gas to over 110,000 customers in the Reno-Sparks
area. SPPC is the power off-taker of the energy and capacity from BPP's,
Steamboat Geothermal LLC's, and Steamboat Development Corp.'s Projects.
IID, a community-owned utility, provides irrigation water and electric power to
the lower southeastern portion of California's desert. IID provides electricity
to over 100,000 customers in Imperial County and parts of Riverside and San
Diego counties. IID also wheels Ormesa's electricity to SCE.
Stone & Webster Management Consultants, Inc. (Stone & Webster) performed an
analysis, technical review, and engineering assessment of the Projects in
accordance with the Agreement dated December 2, 2003, between Stone & Webster
and Ormat Nevada, Inc. in connection with the financing of Ormat's ownership
interests in the Projects and for inclusion in the offering memorandum, or any
registration statement related to such financing. The assessment consisted of a
review of the plants and Project documentation, site visits, discussions with
Project affiliates and other parties, and review of the Financial Projections
dated February 7, 2004.
This report provides a summary of our review and observations of the condition
of the plants, operating and maintenance practices, historical plant
performance, permits and licenses, existing agreements and contracts, and
financial projections. Site visits were conducted by Stone & Webster on November
3 and December 8-10, 2003
Stone & Webster has reviewed the Geothermal Consultant's (GeothermEx) report. In
all instances where we have cited resource characteristics and performance
parameters, we have relied upon the GeothermEx report and have not independently
verified the geothermal fluid properties or reserve bases. The physical
distinction between GeothermEx's scope of work and Stone & Webster's scope of
work as the Independent Engineer can be thought of as follows. GeothermEx's
scope of work addressed the geothermal fluid production and re-injection of
geothermal
- --------------------------------------------------------------------------------
Page 1
EXECUTIVE SUMMARY
================================================================================
fluid back into the ground. The Independent Engineer's scope of work addresses
utilization of the geothermal fluids from the well heads to the power plant, as
well as all power generation equipment.
Plant generating capacity can be expressed in many ways including gross
capacity, net capacity, nameplate capacity, demonstrated operating PPA capacity,
as well as other terms. These capacity ratings are affected by a number of
different variables, such as auxiliary levels, ambient air temperatures,
equipment condition, and contractual requirements. In order to provide
consistency, we have expressed the Projects' generation capacity in terms of
gross MW output using values provided by Ormat.
MAMMOTH
The combined generation capacity of G1, G2, and G3 is 35 MW gross. Ormat owns 50
percent of the Mammoth Project. The Commercial Operation Date (COD), gross
generation capacity, and number of binary units for each plant are provided in
the table below.
PLANT COD GROSS CAPACITY BINARY UNITS
----- ---- -------------- ------------
G1 1985 9 MW 2
G2 1990 13 MW 3
G3 1990 13 MW 3
Mammoth entered into an Amended and Restated Power Purchase Agreement (G1 PPA)
with SCE in December 1986. The G1 PPA was amended in May 1990. G1 can sell
energy and capacity for a term of 30 years, which ends in 2015.
Mammoth entered into a Long Term Power Purchase Agreement (G2 PPA) with SCE in
April 1985 for the purchase and sale of the capacity and net electrical output
of G2. The G2 PPA was amended in October 1989 and December 1989. G2 can sell
energy and capacity for a term of 30 years, which ends in 2020.
Mammoth (as successor to Santa Fe Geothermal, Inc.) entered into a Long Term
Power Purchase Agreement (G3 PPA) with SCE in April 1985 for the purchase and
sale of the capacity and net electrical output of G3. The G3 PPA was amended in
October 1985, and December 1989. G3 can sell energy and capacity for a term of
30 years, which ends in 2020.
In November 2001, SCE and Mammoth entered into three separate Agreements
Addressing Renewable Energy Pricing and Payment Issues, which redefined the
energy payment schedule for each of the three facilities for the period May 2002
through April 2007.
Interconnection provisions for G1 were included as part of the G1 PPA and
specify that SCE is responsible for designing, providing, installing, operating,
and maintaining the electrical interconnects from G1 to SCE's grid.
Separate Interconnection Facilities Agreements between Mammoth and SCE relating
to G2 and G3 were executed on April 15, 1985 as part of the PPAs. The agreements
provide the terms and conditions for designing, providing, installing,
operating, and maintaining the electrical interconnections from G2 and G3 to
SCE's grid.
Mammoth entered into a Plant operating Service Agreement (Mammoth O&M Agreement)
with Ormat Nevada Inc. (as successor to Pacific Power Plant operations) on
January 1, 1995 for the operation and maintenance of the Mammoth plants. The
agreement remains in effect until December 31, 2006 and this is subject to
automatic three-year extensions.
A program that will increase the combined G1 and G2 output by approximately 3.6
MW has been initiated. The project is the Mammoth Project Enhancement and
entails constructing a 3,600-gpm pipeline to the plants from two new production
wells on a previously un-utilized federal geothermal lease. Permits for the
wells have been obtained and pipeline approval is expected by early 2004. The
first production well is scheduled to be operational in 2005. The increase in
generation (starting in 2006) has been accounted for in the Financial
Projections. The capital for this project is not part of this Bond offering.
Ormat, as 50 percent owner of Mammoth, is providing 50 percent of the capital to
complete this project.
- --------------------------------------------------------------------------------
Page 2
EXECUTIVE SUMMARY
================================================================================
ORMESA
The Ormesa GEM 2 and GEM 3 plants, which began operation in 1989, use dual-flash
geothermal technology and each plant has a capacity of 17 MW gross for a
combined capability of 34 MW gross. The OG I, OG II, OG IE, and OG IH plants all
use binary geothermal technology. The COD gross generation capacity and number
of binary units for each plant is provided in the table below.
PLANT COD GROSS CAPACITY BINARY UNITS
----- ---- -------------- ------------
OG I 1987 21 MW 2+2*
OG IE 1988 10 MW 12
OG IH 1989 10 MW 12
OG II 1988 19 MW 20
* OG I originally consisted of 26 binary units. In 2003, 24 of the binary
units were replaced with two integrated two-level units (ITLU) and two of
the original binary units were converted for use with low-temperature
reject fluid from the GEM plants in a bottoming cycle, each generating
approximately 1 MW.
Ormesa delivers and sells its output under two 30-year PPAs with SCE, which were
executed in 1984 and expire in 2016 and 2018, respectively. Under the OG I and
OG II PPAs, the OG I Units (OG I, OG IE and OG IH) are contracted to deliver a
contract capacity of 31.5 MW and OG II is contracted to deliver a contract
capacity of 15 MW. The two PPAs provide for monthly capacity and energy
payments. GEM 2 and GEM 3 support the auxiliary loads of all the other plants
and do not export power for sale.
Due to events that occurred during the energy crisis in California, SCE did not
pay for energy delivered under the OG I and OG II PPAs during the period from
November 1, 2000 through March 26, 2001. Payments due totaled $14.1 million and
$7.1 million respectively. On June 19, 2001 (amended November 21, 2001), SCE and
Ormesa entered into an Agreement Addressing Renewable Energy Pricing and Payment
Issues in order to: 1) establish a five-year fixed rate for energy (alternative
Short Run Avoided Cost or SRAC), 2) establish an agreed upon energy loss
adjustment factor of 1.0, and 3) establish a payment schedule for the unpaid
energy delivered.
Ormesa entered into Plant Connection Agreements for GEM 2 and GEM 3 in March
1989 and Plant Connection Agreements for OG I in October 1985 and for OG IE and
OG IH in October 1989. The interconnection for OG II is addressed in the PPA and
a Plant Connection Agreement dated May 26, 1987. IID has agreed to wheel the
Project's net output to SCE and to sell electricity required to operate the
plants' internal loads under a IID-Edison Transmission Service Agreement dated
September 26, 1985.
Ormesa entered into an Energy Services Agreement (ESA) with IID on February 11,
2003, which sets forth the terms and conditions for Ormesa's purchase of standby
services from IID and the responsibilities and cost allocations associated with
the distribution facilities and metering within the Ormesa site. The effective
date of the ESA is January 1, 2003 and the initial term is for 15 years, which
can be extended by mutual agreement of the parties.
Ormesa entered into an Operation and Maintenance Agreement (Ormesa O&M
Agreement) with Ormat Nevada Inc. on April 15, 2002 for operation and
maintenance of the Ormesa Project, including power plants and wells. The
Agreement remains in effect until expiration or termination of both Ormesa PPAs.
Water is supplied to the Ormesa plants pursuant to an Amended and Restated Water
Supply Agreement with IID, which requires IID to deliver to Ormesa up to 10,000
acre-feet per year of water. The agreement terminates upon expiration or
termination of the PPAs. The volume of water has been sufficient to meet the
historical water requirements of the Ormesa Project.
- --------------------------------------------------------------------------------
Page 3
EXECUTIVE SUMMARY
================================================================================
BRADY AND DESERT PEAK
The Brady and Desert Peak plants use dual-flash geothermal technology. The COD,
gross generation capacity, and number of dual-flash units for each plant are
provided in the table below.
PLANT COD GROSS CAPACITY BINARY UNITS
----------- ---- -------------- ------------
Brady 1992 24.0 MW 3*
Desert Peak 1985 8 MW 1
* A new binary system OEC was added to Brady in 2002 to increase plant
efficiency.
BPP (as successor to Nevada Geothermal Power Partners) entered into a PPA with
SPPC in October 1990. The Brady PPA was amended in July 1991 and June 2002. BPP
can sell up to 19.9 MW of monthly capacity for a term of 30 years, which ends in
2022. The PPA provides for monthly energy and capacity payments. The electrical
interconnection technical requirements, responsibilities and costs were
established in the June 2002 Amendment.
On May 1, 2002, ConAgra Foods Inc. (ConAgra) entered into a Settlement Agreement
with BPP, ORNI 1, LLC, ORNI 2, LLC, Ormat Nevada, and Ormat Technologies, Inc.
to provide geothermal fluid to ConAgra's Gilroy food processing plant located
adjacent to the Project between May 10 and December 10 of each calendar year.
The term of the Settlement Agreement expires on December 31, 2019. ConAgra
agrees to pay BPP on a monthly basis, an hourly fee of $30 for each hour that
geothermal fluid is supplied with an annual cap of $154,080.
BPP entered into a Fluid Supply Agreement with Western States Geothermal Company
on December 15, 2003. The agreement obligates Western States Geothermal Company
to provide a sufficient supply of geothermal fluid to allow the Desert Peak 1
plant to produce 7 MW of capacity. The agreement is effective as of January 1,
2004 and remains in effect until the expiration or termination of the Brady PPA.
BPP is to pay Western States Geothermal Company 1.0 percent of the net revenues
of Desert Peak 1 derived directly from the sale of electricity under the Brady
PPA and reimbursement of all rents and royalties.
BPP entered into an Operation and Maintenance Agreement (Brady O&M Agreement)
with Ormat Nevada, Inc. on January 1, 2002 for operation and maintenance of the
BPP Project including power plants and wells. The agreement remains in effect
until expiration or termination of the Brady PPA.
STEAMBOAT
The Steamboat plants all use binary geothermal technology. The COD, gross
generation capacity and number of binary units for each plant are provided in
the table below.
PLANT COD GROSS CAPACITY BINARY UNITS
------------ ---- -------------- ------------
Steamboat 1 1986 7 MW 7
Steamboat 1A 1988 3 MW 2
Steamboat 2 1992 16 MW 2
Steamboat 3 1992 16 MW 2
On November 18, 1983, Steamboat (as successor to Geothermal Development
Associates) entered into an Agreement For The Purchase And Sale Of Electricity
(Steamboat 1 PPA) with SPPC. The Steamboat 1 PPA was amended on March 6, 1987.
The term of the Steamboat 1 PPA continues through December 5, 2006 and
thereafter continues year to year unless either party elects to terminate.
Energy and capacity rates are based on the SRAC rates in effect for each billing
period.
On October 29, 1988, Steamboat (as successor to Far West Capital, Inc.) entered
into a Long Term Agreement For The Purchase And Sale Of Electricity (Steamboat
1A PPA) with SPPC. The term of the Steamboat 1A PPA is 30 years from the COD of
December 1988. Commencing on the tenth anniversary of the plant's COD and
continuing for the balance of the term, payments are based on the Short Term
Rates Cogeneration and Small Power Production Schedule.
- --------------------------------------------------------------------------------
Page 4
EXECUTIVE SUMMARY
================================================================================
The electrical interconnections for Steamboat 1/1A are addressed in the PPAs and
a Special Facilities Agreement with SPPC.
Ormat has indicated that upon completion of the Galena unit, a new PPA will be
negotiated to replace the existing Steamboat 1 and 1A PPAs. The proposed energy
rate is $.052/kWh, escalated at 1.0 percent per annum.
On January 24, 1991 and January 18, 1991 Steamboat (as successor to Far West
Capital, Inc.) entered into respective Long Term Agreements For The Purchase And
Sale Of Electricity (Steamboat 2 and Steamboat 3 PPAs) with SPPC. The Steamboat
2 PPA was amended on October 29, 1991 and on October 29, 2002.
The term of the Steamboat 2 and Steamboat 3 PPAs is 30 years from COD of
December 1992. Contract capacity ranges from 9,140 to 13,460 kW monthly with an
annual monthly average of 12,000 kW. Steamboat 2 and Steamboat 3 each have the
right to be economically dispatched for up to 11.14 million kWh per year with
SPPC having the right of first refusal to purchase this power. Capacity payments
specified in the Steamboat 2 and 3 PPAs are $19.04/kW month for years 1-14 and
$14.00/kW month thereafter.
Electrical interconnection requirements for Steamboat 2/3 are included in the
PPAs. A Special Facilities Agreement with SPPC provides for SPPC to design,
construct, operate and maintain the interconnection facilities for Steamboat
2/3.
ORNI 7, LLC and Steamboat Geothermal LLC entered into an Amended and Restated
Operation and Maintenance Agreement (Steamboat O&M Agreement) with Ormat Nevada
Inc. on December 8, 2003 for operation and maintenance of the Steamboat Project
power plants and wells, including Galena. Steamboat Development is to become a
party to the agreement as of the closing of the offering. The agreement remains
in effect until expiration or termination of the Steamboat PPAs. Upon completion
of the acquisition of Steamboat 2/3, Steamboat 1, 1A, 2 and 3 are to all be
operated and maintained under the same O&M agreement. Upon completion of the
Galena plant, its operations and maintenance are also to be governed by the same
O&M agreement with Ormat Nevada, Inc.
ORNI 7 currently has plans to expand the capacity of the Steamboat Project
through the construction of the Galena plant. The Galena plant is to be
constructed pursuant to an EPC Contract between ORNI 7 and Ormat Nevada, Inc.,
which is under negotiation. The proposed EPC contract guarantees a 22.7 MW net
plant output. The plant design consists of two ITLUs. All the brine flow to the
Steamboat 1/1A plants and one-third of the brine flow to the Steamboat 2/3
plants will be diverted to the Galena plant. No changes will be made to the
existing production and injection wells. Additional brine flow to the Galena
plant will be supplied from a rejuvenated production well. The cost of the
Galena plant is estimated to be $25.8 million and has been accounted for in the
Financial Projections. The completion schedule is approximately 15.5 months,
with an anticipated notice-to-proceed date of February 15, 2004 and a guaranteed
completion date of May 30, 2005. The Financial Projections do not account for
revenues from the Galena plant until January 2006.
Ormat Nevada's obligations under the EPC Contract will be unconditionally
guaranteed by Ormat Technologies, Inc., an upstream indirect parent of Ormat
Nevada, Inc.
1.2 CONCLUSIONS
The conclusions and observations provided herein are based on Stone & Webster's
review of the documentation listed in Attachment 1 of this report, discussions
with Project participants, and site visits. The conclusions and observations
below apply to all plants identified above unless otherwise noted, and are
subject to assumptions and qualifications set forth in this report.
Financial Projections of future revenues involve, by necessity, making
assumptions regarding business and economic conditions and other events not
within the control of the Project participants or Stone & Webster and are
inherently subject to contingencies. Accordingly, actual results may differ,
perhaps materially, from those projected.
- --------------------------------------------------------------------------------
Page 5
EXECUTIVE SUMMARY
================================================================================
Stone & Webster's conclusions concerning the Projects are summarized as follows:
o Equipment used at the Projects is utility grade and typical of equipment
operating in other geothermal power generation facilities. Based on Stone
& Webster's site visits on November 3 and December 8-10, 2003, equipment
at all Projects is in good working condition and is well maintained.
o All the Projects have experienced above-average availability and excellent
operating performance, reflecting good equipment reliability and
maintenance practices. All of the Projects are base load facilities and
maintenance is performed throughout the year. Maintenance is scheduled to
accommodate on-peak capacity requirements in accordance with the power
purchase agreements. Based on our review of the past five years of
operations, the Projects have been operated and maintained in a safe and
reliable manner.
o The electrical system within each Project and the transmission
interconnections are capable of supporting the generation and delivery of
the Projects' output. The electrical interconnection agreements are in
place for each Project and allow for the delivery of each Project's full
load capacity. System curtailments have not had any significant impact on
the Projects' performance.
o The quality of the geothermal fluids for all of the Projects is better
than that used for many geothermal power generation facilities. Due to the
high quality of the geothermal fluid at Mammoth, it is not categorized as
brine. The high quality of the geothermal fluids at the sites has a
positive effect in reducing equipment deterioration and maintenance
requirements.
o Stone & Webster has reviewed the material permits and the compliance
thereto. All material federal, state and local permits are in place and
renewals have been identified. The Projects have maintained the permits
and should be able to continue operation in compliance with the permits.
o There are no outstanding compliance issues with any of the Projects'
permits required for plant and well field operation; therefore, it is
expected that all permits will be renewed prior to expiration. No permit
issues were identified that would impact future Projects' operations.
o Stone & Webster has reviewed all major contracts and agreements. Summaries
are included in the text of this report. From a technical standpoint, all
Projects should be able to continue to meet their contractual obligations.
o The Financial Projections contain appropriate technical assumptions
regarding the capacity and energy production of each Project on the basis
of historic information and Ormat's planned capital improvements at
Mammoth, and expansion of the Steamboat Project through addition of the
Galena plant.
o The assumptions in the Financial Projections concerning the geothermal
resources are consistent with the resource supply evaluation prepared by
GeothermEx.
o The O&M expense budgets are appropriate and conservative compared with
historic information and contractual obligations.
o Major maintenance costs are included in the operating costs and capital
expenditure budgets and appear reasonable.
o The revenues in the Financial Projections are consistent with the
compensation and penalty structure set forth in the power purchase
agreements.
o Ormat has developed an operating plan and capital expenditure program for
each Project. Ormat's operating plan and expenditures are reflected in the
pro-forma and Financial Projections reviewed by Stone & Webster. Stone &
Webster is of the opinion that Ormat's operating plan and capital
expenditures provide a good basis for safe and reliable operation in
compliance with all relevant environmental and other permits and approvals
required, the power purchase agreements, and support the projected
revenues and cash flow included in the Financial Projections. Based on our
review of Ormat's operating plan and the technical assumptions in the
Financial Projections, the projected revenues and cash flows included in
the Financial Projections are reasonable.
- --------------------------------------------------------------------------------
Page 6
EXECUTIVE SUMMARY
================================================================================
o The Mammoth Project Enhancement at the Mammoth site and the Galena plant
addition at the Steamboat Project are the two most significant capital
projects. Both projects are intended to increase generation capability at
the respective sites. Stone & Webster believes that these projects will
meet their projected production levels. The capital required for the
Mammoth Project Enhancement is not part of this offering. Ormat, as 50
percent owner of Mammoth, is funding 50 percent of the capital for this
project. However, proceeds from this offering will be used, in part, to
capitalize the Galena plant.
o Given the proposed plant design and the availability of geothermal fluids
with properties consistent with the design basis of the plant (as
confirmed by the GeothermEx report), Stone & Webster believes the Galena
plant will be able to 1) satisfy the performance guarantees, 2) achieve
the assumptions of capacity and production in the base case Financial
Projections and 3) fulfill its performance obligations under the Galena
PPA that is currently under negotiation.
o In geothermal projects, generally there are three primary elements that
can negatively affect energy production: 1) declining geothermal fluid
flow, 2) accelerated resource cooling and 3) increased equipment failures.
It was agreed by GeothermEx, Ormat and Stone & Webster that, on the basis
of historic operating data, a declining rate of geothermal fluid flow was
less of a concern for these four Projects than declining resource
temperatures. Equipment failures will affect the projects in two ways: 1)
increased O&M costs and 2) decreased equipment availability. Stone &
Webster performed three sensitivity analyses to determine the impact of
declining resource temperatures, unexpected increases in O&M costs and
reduced equipment availability on the Financial Projections and the debt
service coverage ratios (DSCRs). Additionally, the effect of decreased
SRAC energy rates was investigated. Results of the sensitivity analyses
are set forth below.
SENSITIVITY ANALYSIS
PARAMETER SENSITIVITY MINIMUM DSCR AVERAGE DSCR
- ---------------------------------- ------------ ------------
Base Case 1.58 1.58
- ---------------------------------- ------------ ------------
Accelerated Cooling 1.26 1.47
- ---------------------------------- ------------ ------------
5% Increase in O&M Costs 1.50 1.51
- ---------------------------------- ------------ ------------
2% Decrease in Availability 1.54 1.55
- ---------------------------------- ------------ ------------
15% Decrease in SRAC Energy Rates 1.34 1.43
- ---------------------------------- ------------ ------------
Accelerated Cooling/Increased O&M 1.20 1.40
- ---------------------------------- ------------ ------------
Decreased SRAC Rates/Increased O&M 1.27 1.36
- ---------------------------------- ------------ ------------
Note: The above sensitivity analysis assumes a total source of funds of
$190 million amortized until 2020 at a bond coupon rate of 8.25%.
- --------------------------------------------------------------------------------
Page 7
================================================================================
SECTION 2.0
FACILITIES DESCRIPTION
Two types of geothermal power cycles, binary, and double (or dual) flash, are
used at the Projects.
The binary cycle uses two closed-loop systems. Isobutane or isopentane is used
in the power cycle due to its ability to vaporize at a relatively low
temperature. The hydrocarbon fluid is circulated through heat exchangers, where
it vaporizes, then passes through the turbine and exits to the condenser, where
it is cooled to a liquid and collected in a storage vessel for pumping back to
the heat exchangers. Except for occasional minor leaks in the system, the
hydrocarbon fluid is contained and not released. The geothermal brine fluid is
pumped from the production wells, through the heat exchangers where heat is
transferred to heat the hydrocarbon fluid, and then it is pumped back into the
ground through injection wells. The geothermal brine is in a liquid phase with
dissolved noncondensable gases. Neither the geothermal fluid nor the
noncondensable gases are released to the atmosphere.
In the dual-flash cycle, the geothermal brine fluid is first directed to an
auxiliary flash tank where steam is separated and flows to high-pressure flash
tanks. High-pressure steam leaving the high-pressure flash tanks passes through
demisters and then flows to the high-pressure turbine inlets. The geothermal
fluid underflow leaving the auxiliary flash tank and the high-pressure flash
tanks is directed to low-pressure flash tanks. The low-pressure steam leaving
the low-pressure flash tanks passes through demisters and then flows to the
low-pressure turbine inlets. The geothermal fluid underflow leaving the
low-pressure flash tanks is directed to surge tanks. Booster pumps are used to
pump the geothermal fluid back to the injection wells.
2.1 MAMMOTH
Mammoth consists of three geothermal plants located in Mono County, California,
approximately three miles from the town of Mammoth Lakes. The site is within the
East Valley Unit of the Long Valley Known Reserve Geothermal Resource Area
(KGRA) in an area generally known as the Casa Diablo Hot Springs.
The plants are designated Mammoth Pacific I (G1), Mammoth Pacific II (G2), and
Pacific Lighting Energy Services (G3). G1 has a gross output rating of 9 MW and
G2 and G3 are rated at 13 MW each for a total gross capacity of 35 MW. G1 began
operation in 1985 and G1 and G2 began operation in 1990. All three plants
utilize isobutane binary power cycles to convert geothermal energy to electrical
energy. The plants operate under three separate power sales agreements and the
geothermal fluid is supplied pursuant to a resource lease held by Mammoth.
DESIGN DISCUSSION AND CONDITION
Plant Configuration
G1 has two identical power generating systems (trains) and the other two plants
are each configured with three identical power-generating trains. Each train
includes: (a) shell and tube heat exchangers in which geothermal fluid vaporizes
isobutane, (b) a turbo-expander and associated auxiliaries, where energy in the
isobutane is converted to mechanical energy, (c) a gear box, (d) an electric
generator and associated auxiliaries, (e) air-cooled condensers, where isobutane
is condensed, and (f) the isobutane circulation system.
Air-cooled condensers cool the isobutane to a liquid by the flow of ambient air
over finned condenser tubes. Unlike water-cooled condensers, air-cooled
condensers do not require water for operation and do not discharge water vapor
to the atmosphere. Performance of a plant using an air-cooled condenser is more
sensitive to ambient temperature than a plant with a water-cooled condenser.
Because ambient conditions vary significantly throughout the year, plant output
also varies significantly with ambient temperature. Due to the capacity and
energy payment structure set forth in the PPAs, there are no financial penalties
associated with the variation of plant output on an annual basis.
The geothermal fluid supply system includes well pumps, motors, piping to the
plants and associated fittings and thermal insulation. The pump impellers are
located at the bottom of the wells and are driven with a shaft by a motor
located above ground. Line shaft bearing failures are the most common failures
in the well pumping system. Presently, the average life of the line shaft is
four years.
- --------------------------------------------------------------------------------
Page 8
FACILITIES DESCRIPTION
================================================================================
The plants are currently supplied by twelve wells of which eight are generally
operated simultaneously. The chemistry of the geothermal fluid is relatively
benign compared to many other geothermal resources. An assessment of the
geothermal resource, future production, and condition of the wells is addressed
in the GeothermEx report.
The geothermal fluid injection systems pump the cooled fluid back into the
ground through the injection wells. There are a total of eight injection wells,
with the five deeper wells in service and the three shallow injection wells
utilized on a limited basis.
The plants have a combined total of eight radial-inflow turbo-expanders. These
single stage machines were manufactured by Rotoflow, which has been wholly-owned
by GE Power Systems since 2000. The isobutane working fluid is very clean and
benign, so the turbo-expanders experience minimal wear and infrequent problems.
Spare parts kept at the Project include two turbine cold sections, three forged
wheels, three cast wheels, one generator and one reduction gear.
Electrical Interconnection
Mammoth is a base load plant located in a remote area of the SCE power grid,
with few other generating plants in the area. Consequently, Mammoth provides
system support to SCE and as a result, pays no line losses under its power sales
agreements.
The Mammoth plants do not have black-start capability and therefore require
supplemental power to start up. When a plant is off line, electrical power is
backfed from SCE through the main electrical interconnection. Revenue metering
is provided for each of the three plants in the corresponding interconnection
switchyard. The output of the plants is then connected to a network of 33 kV
overhead distribution lines connecting the site to SCE's Casa Diablo Substation.
The one half mile, 33 kV line between Mammoth and the substation is owned,
operated, and maintained by SCE.
Electrical Generation and Distribution Systems
Electrical energy is generated at Mammoth by eight 5,000 kW, 4.16 kV electrical
generators manufactured by Electric Machinery Company. G1 has two generator
step-up (GSU) transformers, with one designated for each respective generator.
G2 and G3 each have a single GSU transformer shared by the three generators.
Each plant includes an electrical equipment building to house the 4.16 kV
switchgear, secondary unit substations, load centers, motor control centers
(MCCs), and battery and DC systems.
The Mammoth plants' electrical generation and distribution systems and equipment
are industrial-grade equipment manufactured to appropriate NEMA, IEEE and ANSI
Standards. This type of equipment is inherently rugged and is capable of
supporting operation for the duration of the PPAs.
The plant electrical systems should have adequate capacity to accommodate the
near-term changes to Mammoth proposed by Ormat.
Instrument and Control Systems
Mammoth is controlled from a central control room via an ABB distributed control
system (DCS). Mammoth has recently completed a DCS upgrade. The upgrade includes
integration of DCS controls for most major plant components and systems. Design
features of the DCS upgrade include relocation of control and monitoring
functions for major mechanical systems and equipment to the DCS, manual local
controls for equipment, hard-wired emergency shutdown controls, and a
CRT/Keyboard operator interface. The DCS and supporting control and instrument
systems are utility grade equipment manufactured to appropriate standards. This
type of instrument and control equipment, when operated and maintained in
accordance with the manufacturer's instructions and recommendations should be
capable of supporting plant operation for the duration of the PPAs. Given the
relatively new age of the control system, spare parts should be readily
available. Plant instrument and control systems should have adequate capacity to
accommodate the near-term changes to Mammoth proposed by Ormat.
- --------------------------------------------------------------------------------
Page 9
FACILITIES DESCRIPTION
================================================================================
Balance of Plant
Waste disposal is required for lubricating oils and for scale removed from the
isobutene heat exchangers. These materials represent small quantities annually
and are disposed off-site.
The geothermal fluid is not excessively aggressive; therefore, corrosion and
material selection are not major considerations, as they are with many other
geothermal installations. For the most part, carbon steel, ductile iron and some
stainless steel are used in the geothermal fluid flow path.
The plants are equipped with adequate fire protection systems, including a
250,000-gallon fire water storage tank.
Since the plants use air-cooled condensers, very small amounts of water are used
during operation. In addition to the firewater storage tank, Mammoth has an
80,000-gallon service water storage tank. Water for both tanks is supplied from
either the City of Mammoth Springs or geothermal fluid is used. Bottled water is
used for on-site potable water.
2.2 ORMESA
The Ormesa Project consists of a group of five geothermal power plants located
on a common site in Imperial County, California. GEM 2 and GEM 3 each have a
gross capacity of 17 MW and began operation in 1989. OG I is rated at 21 MW
gross and began operation in 1987 followed by OG IE, rated at 10 MW gross, with
operation beginning in 1988. OG II, rated at 19 MW gross, began operation in
1988, and OG IH, rated at 10 MW gross, started operating in 1989. The GEM 2 and
GEM 3 units utilize a dual-flash steam power cycle and the OG I Units and OG II
utilize binary power cycles.
The plants operate under two separate power sales agreements established with
SCE. Power is transmitted from Ormesa to SCE, pursuant to an agreement with IID.
Cooling water is also purchased from IID.
DESIGN DISCUSSION AND CONDITION
GEM 2 & 3 Configuration
The GEM 2 & 3 generating units are nearly identical configurations and consist
of two Mitsubishi steam turbines, each driving an electrical generator. These
units are currently being used to serve the auxiliary load requirements of the
Ormesa Project.
Geothermal brine enters the plant at 190 psig and 335 Degree F and is piped to
the auxiliary flash tank. In the tank, brine is flashed to steam and flows out
to a demister and is then admitted to the turbine as high-pressure steam at 30
psig. Brine from the auxiliary flash tank flows to the low-pressure flash tank,
where a portion is flashed to low-pressure steam. Steam flowing out of the tank
is passed through a demister and then enters the turbine at approximately 2.5
psig. The brine remaining in the low-pressure flash tank flows to the brine
return surge tank. Booster pumps at the surge tank pump the brine to the
injection pumps, where it is pumped back into the ground through injection
wells.
Exhaust steam leaving the turbine is condensed in a direct-contact condenser
located adjacent to the turbine. Cooling water is sprayed directly into the
direct-contact condenser and becomes mixed with the condensate in the condenser
hotwell. A hotwell pump transfers the hotwell water to a mechanical draft
cooling tower, where it is cooled by air and falls into the tower basin. The
cooled water flows back to the condenser through a vacuum siphon to continue
condensing the steam.
The Mitsubishi steam turbines are dual-pressure, impulse-reaction, condensing
type machines designed to operate at 3,600 rpm. Each turbine rotor has four
stages of blades.
- --------------------------------------------------------------------------------
Page 10
FACILITIES DESCRIPTION
================================================================================
OG IE, OG IH and OG II Configuration
The OG IE, OG IH, and OG II plants utilize Ormat Energy Converter (OEC) modules
arranged for operation at two levels. OG IE was designed for operation with five
pairs of identical OEC modules. OG IH and OG II were designed for operation with
12 OEC and 20 OEC modular units, respectively, arranged in two cascading levels.
The plants were constructed with multiple OECs interconnected with an isopentane
piping system and a heat exchanger, functioning as the isopentane vaporizer. The
liquid isopentane is vaporized in the heat exchanger and then flows to the
turbine, where it expands through the blades and rotates the combined turbine
and electrical generator. A condenser at the turbine exhaust condenses the
isopentane and it is pumped back to the heat exchanger. Circulating water from
the cooling towers passes through the condensers to cool and condense the
isopentane.
The circulating water systems for the three plants are similar and consist of
circulating pumps that pump the cool circulating water from the cooling tower
basin to the individual condensers, where the water is heated as it cools the
isopentane. The circulating water continues to the top of the mechanical draft
cooling towers and then cascades down through the tower fill as it is cooled by
air passing through the tower.
OG I Configuration
In July 2003, a modification was completed at the OG I plant to replace the
original 24 Level I and Level II OECs with two new Ormat Integrated Two Level
Units (ITLUs), each generating approximately 10 MW. In addition, two of the
original Level 3 OECs were modified for use with low-temperature brine from the
GEM plant in a bottoming cycle, each generating approximately 1 MW.
Entering geothermal brine is piped to the Level I OEC and passes through a heat
exchanger, which heats the isopentane working fluid to the vapor state and then
it is admitted to the high-pressure turbine. Isopentane exhaust leaves the
high-pressure turbine and is routed to the low-pressure turbine. After leaving
the low-pressure turbine, the isopentane is condensed and is returned to resume
the cycle again. The high-pressure turbine and the low-pressure turbine are
coupled together to drive the Level I OEC electrical generator. After leaving
the Level I OEC, the geothermal brine enters the Level II OEC and the above
cycle is repeated at a lower energy level.
An external cooling water system is used to remove heat by cooling and
condensing the isopentane. The system consists of a mechanical draft cooling
tower and the associated pumps and piping systems to circulate the cooling
water.
Electrical Interconnection
The Ormesa Project is a base load generating facility located in IID's service
area in Southern California. Energy generated by each of the plants is delivered
to the Ormesa switching station via a single 13.8 kV overhead radial feeder from
IID's 92 kV Highline Substation. A 230 kV transmission line owned and operated
by IID connects the 230 kV Highland Substation to SCE's 230 kV Mirage
Substation. IID receives the energy from the Ormesa interconnection and wheels
the power for delivery to SCE's Mirage Substation, near Palm Springs, CA. The
230 kV line is owned, operated, and maintained by IID.
The Ormesa plants do not have black-start capability. When a plant is off-line,
electrical power is backfed from IID through the main electrical interconnection
to the Mirage Substation.
Electrical Generation and Distribution Systems
The electrical distribution system is designed in a single feed, single bus
radial configuration. This configuration provides minimal diversity as well as
redundancy and is consistent with similar size and type facilities.
The design of the electrical distribution and generation systems is functional
and adequate for the Ormesa Project. Electrical generation and distribution
systems equipment are utility-grade equipment in good operating condition and
are manufactured to appropriate NEMA, IEEE and ANSI Standards. This type of
equipment is inherently rugged and is capable of supporting operation for the
duration of the PPAs.
- --------------------------------------------------------------------------------
Page 11
FACILITIES DESCRIPTION
================================================================================
Instrument and Control Systems
The Ormesa plants are controlled from the GEM plant central control room via a
recently upgraded (year 2000) Westinghouse Ovation DCS.
Visual inspection of various existing instrument and control (I&C) devices
indicates that I&C equipment is in good condition and has been adequately
maintained. I&C systems and components are utility grade equipment manufactured
to appropriate industry standards. This type of I&C equipment, if operated and
maintained in accordance with the manufacturer's instructions and
recommendations, is capable of supporting continued plant operation for the
duration of the PPAs. Given the relatively new age of the control system, spare
parts should be readily available.
Balance of Plant
The Ormesa plants have an extensive, integrated well and well field piping
network. The production well downhole brine pumps are multi-stage centrifugal
turbine pumps manufactured by Goulds and Johnston Pumps companies. The electric
motors driving the pumps are all located above ground. The pumps are set at
varying depths ranging from approximately 600 to 1,800 feet.
The Ormesa production pumps average approximately 24 months of service between
overhauls. Arrangements have been established with both Goulds and Johnston
Pumps companies to service and replace pumps in a five-day turnaround period.
The total cost for a pump rebuild, replacement and installation is about
$120,000.
The geothermal brine, if not properly handled, can cause scaling and corrosion
related operating problems. These potential problems are controlled and
minimized through the injection of scale forming inhibitors and corrosion
inhibiting chemicals.
2.3 BRADY AND DESERT PEAK
The BPP Project consists of the Brady and Desert Peak plants, located in the Hot
Springs Mountains approximately 65 miles northeast of Reno, Nevada on a group of
leases in the Brady-Hazen KGRA. Brady has a gross capacity of 24 MW and began
operation in 1992. Desert Peak has a gross capacity of 8 MW and began operation
in 1985. Both plants utilize a dual-flash power cycle. The plants supply power
to SPPC under one PPA and also supply geothermal fluid to ConAgra Foods, Inc.,
which is located adjacent to the Brady plant.
DESIGN DISCUSSION AND CONDITIONS
Brady Plant Configuration
Brine entering the plant from the well field enters the two high-pressure flash
tanks. The resulting flash steam is piped directly to the associated
high-pressure steam turbine. The brine leaving the two high-pressure flash tanks
flows to a single low-pressure flash tank. This tank provides flash steam
directly to the low-pressure turbine. Brine leaving the low-pressure flash tank
at a temperature of 230 Degree F, is pumped to an OEC to produce additional
electric energy. In August 2002, the OEC was installed to utilize a portion of
the energy in the brine leaving the double flash cycle.
The OEC consists of two isopentane turbines coupled to a single synchronous
electric generator. The two isopentane turbines operate with the conventional
Ormat isopentane cycle, where the isopentane is heated and vaporized using a
brine heat exchanger. The vaporized isopentane flow rotates both turbines and
then the exhaust flows through two condensers, where the isopentane is condensed
to a liquid and pumped back to the brine heat exchanger. Cooling is provided by
a horizontal air-cooled heat exchanger. When the brine leaves the OEC, it is
pumped into the ground through an injection well.
The power generation equipment consists of two identical General Electric CL-55
high-pressure condensing steam turbines rated for an inlet steam flow of 189,000
lb/hr at 597 psia and 292 Degree F. The turbines each drive an Ideal
- --------------------------------------------------------------------------------
Page 12
FACILITIES DESCRIPTION
================================================================================
Electric generator. The single low-pressure condensing steam turbine is also a
General Electric model CL-55 machine rated for an inlet steam flow of 221,250
lb/hr at 34.5 psia and 259 Degree F and drives an Ideal Electric generator.
Brady uses a circulating water system consisting of a 3-cell Ecodyne mechanical
draft cooling tower and circulating pumps to circulate cooled water through the
three steam condensers.
Desert Peak Plant Configuration
Brine from the well field enters a high-pressure separator, where steam is
separated and flows to the high-pressure inlet of the steam turbine. The brine
flow leaving the high-pressure separator flows to a low-pressure separator where
the low-pressure steam is directed to the low-pressure steam turbine inlet.
Steam exhausting from the steam turbine enters a direct-contact spray condenser,
where it is cooled and mixed with cooled water from the cooling tower.
Condensate in the condenser hotwell is pumped to the top of the cooling tower to
be cooled again.
The steam turbine was manufactured by Transamerica Delaval and is connected to
an induction type electrical generator manufactured by Electric Machinery
Company. The steam turbine was designed for a high-pressure steam flow of 92,200
lb/hr at 74 psig and a low-pressure steam flow of 98,600 lb/hr at 7 psig.
Electrical Interconnection
Originally, electrical power generated at Desert Peak was transformed from 13.8
kV to 120 kV at the plant substation and transmitted through a 4.8 mile 120 kV
transmission line to the SPPC electrical distribution system. This line is
currently disconnected. At present, Desert Peak transmits all of its power
through a 4-mile 13.8 kV transmission line to the Brady plant substation, where
it is regulated to 12.47 kV to match the output of the Brady electrical
generators. The combined output from the Brady Plant substation is transferred
at 12.47 kV to the SPPC substation where it is transformed to 120 kV for
distribution on the SPPC system.
Electrical Generation and Distribution Systems
Brady and Desert Peak primarily utilize induction generators. The OEC facility
generator is a synchronous machine. The plants do not have black start
capability. When either plant is shut down, backfed electrical power from SPPC
via the main electrical interconnection is necessary for plant startup.
In general, the electrical distribution system is designed in a single feed,
single bus radial configuration. This configuration provides minimal diversity
as well as redundancy and is consistent with the type and relative size of the
Brady and Desert Peak plants.
The design of the electrical distribution and generation systems is functional
and adequate for the intended purpose. Electrical generation and distribution
systems and equipment are utility-grade equipment in good operating condition,
manufactured to appropriate NEMA, IEEE, and ANSI Standards. This type of
equipment is inherently rugged and is capable of supporting continuous operation
for the duration of the PPAs.
Instrument and Control
Desert Peak is controlled with a Micon DCS supported with Modicon programmable
logic controllers. This equipment is old and is not supported by the
manufacturers. Two years ago, the plant purchased a new Modicon-840 Integrated
Control System. The new control system is presently stored in the warehouse and
will be installed when the existing system is no longer functional.
Brady utilizes a Bailey Infi 90 DCS. It is working well and has been upgraded.
When the Ormat OEC was constructed, it was supported with an Allen Bradley FLC
500 control system.
- --------------------------------------------------------------------------------
Page 13
FACILITIES DESCRIPTION
================================================================================
Balance of Plant
Brady is supported by a geothermal brine well field consisting of seven
production wells. Normally five wells operate to support plant operation. Desert
Peak is operated with brine supply from three production wells.
2.4 STEAMBOAT
The Steamboat Project, located in Washoe County, Nevada, consists of four binary
cycle generating plants located on a common site. The plants are designated as
Steamboat 1, which has a gross rating of 7 MW and began operation in 1986,
Steamboat 1A, which is rated at 3 MW and began operation in 1988, and Steamboat
2 and 3, which are rated at 16 MW each and began operation in 1992. A future
binary generating plant projected to have a capacity of approximately 22.7 MW is
planned for development at the Steamboat site and is designated as the Galena
Plant.
DESIGN DISCUSSION AND CONDITION
Steamboat 1 & 1A Configuration
Steamboat 1 utilizes OEC equipment, with four OECs arranged for Level 1
operation and three OECs arranged for Level 2 operation. The cycle equipment
configuration is the same for each Level, but the Level 1 cycle receives the
hottest brine, and then brine leaving Level 1 cascades to Level 2. The power
cycle uses a feed pump to pump liquid isopentane through a preheater. After
leaving the preheater, the isopentane flows to the brine heat exchanger where it
is vaporized and is directed to the turbine. The high-pressure vapor expands
through the turbine, which drives a gearbox coupled to an induction electric
generator. The low-pressure exhaust isopentane vapor flows to the air cooler,
where it is condensed and starts the cycle again.
When Steamboat 1A was added, it was designed for Level 3 operation, which is a
lower energy level than is used for the Steamboat 1 configuration. The power
cycle is similar, but Steamboat 1A uses two OECs and two synchronous electric
generators.
Steamboat 2 & 3 Configuration
Steamboat 2 & 3, are identical in design and utilize Rotoflow turboexpanders.
Each unit is comprised of a closed isobutane power cycle that includes two
radial-inflow turboexpanders with associated auxiliaries, six brine/isobutane
heat exchangers, air coolers, an isobutane accumulator, and isobutane
circulating pumps. The cycle is a conventional isobutane power cycle, wherein
the isobutane working fluid is heated and vaporized using heat from the brine in
the heat exchangers. The isobutane expands through the turbine rotating the
turbine and the electrical generator. It is exhausted from the turbine and
passes through the air cooler, where it is condensed. Liquid isobutane leaving
the air cooler is collected in an accumulator and then is pumped back to the
heat exchangers to commence the cycle again.
The air cooled condensers cool the isobutane to a liquid by the flow of ambient
air over finned condenser tubes. Unlike water-cooled condensers, air cooled
condenser do not require water for operation and do not discharge water vapor to
the atmosphere. Performance of a plant using an air cooled condenser is more
sensitive to the ambient temperature than a plant with a water cooled condenser.
Because ambient conditions vary significantly throughout the year, plant output
varies with ambient temperature. The capacity and energy payment structure set
forth in the PPAs is designed as such so there are no penalties associated with
the variation of plant output on an annual basis.
Galena Plant Configuration
Ormat intends to construct the Galena plant on land adjoining the existing
Steamboat plants. This approximately 22.7 MW electric generating plant will use
the latest ITLU binary cycle technology. Presently, construction is scheduled to
start on June 30, 2004 and the guaranteed completion date is May 30, 2005.
- --------------------------------------------------------------------------------
Page 14
FACILITIES DESCRIPTION
================================================================================
Galena is to utilize brine sources currently available at the site. It is
intended that the present brine supply to Steamboat 1/1A and one-third of the
brine presently supplied to Steamboat 2/3 will be directed to Galena. This
amounts to 4,846,000 lbs/hr of brine at 215 psig and 306.7 Degree F. An
additional supply of brine will be obtained from an unused existing well, which
is expected to produce 500,000 lb/hr of brine at 280 Degree F.
Each ITLU has a dual power cycle. Each power cycle features a vaporizer,
preheater, a recuperator pump, and a turbine. Brine passes through the preheater
and vaporizer to heat the isopentane to the vapor state and then it is directed
to the turbine. After leaving the turbine, the isopentane enters the recuperator
where it is cooled and condensed. Pumps at the recuperator pump the liquid
isopentane to the preheater to start the cycle again. Each of the two turbines
in the ITLU drives a common synchronous electric generator.
Electrical Interconnection
Steamboat 1/1A have a total of nine electrical generators producing electricity
at 600V. Both plants each have an electric transformer rated 600V/24.9 kV that
supplies the main plant distribution bus. The 24.9 kV bus supplies energy to the
SPPC substation, where voltage is raised to 120 kV for distribution to the SPPC
transmission system. Steamboat 2 and 3 each has two electrical generators
producing electricity at 4,160 V. A bus from each unit is connected to a common
4160 V/120 kV electrical transformer in the SPPC substation for distribution to
the SPPC transmission system. When the Galena plant is completed, it will
provide electrical energy to the existing SPPC substation at 13.8 kV.
Electrical Generation and Distribution Systems
Steamboat does not have black-start capability. When units are off line,
electrical power is backfed from SPPC through the substation for plant startup.
Auxiliary loads are served by the electrical distribution system at 4,160 VAC,
600 480 VAC, 120 VAC and 125 VDC. Electrical equipment enclosures are provided
to house electrical distribution system components.
Based on historical performance, the design of the electrical distribution and
generation systems is functional and adequate for the Steamboat Project.
Electrical generation and distribution systems equipment are utility-grade
equipment in good operating condition and manufactured to appropriate NEMA,
IEEE, and ANSI Standards.
Instrument and Control Systems
Steamboat 1 and 1A are controlled with a GE series 6 coated system that is
linked to programmable logic controllers. The plant operator uses Windows-based
software to interface with the GE system. Steamboat 2 and 3 are controlled with
a Bailey Infi 90 DCS, which has had some recent upgrades.
Visual inspection of the various existing instrument and control devices
indicates that the equipment is in good condition and has been reasonably
maintained. I&C systems and components are utility-grade equipment manufactured
to appropriate industry standards.
- --------------------------------------------------------------------------------
Page 15
================================================================================
SECTION 3.0
OPERATIONS AND MAINTENANCE
Successful operation of any geothermal power generating facility is dependent
upon proper operation and diligent maintenance practices. Stone & Webster's O&M
assessment of the Projects was based on site visits, review of historic
Projects' O&M records and the Projects' outage reports. In addition, our
assessment focused on the Projects' operating history, O&M activities and
staffing, equipment condition, historical maintenance problems and spare parts.
Based on our review of approximately the past six years of operation, the
Projects have been operated and maintained in a safe and reliable manner with
above average availability and operating performance.
3.1 MAMMOTH
MAMMOTH OPERATING STATISTICS
1998 1999 2000 2001 2002 2003
------ ------ ------ ------ ------ ------
Net Energy Delivered (GWh) 236.0 231.0 233.9 231.7 226.4 219.3
Availability Factor (%) 99.0 99.5 99.7 99.4 99.5 99.1
Mass Flow Rate (klb/Hr) 6,047 6,156 6,281 6,007 6,060 N/A
Inlet Temperature Degree F 317 316 316 314 315 N/A
Mammoth has experienced excellent operating performance as illustrated by the
key performance indicators shown in the above table. Availability of Mammoth has
approached 100 percent repeatedly, which is an indication of excellent
maintenance and equipment reliability. Mammoth has experienced limited outages
and the high capacity factors reflect efficient utilization. A previous site
inspection by Stone & Webster on November 3, 2003 indicated that the Project is
properly maintained and in good condition.
Mammoth incurs a decline in summer performance due to its air-cooled condensers.
The output of the plants varies dramatically with ambient temperature. As a
result, the facility's output during a summer month is approximately 80 percent
of the output during a winter month. An ongoing testing program of evaporative
cooling systems to enhance performance on hot days has been taking place at G1
since 2001 with reported positive results. Due to the capacity and energy
payment structure set forth in the PPAs, there are no financial penalties
associated with the variation of plant output on an annual basis.
Mammoth has had a slight decline in generation over the life of the facility
primarily due to decreases in geothermal fluid temperature. The geothermal fluid
temperature decline has been stabilized for the past several years so
performance has been more consistent. In addition, Mammoth has continued to take
steps to minimize any further decline in output by making improvements such as
the enhanced evaporative cooling systems and new geothermal production wells.
Mammoth is a base load facility with on-peak operations during June through
September. Maintenance that may limit output is scheduled during the off-peak
months of October through May. Whenever possible, maintenance is scheduled to
coincide with other power limiting events such as SCE power curtailments or
annual injection well surveys. Also, the modular design of Mammoth allows
maintenance to be performed without significant disruption to the turbine
generators. Pre-peak and post-peak inspection and maintenance is performed on
individual units each year. Other periodic maintenance activities include
semi-annual analysis of oil in major transformers. Motors are reportedly rebuilt
corresponding to the maintenance cycle on the associated driven equipment.
Major electrical equipment inspection and maintenance outages are scheduled
every four years and include turbine generator seal replacement. Scheduled work
includes calibration of protective relays, and cleaning, inspection, adjusting,
and general maintenance of electrical equipment including circuit breakers,
switchgear, MCCs, and DC systems. This periodic maintenance activity was last
performed in 2002. With the exception of heat exchanger retubing, major
maintenance costs are reported to fluctuate very little from year to year.
In order to improve equipment operating performance and maintenance issues,
Mammoth has obtained cost-sharing grants with several industry partners. The
well pumps are prone to problems due to the exposure to geothermal fluid
- --------------------------------------------------------------------------------
Page 16
OPERATIONS AND MAINTENANCE
================================================================================
and the fact that they cannot be easily monitored because they are located
within the well casings. The plant staff has reduced the problems dramatically
since the startup of the project, such that well pump failures are extremely
infrequent. Additional improvements continue to be sought.
Mammoth had experienced a number of turbine generator problems including two
generator failures on G1. Due to modifications and good spare part inventories,
negative effects on plant performance have been minimized. Stone & Webster
reviewed the annual plant manager reports from the last five years, and observed
no indications of significant recurring problems with the generators or the
electrical systems. The site visit on November 3, 2003 confirmed that these
problems have been corrected and are properly managed to minimize failures.
The turbo-expanders, cycle pumps, and other components in the isobutane cycle
require very little maintenance because the isobutane is clean and benign. The
condensers operate well and require minimal maintenance. The fans, motors, and
drives require minor maintenance and the fins are occasionally cleaned to remove
dirt.
The controls and instrumentation equipment installed at Mammoth appear to be
functional, in reasonable condition, and adequately maintained. This type of
equipment should be adequate for continued operation assuming proper maintenance
and subject to spare parts availability. Given the current age of the control
systems, spare parts should continue to be available from the original equipment
manufacturer (OEM) or from an after-market source for a reasonable period of
time.
The geothermal fluid is not aggressive; therefore, corrosion and material
selection should not be major considerations, as they are with many other
geothermal installations. For the most part, carbon steel, ductile iron, and
some stainless steel are used in the geothermal fluid flow path. While corrosion
has not been significant, heat exchanger tube leaks were occurring due to
scaling. A preventative maintenance program was implemented that entails regular
cleaning and on-site re-tubing.
Tube bundles in heat exchangers are budgeted for replacement every six years, at
a cost of approximately $250,000, and are cleaned twice a year. A recent
inspection determined that tube failures and pitting are occurring in the G1 air
cooler condenser and will require replacement of tubing. This pitting problem in
the G1 air condenser tubing is not considered symptomatic with the other air
cooled condensers. The bottom two rows of the condenser tubing are blocked with
corrosion products and therefore the efficiency of the condenser has been
reduced. The total cost for replacement of the condenser tubing will be
$1,250,000 and the replacement is scheduled for 2004. The funds for the
condenser tubing replacement have already been allocated by Ormat and are not
part of the cash flows for this bond offering; therefore, this capital
expenditure has not been included in the Financial Projections.
A program that will increase the combined G1 and G2 output by 3.6 MW has been
initiated. The project is the Mammoth Project Enhancement and entails
constructing a 3,600-gpm pipeline to the plants from two new production wells on
a previously un-utilized federal geothermal lease. Permits for the wells have
been obtained and pipeline approval is expected by early of 2004. The first
production well is scheduled to be operational in 2005. The increase in
generation beginning in 2006 has been accounted for in the Financial
Projections. The capital for this project is not part of this bond offering.
Ormat owns 50 percent of Mammoth and is funding 50 percent of the project cost
through other sources of capital.
Mammoth has a staff of 21 employees, consisting of three managers, two
administrators, ten operators and six maintenance personnel, including one
foreman. Operators work 12-hour shifts and perform a large portion of
preventative maintenance. The maintenance crew works a standard 40-hour week.
We consider that the operations and maintenance organization at Mammoth is
comprehensive and organized and that normal equipment maintenance is being
conducted to the manufacturer's recommendations and to utility industry
practices.
3.2 ORMESA
For the operating period from 2000-2002 GEM 2, which was overhauled in 1998, has
been used on-site for auxiliary power requirements. During this period,
availability has been good, averaging 98.6 percent since 2000. GEM 3 was
overhauled in 2003 and has recently been returned to service.
- --------------------------------------------------------------------------------
Page 17
OPERATIONS AND MAINTENANCE
================================================================================
ORMESA BINARY PLANTS OPERATING STATISTICS
1998 1999 2000 2001 2002 2003
------ ------ ------ ------ ------ ------
Net Energy Delivered (GWh) NA 381.3 372.2 374.7 353.7 397.4
Availability Factor (%) NA 98.3 98.8 99.3 98.5 98.9
Mass Flow Rate (klb/hr) NA * 13,465 13,952 14,918 N/A
Brine Inlet Temperature (Degree F) NA 297 305 306 304 N/A
NA = Information not available
* Value provided for brine flow was questionable and not used
Availability factors and delivered energy for the binary plants consistently
show favorable operating numbers. The recent addition of the new ITLUs at OG I
should support these operating trends.
Ormesa is a base load facility operating continually through the twelve-month
annual period. Generation decreases during the summer months because of
reduction in the cooling capability. Annual maintenance is normally scheduled
for the end of February and during October.
During 2003, in addition to the normal maintenance activities of lubrication,
valve repair, seal replacements, equipment adjustments, instrument replacements,
vibration monitoring, cleaning and painting, the following significant major
maintenance projects were completed:
o Condensers on OG IH and OG II plants were opened, cleaned, and repaired
o Leaks in the OG I plant cooling tower basin were repaired
o OG IE plant cooling tower was repaired
o A preheater bypass was installed on the OG IH plant
o OG IE plant vaporizer was retubed
o An injection pump was replaced
A significant capital expenditures program was completed in 2003. It included:
o Complete overhaul of the GEM 2 plant, including a steam turbine rebuild
o Refurbishment of OG I and OG II plant cooling towers
o Purchase of a replacement air compressor
o Upgrade of plant control system Ovation software
o Telephone system upgrade
o Purchase of replacement electrical breakers
o Purchase of new vehicles
o Purchase of a forklift
The largest project completed at the site during 2003 was the modification at OG
I to replace the 24 old OECs with the two ITLUs. This improved the efficiency of
the brine utilization.
Ormesa has a staff of 55 full-time employees, which is greater than the other
Projects, but reflects greater generating capacity and larger well field and
brine piping systems. The majority of the staff is organized under the Plant
Operations Manager and represents 41 of the full-time employees. This group
consists of four designated production crews, maintenance technicians and a
performance optimization group. A separate group of five people are organized to
operate the well field. In addition, four people work in technical supports, and
the remaining five employees work in administrative positions.
Because of the different generating equipment configurations, Ormesa stocks a
substantial inventory of spare parts. The GEM plants have a spare steam turbine
rotor, a set of diaphragms, bearings, rupture disks and governor valve
- --------------------------------------------------------------------------------
Page 18
OPERATIONS AND MAINTENANCE
================================================================================
and stop valve components. Also in stock are a cooling tower fan motor, a set of
fan blades, various spare pump seals and motors, electro-hydraulic control and
Bailey DCS cards and a spare motor for the air compressor.
The plants have a spare OEC turbine, electrical generators, feed pumps and
motors, cooling water pumps and motors, cooling tower fan gearboxes and motors,
480V and 600V transformers, one injection pump and motors, brine valves,
preheaters, miscellaneous small pumps and motors and control cards. Spare parts
for the new equipment added at OG I have been acquired.
For the well field, the Project stocks one spare production pump, five
production pump motors, four seal water pumps, four oil pumps, two coolers, pump
seals, pump casing and shafting.
We consider that the operations and maintenance organization at Ormesa is
comprehensive and organized, and that normal equipment maintenance is being
conducted to the manufacturer's recommendations and to utility industry
practices.
3.3 BRADY AND DESERT PEAK
BRADY/DESERT PEAK COMBINED OPERATING STATISTICS
1998 1999 2000 2001 2002 2003
------ ------ ------ ------ ------ ------
Net Delivered Energy (GWh) 160.7 153.9 139.7 127.6 161.1 172.9
Availability Factor (%) 98.9 99.5 99.8 99.4 99.8 98.7
Mass Flow Rate (klb/hr) 5,907 5,650 5,517 4,987 5,373 N/A
Brine Inlet Temperature (Degree F) 318 315 311 311 309 N/A
The availability factors are consistently high for Brady and Desert Peak. During
the years 2000 and 2001, the delivered energy and brine flow show a decline.
This was a result of a change instituted by the previous owner in the manner in
which brine was reinjected. In 1999, to respond to falling brine temperatures,
it was decided to reinject the brine outside of the existing production field in
the hope that the production field would be recharged with hotter brine. During
this time, only a slight increase in brine temperature was measured, but there
was a significant drawdown of the brine resource in the production field. Once
this was observed, the injection of brine outside the production field was
halted and the previous injection procedures were reinstituted. As a result, the
resource level in the production field has been recovering, but brine
temperatures continue to decline.
Brady and Desert Peak are base load facilities with the peak generating
capability occurring in the winter and a reduced capability in the summer which
amounts to an approximate 24 percent reduction in output.
Normal annual maintenance requires that one steam turbine be opened, inspected,
cleaned and repaired every year. Since there are three steam turbines at Brady
and one steam turbine at Desert Peak, this translates into an inspection for
each machine every four years. During this outage, all of the turbine auxiliary
equipment is inspected, adjusted and recalibrated if necessary. The annual
maintenance procedure also requires that the steam separators, condensers,
cooling towers, air compressors and pumps are inspected, cleaned and repaired
and electrical equipment is analyzed and recalibrated.
The OEC has just completed its first year of operation. A routine maintenance
schedule that dictates when certain equipment is taken out of service will not
be used for this equipment. Instead an equipment monitoring program will
normally dictate when a maintenance outage is required on the basis of
performance degradation or other factors, such as vibration or leakages.
Brady and Desert Peak have a combined operating staff of 17 people, with the
majority of the staff working primarily at the Brady plant.
The most significant change to Brady occurred in 2002 when an OEC was added to
operate in a bottoming cycle. In addition, during 2002-2003 a number of pumps
and/or motors were replaced, the air ejector nozzles and bodies were replaced,
and work was done on the production wells.
- --------------------------------------------------------------------------------
Page 19
OPERATIONS AND MAINTENANCE
================================================================================
At present, the major spare parts consist of an injection pump, a condensate
pump, a cooling basin pump motor, a cooling fan motor, a cooling tower gear box,
a complete set of turbine bearings, seals and other parts for a turbine rebuild
and one spare refurbishable turbine rotor.
3.4 STEAMBOAT
STEAMBOAT 1 AND 1A OPERATING STATISTICS
1998 1999 2000 2001 2002 2003
------ ------ ------ ------ ------ ------
Net Delivered Energy (GWh) 51.4 48.2 42.3 46.9 46.1 44.7
Availability Factor (%) 99.9 99.1 96.8 99.9 99.6 95.3
Mass Flow Rate (GPM) 4,029 4,047 4,023 4,073 4,016 N/A
Brine Inlet Temperature-Unit 1 (Degree F) 322 320 320 318 316 N/A
Brine Inlet Temperature-Unit 1A (Degree F) 269 265 264 260 260 N/A
*N/A=budget numbers are not available
The data for Units 1 & 1A shows that delivered energy has dropped by about 10
percent over the past five years and well field temperatures have also
decreased. This deterioration in output is being addressed through the addition
of the Galena plant. Despite the drop in generation and temperatures,
availability numbers remain high, thus indicating that the plants are adequately
maintained.
STEAMBOAT 2 AND 3 OPERATING STATISTICS
1998 1999 2000 2001 2002 2003
------ ------ ------ ------ ------ ------
Net Delivered Energy (GWh) 259.1 253.0 253.4 253.9 242.0 243.0
Availability Factor (%) 99.8 99.7 99.4 99.7 97.7 99.0
Mass Flow Rate (klb/hr) 8,460 8,487 8,250 8,723 8,374 N/A
Brine Inlet Temperature (Degree F) 311 311 311 311 310 N/A
In general, the operating statistics for Steamboat 2 and 3 are good, featuring
high availability factors. During 2001 and 2002, more brine was required to
produce each GWh of generation. This increase in brine requirements was
attributable to higher average annual ambient air temperatures than experienced
in previous years.
Steamboat is a base load facility with the peak generating capability occurring
in the winter. Reductions in generating capability during the summer period can
be as high as 44 percent. This is primarily a result of the reduced generating
capability that occurs with plants utilizing air-cooled condensers during
periods of higher ambient temperatures.
Steamboat presently has a staff of 18 employees and has positions open for an
I&C technician and a maintenance employee.
An examination of the monthly operating reports shows that O&M expenditures tend
to be for consumables, such as chemicals and lubricants, and for pump rebuild
costs, fan belt replacements, small transformer replacements, valve repairs,
etc. that occur on a monthly basis, rather than the large expenditures
associated with annual or bi-annual maintenance outages.
The spare parts inventory consists primarily of replacement parts for Steamboat
2 & 3. The following are the significant spare components in the warehouse: a
turbine rotor and exciter, turbine bearings, turbine coupling, circulating water
pump motor, set of air cooler fan blades, six stage submersible pump and two
spare downhole pumps.
The plant and equipment all appeared to be well maintained and in good operating
condition during the site visit. Plant personnel are organized, experienced and
knowledgeable in geothermal plant operation.
- --------------------------------------------------------------------------------
Page 20
================================================================================
SECTION 4.0
ENVIRONMENTAL ASSESSMENT
4.1 MAMMOTH
The following operating permits, orders and license agreements are in place for
Mammoth G1, G2 and G3 and include permits and license agreements for the
geothermal well field operations:
PERMITTING AGENCY PERMIT NUMBER DESCRIPTION OF PERMIT
- ---------------------------------------- ---------------------------- --------------------------------------
Great Basin Unified Air Pollution 601, 602 , 583 & 575 Permits to Operate G1, G2, & G3
Control District
- ---------------------------------------- ---------------------------- --------------------------------------
Great Basin Unified Air Pollution 567,598,597,600,594,593, Permits to Operate Injection,
Control District 703,704,584,585,586,589, Production, Observation, Exploration
590,591,576,577,578,579, Wells
580,572,573,574,582, 1052,
1073
- ---------------------------------------- ---------------------------- --------------------------------------
CA Regional Water Quality Control Board Order No. 6-84-89 Waste Discharge Requirements Plant &
Board Injection Wells G1
- ---------------------------------------- ---------------------------- --------------------------------------
CA Regional Water Quality Control Board Waiver for Waste Discharge G2 & G3
Requirements
- ---------------------------------------- ---------------------------- --------------------------------------
CA Division of Oil & Gas Various Permits Report on Proposed Geothermal
Operations (Production & Injection
Wells) G1, G2 & G3
- ---------------------------------------- ---------------------------- --------------------------------------
CA Division of Oil & Gas Various Injection Permits Injection Reports
- ---------------------------------------- ---------------------------- --------------------------------------
CA Division of Oil & Gas Various Injection Permits Injection Profile Survey
- ---------------------------------------- ---------------------------- --------------------------------------
CA Division of Oil & Gas Production Well Start-up Pits HGC
Production Wells
- ---------------------------------------- ---------------------------- --------------------------------------
CA Division of Occupational Safety and Various Permits Permits to Operate Air Pressure Tanks
Health
- ---------------------------------------- ---------------------------- --------------------------------------
Mono County Planning Commission 36-81-57 Conditional Use Permit G1
- ---------------------------------------- ---------------------------- --------------------------------------
Mono County Planning Commission OIE-86-02 Conditional Use Permit G2
- ---------------------------------------- ---------------------------- --------------------------------------
Mono County License Agreement Monitoring Well No. CW 3
- ---------------------------------------- ---------------------------- --------------------------------------
Bonneville Pacific Corp. Mitigation Agreement Monitoring Well
- ---------------------------------------- ---------------------------- --------------------------------------
Los Angeles Dept. of Water & Power License Agreement Monitoring Well No. 28-34
- ---------------------------------------- ---------------------------- --------------------------------------
Bureau of Land Management #CA-017-P006-60 Record of Decision G3
- ---------------------------------------- ---------------------------- --------------------------------------
Bureau of Land Management # CACA 21918 Power Plant License G3
- ---------------------------------------- ---------------------------- --------------------------------------
Bureau of Land Management #CA-017-GUP8-37 Geothermal Utilization Permit for G3
Geothermal Project
- ---------------------------------------- ---------------------------- --------------------------------------
Bureau of Land Management #CA-017-P007-27 Plan of Baseline Data Collection
- ---------------------------------------- ---------------------------- --------------------------------------
Bureau of Land Management Plan for Monitoring Well Operation
- ---------------------------------------- ---------------------------- --------------------------------------
Available General Manager Monthly Status Reports and Monthly Production and
Injection Reports for the Mammoth Project were reviewed for the period of 2000
to 2003. The reported isobutane losses are within permit requirements. The
reports confirm that the plants and geothermal well field are being operated
within permit compliance and reporting requirements. Well site environmental
inspections, equipment safety, and environmental inspections are being conducted
as required.
Appropriate easements, leases and agreements are in place for geothermal
production and injection wells, with California Energy (Magma) for G1 and G2,
and the Bureau of Land Management (BLM) for G3. Well permits have been obtained
for geothermal production and injection wells and well modifications. Reporting
to the BLM and California Division of Oil and Gas on well operation is
considered current. Air quality permits for each well are current with the Great
Basin Unified Air Pollution Control District (GBUAPCD).
- --------------------------------------------------------------------------------
Page 21
ENVIRONMENTAL ASSESSMENT
================================================================================
The required certification and recertification with the FERC as a small power
production facility have been submitted and approved for G1, G2, and G3.
Each plant has an Air Quality Permit from the GBUAPCD. A Title V Air Quality
Operating Permit is not required since there are no air emission discharges from
the plants. The Air Quality Permit in place covers incidental isobutane releases
that may occur at the site. The isobutane releases from system leaks and losses
during repairs and modifications are being managed and are in compliance with
permit requirements. Modifications are being made during equipment and tubing
change-outs to reduce isobutane releases. Each production and injection well has
an Air Quality Permit from the GBUAPCD.
There are no outstanding compliance issues with any of the permits required for
plant and well field operation; therefore, it is expected that all permits will
be renewed at expiration. No permit issues were identified that will impact
future Mammoth operation.
Protection of the sensitive geothermal water supply for a fish hatchery and
geothermal spring's down-gradient of the Mammoth geothermal resources was a
major permitting requirement for Mammoth. Mammoth is required to perform
settlement monitoring and groundwater monitoring at designated locations to
evaluate the affects from management of the geothermal resources. This data is
provided to the U.S. Geological Survey (USGS) annually for analysis and
evaluation. The USGS has not identified any adverse impacts to sensitive areas
resulting from management of the geothermal resources for Mammoth.
The planned expansion for two production wells and a pipeline on a BLM lease
will be up-gradient of the existing geothermal resources being used for Mammoth
and should not have any adverse impact on the sensitive geothermal resource for
fish hatchery or geothermal springs. The requirement to protect this geothermal
resource has been taken into account in the BLM well permitting and pipeline
routing process. Permits for geothermal exploration drilling were received in
February 2002 from the BLM. The Plan of Development will be submitted to the BLM
in early 2004 for installation of two geothermal production wells. The
environmental assessment for the pipeline has been completed and the information
will be submitted to the BLM in January 2004. Mammoth has been working with the
BLM and US Fish and Wildlife to identify primary and alternate pipeline routes
to avoid sensitive environmental areas and maintain a low visibility for the
pipeline. The BLM will prepare and issue the formal environmental assessment
report (EA) for public comment and final issue. The existing monitoring program
will be expanded if required to assure that the new production wells and
pipeline will not have any adverse impact to sensitive geothermal resources. The
planned geothermal resource expansion for Mammoth should not have any adverse
impact to sensitive geothermal resources. No fatal flaws have been identified
during the initial well permitting and EA process. It is anticipated that the EA
process and BLM approval for the pipeline should be completed in the second
quarter of 2004.
4.2 ORMESA
The following operating permits and Board orders are in place for OG I, OG II,
OG IE, OG IH, GEM 2 and GEM 3 and include permits and Board orders for the
geothermal well field operation:
PERMITTING AGENCY PERMIT NUMBER DESCRIPTION OF PERMIT
- ------------------------------- ---------------- --------------------------------------------
Imperial County Air Pollution PTO 1716G Operating Permit - OG I Plant and 21 Wells
Control District
- ------------------------------- ---------------- --------------------------------------------
Imperial County Air Pollution PTO 1883E Operating Permit - OG II Plant and 14 Wells
Control District
- ------------------------------- ---------------- --------------------------------------------
Imperial County Air Pollution PTO 1942H Operating Permit - OG IE Plant and 7 Wells
Control District
- ------------------------------- ---------------- --------------------------------------------
Imperial County Air Pollution PTO 2047D Operating Permit - OG IH Plant and 8 Wells
Control District
- ------------------------------- ---------------- --------------------------------------------
Imperial County Air Pollution PTO 2002G Operating Permit - GEM and GEM 3 Plant and
Control District 39 Wells
- ------------------------------- ---------------- --------------------------------------------
- --------------------------------------------------------------------------------
Page 22
ENVIRONMENTAL ASSESSMENT
================================================================================
PERMITTING AGENCY PERMIT NUMBER DESCRIPTION OF PERMIT
- ----------------------------------- -------------------------- -------------------------------------------
Imperial County Air Pollution V-2002 Title V Operating Permit - GEM and GEM 3
Control District Plant and 39 Wells
- ----------------------------------- -------------------------- -------------------------------------------
Imperial County Public Health 46S-8660-03 GEM 2/3 Small Water Permit (Potable Water
Department Treatment System)
- ----------------------------------- -------------------------- -------------------------------------------
CA Regional Water Quality Control Board Order No. 00-103 Waste Discharge Order - OG I (Plant and
Board Well Field)
- ----------------------------------- -------------------------- -------------------------------------------
CA Regional Water Quality Control Board Order No. 00-090 Waste Discharge Order - OG II (Plant and
Board Well Field)
- ----------------------------------- -------------------------- -------------------------------------------
CA Regional Water Quality Control Board Order No. 00-102 Waste Discharge Order - OG IE (Plant and
Board Well Field)
- ----------------------------------- -------------------------- -------------------------------------------
CA Regional Water Quality Control Board Order No. 00-085 Waste Discharge Order - OG IH (Plant and
Board Well Field)
- ----------------------------------- -------------------------- -------------------------------------------
CA Regional Water Quality Control Board Order No. 00-101 Waste Discharge Order - GEM and GEM 3
Board (Plant and Well Field)
- ----------------------------------- -------------------------- -------------------------------------------
EPA Region 9 RCRA ID No. CA0000138271 OG I RCRA Small Generator Permit
- ----------------------------------- -------------------------- -------------------------------------------
EPA Region 9 RCRA ID No. CAD983613449 OG II RCRA Small Generator Permit
- ----------------------------------- -------------------------- -------------------------------------------
EPA Region 9 RCRA ID No. CAR000045096 GEM and GEM 3 RCRA Small Generator Permit
- ----------------------------------- -------------------------- -------------------------------------------
Bureau of Land Management #CA 17129 Power Plant License OG I
- ----------------------------------- -------------------------- -------------------------------------------
Bureau of Land Management #CACA 22405 Power Plant License OG IE
- ----------------------------------- -------------------------- -------------------------------------------
Bureau of Land Management #CA 20172 Power Plant License OG II
- ----------------------------------- -------------------------- -------------------------------------------
Bureau of Land Management #CA24678 Power Plant License OG IH
- ----------------------------------- -------------------------- -------------------------------------------
Bureau of Land Management #CACA22079 Power Plant License GEM 2 & 3
- ----------------------------------- -------------------------- -------------------------------------------
Available quarterly, semi-annual, and annual compliance monitoring reports for
Ormesa were reviewed for the period of 2000 to 2003. The reports confirm that
the plants and geothermal well field are being operated within permit compliance
and reporting requirements. Well site environmental inspections, equipment
safety, and environmental inspections are being conducted as required.
Long-term BLM leases have been obtained for geothermal production wells,
injection wells, pipelines, and power plants located on BLM property. These BLM
leases also contain the licenses for the respective power plant sites.
Appropriate air quality permits and waste discharge orders are in place for
operation of the geothermal production and injection wells. Permits were
obtained from the BLM for initial installation of geothermal production and
injection wells, well modifications, and pipelines. Monthly and quarterly
reporting requirements for the BLM Operations Reports and the California
Division of Oil and Gas for well operation are considered current. Air quality
permits for wells are current with the Imperial County Air Pollution Control
District (ICAPCD). The Imperial County Health Services monthly and quarterly
water monitoring reports are current. There are no outstanding compliance issues
identified in any of these reports, which will affect renewal of air permits,
Board orders on the BLM leases.
- --------------------------------------------------------------------------------
Page 23
ENVIRONMENTAL ASSESSMENT
================================================================================
OG I, OG II, OG IE and OG IH binary units have air quality permits from the
ICAPCD. A Title V Air Quality Operating Permit is not required for these plants
since there are no air emission discharges from the plants. The air quality
permits in place covers incidental isopentane releases that may occur at the
site. The isopentane releases from system leaks and losses during repairs and
modifications are being managed and are in compliance with permit requirements.
The air quality permit for each of these Ormesa facilities also includes
production and injection wells for the facility, and is renewed annually with
ICAPCD. There were no outstanding air quality issues identified at any of the
facilities.
GEM 2 and GEM 3 have two steam generating units and a Title V Operating Permit
from ICAPCD. This permit also includes the production, injection and observation
wells that support the facility. There are no outstanding air quality issues at
the GEM 2 and GEM 3 facility. The Title V Operating Permit is valid though
December 31, 2004 and has to be renewed in 2004. Air emission monitoring reports
indicate that the facility is in compliance with the permitted emission limits.
It is expected that the Title V Operating Permit will be renewed without issue
or any new conditions. The Change in Ownership/Redesignation was submitted by
Ormesa to the EPA in 2002 for the Title V Operating Permit and approval is still
pending from the EPA. The approval for ownership change by the EPA is routine
and does not affect operation of the project.
All California and EPA Resource Conservation Recovery Act (RCRA) small hazardous
generator permits are in place as required for the Ormesa facilities. The GEM
facility received a notice of violation during a site inspection by the
California Department of Toxic Substances Control (DTSC) on December 4, 2003.
Small spills of used oil were identified in the hazardous materials storage area
and at the brine pond. Ormesa worked with state regulators and had the
contaminated soil properly removed and disposed of by January 3, 2004. The
hazardous waste manifest to confirm closure of this violation was submitted to
the DTSC as required. This violation incident is considered minor and will not
affect the current permits or future renewal.
All geothermal brine is discharged into injection wells and is covered by waste
discharge orders issued by the CA Regional Water Quality Control Board. NPDES
permits are not required for the Ormesa facilities for discharge of treated
wastewater. All sanitary wastes are treated by permitted leach fields at each
facility. Cooling water blowdown is collected and discharged into dedicated
injection wells for wastewater blowdown, which have appropriate waste discharge
orders issued by the CA Regional Water Quality Control Board. Ormesa is current
with all monthly and quarterly reporting requirements for BLM Monthly Operations
Reports and Imperial County Health Service Department.
There are no outstanding compliance issues with any of the permits required for
plant and well field operation; therefore, it is expected that all permits will
be renewed at expiration. No permit issues were identified that will impact
future Ormesa operation.
4.3 BRADY AND DESERT PEAK
The following operating permits and agreements are in place for Brady and Desert
Peak and include permits and agreements for the geothermal well field operation:
PERMITTING AGENCY PERMIT NUMBER DESCRIPTION OF PERMIT
- -------------------------------- ------------------------------------------ -------------------------------
Nevada Bureau of Air Quality AP49911-0229 Class II Air Quality Operating
Permit - Brady Plant and
cooling tower system
- -------------------------------- ------------------------------------------ -------------------------------
Nevada Bureau of Air Quality AP4911-0503.01 Class II Air Quality Operating
Permit - Desert Peak Plant and
cooling tower system
- -------------------------------- ------------------------------------------ -------------------------------
Nevada Division of Environmental UNEV87050 Brady - Authorization to
Protection Inject/Discharge for 12
injection wells and surface
basins, Pond 1A
- -------------------------------- ------------------------------------------ -------------------------------
- --------------------------------------------------------------------------------
Page 24
ENVIRONMENTAL ASSESSMENT
================================================================================
PERMITTING AGENCY PERMIT NUMBER DESCRIPTION OF PERMIT
- -------------------------------- ------------------------------------------ -----------------------------
Nevada Division of Environmental UNEV40019 Desert Peak - Authorization to
Protection Inject/Discharge 1 injection
well, surface discharge area,
and evaporation basin.
- -------------------------------- ------------------------------------------ -------------------------------
Nevada Division of Wildlife S22502 Special License/Permit - Brady
- -------------------------------- ------------------------------------------ -------------------------------
Nevada State Fire Marshall 182-354 Brady - Hazardous Materials
Permit
- -------------------------------- ------------------------------------------ -------------------------------
Nevada State Fire Marshall 219-428 Desert Peak - Hazardous
Materials Permit
- -------------------------------- ------------------------------------------ -------------------------------
Churchill County Planning APN 004-031-01 & Special Use Permit - Brady
Commission - Nevada APN 004-031-13 Expansion from 18 to 22.5 MW
342895
- -------------------------------- ------------------------------------------ -------------------------------
State of Nevada Permit No.59711,57238,57239, Certificates of Appropriation
57240,57241,57243, 57245, of Water Permits - Brady
57287,57289,57297,60930,60931, geothermal production wells
62118,64485,64486,64487,64488
- -------------------------------- ------------------------------------------ -------------------------------
State of Nevada Permit No. 45397,46070,30886,46071,31002, Certificates of Appropriation
46586 of Water Permits - Desert Peak
geothermal production wells
- -------------------------------- ------------------------------------------ -------------------------------
A Special Use Permit from Churchill County was required and obtained for Brady.
Desert Peak was originally constructed as a research facility and thus was not
required to obtain a Special Use Permit from Churchill County.
Available compliance monitoring reports for Brady and Desert Peak were reviewed.
The reports confirm that the Brady and Desert Peak geothermal plants and
geothermal well fields are being operated within permit compliance and reporting
requirements.
The appropriate injection well permits are in place with the Nevada Division of
Environmental Protection (NDEP). Appropriate permits are in place with the State
of Nevada to appropriate the geothermal fluid for operation of the geothermal
well field. Inspections, production reporting, quarterly monitoring, and
injection well mechanical integrity reporting to the NDEP indicate that the well
fields for Brady and Desert Peak are being operated in compliance with permit
requirements.
Brady and Desert Peak are double-flash steam generation units and have Class II
Air Quality Operating Permits from the Nevada Bureau of Air Pollution Control
for air emissions from the power plants and cooling towers. The Class II Air
Quality Permit for Brady expires in March 2007 and the permit for Desert Peak
expires in September 2008. There are no outstanding air quality issues with
either of the facilities. A Title V Operating Permit is not required for either
Brady or Desert Peak.
A hazardous materials and storage permit is in place as required with the Nevada
State Fire Marshal for Desert Peak. There are no outstanding compliance issues
with this permit. Brady does not generate or store enough hazardous waste to
require a permit.
All geothermal brine is discharged into injection wells and covered by the
Injection/Discharge permits issued by the NDEP for Brady and Desert Peak. The
cooling tower wastewater blowdown for Brady is treated and discharged to a lined
evaporation pond in compliance with the NDEP Injection/Discharge permit. The
cooling tower wastewater
- --------------------------------------------------------------------------------
Page 25
ENVIRONMENTAL ASSESSMENT
================================================================================
blowdown for Desert Peak is treated and discharged to a surface basin within the
geothermal resource area in compliance with the NDEP Injection/Discharge permit.
There are no outstanding compliance issues with any of the permits required for
operation of Brady or Desert Peak plants and geothermal well fields; therefore,
it is expected that all permits will be renewed at their expiration dates. No
permit issues were identified that will impact future Brady or Desert Peak
operation.
4.4 STEAMBOAT
The following operating permits and agreements are in place for Steamboat 1, 1A,
2, and 3 and include permits and agreements for the geothermal well field
operation:
PERMITTING AGENCY PERMIT NUMBER DESCRIPTION OF PERMIT
- ----------------------------------------- -------------------------- ------------------------------------------
Air Quality Management Division, Washoe A01177A Permit to Operate Steamboat 1
County District Health Dept.
- ----------------------------------------- -------------------------- ------------------------------------------
Air Quality Management Division, Washoe A01440A Permit to Operate Steamboat 1A
County District Health Dept.
- ----------------------------------------- -------------------------- ------------------------------------------
Air Quality Management Division, Washoe A90A Permit to Operate Steamboat 2 and 3
County District Health Dept.
- ----------------------------------------- -------------------------- ------------------------------------------
Air Quality Management Division, Washoe 10216GS Permit to Operate Gasoline Dispensing
County District Health Dept. Facility
- ----------------------------------------- -------------------------- ------------------------------------------
Nevada Division of Environmental UNEV50018 Underground Injection Control Permit - 6
Protection injection wells
- ----------------------------------------- -------------------------- ------------------------------------------
NV State Fire Marshal 1697-3384 NV Hazardous Materials Storage Permit
- ----------------------------------------- -------------------------- ------------------------------------------
Fire Dept. City of Reno, NV 02467 Permit for Storage of
Flammable/Combustible Liquids and
Hazardous Production Materials
- ----------------------------------------- -------------------------- ------------------------------------------
Office of The Washoe County Clerk SPB2-3-84 Special Use Permit Steamboat 1 and 1A
- ----------------------------------------- -------------------------- ------------------------------------------
Office of The Washoe County Clerk SPB6-9-04 Special Use Permit Steamboat 2 and 3
- ----------------------------------------- -------------------------- ------------------------------------------
NV Division of Minerals 458PA Geothermal Project Area Permit,
Production and Injections Wells
- ----------------------------------------- -------------------------- ------------------------------------------
NV Division of Forestry Restoration Agreement Remedial and Restoration for Protection
of Endangered Steamboat Buckwheat Plant
- ----------------------------------------- -------------------------- ------------------------------------------
NV Division of Forestry Conditional Permit Permit for Disturbance Phase I BLM Towne
Parcel (1998)
- ----------------------------------------- -------------------------- ------------------------------------------
NV Division of Forestry Conditional Permit Permit for Disturbance Phase II BLM
Parcel Guisti (1998)
- ----------------------------------------- -------------------------- ------------------------------------------
Available compliance monitoring reports for Steamboat were reviewed.
Inspections, quarterly monitoring, and injection well mechanical integrity
reports to the NDEP and Nevada Division of Minerals indicate wells are being
operated in compliance with permit requirements. The reports confirm that the
plants and geothermal well field are being operated within permit compliance and
reporting requirements and there are no outstanding compliance issues.
Appropriate air quality permits and well injection permits are in place for
geothermal production and injection wells. Permits and approvals have been
obtained for injection wells, testing and well modifications.
Steamboat 1, 1A, 2 and 3 are binary units and have air quality permits from the
Air Quality Management Division, Washoe County District Health Dept. A Title V
Air Quality Operating Permit is not required for these plants since there are no
air emission discharges from the plants. The air quality permits in place cover
incidental isopentane releases that may occur at the site. The isopentane
releases from system leaks and losses during repairs and modifications are being
managed and are in compliance with permit requirements. The air quality permit
for each of
- --------------------------------------------------------------------------------
Page 26
ENVIRONMENTAL ASSESSMENT
================================================================================
the Steamboat facilities is renewed annually with the Air Quality Management
Division, Washoe County District Health Department. There are no outstanding air
quality issues with any of the facilities.
All hazardous materials and storage permits are in place as required for the
Steamboat facilities and there are no outstanding compliance issues with these
permits. Permits for hazardous materials are in place with the Nevada State Fire
Marshal and the Fire Department of Reno, NV.
All geothermal brine is discharged into injection wells and covered by a permit
from NDEP. NPDES permits are not required for Steamboat since the isopentane is
condensed by air coolers.
There are no outstanding compliance issues with any of the permits required for
plant and well field operation; therefore, it is expected that all permits will
be renewed at expiration. No permit issues were identified that will impact
future Steamboat operation.
The expansion for Steamboat 2 and 3 resulted in disturbance of the Steamboat
Buckwheat plant habitat in 1998. A Restoration Agreement between the Nevada
Division of Forestry and Steamboat was agreed to in October 2001 for restoration
and recovery of the Steamboat Buckwheat plant habitat. This Restoration
Agreement closes the notice of violation issued to Steamboat by the US Fish and
Wildlife Service office in Nevada in 2001. No legal action was warranted and no
further action is pending. This action is considered closed, with implementation
of the restoration program by Steamboat, as outlined in the Restoration
Agreement.
- --------------------------------------------------------------------------------
Page 27
================================================================================
SECTION 5.0
CONTRACTS AND AGREEMENTS
5.1 MAMMOTH
POWER PURCHASE AGREEMENTS
Mammoth entered into an Amended and Restated Power Purchase Sales Agreement (G1
PPA) with SCE on December 2, 1986 for the purchase and sale of the capacity and
net electrical output of G1, which replaced the original agreements executed on
October 20, 1983 and amended on December 30, 1983. The G1 PPA was amended on May
18, 1990. The G1 PPA term is for 30 years and expires in 2015. Base capacity
price is $0.0194 per kWh and is adjusted for capacity and availability factors.
Interconnection provisions for G1 were included as part of the G1 PPA and
specify that SCE is responsible for designing, providing, installing, operating,
and maintaining the electrical interconnects from G1 to SCE's grid.
Mammoth entered into a Long Term Power Purchase Agreement (G2 PPA) with SCE on
April 15, 1985 for the purchase and sale of the capacity and net electrical
output of G2. The G2 PPA was amended in October 1989 and December 1989. The G2
PPA term is for 30 years, expiring in 2020. G2 receives as-available capacity
payments of $235 per kW-year. No minimum performance levels are set in the G2
PPA for capacity payments. An Interconnection Facility Agreement was established
in the amendments.
Mammoth (as successor to Santa Fe Geothermal, Inc.) entered into a Long Term
Power Purchase Agreement (G3 PPA) with SCE on April 16, 1985 for the purchase
and sale of the capacity and net electrical output of G3. The G3 PPA was amended
in October 1985 and December 1989. The G3 PPA term is for 30 years, expiring in
2020. The monthly capacity payments are based on a contract capacity of 10 MW
and a contract capacity price of $187 per kW-year. G3 is also paid bonus
capacity payments, up to 18 percent of the capacity payment, based on the
capacity factor during peak months and periods. Both the capacity payments and
bonus capacity payments are subject to minimum performance requirements. An
Interconnection Facility Agreement was established in the amendments.
On November 30, 2001, SCE and Mammoth entered into three separate amended
Agreements Addressing Renewable Energy Pricing and Payment Issues, which
redefined the energy payment schedule for each of the three facilities for a
Fixed Rate Period beginning May 1, 2002 through April 2007. Under these amended
agreements, the energy price is at a fixed rate of $0.0537 per kWh. After this
period, the energy payments will be based on SCE's SRAC for the remaining period
of the contracts.
The capacity and energy payments under the PPAs are accurately reflected in the
Financial Projections.
PLANT OPERATING SERVICES AGREEMENT
The Plant Operating Services Agreement (Mammoth O&M Agreement), dated January 1,
1995, provides for the operation and maintenance of G1, G2 and G3 by Ormat
Nevada, Inc. The Mammoth O&M Agreement was originally signed by Pacific Power
Plant Operations (PPPO) and subsequently assigned to Ormat Nevada. The initial
term of the agreement was three years, and the agreement is subject to automatic
three-year extensions unless notice of termination is provided no later than 30
days prior to end of the term by Mammoth or 180 days prior to the end of the
term by Ormat Nevada. Additionally, either party can terminate the agreement
with 60 days notice, subject to requirements for extension if necessary to allow
for retention of a new operator. As started in a Letter Agreement, dated
December 17, 2003, Ormat Nevada cannot terminate the Mammoth O&M Agreement prior
to December 31, 2006.
The Mammoth O&M Agreement requires Ormat Nevada to provide operating and
maintenance services, with salaries and other costs subject to reimbursement by
Mammoth. Ormat Nevada's administrative costs are also subject to reimbursement.
These costs are accurately depicted in the Financial Projections.
- --------------------------------------------------------------------------------
Page 28
CONTRACTS AND AGREEMENTS
================================================================================
ELECTRICAL INTERCONNECTION AGREEMENTS
The agreements governing Mammoth's electrical interconnections with SCE are
discussed in Section 5.5.
5.2 ORMESA
POWER PURCHASE AGREEMENTS
The OG I Units (OG I, OG IE, OG IH) and OG II each have separate, but similar
PPAs and, unless otherwise noted, the following discussion applies to both.
On July 18, 1984, Republic Geothermal, Inc. entered into a Power Purchase
Contract (OG I PPA) with SCE, which was assigned to Ormesa Geothermal, Inc. on
July 22, 1985. Amendment I to the OG I PPA, dated December 23, 1988, adjusted
payments to provide more certainty to Ormesa and reduce overall cost to SCE.
Ormat Systems Inc. entered into a Power Purchase Contract (OG II PPA) with SCE
on June 13, 1984, which was assigned to Ormesa Geothermal, Inc. on April 30,
1987.
Due to disputes that occurred during the energy crisis in California, SCE did
not pay for energy delivered under the OG I and OG II PPAs during the period
from November 1, 2000 through March 26, 2001. Payments due totaled $14.1 million
and $7.1 million respectively. On June 19, 2001 (amended November 30, 2001), SCE
and Ormesa entered into Agreements for the OG I Units and OG II Addressing
Renewable Energy Pricing and Payment Issues in order to: 1) establish a
five-year fixed rate for energy (alternative SRAC), 2) establish an agreed upon
energy loss adjustment factor of 1.0, and 3) establish a payment schedule for
the unpaid energy delivered.
The OG I and OG II PPA's are in effect for 30 years from the COD. OG I's COD was
in December 1986, and OG II's COD was in December 1987. OG I is contracted to
deliver contract capacity of 31.5 MW to SCE's Mirage substation. The OG II PPA
contract capacity is 15 MW.
SCE is required to make monthly payments to Ormesa through a capacity payment
with provisions for a capacity bonus payment, an excess capacity payment, and an
energy payment. The monthly capacity payment is calculated using the contract
capacity price, contract capacity, a conversion factor, and a period performance
factor. Capacity price is $170/kW/yr for OG I and $184/kW/yr for OG II. Also,
Ormesa is eligible for a capacity bonus payment based on the on-peak capacity
factor exceeding 85 percent.
The monthly capacity payment and capacity bonus payment are contingent upon
Ormesa providing the contract capacity in each peak month for all on-peak hours
except for a 20 percent forced outage allowance each peak month. Ormesa is not
subject to any performance requirements during off-peak months.
Payment for capacity in excess of contract capacity is based on contract
capacity pricing. SCE is required to make a monthly energy payment equal to
SCE's short run avoided costs (SRAC), except during the period of May 1, 2002
through April 30, 2007, when energy rates are fixed at a weighted average of
5.37 cents per kWh.
SCE is allowed to curtail power purchases for up to 300 off-peak hours annually
during periods when purchases would exceed SCE's SRAC or when the SCE system
demand would require SCE hydro power be spilled to reduce generation. Ormesa has
indicated that curtailment at the Project has not occurred for the past three
years.
ELECTRICAL INTERCONNECTION AGREEMENTS
The agreements governing the Ormesa plants' electrical interconnections to IID
and SCE are discussed in section 5.5.
ENERGY SERVICES AGREEMENT
Ormesa entered into an Energy Services Agreement (ESA) with IID on February 11,
2003, which sets forth the terms and conditions for Ormesa's purchase of standby
services from IID and the responsibilities and cost allocations associated with
the distribution facilities and metering within the Ormesa site. The effective
date of the
- --------------------------------------------------------------------------------
Page 29
CONTRACTS AND AGREEMENTS
================================================================================
ESA is January 1, 2003 and the initial term is for 15 years, which can be
extended by mutual agreement of the parties.
The ESA supersedes the Interim Distribution Service Agreement dated March 8,
1999, whereby Ormesa elected to self-serve the electrical loads of the plant
within the Ormesa site. As mentioned elsewhere in this report, the GEM 2 and GEM
3 plants serve the production and re-injection system and plant auxiliary loads.
Ormesa and IID have agreed on 1) terms and conditions for which IID provides
standby services up to 2 MW to the Ormesa plants and well fields, and 2) a
simplified export metering scheme and a method to capture electrical services
provided by IID to Ormesa.
The ESA sets forth the design and compensation structure for the new metering
scheme, capital additions, standby services, operation and maintenance charges,
and distribution facilities charges (balance under the Interim Distribution
Service Agreement).
OPERATION AND MAINTENANCE AGREEMENT
Ormesa entered into an Operation and Maintenance Agreement (Ormesa O&M
Agreement) with Ormat Nevada Inc. on April 15, 2002 for operation and
maintenance of the Ormesa Project, including power plants and wells. The
Agreement remains in effect until expiration or termination of both Ormesa PPAs.
Ormesa is required to pay Ormat Nevada a fixed monthly fee of $830,000 (2002 $)
subject to annual adjustment based on the Consumer Price Index. The monthly fee
covers all costs associated with the ordinary maintenance of the Project
including labor, parts, consumables and fees, and costs of subcontractors. At
Ormat Nevada's request, the operation fee can be renegotiated every five years.
For Extraordinary Operation Expenses such as major equipment repair, maintenance
or modifications not due to operator negligence, Ormat Nevada is reimbursed the
actual cost and expenses, plus a 10 percent mark-up. There are no bonus or
performance incentive provisions in the Agreement. Costs are accurately
reflected in the Financial Projections.
At least sixty days prior to each calendar year, Ormat Nevada is required to
submit a proposed operating plan and budget including a monthly breakdown of
anticipated extraordinary operation expenses.
The Ormesa O&M Agreement sufficiently addresses the critical elements of the
Project's operation and maintenance. While there are no direct incentive
provisions, based on the ownership structure between the Parties and historical
performance, the Ormesa O&M Agreement appears to be adequate for continued
operation of the Project.
AMENDED AND RESTATED WATER SUPPLY AGREEMENT
An Amended and Restated Water Supply Agreement with IID was entered into on
March 6, 1990 to provide up to 10,000 acre-feet, annually, of Colorado River
water to the Project from IID's existing canal system. The Project is also
allowed to discharge drain water into the IID drainage system. The agreement
terminates upon the termination or expiration of the Project PPAs, but is not to
extend beyond March 6, 2020. Water rates are based on IID's current industrial
water rate. Discharge rates, also adjusted for current industrial rates apply to
drainage water in excess of 15 percent of the IID water used by the Project and
in excess of 5 percent of ground water pumped from wells. The Project is
responsible for any costs necessary to maintain or improve canal water retrieval
systems.
The Water Supply Agreement has been adequate to meet historical water
requirements at Ormesa.
5.3 BRADY AND DESERT PEAK
POWER PURCHASE AGREEMENT
On October 5, 1990, Brady Power Partners (BPP) (as successor to Nevada
Geothermal Power Partners) entered into a Long Term Agreement For The Purchase
And Sale Of Electricity with SPPC (The Brady PPA was amended on July 12, 1991
and June 24, 2002. The parties have also exchanged various correspondence and
entered into various consents and assignments which have modified some terms,
conditions and exhibits in the agreement since October 5, 1990.
- --------------------------------------------------------------------------------
Page 30
CONTRACTS AND AGREEMENTS
================================================================================
The term of the Brady PPA is 30 years from the Brady plant COD of August 20,
1992 resulting in a termination date of August 2022. Contract capacity ranges
from 17,700 to 19,900 kW monthly with an annual monthly average of 18,700 kW.
SPPC is obligated to purchase up to 188,877,610 kWh per year of energy at the
PPA rates. BPP has the right to market any energy above 188,877,610 Kwh per year
(Excess Energy). SPPC has the first right to purchase any Excess Energy. BPP has
the right to economically dispatch the Project for up to 6 million kWh per year
with SPPC, who has the right of first refusal to purchase this power.
Monthly capacity payments specified in the Brady PPA are (1) equal to the sum of
two-thirds times $20.25/kW-month and one-third times $14.62/kW-month for years
1-20 (through 2012) and (2) equal to the sum of two-thirds times $8.88/kW-month
and one-third times $6.41/kW- month thereafter. At the end of each contract
year, SPPC calculates the three-year rolling average of the peak period
capacity. If the average is below 95 percent and greater than or equal to 85
percent of the peak period value, then the capacity rate for the following year
is reduced 1.0 percent for each percent or portion thereof that the average is
below 100 percent. If the three-year rolling average is less than 85 percent,
then the Project may be permanently derated. A settlement agreement dated
February 16, 2001 and Amendment 2 provide for a one-time waiver of the
three-year rolling average calculation for the contract year ending August 2002.
Energy rates are based on deliveries during specified winter and summer seasons
for on-peak, mid-peak, and off-peak periods. Two-thirds of the energy rate is
escalated annually on a fixed (4 percent) basis and one-third of the energy rate
is escalated annually based on a three-year rolling average of the change in the
GDP deflator during the prior calendar year.
The Brady PPA is properly modeled in the Financial Projections.
SETTLEMENT AGREEMENT
On May 1, 2002, ConAgra Foods Inc. (ConAgra) entered into a Settlement Agreement
with BPP, ORNI 1, LLC, ORNI 2, LLC, Ormat Nevada, and Ormat Technologies, Inc.
to provide geothermal fluid to ConAgra's Gilroy food-processing plant, located
adjacent to the Project, between May 10 and December 10 of each calendar year.
The term of the Settlement Agreement expires on December 31, 2019. ConAgra
agrees to pay BPP on a monthly basis, an hourly fee of $30 for each hour that
the geothermal fluid is supplied with an annual cap of $154,080.
OPERATION AND MAINTENANCE AGREEMENT
BPP entered into an Operation and Maintenance Agreement (Brady O&M Agreement)
with Ormat Nevada Inc. on January 1, 2002 for operation and maintenance of the
BPP Project including power plants and wells. The agreement remains in effect
until expiration or termination of the Brady PPA. BPP is required to pay Ormat
Nevada a fixed monthly fee of $250,000 (2001 $) subject to annual adjustment
based on the Consumer Price Index. The monthly fee covers all costs associated
with the ordinary maintenance of the Project including labor, parts, consumables
and fees and costs of subcontractors. At Ormat Nevada's request, the operation
fee can be renegotiated every five years. For extraordinary operation expenses
such as major equipment repair, maintenance or modifications not due to operator
negligence, Ormat Nevada is reimbursed the actual cost and expenses plus a 10
percent mark-up. There are no bonus or performance incentive provisions in the
Agreement. Costs are accurately depicted in the Financial Projections.
At least sixty days prior to each calendar year, Ormat Nevada is required to
submit a proposed operating plan and budget including a monthly breakdown of
anticipated extraordinary operation expenses.
The Brady O&M Agreement sufficiently addresses the critical elements of the
Project's operation and maintenance. While there are no direct incentive
provisions, based on the ownership structure between the Parties and historical
performance of the identical Ormesa O&M Agreement, the Brady O&M Agreement
appears to be adequate for continued operation of the BPP Project.
- --------------------------------------------------------------------------------
Page 31
CONTRACTS AND AGREEMENTS
================================================================================
FLUID SUPPLY AGREEMENT
BPP entered into a Fluid Supply Agreement with Western States Geothermal Company
on December 15, 2003. The agreement obligates Western States Geothermal Company
to provide a sufficient supply of geothermal fluid to allow the Desert Peak 1
plant to produce 7 MW of capacity. The agreement is effective as of January 1,
2004 and remains in effect until the expiration or termination of the Brady PPA.
BPP is to pay Western States Geothermal Company 1.0 percent of the net revenues
of Desert Peak 1 derived directly from the sale of electricity under the Brady
PPA and reimbursement of all rents and royalties.
INTERCONNECTION AGREEMENTS
The Agreements governing the BPP Project electrical interconnection with SPPC
are discussed in Section 5.5.
5.4 STEAMBOAT
POWER PURCHASE AGREEMENTS
Steamboat 1 and 1A
On November 18, 1983, Steamboat (as successor to Geothermal Development
Associates) entered into an Agreement For The Purchase And Sale Of Electricity
(Steamboat 1 PPA) with SPPC. The Steamboat 1 PPA was amended on March 6, 1987.
The term of the Steamboat 1 PPA continues through December 5, 2006 and
thereafter continues year to year unless either party elects to terminate.
Energy and capacity rates are based on the SRAC rates in effect for each billing
period.
On October 29, 1988, Steamboat (as successor to Far West Capital, Inc.) entered
into a Long Term Agreement For The Purchase And Sale Of Electricity (Steamboat
1A PPA) with SPPC. The term of the Steamboat 1A PPA is 30 years from the COD of
December 1988, resulting in a termination date of 2018. Commencing on the tenth
anniversary of the plant's COD and continuing for the balance of the term,
payments are based on the Short Term Rates Cogeneration and Small Power
Production Schedule.
Ormat has indicated that upon completion of the Galena unit, a new PPA will be
negotiated to replace the existing Steamboat 1/1A PPAs. Ormat is negotiating a
PPA for the Galena Plant, which will, in part, replace the existing Steamboat
1/1A PPA. The Financial Projections represent the shift in revenues from
Steamboat 1/1A to Galena beginning in 2006.
Steamboat 2 and 3
Steamboat 2 and 3 each have separate, but essentially identical, PPAs. Unless
otherwise noted, the following description applies to both PPAs.
On January 24, 1991 and January 18, 1991 Steamboat (as successor to Far West
Capital, Inc.) entered into respective Long Term Agreements For The Purchase And
Sale Of Electricity (Steamboat 2 and Steamboat 3 PPAs) with SPPC. The Steamboat
2 PPA was amended on October 29, 1991 and October 29, 2002. Both amendments
addressed change in the COD of Steamboat 2. The October 29, 2002 amendment was
between SPPC and First Interstate Bank of Nevada, N.A. as Owner Trustee.
The term of the Steamboat 2 and 3 PPAs is 30 years from the COD of December 1992
resulting in a termination date of 2022. Contract capacity ranges from 9,140 to
13,460 kW monthly with an annual monthly average of 12,000 kW. Steamboat 2 and 3
have the right to economically dispatch each plant for up to 11.14 million kWh
per year with SPPC having the right of first refusal to purchase this power.
Capacity payments specified in the Steamboat 2/3 PPAs are $19.04/kW month for
years 1-14 and $14.00/kW month thereafter. At the end of each contract year,
SPPC calculates the three-year rolling average of the peak period capacity. For
years 1-14, if the average is below 95 percent and greater than or equal to 85
percent of the peak period value, then the capacity rate for the following year
is reduced 1.0 percent for each percent or portion thereof
- --------------------------------------------------------------------------------
Page 32
CONTRACTS AND AGREEMENTS
================================================================================
that the average is below 100 percent. For years 15-30, the capacity rate
reduction increases from 1.0 percent to 1.3 percent. If the three-year rolling
average of the peak capacity is less than 85 percent, then Steamboat is required
to pay SPPC $1.0 million (1992 $) in liquidated damages.
The energy base rate specified at the time the PPAs were executed was $0.025 per
kWh. The energy rate is escalated annually at a fixed 4.12 percent basis for
years 1-14 and at 3.0 percent for years 15-30.
The Steamboat 2 and 3 PPAs are properly modeled in the Financial Projections.
OPERATION AND MAINTENANCE AGREEMENT
ORNI 7, LLC and Steamboat Geothermal LLC entered into an Amended and Restated
Operation and Maintenance Agreement (Steamboat O&M Agreement) with Ormat Nevada
Inc. on December 8, 2003 for operation and maintenance of the Steamboat Project
power plants and wells, including Galena. Steamboat Development is to become a
party to the agreement as of the closing of the offering. The agreement remains
in effect until expiration or termination of the Steamboat PPAs. Upon completion
of the acquisition of Steamboat 2/3, Steamboat 1/1A/2/3 are to all be operated
and maintained under the same O&M agreement. Upon completion of the Galena
plant, its operations and maintenance are also to be governed by the same O&M
agreement with Ormat Nevada, Inc.
Steamboat is required to pay Ormat Nevada a fixed monthly fee of $246,250
subject to annual adjustment based on the Consumer Price Index. The monthly fee
covers all costs associated with the ordinary maintenance of the Project
including labor, parts, consumables and fees and costs of subcontractors. At
Ormat Nevada's request, the operation fee can be renegotiated every five years.
For extraordinary operation expenses such as major equipment repair,
maintenance, or modifications not due to operator negligence, Ormat Nevada is
reimbursed the actual cost and expenses plus a 10 percent mark-up. There are no
bonus or performance incentive provisions in the Agreement. Costs are accurately
reflected in the Financial Projections.
At least sixty days prior to each calendar year, Ormat Nevada is required to
submit a proposed operating plan and budget including a monthly breakdown of
anticipated extraordinary operation expenses.
The Steamboat O&M Agreement sufficiently addresses the critical elements of the
Project's operation and maintenance. While there are no direct incentive
provisions, based on the ownership structure between the parties and historical
performance of the identical Ormesa O&M Agreement, the Steamboat O&M Agreement
appears to be adequate for continued operation of the Project.
INTERCONNECTION AGREEMENTS
The agreements governing Steamboat's electrical interconnection with SPPC are
discussed in Section 5.5.
GALENA ENGINEERING PROCUREMENT AND CONSTRUCTION CONTRACT
Ormat Nevada, Inc. and ORNI 7 are negotiating an Engineering, Procurement and
Construction Contract (EPC Contract) for the completion of an approximately 22.7
MW geothermal power plant, to be named the Galena plant (Facility). The Galena
plant is an expansion of the Steamboat site. The $25.8 million in the Financial
Projections includes the debt, which is to be funded by proceeds from this
offer, and equity. A portion of the equity will be used by ORNI 7 to fulfill its
obligation under the EPC Contract.
Ormat Nevada agrees to provide development support, design, engineering,
procurement, construction, commissioning, and performance testing of Galena. The
EPC Contract sets forth more specific responsibilities of Ormat Nevada.
ORNI 7 agrees to, among other things, make available the site, arrange for
utilities, prepare all environmental assessments, provide operational support,
provide a geothermal heat resource in the time frame required by Ormat Nevada,
and to maintain and make available the geothermal piping gathering system. Stone
& Webster believes that ORNI 7 will be able to perform its obligations in a
manner that will support the construction, commissioning, testing and completion
of the Galena plant in accordance with the schedule set forth in the EPC
Contract. It is Stone &
- --------------------------------------------------------------------------------
Page 33
CONTRACTS AND AGREEMENTS
================================================================================
Webster's understanding that $25.8 million of the funds from the bond offering
will be used to capitalize the Galena plant. This level of funding should be
sufficient to support ORNI 7's obligation to complete the plant construction,
including the extension of the gathering system.
The Galena plant will operate as an integrated plant with the existing Steamboat
plants just as the 1, 1A, 2, and 3 plants are currently being operated. Prior to
the commencement of commissioning activities of the Galena plant, the Steamboat
1, 1A, 2, and 3 plants will have to shutdown to allow for the inter-tie of (i)
the geothermal piping gathering system and related valves and controls to the
Galena plant, (ii) the instrumentation and control system to the overall site
control room, and (iii) the Galena plant to the existing switchyard for export
of power to Nevada Power Co. (NPC). The shutdown of the existing Steamboat
plants is contemplated to be done during off-peak period for short durations;
the total duration of the shutdowns will most likely not exceed three days. Some
of the shutdowns can take place without taking Steamboat 2/3 off line, thus
minimizing the impact of any lost generation. Once testing starts that require
geothermal fluid to functionally test the Galena plant in preparation for
performance testing, Steamboat 1/1A will be shutdown, and the geothermal fluid
will be used to support Galena plant testing while maintaining flow to Steamboat
2/3 in order to maximize energy and capacity revenues during this transition
time.
The anticipated notice-to-proceed date is currently scheduled for February 15,
2004. Based on this date, the guaranteed completion date is May 30, 2005. Any
delay in the notice-to-proceed date could result in a slip in the interim
schedule milestones and the guaranteed completion date.
Compensation to Ormat Nevada is to be in accordance with a milestone payment
schedule. The milestone payment schedule set forth in the EPC Contract includes
nine payment events. The payment approval process is subject to approval by ORNI
7 and an independent engineer. It is expected that Stone & Webster will act as
independent engineer under the EPC Contract.
Acceptance of the facility is based on Ormat Nevada satisfying the conditions of
final acceptance. There are no provisions for mechanical completion or
substantial completion.
The EPC Contract includes testing provisions similar to those customarily
considered mechanical completion tests. It also includes tests for final
acceptance, which include a Net Electricity Delivery Test.
Liquidated damages for delay in final acceptance equal 0.2 percent per day for
each day that elapses between the guaranteed completion date and the final
acceptance date. Liquidated damages for failure to meet performance guarantees
are effective if the results of the performance test are more than 1.0 percent
below the performance guarantee. The liquidated damages are equal to 1.1 percent
of the contract price for each percentage point of capacity deficiency.
The Financial Projections do not account for energy revenues from the Galena
Plant until January 2006 which is seven months after the guaranteed completion
date of May 30, 2005. Stone & Webster believes that completion will occur by the
guaranteed completion date or very soon thereafter; therefore, the liquidated
damages for delay most likely will not have to cover lost revenues. ORNI 7's
costs in the event of completion delay are very minimal.
Under the EPC Contract, non-performance attributable to equipment is a
contractor risk, which is offset by the liquidated damages (LDs), which in turn
will be used to reduce bondholder debt. The performance of the Galena plant is
largely dependent upon two factors: plant design and the availability of
geothermal fluid with properties consistent with the design basis of the plant.
Based on our review of the EPC Contract scope of work and the plant design
details, we believe that if the plant is constructed in accordance with the EPC
Contract, the plant will be able to satisfy 1) the performance guarantee, 2) the
assumptions of capacity and production in the base case Financial Projections,
and 3) fulfill its performance obligations under the Galena PPA that is under
negotiation. Based on our review of the GeothermEx report, geothermal fluid with
properties consistent with the properties set forth in the plant design basis is
available. As stated in previous sections of this report, the Galena Plant will
rely on known and established geothermal resources with the Steamboat site.
Stone & Webster also believes there is margin in the base case Galena production
assumptions used in the Financial Projections relative to the design capacity.
This being said, Stone & Webster believes there is very little risk to the
bondholders attributable to plant non-performance.
- --------------------------------------------------------------------------------
Page 34
CONTRACTS AND AGREEMENTS
================================================================================
The warranty period extends for a period of 12 months from the final acceptance
date, and in the event there is re-work, the warranty will be extended for 12
months from the re-work date, but in no event is the total warranty period to
exceed 24 months.
5.5 PROJECTS INTERCONNECTION AGREEMENTS
The Projects have entered into various electrical interconnection arrangements
either through interconnection agreements, PPAs, plant connection agreements and
transmission services agreements. The agreements identify the responsible
parties, and provide the terms and conditions for designing, installing,
operating, and maintaining a connection from the plants to the bulk power grid.
Key technical aspects of the agreements include the contract capacity of the
interconnection, the physical location or point of interconnection,
identification of the portions of the interconnection supplied by the grid
owner, identification of the portions of the interconnection provided by the
generator, and costs and schedules, and responsibilities for construction of the
interconnection. As part of the design of the interconnection, system impact
studies (SIS) are performed to evaluate any negative impact to the design
ratings of existing equipment in the vicinity of the interconnection. Since the
interconnections for the Projects are completed and any mitigation of system
impacts has been addressed, discussion of interconnection activities prior to
construction completion or are not discussed further in this report.
The agreements that govern the electrical interconnection of the Projects are
summarized in Table 5-1.
TABLE 5-1
SUMMARY OF INTERCONNECTION AGREEMENTS
- --------------------- ---------------------------------------------------------
PLANT CURRENT INTERCONNECTION FACILITIES AGREEMENT
- --------------------- ---------------------------------------------------------
Mammoth G1 Amended and Restated Purchase and Sales Agreement between
Mammoth and SCE executed December 2, 1986.
- --------------------- ---------------------------------------------------------
Mammoth G2 Amendment 1 of the Power Purchase Contract between
Mammoth and SCE was executed on October 27, 1989.
- --------------------- ---------------------------------------------------------
Mammoth G3 Amendment No. 1 of the Power Purchase Contract between
Pacific Lighting Energy Systems and SCE was executed on
October 27, 1989.
- --------------------- ---------------------------------------------------------
GEM 2 Plant Connection Agreement for the Geo East Mesa Limited
Partnership Unit No. 2 between Imperial Irrigation
District and Geo East Mesa Limited Partnership dated
March 21, 1989, Transmission Service Agreement for the
Geo East Mesa Limited Partnership Unit No. 2 between
Imperial Irrigation District and Geo East Mesa Limited
Partnership, dated March 21, 1989.
- --------------------- ---------------------------------------------------------
GEM 3 Plant Connection Agreement for the Geo East Mesa Limited
Partnership Unit No. 2 between Imperial Irrigation
District and Geo East Mesa Limited Partnership, dated
March 21, 1989. Transmission Service Agreement for the
Geo East Mesa Limited Partnership Unit No. 3 between
Imperial Irrigation District and Geo East Mesa Limited
Partnership, dated March 21, 1989.
- --------------------- ---------------------------------------------------------
OG I Plant Connection Agreement for the Ormesa Geothermal
Plant between Imperial Irrigation District and Ormesa
Geothermal dated October 1, 1985, Transmission Service
Agreement for the Ormesa I, Ormesa IE and Ormesa IH
Geothermal Power Plants between Imperial Irrigation
District and Ormesa Geothermal dated October 3, 1989.
- --------------------- ---------------------------------------------------------
OG IE Plant Connection Agreement for the Ormesa IE
Geothermal Power Plant between Imperial Irrigation
District and Ormesa IE, dated October 3, 1989.
Transmission Service Agreement for the Ormesa I, Ormesa
IE and Ormesa IH Geothermal Power Plants between Imperial
Irrigation District and Ormesa Geothermal, dated October
3, 1989.
- --------------------- ---------------------------------------------------------
OG IH Plant Connection Agreement for the Ormesa IH
Geothermal Power Plant between Imperial Irrigation
District and Ormesa IH, dated October 3, 1989.
Transmission Service Agreement for the Ormesa I, Ormesa
IE and Ormesa IH Geothermal Power Plants between Imperial
Irrigation District and Ormesa Geothermal, dated October
3, 1989.
- --------------------- ---------------------------------------------------------
- --------------------------------------------------------------------------------
Page 35
CONTRACTS AND AGREEMENTS
================================================================================
- --------------------- ---------------------------------------------------------
PLANT CURRENT INTERCONNECTION FACILITIES AGREEMENT
- --------------------- ---------------------------------------------------------
OG II Power Purchase Contract between Southern California
Edison Company and Ormat Systems Inc. dated June 13,
1984, [Plant Connection Agreement dated May 26, 1987
between Ormesa and IID.]
- --------------------- ---------------------------------------------------------
OG I, OG IE, OG IH, IID-Edison Transmission Service Agreement for
OG II Alternative Resources between Imperial Irrigation
District and Southern California Edison, dated September
26, 1985, Amendment No 1, dated August 25, 1987.
- --------------------- ---------------------------------------------------------
Brady/Desert Amendment 2, dated June 17, 2002, to the Long Term
Peak Agreement for the Purchase and Sale of Electricity
between SPPC and Nevada Geothermal Power Partners
- --------------------- ---------------------------------------------------------
Steamboat 1 Agreement for the Purchase and Sale of Electricity
between SPPC and Geothermal Development Associates,
dated November 18, 1983.
- --------------------- ---------------------------------------------------------
Steamboat 1A Long Term Agreement for the Purchase and Sale of
Electricity between SPPC and Far West Capital, Inc.,
dated October 29, 1988. Special Facilities Agreement
between SPPC and Far West Capital, Inc., dated October
29 1988.
- --------------------- ---------------------------------------------------------
Steamboat 2 Long Term Agreement for the Purchase and Sale of
Electricity between SPPC and Far West Capital, Inc.,
dated January 24, 1991. Special Facilities Agreement
between SPPC and First Interstate Bank of Nevada, N.A.,
dated April 24, 1992.
- --------------------- ---------------------------------------------------------
Steamboat 3 Long Term Agreement for the Purchase and Sale of
Electricity between SPPC and Far West Capital, Inc.
dated January 18, 1991 Special Facilities Agreement
between SPPC and First Interstate Bank of Nevada, N.A.
dated April 24, 1992.
- --------------------- ---------------------------------------------------------
The Mammoth Project delivers its energy and capacity to SCE. The Ormesa Project
delivers its energy and capacity to SCE via IID. Both of these Projects are
subject to the same technical electrical interconnection requirements
established by SCE. Stone & Webster is not aware of any technical problem or
limitation with the electrical interconnections of the Mammoth and Ormesa
Projects.
The Brady/Desert Peak Project and the Steamboat Project deliver their energy and
capacity to SPPC. Both of these Projects are subject to the same technical
electrical interconnection requirements for small power producers established by
SPPC. Stone & Webster is not aware of any technical problem or limitation with
the electrical interconnection of the Brady/Desert Peak and Steamboat Projects.
- --------------------------------------------------------------------------------
Page 36
================================================================================
SECTION 6.0
FINANCIAL PROJECTIONS
Stone & Webster reviewed the Financial Projections for this bond offering. The
Financial Projections generate the income and cash flows for the Projects from
2004 through the end of the individual PPA terms. The resulting incomes and cash
flows from each Project are subsequently rolled together to generate
consolidated income and cash flow statements. Our review of the Financial
Projections focused on the reasonableness and completeness of the inputs for
determining capacity and energy production, operating costs, revenues, capital
expenditures, and consistency with the major Project documents. Stone & Webster
also reviewed the structure of the spreadsheet model and key mathematical
formulas for accuracy and consistency with project documents. Consolidated
income and cash flow statements prepared by Stone & Webster on the basis of the
Financial Projections are in Attachment II.
Due to uncertainties necessarily inherent in relying upon assumptions and
projections, it should be anticipated that actual operating results could
differ, perhaps materially, from those assumed and described herein.
6.1 REVENUES
The individual Project revenues are generated from the sale of capacity and
energy to their respective off-takers through a total of ten long-term PPAs. The
plants at the Mammoth, Ormesa, and Brady/Desert Peak sites are also capable of
earning capacity bonus payments based on meeting minimum performance
requirements. The projected capacity and energy payments to each Project are
consistent with the terms of the ten PPAs.
The percent distribution of the total annual revenues between the four Projects
is shown in the following table. On average, approximately 13 percent of the
total annual revenues realized by Ormat are from the Mammoth Project (accounting
for 50 percent of the total Mammoth Project revenues); 44 percent of the total
annual revenues are from the Ormesa Project; 15 percent of the total annual
revenues are from the Brady/DP Project; and 28 percent of the total annual
revenues are from the Steamboat Project.
TABLE 6-1
PERCENT DISTRIBUTION OF PROJECT REVENUES
PERCENT DISTRIBUTION OF TOTAL REVENUES
BETWEEN THE PROJECTS
---------------------------------------------------------------------------
5-YEAR 10-YEAR 17-YEAR
PROJECT 2004 2005 2006 AVERAGE AVERAGE AVERAGE
------- --------- --------- --------- ------------- ------------- ------------
MAMMOTH (50% OWNERSHIP)
Capacity Revenues (%) 3.0 3.0 2.9 3.0 3.0 2.9
Energy Revenues (%) 8.6 8.5 8.8 8.5 8.7 10.2
Bonus and Other (%) 0.7 0.7 0.7 0.7 0.7 0.7
--------- --------- --------- ------------- ------------- ------------
Net Revenues (%) 12.4 12.2 12.5 12.2 12.3 13.8
ORMESA
Capacity Revenues (%) 11.7 11.6 10.7 11.3 11.1 9.9
Energy Revenues (%) 34.4 33.8 30.8 31.2 31.3 29.8
Bonus and Other (%) 1.8 1.8 1.7 1.8 1.7 1.5
--------- --------- --------- ------------- ------------- ------------
Net Revenues (%) 47.9 47.3 43.1 44.2 44.2 41.2
BRADY AND DESERT PEAK
Capacity Revenues (%) 5.5 5.9 5.4 5.6 4.9 3.8
Energy Revenues (%) 10.6 10.7 9.9 10.6 10.8 12.0
Bonus and Other (%) 0.2 0.2 0.2 0.2 0.2 0.2
--------- --------- --------- ------------- ------------- ------------
Net Revenues (%) 16.2 16.8 15.5 16.4 16.0 16.0
STEAMBOAT
Capacity Revenues (%) 7.8 7.7 7.0 7.1 6.2 6.2
Energy Revenues (%) 15.6 16.1 21.9 20.1 21.3 22.9
Bonus and Other (%) 0.0 0.0 0.0 0.0 0.0 0.0
--------- --------- --------- ------------- ------------- ------------
Net Revenues (%) 23.5 23.8 29.0 27.2 27.5 29.1
- --------------------------------------------------------------------------------
Page 37
FINANCIAL PROJECTIONS
================================================================================
Energy revenues are based on the energy delivered to the respective off-taker.
Historic and projected energy production for each Project is graphically
presented in Attachment II. The following factors were taken into account for
projected energy production. It should be noted that in all instances where we
have cited resource characteristics and performance parameters, we have relied
upon the GeothermEx report and have not independently verified the properties or
reserve bases.
MAMMOTH
o Projected production for 2004 is 223,347 MWh. This value is consistent
with historic data.
o An increase of approximately 30,500 MWh of energy sales in 2006 reflects
the completion of the Mammoth Project Enhancement.
o After 2006, the resource is projected to decline at an annual value equal
to 1.1 percent of the 2006 production value. This percent reduction in
generation correlates to an assumed reduction of 1 Degree F in resource
temperature. Since 1998, the average generation decline has been about 1.0
percent with temperature reductions of approximately 1 Degree F per year.
ORMESA
o The 2004 base case assumption is a total production of 445,000 MWh. This
value is based on an increase in production resulting from modifications
made to the Project during 2003. This production level was successfully
demonstrated in 2003 via a seven-day acceptance test.
o The net generation is modeled to decline at a 1.0 percent annual rate.
This rate represents an annual temperature decline of 1 Degree F per year.
These assumptions are conservative given the past performance of the
Project and the operating methods practiced by Ormesa. Due to the number
of available wells and the plant configuration, Ormesa has a large degree
of operational flexibility that allows them to offset production losses
resulting from resource cooling, thus reducing the effect of resource
cooling.
BRADY AND DESERT PEAK
o The 2004 base case assumption is a total net electric energy production of
176,279 MWh with Brady contributing 129,279 MWh and Desert Peak
contributing 52,000 MWh. The net energy production includes the transfer
of steam to ConAgra, which is equivalent to 5,000 MWh per year. The Brady
contribution is consistent with historic data. The Desert Peak
contribution is based on historic data and the anticipated increase in
production resulting from reconfiguration of a well from injection to
production. January 2003 operating data confirm the ability of Desert Peak
to deliver 52,000 MWh.
o The Brady net generation is modeled to decline by 2.25 percent of the 2003
production level each year after 2003. This rate represents an annual
temperature decline of 2.5 Degree F per year. This reduction in energy
production is based on the theoretical fluid flow expected after ten years
assuming an annual temperature decline of 2.5 Degree F. The assumptions
used to determine the theoretical fluid flow and the effect on production
are conservative.
o The Desert Peak net generation does not decline in the model except for a
maintenance cycle every three years, which results in a production decrease
of 1,000 MWh. The reason that Desert Peak's net generation accounts for
this decrease is that it has a single turbine and generator that require
overhauls approximately every three years. The entire plant is shutdown for
this overhaul. Net generation is assumed to be constant due to the excess
geothermal reserves at the Desert Peak field.
STEAMBOAT
o Projected production for Steamboat 1/1A and Steamboat 2/3 for the years
2004 and 2005 are based on historic performance.
- --------------------------------------------------------------------------------
Page 38
FINANCIAL PROJECTIONS
================================================================================
o After 2005, the Financial Projections reflect the current operating plan
of redirecting all of the brine flow currently supplying Steamboat 1/1A
and one-third of the brine flow currently supplying Steamboat 2/3 to the
Galena plant. In the Financial Projections the construction of Galena is
expected to be completed by the beginning of 2006.
o Initial Galena output is projected to be 183,635 MWh (or approximately
21.5 MW) in 2006. This value is consistent with the heat balances
generated for the new unit based on review of the EPC Contract Scope Book
and associated flow diagrams and heat balances.
o Since one-third of the flow to Steamboat 2/3 will be redirected to Galena,
the expected Steamboat 2/3 production will be less the contractual
requirement of 210,000 MWh. To make up the shortfall, a portion of the
power generated by Galena will be credited to Steamboat 2/3. The Financial
Projections reflect a constant net production of 210,000 MWh at Steamboat
2/3. The projected Galena net production includes auxiliary loads at
Steamboat 2/3 and Galena and decreases in production resulting from
resource temperature declines. This treatment allows for maximum revenue
generation under the current PPAs.
o Energy revenues from Galena, starting in 2006, are based on an energy
payment of 5.2 cents per kWh escalated at 1.0 percent per year. No
capacity payments for Galena have been modeled in the Financial
Projections.
o The Galena plant is scheduled to be complete by May 31, 2005. After the
Galena plant is operational, the Steamboat Project energy production is
projected to decline at an annual value equal to 1.9 percent of the total
2006 net production. This decline corresponds to a temperature decline of
1.8 Degree F. This generation decline is consistent with historic data.
6.2 OPERATING EXPENSES
The Financial Projections include costs for O&M fees, field O&M, royalty and
lease payments, insurance and taxes. The operating costs generally appear
conservative and reasonable compared to historic expenses. The O&M and labor
expenses are escalated at 2 percent per annum.
6.3 MAJOR MAINTENANCE AND CAPITAL EXPENDITURES
Due to the modular design of the Projects, individual equipment units can be
overhauled without significantly affecting production and without resulting in
periodic spikes in overhaul and major maintenance expenses as typically observed
with standard fossil fuel electric generation plants. For these reasons, the
projected major maintenance expenses for the Projects are generally steady from
year to year and comprise less than 10 percent of the direct O&M expenses. The
thorough and prudent routine O&M program practiced at each Project also
contributes to lower major maintenance costs. Stone & Webster believes that the
projected major maintenance costs are reasonable on the basis of historic data
and the operating philosophies practiced by Ormat or its affiliate companies.
6.4 SENSITIVITY ANALYSIS
In geothermal projects, generally there are three primary elements that can
negatively affect energy production: 1) declining geothermal fluid flow, 2)
accelerated resource cooling and 3) increased equipment failures. It was agreed
by GeothermEx, Ormat and Stone & Webster that, on the basis of historic
operating data, a declining rate of geothermal fluid flow was less of a concern
for these four Projects than declining resource temperatures. Equipment failures
will affect the projects in two ways: 1) increased O&M costs and 2) decreased
equipment availability. Stone & Webster performed three sensitivity analyses to
determine the impact of declining resource temperatures, unexpected increases in
O&M costs and reduced equipment availability on the Financial Projections and
the debt service coverage ratios (DSCRs). Additionally, the effect of a decrease
SRAC energy rates was investigated. Results of the sensitivity analyses are set
forth in Table 6-2. The sensitivity analyses are described in more detail in the
following section.
- --------------------------------------------------------------------------------
Page 39
FINANCIAL PROJECTIONS
================================================================================
TABLE 6-2
SENSITIVITY ANALYSIS
PARAMETER SENSITIVITY MINIMUM DSCR AVERAGE DSCR
- ------------------------------------- ------------- ------------
Base Case 1.58 1.58
Accelerated Cooling 1.26 1.47
5% Increase in O&M Costs 1.50 1.51
2% Decrease in Availability 1.54 1.55
15% Decrease in SRAC Energy Rates 1.34 1.43
Accelerated Cooling/Increased O&M 1.20 1.40
Decreased SRAC Rates/Increased O&M 1.27 1.36
Note: The above sensitivity analysis assumes a total source of funds of
$190 million amortized until 2020 at a bond coupon rate of 8.25%.
ACCELERATED COOLING SENSITIVITY
An annual cooling rate and an appropriate accelerated rate for each site were
determined in discussions between GeothermEx, Ormat and Stone & Webster. Ormat
provided the relationships between the temperature decline and the reduction in
energy production listed in the following table. Stone & Webster confirmed these
relationships through review of historical production data.
TABLE 6-3
ACCELERATED COOLING SENSITIVITY
ANALYSIS PARAMETERS
BASE CASE ACCELERATED COOLING
RATE OF DECLINE RATE OF ANNUAL RATE OF ANNUAL TEMPERATURE
BASIC RELATIONSHIP(1) TEMPERATURE DECLINE DECLINE
- ------------ ----------------------- -------------------------- --------------------------
PLANT DEGREE F % MWH DEGREE F % MWH DEGREE F % MWH
- ------------ ------------ ----- ------------ ----- ------------ ------
Mammoth 1.0 Degree F 1.10% 1.0 Degree F 1.10% 1.5 Degree F 1.65%
Ormesa(2) 1.0 Degree F 1.00% 1.0 Degree F 1.00% 1.0 Degree F 1.00%
Brady 1.0 Degree F 0.90% 2.5 Degree F 2.25% 3.5 Degree F 3.15%
Desert Peak(3) 0.0 Degree F 0.00% 0.0 Degree F 0.00% 0.0 Degree F 0.00%
Steamboat 1.0 Degree F 1.10% 1.8 Degree F 1.98% 2.7 Degree F 2.97%
(1) Percent decline in production (MWh) associated with each degree decline in
resource temperature.
(2) No change from the base case temperature decline was assumed in the
accelerated cooling sensitivity case. The equipment and well configuration
at Ormesa allows for maximum operational flexibility, allowing Ormat to
have greater control over resource cooling than at the other three plants.
(3) The energy production at Desert Peak is assumed to be constant without
resource cooling. Since excess geothermal reserves are available at Desert
Peak, cooling trends can be offset by increasing geothermal fluid flow,
which allows for constant energy generation.
These assumptions provide a simplified approach for modeling the effect of
resource cooling on energy production. It should be noted that the rate of
resource cooling can vary from year to year and is dependent on a number of
factors including operating strategy and geological occurrences. The actual rate
of production decline at each property will be dependent on the actual rate of
resource cooling at each geothermal field. However, the assumed base case rates
of annual temperature decline and the associated declines in production outlined
in the table above appear to be conservative and consistent with historic data.
The accelerated cooling sensitivity assumes that accelerated cooling will be
experienced at all four projects. Although this would most likely not be the
case in reality, it presents the worse case scenario for the sensitivity
analysis.
- --------------------------------------------------------------------------------
Page 40
FINANCIAL PROJECTIONS
================================================================================
As a result of applying the accelerated cooling rates outlined above, the
average DSCR was decreased from 1.58 to 1.47.
O&M COST SENSITIVITY
O&M costs can be increased as the result of several factors, including, but not
limited to, increased equipment failures and increases in unit costs such as
labor, parts and consumables. For this O&M cost sensitivity analysis, the fixed
and variable O&M costs for each Project were increased by 5.0 percent. Once
again, the likelihood of O&M costs increasing at all four Projects is highly
unlikely, but this sensitivity presents a worse case scenario. The resulting
average DSCR is 1.51.
AVAILABILITY SENSITIVITY
The assumed availability of each plant in the Financial Projections is 95
percent. Stone & Webster considers this base case value to be conservative.
Historically, the availability at the four plants has been in excess of 98
percent. These high availabilities are the function of plant configurations and
Ormat's operating strategy of scheduling maintenance to maximize availability
and revenue. In most cases, there are multiple generating units at each site.
When one unit is taken out of service for either scheduled or unscheduled
maintenance, the effect on the overall availability and production tends to be
minimal. This is primarily because the geothermal fluid can be re-directed to
the other units for additional production from the operating units.
Additionally, equipment failures are infrequent and quickly repaired.
For these reasons, the availability sensitivity was based on a reduction in
availability of only 2 percent (from 95 percent to 93 percent). The average DSCR
is 1.55 with a minimum DSCR of 1.54.
SRAC ENERGY RATE SENSITIVITY
After April 2007, the energy rates paid to the Ormesa and Mammoth Projects by
SCE will be dependent on SCE's SRAC. This rate can vary depending on the market
conditions in the state of California. A sensitivity analysis was performed to
determine the effect of decreasing the SRAC by 15 percent. The average DSCR
decreased to 1.43 from the base case of 1.58.
COMBINED SENSITIVITY CASES
Two sensitivity cases were conducted to determine the effect of combining 1) the
increased O&M cost case with the accelerated cooling case and 2) the increased
O&M cost case with the decreased SRAC case. The minimum DSCR values are 1.20 and
1.27, with average DSCR values of 1.40 and 1.36, respectively. Stone & Webster
considers these two sensitivity cases to be extreme downside scenarios with a
very remote chance of occurrence; however, these two sensitivity cases do
demonstrate the robust nature of the Projects.
- --------------------------------------------------------------------------------
Page 41
================================================================================
ATTACHMENT I
DOCUMENTS REVIEWED
================================================================================
Attachment I
================================================================================
DOCUMENTS REVIEWED LIST
Lehman 144A Pro Forma and revisions through 1/22/04
Ormat Funding Corp Offering Memorandum and Revisions through 1/18/04
Ormat Funding Corp Contract Summaries and Revisions through 1/8/04
GeothermEx Report with Revisions through 1/16/04
Independent Technical Evaluation Covanta Geothermal Assets by Stone & Webster
for CSG Investments, Inc. November 2003
Mammoth Pacific G 1 Power Purchase Agreement dated October 20, 1983
Mammoth Pacific G 1 First Amendment to Power Purchase Agreement dated December
30, 1983
Mammoth Pacific G 1 Amended and Restated Power Purchase Agreement dated December
2, 1986
Amendment to Mammoth Pacific G 1 Amended and Restated Power Purchase Agreement
dated May 18, 1990
Mammoth Pacific G 2 Long Term Power Purchase Agreement dated April 15, 1985
Mammoth Pacific G 2 Amendment to Long Term Power Purchase Agreement dated
October 1989
Mammoth Pacific G 2 Amendment to Long Term Power Purchase Agreement dated
December 1989
Mammoth Pacific G 3 Long Term Power Purchase Agreement dated April 16, 1985
Mammoth Pacific G 3 Amendment to Long Term Power Purchase Agreement dated
October 1985
Mammoth Pacific G 3 Amendment to Long Term Power Purchase Agreement dated
December 1989
Mammoth Pacific G 1 Amended Agreement Addressing Renewable Energy Pricing and
Payment Issues dated November 30, 2001
Mammoth Pacific G 2 Amended Agreement Addressing Renewable Energy Pricing and
Payment Issues dated November 30, 2001
Mammoth Pacific G 3 Amended Agreement Addressing Renewable Energy Pricing and
Payment Issues dated November 30, 2001
Mammoth Plant Operating Services Agreement dated January 1, 1995
Letter Agreement dated December 17, 2003 re: O&M
Great Basin Unified Air Pollution Control District Permits to Operate G1, G2, &
G3
Great Basin Unified Air Pollution Control District Permits to Operate Injection,
Production, Observation, Exploration Wells
CA Regional Water Quality Control Board Waste Discharge Requirements Plant &
Injection Wells G1
CA Regional Water Quality Control Board Waiver for Waste Discharge Requirements
G2 & G3
CA Division of Oil & Gas Report on Proposed Geothermal Operations (Production &
Injection Wells) G1, G2 & G3
CA Division of Oil & Gas Injection Reports
CA Division of Oil & Gas Injection Profile Survey
CA Division of Oil & Gas Production Well Start-up Pits HGC Production Wells
CA Division of Occupational Safety and Health Permits to Operate Air Pressure
Tanks
Mono County Planning Commission Conditional Use Permit G1
Mono County Planning Commission Conditional Use Permit G2
Mono County Monitoring License Agreement Well No. CW 3
Bonneville Pacific Corp. Mitigation Agreement Monitoring well
Los Angeles Dept. of Water & Power License Agreement Monitoring Well No. 28-34
Bureau of Land Management Record of Decision G3
Bureau of Land Management Power Plant License G3
Bureau of Land Management Geothermal Utilization Permit for G3 Geothermal
Project
Bureau of Land Management Plan of Baseline Data Collection
Bureau of Land Management Plan for Monitoring Well Operation
Harris Group Inc. East Mesa Report 12/31/02
Harris Group Inc. Report - East Mesa Performance Test Results
IID Participants Memorandum of Understanding dated August 1, 1986
Interim Distribution Service Agreement Between IID and East Mesa dated March 8,
1999
MOU between IID and Ormesa dated November 21, 2002
Amended and Restated Water Supply Agreement between IID and Trigor Geothermal
dated March 6, 1990
Operation and Maintenance Agreement between Ormesa LLC and Ormat Nevada dated
April 15, 2002
Energy Services Agreement between IID and Ormesa dated February 11, 2003
Plant Connection Agreement between IID and Ormesa Geothermal dated October 1,
1985
Plant Connection Agreement between IID and Ormesa IH dated October 3, 1989
- --------------------------------------------------------------------------------
Page 1
Attachment I
================================================================================
Plant Connection Agreement between IID and Ormesa IE dated October 21, 1988
Plant Connection Agreement between IID and Ormesa Geothermal II dated May 26,
1987
Plant Connection Agreement between IID and Geo East mesa Limited re GEM 2 plant
dated March 2, 1989
Plant Connection Agreement between IID and Geo East Mesa Limited re GEM 3 plant
dated March 2, 1989
Transmission Services Agreement between IID and Geo East Mesa No. 2 dated March
21, 1989
Transmission Services Agreement between IID and Geo East Mesa No. 3 dated March
21, 1989
Transmission Services Agreement between IID and Ormesa Geothermal for Ormesa I,
IE, IH dated October 3, 1989
Transmission Services Agreement for Alternate Resources between IID and SCE
dated September 26, 1985
Amendment No. 1 for the Transmission Services Agreement for Alternate Resources
between IID and SCE dated August 25, 1987
Power Purchase Contract between SCE and Republic Geothermal dated July 18, 1984
(OG I)
Amendment 1 to the Power Purchase Contract between SCE and Republic Geothermal
dated December 23, 1988
Agreement Addressing Renewable Energy Pricing and Payment Issues between SCE and
Ormesa dated June 19, 2001 (OG I)
Amendment 1 to the Agreement Addressing Renewable Energy Pricing and Payment
Issues between SCE and Ormesa dated November 21, 2001
Power Purchase Contract between SCE and Ormat Systems dated June 13, 1984 (OG
II)
Agreement Addressing Renewable Energy Pricing and Payment Issues between SCE and
Ormesa dated June 19, 2001 (OG II)
Amendment 1 to the Agreement Addressing Renewable Energy Pricing and Payment
Issues between SCE and Ormesa dated November 21, 2001 (OG II)
Covanta Energy Geothermal Assets IM
East Mesa Geothermal Description of Maintenance Program
East Mesa Plant Equipment List
East Mesa Inventory
East Mesa Field Map
East Mesa Scope of Work for GEM 2 Steam Turbine Overhaul Conducted in 2003
Ormesa Geothermal Project Information Package
Ormesa 2003 Training Schedule
Ormesa Operating Statistics 1999-2002
Ormesa Quarterly Operating Reports 2001 and 2003
Ormesa Monthly Production Reports December 2000, 2001, 2002
Ormesa 2003 CapEx and MM
Ormesa 2003 Budget vs Actual
Ormesa 2004 Approved Budget
Ormesa BLM Lease Numbers and Areas for Wellfield and Plants
Imperial County Air Pollution Control District Operating Permit - OG I Plant and
21 Wells
Imperial County Air Pollution Control District Operating Permit - OG II Plant
and 14 Wells
Imperial County Air Pollution Control District Operating Permit - OG IE Plant
and 7 Wells
Imperial County Air Pollution Control District Operating Permit - OG IH Plant
and 8 Wells
Imperial County Air Pollution Control District Operating Permit - GEM and GEM 3
Plant and 39 Wells
Imperial County Air Pollution Control District Title V Operating Permit - GEM
and GEM 3 Plant and 39 Wells
Imperial County Public Health Department GEM 2/3 Small Water Permit (Potable
Water Treatment System)
CA Regional Water Quality Control Board Waste Discharge Order - OG I (Plant and
Well Field)
CA Regional Water Quality Control Board Waste Discharge Order - OG II (Plant and
Well Field)
CA Regional Water Quality Control Board Waste Discharge Order - OG IE (Plant and
Well Field)
CA Regional Water Quality Control Board Waste Discharge Order - OG IH (Plant and
Well Field)
CA Regional Water Quality Control Board Waste Discharge Order - GEM and GEM 3
(Plant and Well Field)
EPA Region 9 OG I RCRA Small Generator Permit
EPA Region 9 OG II RCRA Small Generator Permit
EPA Region 9 GEM and GEM 3 RCRA Small Generator Permit
Long Term Agreement for the Purchase and Sale of Electricity between Nevada
Geothermal Power Partners and SPPC dated October 5, 1990
Amendment to the Long Term Agreement for the Purchase and Sale of Electricity
between Nevada Geothermal Power Partners and SPPC dated July 12, 1991
Amendment No. 2 to the Long Term Agreement for the Purchase and Sale of
Electricity between Brady Power
- --------------------------------------------------------------------------------
Page 2
Attachment I
================================================================================
Partners and SPPC dated June 24, 2002
Settlement Agreement between ConAgra Foods Inc. and Brady Power Partners, ORNI
1, LLC, ORNI 2, LLC, Ormat Nevada, and Ormat Technologies, Inc. dated May 1,
2002
Fluid Supply Agreement between Brady Power Partners and Western States
Geothermal Company dated December 15, 2003
Operation and Maintenance Agreement between Brady Power Partners and Ormat
Nevada Inc. dated January 1, 2002
Ormat Funding Corp Information Memorandum Brady Operating Budget 1999, 2003
Brady DP Operating Statistics 1998-2002
BPP 2004 Consolidated Approved Budget Desert Peak Process Manual
Brady/Desert Peak Org Chart
Brady O&M
Section 9 Maintenance Instructions
Brady-Desert Peak Consolidated Maintenance
Plan
BPP Budget Summary Sheets and Variance Reports 99-04
BPP Generation and
Production Reports November 02-November 03
OEC General Description and Technical Data
Desert Peak One-Line, Process Flow and Heat & Mass Balance Diagrams
Nevada Bureau of Air Quality Class II Air Quality Operating Permit - Brady Plant
and cooling tower system
Nevada Bureau of Air Quality Class II Air Quality Operating Permit - Desert Peak
Plant and cooling tower system
Nevada Division of Environmental Protection Brady - Authorization to
Inject/Discharge for 12 injection wells and surface basins, Pond 1A
Nevada Division of Environmental Protection Desert Peak - Authorization to
Inject/Discharge 1 injection well, surface discharge area, and evaporation
basin.
Nevada Division of Wildlife Special License/Permit - Brady
Nevada State Fire Marshall Brady - Hazardous Materials Permit
Nevada State Fire Marshall Desert Peak - Hazardous Materials Permit
Churchill County Planning Commission - Nevada Special Use Permit - Brady
Expansion from 18 to 22.5 MW
State of Nevada Certificates of Appropriation of Water Permits - Brady
geothermal production wells
State of Nevada Certificates of Appropriation of Water Permits - Desert Peak
geothermal production wells
Ormat Brady Permit Review
Agreement for the Purchase and Sale of Electricity between Geothermal
Development Associates and SPPC dated November 18, 1983 (Steamboat 1 PPA)
Amendment to the Agreement for the Purchase and Sale of Electricity between
Geothermal Development Associates and SPPC dated March 6, 1987
Long Term Agreement for the Purchase and Sale of Electricity between Far West
Capital and SPPC dated October 29, 1988 (Steamboat 1A PPA)
Special Facilities Agreement between SPPC and Far West Capital, Inc. dated
October 29, 1988
Long Term Agreement for the Purchase and Sale of Electricity between Far West
Capital and SPPC dated January 24, 1991 (Steamboat 2 PPA)
Amendment 1 to Long Term Agreement for the Purchase and Sale of Electricity
between Far West Capital and SPPC dated October 29, 1991
Amendment 2 to Long Term Agreement for the Purchase and Sale of Electricity
between First Interstate Bank of Nevada and SPPC dated October 29, 2002
Long Term Agreement for the Purchase and Sale of Electricity between Far West
Capital and SPPC dated January 18, 1991 (Steamboat 3 PPA)
Special Facilities Agreement between First Interstate Bank of Nevada, N.A. and
SPPC dated April 24, 1992 (Steamboat 2/3)
Amended and Restated Operation and Maintenance Agreement between ORNI 7, LLC and
Steamboat Geothermal LLC dated December 8, 2003
Agreement Regarding Use of Water Supply between Steamboat Development Corp and
US Energy Geothermal, LLC dated June 30, 2003
Nevada PUC Consent to Changes in SB 1/1A Pricing from SRAC to COB
- --------------------------------------------------------------------------------
Page 3
Attachment I
================================================================================
Monthly Manager Reports SB 2/3 (Jan 99-Nov 03)
Monthly Manager Reports SB 1/1A (Dec 01-Oct 03) SB 2/3
Monthly Budget Projections (99-02)
SB 2/3 Performance Data (97-03) and Galena Estimate
SB 1/1A Plant Operating Procedures
SB Site Layout and P&IDs Steamboat One Line Diagrams
SB 2/3 Spare Parts List
SB Staffing Chart
Inventory of Parts at Steamboat 2/3
Galena EPC Contract 12/11 with Revisions 12/15, 12/17, 12/22, 12/29, 1/13, 1/18
Galena Long Term firm Power Purchase Agreement Drafts 12/15/03, 1/19/04
Division of Minerals Compliance Report Oct 03
SB 2/3 Emissions Monitoring 10/9/03
UIC Permit Quarterly Report 11/03
Air Quality Management Division, Washoe County District Health Dept. Permit to
Operate Steamboat 1
Air Quality Management Division, Washoe County District Health Dept. Permit to
Operate Steamboat 1A
Air Quality Management Division, Washoe County District Health Dept. Permit to
Operate Steamboat 2 and 3
Air Quality Management Division, Washoe County District Health Dept. Permit to
Operate Gasoline Dispensing Facility
Nevada Division of Environmental Protection Underground Injection Control Permit
- - 6 injection wells
NV State Fire Marshal NV Hazardous Materials Storage Permit
Fire Dept. City of Reno, NV Permit for Storage of Flammable/Combustible Liquids
and Hazardous Production Materials
Office of The Washoe County Clerk Special Use Permit Steamboat 1 and 1A
Office of The Washoe County Clerk Special Use Permit Steamboat 2 and 3
NV Division of Minerals Geothermal Project Area Permit, production and
injections wells
NV Division of Forestry Remedial and Restoration for protection of endangered
Steamboat buckwheat plant
NV Division of Forestry Permit for disturbance Phase I BLM Towne Parcel (1998)
NV Division of Forestry Permit for disturbance Phase II BLM Parcel Guisti (1998)
- --------------------------------------------------------------------------------
Page 4
================================================================================
ATTACHMENT II
FINANCIAL PROJECTIONS
================================================================================
BASE CASE
SCHEDULE OF DEBT COVERAGE RATIOS
AMOUNTS IN THOUSANDS
2004 2005 2006 2007 2008 2009 2010 2011
------- ------- ------- ------- ------- ------- ------- -------
SOURCES OF CASH
Energy Payments 42,087 48,313 54,405 51,305 50,575 52,269 53,409 54,636
Capacity Payments 17,054 19,804 19,957 19,943 18,479 18,464 18,436 18,345
Bonus & Other Payments 1,691 1,852 1,874 1,882 1,891 1,908 1,925 1,941
Working Capital (1,711) (580) (461) 322 284 (101) (5) (48)
------- ------- ------- ------- ------- ------- ------- -------
TOTAL SOURCES OF CASH 59,121 69,389 75,776 73,452 71,229 72,540 73,764 74,873
------- ------- ------- ------- ------- ------- ------- -------
CASH OPERATING COSTS
Plant & Field O&M 21,169 24,687 25,672 26,197 26,732 27,278 27,836 28,405
Other O&M Including MM 5,143 5,158 5,243 4,947 5,296 5,048 5,367 5,195
Owner's Costs 3,522 3,507 4,188 4,054 3,887 3,957 4,043 4,134
Property&Other Taxes 1,075 1,288 1,280 1,177 1,105 1,058 1,011 965
------- ------- ------- ------- ------- ------- ------- -------
TOTAL CASH OPERATING COSTS 30,909 34,640 36,383 36,374 37,020 37,341 38,258 38,699
------- ------- ------- ------- ------- ------- ------- -------
NET OPERATING CASH FLOW 28,212 34,748 39,392 37,078 34,209 35,199 35,507 36,175
------- ------- ------- ------- ------- ------- ------- -------
Debt Service of Ormesa Loan 4,784
NETCASH FOR BONDS REPAYMENT 23,428 34,748 39,392 37,078 34,209 35,199 35,507 36,175
DEBT SERVICE
Principal Payments 511 6,090 9,611 8,932 7,835 9,141 10,118 11,410
Interest Expense 13,897 15,725 15,144 14,354 13,629 12,947 12,162 11,290
Agent & Other Fees 200 203 206 209 212 215 219 222
------- ------- ------- ------- ------- ------- ------- -------
TOTAL DEBT SERVICE 14,609 22,018 24,961 23,494 21,676 22,304 22,499 22,922
------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio 1.60 1.58 1.58 1.58 1.58 1.58 1.58 1.58
======= ======= ======= ======= ======= ======= ======= =======
Less: Subordinated Fees 0 0 0 0 0 0 0 0
------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio with Subordination 1.60 1.58 1.58 1.58 1.58 1.58 1.58 1.58
======= ======= ======= ======= ======= ======= ======= =======
2012 2013 2014 2015 2016 2017 2018 2019 2020
------- ------- ------- ------- ------- ------- ------- ------- -------
SOURCES OF CASH
Energy Payments 55,202 56,696 58,877 61,969 62,339 62,889 43,971 33,990 33,973
Capacity Payments 16,012 15,943 15,864 75,343 15,171 15,080 9,628 6,793 6,712
Bonus & Other Payments 1,958 1,976 1,994 2,013 1,924 1,937 1,160 686 696
Working Capital 215 (50) (106) (144) 63 34 1,113 366 34
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL SOURCES OF CASH 73,387 74,565 76,630 79,181 79,498 79,940 55,872 41,835 41,414
------- ------- ------- ------- ------- ------- ------- ------- -------
CASH OPERATING COSTS
Plant & Field O&M 28,986 29,578 30,183 30,800 31,430 32,073 19,643 13,095 13,372
Other O&M Including MM 5,271 5,348 5,427 5,506 5,588 5,670 5,091 2,247 2,288
Owner's Costs 4,170 4,715 4,810 4,905 4,973 5,032 4,685 3,854 3,786
Property&Other Taxes 919 873 828 783 739 696 654 649 632
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL CASH OPERATING COSTS 39,345 40,514 41,248 41,995 42,730 43,471 30,073 19,844 20,078
------- ------- ------- ------- ------- ------- ------- ------- -------
NET OPERATING CASH FLOW 34,041 34,051 35,382 37,186 36,768 36,469 25,799 21,991 21,336
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Service of Ormesa Loan
NETCASH FOR BONDS REPAYMENT 34,041 34,051 35,382 37,186 36,768 36,469 25,799 21,991 27,336
DEBT SERVICE
Principal Payments 11,001 11,943 13,821 16,165 17,271 18,549 13,234 11,890 12,477
Interest Expense 10,343 9,404 8,366 7,162 5,788 4,317 2,874 1,795 788
Agent & Other Fees 225 229 232 236 239 243 246 250 254
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL DEBT SERVICE 21,570 21,576 22,420 23,563 23,298 23,108 16,354 13,934 13,519
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio 1.58 1.58 1.58 1.58 1.58 1.58 1.58 1.58 1.58
======= ======= ======= ======= ======= ======= ======= ======= =======
Less: Subordinated Fees 0 0 0 0 0 0 0 0 0
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio with Subordination 1.58 1.58 1.58 1.58 1.58 1.58 1.58 1.58 1.58
======= ======= ======= ======= ======= ======= ======= ======= =======
BASE CASE
Pro-forma Projected Statement of Cash Flow
for the Periods Indicated
In thousands of dollars
2004 2005 2006 2007 2008 2009 2010 2011
------- ------- ------- ------- ------- ------- ------- -------
Book Pre-tax Income (Loss) 3,914 5,620 10,723 8,412 7,001 9,055 10,049 11,628
Depreciation 9,680 12,291 12,291 12,291 12,291 12,291 12,291 12,291
Amortization 1,304 1,490 1,490 1,490 791 791 791 791
Income Tax Payments -- -- -- -- -- -- -- --
Change in Receivables (1,591) (761) (522) 259 182 (141) (94) (96)
Change in Payables 295 294 89 19 74 25 73 33
Change in Prepaid Expenses (414) (113) (28) 44 28 16 16 15
------- ------- ------- ------- ------- ------- ------- -------
Cash Flow From Operations 13,187 18,820 24,043 22,515 20,368 22,037 23,126 24,663
------- ------- ------- ------- ------- ------- ------- -------
Debt Funded (Assumed) --
Equity Contributions 17,878 2,150
Uses of Capital (17,878) (2,150)
Sr. Debt 144A (511) (6,090) (9,611) (8,932) (7,835) (9,141) (10,118) (11,410)
UC Loan (3,856)
Cash from Financing Activities
Cash Generated During Period
Reserve Fund Withdrawals 12,948 15,200 24,777 23,426 20,055 21,941 22,916 25,341
Reserve Fund (Payments) (13,187) (16,670) (24,043) (22,515) (20,368) (22,037) (23,126) (24,663)
Less Capital Investment (1,647) -- -- (1,000) -- -- -- (1,000)
Reclamation Fund (31) (31) (31) (31) -- -- -- --
------- ------- ------- ------- ------- ------- ------- -------
Beginning Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- -------
Cash Balance Before Distribution 9,403 13,729 17,635 15,963 14,720 15,300 15,298 15,430
------- ------- ------- ------- ------- ------- ------- -------
Cash (Distributions) Calls* (6,903) (11,229) (15,135) (13,463) (12,220) (12,800) (12,798) (12,930)
------- ------- ------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- ------- ------- -------
Ending Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- -------
2012 2013 2014 2015 2016 2017 2018 2019 2020
------- ------- ------- ------- ------- ------- ------- ------- -------
Book Pre-tax Income (Loss) 10,175 11,386 13,807 16,850 17,595 18,793 8,484 10,718 11,399
Depreciation 12,291 12,291 12,291 12,291 12,291 12,291 12,291 8,862 8,862
Amortization 791 791 791 791 791 791 791 -- --
Income Tax Payments (5,194) (7,860) (8,708) (9,773) (10,034) (10,453) (6,845) (6,584) (6,822)
Change in Receivables 146 (120) (177) (216) (9) (39) 2,096 1,108 7
Change in Payables 55 56 57 58 59 60 (1,084) (783) 27
Change in Prepaid Expenses 15 15 14 14 13 13 101 41 0
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash Flow From Operations 18,279 16,558 18,076 20,015 20,707 21,456 15,834 13,362 13,473
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Funded (Assumed)
Equity Contributions
Uses of Capital
Sr. Debt 144A (11,001) (11,943) (13,821) (16,165) (17,271) (18,549) (13,234) (11,890) (12,477)
UC Loan
Cash from Financing Activities
Cash Generated During Period
Reserve Fund Withdrawals 18,278 16,138 17,506 20,150 20,804 24,835 17,046 13,572 20,106
Reserve Fund (Payments) (18,279) (16,558) (18,076) (20,015) 20,707) (21,456) (15,834) (13,362) (13,473)
Less Capital Investment -- -- -- (1,000) -- -- -- (1,000) --
Reclamation Fund -- -- -- -- -- -- -- -- --
------- ------- ------- ------- ------- ------- ------- ------- -------
Beginning Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash Balance Before Distribution 9,776 6,694 6,185 5,485 6,033 8,786 6,312 3,182 10,129
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash (Distributions) Calls* (7,276) (4,194) (3,685) (2,985) (3,533) (6,286) (3,812) (682) (7,629)
------- ------- ------- ------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- ------- ------- ------- -------
Ending Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- ------- -------
ACCELERATED COOLING
SCHEDULE OF DEBT COVERAGE RATIOS
AMOUNTS IN THOUSANDS
2004 2005 2006 2007 2008 2009 2010 2011
------- ------- ------- ------- ------- ------- ------- -------
SOURCES OF CASH
Energy Payments 42,043 48,211 54,246 50,861 49,849 51,253 52,102 53,033
Capacity Payments 17,054 19,804 19,957 19,936 18,451 18,295 18,170 17,942
Bonus & Other Payments 1,691 1,852 1,874 1,882 1,891 1,908 1,925 1,941
Working Capital (1,707) (576) (456) 347 309 (65) 27 (12)
------- ------- ------- ------- ------- ------- ------- -------
TOTAL SOURCES OF CASH 59,081 69,291 75,621 73,025 70,500 77,391 72,224 72,904
------- ------- ------- ------- ------- ------- ------- -------
CASH OPERATING COSTS
Plant & Field O&M 21,169 24,687 25,672 26,197 26,732 27,278 27,836 28,405
Other O&M Including MM 5,143 5,158 5,243 4,947 5,296 5,048 5,367 5,195
Owner's Costs 3,522 3,505 4,185 4,035 3,852 3,903 3,972 4,044
Property&Other Taxes 1,075 1,288 1,280 1,177 1,105 1,058 1,011 965
------- ------- ------- ------- ------- ------- ------- -------
TOTAL CASH OPERATING COSTS 30,909 34,638 36,380 36,355 36,985 37,287 38,186 38,609
------- ------- ------- ------- ------- ------- ------- -------
NET OPERATING CASH FLOW 28,172 34,653 39,241 36,670 33,515 34,104 34,038 34,296
------- ------- ------- ------- ------- ------- ------- -------
Debt Service of Ormesa Loan 4,784
NET CASH FOR BONDS REPAYMENT 23,388 34,653 39,241 36,670 33,515 34,704 34,038 34,296
DEBT SERVICE
Principal Payments 511 6,090 9,611 8,932 7,835 9,141 10,118 11,410
Interest Expense 13,897 15,725 15,144 14,354 13,629 12,947 12,162 11,290
Agent & Other Fees 200 203 206 209 212 215 219 222
------- ------- ------- ------- ------- ------- ------- -------
TOTAL DEBT SERVICE 14,609 22,018 24,961 23,494 21,676 22,304 22,499 22,922
------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio 1.60 1.57 1.57 1.56 1.55 1.53 1.51 1.50
======= ======= ======= ======= ======= ======= ======= =======
Less: Subordinated Fees 0 0 0 0 0 0 0 0
------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio with
Subordination 1.60 1.57 1.57 1.56 1.55 1.53 1.51 1.50
======= ======= ======= ======= ======= ======= ======= =======
2012 2013 2014 2015 2016 2017 2018 2019 2020
------- ------- ------- ------- ------- ------- ------- ------- -------
SOURCES OF CASH
Energy Payments 53,304 54,493 56,354 59,107 59,164 59,394 40,127 29,829 29,492
Capacity Payments 15,676 15,546 15,413 14,957 14,771 14,781 9,422 6,668 6,547
Bonus & Other Payments 1,958 1,976 1,994 2,013 1,924 1,937 1,146 658 668
Working Capital 234 (19) (74) (121) 91 52 1,135 387 64
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL SOURCES OF CASH 71,173 71,995 73,687 75,956 75,950 76,164 51,831 37,542 36,770
------- ------- ------- ------- ------- ------- ------- ------- -------
CASH OPERATING COSTS
Plant & Field O&M 28,986 29,578 30,183 30,800 31,430 32,073 19,643 13,095 13,372
Other O&M Including MM 5,271 5,348 5,427 5,506 5,588 5,670 5,091 2,247 2,288
Owner's Costs 4,065 4,565 4,639 4,715 4,764 4,805 4,439 3,590 3,503
Property&Other Taxes 919 873 828 783 739 696 654 649 632
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL CASH OPERATING COSTS 39,241 40,365 41,076 41,805 42,521 43,245 29,826 19,580 19,795
------- ------- ------- ------- ------- ------- ------- ------- -------
NET OPERATING CASH FLOW 31,932 31,631 32,611 34,151 33,429 32,920 22,004 17,962 16,975
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Service of Ormesa Loan
NET CASH FOR BONDS REPAYMENT 31,932 31,631 32,611 34,151 33,429 32,920 22,004 17,962 16,975
DEBT SERVICE
Principal Payments 11,001 11,943 13,821 16,165 17,271 18,549 13,234 11,890 12,477
Interest Expense 10,343 9,404 8,366 7,162 5,788 4,317 2,874 1,795 788
Agent & Other Fees 225 229 232 236 239 243 246 250 254
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL DEBT SERVICE 21,570 21,576 22,420 23,563 23,298 23,108 16,354 13,934 13,519
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio 1.48 1.47 1.45 1.45 1.43 1.42 1.35 1.29 1.26
======= ======= ======= ======= ======= ======= ======= ======= =======
Less: Subordinated Fees 0 0 0 0 0 0 0 0 0
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio with
Subordination 1.48 1.47 1.45 1.45 1.43 1.42 1.35 1.29 1.26
======= ======= ======= ======= ======= ======= ======= ======= =======
ACCELERATED COOLING
Pro-forma Projected Statement of Cash Flow
for the Periods Indicated
In thousands of dollars
2004 2005 2006 2007 2008 2009 2010 2011
------- ------- ------- ------- ------- ------- ------- -------
Book Pre-tax Income (Loss) 3,871 5,519 10,566 7,980 6,282 7,924 8,547 9,713
Depreciation 9,680 12,291 12,291 12,291 12,291 12,291 12,291 12,291
Amortization 1,304 1,490 1,490 1,490 791 791 791 791
Income Tax Payments -- -- -- -- -- -- -- --
Change in Receivables (1,588) (756) (518) 283 207 (106) (62) (60)
Change in Payables 295 294 89 19 74 25 73 33
Change in Prepaid Expenses (414) (113) (28) 44 28 16 16 15
------- ------- ------- ------- ------- ------- ------- -------
Cash Flow From Operations 13,147 18,724 23,891 22,107 19,674 20,942 21,657 22,784
------- ------- ------- ------- ------- ------- ------- -------
Debt Funded (Assumed) --
Equity Contributions 17,878 2,150
Uses of Capital (17,878) (2,150)
Sr. Debt 144A (511) (6,090) (9,611) (8,932) (7,835) (9,141) (10,118) (11,410)
UC Loan (3,856)
Cash from Financing Activities
Cash Generated During Period
Reserve Fund Withdrawals 12,909 15,104 24,626 23,018 19,361 20,846 21,447 23,462
Reserve Fund (Payments) (13,147) (16,574) (23,891) (22,107) (19,674) (20,942) (21,657) (22,784)
Less Capital Investment (1,647) -- -- (1,000) -- -- -- (1,000)
Reclamation Fund (31) (31) (31) (31) -- -- -- --
------- ------- ------- ------- ------- ------- ------- -------
Beginning Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- -------
Cash Balance Before Distribution 9,363 13,633 17,484 15,555 14,026 14,204 13,829 13,551
------- ------- ------- ------- ------- ------- ------- -------
Cash (Distributions) Calls* (6,863) (11,133) (14,984) (13,055) (11,526) (11,704) (11,329) (11,051)
------- ------- ------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- ------- ------- -------
Ending Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- -------
2012 2013 2014 2015 2016 2017 2018 2019 2020
------- ------- ------- ------- ------- ------- ------- ------- -------
Book Pre-tax Income (Loss) 8,046 8,935 11,004 13,792 14,229 15,226 4,666 6,669 7,007
Depreciation 12,291 12,291 12,291 12,291 12,291 12,291 12,291 8,862 8,862
Amortization 791 791 791 791 791 791 791 -- --
Income Tax Payments (2,349) (7,003) (7,727) (8,702) (8,856) (9,204) (5,509) (5,166) (5,285)
Change in Receivables 165 (90) (146) (193) 18 (21) 2,118 1,128 37
Change in Payables 55 56 57 58 59 60 (1,084) (783) 27
Change in Prepaid Expenses 15 15 14 14 13 13 101 41 0
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash Flow From Operations 19,014 14,995 16,285 18,051 18,547 19,156 13,375 10,751 10,649
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Funded (Assumed)
Equity Contributions
Uses of Capital
Sr. Debt 144A (11,001) (11,943) (13,821) (16,165) (17,271) (18,549) (13,234) (11,890) (12,477)
UC Loan
Cash from Financing Activities
Cash Generated During Period
Reserve Fund Withdrawals 19,013 14,575 15,716 18,185 18,643 22,535 14,587 10,960 17,282
Reserve Fund (Payments) (19,014) (14,995) (16,285) (18,051) (18,547) (19,156) (13,375) (10,751) (10,649)
Less Capital Investment -- -- -- (1,000) -- -- -- (1,000) --
Reclamation Fund -- -- -- -- -- -- -- -- --
------- ------- ------- ------- ------- ------- ------- ------- -------
Beginning Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash Balance Before Distribution 10,511 5,132 4,394 3,520 3,872 6,486 3,853 571 7,304
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash (Distributions) Calls* (8,011) (2,632) (1,894) (1,020) (1,372) (3,986) (1,353) 1,929 (4,804)
------- ------- ------- ------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- ------- ------- ------- -------
Ending Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- ------- -------
INCREASED O&M COSTS
SCHEDULE OF DEBT COVERAGE RATIOS
AMOUNTS IN THOUSANDS
2004 2005 2006 2007 2008 2009 2010 2011
------- ------- ------- ------- ------- ------- ------- -------
SOURCES OF CASH
Energy Payments 42,087 48,313 54,405 51,305 50,575 52,269 53,409 54,636
Capacity Payments 17,054 19,804 19,957 19,943 18,479 18,464 18,436 18,345
Bonus & Other Payments 1,691 1,852 1,874 1,882 1,891 1,908 1,925 1,941
Working Capital (1,606) (574) (459) 325 287 (98) (3) (45)
------- ------- ------- ------- ------- ------- ------- -------
TOTAL SOURCES OF CASH 59,226 69,395 75,778 73,455 71,231 72,543 73,767 74,876
------- ------- ------- ------- ------- ------- ------- -------
CASH OPERATING COSTS
Plant & Field O&M 22,227 25,922 26,932 27,482 28,044 28,617 29,202 29,799
Other O&M Including MM 5,350 5,267 5,355 5,061 5,412 5,166 5,488 5,318
Owner's Costs 3,522 3,507 4,188 4,054 3,887 3,957 4,043 4,134
Property&Other Taxes 1,075 1,288 1,280 1,177 1,105 1,058 1,011 965
------- ------- ------- ------- ------- ------- ------- -------
TOTAL CASH OPERATING COSTS 32,174 35,984 37,754 37,773 38,447 38,798 39,744 40,216
------- ------- ------- ------- ------- ------- ------- -------
NET OPERATING CASH FLOW 27,052 33,411 38,024 35,681 32,784 33,745 34,023 34,660
------- ------- ------- ------- ------- ------- ------- -------
Debt Service of Ormesa Loan 4,784
NET CASH FOR BONDS REPAYMENT 22,268 33,411 38,024 35,681 32,784 33,745 34,023 34,660
DEBT SERVICE
Principal Payments 511 6,090 9,611 8,932 7,835 9,141 10,118 11,410
Interest Expense 13,897 15,725 15,144 14,354 13,629 12,947 12,162 11,290
Agent & Other Fees 200 203 206 209 212 215 219 222
------- ------- ------- ------- ------- ------- ------- -------
TOTAL DEBT SERVICE 14,609 22,018 24,961 23,494 21,676 22,304 22,499 22,922
------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio 1.52 1.52 1.52 1.52 1.51 1.51 1.51 1.51
======= ======= ======= ======= ======= ======= ======= =======
Less: Subordinated Fees 0 0 0 0 0 0 0 0
------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio with
Subordination 1.52 1.52 1.52 1.52 1.51 1.51 1.51 1.51
======= ======= ======= ======= ======= ======= ======= =======
2012 2013 2014 2015 2016 2017 2018 2019 2020
------- ------- ------- ------- ------- ------- ------- ------- -------
SOURCES OF CASH
Energy Payments 55,202 56,696 58,877 61,969 62,339 62,889 43,971 33,990 33,973
Capacity Payments 16,012 15,943 15,864 15,343 15,171 15,080 9,628 6,793 6,712
Bonus & Other Payments 1,958 1,976 1,994 2,013 1,924 1,937 1,160 686 696
Working Capital 218 (47) (103) (141) 66 37 1,058 337 36
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL SOURCES OF CASH 73,390 74,568 76,633 79,184 79,501 79,943 55,818 41,806 41,416
------- ------- ------- ------- ------- ------- ------- ------- -------
CASH OPERATING COSTS
Plant & Field O&M 30,408 31,030 31,664 32,312 32,972 33,647 20,595 13,719 14,009
Other O&M Including MM 5,397 5,476 5,557 5,640 5,723 5,809 5,199 2,339 2,382
Owner's Costs 4,170 4,715 4,810 4,905 4,973 5,032 4,685 3,854 3,786
Property&Other Taxes 919 873 828 783 739 696 654 649 632
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL CASH OPERATING COSTS 40,893 42,094 42,859 43,639 44,409 45,184 31,133 20,560 20,809
------- ------- ------- ------- ------- ------- ------- ------- -------
NET OPERATING CASH FLOW 32,496 32,474 33,773 35,544 35,093 34,759 24,685 21,246 20,606
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Service of Ormesa Loan
NET CASH FOR BONDS REPAYMENT 32,496 32,474 33,773 35,544 35,093 34,759 24,685 21,246 20,606
DEBT SERVICE
Principal Payments 11,001 11,943 13,821 16,165 17,271 18,549 13,234 11,890 12,477
Interest Expense 10,343 9,404 8,366 7,162 5,788 4,317 2,874 1,795 788
Agent & Other Fees 225 229 232 236 239 243 246 250 254
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL DEBT SERVICE 21,570 21,576 22,420 23,563 23,298 23,108 16,354 13,934 13,519
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio 1.51 1.51 1.51 1.51 1.51 1.50 1.51 1.52 1.52
======= ======= ======= ======= ======= ======= ======= ======= =======
Less: Subordinated Fees 0 0 0 0 0 0 0 0 0
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio with
Subordination 1.51 1.51 1.51 1.51 1.51 1.50 1.51 1.52 1.52
======= ======= ======= ======= ======= ======= ======= ======= =======
INCREASED O&M COSTS
Pro-forma Projected Statement of Cash Flow
for the Periods Indicated
in thousands of dollars
2004 2005 2006 2007 2008 2009 2010 2011
------- ------- ------- ------- ------- ------- ------- -------
Book Pre-tax Income (Loss) 2,649 4,276 9,351 7,013 5,573 7,598 8,562 10,111
Depreciation 9,680 12,291 12,291 12,291 12,291 12,291 12,291 12,291
Amortization 1,304 1,490 1,490 1,490 791 791 791 791
Income Tax Payments -- -- -- -- -- -- -- --
Change in Receivables (1,591) (761) (522) 259 182 (141) (94) (96)
Change in Payables 400 301 91 21 76 27 76 36
Change in Prepaid Expenses (414) (113) (28) 44 28 16 16 15
------- ------- ------- ------- ------- ------- ------- -------
Cash Flow From Operations 12,027 17,483 22,674 21,119 18,942 20,583 21,642 23,149
------- ------- ------- ------- ------- ------- ------- -------
Debt Funded (Assumed) --
Equity Contributions 17,878 2,150
Uses of capital (17,878) (2,150)
Sr. Debt 144A (511) (6,090) (9,611) (8,932) (7,835) (9,141) (10,118) (11,410)
UC Loan (3,856)
Cash from Financing Activities
Cash Generated During Period
Reserve Fund Withdrawals 11,789 13,863 23,409 22,029 18,630 20,487 21,432 23,826
Reserve Fund (Payments) (12,027) (15,333) (22,674) (21,119) (18,942) (20,583) (21,642) (23,149)
Less Capital Investment (1,647) -- -- (1,000) -- -- -- (1,000)
Reclamation Fund (31) (31) (31) (31) -- -- -- --
------- ------- ------- ------- ------- ------- ------- -------
Beginning Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- -------
Cash Balance Before Distribution 8,243 12,392 16,266 14,566 13,295 13,845 13,814 13,916
------- ------- ------- ------- ------- ------- ------- -------
Cash (Distributions) Calls* (5,743) (9,892) (13,766) (12,066) (10,795) (11,345) (11,314) (11,416)
------- ------- ------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- ------- ------- -------
Ending Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- -------
2012 2013 2014 2015 2016 2017 2018 2019 2020
------- ------- ------- ------- ------- ------- ------- ------- -------
Book Pre-tax Income (Loss) 8,627 9,806 12,195 15,205 15,917 17,081 7,424 10,002 10,667
Depreciation 12,291 12,291 12,291 12,291 12,291 12,291 12,291 8,862 8,862
Amortization 791 791 791 791 791 791 791 -- --
Income Tax Payments (709) (7,308) (8,144) (9,197) (9,446) (9,854) (6,474) (6,333) (6,566)
Change in Receivables 146 (120) (177) (216) (9) (39) 2,096 1,108 7
Change in Payables 57 58 60 61 62 63 (1,139) (811) 28
Change in Prepaid Expenses 15 15 14 14 13 13 101 41 0
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash Flow From Operations 21,219 15,534 17,031 18,949 19,620 20,346 15,091 12,868 12,998
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Funded (Assumed)
Equity Contributions
Uses of capital
Sr. Debt 144A (11,001) (11,943) (13,821) (16,165) (17,271) (18,549) (13,234) (11,890) (12,477)
UC Loan
Cash from Financing Activities
Cash Generated During Period
Reserve Fund Withdrawals 21,217 15,114 16,461 19,084 19,716 23,725 16,303 13,077 19,631
Reserve Fund (Payments) (21,219) (15,534) (17,031) (18,949) (19,620) (20,346) (15,091) (12,868) (12,998)
Less Capital Investment -- -- -- (1,000) -- -- -- (1,000) --
Reclamation Fund -- -- -- -- -- -- -- -- --
------- ------- ------- ------- ------- ------- ------- ------- -------
Beginning Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash Balance Before Distribution 12,716 5,670 5,140 4,419 4,945 7,676 5,569 2,688 9,654
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash (Distributions) Calls* (10,216) (3,170) (2,640) (1,919) (2,445) (5,176) (3,069) (188) (7,154)
------- ------- ------- ------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- ------- ------- ------- -------
Ending Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- ------- -------
DECREASED AVAILABILITY
SCHEDULE OF DEBT COVERAGE RATIOS
AMOUNTS IN THOUSANDS
2004 2005 2006 2007 2008 2009 2010 2011
------- ------- ------- ------- ------- ------- ------- -------
SOURCES OF CASH
Energy Payments 41,576 47,613 53,686 50,626 49,904 51,577 52,703 53,914
Capacity Payments 17,041 19,790 19,941 19,927 18,462 18,427 18,361 18,266
Bonus & Other Payments 1,691 1,852 1,874 1,882 1,891 1,908 1,925 1,941
Working Capital (1,667) (565) (459) 319 283 (97) (1) (46)
------- ------- ------- ------- ------- ------- ------- -------
TOTAL SOURCES OF CASH 58,641 68,690 75,042 72,753 70,541 71,815 72,988 74,075
------- ------- ------- ------- ------- ------- ------- -------
CASH OPERATING COSTS
Plant & Field O&M 21,169 24,687 25,672 26,197 26,732 27,278 27,836 28,405
Other O&M Including MM 5,143 5,158 5,243 4,947 5,296 5,048 5,367 5,195
Owner's Costs 3,511 3,487 4,163 4,030 3,863 3,932 4,018 4,108
Property&Other Taxes 1,075 1,288 1,280 1,177 1,105 1,058 1,011 965
------- ------- ------- ------- ------- ------- ------- -------
TOTAL CASH OPERATING COSTS 30,898 34,621 36,358 36,350 36,996 37,317 38,232 38,673
------- ------- ------- ------- ------- ------- ------- -------
NET OPERATING CASH FLOW 27,743 34,070 38,683 36,403 33,546 34,499 34,755 35,402
------- ------- ------- ------- ------- ------- ------- -------
Debt Service ot Ormesa Loan 4,784
NET CASH FOR BONDS REPAYMENT 22,959 34,070 38,683 36,403 33,546 34,499 34,755 35,402
DEBT SERVICE
Principal Payments 511 6,090 9,611 8,932 7,835 9,141 10,118 11,410
Interest Expense 13,897 15,725 15,144 14,354 13,629 12,947 12,162 11,290
Agent & Other Fees 200 203 206 209 212 215 219 222
------- ------- ------- ------- ------- ------- ------- -------
TOTAL DEBT SERVICE 14,609 22,018 24,961 23,494 21,676 22,304 22,499 22,922
------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio 1.57 1.55 1.55 1.55 1.55 1.55 1.54 1.54
======= ======= ======= ======= ======= ======= ======= =======
Less: Subordinated Fees 0 0 0 0 0 0 0 0
------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio with Subordination 1.57 1.55 1.55 1.55 1.55 1.55 1.54 1.54
======= ======= ======= ======= ======= ======= ======= =======
2012 2013 2014 2015 2016 2017 2018 2019 2020
------- ------- ------- ------- ------- ------- ------- ------- -------
SOURCES OF CASH
Energy Payments 54,473 55,948 58,101 61,154 61,519 62,061 43,380 33,523 33,505
Capacity Payments 15,946 15,879 15,713 15,267 15,099 15,011 9,562 6,729 6,768
Bonus & Other Payments 1,958 1,976 1,994 2,013 1,924 1,937 1,160 686 696
Working Capital 215 (48) (96) (147) 64 34 1,093 356 24
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL SOURCES OF CASH 72,592 73,754 75,712 78,287 78,606 79,043 55,194 41,293 40,993
------- ------- ------- ------- ------- ------- ------- ------- -------
CASH OPERATING COSTS
Plant & Field O&M 28,986 29,578 30,183 30,800 31,430 32,073 19,643 13,095 13,372
Other O&M Including MM 5,271 5,348 5,427 5,506 5,588 5,670 5,091 2,247 2,288
Owner's Costs 4,145 4,685 4,778 4,874 4,943 5,002 4,655 3,824 3,759
Property&Other Taxes 919 873 828 783 739 696 654 649 632
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL CASH OPERATING COSTS 39,320 40,484 41,215 41,964 42,700 43,441 30,043 19,814 20,050
------- ------- ------- ------- ------- ------- ------- ------- -------
NET OPERATING CASH FLOW 33,272 33,270 34,496 36,323 35,906 35,602 25,152 21,479 20,943
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Service ot Ormesa Loan
NET CASH FOR BONDS REPAYMENT 33,272 33,270 34,496 36,323 35,906 35,602 25,152 21,479 20,943
DEBT SERVICE
Principal Payments 11,001 11,943 13,821 16,165 17,271 18,549 13,234 11,890 12,477
Interest Expense 10,343 9,404 8,366 7,162 5,788 4,317 2,874 1,795 788
Agent & Other Fees 225 229 232 236 239 243 246 250 254
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL DEBT SERVICE 21,570 21,576 22,420 23,563 23,298 23,108 16,354 13,934 13,519
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio 1.54 1,54 1.54 1.54 1.54 1.54 1.54 1.54 1.55
======= ======= ======= ======= ======= ======= ======= ======= =======
Less: Subordinated Fees 0 0 0 0 0 0 0 0 0
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio with Subordination 1.54 1,54 1.54 1.54 1.54 1.54 1.54 1.54 1.55
======= ======= ======= ======= ======= ======= ======= ======= =======
DECREASED AVAILABILITY
Pro-forma Projected Statement of Cash Flow
for the Periods Indicated
in thousands of dollars
2004 2005 2006 2007 2008 2009 2010 2011
------- ------- ------- ------- ------- ------- ------- -------
Book Pre-tax Income (Loss) 3,402 4,925 10,012 7,740 6,338 8,351 9,293 10,854
Depreciation 9,680 12,291 12,291 12,291 12,291 12,291 12,291 12,291
Amortization 1,304 1,490 1,490 1,490 791 791 791 791
Income Tax Payments -- -- -- -- -- -- -- --
Change in Receivables (1,548) (746) (521) 256 181 (138) (90) (94)
Change in Payables 295 294 89 19 74 25 73 33
Change in Prepaid Expenses (414) (113) (28) 44 28 16 16 15
------- ------- ------- ------- ------- ------- ------- -------
Cash Flow From Operations 12,718 18,141 23,334 21,840 19,704 21,336 22,374 23,890
------- ------- ------- ------- ------- ------- ------- -------
Debt Funded (Assumed) --
Equity Contributions 17,878 2,150
Uses of Capital (17,878) (2,150)
Sr. Debt 144A (511) (6,090) (9,611) (8,932) (7,835) (9,141) (10,118) (11,410)
UC Loan (3,856)
Cash from Financing Activites
Cash Generated During Period
Reserve Fund Withdrawals 12,480 14,522 24,068 22,751 19,392 21,240 22,164 24,568
Reserve Fund (Payments) (12,718) (15,991) (23,334) (21,840) (19,704) (21,336) (22,374) (23,890)
Less Capital Investment (1,647) -- -- (1,000) -- -- -- (1,000)
Reclamation Fund (31) (31) (31) (31) -- -- -- --
------- ------- ------- ------- ------- ------- ------- -------
Beginning Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- -------
Cash Balance Before Distribution 8,934 13,050 16,926 15,288 14,057 14,599 14,547 14,657
------- ------- ------- ------- ------- ------- ------- -------
Cash (Distributions) Calls* (6,434) (10,550) (14,426) (12,788) (11,557) (12,099) (12,047) (12,157)
------- ------- ------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- ------- ------- -------
Ending Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- -------
2012 2013 2014 2015 2016 2017 2018 2019 2020
------- ------- ------- ------- ------- ------- ------- ------- -------
Book Pre-tax Income (Loss) 9,406 10,603 12,911 15,989 16,733 17,925 7,856 10,217 11,015
Depreciation 12,291 12,291 12,291 12,291 12,291 12,291 12,291 8,862 8,862
Amortization 791 791 791 791 791 791 791 -- --
Income Tax Payments (3,004) (7,586) (8,394) (9,472) (9,732) (10,149) (6,625) (6,408) (6,688)
Change in Receivables 145 (119) (167) (219) (9) (39) 2,076 1,097 (3)
Change in Payables 55 56 57 58 59 60 (1,084) (783) 27
Change in Prepaid Expenses 15 15 14 14 13 13 101 41 0
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash Flow From Operations 19,699 16,051 17,504 19,453 20,147 20,893 15,406 13,026 13,213
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Funded (Assumed)
Equity Contributions
Uses of Capital
Sr. Debt 144A (11,001) (11,943) (13,821) (16,165) (17,271) (18,549) (13,234) (11,890) (12,477)
UC Loan
Cash from Financing Activites
Cash Generated During Period
Reserve Fund Withdrawals 19,697 15,631 16,934 19,587 20,244 24,272 16,618 13,235 19,846
Reserve Fund (Payments) (19,699) (16,051) (17,504) (19,453) (20,147) (20,893) (15,406) (13,026) (13,213)
Less Capital Investment -- -- -- (1,000) -- -- -- (1,000) --
Reclamation Fund -- -- -- -- -- -- -- -- --
------- ------- ------- ------- ------- ------- ------- ------- -------
Beginning Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash Balance Before Distribution 11,196 6,187 5,612 4,923 5,473 8,223 5,884 2,846 9,869
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash (Distributions) Calls* (8,696) (3,687) (3,112) (2,423) (2,973) (5,723) (3,384) (346) (7,369)
------- ------- ------- ------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- ------- ------- ------- -------
Ending Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- ------- -------
DECREASED SRAC RATE
SCHEDULE OF DEBT COVERAGE RATIOS
AMOUNTS IN THOUSANDS
2004 2005 2006 2007 2008 2009 2010 2011
------- ------- ------- ------- ------- ------- ------- -------
SOURCES OF CASH
Energy Payments 42,087 48,313 54,405 47,651 46,672 48,117 49,107 50,163
Capacity Payments 17,054 19,804 19,957 19,943 18,479 18,464 18,436 18,345
Bonus & Other Payments 1,691 1,852 1,874 1,882 1,891 1,908 1,925 1,941
Working Capital (1,711) (580) (461) 627 305 (80) 7 (33)
------- ------- ------- ------- ------- ------- ------- -------
TOTAL SOURCES OF CASH 59,121 69,389 75,776 70,103 67,346 68,410 69,475 70,415
------- ------- ------- ------- ------- ------- ------- -------
CASH OPERATING COSTS
Plant & Field O&M 21,169 24,687 25,672 26,197 26,732 27,278 27,836 28,405
Other O&M Including MM 5,143 5,158 5,243 4,947 5,296 5,048 5,367 5,195
Owner's Costs 3,522 3,507 4,188 4,011 3,818 3,883 3,967 4,055
Property&Other Taxes 1,075 1,288 1,280 1,177 1,105 1,058 1,011 965
------- ------- ------- ------- ------- ------- ------- -------
TOTAL CASH OPERATING COSTS 30,909 34,640 36,383 36,332 36,950 37,267 38,182 38,620
------- ------- ------- ------- ------- ------- ------- -------
NET OPERATING CASH FLOW 28,212 34,748 39,392 33,771 30,396 31,142 31,293 31,795
------- ------- ------- ------- ------- ------- ------- -------
Debt Service of Ormesa Loan 4,784
NET CASH FOR BONDS REPAYMENT 23,428 34,748 39,392 33,771 30,396 31,142 31,293 31,795
DEBT SERVICE
Principal Payments 511 6,090 9,611 8,932 7,835 9,141 10,118 11,410
Interest Expense 13,897 15,725 15,144 14,354 13,629 12,947 12,162 11,290
Agent & Other Fees 200 203 206 209 212 215 219 222
------- ------- ------- ------- ------- ------- ------- -------
TOTAL DEBT SERVICE 14,609 22,018 24,961 23,494 21,676 22,304 22,499 22,922
------- ------- ------- ------- ------- ------- ------- -------
Dabt Coverage Ratio 1.60 1.58 1.58 1.44 1.40 1.40 1.39 1.39
======= ======= ======= ======= ======= ======= ======= =======
Less: Subordinated Fees 0 0 0 0 0 0 0 0
------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio with Subordination 1.60 1.58 1.58 1.44 1.40 1.40 1.39 1.39
======= ======= ======= ======= ======= ======= ======= =======
2012 2013 2014 2015 2016 2017 2018 2019 2020
------- ------- ------- ------- ------- ------- ------- ------- -------
SOURCES OF CASH
Energy Payments 50,649 51,941 53,808 56,441 56,778 57,259 41,183 32,722 32,721
Capacity Payments 16,012 15,943 15,864 15,343 15,171 15,080 9,628 6,793 6,712
Bonus & Other Payments 1,958 1,976 1,994 2,013 1,924 1,937 1,160 686 696
Working Capital 222 (33) (79) (106) 66 40 876 239 33
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL SOURCES OF CASH 68,841 69,827 71,587 73,691 73,940 74,316 52,847 40,440 40,162
------- ------- ------- ------- ------- ------- ------- ------- -------
CASH OPERATING COSTS
Plant & Field O&M 28,986 29,578 30,183 30,800 31,430 32,073 19,645 13,095 13,372
Other O&M Including MM 5,271 5,348 5,427 5,506 5,588 5,670 5,091 2,247 2,288
Owner's Costs 4,090 4,631 4,721 4,808 4,876 4,933 4,582 3,752 3,686
Property&Other Taxes 919 873 828 783 739 696 654 649 632
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL CASH OPERATING COSTS 39,265 40,430 41,158 41,898 42,633 43,373 29,972 19,742 19,977
------- ------- ------- ------- ------- ------- ------- ------- -------
NET OPERATING CASH FLOW 29,576 29,396 30,429 31,793 31,307 30,943 22,875 20,698 20,184
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Service of Ormesa Loan
NET CASH FOR BONDS REPAYMENT 29,576 29,396 30,429 31,793 31,307 30,943 22,875 20,698 20,184
DEBT SERVICE
Principal Payments 11,001 11,943 13,821 16,165 17,271 18,549 13,234 11,890 12,477
Interest Expense 10,343 9,404 8,366 7,162 5,788 4,317 2,874 1,795 788
Agent & Other Fees 225 229 232 236 239 243 246 250 254
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL DEBT SERVICE 21,570 21,576 22,420 23,563 23,298 23,108 16,354 13,934 13,519
------- ------- ------- ------- ------- ------- ------- ------- -------
Dabt Coverage Ratio 1.37 1.36 1.36 1.35 1.34 1.34 1.40 1.49 1.49
======= ======= ======= ======= ======= ======= ======= ======= =======
Less: Subordinated Fees 0 0 0 0 0 0 0 0 0
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio with Subordination 1.37 1.36 1.36 1.35 1.34 1.34 1.40 1.49 1.49
======= ======= ======= ======= ======= ======= ======= ======= =======
DECREASED SRAC RATE
Pro-forma Projected Statement of Cash Flow
for the Periods Indicated
in thousands of dollars
2004 2005 2006 2007 2008 2009 2010 2011
------- ------- ------- ------- ------- ------- ------- -------
Book Pre-tax Income (Loss) 3,914 5,620 10,723 4,801 3,168 4,977 5,823 7,234
Depreciation 9,680 12,291 12,291 12,291 12,291 12,291 12,291 12,291
Amortization 1,304 1,490 1,490 1,490 791 791 791 791
Income Tax Payments -- -- -- -- -- -- -- --
Change in Receivables (1,591) (761) (522) 563 203 (121) (82) (82)
Change in Payables 295 294 89 19 74 25 73 33
Change in Prepaid Expenses (414) (113) (28) 44 28 16 16 15
------- ------- ------- ------- ------- ------- ------- -------
Cash Flow From Operations 13,187 18,820 24,043 19,208 16,555 17,980 18,912 20,284
------- ------- ------- ------- ------- ------- ------- -------
Debt Funded (Assumed) --
Equity Contributions 17,878 2,150
Uses of Capital (17,878) (2,150)
Sr. Debt 144A (511) (6,090) (9,611) (8,932) (7,835) (9,141) (10,118) (11,410)
UC Loan (3,856)
Cash from Financing Activites
Cash Generated During Period
Reserve Fund Withdrawals 12,948 15,200 24,777 20,119 16,243 17,884 18,702 20,961
Reserve Fund (Payments) (13,187) (16,670) (24,043) (19,208) (16,555) (17,980) (18,912) (20,284)
Less Capital Investment (1,647) -- -- (1,000) -- -- -- (1,000)
Reclamation Fund (31) (31) (31) (31) -- -- -- --
------- ------- ------- ------- ------- ------- ------- -------
Beginning Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- -------
Cash Balance Before Distribution 9,403 13,729 17,635 12,656 10,908 11,242 11,085 11,051
------- ------- ------- ------- ------- ------- ------- -------
Cash (Distributions) Calls* (6,903) (11,229) (15,135) (10,156) (8,408) (8,742) (8,585) (8,551)
------- ------- ------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- ------- ------- -------
Ending Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- -------
2012 2013 2014 2015 2016 2017 2018 2019 2020
------- ------- ------- ------- ------- ------- ------- ------- -------
Book Pre-tax Income (Loss) 5,702 6,714 8,827 11,419 12,132 13,262 5,796 9,553 10,248
Depreciation 12,291 12,291 12,291 12,291 12,291 12,291 12,291 8,862 8,862
Amortization 791 791 791 791 791 791 791 -- --
Income Tax Payments -- (2,804) (6,965) (7,872) (8,122) (8,517) (5,904) (6,176) (6,419)
Change in Receivables 152 (103) (151) (178) (6) (34) 1,859 981 6
Change in Payables 55 56 57 58 59 60 (1,084) (783) 27
Change in Prepaid Expenses 15 15 14 14 13 13 101 41 0
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash Flow From Operations 19,007 16,960 14,865 16,523 17,159 17,867 13,850 12,478 12,723
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Funded (Assumed)
Equity Contributions
Uses of Capital
Sr. Debt 144A (11,001) (11,943) (13,821) (16,165) (17,271) (18,549) (13,234) (11,890) (12,477)
UC Loan
Cash from Financing Activites
Cash Generated During Period
Reserve Fund Withdrawals 19,006 16,539 14,296 16,658 17,255 21,245 15,062 12,687 19,356
Reserve Fund (Payments) (19,007) (16,960) (14,865) (16,523) (17,159) (17,867) (13,850) (12,478) (12,723)
Less Capital Investment -- -- -- (1,000) -- -- -- (1,000) --
Reclamation Fund -- -- -- -- -- -- -- -- --
------- ------- ------- ------- ------- ------- ------- ------- -------
Beginning Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash Balance Before Distribution 10,504 7,096 2,974 1,993 2,484 5,197 4,328 2,297 9,379
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash (Distributions) Calls* (8,004) (4,596) (474) 507 16 (2,697) (1,828) 203 (6,879)
------- ------- ------- ------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- ------- ------- ------- -------
Ending Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- ------- -------
INCREASED O&M COSTS/ACCELERATED COOLING
SCHEDULE OF DEBT COVERAGE RATIOS
AMOUNTS IN THOUSANDS
2004 2005 2006 2007 2008 2009 2010 2011
------- ------- ------- ------- ------- ------- ------- -------
SOURCES OF CASH
Energy Payments 42,043 48,211 54,246 50,861 49,849 51,253 52,102 53,033
Capacity Payments 17,054 19,804 19,957 19,936 18,451 18,295 18,170 17,942
Bonus & Other Payments 1,691 1,852 1,874 1,882 1,891 1,908 1,925 1,941
Working Capital (1,602) (569) (454) 349 312 (62) 29 (9)
------- ------- ------- ------- ------- ------- ------- -------
TOTAL SOURCES OF CASH 59,187 69,298 75,623 73,027 70,502 71,394 72,226 72,907
------- ------- ------- ------- ------- ------- ------- -------
CASH OPERATING COSTS
Plant & Field O&M 22,227 25,922 26,932 27,482 28,044 28,617 29,202 29,799
Other O&M Including MM 5,350 5,267 5,355 5,061 5,412 5,166 5,488 5,318
Owner's Costs 3,522 3,505 4,185 4,035 3,852 3,903 3,972 4,044
Property&Other Taxes 1,075 1,288 1,280 1,177 1,105 1,058 1,011 965
------- ------- ------- ------- ------- ------- ------- -------
TOTAL CASH OPERATING COSTS 32,174 35,982 37,751 37,754 38,412 38,744 39,673 40,125
------- ------- ------- ------- ------- ------- ------- -------
NET OPERATING CASH FLOW 27,012 33,315 37,872 35,273 32,090 32,650 32,554 32,781
------- ------- ------- ------- ------- ------- ------- -------
Debt Service of Ormesa Loan 4,784
NET CASH FOR BONDS REPAYMENT 22,228 33,315 37,872 35,273 32,090 32,650 32,554 32,781
DEBT SERVICE
Principal Payments 511 6,090 9,611 8,932 7,835 9,141 10,118 11,410
Interest Expense 13,897 15,725 15,144 14,354 13,629 12,947 12,162 11,290
Agent & Other Fees 200 203 206 209 212 215 219 222
------- ------- ------- ------- ------- ------- ------- -------
TOTAL DEBT SERVICE 14,609 22,078 24,961 23,494 21,676 22,304 22,499 22,922
------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio 1.52 1.51 1.52 1.50 1.48 1.46 1.45 1.43
======= ======= ======= ======= ======= ======= ======= =======
Less: Subordinated Fees 0 0 0 0 0 0 0 0
------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio with Subordination 1.52 1.51 1.52 1.50 1.48 1.46 1.45 1.43
======= ======= ======= ======= ======= ======= ======= =======
2012 2013 2014 2015 2016 2017 2018 2079 2020
------- ------- ------- ------- ------- ------- ------- ------- -------
SOURCES OF CASH
Energy Payments 53,304 54,493 56,354 59,107 59,164 59,394 40,127 29,829 29,492
Capacity Payments 15,676 15,546 15,413 14,957 14,771 14,781 9,422 6,668 6,547
Bonus & Other Payments 1,958 1,976 1,994 2,013 1,924 1,937 1,146 658 668
Working Capital 237 (17) (72) (118) 93 55 1,081 358 66
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL SOURCES OF CASH 71,175 71,998 73,690 75,958 75,953 76,167 51,776 37,513 36,771
------- ------- ------- ------- ------- ------- ------- ------- -------
CASH OPERATING COSTS
Plant & Field O&M 30,408 31,030 31,664 32,312 32,972 33,647 20,595 13,719 14,009
Other O&M Including MM 5,397 5,476 5,557 5,640 5,723 5,809 5,199 2,339 2,382
Owner's Costs 4,065 4,565 4,639 4,715 4,764 4,805 4,439 3,590 3,503
Property&Other Taxes 919 873 828 783 739 696 654 649 632
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL CASH OPERATING COSTS 40,789 41,944 42,688 43,449 44,199 44,957 30,886 20,296 20,526
------- ------- ------- ------- ------- ------- ------- ------- -------
NET OPERATING CASH FLOW 30,387 30,054 31,002 32,509 31,753 31,210 20,890 17,217 16,245
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Service of Ormesa Loan
NET CASH FOR BONDS REPAYMENT 30,387 30,054 31,002 32,509 31,753 31,210 20,890 17,217 16,245
DEBT SERVICE
Principal Payments 11,001 11,943 13,821 16,165 17,271 18,549 13,234 11,890 12,477
Interest Expense 10,343 9,404 8,366 7,162 5,788 4,317 2,874 1,795 788
Agent & Other Fees 225 229 232 236 239 243 246 250 254
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL DEBT SERVICE 21,570 21,576 22,420 23,563 23,298 23,108 16,354 13,934 13,519
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio 1.41 1.39 1.38 1.38 1.36 1.35 1.28 1.24 1.20
======= ======= ======= ======= ======= ======= ======= ======= =======
Less: Subordinated Fees 0 0 0 0 0 0 0 0 0
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio with Subordination 1.41 1.39 1.38 1.38 1.36 1.35 1.28 1.24 1.20
======= ======= ======= ======= ======= ======= ======= ======= =======
INCREASED O&M COSTS/ACCELERATED COOLING
Pro-forma Projected Statement of Cash Flow
for the Periods Indicated
In thousands of dollars
2004 2005 2006 2007 2008 2009 2010 2011
------- ------- ------- ------- ------- ------- ------- -------
Book Pre-tax Income (Loss) 2,606 4,175 9,195 6,580 4,854 6,467 7,061 8,196
Depreciation 9,680 12,291 12,291 12,291 12,291 12,291 12,291 12,291
Amortization 1,304 1,490 1,490 1,490 791 791 791 791
Income Tax Payments -- -- -- -- -- -- -- --
Change in Receivables (1,588) (756) (518) 283 207 (106) (62) (60)
Change in Payables 400 301 91 21 76 27 76 36
Change in Prepaid Expenses (414) (113) (28) 44 28 16 16 15
------- ------- ------- ------- ------- ------- ------- -------
Cash Flow From Operations 11,987 17,387 22,522 20,711 18,248 19,487 20,173 21,270
------- ------- ------- ------- ------- ------- ------- -------
Debt Funded (Assumed) --
Equity Contributions 17,878 2,150
Uses of Capital (17,878) (2,150)
Sr. Debt 144A (511) (6,090) (9,611) (8,932) (7,835) (9,141) (10,118) (11,410)
UC Loan (3,856)
Cash from Financing Activities
Cash Generated During Period
Reserve Fund Withdrawals 11,749 13,767 23,257 21,621 17,936 19,392 19,963 21,947
Reserve Fund (Payments) (11,987) (15,237) (22,522) (20,711) (18,248) (19,487) (20,173) (21,270)
Less Capital Investment (1,647) -- -- (1,000) -- -- -- (1,000)
Reclamation Fund (31) (31) (31) (31) -- -- -- --
------- ------- ------- ------- ------- ------- ------- -------
Beginning Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- -------
Cash Balance Before Distribution 8,203 12,296 16,115 14,158 12,601 12,750 12,345 12,037
------- ------- ------- ------- ------- ------- ------- -------
Cash (Distributions) Calls * (5,703) (9,796) (13,615) (11,658) (10,101) (10,250) (9,845) (9,537)
------- ------- ------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- ------- ------- -------
Ending Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- -------
2012 2013 2014 2015 2016 2017 2018 2019 2020
------- ------- ------- ------- ------- ------- ------- ------- -------
Book Pre-tax Income (Loss) 6,498 7,355 9,392 12,147 12,551 13,513 3,606 5,952 6,276
Depreciation 12,291 12,291 12,291 12,291 12,291 12,291 12,291 8,862 8,862
Amortization 791 791 791 791 791 791 791 -- --
Income Tax Payments -- (4,314) (7,163) (8,127) (8,268) (8,605) (5,138) (4,916) (5,029)
Change in Receivables 165 (90) (146) (193) 18 (21) 2,118 1,128 37
Change in Payables 57 58 60 61 62 63 (1,139) (811) 28
Change in Prepaid Expenses 15 15 14 14 13 13 101 41 0
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash Flow From Operations 19,818 16,107 15,240 16,984 17,459 18,046 12,632 10,257 10,174
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Funded (Assumed)
Equity Contributions
Uses of Capital
Sr. Debt 144A (11,001) (11,943) (13,821) (16,165) (17,271) (18,549) (13,234) (11,890) (12,477)
UC Loan
Cash from Financing Activities
Cash Generated During Period
Reserve Fund Withdrawals 19,817 15,687 14,671 17,119 17,555 21,424 13,844 10,466 16,807
Reserve Fund (Payments) (19,818) (16,107) (15,240) (16,984) (17,459) (18,046) (12,632) (10,257) (10,174)
Less Capital Investment -- -- -- (1,000) -- -- -- (1,000) --
Reclamation Fund -- -- -- -- -- -- -- -- --
------- ------- ------- ------- ------- ------- ------- ------- -------
Beginning Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash Balance Before Distribution 11,315 6,244 3,349 2,454 2,784 5,376 3,110 76 6,830
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash (Distributions) Calls * (8,815) (3,744) (849) 46 (284) (2,876) (610) 2,424 (4,330)
------- ------- ------- ------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- ------- ------- ------- -------
Ending Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- ------- -------
INCREASED O&M COSTS/DECREASED SRAC RATE
SCHEDULE OF DEBT COVERAGE RATIOS AMOUNTS IN
THOUSANDS
2004 2005 2006 2007 2008 2009 2010 2011
------- ------- ------- ------- ------- ------- ------- -------
SOURCES OF CASH
Energy Payments 42,087 48,313 54,405 47,651 46,672 48,117 49,107 50,163
Capacity Payments 17,054 19,804 19,957 19,943 18,479 18,464 18,436 18,345
Bonus & Other Payments 1,691 1,852 1,874 1,882 1,891 1,908 1,925 1,941
Working Capital (1,606) (574) (459) 629 307 (77) 10 (31)
------- ------- ------- ------- ------- ------- ------- -------
TOTAL SOURCES OF CASH 59,226 69,395 75,778 70,105 67,349 68,412 69,477 70,417
------- ------- ------- ------- ------- ------- ------- -------
CASH OPERATING COSTS
Plant & Field O&M 22,227 25,922 26,932 27,482 28,044 28,617 29,202 29,799
Other O&M Including MM 5,350 5,267 5,355 5,061 5,412 5,166 5,488 5,318
Owner's Costs 3,522 3,507 4,188 4,011 3,818 3,883 3,967 4,055
Property&Other Taxes 1,075 1,288 1,280 1,177 1,105 1,058 1,011 965
------- ------- ------- ------- ------- ------- ------- -------
TOTAL CASH OPERATING COSTS 32,174 35,984 37,754 37,731 38,378 38,724 39,668 40,137
------- ------- ------- ------- ------- ------- ------- -------
NET OPERATING CASH FLOW 27,052 33,411 38,024 32,374 28,971 29,688 29,809 30,281
------- ------- ------- ------- ------- ------- ------- -------
Debt Service of Ormesa Loan 4,784
NET CASH FOR BONDS REPAYMENT 22,268 33,411 38,024 32,374 28,971 29,688 29,809 30,281
DEBT SERVICE
Principal Payments 511 6,090 9,611 8,932 7,835 9,141 10,118 11,410
Interest Expense 13,897 15,725 15,144 14,354 13,629 12,947 12,162 11,290
Agent & Other Fees 200 203 206 209 212 215 219 222
------- ------- ------- ------- ------- ------- ------- -------
TOTAL DEBT SERVICE 14,609 22,018 24,961 23,494 21,676 22,304 22,499 22,922
------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio 1.52 1.52 1.52 1.38 1.34 1.33 1.32 1.32
======= ======= ======= ======= ======= ======= ======= =======
Less: Subordinated Fees 0 0 0 0 0 0 0 0
------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio with
Subordination 1.52 1.52 1.52 1.38 1.34 1.33 1.32 1.32
======= ======= ======= ======= ======= ======= ======= =======
2012 2013 2014 2015 2016 2017 2018 2019 2020
------- ------- ------- ------- ------- ------- ------- ------- -------
SOURCES OF CASH
Energy Payments 50,649 51,941 53,808 56,441 56,778 57,259 41,183 32,722 32,721
Capacity Payments 16,012 15,943 15,864 15,343 15,171 15,080 9,628 6,793 6,712
Bonus & Other Payments 1,958 1,976 1,994 2,013 1,924 1,937 1,160 686 696
Working Capital 225 (30) (77) (103) 69 42 822 210 34
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL SOURCES OF CASH 68,843 69,829 71,590 73,694 73,943 74,319 52,793 40,412 40,163
------- ------- ------- ------- ------- ------- ------- ------- -------
CASH OPERATING COSTS
Plant & Field O&M 30,408 31,030 31,664 32,312 32,972 33,647 20,597 13,719 14,009
Other O&M Including MM 5,397 5,476 5,557 5,640 5,723 5,809 5,199 2,339 2,382
Owner's Costs 4,090 4,631 4,721 4,808 4,876 4,933 4,582 3,752 3,686
Property&Other Taxes 919 873 828 783 739 696 654 649 632
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL CASH OPERATING COSTS 40,813 42,010 42,770 43,542 44,311 45,085 31,032 20,458 20,709
------- ------- ------- ------- ------- ------- ------- ------- -------
NET OPERATING CASH FLOW 28,030 27,819 28,820 30,152 29,632 29,234 21,760 19,953 19,454
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Service of Ormesa loan
NET CASH FOR BONDS REPAYMENT 28,030 27,819 28,820 30,152 29,632 29,234 21,760 19,953 19,454
DEBT SERVICE
Principal Payments 11,001 11,943 13,821 16,165 17,271 18,549 13,234 11,890 12,477
Interest Expense 10,343 9,404 8,366 7,162 5,788 4,317 2,874 1,795 788
Agent & Other Fees 225 229 232 236 239 243 246 250 254
------- ------- ------- ------- ------- ------- ------- ------- -------
TOTAL DEBT SERVICE 21,570 21,576 22,420 23,563 23,298 23,108 16,354 13,934 13,519
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio 1.30 1.29 1.29 1.28 1.27 1.27 1.33 1.43 1.44
======= ======= ======= ======= ======= ======= ======= ======= =======
Less: Subordinated Fees 0 0 0 0 0 0 0 0 0
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Coverage Ratio with
Subordination 1.30 1.29 1.29 1.28 1.27 1.27 1.33 1.43 1.44
======= ======= ======= ======= ======= ======= ======= ======= =======
INCREASED O&M COSTS/DECREASEDARAC RATE
Pro-forma Projected Statement of Cash Flow
for the Periods Indicated
In thousands of dollars
2004 2005 2006 2007 2008 2009 2010 2011
------- ------- ------- ------- ------- ------- ------- -------
Book Pre-tax Income (Loss) 2,649 4,276 9,351 3,401 1,740 3,520 4,336 5,718
Depreciation 9,680 12,291 12,291 12,291 12,291 12,291 12,291 12,291
Amortization 1,304 1,490 1,490 1,490 791 791 791 791
Income Tax Payments -- -- -- -- -- -- -- --
Change in Receivables (1,591) (761) (522) 563 203 (121) (82) (82)
Change in Payables 400 301 91 21 76 27 76 36
Change in Prepaid Expenses (414) (113) (28) 44 28 16 16 15
------- ------- ------- ------- ------- ------- ------- -------
Cash Flow From Operations 12,027 17,483 22,674 17,812 15,130 16,525 17,428 18,769
------- ------- ------- ------- ------- ------- ------- -------
Debt Funded (Assumed) --
Equity Contributions 17,878 2,150
Uses ol Capital (17,878) (2,150)
Sr. Debt 144A (511) (6,090) (9,611) (8,932) (7,835) (9,141) (10,118) (11,410)
UC Loan (3,856)
Cash from Financing Activities
Cash Generated During Period
Reserve Fund Withdrawals 11,789 13,863 23,409 18,722 14,817 16,430 17,218 19,447
Reserve Fund (Payments) (12,027) (15,333) (22,674) (17,812) (15,130) (16,525) (17,428) (18,769)
Less Capital Investment (1,647) -- -- (1,000) -- -- -- (1,000)
Reclamation Fund (31) (31) (31) (31) -- -- -- --
------- ------- ------- ------- ------- ------- ------- -------
Beginning Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- -------
Cash Balance Before Distribution 8,243 12,392 16,266 11,259 9,483 9,788 9,601 9,536
------- ------- ------- ------- ------- ------- ------- -------
Cash (Distributions) Calls* (5,743) (9,892) (13,766) (8,759) (6,983) (7,288) (7,101) (7,036)
------- ------- ------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- ------- ------- -------
Ending Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- -------
2012 2013 2014 2015 2016 2017 2018 2019 2020
------- ------- ------- ------- ------- ------- ------- ------- -------
Book Pre-tax Income (Loss) 4,155 5,135 7,216 9,774 10,454 11,549 4,736 8,836 9,516
Depreciation 12,291 12,291 12,291 12,291 12,291 12,291 12,291 8,862 8,862
Amortization 791 791 791 791 791 791 791 -- --
Income Tax Payments -- -- (4,167) (7,296) (7,534) (7,918) (5,533) (5,325) (6,163)
Change in Receivables 152 (103) (151) (178) (6) (34) 1,859 981 6
Change in Payables 57 58 60 61 62 63 (1,138) (812) 28
Change in Prepaid Expenses 15 15 14 14 13 13 101 41 0
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash Flow From Operations 17,462 18,187 16,054 15,457 16,071 16,757 13,107 11,984 12,249
------- ------- ------- ------- ------- ------- ------- ------- -------
Debt Funded (Assumed)
Equity Contributions
Uses ol Capital
Sr. Debt 144A (11,001) (11,943) (13,821) (16,165) (17,271) (18,549) (13,234) (11,890) (12,477)
UC Loan
Cash from Financing Activities
Cash Generated During Period
Reserve Fund Withdrawals 17,460 17,767 15,485 15,592 16,167 20,135 14,319 12,193 18,882
Reserve Fund (Payments) (17,462) (18,187) (16,054) (15,457) (16,071) (16,757) (13,107) (11,984) (12,249)
Less Capital Investment -- -- -- (1,000) -- -- -- (1,000) --
Reclamation Fund -- -- -- -- -- -- -- -- --
------- ------- ------- ------- ------- ------- ------- ------- -------
Beginning Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash Balance Before Distribution 8,959 8,323 4,163 927 1,396 4,086 3,585 1,803 8,905
------- ------- ------- ------- ------- ------- ------- ------- -------
Cash (Distributions) Calls* (6,459) (5,823) (1,663) 1,573 1,104 (1,586) (1,085) 697 (6,405)
------- ------- ------- ------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- ------- ------- ------- -------
Ending Cash Balance 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500
------- ------- ------- ------- ------- ------- ------- ------- -------
Offices:
Boston, MA
Denver,CO
Houston, TX
London,UK
New york, NY
Schenectady, NY
Washington, DC
Shaw Stone & Webster Management Consultants, Inc.
8310 South Valley Highway, #250 Englewood, CO 80112
Tele: 303-741-7900 Fax: 303-741-7599
