HomeMy WebLinkAbout4 UAMPS Intermountain Power Project Agenda Item # 4
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Memorandum
To: Board of Directors
From: Stephen Hollabaugh
Date: November 22, 2006
Subject: UAMPS Intermountain Power Project Unit #3
History-
The District is a UAMPS member and is active within the IPP#3 Project. The District has been
involved with this project for about the last five years. The District participated in funding for the
Development Phase of IPP#3. This project has progressed through the Development Phase,
and the District will soon enter into the Power Sales Contract of the project (construction phase).
At the October 18 Board meeting the following were reviewed and discussed
• Ownership Agreement
• Unit 3 Construction Lease, Use and Services Agreement
• Common Facilities and Site Agreement
At the November 1 Board meeting we discussed the following Documents:
• TDPUD future Resource Plan (also attached to this staff report)
• Power Sales Contract (most recent)
At the November 15 Board meeting, the district heard from the about Alternative energy and
some of the publics concerns about Coal and the length of the contract
New Information
Within the Board packet, there is an Executive Summary of the Intermountain Power Project
Unit 3 Project Agreements. These agreements are the same that were handed out and
reviewed by Steve Gross at the November 1st Board meeting. Also in this Board packet is an
updated Power Sales Contract and Resolution.
UAMPS IPP3
At this meeting (November 29th) there will be a presentation from Stephen Hollabaugh and Doug
Hunter (General Manager of UAMPS) discussing the following:
• Integrated Resource Plan; including the different generation options and how each
interact with each other in a portfolio. This presentation will discuss how to put together a
diverse portfolio and explain the energy and capacity needs of the different generation
types.
• Correct a lot of the misinformation concerning the existing Intermountain Power Plant
Units 1&2
• Clarify the technology being used in the Intermountain Power Plant Unit 3.
• Economics of different generation alternatives
• Transmission constraints
• Answer any question the Board may have
Previously on the November 15, 2006 agenda memorandum:
• Economics of IPP Unit 3
o As a base load resource the District can stabilize its power supply needs for our
customers. The estimated cost of IPP Unit three is under $40 MWh. This is
compared to a market price of about $70 MWh. What does this difference
represent? At a conservative $30 MWh difference this represents about
$5,000,000 a year savings to our customers. If we do not enter into this
contract and incur the additional cost of $5,000,000 annually we will require
approximately a 25% to 30% rate increase to just cover the cost of the base
resource.
• Current WAPA contract and possible future small hydro generation (Stampede) within the
TDPUD resource mix.
o The District worked on acquiring a WAPA allocation since the 1980's and was
stopped by PG&E and Sierra Pacific Power Company who denied the District
transmission access. The District finally acquired a small allocation of WAPA that
started in 2005. As one can see, it takes a long time and a lot of work to acquire
hydro based generation. This varies with hydro conditions and may represent 2%
to 5% of our energy portfolio.
o The District submitted a proposal with the City of Fallon for the Stampede
Generation on June 7, 2006 this generation will be a great asset to our power
supply portfolio. The generation is a run of the river non-firm energy product. Our
submittal was the only submittal for this generation. Stay tuned to future updates.
Making progress with a Federal agency can sometimes take time. The District is
hopeful that by April of 2007 it might have access to some of this generation. This
may represent about 5000 MWhs a year or about 2% to 3% of our energy
portfolio.
• Current District efforts concerning Green building and alternative energy.
o District staff (Scott Terrell) is a member of both the Town of Truckee Green
Building Committee and the Sierra Green Building Association. Scott has worked
2 UAMPS IPP3
with SiGBA, the Town of Truckee, CATT and others to put together green building
education and training programs, classes and a Regional Green Building
Resource Guide to help contractors, businesspersons and homeowners make use
of the benefits of green building. Staff works closely with the Truckee building
community and homeowners to integrate green design in as many projects as
possible. Truckee is considered the Greenest Small Town in America 2010 based
on the square footage of commercial green buildings per capita anywhere in the
country. The District was also instrumental in working with the Truckee Recreation
and Parks District to pilot a small Biomass Gasification electric and heat
generation project located at the Truckee Regional Park.
Power Sales Contract:
Steve Gross will present the Power Sales Contract at the November 29, 2006 meeting in
substantially complete form.
Conclusion:
If the District is able to secure a low cost base resource, it provides balance to our portfolio. This
will allow the District to pursue additional energy resource options including conservation efforts,
renewable and other fuel resources. The IPP Unit 3 meets the needs of the District for a base
load resource and is located where transmission is available for reliable delivery.
Given the Integrated Resource Plan options, the Board will need to make a policy decision
concerning the resource mix. Once this is done, the Board can address the amount of base
load resource needed and if the Intermountain Power Plant Unit 3 meets this need.
3 UAMPS IPP3
Generation and Consumption of Fuels for Electricity Generation,
July 2006
Energy Information Administration, Electric Power Monthly, October 2006
Year-to-date, 48.6 percent of the Nation's electric power was generated at coal-fired plants (Figure 1).
Nuclear plants contributed 19.5 percent, 19.5 percent was generated by natural gas-fired plants, and 1.6
percent was generated at petroleum-fired plants. Conventional hydroelectric power provided 8.0 percent
of the total, while other renewables (primarily biomass, but also geothermal, solar, and wind) and other
miscellaneous energy sources generated the remaining electric power.
Figure 1. Net Generation Shares by Energy Source:
Total (All Sectors),Year-to-Date through July, 2006
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3_0%1.6 1+pz, 4 -6%
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19.5%
7_
:X Coal 11:: Hydroelectric
Natural Gals Nuclear
11 Other Energy Sources Petroleum
4 UAMPS IPP3
11/15/06
EXECUTIVE SUMMARY
INTERMOUNTAIN POWER PROJECT UNIT 3
PROJECT AGREEMENTS
This Executive Summary provides a summary description the basic terms and provisions
of the principal Project Agreements providing for the acquisition, construction and operation of
Intermountain Power Project Unit 3 (the "Project"). These Project Agreements are (i) the
Ownership Agreement (the "Ownership Agreement") among Utah Associated Municipal Power
Systems and the other co-owners of Unit 3 (collectively, the "Owners"), (ii) the Common
Facilities and Site Agreement (the "CFA"), (iii) the Construction Lease, Use and Services
Agreement (the "CLUSA") and (iv) the Joint Operating Agreement (the "JOA"). The Owners,
Intermountain Power Agency ("IPA") and the Department of Water and Power of the City of
Los Angeles ("LADWP") are all parties to the CFA, the CLUSA and the JOA.1
Each of the Project Agreements is presently in draft form and subject to continuing
negotiations by the parties. Approval of each Project Agreement by the UAMPS Unit 3 Project
Management Committee is required before its execution. This Executive Summary does not
summarize and describe all of the provisions of the Project Agreements and Participants should
refer to the complete copies of the Project Agreements for further details.
Except as otherwise defined herein,capitalized terms have the meanings assigned to them in the Intermountain
Unit 3 Power Sales Contracts. Please note that the term"Project"means UAMPS' undivided ownership
interest in the 900 MW third generating unit to be constructed at the Intermountain Generating Station and
"Unit 3"means the entire 900 MW third generating unit to be constructed at the Intermountain Generating
Station.
Power-Proj ectAgreements
THE OWNERSHIP AGREEMENT
Ownership and Percentage Share
Each Owner will own its percentage Ownership Interest as a tenant in common in the
Unit 3. Each Owner's Percentage Share determines the amount of Capacity available to such
Owner, as well as such Owner's share of the costs for Construction Work, Capital Improvements
and Operating Expenses.
Operating Committee
The Owners will form an Owners Committee that will be responsible for, and will have
the exclusive authority to carry out, all decisions regarding constructing, equipping, designing,
operating, maintaining and administering the Unit 3. Each Owner will appoint one
representative (and one alternate) to the Owners Committee. Any action of the Owners
Committee must be taken at a noticed meeting that is attended by a majority of the
representatives and must be approved by both (i) a majority of the representatives, and (ii) a
majority of the Percentage Shares, except as otherwise provided. The Owners Committee will,
among other duties, appoint and supervise the Project Manager and the Operating Agent, adopt a
Fuel Operating Plan, approve annual budgets, obtain and maintain governmental approvals and
schedule delivery of Capacity.
Construction Costs
Each month during the Construction Work, the Owners Committee will require the
Project Manager to issue an invoice to the Owners stating the amount required to be deposited
into the Operating Account for payment of Construction Costs, which payment will be due on or
before the tenth day of the succeeding month. If circumstances require, the Owners Committee
or the Project Manager will notify the Owners that additional funds are required to be deposited
into the Operating Account for the payment of Construction Costs.
Scheduling Capacity
Each Owner will schedule its Percentage Share of the General Service Requirements
subject to Planned Outages, Operating Emergencies or other restrictions as determined by the
Operating Agent. Each Owner is obligated to take delivery of its Percentage Share of the
Minimum Generating Capability. Each Owner will schedule and deliver to the High Voltage
Switchyard its Percentage Share of the Testing and Start-Up Capacity and Energy as necessary.
Each Owner will provide its own electric reserve requirements, including spinning reserves, for
its Percentage Share of the Available Generating Capability.
Capital Improvements
Each Owner will pay its Percentage Share of the costs incurred for Capital Improvements
as provided in the Owners Committee's annual capital expenditures budget. Upon the adoption
of an annual capital expenditures budget, the Owners Committee will submit to the Owners a
forecast of cash flow requirements for each authorized Capital Improvement.
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Operating Expenses
Each month, each Owner will advance its share of Operating Funds as shown on the
estimated billing for the next month's cost of Operating Work and Capital Improvements. Any
disputed billings will be paid and then protested as provided in the Ownership Agreement.
Liens
No Owners will be permitted to create any Lien on the Unit 3 other than:
• a Permitted Lien secured by an Owner's Ownership
Interest;
• Liens for taxes not yet due;
• certain mechanics' or materialmen's liens or other similar
Liens arising in the ordinary course of business; and
• certain other Liens expressly permitted under the Project
Documents.
Restrictions on Transfer
No Owner may Transfer any portion of its Ownership Interest without the prior written
consent of the Owners Committee except for the following Permitted Transfers:
• a Transfer pursuant to foreclosure of a Permitted Lien;
• a Transfer to an Affiliate, provided that such Affiliate is
Creditworthy;
• a Transfer to another Owner that is not in default of its
obligations under the Ownership Agreement;
• a Transfer to any Creditworthy Person.
Right of First Refusal
For any Permitted Transfer, the other Owners will have a six month right of first refusal
to purchase the Ownership Interest on the same terms as offered to a third party.
Insurance and Casualty
The Ownership Agreement specifies the types and amounts of insurance to be maintained
by the Owners Committee and procedures for repair and replacement in the event of damage to
the Unit 3.
Defaults and Remedies
In the event any Owner is in Default, the Non-Defaulting Owners have the right to sell or
use the Defaulting Owner's Capacity. If the default continues for 60 days, the Non-Defaulting
Owners have the right to terminate or sell the Defaulting Owner's Ownership Interest.
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Indemnification
Each Owner agrees to indemnify the other Owners for any Third-Party Liability incurred
by the Indemnifying Owner, including Willful Actions, Liens and Personal Taxes. Other
liabilities will be Shared Liabilities of the Unit 3 and allocated among the Owners in accordance
with their Percentage Interests.
Termination
The Ownership Agreement will terminate on the later of: (i)December 31, 2057, or
(ii) the date on which the Unit 3 shall have been permanently removed from service by the
Owners Committee.
COMMON FACILITIES AND SITE AGREEMENT
Unit 3 Site
The Owners agree to purchase from IPA fee title to the parcel of land constituting the site
of Unit 3, subject to certain nonexclusive rights of IPA. The Owners will acquire undivided
ownership interests in the Unit 3 site, as tenants in common, in accordance with their percentage
ownership interests in Unit 3.
Existing Common Facilities
IPA will sell to Owners (in proportion to their ownership interests in Unit 3) an undivided
interest in the Existing Common Facilities (including land, buildings, improvements, facilities,
equipment, water supply, rolling stock and personal property) of the Intermountain Power
Project. The Existing Common Facilities will be used in the operation, maintenance, repair,
replacement and improvement of Unit 3 in common with Units 1 and 2. The Owners have also
agreed on the values of the Existing Common Facilities as of the Effective Date. IPA will be
responsible for any replacement or additions to the Existing Common Facilities prior to the
Closing Date and the values will be adjusted accordingly. The listed values of the Existing
Common Facilities (with some exceptions) will escalate at the rate of 2.25% per annum until the
Closing Date.
Required Common Facilities Additions and Improvements
Other land, buildings, improvements, facilities and equipment will be acquired and/or
added to the Existing Common Facilities to provide the necessary capability for the service and
support of Unit 3 in common with the service and support of Units 1 and 2 ("Required Common
Facilities Additions and Improvements"). Such Required Common Facilities Additions and
Improvements will be acquired, constructed, or added at the expense of the Owners (with
appropriate adjustment being made to the purchase price for the Existing Common Facilities).
IPA and the Owners will also share joint common ownership of the Required Common Facilities
Additions and Improvements.
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Joint Common Facilities
The Existing Common Facilities and the Required Common Facilities Additions and
Improvements constitute the Joint Common Facilities. Any additions or improvements of the
Joint Common Facilities subsequent to the Closing Date will become part of the Joint Common
Facilities. IPA will own 66 2/3% of the Joint Common Facilities and the Owners will own the
remaining 33 1/3% in accordance with their ownership interests in Unit 3. IPA will retain title to
all other real property and facilities, including the Intermountain Generation Station, the
Southern Transmission System, and the Northern Transmission System. Various access
easements are also described. Payment to IPA for the Joint Common Facilities will be made in
three installments: first, upon start of construction; second, twenty-four months after start of
construction; and finally, on the Closing Date, which will be immediately prior to the
commercial operation of Unit 3.
Water Lease
IPA will to lease to the Owners (in proportion to the Joint Common Facilities
Percentages) water rights for a term of 50 years with two successive 20-year renewal options.
The rent for the initial term will be prepaid as part of the Joint Common Facilities Purchase
Price.
Several Obligations
The obligations of the Owners to make payments under the CFA are several and not joint
and are proportionate to each Owner's ownership interest in Unit 3.
Insurance
Prior to the Closing Date, IPA will maintain with respect to the Joint Common Facilities
all risk property insurance, general liability insurance, property damage insurance and other
insurance as provided for in the IPP Agreements and consistent with Prudent Utility Practice.
Proceeds of such insurance will be applied as provided for in the IPP Agreements. After the
Closing Date, IPA and the Owners will maintain insurance with respect to the Joint Common
Facilities as provided in the Joint Operating Agreement.
Taxes
After the Closing Date, IPA and the Owners will each separately report and otherwise be
responsible for the payment of all property taxes, payments or fees in lieu of taxes and impact
alleviation or mitigation payments with respect to their respective undivided ownership interests
in the Joint Common Facilities or gross receipts. The Owners are responsible for payment of all
sales and transfer taxes and recording fees, if any, incurred in connection with the transfer of the
real or personal property under the CFA.
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Covenants Against Liens
Prior to the Closing Date, IPA will not allow any unsatisfied liens on the Joint Common
Facilities except for ordinary course mechanics liens not yet due or being contested. Neither IPA
nor the Owners will allow any unsatisfied lien on their respective ownership interests in the Joint
Common Facilities except as permitted by the Common Facilities Agreement, the Unit 3
Construction Lease and Agreement or the Joint Operating Agreement.
Retirement of Units
Upon the retirement from service and decommissioning of Units 1 and 2 while Unit 3
continues in operation, IPA is required to restore the Units 1 and 2 site and sell to the Owners
IPA's remaining rights in the Joint Common Facilities (other than IPA's water rights constituting
Joint Common Facilities) for salvage value as determined by a Decommissioning Consultant.
Similar procedures are described for the decommissioning of Unit 3, with the Owners selling
their remaining rights in the Joint Common Facilities to IPA.
Default and Remedies
Failure by IPA or the Owners to meet their payments or other obligations under the CFA
will constitute a default, in which case IPA or Los Angeles can terminate the CFA. The Owners
and IPA have the right to enforce any other legal remedies but there is no alternative dispute
resolution procedure specified.
Transfer or Assignment
Any Owner's rights in the CFA are subject to certain restrictions but an Owner may
transfer its interest in the CFA to the following:
• any trustee or secured party, as security for bonds or other
indebtedness of such Owner, and such trustee or secured
party may sell such security in foreclosure proceedings,
possess or take control or cause a receiver to be appointed
with respect thereto; or
• any corporation or other entity merging with, or acquiring
all or substantially all of the property of, the Owner.
Obligations of IPA and Los Angeles
The Owners acknowledge that IPA and Los Angeles have independent obligations and
responsibilities with respect to the Intermountain Power Project and to the IPP Power Purchasers
and that nothing in the CFA will be interpreted as preventing IPA and Los Angeles from
exercising their rights or fulfilling their duties under the IPP Agreements and related agreements.
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Term
The CFA remains in effect until such time as Unit 3, or Units 1 and 2, have been
decommissioned and all sales and payments associated with such decommissioning have been
made.
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CONSTRUCTION LEASE, USE AND SERVICES AGREEMENT
Purpose
The purpose of the CLA is to lease and to obtain rights to use certain portions of the IPP
Site and certain buildings, structures, infrastructure, property and improvements and equipment,
facilities and entitlements for the purposes of the construction and installation of Unit 3 and to
obtain certain utility and other services necessary for the construction and installation of Unit 3.
Term
The term of the CLA shall continue until unless extended as necessary to take
into account any Uncontrollable Forces. The CLA may also be terminated earlier in the event of
completion of Unit 3 or abandonment of construction of Unit 3.
Lease of Real and Personal Property
The Exhibits to the CLA describe the real and personal property, buildings,
infrastructure, improvements, equipment, vehicles and other property to be leased to the Owners
for the construction of Unit 3 under the CLA and the applicable rental rates.
Non-Exclusive Licenses
The Exhibits to the CLA describe the property, contract rights, permits governmental
approvals and other intangible property to be licensed to the Owners for the construction of Unit
3 and the applicable fees and charges. Owners will have the right to use up to one-third of the
capability of the Joint Common Facilities as required for testing and start-up of Unit 3 and the
Commercial Operation.
Grant of Easements
IPA grants to the Owners temporary non-exclusive easements across the IPP Site for
conduits and facilities for necessary utilities and for access to Unit 3 Construction Properties and
Facilities. IPA reserves for itself utility easements and access easements for the benefit of Units
1 and 2.
Participation of IPA and Los Angeles
Owners agree to keep IPA, Los Angeles and IPSC fully informed of their plans and
actions pertaining to the licensing, construction, installation, testing, start-up and Commercial
Operation of Unit 3. IPA, Los Angeles and IPSC will be notified and permitted to attend all
meetings with third parties and to provide input and objections to activities, plans or proposals
that could have a material adverse effect on any IPP Facilities or on the IPP Power Purchasers.
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Plans and Specifications
Owners agree to provide copies of the Unit 3 Plans and Specifications to be furnished to
IPA and Los Angeles. IPA and Los Angeles will have the right to approve the Unit 3 Plans and
Specifications and to object if they are not in compliance with the requirements of the CLA.
Completion of Unit 3
Owners agree to proceed with the licensing, construction, installation, testing and start-up
and the Commercial Operation of Unit 3 with reasonable diligence and in accordance with
Prudent Utility Practice so as to complete such activities, including site restoration, not later than
, 20_, unless prevented by Uncontrollable Forces.
Design and Construction; Switchyard Additions
Unit 3 will be designed, constructed and installed so that its operation will be compatible
with the operation of Units 1 and 2 and the other IPP Facilities and will permit the common and
coordinated operation of the three Units in accordance with Prudent Utility Practice. The
Owners agree to pay for a consulting firm to study the sufficiency of the capability of the
existing IPP switchyard facilities and the compliance thereof with the reliability standards of the
Western Electric Coordinating Council in accommodating the power flows associated with Unit
3 as well as Units 1 and 2. Any required upgrade will be funded as Required Common Facilities
Additions and Improvements.
Liability for IPA Increased Costs
If any activities related to Unit 3 require any modification of or addition to Units 1 or 2 or
other IPP Facilities not otherwise provided for in the CLA or result in an increase in the costs of
Units 1 and 2 or any other IPP Facilities, or result in the reduced availability of the output of
Units 1 and 2, the Owners will reimburse IPA or IPP Power or IPP Power Purchasers.
Water Service
IPA, Los Angeles and/or IPSC will furnish water, electricity, telephone, garbage, fire,
hazmat and other services to meet the requirements for the licensing, construction, installation,
testing and start-up and the Commercial Operation of Unit 3. The Owners shall pay for such
services in accordance with the rate schedules in the CLA.
Insurance
The CLA describes the amounts and types of insurance that must be maintained by the
Owners.
Indemnification
Unit 3 Owner Participants agree to indemnify IPA, Los Angeles and IPSC and their
respective employees and agents, for all liabilities as a result of:
9
• the design, licensing, construction, installation, testing,
start-up or Commercial Operation of Unit 3, including
activities related or incidental thereto, undertaken under the
Construction Lease and Agreement;
• the use, possession, condition, operation, maintenance or
management of the Unit 3 Construction Properties and
Facilities;
• any violation of laws, covenants, restrictions, easements or
conditions affecting the Unit 3 Construction Properties and
Facilities; or
• any failure on the part of the Unit 3 Owner Participants or
any contractor or employee of any Unit 3 Owner
Participant to perform or comply with any of the provisions
contained in the Construction Lease and Agreement.
from any and all mechanics', laborers', materialmen's liens or other liens filed or arising from
the design, licensing, construction, installation, testing, start-up or Commercial Operation of Unit
3.
Events of Default
Failure by the Owners to meet their payments or other obligations under the CLA will
constitute an Event of Default in which case IPA or Los Angeles can terminate the CLA.
Confidential Information
The disclosure of Unit 3 Confidential Information and IPP Confidential Information is
restricted.
Dispute Resolution
Any Disputed Matter will initially be determined by a Project Consultant appointed by
the parties to settle the dispute in compliance with the CLA and consistent with Prudent Utility
Practice. Each party will be obligated to comply with the recommendations of the Project
Consultant unless it determines that such recommendation would violate applicable law, cause a
breach of the IPP Agreements, endanger the safe operation of Units 1 or 2 or any other IPP
Facility or the safety of construction, installation work, testing, start-up or Commercial
Operation of Unit 3, as applicable. The costs of the Project Consultant will be paid for solely by
the Owners. Either party may challenge the determination of the Project Consultant by judicial
action.
Transfer or Assignment
Any Owner's rights in the CLA are subject to certain restrictions but an Owner may
transfer its interest in the CLA to the following:
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• any trustee or secured party, as security for bonds or other
indebtedness of such Owner, and such trustee or secured
party may sell such security in foreclosure proceedings,
possess or take control thereof or cause a receiver to be
appointed with respect thereto;
• any corporation or other entity merging with, or acquiring
all or substantially all of the property of, the Owner.
Provided that such transaction(i) also transfers all of the Owner's Ownership Interest in Unit 3
and (ii) does not affect the federal tax exempt status of interest on the IPA Bonds.
Several Obligations
The obligations of the Owners to make payments under the CLA are several and not joint
and will be proportionate to each Owner's Percentage Interest.
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JOINT OPERATING AGREEMENT
Joint Project Agent; Joint Operating Agent
IPA is appointed as the Joint Project Agent. Los Angeles is appointed as the Joint
Operating Agent, including being responsible for arranging the procurement, transportation and
delivery of coal for the Common Coal Stockpile. IPSC, at the direction of the Joint Operating
Agent, will perform substantially the same responsibilities with respect to Unit 3 as it performs
and carries out with respect to Units 1 and 2, including the Joint Agency Services.
Joint Operating Committee
The Joint Operating Committee will consist of(i) seven members designated by IPA and
the IPP Coordinating Committee, including members representing IPP Power Purchasers with
IPP Generation Entitlement Shares totaling at least 60%, and (ii) three members designated by
the Unit 3 Owners Committee, including members representing Owners with Unit 3 Ownership
Shares totaling at least 60%. Action by the Joint Operating Committee will be taken by a vote of
80% of all the members of the Joint Operating Committee with each member having one vote,
provided that such vote shall include the approval vote of members representing (a) IPP Power
Purchasers with at least 60% of IPP Generation Entitlement Shares and (b) Owners with at least
60% of Unit 3 Ownership Shares. The responsibilities of the Joint Operating Committee will
include approving the Common Operating Budget and any Common Facilities Capital
Improvement Budget and approving policies and guidelines relating to the Common Coal
Stockpile, the Common Operating Services, the Unit 3 Discrete Operating Services and Units 1
and 2 Discrete Operating Services.
Common Operating Services by Joint Operating Agent and IPSC
The Joint Operating Agent will have responsibility for performing, or causing IPSC to
perform, on behalf of IPA and the Owners in accordance with Prudent Utility Practice all
Common Operating Services, including the management, administration, control, operation,
maintenance, scheduling of maintenance and other outages, scheduling and delivery of
generation output, and the repair, replacement, renewal and improvement of Unit 3 and the Joint
Common Facilities.
Unit 3 Discretionary Operating Services
IPA, in its capacity as the Joint Project Agent, will have responsibility for performing in
accordance with Prudent Utility Practice certain Unit 3 Discrete Operating Services, including
administration services in connection with Utah taxes and payments in lieu of taxes, providing
public relations and legislative support services and arranging for services of auditors,
consultants and legal counsel. Los Angeles, in its capacity as the Joint Operating Agent, shall
have the responsibility for performing, or causing IPSC to perform, in accordance with Prudent
Utility Practice the Unit 3 Discrete Operating Services, other than those to be performed by the
Joint Project Agent
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Entitlement to Available Output, Scheduling and Dispatching
Each Owner will be entitled to schedule Capacity and Energy from Unit 3 up to an
amount equal to its Unit 3 Ownership Share of the Available Generating Capability. The
Capacity and Energy of Unit 3 will be scheduled by each Owner with the Joint Operating Agent,
subject to scheduled outages, planned interruptions or shutdowns of Unit 3 or the Joint Common
Facilities for safety, reliability or integrity requirements thereof and to Operating Contingencies.
Each Owner must schedule Capacity and Energy up to its Unit 3 Ownership Share of the Unit 3
Minimum Generating Capability during ramp-up and ramp-down of Unit 3.
Common Coal Stockpile; Ownership; Costs
The Common Coal Stockpile will be owned proportionately by IPA and each of the
Owners, as tenants in common. Coal Accounts are established for the purpose of measuring the
parties' respective Coal Accounts in terms of BTU. The Unit 3 Coal Procurement Agent shall
negotiate, and each of the Unit 3 Coal Procurement Agency Participants will enter into, contracts
as recommended by the Unit 3 Coal Procurement Agent for the procurement, transportation and
delivery of the coal supply for the Common Coal Stockpile. The Joint Operating Agent shall
provide the Coal Administration Services for all the coal procured, transported and delivered.
The Coal Procurement and Transportation Costs with respect to Unit 3 will be allocated
among such Unit 3 Coal Procurement Agency Participants in proportion to the amount of Energy
delivered to the Unit 3 Coal Procurement Agency Participants. The Owners have the option to
establish a Unit 3 Separate Coal Stockpile.
Operating Costs Budget and Allocation
The Common Operating Budget will be approved (after any changes by IPA and the IPP
Coordinating Committee) by the Unit 3 Owners Committee. Common Fixed Operating Costs
will be allocated between IPA and the Owners in the ratio that the Rated Capacity of Units 1 and
2 bears to the Rated Capacity of Unit 3. Common Variable Operating Costs will be allocated
between IPA and the Owners collectively, in the ratio that the amount of Energy generated
during such month by Units 1 and 2 (including General Service Requirements) bears to the
amount of Energy generated during such month by Unit 3 (including General Service
Requirements).
The Unit 3 Operating Budget will be approved by the Unit 3 Owners Committee. Unit 3
Allocated Common Fixed Operating Costs and Unit 3 Discrete Fixed Operating Costs will be
allocated among each of the Owners in proportion to their respective Unit 3 Ownership Shares.
Unit 3 Allocated Common Variable Operating Costs and Unit 3 Discrete Variable Operating
Costs will be allocated to each Owner in proportion to the amount of the net Energy delivered to
such Owner.
Common Facilities Capital Improvement Costs Budget and Allocation
The Common Facilities Capital Improvement Budget will be approved (after any changes
by IPA and the IPP Coordinating Committee) by the Unit 3 Owners Committee. Common
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Facilities Capital Improvement Costs will be allocated between IPA and the Owners collectively,
in the ratio that the Rated Capacity of Units 1 and 2 bears to the Rated Capacity of Unit 3. The
Unit 3 Capital Improvement Budget will be approved by the Unit 3 Owners Committee. Unit 3
Capital Improvement Costs will be allocated to each Owner in proportion to its Unit 3
Ownership Shares.
Common Auxiliary Services
The Joint Operating Agent will provide security, fire, hazmat, telephone, medical and
other services for Unit 3 and the Joint Common Facilities, as well as for Units 1 and 2 and the
other IPP Facilities.
Taxes
All Taxes and Impositions with respect to the Joint Common Facilities and any Capital
Improvements will be paid by IPA and the Owners in accordance with their respective ownership
interests. All Taxes and Impositions with respect to Unit 3 and any Capital Improvements will
be paid by each of the Owners in accordance with the Unit 3 Ownership Agreement.
Insurance
The JOA describes the amounts and types of insurance that must be maintained by the
IPA and the Owners for the Joint Common Facilities and Unit 3.
Permits and Approvals
All costs of maintaining compliance with environmental laws and regulations and with
permits and approvals, will be Common Operating Costs or Unit 3 Discrete Operating Costs, as
applicable, or Common Facilities Capital Improvement Costs or Unit 3 Capital Improvement
Costs, as applicable, under the Joint Operating Agreement. Each Owner will be entitled to a
prorata share of allowances or emission credits with respect to compliance of Unit 3 stack
emissions.
Indemnification
IPA and the Owners agree to indemnify the Joint Project Agent, the Joint Operating
Agent and IPSC, and the IPP Operating Agent from liabilities related to Unit 3 other than those
resulting from gross negligence or intentional wrongdoing by such parties.
Rights and Remedies
Upon any Event of Default, any party may exercise any right that may be available under
applicable law to enforce the JOA. Other rights and remedies of parties in the Event of Default
will be similar to the rights and remedies under the Ownership Agreement.
14
Retirement and Decommissioning
Upon the retirement from service and decommissioning of both Units 1 and 2 while Unit
3 continues in operation, IPA is required to restore the Units 1 and 2 site (exclusive of the sites of
the Joint Common Facilities) and sell to the Owners IPA's remaining rights in the Joint Common
Facilities (other than IPA's water rights constituting Joint Common Facilities) for salvage value
as determined by a Decommissioning Consultant. Similar procedures are described for the
decommissioning of Unit 3, with the Owners selling their remaining rights in the Joint Common
Facilities to IPA.
Transfer or Assignment
Any rights of IPA or the Owner under the JOA are subject to certain restrictions but an
Owner or IPA may transfer its interest in the JOA to the following:
• any trustee or secured party, as security for bonds or other
indebtedness, and such trustee or secured party may sell
such security in foreclosure proceedings, possess or take
control or cause a receiver to be appointed with respect
thereto; or
• any corporation or other entity merging with, or acquiring
all or substantially all of the property of, the Owner or IPA,
as applicable.
Several Obligations
The obligations of the Owners to make payments under the JOA are several and not joint
and will be proportionate to each Owner's ownership interest in Unit 3.
Obligations of IPA and Los Angeles
The parties acknowledge that IPA and Los Angeles have obligations and responsibilities
with respect to the Intermountain Power Project and to the IPP Power Purchasers and that
nothing in the JOA will be interpreted as preventing IPA and Los Angeles from exercising their
rights or fulfilling their duties under the IPP Agreements and related agreements.
Dispute Resolution
Any Disputed Matter will initially be submitted to the Joint Operating Committee for
review. If the matter is not resolved, the parties will appoint a Project Consultant to settle the
dispute in compliance with the JOA and consistent with Prudent Utility Practice. Each party will
be obligated to comply with the recommendations of the Project Consultant. The costs of the
Project Consultant will be Common Fixed Operating Costs. Either party may challenge the
determination of the Project Consultant by judicial action.
Term of Agreement
The JOA will remain in effect until the decommissioning of Units 1 and 2, or of Unit 3.
15
l�
IIIIIIIIIQ UII �E IIIIEIII III�I I�I�II�NER
I
y Public
Resolution No. 2006 - XXX
A Resolution authorizing and approving:
(1) a power supply resource plan; (2) the Intermountain Unit 3 Project
Power Sales Contract with Utah Associated Municipal Power Systems
("UAMPS"); (3) the Second Amendment to the UAMPS Agreement
for Joint and Cooperative Action; and (4) related matters.
WHEREAS, Truckee Donner Public Utility District (the "Participant") is a member of Utah
Associated Municipal Power Systems ("UAMPS") pursuant to the provisions of the Utah
Associated Municipal Power Systems Amended and Restated Agreement for Joint and Cooperative
Action, as amended (the "Joint Action Agreement");
WHEREAS, one of the purposes of UAMPS under the Joint Action Agreement is the
acquisition and construction of electric generating, transmission and related facilities in order to
secure reliable, economic sources of electric power and energy for its members;
WHEREAS, UAMPS has proposed to participate as a joint owner in the acquisition and
construction of a coal-fired electric generating facility at the Intermountain Generating Station in
Millard County, Utah, together with related facilities and equipment (the "Project");
WHEREAS, the Board of Directors of the Participant (the "Governing Body") has reviewed
the long-term power supply resource plan (the "Power Supply Resource Plan") of the Participant
which sets forth the needs of the Participant for long-term, reliable, cost-based supplies of electric
power and energy, has reviewed engineering studies and reports with respect to the Project and has
considered, among other things, the following: (a) the economies and efficiencies of scale to be
achieved through the acquisition and construction by UAMPS of the Project for the benefit of the
Participant and the other members of UAMPS participating in the Project, (b) the need of the
Participant for the electric energy represented by its Entitlement Share in the Project to meet its
current and reasonably expected power supply requirements and to provide reserve capacity, (c) the
estimated useful life of the Project, (d) the estimated time necessary for the acquisition and
construction of the Project and the length of time in advance necessary to obtain, acquire or
construct an additional or alternative power supply, (e) the reliability and availability of the
Participant's existing power supply sources, the Project and alternative power supply sources and
the cost or estimated cost thereof, and (f) all such other matters as were deemed necessary or
appropriate by the Participant as a basis for and in connection with its authorization and execution
of the Power Sales Contract;
WHEREAS, the Governing Body has also reviewed (or caused to be reviewed on its behalf)
copies of the current drafts of the Project Agreements (as defined in the Power Sales Contract) or
summaries thereof, and representatives of the Participant have participated in discussions and
conferences with UAMPS and others regarding the Project and have received from UAMPS all
Resolution 2006-XX I
requested information and materials necessary for the decision of the Governing Body to authorize
and approve the Power Sales Contract;
WHEREAS, the Participant acknowledges that the obligation of the Participant to make the
payments provided for in the Power Sales Contract will be a special obligation of the Participant
and an operating expense of the Participant's electric system, payable from the revenues and other
available funds of the electric system, and that the Participant shall be unconditionally obligated to
make the payments required under the Power Sales Contract whether or not the Project or any
portion thereof is acquired, constructed, completed, operable or operating and notwithstanding the
suspension, interruption, interference, reduction or curtailment of the output thereof for any reason
whatsoever;
WHEREAS, in connection with the Project, it is necessary and desirable for the Participant to
approve, authorize and execute the Second Amendment dated as of , 2006 (the
"Second Amendment") to the Joint Action Agreement to provide for the continuation of the
existence of UAMPS through the date on which the Project has been removed from service and all
indebtedness of UAMPS relating to the Project has been fully paid or discharged; and
WHEREAS, the Participant now desires to authorize and approve the Power Supply Resource
Plan, the Power Sales Contract and the Second Amendment;
Now, THEREFORE, BE IT RESOLVED by the Governing Body of Truckee Donner Public
Utility District, as follows:
Section 1. Approval of Power Supply Resource Plan. The Power Supply Resource Plan
of the Participant attached hereto as Annex A is hereby authorized and approved.
Section 2. Execution and Delivery of the Power Sales Contract; Participant's
Representative. (a) The Power Sales Contract, in substantially the form attached hereto as Annex B,
including the Participant's 4.444% Entitlement Share (representing approximately 20,000 kW of
capacity) is hereby authorized and approved, and the President is hereby authorized, empowered
and directed to execute and deliver the Power Sales Contract on behalf of the Participant, and the
Clerk of the Governing Body is hereby authorized, empowered and directed to attest and
countersign such execution and to affix the corporate seal of the Participant to the Power Sales
Contract, with such changes to the Power Sales Contract from the form attached hereto as Exhibit B
as shall be necessary to conform to the Participant's legal status, to complete the form of the Power
Sales Contract or to correct any minor irregularities or ambiguities therein and as are approved by
the President, his execution thereof to constitute conclusive evidence of such approval.
(b) The appointment of Stephen Hollabaugh as the Participant's Representative to
UAMPS and of Peter L. Holzmeister and J. Ron Hemig as alternate Representatives is hereby
confirmed. Such Representative (or, in his or her absence, such alternate(s)) is hereby delegated
full authority to act on all matters that may come before the Project Management Committee
established by the Power Sales Contract, and shall be responsible for reporting regularly to the
Governing Body regarding the activities of the Project Management Committee.
Section 3. Approval of Second Amendment. The Second Amendment, in substantially the
form attached hereto as Annex C is hereby authorized and approved, and the President is hereby
Resolution 2006-XX 2
authorized, empowered and directed to execute and deliver the Second Amendment on behalf of the
Participant, and the Clerk is hereby authorized, empowered and directed to attest and countersign
such execution and to affix the corporate seal of the Participant to the Second Amendment.
Section 4. Miscellaneous; Effective Date. (a) This resolution shall be and remain
irrepealable until the expiration or termination of the Power Sales Contract in accordance with its
terms.
(b) All previous acts and resolutions in conflict with this resolution or any part hereof are
hereby repealed to the extent of such conflict.
(c) In case any provision in this resolution shall be invalid, illegal or unenforceable, the
validity, legality and enforceability of the remaining provisions shall not in any way be affected or
impaired thereby.
(d) This resolution shall take effect immediately upon its adoption and approval.
PASSED AND ADOPTED by the Board of Directors of the Truckee Donner Public Utility District
in a meeting duly called and held within said District on the 15`h day of November, 2006.
AYES:
NOES:
ABSTAIN:
ABSENT:
TRUCKEE DONNER PUBLIC UTILITY DISTRICT
J. Ron Hemig, President
ATTEST:
Peter L. Holzmeister, Clerk of the Board
[SEAL]
Resolution 2006-XX 3
TRUCKEE DOEIIII
Public Utility District
Memorandum
To: Board of Directors
From: Peter Holzmeister
Subject: Letter sent to all customers
Date: November 22, 2006
Attached is a copy of the letter sent to all customers.
This is part of the outreach program to make sure all
customers have information about the proposal to
purchase power through UAMPS and give them a chance
to comment or attend the public hearing on the 29th.
These letters will begin appearing in mail boxes today.
Directors
Joseph R. Aguera
Truckee Donner J. Ron Hemig
Patricia S. Sutton
Tim F. Taylor
Public Utility District Bill Thomason
General Manager
Peter Holzmeister
November 17, 2006
Dear Valued Customer:
The Board of Directors of Truckee Donner PUD is considering entering into a contract for the
purchase of electric energy from a power plant in Utah. This has become a controversial idea. Two
points of view have been expressed regarding our plan. One point of view results in a large
increase in Truckee's electric rates. We are seeking input from the community.
The Truckee Donner PUD does not own or operate any power generation facilities. We buy the
power we need to serve our customers. Today, the primary method for generating electricity in the
United States is by burning coal. Other sources include nuclear plants, natural gas burning plants,
hydro generation plants, wind power and solar plants. Over the years the District has purchased
electric power from suppliers using primarily coal and hydro plants.
We have entered into many contracts over the years for the purchase of electric power. Our goal
has been to secure the most economical power available. Our current contract expires on April 1,
2009. Over the past six years we have been investigating various ways to best secure an
economical electric power supply. One of the options we have been considering is entering into a
contract to obtain power from a plant in Utah.
The plant in question has not yet been built. It is scheduled to be built by 2012. The plant will burn
coal to heat water to produce electricity. The contract would last for fifty years, unless we sell our
interest in it at an earlier time. The price for this power is approximately one-half the price of our
alternative sources of electric power. The cost to generate electricity at the new Utah plant will be
approximately $35 per megawatt of demand. The cost to acquire power from other available
sources is $74 per megawatt of demand. The amount of power we would purchase would cover the
portion of our power needs called base load. Base load is the electricity that the Truckee community
uses on a steady continuing basis. The remainder of our power needs, called peaking power needs,
would be satisfied by purchasing power from other sources.
There is an increasing requirement in the United States to consider environmentally friendly power in
a power supply portfolio. Environmentally friendly power using renewable and clean technology is
expensive, but we need to support these power generation technologies rather than just seek the
lowest cost power. We need to balance economics and environment. So we plan to aggressively
seek power from renewable power plants to satisfy the District's peaking energy requirement, as
well as growth in our base. However, this may be difficult given that right now only 6% of the power
generated in the Unites States is considered renewable power. Also, the location of that generation
is not in proximity to the transmission lines that serve Truckee. As the availability of renewable
generation increases we will be able to add these kinds of power sources to our portfolio.
P. O. Box 309—Truckee, CA 96160—Phone 530-587-3896—www.tdpud.org
As already stated in this letter, for many years the primary source of electric energy coming to
Truckee has been coal fueled generation. Our proposal to secure energy from the plant in Utah is
controversial because the fuel is coal. Coal is a concern because when burned it emits pollutants
into the environment and contributes to global warming. Advances in technology continue to
improve the cleanliness of coal plant emissions. This plant to be built in Utah will be state-of-the-art
and can be modified as further technological improvements are developed.
The District's goal is to secure low cost power from the Utah power plant ($35 per megawatt) for our
base load and use the savings to secure alternate fuel power for our peaking power needs. The
reality is that plants that burn coal are the only realistic option we have for serving our base load
Some people are genuinely concerned about the side effects associated with burning coal. They
believe that the Truckee community should make a clear statement that it values a clean and
healthy environment by rejecting this long term contract with a coal burning plant. They have
suggested that the District should use short term contracts with coal plants ($72 per megawatt) and
take advantage of renewable power plants as soon as possible to eliminate coal. We can do this,
but the cost is high. It would require a rate increase of 15 to 20% beginning on January 1, 2009. If
we also seek to secure renewable power plants, a very expensive source of power ($80 per
megawatt), we will need an additional increase of about 10%, as soon as January 1, 2009. So the
electric rates in Truckee could increase by 25 to 30% on January 1, 2009.
Both sides of this dialogue agree on the importance of developing renewable power as part of the
Truckee power supply portfolio. Both sides agree, I think, that coal is a necessary fuel for
generating electricity until renewable plants are available. We disagree on the appropriate length of
the contract. The District's idea is to have a fifty year contract that can be sold to another party if we
choose to, and if we have a willing buyer. The other view believes that we should have short-term
contracts, a series of five year contracts for example, so that it is easier to abandon coal contracts
A special public hearing will be held to discuss this issue at 7:00 PM on November 29, 2006 at the
Truckee Donner PUD Board Room at 11570 Donner Pass Road. You are encouraged to attend. If
you cannot attend the public hearing I would like to hear your opinion regarding these-alternate
ideas. Please send me an e-mail at peterholzmeister@tdpud.org or send me a letter to P.O. Box
309, Truckee, California 96160. Thank you for your input on this matter.
Very truly yours,
s
Peter L. Holzmeister
Memorandum
To: Board of Directors
From: Peter Holzmeister
Subject: E-mails involving Scott Terrell
Date: November 22, 2006
Please review the attached a-mails between Scott and
Tim Wagner. They were attached to another e-mail,
unintentionally I believe. I have had a conversation with
Scott about his involvement behind the scenes in a
matter that was being discussed in open by the Board
and staff. Scott was defensive.
The a-mails speak for themselves.
Page 1 of 4
Peter Holzmeister
From: Tim Wagner[tim.wagner@sierraclub.org]
Sent: Tuesday, November 21, 2006 7:59 AM
To: Scott Terrell
Cc: Neal Mock; Ronnie Colby, Truckee Biofuels; Brian Woody; Peggy Towns; pmayfield@onebox.com;
sfrisch@sbcouncil.org
Subject: RE: NEWS FLASH re IPP contract renewals: California
Thanks for your kind words Scott. There will be local press on this Wednesday so 1 will send it out then. And btw—
I would love to come to your neck of the woods. Never been and I hear it's simply stunning. Good luck on
achieving a victory and let me know if there's anything I can do to help.
tw
Tim Wagner
Director, Utah Smart Energy Campaign
Utah Chapter Sierra Club
2120 S. 1300 E., Suite 204
Salt Lake City, UT 84106
office: 801/467-9294
cell: 801/502-5450
fax: 801/467-9296
www.utah.sierraclub.org
From: Scott Terrell [mai Ito:scottterrell@tdpud.org]
Sent: Monday, November 20, 2006 5:16 PM
To: Tim Wagner
Cc: Neal Mock; Ronnie Colby,Truckee Biofuels; Brian Woody; Peggy Towns; pmayfield@onebox.com;
sfrisch@sbcouncil.org
Subject: RE: NEWS FLASH re IPP contract renewals: California
Hi Tim,
You obviously did your job along with others to kill several public utilities participation in this project!
If you come to Truckee you will have many new friends and our hospitality!
Congratulations and thanks for being a good humanitarian!
Thank the others for us as I think this decision will likely kill Truckee's participation in this project.
Someone from our group is going to send this to all the media in the area.
Folks, this may not be the end of Truckee's involvement, but I think we are really close!
We still need 500 people to show up to the Nov. 29 Board meeting to oppose this project!
Now it's time to start working on Building a Conservation Power Plant in Truckee!
Thanks Again, Scott
From: Tim Wagner [mailto:tim.wagner@sierraclub.org]
11/22/2006
Page 2 of 4
Sent: Monday, November 20, 2006 3:51 PM
To: Tim Wagner
Subject: FW: NEWS FLASH re IPP contract renewals: California
THIS IS HUGE!!!!!
TW
Tim Wagner
Director, Utah Smart Energy Campaign
Utah Chapter Sierra Club
2120 S. 1300 E., Suite 204
Salt Lake City, UT 84106
office: 801/467-9294
cell: 801/502-5450
fax: 801/467-9296
www.utah.sierraclu..b...,org
From: V. John White [mailto:vjw@ceert.org]
Sent: Monday, November 20, 2006 4:27 PM
To: David Czamanske; Kip.Lipper@SEN.CA.GOV; twagnersc@earthlink.net; donbremner@earthlink.net;
scarter@nrdc.org; tim.wagner@sierraclub.org; vpatton@environmentaldefense.org;
jnielsen@westernresources.org; jmartin@westernresources.org; wendy@betterworidgroup.com;
tim@coalitionforcleanair.org; rcavanagh@nrdc.org; bernadette@environmentcalifornia.org;
olsen@avenuecable.com; Rich Ferguson; Rhonda Mills; John Shahabian; Jose Carmona; Paul Vercruyssen;
metropulos@sierraclub-sac.org
Subject: RE: NEWS FLASH re IPP contract renewals: California
Thanks, David to you, Tim Wagner, and Sheryl Carter for all of you excellent work in turning this one around.
From: David Czamanske [mailto:dczamanske@hotmail.com]
Sent: Monday, November 20, 2006 3:20 PM
To: Kip.Lipper@SEN.CA.GOV; twagnersc@earthlink.net; donbremner@earthlink.net; scarter@nrdc.org; V. John
White; tim.wagner@sierraclub.org; vpatton@environmentaldefense.org; jnielsen@westernresources.org;
jmartin@westernresources.org; wendy@betterworldgroup.com; tim@coalitionforcleanair.org;
rcavanagh@nrdc.org; bernadette@environmentcalifornia.org; olsen@avenuecable.com; Rich Ferguson; Rhonda
Mills; John Shahabian; Jose Carmona; Paul Vercruyssen; metropulos@sierraclub-sac.org
Subject: NEWS FLASH re IPP contract renewals: California
3:00 pm, Monday, November 20, 2006
Representatives of the utilities departments of 6 California cities, which are purchasers of 75% of the
electric power generated by the coal-burning Intermountain Power Plant, located in Delta, Utah, stated
today that they have withdrawn efforts to renew their current coal power purchase agreements, which
expire in 2027, prior to January 1, 2007, in favor of commiting funds to study ways to reduce the plant's
greenhouse gas emissions in the near future.
11/22/2006
Page 3 of 4
The statements were made during this morning's meeting of the Intermountain Power Authority's
Coordinating Committee, which represents all utilities which purchase and distribute the plant's power.
Reps of each of the 5 cities which had been considering contract renewal - Anaheim, Riverside,
Burbank, Pasadena, and Glendale - stated upon inquiry from IPP General Manager Reed Searle the they
have withdrawn attempts to have their respective city councils renew their coal power purchase
agreements prior to January 1, 2007. (The Los Angeles DWP had already indicated it would not be
seeking renewal of its contract at this time; Fred Fletcher of Burbank Water and Power stated that his
department would be recommending, at that city council's Dec 5 meeting, that approval of the city's
contract, which had taken place on October 24,be rescinded.)
Acting on a motion introduced by Fred Fletcher of Burbank Water and Power, the Coordinating
Committee agreed to (a) allocate funds in next fiscal year's budget to retain consultants to study ways to
reduce greenhouse gas emissions from Intermountain Power Plant, and (b) etablish a subcommittee to
prepare a specific budgetary request by March 2007 for inclusion in the next budget.
During extensive discussion of the issue of greenhouse gas emissions earlier in the meeting, Eric Tharp
of Los Angeles DWP, operating agency of IPP, stated that he had prespared and presented to the
Cordinating Committee a list of ten possible actions, including carbon sequestration and
cogasification, that might be taken to reduce IPP's greenhouse gas emissions. This list was not available
nor discussed at the meeting.
Offer to renew contracts extended: Meanwhile, Mr. Searle stated that on October 26 IPA extended the
opportunity of all power purchasers to renew their power purchase contracts from the original deadline
of May 1, 2007, to January 1, 2023*. The contract renewals are contingent on 85% or more of the
current contractors renewing their contracts. If 85% or more renew, and some of the remainder do not,
IPA will have the right to put up for sale those entitlements not renewed. If less than 85% indicate an
intention to renew, owenership of the entire power plant and associated facilities will reveret to IPA. In
the meantime, LA DWP will continue to be the plant's operating agent.
* Ownership interest in IPP among California cities is as follows: Los Angeles,44.6%; Anaheim,
13.2%, Riverside, 7.6% Burbank 4.4%, Pasadena, 3.4%, Glendale, 1.7%.
From: "Lipper,Kip"<Kip.Lipper@a5EN.CA.GOV>
To: 'David Czamanske"
Subject: RE,ALERT re IPP Board meetings in Burbank, 9 am&1 pm, Monday,November 20
Date: Mon,20 Nov 2006 09.•48:15-0800
i
Senate staff just concluded a meeting with the non-LA SCPPA members this morning. They want to talk about
converting the plant to IGCC/sequestration as a condition of renewal.
More later.
------------------------------------------
Kip Lipper
Office of the Senate Pro Tern
State Capitol Room 420
Sacramento, CA 95814
916.445.0924 (0)
E 916.445.0596 (F)
Kip._Lipper_(sen.ca.g.ov
-----Original Message-----
From: David Czamanske [mailto:dczamanske@hotmail.com]
11/22/2006
Page 4 of 4
Sent: Saturday, November 18, 2006 5:00 PM
To: twagnersc@earthlink.net; donbremner@earthlink.net; scarter@nrdc.org; vjw@ceert.org;
tim.wagner@sierraclub.org; Lipper, Kip; vpatton@environmentaldefense.org;
jnielsen@westernresources.org; jmartin@westernresources.org; wendy@betterworidgroup.com;
tim@coalitionforcleanair.org; rcavanagh@nrdc.org; bernadette@environmentcalifornia.org;
olsen@avenuecable.com; rich@ceert.org; rhonda@ceert.org; js@ceert.org; jose@ceert.org;
paul@ceert.org; metropulos@sierraclub-sac.org
Subject: ALERT re IPP Board meetings in Burbank, 9 am & 1 pm, Monday, November 20
Notice: Quarterly meetings of the Coordinating Council and of the Board of Directors of
the Intermountain Power Authority will take place on Monday,November 20, at the
Burbank Airport Hilton
The Coordinating Council is composed of reps of all public & private utilities which have
entitlements to power produced at the Power Plant.
The Board of Directors is composed of reps from seven Utah cities who comprise the current
governing board of Intermountain Power Authority.
Meeting time of the Coordinating Council: 9 am
Meeting time of the Board of Directors: 1 pm
It is not clear if the Coordinating Council mtg is open to the public; however since IPA is a
public entity authorized under a law enacted by the Utah Legislature, the Board meeting itself
must be open to the public.
Agendas of the Council and Board are posted at www.ipautah.com. Note Coordinating
Council agenda item 9 "Discussion of Renewal of Power Sales Contract Amendments
approved by IPA Board of Directors"
This website contains much information about IPA, including an Overview, Organizational
Purpose, Recent Developments regarding Units 1 & 2, Recent Developments regarding
Proposed Unit 3, and a Summary of Key Contract Provisions. (You may want to consider
printing out these webpages for ready reference.)
David Czamanske
PS. I plan to attend these meetings to get a first-hand look at these folks in action, and to offer
comments on the proposed contract renewals.
11/22/2006
MEMORANDUM
TO: Board of Directors, Truckee-Donner Public Utility District
DATE: November 27, 2006
FROM: Steven C. Gross, General Counsel
RE: Power Sales Contract with UAMPS - Risk Analysis
During the November 15, 2006 Board meeting, I was asked to prepare a risk analysis of the
Intermountain Unit 3 Project Power Sales Contract (PSC) with UAMPS. I have compiled a list of
potential risks associated with the PSC and some assessment of them. They are listed in no
particular order. This memorandum is not, nor is it intended to provide, an exhaustive discussion of
the potential risks associated with the PSC. I expect that Steve Hollabaugh and UAMPS will have
additional insight and input on some of these risks.
In addition to the issues discussed in this memorandum, I have attached a memorandum
dated November 1, 2006 from UAMPS' General Manager, Doug Hunter. The second half of this
UAMPS' memorandum assesses some of the "perceived risks inherent in the Unit 3 project." This
assessment may be of interest to the Board.
Potential Risks
I. Delayed Construction
A risk associated with the PSC is that Intermountain Unit 3 Project is not yet
constructed. Section 4 of the PSC recognizes that various permits and approvals necessary for
construction and operation of the Project have not been obtained and that certain permits and
approvals may be subject to continuing regulatory, administrative and judicial proceedings. The
District has been informed by UAMPS that the unsecured permits and approvals relate to
transmission rights and that construction of the Project should not be delayed as a result of the
issues associated with transmission. UAMPS is assisting some of the Participants with
transmission, but ultimately under the PSC each Participant is responsible for securing its own
transmission. This obligation is set forth in Section 10(a) of the PSC.
As with any construction Project, the time for completion could be delayed. One
1
could argue that the bigger the project, the greater the possible delays. This is quite a large
project and actual construction could be delayed. The result could be that the delivery of power
would be delayed as well. Depending on the timing and duration of a delay, if there is a delay,
there may be plenty of time to mitigate this risk and purchase other power during the period of a
delay because deliveries of energy are not scheduled to begin until 2012.
II. Construction Costs Exceed Estimated Costs and/or Project Budget
The current estimated price for the power, approximately $35 MWh is based on the
current estimated cost of construction of the Project. Should the actual costs of construction
exceed the estimate or budged cost, due to delays, increased cost of materials, equipment, etc.,
then the cost of the power to the District would increase. We understand that UAMPS and its
technical staff and consultants have used great care in estimating the construction costs, as this
is of great concern to the owners of Unit 3 and all of the Participants. Nonetheless, there are no
guarantees on the cost of construction.
III. Construction Financing Costs Exceed Estimated Costs and/or Project Bud-get (Interest
Rate Risk
As described to the District and other UAMPS members, UAMPS intends to finance
the Project with Bond Anticipation Notes through construction (the short-term or construction
financing) and then convert the long-term debt to Bonds. The Bonds will not be sold until
construction is complete, probably somewhere around 2012. If interest rates rise during the next
five years, the cost of the borrowing/debt service is more expensive. In as much as the amount
of the debt service is a component of the cost of the power to the District and the other
Participants, if the interest rates on the Bonds end up being greater than anticipated at this time,
the cost of the PSC to the District will increase.
IV. Cost of Coal Increases or Exceeds the Cost of fuel, i.e. —Natural Gas
One of the factors that determines the cost of the power to the District under the PSC
is the cost of coal. The cost of coal can be affected by the cost of labor, the cost of mining
technology or additional mining costs caused by increased or more expensive regulatory
2
controls. Also, if the coal quality is less than expected, the plant may have to burn more coal to
produce the same amount of power. If the cost of coal increases beyond what is expected, the
cost of the power to the District under the PSC would increase.
In addition to the risk of greater energy costs, it is possible that over time (i.e. — the
fifty year term of the PSC) the cost of coal, and power generated from coal, will be greater the
costs of power produced from other fuel sources, such as natural gas, wind, water or nuclear
energy. Historically this has not been the case; however only time will tell if this remains true.
In the event that alternative fuel becomes less expensive than coal, then it is possible that the
cost of power under the PSC could be greater than the cost of other power. In other words, over
the course of the fifty year term of the PSC the cost of energy could be expensive vis-a-vis other
energy. However, in order to accurately make this assessment, it would be necessary to look not
only at the cost of fuel, but also the relative cost of the power plant to utilize that fuel at the time
that fuel is less expensive than coal, transmission availability, etc.
V. Disruptions in the Fuel (Coal) Supply
In the event that there is a disruption in the supply of fuel/coal to the plant, due to a
problem with the mine, labor unrest or other event, then the plant could not operate and the
delivery of power would be disrupted. The District would have to purchase power elsewhere
and potentially at a greater cost.
VI. Damage to, or Destruction of, the Power Plant
It is possible that the Power Plant could be damaged or destroyed and that the
production and delivery of power to the District would be interrupted, yet because the PSC is a
"take or pay" contract, the District would still be obligated to make its payments to UAMPS. In
this event, the District would have to purchase power from an alternate source or supplier and
still pay for the power under the PSC. In effect, the District could have to pay for power twice.
I have discussed this risk with UAMPS' bond counsel Jim Burr. He informed me
that pursuant to the Ownership Agreement between UAMPS and the other Unit 3 owners, the
Unit 3 Owners will maintain insurance on Unit 3 that includes coverage of losses due to
business interruption. This business interruption insurance will include the debt service
3
obligation of DAMPS. If, for example, a catastrophic event damages the Power Plant and
causes the curtailment of power deliveries to the District and the other Participants, insurance
will pay UAMPS an amount that would include the amount that UAMPS would be obligated to
pay to its bond holders, as well as other operations and maintenance expenses. Because
UAMPS would be made whole from insurance proceeds, it would be able to relieve the District
and the other Participants from their payment obligations under their various PSC's. I
understand that this is what is contemplated; however, it is not spelled out in the PSC.
The insurance coverage described above would provide business interruption
coverage for a maximum period of twelve months. Therefore, if the Power plant could not be
repaired or rebuilt within that time period, the District and other participants would be at risk.
Mr. Burr explained that the District and other Participants could decide to increase that type of
insurance and be covered for a longer period of time if they so desired. I do not know how
much such coverage would cost. It may also be possible for the District to obtain its own
coverage to mitigate this risk. However, I do not know if this type of insurance is available for
the District to purchase in this situation or how much it would cost.
VII. Damage to, or Destruction of, the Transmission System
It is possible that the transmission system that brings the power from the Plant to the
District would be damaged or destroyed. The result would be that deliveries of power to the
District would be interrupted. While this is a real risk, in general it does not appear to be any
greater if the District enters into the PSC rather than purchasing power from another source or
supplier. In other words, no matter where the District's power comes from, there is a risk
associated with damage to or destruction of the transmission system over which power is
delivered to the District.
Due to the nature of the PSC as a "take or pay" contract, if the District could not
transmit the power from the Power Plant to the District due to a disruption in transmission
service, then the District would still be obligated to pay for the power and fulfill its obligations
under the PSC. However, under the PSC the District has the right to sell its Entitlement Share
(the power it is obligated to pay for) to another Participant or to a third party. Thus, the District
has the ability to significantly mitigate this risk.
4
This potential risk is further mitigated by the fact that there are two transmission
paths from the Power Plant. The District will receive its power from the northern most
transmission line. If there is a disruption in this line or in the line from the point of delivery at
Sierra Pacific Power Company's transmission system, it does not mean that there would be a
disruption in the transmission line that travels in a southerly direction from the power plant.
Thus, in the event of a disruption in the transmission system that serves the District would likely
be able to sell its Entitlement Share to another Participant or thirds party that would utilize the
other transmission system.
VIII. Change in Law
A. Future Requirements for Capital Improvements for New or Improved Pollution
Control Technology
Future legislation or regulations or new interpretations of existing laws and
regulations could lead to the need to retrofit the Power Plant with expensive capital
improvements or improved pollution control technology. The net result to the District
and the other Participants would be increased costs of power under the PSC. While I
understand that Unit 3 is designed to incorporate the state of the art pollution control
technology, it is still possible that new or improved systems will be developed in the
future and may address the reduction or control of other pollutants, such as mercury.
Currently we are seeing California becoming more aggressive in its attempt
to regulate greenhouse gases. SB 1368 will, among other things, limit the ability of
investor and publicly owned electric utilities from entering into financial commitments
of greater than five years for base load generation that does not meet certain greenhouse
gas emission standards. Similarly, AB 32 is another law which is designed to address
global warming by reducing greenhouse gas emissions. This law will require the
California Environmental Protection Agency to work with other state agencies to: (1)
promulgate and implement greenhouse gas emissions cap for the electric power,
industrial and commercial sectors through regulations in an economically efficient
manner; (2) institute a schedule for greenhouse gas reductions; (3) Develop and
5
enforcement mechanism for reducing greenhouse gases; and (4) establish a program to
track and report greenhouse gas emissions. There are certainly more laws and/or
regulations to follow; however it is too early to determine if or how they may affect the
District or the PSC.
B. Tax on Greenhouse Gas Production/Emissions
It is possible that the federal government or individual states could make
power produced by coal more expensive in the future by taxing greenhouse gases. I am
not aware of any pending legislation that would tax greenhouse gases; however,
anything is possible in the future.
IX. Default by UAMPS
There is a risk that UAMPS could default in its obligations under PSC. In this event,
the District's sole remedy is limited to seeking and obtaining a court order to require that
UAMPS perform its obligations. The District would not be entitled to withhold or offset any
amount owed to UAMPS. (Section 25.) However, prior to going to court, the District is
required to submit to mediation by the project Management Committee.
X. Default by Another Participant in Unit 3
Currently it is anticipated that 28 UAMPS' members will be "Participants," that is to
say that they will enter into power purchase contracts with UAMPS, very similar to the PSC.
UAMPS will be dependent upon each Participant to meet its obligations in order for UAMPS to
meet its obligations to the other Unit 3 owners and to its bondholders. In the event that any of
the Participants, including the District, defaults in its obligations to UAMPS, the other
Participants are required to "step-up"their obligations.
Section 23 of PSC addresses this obligation. It provides that in the event of a default
by one of the Participants, UAMPS will first reallocate the defaulting Participant's Entitlement
Share among the nondefaulting Participants, pro rata on the basis of their then-current
Entitlement Share. (Section I0(b)(1).) Within sixty days of that reallocation, the nondefaulting
Participants are required to notify UAMPS that they either want to retain the portion allocated to
6
them, and any additional amount, if desired, or that they want to less than or none of the portion
allocated to them. (Section 10(b)(2).) Within thirty days after hearing back from all of the
nondefaulting Participants, UAMPS will then determine whether all of the defaulting
Participant's Entitlement Share will be voluntarily pick-up by the nondefaulting Participants. If
it has not been, then UAMPS will reallocate the remainder among the non-defaulting
Participants who did not elect to retain the initial allocation. However, in no event shall a
nondefaulting Participant's Entitlement Share be increased by more than 25% over its initial
Entitlement Share. (Section 10(b)(3).)
Therefore, there is a risk that the District could be required to take 25%more than its
Entitlement Share. This could happen repeatedly if more than one of the other Participants
defaults.
XI. Long-Term (50 year) Contract
There are potential risks associated with entering into a contract with such a long-
term as fifty years. Many of those risks are addressed above. These include potential
disruptions in the fuel supply, damage or destruction to the transmission system or to the Power
Plant, the increase in the price of coal relative to other types of fuel, changes in the law and
default by UAMPS or by other Participants. It is important to keep in mind that while the risks
continue to exist, the likely financial rewards of such a contract increase significantly after the
first thirty years. After the Bonds/long-term financing are paid off, the cost of the power to the
District and other Participants under the PSC will decrease accordingly.
One significant mitigating factor in considering the fifty year term of the PSC is that
the District has the ability to assign or sell all or part of its Entitlement Share or its interests
under the PSC. Section 18 of the PSC sets forth the procedural requirements that the District,
and any other Participant, would have to follow in order to do this. The important part to note is
that provided there is a buyer that satisfies the conditions in the PSC, the District can in effect
stop purchasing power from the Project.
7
i
UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS
2825 East Cottonwood Parkway
Suite 200
Salt Lake City, UT 84121-7055
Phone: 801-566-3938
Toll Free: 800-872-5961
Fax: 801-561-2687
MEMORANDUM
TO: Unit 3 Participants
FROM: Doug Hunter
DATE: November 1, 2006
SUBJECT: Unit 3 status as of October 17, 2006
The Unit 3 Project Management Committee("PMC") approved issuing a Request for Proposal
("RFP")for an Underwriter at its meeting on October 17th. This agenda item was first brought to
the PMC on September 18th,but was tabled until October 2"d in order for Intermountain Power
Agency("IPA") to make a proposal to finance in lieu of UAMPS financing. After IPA made its
presentation (if you missed it you can see it on UAMPS'web page),the PMC instructed UAMPS
staff to provide an analysis of the IPA proposal during its regularly scheduled meeting on October
17th. The staff presented its analysis at that meeting (available on UAMPS'web site). The PMC
subsequently resolved to issue the RFP. They also expressed their appreciation to IPA for taking
the time and expense to put together their proposal.
The PMC also authorized UAMPS to file for the necessary transmission rights needed on the
Northern Transmission System ("NTS"). This filing has been completed and provides the Unit 3
Project with reservation of surplus capacity associated with the NTS necessary for all Participants
to access either PacifiCorp's transmission system at the Mona substation or Sierra Pacifiic's
transmission system at the Gondor substation. This in no way limits other arrangements individual
Participants may make with IPA or others to gain access on the NTS.
Finally, the PMC approved distribution of the Power Sales Contract("PSC")to the Participants for
review and execution.
There were a number of changes from the draft reviewed in my memo of September 26,2006
which include the following:
November 1, 2006
Page 2
Section 3-the revisions to this section include: (1)coordinating the effective date and Entitlement
Share provisions of the Power Sales Contract with the IPP Unit 3 Project Agreement; (2)the
addition of a new"Orphan Share"provision to cover Power Sales Contracts that are not executed
by prospective Participants; (3) Power Sales Contract becomes effective upon Participants
execution and delivery of at least 85%Entitlement Share; (4) removal of the provision that
permitted a reduction in a Participant's initial Entitlement Share;and (5)financing provisions moved
to a new Section 5.
Section 4-revised to reflect current status of Unit 3 permits and approvals.
Section 5-the provisions for the construction financing of the Project are set out in a new Section
5(all subsequent section numbers increase by 1). Construction financing may consist of Bond
Anticipation Notes or Bonds.
Section 6-revised to permit partial Capital Cost Payments out of retained earnings.
Section 7-various refinements to PMC responsibilities.
Section 10-metering and power factor provisions removed.
Section 18-scope of rate covenant narrowed (paragraph(b)(1)). Technical revisions to provisions
respecting Participant sales and assignments of utility systems and Entitlement Shares(paragraph
(b)(3))•
Sections 22 and 23-remedies upon default revised to address Participants that have made a
Capital Cost Payment.
Section 31 —upon written request of the Participant stating that transmission is not available, the
Power Sales Contract may be terminated by the determination of the PMC.
A few of the Participants have asked me to provide an assessment of the perceived risks inherent
in the Unit 3 Project.
What 1s risk? Risk is the potential loss of money or opportunity given a course of action. A
standard example is choosing a course of action that precludes changing that course without some
monetary loss. More specifically, if you choose to participate in Unit 3,what other options are you
not taking and what assurance do you have that the projected costs of participation will turn into
actual costs of participation?
The basis of UAMPS' approach to project development is to acquire as much information as
possible about a given proposal before committing to it. To achieve this, UAMPS normally
organizes a Study Project for conceptualization and analysis of the project in which potential risks
are identified and quantified.
November 1,2006
Page 3
The Unit 3 process followed this path in July 2001. After reviewing several coal generation projects
UAMPS, in coordination with the Los Angeles Department of Water and Power("LADWP")and
Intermountain Power Agency("IPA"), established a conceptual design for a third unit at the
Intermountain Power Project based upon replicating the size and performance of the existing Units
1 and 2. This effort was memorialized in an Executive Report issued in 2002 and updated in
December 2003. The reports established the conceptual design and provided a basis for our
retained engineering firm, Sargent and Lundy("S&L"), to solicit indicative bids from the market for
Unit 3. Additionally S&L provided estimated owner's costs and the cost of labor. The Study Group
retained the services of Goldman Sachs to develop the cost of capital and R.W. Beck&Associates
to develop the cost of operations. LADWP and UAMPS developed estimates for the cost of fuel.
With the compellation of this work product,the Study Group had a good understanding for the all-in
cost of Unit 3. Although this did not alter any form of potential risk, it did allow the Study Group to
identify and measure the value of each risk component.
Subsequent to these efforts,the Study Group morphed into the Unit 3 Development Committee
(DC),which is the collection of potential Unit 3 owners(UAMPS 50%, PacifiCorp Energy 38%,
SNWA 11%and the City of Glendale, California 1%). The DC has since refined the estimated
costs of Unit 3 to obtain a better understanding for the cost of construction,the cost of fuel,the cost
of operations, the cost of administrative functions and the cost of financing.
The Development Committee is now in the process of drafting the required Project Agreements
(Ownership Agreement, Joint Operating Agreement,Common Facilities Agreement and the
Construction Lease and Use Agreement),which will further reduce the potential risk.
The one item that is still not fully known is transmission. As previously stated UAMPS has filed a
FERC transmission request on LADWP, as the operator for Units 1 and 2, and the operator of the
Northern and Southern Transmission Systems (NTS) and (STS). This filing will provide the Unit 3
Project with some comfort but still requires additional work. Unfortunately the transmission issue
cannot be resolved before December 31, 2006 when the PSC is requested to be executed. Again,
as stated above the PSC, Section 31 is being revised to allow termination of the PSC on a vote of
the PMC if transmission is not available.
It should also be noted that UAMPS has not entertained any fuel contracts for its share of Unit 3
but is in the process of developing a plan for PMC review. Once the PMC adopts a plan and the
PSC becomes effective, UAMPS may begin acquiring coal resources. The Unit 3 studies have
reviewed all of coal within reach of the Project. The full rail access to the Western coal markets is
one of the reasons that this site was chosen over other sites.
The bus bar cost of Unit 3 is still estimated to be in the$351MWh range. UAMPS has retained
Burns and Roe to evaluate the legitimacy of Unit 3 construction and operating costs. Zions Public
Finance, UAMPS' Financial Agent,will provide the pro forma runs on these costs.
It is fair to state that all major Unit 3 risks have been discovered and plans are in place to manage
these risks in a reasonable and economic manner. The two remaining risk areas that have not
been analyzed are Participant risks;opportunity loss and entitlement.
November 1,2006
Page 4
Given the need for a supply side resource in 2012 the options are limited. I am aware of number of
potential participants that are still evaluating potential options to Unit 3, If Unit 3 is not necessarily
needed in 2012, you may be foregoing the option to wait for a project that would better fit your
needs.
In essence,the Entitlement Share that each Participant chooses brings with it risk. Unit 3 is
expected to produce economic energy for at least 30 years, and depending on maintenance
investments will likely run for 50 years.
Your level of subscription should be based on your confidence as to growth within your system and
the ability of your retail rates to take an increase due to surplus Unit 3. If your load fails to grow at
the rate predicted, retail rates would have to be increased, which will have a tendency to reduce
load further causing a dangerous cyclical increase in rates. This could ultimately end in your
default under provisions of the PSC.
Risk is always with us. I know of no way short of inaction that it can be eliminated but it can be
managed. UAMPS spends a considerable amount of time analyzing any project before embarking
on a course of action, which should provide a high probability that our projects will be successful.
But still, it is very important that each of you understand the risk that you are taking when you
execute the PSC.