HomeMy WebLinkAboutAgenda Report - October 30, 2001 B-03 SMa
® CITY OF LODI COUNCIL COMMUNICATION
AGENDA TITLE: Adopt resolution authorizing the City Manager to execute Exhibit B of the Master Power
Purchase and Sale Agreement between the City of Lodi and the State of California
Department of Water Resources (EUD)
MEETING DATE: October 30, 2001
PREPARED BY: Electric Utility Director
RECOMMENDED ACTION: That the City Council adopt a resolution authorizing the City Manager to
execute Exhibit B of the Master Power Purchase and Sale Agreement
between the City of Lodi and the State of California Department of Water
Resources.
BACKGROUND INFORMATION: For nearly five months, City staff and the State of California Department of
Water Resources (DWR) have been negotiating the terms and conditions of
the development of a peak power generating plant to be located with the City
limits of Lodi. DWR purchases power for two of the State's largest investor-owned utilities as a result of the
"meltdown" of California's power markets at the beginning of the year.
DWR has determined that the State would benefit from additional peak generating capacity and City staff has
determined that an appropriately designed and located peaking facility would be advantageous to the reliability and
energy security of City of Lodi electric customers.
City staff is now seeking Council approval to proceed with the development of a 43-45Mw peaking power generating
facility with the Lodi City limits. The basic parameters of the transaction is as follows:
• Lodi would develop the new peaking plant.
• Lodi would finance the plant through the issuance of bonds.
• Lodi would own and operate the plant.
• Lodi will retain the right to recall up to 22Mw of capacity commencing July 1, 2005.
• DWR would pay Lodi a fixed and variable monthly amount for the fifteen (15) year term of the agreement.
• DWR would supply the fuel or pay Lodi to supply the fuel for the plants output.
• After the fifteen (15) year term of the agreement, the plant output would belong to Lodi without further
obligation to DWR.
City staff respectfully requests City Council authorization for the City Manager to execute Exhibit B — Master Power
Purchase and Sale Agreement Confirmation Letter (2001 B Transaction — Peaking Capacity) between the City of Lodi
and DWR. Exhibit B is in substantially final form. It should be noted that Council's authorization of Exhibit B is
contingent upon an appropriate site being located within the City limits of Lodi as contemplated under all appropriate
provisions of the California Environmental Quality Act. Additionally, Council's authorization is contingent upon the
City's ability to finance the project.
A complete financial pro forma statement related to the plant will be prepared in conjunction with the financing of the
project. The financial analysis will be presented to the Council in conjunction with its consideration of City staffs
financing request at a future date.
APPROVED:
H. ixon Fly n - City Ma ger
CITY OF LODI COUNCIL COMMUNICATION
FUNDING: Through existing Bulk Power Purchases A //�
ANV/1st
Alan N. Vallow
Electric Utility Director
City Attorney
APPROVED:
H. Dix Flynn - City Manager
REVISED DRAFT CONFIDENTIAL
EXHIBIT B
MASTER POWER PURCHASE AND SALE AGREEMENT
CONFIRMATION LETTER
(2001B Transaction --Peaking Capacity)
This confirmation letter shall confirm the Transaction agreed to on , 2001
between the City of Lodi ("Party A") and State of California Department of Water Resources
with respect to its responsibilities pursuant to California Water Code Section 80000 et seq.
regarding the Department of Water Resources Electric Power Fund separate and apart from its
powers and responsibilities with respect to the State Water Resources Development System
("Party B") regarding the sale/purchase of the Product under the terms and conditions as follows:
Seller: City of Lodi, Electric Utility Department
Buyer: State of California Department of Water Resources
Product:
[] Into , Seller's Daily Choice
[] Firm (LD)
[] Firm (No Force Majeure)
[] System Firm
(Specify System: )
® Unit Firm — See Special Condition 2 below.
[] Other:
Q Transmission Contingency (If not marked, no transmission contingency)
[) FT -Contract Path Contingency [] Seller [] Buyer
[) FT -Delivery Point Contingency [] Seller [] Buyer
[] Transmission Contingent [] Seller [] Buyer
[] Other transmission contingency
(Specify: )
CDWR — Lodi PPA Page 1 of 18 11:24 AM;10/25/01
REVISED DRAFT CONFIDENTIAL
Quantity: The contract Quantity of the Unit Firm Product (if any) shall be determined
for each month throughout the Delivery Period (as defined below) as
follows:
1. From the Commercial Operations Date ("COD") through May 31,
2005, as the Net Demonstrated Capacity ("NDC") of the Facility, as
determined pursuant to Special Condition 4, as dispatched by Buyer
pursuant to Special Condition 8; and
2. From June 1, 2005 until the end of the Delivery Period, as the
most current NDC of the Facility, as determined pursuant to Special
Condition 4, less any Call -Back Capacity, as dispatched by Buyer
pursuant to Special Condition 8;
Where:
The expected value of the NDC of the Facility is equal to 43 MW
(the "Contract Capacity');
The COD is determined pursuant to Special Condition 3, and is
expected to be , 2002; and
Call -Back Capacity is determined pursuant to Special Condition 5.
Delivery Point: The Delivery Point for the Unit Firm Product shall be the Industrial
Substation, 60 kV bus, located in Lodi, California, which is part of the
CAISO-controlled transmission grid in the NP -15 zone.
Contract Price: The Contract Price for the Unit Firm Product (if any), in total dollars, shall
be determined each month as the sum of the following charges:
Capacity Charge
For each month, the product of 1) $7.65/kW-month (the "Base Capacity Price", as may
be adjusted pursuant to Special Condition 6), and 2) the Quantity in effect for the month,
expressed in kW; provided that the above product shall be subject to further adjustment to
account for Actual Availability and Actual Starting Reliability pursuant to Special
Condition 7.
Fuel Charge
For each month, the Fuel Charge shall be determined as follows (a negative Fuel Charge
would reflect a payment due from Seller to Buyer resulting from overuse of Buyer -
supplied fuel due to an excessive heat rate):
Fuel Charge = Gross Fuel Costs x Heat Rate Factor
Gross Fuel Costs = Monthly Fuel Quantity x Monthly Fuel Price
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Monthly Fuel Quantity = Monthly metered usage of gas (MMBtu) for the Facility to
generate power scheduled or requested by Buyer in accordance with the "Special
Conditions" below, plus equivalent gas at the Guaranteed Heat Rate for any ISO
imbalance energy. Such monthly metered usage of gas shall be determined based on the
ratio of 1) the actual output of the Facility to supply Buyer's scheduled or requested
energy (but not any energy generated in excess of Buyer's hourly schedules or real-time
schedule changes) to 2) the actual total output of the Facility. Seller shall be solely
responsible to acquire and pay for any and all gas used to generate energy other than
Buyer's scheduled or requested energy.
Monthly Fuel Price = Gas cost ($/MMBtu) as determined pursuant to Special Condition
12.
Heat Rate Factor:
If Seller supplies gas:
Lesser of. 1.0, or (Guaranteed Heat Rate/Monthly Effective Heat Rate)
If Buyer supplies gas:
[Lesser of. 1.0, or (Guaranteed Heat Rate/Monthly Effective Heat Rate+I
Guaranteed Heat Rate = 10,000 Btu/kWh (with gas compression), or
9,500 Btu/kWh (without gas compression)
Monthly Effective Heat Rate = (Monthly Fuel Quantity/Monthly Scheduled Energy)
Monthly Scheduled Energy = Total energy during a month scheduled or requested by
Buyer in accordance with "Special Conditions" for delivery by Seller from Unit(s) on
Buyer's account
Variable O&M Charge
A monthly charge for Variable O&M shall be determined as the product of 1) the
applicable Variable O&M Rate shown in Attachment 1 to this Exhibit and 2) the MWh of
generation from the Facility delivered to Buyer during the month.
Fixed O&M Charge
A monthly charge for Fixed O&M shall be determined each month as the product of 1)
the applicable Fixed O&M Rate shown in Attachment 1 to this Exhibit and 2) the
Quantity in effect for the month, expressed in kW.
Delivery Period: June 1, 2002 through May 31, 2017.
Special Conditions: (1) See Cover Sheet to Master Agreement.
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(2) Seller shall supply the Quantity to be delivered under this
Transaction from the 43 MW LM600 combustion turbine power plant that
Seller would be developing at a site within the city limits of the City of
Lodi, California (the "Facility'), in accordance with the defmition of the
Unit Firm Product in Schedule P. The Facility shall include static
catalytic reduction that will limit NOx emissions to 5 PPM. All emissions
reduction credits required to operate the Facility at Contract Capacity
during all Peak Period hours of the Delivery Period shall be provided by
Seller. Seller shall obtain additional credits as needed for its own use of
the Facility during non -Peak Period hours.
(3) Seller's obligations hereunder with respect to the energy to be supplied
from the Facility are subject to and contingent on the Facility having
achieved "commercial operation" before Seller is obligated to supply such
energy. Buyer's obligations hereunder with respect to capacity and energy
to be received from the Facility are subject to and conditioned on the
Facility having achieved "commercial operation" before Buyer is
obligated to pay the Contract Price or any portion thereof. The Facility
shall be considered to have achieved said "commercial operations" on the
Commercial Operations Date ("COD"), which is the date upon which
Seller first certifies in writing to the Buyer that all of the following
conditions precedent to the Commercial Operations Date have been
satisfied:
(i) Seller has completed a Net Demonstrated Capacity Test for Peaking
Facilities pursuant to Special Condition 4 that achieves an NDC of no
less than 95% of Contract Capacity; and
(ii) Seller has received all necessary approvals, licenses, permits and
emission reduction credits (if applicable) for operating the Unit at its
NDC for all Peak Period hours in each calendar year in the Delivery
Period (prorated on a daily basis in the event of a partial calendar year
during the Delivery Period) for the term of the Agreement, except for
final permits which Seller reasonably expects to obtain in the normal
course and which are not required for Seller to fulfill its obligations
pursuant to the Agreement.
(iii) Seller has obtained Buyer's written approval for the site location of
the Facility.
(4) The contract Quantity for the Facility for purposes of determining the
capacity payment shall be equal to the Net Demonstrated Capacity
("NDC") of the Facility, which will be established and updated from time
to time by testing and adjustment pursuant to the procedures and
requirements of the "Net Demonstrated Capacity Test for Peaking
Facilities" attached hereto as Procedure 1.
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REVISED DRAFT
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(5) Call -Back Capacity is the amount, in MW, by which Seller may
decrease the Quantity of the Product once in any 12 -month period
beginning June 1 (each a "Contract Year"), beginning with the Contract
Year starting June 1, 2005; provided that the Call -Back Capacity shall: 1)
be in one MW increments, 2) not exceed 22 MW, 3) not be reduced from
one Contract Year to a subsequent Contract Year, and 4) not decrease the
contract Quantity below 21 MW. Seller shall provide written notice to
Buyer of the Call -Back Capacity amount for each affected Contract Year
by the preceeding December 31.
(6) The Base Capacity Price shall be subject to a one-time adjustment
to account for any difference between expected and actual costs for the
following items related to the Facility: 1) gas pipeline and interconnection,
2) electrical transmission system interconnection, and 3) emission offset
credits (in total, the "Nonfirm Cost Components"). The adjustment shall
be equal to an increase or decrease of $0.05/kW-month for every $400,000
by which the actual cost of the Nonfirm Cost Components is greater or
lesser, respectively, than $6,360,000; provided, however, that in no event
may an adjustment increase the Base Capacity Price more than $0.30/kW-
month.
(7) After the end of each month, the capacity payment paid or payable
that month pursuant to the other terms of this Transaction (including
Special Condition 6), shall be adjusted by the Actual Availability Factor
(AAF) and the Actual Starting Reliability Factor (ASRF) to arrive at the
Adjusted Capacity Charge (ACC).
Where:
ACC = [(Capacity payment paid or payable) x AAF x ASRF];
AAF = [1 + Lesser of [0 or (2 x (AA -TA))]];
ASRF = [l + Lesser of [0 or (PSRF x (ASR -GSR))]];
AA = Actual Availability = (Summation of Hourly Availability Factors
for Availability Hours) / (# of Availability Hours in month);
TA = Target Availability = .95 for the Summer Season or .92 for the
Winter Season (the Summer Season is the Peak Period of the months June
through October; the Winter Season is the Peak Period of the months
November through May);
Availability Hours are all Peak Period hours in a month, other than hours
during Scheduled Maintenance or excused by Force Majeure;
Hourly Availability Factor is determined for each Availability Hour as
follows:
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i) For hours in which Buyer has scheduled energy, the quotient of 1)
energy actually delivered by Seller to Buyer from the Facility plus,
if Buyer supplies Fuel, any scheduled energy that was
undeliverable solely due to the non-delivery of gas, divided by 2)
total scheduled energy;
ii) For hours in which Buyer has not scheduled energy, the quotient of
1) contract Quantity that was actually schedulable for delivery,
divided by 2) contract Quantity;
PSRF = Period Starting Reliability Factor = 3 for Summer Season months
and 1 for Winter Season months;
GSR = Guaranteed Starting Reliability =.95;
ASR = Actual Starting Reliability = Quotient of 1) successful starts made
at the allowable request of Buyer during the current and prior 11 months,
divided by 2) number of allowable start requests made by Buyer during
the current and prior 11 months; provided that the ASR shall be deemed
equal to the GSR until the first delivery month within which the day
before the first anniversary of the COD occurs (if by such date Buyer has
made at least 50 start requests, and if such number of start requests have
not occurred by such date, the first delivery month within which the 50'`
request is made); and further provided that if the above 12 -month period
does not include at least 50 start-up requests, then the most recent 50 start-
up requests shall be used to calculate ASR.
(8) Seller shall only be required to deliver the energy described in this
Transaction if Buyer schedules energy from the Facility as provided
herein. Subject to the terms and conditions set forth herein, Buyer may
schedule such energy only for hours within the Peak Period (as hereinafter
defined) and only up to the then applicable contract Quantity; provided,
however, that the quantity of energy which is scheduled must: 1) comply
with the ramp times, minimum run times, shut down times and other
operating specifications of the manufacturer, 2) reflect ambient conditions,
and 3) account for unavailability of the Facility due to Scheduled
Maintenance, Forced Outage, or Force Majeure. Capacity not scheduled
by Buyer shall be available for unrestricted use by Seller, as is capacity
during other than Peak Period hours. As used herein, 'Peak Period"
means the hours from the hour ending at 0700 through to the hour ending
at 2200, Pacific Time, Monday through Saturday, during the Delivery
Period. Scheduling shall conform to ISO and WSCC standards.
Buyer shall schedule energy with Seller on a day -ahead basis by providing
notice to Seller at least 60 minutes prior to the earlier of: 1) the day ahead
scheduling deadline of the ISO or its successor, or 2) the daily gas supply
nomination deadline; provided, however, that Buyer may make real-time
schedule changes to the extent the Facility output has not already been
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CONFIDENTIAL
committed by Seller for sale to a third parry or made unavailable due to
Scheduled Maintenance. Buyer shall be responsible for any Fuel cost
impacts or Fuel imbalance charges resulting from its real-time schedule
changes, provided that Seller specified to Buyer at the time of Buyer's
requested real-time schedule change the amount of such impacts or
charges. To the extent any such costs are not identified by Seller and
accepted by Buyer, all such costs shall be borne by Seller.
(9) Notwithstanding anything to the contrary herein, Seller shall
arrange and be responsible for transmission service to the Delivery Point,
if any, and shall obtain Schedule Coordinator services necessary to deliver
the Product to the Delivery Point. Seller shall be responsible for all
charges due to the CAISO, and entitled to receive all payments from the
CAISO, related to deviations; provided that in the case of real-time
schedule changes by Buyer resulting in generation in excess of the
schedule with the CAISO, Buyer shall receive any payments from CAISO
related to deviations.
(10) Seller shall be entitled to make the Facility unavailable for
scheduling for up to fourteen (14) peak days per Contract Year as
Scheduled Maintenance. Scheduled Maintenance hours shall not be
included in the calculation of the Facility's Actual Availability. In no
event may Scheduled Maintenance occur during the months of June
through October, inclusive.
(11) Metering shall conform to ISO standards or the equivalent. Any
generation meter multiplier (GMM) adjustments shall be for Buyer's
account (i.e. notwithstanding any required GMM adjustments, Seller shall
be deemed to have delivered the full metered amount of energy from the
Facility).
(12) (i) Fuel Supply Plan. At least ninety (90) Days prior to the
commencement of the next succeeding Fuel Supply Period, Seller shall
provide for Buyer's approval a proposed Fuel Supply Plan for the next
succeeding Fuel Supply Period. The Fuel Supply Plan shall provide
information regarding, at a minimum, 1) expected Fuel requirements, 2)
how Seller intends to obtain or provide Fuel and Fuel -related services such
as transportation, distribution, storage and any other delivery services to
account for particular commodity requirements, 3) an estimate of
delivered gas costs and 4) any other special considerations such as
financial risk issues. Seller should recognize that Buyer may have a
portfolio of facilities for which it supplies fuel, and that it is in Buyer's
interests to supply Fuel Manager Services to the Facility; thus, Seller's
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CONFIDENTIAL
proposed Fuel Supply Plan should include the appointment of Buyer as
Fuel Manager for all Fuel deliveries to the Facility. The Parties may meet
at mutually agreeable times prior to the next succeeding Fuel Supply
Period to discuss any modifications to Seller's proposed Fuel Supply Plan
that Buyer reasonably requests. Nothing in this Special Condition 12 shall
be construed as obligating Seller to adopt a Fuel Supply Plan or to agree to
any modifications to a Fuel Supply Plan that: (i) Seller reasonably
believes could interfere with its ability to provide the Product from the
Facility; or (ii) Seller reasonably believes, in its sole discretion, could
potentially expose Seller to risks, including credit, market or delivery
risks, or liabilities that Seller considers unacceptable. Any Extended -
Term Obligation included in any Fuel Supply Plan shall be governed by
Section (iv) of this Special Condition 12.
(ii) Parties' Failure to Execute Fuel Supply Plan In the event the Parties
do not agree to a Fuel Supply Plan by the sixtieth (60) day prior to the next
succeeding Fuel Supply Period, Buyer may elect, at Buyer's sole option,
to provide, or cause to be provided, for the next succeeding Fuel Supply
Period, Fuel to the Facility from Buyer's own fuel purchases, and Fuel
Manager Services. Buyer's election to provide, or cause to be provided,
Fuel to the Facility and Fuel Manager Services under this Section (ii) of
this Special Condition 12 shall be expressed in writing to Seller no later
than thirty (30) Days prior to the commencement of the next succeeding
Fuel Supply Period. Buyer's election to provide Fuel and Fuel Manager
Services shall include a supply plan with the same detail contemplated for
a Seller Fuel Supply Plan under Section (i), above, and will necessarily
appoint Buyer as Fuel Manager. If the Parties do not agree on a Fuel
Supply Plan and Buyer does not elect to provide Fuel to the Facility from
Buyer's own fuel purchases, Seller will provide, from the Spot Market,
Fuel necessary for the delivery of energy hereunder during the next
succeeding Fuel Supply Period, or until the Parties have agreed to and
executed a Fuel Supply Plan for such Fuel Supply Period, as well as Fuel
Manager Services (at least until the next Fuel Supply Period). In the event
the Parties have not agreed to and executed a Fuel Supply Plan, Buyer has
not elected to provide Fuel to the Facility from Buyer's own fuel
purchases, and Seller is unable, using commercially reasonable efforts, at
any time during the Fuel Supply Period, to provide Fuel necessary for the
delivery of energy hereunder from the Spot Market, then Buyer will
provide Fuel necessary for the delivery of energy hereunder. In the event
Seller is unable to provide Fuel necessary for the delivery of energy
hereunder from the Spot Market, and Buyer is unable to provide Fuel
necessary for the delivery of energy hereunder, such inability to provide
Fuel shall constitute Force Majeure. Whenever Buyer is not Fuel
Manager, Seller shall ensure that Fuel Manager provides Buyer, upon
Buyer's request and to the extent such information is available, timely
access to daily meter gas volumes for the Fuel relevant to Buyer's energy
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CONFIDENTIAL
and real time notifications of utility and/or account information that may
affect the nomination and scheduling of Buyer's Fuel supplies.
(iii) Buyer Delivery of Fuel Notwithstanding Agreed Fuel Supply Plan. If
Seller is unable to provide Fuel to the Facility during any Fuel Supply
Period for which the Parties have executed a Fuel Supply Plan, Buyer may
provide Fuel to the Facility.
(iv) Extended -Term Obligations._ The Parties acknowledge that any Fuel
Supply Plan may include obligations provided by either Party which
extend beyond the applicable Fuel Supply Period ("Extended -Term
Obligations"). Extended -Term Obligations may include, but are not
limited to, long-term commitments for pipeline capacity, storage rights, or
financial risk products pertaining to the commodity price (such as fixed
prices, costless collars, basis purchases, caps, or other price management
mechanisms). Any Extended -Term Obligation that the Parties specifically
approve in a separate letter agreement of approval shall be deemed
effective and approved for the duration of the period to which it applies,
regardless of whether such period extends beyond the term of any Fuel
Supply Plan. For the avoidance of doubt, if Buyer is providing Fuel from
Buyer's own fuel purchases or if Seller is providing Fuel on the Spot
Market pursuant to Section (ii) above, such provisions must be consistent
with, and are limited by, the terms of any Extended -Term Obligations that
the Parties have specifically approved in a separate letter agreement of
approval. Within forty-five (45) Days prior to the termination of a Fuel
Supply Plan, Buyer may assume all effective and approved Extended -
Term Obligations (except for Seller's firm transportation rights) provided
that Buyer obtains a release from the counter party to the Extended -Term
Obligations releasing Seller from any future obligations Seller has with
regard to such Extended -Term Obligations.
(v) Fuel Price. The Monthly Fuel Price shall be calculated as the average
cost of Fuel delivered to the Facility to generate energy as scheduled or
requested by Buyer, including Extended Term Obligations, for a month,
such Fuel being obtained either 1) under a Fuel Supply Plan, 2) by Seller
on the Spot Market, or 3) by Buyer, as applicable. Buyer shall be solely
responsible, without reimbursement from Seller, for any costs or charges
imposed on or associated with Fuel it provides to the Facility pursuant to
Sections (ii) and (iii) above. In the event Buyer provides Fuel Manager
Services for the Facility, Seller shall pay Buyer an appropriate and
customary fuel management fee.
(vi) Fuel Imbalances. Seller and Buyer shall each be responsible for
any fuel imbalances that each causes;rop vided, however, that if Seller is
providing Fuel pursuant to this Special Condition 12, Seller shall arrange
and deliver Fuel to accommodate Buyer's rights to dispatch at a minimum
of two (2) hours per dispatch and at least two (2) dispatches per Day, as
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REVISED DRAFT
Option Buyer: N/A
Option Seller: N/A
CONFIDENTIAL
scheduled on a day -ahead basis to be achieved without the incurrence of
any penalties. Any natural gas imbalance penalties that are invoiced to
Buyer require documentation of penalty assessment by a non -related third
party, attributable to Buyer's dispatch of Energy from the Facility on the
Day(s) applicable to the imbalance determination, and conditioned upon
any Fuel Manager's reasonable efforts to minimize such imbalance
charges.
Type of Option: N/A
Strike Price: N/A
Premium: N/A
Exercise Period: N/A
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This confirmation letter is being provided pursuant to and in accordance with the Master
Power Purchase and Sale Agreement dated , 2001 (the "Master Agreement")
between Party A and Party B, and constitutes part of and is subject to the terms and provisions of
such Master Agreement. Terms used but not defined herein shall have the meanings ascribed to
them in the Master Agreement.
City of Lodi State of California Department of Water Resources
separate and apart from its powers and
responsibilities with respect to the State
Water Resources Development System
By: By:
Name: Name: Thomas M. Hannigan
Title: Title: Director
Phone No: Phone No: (916) 653-7007
Fax: Fax: (916) 653-0943
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Attachment 1 to Confirmation Letter for 2001B Transaction
Between City of Lodi and CDWR
Effective Date
6/1/2002
6/1/2003
6/1/2004
6/1/2005
6/1/2006
6/1/2007
6/1/2008
6/1/2009
6/1/2010
6/1/2011
6/1/2012
6/1/2013
6/1/2014
6/1/2015
6/1/2016
Variable O&M Rate
($/MWh)
$3.00
$3.09
$3.18
$3.28
$3.38
$3.48
$3.58
$3.69
$3.80
$3.91
$4.03
$4.15
$4.28
$4.41
$4.54
Fixed O&M Rate
($/kW -mo)
$1.82
$1.87
$1.93
$1.99
$2.05
$2.11
$2.17
$2.24
$2.31
$2.37
$2.45
$2.52
$2.59
$2.67
$2.75
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REVISED DRAFT CONFIDENTIAL
PROCEDURE 1
2001B Transaction
Net Demonstrated Capacity Test for Pealdng Facilities
Test Procedure and Schedule
Seller shall prepare and submit its written, proposed test procedure and schedule to Buyer
no less than fifteen (20) business days before the proposed test date for Buyer's
acceptance and, within ten (10) business days of such submittal, Buyer and Seller shall
meet to review and discuss the proposed test procedure and schedule. Except for the
initial test, Buyer and Seller may waive such meeting by mutual agreement.
Within five (5) business days of such meeting or waiver thereof, Buyer shall submit
either its written acceptance or revision, including the reasons for any revisions, of the
proposed test procedure and schedule to Seller. The failure by Buyer to submit timely
such written acceptance or revision shall constitute acceptance of the proposed test
procedure and schedule by Buyer. Such accepted or revised test procedure and schedule
shall be the approved test procedure and schedule.
Seller shall provide written notice to Buyer of any changes to the approved test procedure
and schedule and the reason(s) therefore as soon as reasonably practicable, such changes
being subject to Buyer's approval.
The proposed and approved test procedures shall comply with the requirements of
Section 3 of the Performance Test Code ASME PTC 22-1997 for Gas Turbine Power
Plants or its successor ("PTC 22").
Annual Scheduling Requirement
A successful test is required to be performed once per calendar year. The initial
successful test is required to be performed not less than five days prior to COD and
subsequent successful tests are required to be performed between May 1 and May 31 in
each Contract Year thereafter. For all tests after COD, Seller and Buyer, to the extent
possible, shall schedule such tests during periods in which Buyer has Scheduled the
Facility to operate.
A successful test is also required to be performed as soon as reasonably practicable after
any change to the Facility that is reasonably expected to change the then -current NDC of
the Facility by at least 10% and such change is reasonably expected to last for at least six
(6) months. If the timing of such a required test shall occur reasonably close to the
timing of a required annual test, a single test may be conducted to satisfy both
requirements. In addition, each of Buyer and Seller may request up to two additional
tests per calendar year during the Delivery Period (at any time) utilizing these procedures.
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Test Conditions
A. Start -Up and Stabilization Period
Prior to the start of the test, the Facility shall be started, synchronized and brought to full
load using normal start procedures and then operated continuously at full load for as long
as it is necessary, but in no case for no less than one hour, for all measured parameters to
achieve stable, normal conditions such that any variations in such parameters will be
within the tolerances provided in Table 3.3.3 of PTC 22.
B. Overatina Personnel
The Facility shall be operated by Seller's operating personnel (whether employees of
Seller or Seller's operating contractor) and no one else, including, but not limited to,
representatives of (i) any manufacturer or supplier of the Facility's equipment, (ii) any
provider of engineering or design services related to the Facility, (iii) any provider of
construction services related to the Facility, or (iv) any third party consultant.
C. Duration
The duration of the test shall be four (4) continuous hours, which shall commence only
upon satisfactory completion of the Start -Up and Stabilization Period.
D. Operating Procedures and Conditions
At all times, the Facility shall be operated in compliance with the approved test
procedure, Prudent Utility Practice and all operating procedures recommended, required
or established by (i) the manufacturer or supplier of the Facility's equipment (ii) the
firm(s) that engineered and designed the Facility and (iii) the contractor(s) that
constructed the Facility. Any tests during which such compliance is breached shall be
deemed invalid and not to have occurred.
At no time during the test shall the Facility be subject to disruptions or abnormal
conditions including, but not limited to, any (i) unstable conditions, (ii) equipment,
operating, or regulatory restrictions, or (iii) changes in load from full load other than
those fluctuations naturally arising from variations in ambient temperature. Should any
such disruption be encountered during a test, the test shall be restarted or rescheduled.
E. Applicable Laws and Permits
At all times, the Facility shall be in compliance with all applicable laws, regulations and
permits, including, but not limited to, those governing safety and air and water emissions.
Any tests during which such compliance is breached shall be deemed invalid and not to
have occurred.
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F. Data Collection
At a minimum, the following parameters will be measured and recorded simultaneously
at no greater than five minute intervals:
(a) Instantaneous ambient relative humidity (%)
(b) Instantaneous ambient barometric pressure (inches Hg)
(c) Instantaneous ambient temperature (°F)
(d) Net output since last measurement at the Delivery Point (kWh)
(e) CEMS data required per air permit
(f) Turbine speed (rpm)
(g) Turbine temperatures (°F)
(h) Turbine pressures (psig)
Upon mutual agreement of the parties, additional parameters may be measured and
recorded simultaneously with the required parameters. Such additional parameters may
include for example, gross generator output and fuel consumption, and such additional
measurements may be used only to determine whether or not any abnormal condition
occurred during the test.
G. Instrumentation and Metering
At its own cost, Seller shall provide all instrumentation, metering and data collection
equipment required to perform the test. Wherever possible, the instrumentation, metering
and data collection equipment that will be used after the Facility achieves COD for
monitoring and controlling the operation of the Facility and collecting the data required
for Seller to prepare and submit its monthly invoice to Buyer shall be used for the test.
At its own cost, Seller shall calibrate or cause to be calibrated all such instrumentation,
metering and data collection equipment no more than three (3) months prior to the date of
the test. All Electrical Metering Equipment shall be in compliance with CAISO
Requirements including, but not limited to, those relating to certification and calibration.
Adjustments to Data and Calculation of NDC
Seller shall perform the calculation of NDC using the test data subject to the following
adjustments:
The net output for each data point shall be adjusted to Site Standard Conditions by first
adjusting for differences, if any, between the instantaneous ambient barometric pressure
for that data point and Site Standard Conditions using the formula attached hereto as
Table 1 of Procedure 1, and adjusting that result for differences, if any, between the
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CONFIDENTIAL
instantaneous ambient temperature for that data point and Site Standard Conditions using
the manufacturer's certified performance curve for the Facility's generating equipment.
No adjustment shall be made with respect to relative humidity.
Using the resulting net output data from this sequential, two-step adjustment process, the
average net kW output at Site Standard Conditions at the Delivery Point shall be
calculated for each of the sixteen (16) consecutive fifteen (15) minute intervals
comprising the test. The lowest of the sixteen average net kW values thus calculated
shall be the NDC.
Test Reports
Within ten (10) business days after the completion of the test, Seller shall prepare and
submit to Buyer a written report of the test in accordance with Section 6 of PTC 22. At a
minimum, the report shall include (i) the approved test procedure, (ii) a record of the
personnel present for the test whether serving in an operating, testing, monitoring or other
such participatory role, (iii) documentation of the satisfactory completion of the start-up
and stabilization period, (iv) a record of any unusual or abnormal conditions or events
that occurred during the test and any actions taken in response thereto, (v) the unadjusted
data, (vi) a verification of the validity of the test in accordance with Section 3.5.1 of
PTC 22, (vii) the adjusted data with supporting calculations, (viii) NDC with supporting
calculations, and (ix) Seller's statement of either Seller's acceptance of the test or Seller's
rejection of the test and reason(s) therefore. Within ten (10) business days after receipt of
such report, Buyer shall notify Seller in writing of either Buyer's acceptance of the test or
Buyer's rejection of the test and reason(s) therefore.
Test Acceptance and Re -Testing
If Seller and Buyer both accept a test, the NDC shall be updated to reflect the results of
such test effective upon the first day of the month following the month in which Buyer
receives Seller's test report.
If Seller is unable to complete a test for any reason, it shall be permitted to reconduct
such test.
If either Seller or Buyer reasonably believes an abnormal condition occurred which may
have adversely impacted a completed test, such party may request and shall receive a re-
test.
If, following two completed re -tests, Seller and Buyer cannot agree that the original test
and two re -tests produced accurate, reliable and usable results, the parties shall hire an
independent engineer to observe a third re -test and, after considering the data and records
from the original test and three re -tests, to declare the NDC of the Facility. The cost of
such independent engineer shall be shared equally by the parties.
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CONFIDENTIAL
However, if� following two or more completed re -tests, Seller and Buyer do agree that the
most recent test produced inaccurate or unreliable results, the parties may, but are not
required to, hire such an independent engineer.
Cost and Revenue
For all tests prior to COD, the energy produced by Seller from the Facility shall be
scheduled by Seller into the CAISO controlled grid and Seller shall bear all costs for such
tests and receive all revenues from the sale of such energy.
For all tests after COD, Seller and Buyer shall use commercially reasonable efforts to
schedule such tests during periods in which Buyer has Scheduled the Facility to operate.
If unable to be so scheduled, then the energy produced by Seller from the Facility shall be
scheduled by Seller into the CAISO controlled grid and Seller shall bear all costs for such
test and receive all revenues from the sale of such energy.
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TABLE 1 OF PROCEDURE 1
20018 Transaction
BAROMETRIC PRESSURE ADJUSTMENT FORMULA
MW (adjusted) = MW (observed) * [Standard barometric site pressure/Observed
barometric site pressure]
Where, for the Lodi site ( famsl):
Standard barometric site pressure = in. Hg
Example adjustment calculation:
Observed site conditions and output on day of testloperations:
Power output 42,700 kW
Barometric pressure 30.02 in. Hg
Barometric pressure adjustment calculation:
MW(corrected) = 42,700 kW * ( /30.02)
MW(corrected) = 42,700 kW " .
MW(corrected) = kW
CDWR— Lodi Agreement Page 18 of 18 11:24 AM;10/25/01
RESOLUTION NO. 2001-245
A RESOLUTION OF THE LODI CITY COUNCIL AUTHORIZING
THE CITY MANAGER TO EXECUTE EXHIBIT "B" OF THE MASTER
POWER PURCHASE AND SALE AGREEMENT BETWEEN THE
CITY OF LODI AND THE STATE OF CALIFORNIA
DEPARTMENT OF WATER RESOURCES
WHEREAS, for nearly five months, City staff and the State of California
Department of Water Resources (DWR) have been negotiating the terms and conditions
o the development of a peak power generating plant to be located with the City limits of
Lodi. DWR purchases power for two of the State's largest investor-owned utilities as a
result of the "meltdown" of California's power markets at the beginning of the year; and
WHEREAS, DWR has determined that the State would benefit from additional
peak generating capacity and City staff has determined that an appropriately designed
and located peaking facility would be advantageous to the reliability and energy security
of City of Lodi electric customers; and
WHEREAS, City staff is now seeking Council approval to proceed with the
development of a 43-45Mw peaking power generating facility with the Lodi City limits.
The basic parameters of the transaction is as follows:
• Lodi would develop the new peaking plant.
• Lodi would finance the plant through the issuance of bonds.
• Lodi would own and operate the plant.
• Lodi will retain the right to recall up to 22Mw of capacity commencing July 1,
2005.
• DWR would pay Lodi a fixed and variable monthly amount for the fifteen (15)
year term of the agreement.
• DWR would supply the fuel or pay Lodi to supply the fuel for the plants output.
• After the fifteen (15) year term of the agreement, the plant output would belong
to Lodi without further obligation to DWR; and
WHEREAS, City staff respectfully requests City Council authorization for the City
Manager to execute Exhibit B — Master Power Purchase and Sale Agreement
Confirmation Letter (2001 B Transaction — Peaking Capacity) between the City of Lodi
and DWR. Exhibit B is in substantially final form. It should be noted that Council's
authorization of Exhibit B is contingent upon an appropriate site being located within the
City limits of Lodi as contemplated under all appropriate provisions of the California
Environmental Quality Act. Additionally, Council's authorization is contingent upon the
City's ability to finance the project; and
WHEREAS, the Electric Utility Department respectfully requests City Council
authorization for the City Manager to execute Exhibit "B" of the Master Power Purchase
and Sale Agreement.
NOW, THEREFORE, BE IT RESOLVED, that the Lodi City Council does hereby
authorize the City Manager to execute Exhibit "B" of the Master Power Purchase and
Sale Agreement between the City of Lodi and the State of California Department of
Water Resources presented here in substantial final form.
Dated: October 30, 2001
I hereby certify that Resolution No. 2001-245 was passed and adopted by the
City Council of the City of Lodi in a special meeting held October 30, 2001 by the
following vote:
AYES: COUNCIL MEMBERS — Hitchcock, Howard and Mayor Nakanishi
NOES: COUNCIL MEMBERS — None
ABSENT: COUNCIL MEMBERS — Land
ABSTAIN: COUNCIL MEMBERS — Pennino
SUSAN J. BLACKSTON
City Clerk
2001-245