HomeMy WebLinkAboutAgenda Report - August 21, 2002 I-05AGENDA TITLE: Adopt resolution authorizing the City Manager to execute two agreements that will provide for
the transition from the expiring PG&E Interconnection Agreement (IA) with the City of Lodi
(EUD) for the provision of transmission and ancillary services to the California Independent
System Operator (CAISO) being the new provider with the Northern California Power Agency
(NCPA) acting as Lodi's agent: 1) NCPA Schedule Coordination (SC) Service Agreement
between the City and NCPA; 2) PG&E Replacement Interconnection Agreement (RIA) with
PG&E and NCPA and other City members (EUD)
MEETING DATE: August 21, 2002
PREPARED BY: Electric Utility Director
RECOMMENDED ACTION: That the City Council adopt a resolution authorizing the City Manager to execute with
the City of Lodi the following two agreements: 1) NCPA Schedule Coordination (SC)
Service Agreement between the City and NCPA; 2) PG&E Replacement
Interconnection Agreement (RIA) with PG&E and NCPA and other City members.
Background Information: A number of agreements need to be executed by the City and Northern California
Power Agency (NCPA) on behalf of the City of Lodi in the coming weeks and months
to replace the Pacific Gas and Electric Company (PG&E) Electric Transmission
Interconnection Agreement (IA). The IA terminates on September 1, 2002. The new set of agreements will continue
to provide the City the capability to connect City -owned and contracted generation resources located outside the City
limits to the City's electric load.
The new set of agreements will have a number of signatories including NCPA, NCPA member cities including the City
of Lodi, PG&E and the California Independent Systems Operator (CAISO), the successor transmission system
operator that replaced PG&E after the electricity market deregulation in California in 1998. The combination of the
two agreements listed below will allow the City to operate with reasonable operational and cost certainty in the CAISO
environment upon the termination of the PG&E IA.
City of Lodi has obtained this service from PG&E for decades, and has relied on the PG&E Transmission System
since the 1920s. The City along with other NCPA member Cities are signatories of the PG&E IA since 1983, which
provides, among other things, transmission inter -connection services between City load and City -owned NCPA
generation projects.
In July 1997, PG&E exercised its three-year notice right to terminate the IA, which would have resulted in a
termination date of August 2000. A number of interim agreements extended the IA past August 2000. In August
2001, PG&E unilaterally filed with the Federal Energy Regulatory Commission (FERC) its proposed replacement IA
(RIA) to be effective April 1, 2002. The RIA filed by PG&E provides basic protocols to physically connect loads and
generation resource to the transmission grid, but defers to the CAISO to provide the transmission and control area
services required by the City and other NCPA member cities. NCPA's request to FERC delayed the effective date of
PG&E's proposed RIA to September 1, 2002 and convened a number of technical conferences with NCPA,
PG&E and the CAISO to facilitate the negotiation of an acceptable replacement arrangement by September
1, 2002.
APPROVED:
H. bixon Flynn - City Manager
Since September 2001 with input from City staff and other member Cities, NCPA has been negotiating with the
CAISO to develop a transmission arrangement that is well adapted for load serving entities like the City of Lodi. The
Aggregated Metered Subsystem Operator (MSSO) Agreement now negotiated with the CAISO meets the City's needs
at this time. The replacement to the IA negotiated with the CAISO will result in the City load and City -owned
generation being treated as a Metered Sub -System (MSS) in the CAISO operated electric transmission system with
NCPA becoming an Aggregated Metered Sub System Operator (MSSO).
Key aspects of the MSS/MSSO agreement is briefly outlined below:
• Provides for load following capability with NCPA-owned generation, whereby the City balances load and
resources in real time and avoids the CAISO volatile real time market prices. This also enables the City to
avoid certain CAISO overhead charges.
• Without the MSS/MSSO, Lodi EUD costs for ancillary and transmission services could be 20% higher than
the cost of the new CAISO charge ($200,000 to $300,000 above anticipated costs).
• Local generation, within City limits, will not be subject to CAISO transmission charges when plant output does
not exceed City load. This retains the incentive to site generation within the City.
• City of Lodi/NCPA retains local control over City of Lodi/NCPA-owned generation resource. That is, the
CAISO may not dispatch these units unless NCPA decides to participate in the CAISO operated markets for
energy and ancillary services.
• If the City maintains its full generation capacity and reserve requirements to meet its load, the City will not be
required to participate in any "economic" blackouts which may occur in northern California due to other
utilities' failure to procure sufficient capacity to meet their loads.
Staff recommends that Council authorize the City Manager to execute on behalf of the City the following two
agreements to ensure a reliable transmission interconnection:
1. NCPA Schedule Coordination (SC) Service Agreement between the City and NCPA (Provides a basis for NCPA
to operate for members and for members how they will be accommodated under the CAISO through NCPA);
2. PG&E Replacement Interconnection Agreement (RIA) between PG&E, NCPA, and NCPA member Cities including
Lodi (provides a formal transition form old IA to new situation for PG&E).
The schedule for the action is tight with all NCPA members scheduled to approve the two agreements by
September 1, 2002. The two agreements are attached in final form and are recommended for execution by
the City Manager at this time.
If Lodi does not voluntarily execute these agreements, the ISO and PG&E will unilaterally file the traditional
ISO Agreements at FERC.
APPROVED:
H. Dixon Flynn - City Manager
CITY OF LODI COUNCIL COMMUNICATION
FUNDING: Not applicable. Part of original NCPA budget
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Electric Utility Director
PREPARED BY: Boris Prokop, Power Supply and Rates Manager
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APPROVED:
H. Dixon Flynn - City Manager
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SCHEDULING COORDINATION
PROGRAM AGREEMENT
This Agreement, dated as of , 2002, by and among the
Northern California Power Agency, a joint powers agency of the State of
California (NCPA), and certain members of NCPA: City of Alameda, City of
Biggs, City of Gridley, City of Healdsburg, City of Lodi, City of Lompoc, City of
Palo Alto, Plumas-Sierra Rural Electric Cooperative, City of Roseville, City of
Santa Clara, and City of Ukiah (Participants) that have executed this Agreement,
is entered into on the basis of the following:
0.0 RECITALS:
0.1 NCPA, Silicon Valley Power (City of Santa Clara or Santa Clara),
Pacific Gas and Electric Company (PG&E), Western Area Power
Administration (Western), and the California Independent System
Operator (CAISO) are parties to a Settlement Agreement Among
Pacific Gas and Electric Company, Northern California Power
Agency, The City of Roseville, California, The City of Santa Clara,
California as Silicon Valley Power, and the California Independent
System Operator Corporation, FERC Docket Nos. ER01-2998-000,
ER02-358-000, and EL02-64-000 (Settlement Agreement);
0.2 NCPA, City of Alameda, City of Biggs, City of Gridley, City of
Healdsburg, City of Lodi, City of Lompoc, City of Palo Alto,
Plumas-Sierra Rural Electric Cooperative and City of Ukiah, and
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Santa Clara are parties to separate Replacement Interconnection
Agreements, dated July 12, 2002, with PG&E;
0.3 Roseville is party to Interconnection Agreements with Western
dated March 1, 1994 and March 24,1997;
0.4 NCPA and CAISO are parties to a Metered Subsystem Aggregation
Agreement dated July 12, 2002 (MSS Aggregation Agreement);
0.5 Santa Clara and Roseville are parties to separate Metered
Subsystem Agreements, dated July 12, 2002, with CAISO (MSS
Agreements);
0.6 The Participants desire NCPA to act as their Scheduling Agent as
defined in Section II of the Settlement Agreement and provide
Scheduling Coordination Services;
0.7 The Participants desire NCPA to provide for Scheduling
Coordination Services utilizing the staff and resources of NCPA;
0.8 The Participants desire to equitably allocate the costs of NCPA's
provision of Scheduling Coordination Services;
0.9 The Participants desire to equitably distribute the CAISO charges
and credits accruing to NCPA as Scheduling Coordinator for the
Participants;
0.10 NCPA and the Participants wish to enter into this Agreement to set
forth the terms under which NCPA will provide to the Participants
the Scheduling Coordination Services described hereinafter; and
0.11 This Agreement does not modify or supersede any NCPA Project
(Third Phase) Agreements, the NCPA Facilities Agreement, the
NCPA Pooling Agreement, or any other agreements among NCPA
and its members.
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NOW, THEREFORE, NCPA and the Participants hereby enter into this
AGREEMENT
1.0 Definitions.
1.1 Agreement. This Scheduling Coordination Program Agreement.
1.2 Balancing Account. The Balancing Account is an account
established at NCPA pursuant to this Agreement. The Balancing
Account is established to: (1) make timely payments to the CAISO
under the MSS Agreement and the MSS Aggregation Agreement
and protect NCPA from potential Participant default by providing
funds and time to cure, (2) provide working capital for NCPA's
provision of Scheduling Coordination Services and to bridge
timing differences between the receipt of payments from
Participants and the date payments are due the CAISO, (3) satisfy
CAISO security deposit requirements, and (4) provide security
against Participant default.
1.3 Commission. The NCPA Commission.
1.4 Commissioner. A voting member of the Commission appointed by
a Participant.
1.5 SC Committee. An ad hoc committee composed of one
representative appointed by each Participant that will recommend
SCALD Costs and Allocations.
1.6 Electric System. Electric System means, with respect to each
Participant, all properties and assets, real and personal, tangible
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and intangible, of the Participant now or hereafter existing, used or
pertaining to the generation, transmission, transformation,
distribution and sale of electric capacity and energy, including all
additions, extensions, expansions, improvements and betterments
thereto and equipment thereof; provided, however, that to the
extent the Participant is not the sole owner of an asset or property
or to the extent that an asset or property is used in part for the
above described purposes, only the Participant's ownership
interest in such asset or property or only the part of the asset or
property used for electric purposes shall be considered to be part of
its Electric System.
1.7 Revenues. Revenues means, with respect to each Participant, all
income, rents, rates, fees, charges, and other moneys derived by the
Participant from the ownership or operation of its Electric System,
including, without limiting the generality of the foregoing, (a) all
income, rents, rates, fees, charges or other moneys derived from the
sale, furnishing and supplying of electric capacity and energy and
other services, facilities, and commodities sold, furnished, or
supplied through the facilities of its Electric System, (b) the
earnings on and income derived from the investment of such
income, rents, rates, fees, charges or other moneys to the extent that
the use of such earnings and income is limited by or pursuant to
law to its Electric System and (c) the proceeds derived by the
Participant directly or indirectly from the sale, lease or other
disposition of all or a part of the Electric System, but the term
Revenues shall not include (i) customers' deposits or any other
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deposits subject to refund until such deposits have become the
property of the Participant or (ii) contributions from customers for
the payment of costs of construction of facilities to serve them.
1.8 Scheduling Coordination Participation Percentage. The percentage
share of each Participant in this Agreement as set forth in
Appendix A, Scheduling Coordination Participation Percentages
and SCALD Allocations.
1.9 Scheduling Coordination Services. The services provided to the
Participants by NCPA under this Agreement.
1.10 Participant. An NCPA member or associate member that is a
signatory to this Agreement.
1.11 SCALD Allocations. SCALD Costs allocated to the Participants in
the NCPA Annual Budget.
1.12 SCALD Costs. System Control and Load Dispatch costs as set forth
in the NCPA Annual Budget and incurred throughout the
operating year.
1.13 Service Schedules. Specific arrangements established between
NCPA and the Participant(s) relating to Scheduling Coordination
services.
1.14 Utility Directors. An ad hoc working group of the utility directors
of the Participants that provide advice to the NCPA General
Manager.
2.0 Purpose.
The purpose of this Agreement is to set forth the terms and conditions
under which NCPA will supply to the Participants Scheduling
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Coordination Services as the Participants may request under this
Agreement.
3.0 NCPA Duties.
NCPA shall perform as the Scheduling Coordinator in accordance with
the relevant MSS Agreements and MSS Aggregation Agreement. Such
duties shall include but are not limited to:
3.1 Recommend to the Participants and cooperate with the SC
Committee in the preparation and distribution of the report on
SCALD Costs and SCALD Allocations for consideration by the
Utility Directors and approval by the Commission as provided in
Section 9.2.
3.2 Implement Participant schedules pursuant to the Settlement
Agreement.
3.3 Obtain and maintain metering data to satisfy CAISO
requirements.
3.4 Review, validate, and reconcile CAISO charges and payments
for services, file timely disputes and appropriately pursue
disputes to resolution. Current CAISO charge types are listed in
Appendix B "ISO Settlement Charge Matrix," but are subject to
change by the CAISO.
3.5 Make timely collection from the Participants of costs charged to
NCPA by the CAISO consistent with the provisions of
Appendices B and E, and make timely payments to the CAISO of
such charges in accordance with the provisions of the relevant
MSS Agreements.
4.0 Participant Duties.
The duties of the Participants are to:
4.1 Provide NCPA with load and resource schedules in accordance
with Appendix C "Participant Scheduling Protocols."
4.2 Pay NCPA for CAISO charges referred to in Section 3.
4.3 Provide staff and other assistance as may be required from time to
time necessary for NCPA to fulfill its duties described in Section 3.
4.4 To comply with certain Western Electricity Coordinating Council
(WECC) reliability criteria and to be subject to sanctions imposed
by the WECC Reliability Criteria Agreement should they fail to do
so, as set forth in Section 10.4 of the MSS Aggregation Agreement
or the MSS Agreements and to comply with all relevant
requirements of the MSS Aggregation Agreement or MSS
Agreements, as applicable, to the operation and maintenance of its
Electric System.
4.5 Indemnify NCPA in regard to Scheduling Coordination Services
provided by NCPA.
5.0 Billing and Pam
5.1 CAISO Estimated Invoice. NCPA will issue estimated invoices to
Participants 15 calendar days after the end of each trade month,
with payment due thirty (30) calendar days thereafter. These
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invoices will be based on schedules, metering data, and estimates
of power prices (A/S costs etc.) for the CAISO charge types
enumerated in Appendix B. At the request of individual
Participants, these invoices shall be provided in electronic format.
5.2 CAISO Final Invoice. NCPA will issue final invoices for the CAISO
charge types enumerated in Appendix B to Participants 15 calendar
days after receipt of CAISO final invoices, with payment due thirty
(30) calendar days thereafter. If the CAISO final invoice results in a
credit amount due to any Participant, NCPA will apply the credit
to the balance of the Participant's share of the Balancing Account.
At the request of individual Participants, these invoices shall be
provided in electronic format.
5.3 Allocation of CAISO Charges and Credits. The basis for allocation
to Participants of each CAISO charge type is described in Appendix
B. Upon implementation by the CAISO of new or modified CAISO
charge types, NCPA shall distribute to the SC Committee its
proposal for any necessary changes in Appendix B as soon as
practical. The SC Committee shall make a report to the Utility
Directors and the Commission either recommending adoption of
the NCPA allocation proposal, or offering an alternative proposal.
New charge types and their allocation bases shall be included in an
amended Appendix B.
5.4 NCPA Costs. Monthly billing statements prepared by NCPA shall
be sent to each Participant showing the Participant's share of
SCALD Costs and other expenses relating to this Agreement
incurred by NCPA for the previous month. This information may
be provided on monthly billing statements prepared by NCPA
pursuant to other Project Agreements. Each Participant's share of
such costs and expenses shall be based on schedules contained in
Appendix A, Scheduling Coordination Participation Percentages
and SCALD Allocations.
5.5 Application of Balancing Account. NCPA may apply a
Participant's share of the Balancing Account to the payment of any
portion of a CAISO invoice allocated to that Participant.
Application of such funds shall not relieve the Participant from any
late payment charges pursuant to Section 5.6.
5.6 Late Payments. Amounts shown on each billing statement are
due and payable at the time noted on the invoice, but not later
than thirty (30) days after the date of the invoice, except that any
amount due on a Friday, holiday or weekend may be paid on the
following working day. Any amount due and not paid by a
Participant shall bear interest at the per annum prime rate (or
reference rate) of the Bank of America NT & SA then in effect,
plus two percent per annum computed on a daily basis until
paid.
5.7 Settlement Data. NCPA will make settlement data, including
underlying data received from the CAISO, available to the
Participants. Procedures and formats for the provision of such data
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will be as established by the Participants and NCPA from time to
time and specified in Appendix D, "Settlement Data." The data will
include, but not be limited to, a listing of the CAISO charge types
and NCPA's allocation methodology, and load and power cost data
used for NCPA estimated and final invoices.
5.8 Audit Rights. Each Participant shall have the right to audit any
data created or maintained by NCPA pursuant to this Agreement
on thirty (30) days written notice unless otherwise agreed by such
Participant and NCPA.
5.9 Participant Covenants. Each Participant covenants and agrees (a)
to establish and collect rates and charges for the services and
commodities provided by its Electric System sufficient to provide
Revenues adequate to meet its obligations under this Agreement
and to pay all other amounts payable from, and all lawful charges
against or liens upon, the Revenues; (b) to make payments under
this Agreement from the Revenues of, and as an operating expense
of, its Electric System; (c) to make payments under this Agreement
whether or not there is an interruption in, interference with, or
reduction or suspension of services provided under this Agreement
(such payments are not subject to any reduction, whether by offset
or otherwise, and regardless of whether any dispute exists); and (d)
to operate its Electric System and the business in connection
therewith in an efficient manner and at reasonable cost and to
maintain its Electric System in good repair, working order, and
condition.
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6.0 Defaults
6.1 Failure To Pay. If any Participant fails to pay any amount due to
NCPA within thirty (30) days of the date of the estimated or final
invoice enumerating such amounts, the Participant is in default
and material breach under this Agreement.
6.2 Other Material Breaches. If a Participant is in default or in breach of
any of its covenants under any other agreement with NCPA, it
shall also be considered in material default of this Agreement.
6.3 Cure Period. Upon written notice by NCPA, a Participant shall cure
any default within five (5) working days.
6.4 Cure of Defaults. A default pursuant to Section 6.1 shall be cured
by the payment of any monies due NCPA, including any late
payment charges pursuant to Section 5.6, and repayment of any
funds drawn from the Balancing Account pursuant to Section 5.5.
A default pursuant to Section 6.2 shall be cured by compliance with
the covenant.
6.5 Remedies in the Event of a Material Default. NCPA may suspend
the provision of Scheduling Coordination Service to any Participant
with a default which has not been cured within the Cure Period,
including deducting sums in default from the Balancing Account
share of the defaulting Participant, demanding further assurances,
and taking any other legal or equitable action before or after the
Cure Period to compel the correction of the default, as for example,
to mandate the collection of a surcharge to produce Revenues to
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secure the cure of the default, (and the selection of one remedy
shall not preclude the use of other remedies), on behalf of NCPA
and the non -defaulting Participants (in which event the defaulting
Participant shall not have the right to vote under the provisions of
this Agreement while such defaulting Participant is in material
default as determined by the non -defaulting Participants).
6.6 Obligations in the Event of Default. In the event that a Participant's
share of the Balancing Account is insufficient to cover all CAISO
invoices related to Scheduling Coordination Services provided to a
defaulting Participant, (a) the defaulting Participant shall cooperate
in good faith with NCPA and shall cure the default as rapidly as
possible, on an emergency basis, taking all such action as is
necessary, including but not limited to raising rates and charges to
its customers to increase its Revenues to replenish its share of the
Balancing Account as provided herein, drawing on its cash -on -
hand and lines of credit, obtaining further assurances by way of
credit support and letters of credit, repairing its Electric System,
and taking all such other action as will cure the default quickly;
and provided, however, (b) that no Participant shall be liable under
this Agreement for the obligations of any other Participant, and
each Participant shall be solely responsible and liable for
performance of its obligations under this Agreement, and (c) that
the obligation of each Participant under this Agreement is a several
obligation and not a joint obligation with those of the other
Participants.
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7.0 CAISO Security Deposit
7.1 Any security or other deposit required by the CAISO shall be
provided by each Participant prior to the date NCPA provides any
Scheduling Coordination Services and shall be maintained as may
be required thereafter. The initial deposit amounts are shown on
Appendix F "Security Deposit."
7.2 Any changes in security or other deposits required by the CAISO
may be provided by NCPA from the Balancing Account, and
NCPA shall invoice the Participants within ten (10) working days
for their shares.
8.0 Balancing Account
8.1 Initial Amount. Within thirty (30) days of the effective date of this
Agreement, each Participant shall deposit in the Balancing Account
an amount equal to its three highest months of projected ISO
invoices for the succeeding twelve (12) months. NCPA shall
maintain a detailed accounting of the share of each Participant in
the Balancing Account. Interest earned on the Balancing Account
shall be credited to the shares of the Participants. Any losses in the
Balancing Account, due for example to the compulsory sale of
investments to comply with a requirement of the CAISO, shall be
allocated to the Participants' shares.
8.2 Periodic Reviews. Prior to the effective date of this Agreement and
at least quarterly thereafter, NCPA shall review the balance and
Participant shares of the Balancing Account to ensure the aggregate
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amount is equal to the current projection of the three highest
months of each Participant's projected ISO invoices for the
succeeding twelve months. Any funds in excess of one hundred ten
per cent (110%) of this amount shall be credited to the Participants.
If the funds on deposit in the Balancing Account are less than
ninety per cent (90%) of this amount, NCPA shall prepare an
invoice to the affected Participants who shall remit such funds
within thirty (30) days of the invoice date.
8.3 Emergency Additions. In the event that the funds in the Balancing
Account are insufficient to allow payment of an ISO invoice, NCPA
shall notify Participants and then prepare and send a special or
emergency assessment to the Participants.
8.4 Return of Funds. On the termination of this Agreement or the
withdrawal of a Participant, the affected Participant or Participants
may apply to NCPA for the return of their share of Balancing
Account funds ninety (90) days after the effective date of such
termination or withdrawal. NCPA shall, in its sole discretion, as
determined by a vote of the Commission, excluding the vote of the
withdrawing Participant estimate the then outstanding liabilities of
the Participant, including any estimated contingent liabilities, such
as by way of example CAISO invoices subject to dispute or to
revision by the CAISO or the Federal Energy Regulatory
Commission, and retain all such funds until all such liabilities have
been fully paid or otherwise satisfied in full. NCPA may apply any
remaining Balancing Account funds to any remaining obligation of
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such Participant(s), including but not limited to revised CAISO
invoices.
9.0 NCPA Administrative Costs
9.1 SCALD Allocation. For the NCPA Fiscal Year beginning July 1,
2002, certain SCALD costs shall be allocated to the Participants on
the basis detailed in Appendix A, Scheduling Coordination
Participation Percentages and SCALD Allocations.
9.2 Cost Allocation Study. NCPA, in conjunction with the Participants,
shall prepare and distribute to the SC Committee no later than
December 31, 2002 a report detailing all SCALD costs and
functions. The SCALD related costs and functions shall include,
but not be limited to, ISO Scheduling Coordination Services,
Dispatch, Forecasting, Pre -Scheduling, Hydro Scheduling, ISO
Settlements, NCPA Settlements, and Member Settlements. The
report shall include recommendations for assigning costs to each
function, based on cost causation principles. The SC Committee
shall review the report and make recommendations for adoption
and/or modification of the report. The report and SC Committee
recommendations shall be reviewed and adopted or modified by
the Utility Directors by the end of January 2003. The Utility
Directors shall make a final recommendation for inclusion of the
report results in the NCPA FY2004 budget. Those costs and
allocations approved by the Commission shall be included in the
NCPA FY2004 budget and in a revised Appendix A, Scheduling
Coordination Participation Percentages and SCALD Allocations.
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9.3 Annual Budget. Prior to the beginning of each NCPA fiscal year for
which no budget has been adopted and for each fiscal year for
which a budget will be adopted, NCPA shall give notice to each
Participant of the Participant's projected share of the costs and
expenses that NCPA estimates it will incur in the administration of
this Agreement. Such costs shall be allocated to the Participants by
such methods approved by the Commission pursuant to Section
9.2.
9.4 Scheduling Coordination Participation Percentage. Prior to the
beginning of each NCPA Fiscal Year, the Commission shall revise
the Scheduling Coordination Participation Percentages specified in
Appendix A, Scheduling Coordination Participation Percentages
and SCALD Allocations, on the basis of each Participant's share of
SCALD Costs applicable to this Agreement.
9.5 Scheduling Coordination Participation Percentage. Prior to the
beginning of each NCPA Fiscal Year, the Commission shall revise
the Scheduling Coordination Participation Percentages specified in
Appendix A, Scheduling Coordination Participation Percentages
and SCALD Allocations, on the basis of each Participant's share of
SCALD Costs applicable to this Agreement.
10.0 Administration of Agreement
10.1 NCPA. The Commission has overall responsibility for the
administration of this Agreement.
10.2 SC Committee. The SC Committee shall disband after its initial
participation in the preparation of the report pursuant to Section
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9.2 unless the NCPA General Manager requests the Participants to
reappoint the committee to address such questions as changes in
CAISO charges that may warrant changes in SCALD Costs or
SCALD Allocations.
10.3 NCPA Commission Governance Of The Program.
10.3.1 Commission Meetings. The Commission shall meet in
accordance with provisions of the Joint Powers Agreement.
10.3.2 Quorum. A quorum of the Commission, for purposes of
acting upon matters relating to this Agreement, shall consist
of those Commissioners, or their designated alternates,
representing a numerical majority of the Participants, or, in
the absence of such, those Commissioners representing
Participants having a combined Scheduling Coordination
Participation Percentage of greater than fifty percent (50%).
10.4 Voting
10.4.1 Agreement Voting. Each Participant shall have the right to
cast one vote with respect to matters pertaining to this
Agreement. Actions of the Commission with regard to this
Agreement shall be effective only upon a majority vote
subject to the following exceptions:
(a) Upon demand of any Participant, at any
meeting of the Commission, the vote on any issue relating to
this Agreement, shall be based upon the Scheduling
Coordination Participation Percentages. Each Participant
shall have a number of votes equal to its Scheduling
Coordination Participation Percentage. Actions of the
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Commission shall be effective only upon an affirmative vote
of sixty five percent (65%) or more of the total votes to which
all Participants are entitled.
(b) Any Participant may veto a discretionary
action of the Participants relating to this Agreement that was
not taken by a sixty five percent (65%) or more vote, within
ten (10) days following mailing of notice of such
Commissioners' action by giving written notice of veto to
NCPA, unless at a meeting of the Commissioners or
alternates called for the purpose of considering the veto,
held within thirty (30) days after such veto notice, the
holders of Scheduling Coordination Participation
Percentages totaling sixty five percent (65%) or more shall
vote to override the veto.
(c) The sixty five percent (65%) affirmative vote
required for action pursuant to this section shall be reduced
by the amount that the voting rights of any Participant
exceed thirty five percent (35%), but such sixty five percent
(65%) shall not be reduced below a majority in interest.
11.0 Term and Termination
11.1 Term. This Agreement shall become effective on the date on which
it has been duly executed by NCPA and by six (6) other signatories,
but not later than the date the FERC deems the Settlement
Agreement to be effective and shall continue in effect until
im
terminated by consent of all of the Participants that have not
withdrawn or materially defaulted as provided herein.
11.2 Termination and Partial Termination. Any Participant may
withdraw from the Agreement by submitting notice, in writing, to
all other Participants at least three (3) months in advance of the
effective date of such withdrawal. Withdrawal by any Participant
shall not terminate this Agreement as to the remaining Participants.
Withdrawal by any Participant will not terminate any ongoing or
undischarged contingent liabilities or obligations resulting from
this Agreement until they are satisfied in full or provision
satisfactory to NCPA and its nonwithdrawing Participants has
been made for their satisfaction in full. Such termination shall be
reflected in a revised Appendix A, Scheduling Coordination
Participation Percentages and SCALD Allocations.
11.3 Associated Costs. A Participant withdrawing from this Agreement
pursuant to Section 11.2 shall reimburse NCPA for any costs
resulting from withdrawal, including but not limited to
recomputations of schedules and appendices to this Agreement,
removal of communication equipment and data transmission
facilities, or similar incidental costs.
11.4 Termination for Default. In the event that a default by a Participant
remains uncured for one (1) month after notice, NCPA may
terminate that Participant from the Agreement and take any other
action, including the remedies for default provided in this
Agreement. Termination of a signatory will not terminate any
ongoing or undischarged contingent liabilities or obligations
19
resulting from this Agreement until such obligations are satisfied in
full, and all of the costs thereof, including reasonable attorney fees,
the fees and expenses of other experts, including auditors and
accountants, and other reasonable and necessary costs associated
with any and all of the remedies, are paid in full. Such termination
shall be reflected in a revised Appendix A, Scheduling
Coordination Participation Percentages and SCALD Allocations.
12.0 Confidentiality. Participants and NCPA will keep all confidential or trade
secret information made available to them in connection with this
Agreement confidential, to the extent possible, consistent with applicable
laws, including the California Public Records Act. It shall be the
responsibility of the holder of the claim of confidentiality or trade secret to
defend at its expense against any request that such information be
disclosed. Confidential or trade secret information shall be marked or
expressly identified as such.
13.0 New Participants. New Participants may be added to this Agreement by
a vote of the Commission in accordance with Section 10 and execution
and delivery of this Agreement by the new Participant. The addition of a
new Participant shall be reflected in a revised Appendix A, Scheduling
Coordination Participation Percentages and SCALD Allocations.
14.0 No Consequential Damages. No party to this Agreement shall be liable to
NCPA or to any Participant or Participants for consequential damages
that might result from any action or inaction in connection with this
Agreement.
15.0 Amendments. Except where this Agreement specifically provides
otherwise, this Agreement may be amended only by written instrument
executed by the parties with the same formality as this Agreement.
16.0 Severability. In the event that any of the terms, covenants or conditions of
this Agreement or the application of any such term, covenant or
condition, shall be held invalid as to any person or circumstance by any
court having jurisdiction, all other terms, covenants or conditions of this
Agreement and their application shall not be affected thereby, but shall
remain in force and effect unless the court holds that such provisions are
not severable from all other provisions of this Agreement.
17.0 Governing Law. This Agreement shall be interpreted, governed by, and
construed under the laws of the State of California.
18.0 Headings. All indexes, titles, subject headings, section titles and similar
items are provided for the purpose of convenience and are not intended to
be inclusive, definitive, or affect the meaning of the contents of this
Agreement or the scope thereof.
19.0 Notices. Any notice, demand or request required or authorized by this
Agreement to be given to any party shall be in writing, and shall either be
personally delivered to a representative of the Participant on the
Commission and the Secretary of the Commission or transmitted to the
21
Participant and the secretary at the address shown on the signature pages
hereof. The designation of such address may be changed at any time by
written notice given to the Secretary of the Commission who shall
thereupon give written notice of such change to each Participant.
20.0 Warranty Of Authority. Each Participant, and NCPA, represents and
warrants that it has been duly authorized by all requisite approval and
action to execute and deliver this Agreement and that this Agreement is a
binding, legal, and valid agreement enforceable in accordance with its
terms as to the Participant and as to NCPA.
21.0 Counterparts. This Agreement may be executed in any number of
counterparts, and each executed counterpart shall have the same force
9
and effect as an original instrument and as if all the signatories to all of the
counterparts had signed the same instrument. Any signature page of this
Agreement may be detached from any counterpart of this Agreement
without impairing the legal effect of any signatures thereon, and may be
attached to another counterpart of this Agreement identical in form hereto
but having attached to it one or more signature pages.
0%
IN WITNESS WHEREOF, NCPA and each Participant has, by the
signature of its duly authorized representative shown below, executed and
delivered a counterpart of this Agreement.
NORTHERN CALIFORNIA
POWER AGENCY
By:
Its:
Date:
Address:180 Cirby Way
Roseville, CA 95678
CITY OF BIGGS
By:
Its:
Date:
Address: 464-B B Street
Biggs, CA 95917
CITY OF HEALDSBURG
By:
Its:
Date:
Address: 126 Matheson Street
Healdsburg, CA 95448
CITY OF ALAMEDA
By:
Its:
Date:
Address: 2000 Grand Street
Alameda, CA 94501
CITY OF GRIDLEY
By:
Its:
Date:
Address: 685 Kentucky Street
Gridley, CA 95948
CITY OF LODI
By:
Its:
Date:
Address: 221 West Pine Street
Lodi, CA 95241
23 Afproved as to form
*Wy� Attorney
CITY OF LOMPOC
By:
Its:
Date:
Address: 100 Civic Center Plaza
Lompoc, CA 93438
PLUMAS-SIERRA RURAL ELECTRIC
COOPERATIVE
By:
Its:
Date:
Address: P. O. Box 2000
Portola, CA 96122
CITY OF SANTA CLARA
By:
Date:
Address: 1500 Warburton Avenue
Santa Clara, CA 95080
24
CITY OF PALO ALTO
By:
Its:
Date:
Address: 250 Hamilton Avenue
Palo Alto, CA 94301
CITY OF ROSEVILLE
By:
Its:
Date:
Address: 311 Vernon Street
Roseville, CA 95678
CITY OF UKIAH
By:
Its:
Date:
Address: 300 Seminary Avenue
Ukiah, CA 95482
N N P O eD M V N O A m O
O O N 0 M r N N N M O
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APPENDIX B
ISO CHARGE TYPE MATRIX
APPENDIX B
ISO Charge/Payment Allocation Basis for the Members of The NCPA Pool
This spreadsheet presents the allocation basis for ISO charges and payments within the NCPA Pool. By the time these
allocations are applied, the ISO charges and payments have already been allocated to the Pool as a whole, and these
allocations are only used to further allocate within the Pool.
Notes: Member ISO Gross Metered Load is Metered Load + Internal Generation
Member ISO Net Metered Load = Load as Measured at the Meter
Member ISO Gross Metered Demand = Member ISO Gross Metered Load + RT
Exports (Based On Deal Participation Percentage)
Member ISO Net Metered Demand = Member ISO Net Metered Load + RT Exports
(Based On Deal Participation Percentage)
Ancillary Services Payments
L 0001 Day Ahead Spinning Reserve due SC
L 0051 Hour Ahead Spinning Reserve due SC
L 0002 Day Ahead Non -Spinning Reserve due SC
L 0052 Hour Ahead Non -Spinning Reserve due SC
L 0004 Day Ahead Replacement Reserve due SC
L 0054 Hour Ahead Replacement Reserve due SC
L 0005 Day Ahead Regulation Up due SC
L 0055 Hour Ahead Regulation Up due SC
L 0006 Day Ahead Regulation Down due SC
L 0056 Hour Ahead Regulation Down due SC
ISO Cost Allocation Basis Within
Me NCPA Pool
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Comments
Ancillary Services Costs
R 0111 Spinning Reserve due ISO
R 0112 Non -Spinning Reserve due ISO
R 0114 Replacement Reserve due ISO
R 0115 Regulation Up Due ISO
R 0116 Regulation Down Due ISO
Withholding of Dispatched Replacement Reserve Capacity Payment
L 0024 Dispatched Replacement Reserve (Bid -In) Capacity Withhold
L 0124 Dispatched Replacement Reserve (Self -Provided) Capacity
Withhold
A/S Rational Buyer Settlement
C 1011 Ancillary Service Rational Buyer Adjustment
RMR Preempted Ancillary Service Capacity Settlements
L 0061 Hour Ahead RMR Preemption of Spinning Reserve (HA Price)
L 0062 Hour Ahead RMR Preemption of Non -Spinning Reserve (HA
Price)
L 0064 Hour Ahead RMR Preemption of Replacement Reserve (HA
Price)
L 0065 Hour Ahead RMR Preemption of Regulation Up (HA Price)
L 0066 Hour Ahead RMR Preemption of Regulation Down (HA
Price)
L 0071 Real Time RMR Preemption of Spinning Reserve (DA Price)
L 0072 Real Time RMR Preemption of Non -Spinning Reserve (DA
Price)
L 0074 Real Time RMR Preemption of Replacement Reserve (DA
Price)
L 0075 Real Time RMR Preemption of Regulation Up (DA Price)
Member ISO Gross Metered Demand
Member ISO Gross Metered Demand
Member ISO Gross Metered Demand
Member ISO Gross Metered Demand
Member ISO Gross Metered Demand
Project Participation Percentage
Project Participation Percentage
Member ISO Gross Metered Demand
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
chg matrix says by zone, but calc is by
region
chg matrix says by zone, but calc is
by region
chg matrix says by zone, but calc is
by region
chg matrix says by zone, but calc is
by region
chg matrix says by zone, but calc is
by region
L 0076 Real Time RMR Preemption of Regulation Down (DA Price)
L 0081 Real Time RMR Preemption of Spinning Reserve (HA Price)
L 0082 Real Time RMR Preemption of Non -Spinning Reserve (HA
Price)
L 0084 Real Time RMR Preemption of Replacement Reserve (HA
Price)
L 0085 Real Time RMR Preemption of Regulation Up (HA Price)
L 0086 Real Time RMR Preemption of Regulation Down (HA Price)
RMR Preemption Revenues Allocation
Z 1061 Distribution of Preempted Spinning Reserve
Z 1062 Distribution of Preempted Non -Spinning Reserve
Z 1064 Distribution of Preempted Replacement Reserve
Z 1065 Distribution of Preempted Regulation Up
Z 1066 Distribution of Preempted Regulation Down
RMR Imbalance Energy Payment Withhold
L 0410 Unscheduled RMR Energy
Inter -Zonal Congestion Settlements
Z 0203 Day -Ahead Inter -Zonal Congestion Settlement
Z 0253 Hour -Ahead Inter -Zonal Congestion
0256 Hour -Ahead Inter -Zonal Congestion Debit to SCS
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Project Participation Percentage
Member ISO Gross Metered Demand
Member ISO Gross Metered Demand
Member ISO Gross Metered Demand
Member ISO Gross Metered Demand
Member 150 Gross Metered Demand
Project Participation Percentage
External Ties: Deal Participation
Percentage
Path 15: To Lompoc
External Ties: Deal Participation
Percentage
Path 15: To Lompoc
External Ties: Deal Participation
Percentage
Path 15: To Lompoc
More general logic needed if we ever
take delivery in SP15 or ZP26
More general logic needed if we
ever take delivery in SP15 or ZP26
More general logic needed if we
ever take delivery in SP15 or ZP26
ISO Administrative Charges
C 0521 GMC -Control Area Services Member ISO Gross Metered Demand
C 0522 GMC -Congestion Management (abs(CT203) + abs(CT253)) / 2 in all Easy way to determine net inter -
zones zonal nfu flow
C 0524 GMC-A/S and RT Energy Operations Member ISO Gross Metered Load A reasonable simplified allocation
basis - the charge is actually based
on many components including a/s
purchases and sales, self -provision,
instructed and uninstructed energy
Market Uplifts
C
0591 Emissions Cost Recovery
Member ISO Gross Metered Load
should include exports to other in-state
control areas
C
0592 Start -Up Cost Recovery
Member ISO Gross Metered Load
should include exports to other in-
state control areas
TAC/Wheeling Charges
L
0382 High Voltage Wheeling Charge due ISO
For member load: Member ISO Net
I believe exports from the control
Metered Load
area will only be subject to high
For exports: Based on Deal
voltage wheeling
Participation Percentage
L
0383 Low Voltage Wheeling Charge due ISO
For member load: Member ISO Net
Metered Load
Per Unit Charges
C
1010 Neutrality Adjustments
Member ISO Net Metered Demand
C
1101 Black Start Capacity due ISO
Member ISO Gross Metered Demand
C
1302 Long Term Voltage Support Due ISO
Member ISO Gross Metered Demand
C
1303 Supplemental Reactive Energy Due ISO
Member ISO Gross Metered Demand
C
1353 Black Start Energy Due ISO
Member ISO Gross Metered Demand
Not sure about RT vs HA Exports in
this allocation
C
1999 Rounding Adjustment
Member ISO Gross Metered Demand
Instructed Energy Settlements
L 0302 Supplemental Reactive Energy Due SC Project Participation Percentage
L 0401 Instructed Energy Project Participation Percentage
L 0481 Excess Cost for Instructed Energy Project Participation Percentage
UFE a Uninstructed Energy Settlements
Z 0406 SC Unaccounted for Energy (UFElogical) Member ISO Gross Metered Demand For UFE, HA Exports really refers to
exports from the UDC area
L
0407 Uninstructed Energy
See Pool Settlement for Energy in
MSS&PoolBilling.doc
and Example in MSS&PoolBilling.xls
C
0487 Allocation of Excess Cost for Instructed Energy
To those with net negative UE
No -Pay Provision Settlements
L
0141 No Pay Charge - Spinning Reserve
Project Participation Percentage
L
0142 No Pay Charge - Non Spinning Reserve
Project Participation Percentage
L
0144 No Pay Charge - Replacement Reserve
Project Participation Percentage
C
1030 No Pay Provision Market Refund
Member ISO Gross Metered Demand
L
0145 Non Compliance Charge for Regulation Up
Project Participation Percentage
L
0146 Non Compliance Charge for Regulation Down
Project Participation Percentage
Ferc Fee
C
0550 Ferc Fee
Member ISO Gross Metered Demand
Manual line Item Entries
L
1001 Black Start Energy due SC
Project Participation Percentage
L
1003 Regulation Energy payment Adjustment due SC
Project Participation Percentage
L
1004 Overgeneration due SC
Project Participation Percentage
C
1012 RMR Preemption Revenue Allocation
Member ISO Gross Metered Demand
C
1120 Est. Summer Reliability Contract Capacity Pymt/Charge
Member ISO Net Metered Demand
C
1121 Adj. Summer Reliability Contract Capacity Pymt/Charge
Member ISO Net Metered Demand
C
1210 Existing Contracts Cash Neutrality Charge/Refund
Member ISO Net Metered Demand
L
3101 Black Start Capacity due SC
Project Participation Percentage payment defined by contract
L
3302 Supplemental Reactive Energy due SC
Project Participation Percentage payment defined by contract
L
3303 Long Term Voltage Support due SC
Project Participation Percentage payment defined by contract
C 3351 Grid Management Charge Adjustment Charge/Refund
L 3353 Black Start Energy due SC
L 3473 Discretionary Load Curtailment Program - Energy Payment
C 3483 Discretionary Load Curtailment Program Energy Charge
Non-compliance
C 0480 Underscheduled Load Penalty
L 0485 Insufficient Response to AWE Instruction
C 1480 Underscheduled Load Revenue Allocation
C 3999 Interest and Penalty Charge
Energy Exchange Program
R 1487 Energy Exchange Program Neutrality Adjustment
Demand Relief
L 0007 Demand Relief Monthly Payment
C 0117 Demand Relief Monthly Charge - Capacity
L 3472 Demand Relief Monthly Energy Payment
C 3482 Demand Relief Monthly Charge - Energy
Real Time Intra -Zonal Congestion Settlements
L 0451 Real-time Intra -Zonal Congestion Inc/Dec Settlement
Z 0452 Real-time Intra -Zonal Congestion Charge/Refund (Grid
Operations Charge)
Notes: C Allocated per Control Area
L Allocation per Location
Z Allocation per Zone
R Allocated per Region
B Allocated per Branch Group (Tie)
Member ISO Gross Metered Demand
Project Participation Percentage payment defined by contract
Participant's Bid not implement yet
Member ISO Gross Metered Demand
Member ISO Gross Metered Demand
Project Participation Percentage
Member ISO Gross Metered Demand
Member ISO Gross Metered Demand
To those with net negative UE
Participant's Bid
Member ISO Gross Metered Demand
Participant's Bid
Member ISO Gross Metered Demand
Project Participation Percentage
Member ISO Net Metered Demand
Insufficient response during Stage
1,2 or 3 emergency
not implemented yet
not implemented yet
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APPENDIX C
PARTICIPANT SCHEDULING PROTOCOLS
NCPA SCHEDULE COORDINATION SERVICE
SCHEDULING PROTOCOLS FOR SANTA CLARA
*PURPOSE
The purpose of these protocols is to provide The Participants with written
instructions to follow so that Northern California Power Agency (NCPA) acting
as The Participant's Scheduling Coordinator (NCPA-SC) can satisfy all the
requirements under the NCPA MSS AGGREGATOR Agreement (NMAA) dated
July 12, 2002.
•RESPONSIBILITY
NCPA will follow all provisions of the NCPA/NMAA NCPA MSS
AGGREGATOR AGREEMENT. NCPA-SC will coordinate with The Participants
all schedules required under the NMAA. The NCPA Dispatcher will coordinate
all real-time adjustments to resources with The Participants and the NCPA-SC.
*PROCEDURE
The Participants will provide NCPA-SC with their best -estimated load forecast to
be used for scheduling in the ISO Markets. The Participants will provide NCPA-
SC all information on how they will meet this load forecast so as to provide a
balanced schedule for the scheduling period being scheduled. The Participants
will coordinate with NCPA-SC how they will meet the ancillary service (A/S)
requirement and which resources will be used including the purchasing of A/S
from the ISO A/S market or from third parties. All information provided by The
Participants will follow the timelines listed below as they pertain to scheduling
into the ISO markets.
The Participants will coordinate with the NCPA Pre -Scheduling all schedules
utilizing their shares of the NCPA resources. The Participants will coordinate
with the NCPA-SC and NCPA Dispatcher all adjustments to resource schedules,
both their share of NCPA Resources and The Participants Resources required for
load following under the NMAA.
During times the ISO declares a System Emergency under the NMAA, NCPA
and The Participants will each follow their respective Emergency Action Plans
(EAP's) as directed by the ISO. NCPA Manager of Coordinated Operations or
his designate will coordinate all manual load shedding for the NCPA Pool and
The Participants as directed to by the ISO. ISO is to follow Attachment B of the
NCPA EAP when ordering firm load interruptions.
•COMMUNICATION
The Participants will provide NCPA all necessary meter SCADA data for their
loads and resources used to satisfy their requirements under their agreement
with the ISO and for the NCPA-SC and NCPA Dispatcher to use for real-time
adjustments. Meter data provided by The Participants will be used for settling
with the NCPA Pool and ISO.
•SCHEDULING
All scheduling timelines established by NCPA to meet the ISO deadlines will be
adhered to unless mutually agreed to by both The Participants and NCPA-SC. If
no agreement can be reached, the NCPA-SC will take necessary steps to get
schedules in before the ISO markets close. If The Participants fail to submit a
schedule within the required timeframes, NCPA-SC will exercise its authority to
submit a workable schedule to the ISO on behalf of The Participants. NCPA and
The Participants will work together as soon as possible to resolve all scheduling
disagreements.
*Weekly
1. No later than 14:00 each day, provide a weekly load forecast of hourly MW
values for the next seven (7) days (rolling seven-day forecast).
*Daily
1. The Participants may make daily modification to the Weekly forecast by
providing such changes to NCPA prior to 08:00 two (2) workdays before the
active scheduling day.
•Day Ahead
1. For each scheduling day, The Participants is to provide NCPA with a
complete balanced Day -Ahead schedule no later than 1hour prior to the ISO
Day Ahead Market closing. NCPA-SC and The Participants can mutually
agree to modify the time to submit schedules as necessary.
a. Example: loads, resources, imports, exports, sales, trades, ancillary
services
*Hourly
1. The Participants may make modifications to active schedules by providing
such changes to NCPA no later then 1 hour before the close of the ISO
Hour -Ahead Market unless mutually agreed to between NCPA-SC and The
Participants.
a. Example: For power that is scheduled for generation or delivery
15:00, changes must be submitted to NCPA no later than 11:00.
*Real Time
1. NCPA is to be notified of all forced generation outages that affect the
Generating Resources assigned to the NCPA-SC.
2. NCPA is to be notified of all outages that affect The Participants load.
3. The Participants may instruct the NCPA Dispatcher to raise or lower their
share of the NCPA Resources and/or The Participants Resources assigned
to the NCPA-SC for load following (balancing) purposes as needed.
4. The Participants may request from the NCPA Dispatcher to supply load
following power from the Pool share of the NCPA Resources as available.
The power associated with this request will be credited to The Participants
for settlement purposes (i.e., water, fuel, hours, losses, etc.).
5. The Participants may request from the NCPA Dispatcher to schedule an
import on the COI using The Participant's CRN as assigned by the ISO, up
to 30 minutes prior to the start of the ramp, or closer to the ramp if mutually
agreed by all parties.
6. For load following purposes The Participants will provided NCPA with a
prioritized list of units or contracts that it wishes to use for load following.
This list will include both incremental and decremental resources. To the
extent possible NCPA will follow these instructions.
7. The Participants will make best efforts to keep NCPA informed of any
changes in its system that will affect NCPA's ability to follow load.
•Special Scheduling Provisions
1. The Participants will provide NCPA-SC each day a priority list of resources
to be used for daily load following by the NCPA Dispatcher.
2. The Participants Scheduling of SC/SC Trades: Scheduling of an SC/SC Trade
between a Third Party and NCPA-SC or between Third Party and The
Participants. The Participants will provide all necessary scheduling
information as needed for this power to be included in The Participants
Resource/Load balance for the scheduling day being scheduled.
3. The Participants will provide NCPA-SC a daily data file showing applicable
contract provisions being used under this Agreement of energy, A/S and/or
capacity to be scheduled by NCPA-SC.
4. The Participants are to coordinate all emergency operations including load
curtailments with the NCPA Dispatcher.
5. The Participants can request NCPA to handle special scheduling
arrangements under this MSS AGGREGATOR Agreement on a case-by-case
basis. The NCPA Power Management Team will review each request with
Participant to achieve a mutually acceptable solution. It is the intent of
NCPA that no unreasonable request will be denied.
•Outage Coordination
The NCPA Outage Coordinator (OC) or his designate will coordinate all outages
of the NCPA Facilities and The Participants Facilities assigned to NCPA-SC for
purposes of following the ISO protocols. The OC will insure that at no time will
multiple outages be scheduled at the same time that may have an adverse
impact on the NCPA System.
APPENDIX D
SETTLEMENT DATA
"FOR FUTURE USE"
APPENDIX E
IMBALANCE CHARGES
The MSS agreement anticipates that an MSS or in this case NCPA as the
scheduling coordinator (SC) will follow load. Load following does not mean
real-time regulation, but the movement of resources to match load on average
within each 10 -minute settlement interval. Aside from the obvious contribution
to control area reliability, the primary benefit to the Agency of following load is
to minimize exposure to the ISO's imbalance energy market, and to any current
or future ISO costs that may be assigned to those who buy or sell uninstructed
energy.
To receive the benefits of following load, ISO settlements and indeed the MSS
concept require that the resources be scheduled in the same portfolio as the load.
This is a major reason that Santa Clara is consolidating its ISO scheduling into
NCPA's SC portfolio; that is to enable Santa Clara to follow their load utilizing
their share of the jointly owned resources in addition to their other resources.
There is a related benefit to NCPA Pool and Santa Clara by having all their
resources and load in the same portfolio as their jointly owned resources. The
benefit is the substitution of one resource for another, ie., move one resource up
and another down, after the close of the ISO HA market. To the extent that
resources can be flexibly scheduled (certainly generators, and also contracts with
existing rights flexibility), this substitution of one resource for another can lead to
efficiencies that are allowed by the ISO as long as the MSS stays in total within it
deviation band.
This Appendix addresses two questions. First, how will the MSS operating
entities decide which resources to use to follow load? Second, what is the proper
accounting and settlement if it should happen that one operating entity's
resource is used to follow the other's load? The following proposals have come
out of several discussions with Santa Clara and among NCPA staff.
For the purpose of this discussion, the two MSS operating entities are considered
to be Santa Clara and NCPA Pool, although these concepts could be extended to
any number of non -Pool MSS participants. The order of settlement is to first
determine the ISO uninstructed energy that belongs to NCPA Pool and SNCL,
and any power that flowed between them, and then based on those results to
settle ISO charges within the MSS.
Real-time MSS Decisions
Once the real-time hour begins, we envision that the NCPA-SC dispatcher will
decide which units to move to follow load. The dispatcher's real-time decisions
would be based on rules developed in advance by the operating entities (COG)
based on economic and other factors. While nothing in this discussion is meant
to preclude consultation by the dispatcher with the operating entities, even in
real time, the severe time constraints of the 10 -minute market and workload
dictate that the dispatcher must have the authority to move units quickly to
minimize the uninstructed energy requirement of the MSS as a whole, without
such consultation.
Pre -scheduling Decisions
We have already designed our scheduling program to allow each operating
entity to independently schedule their share of the jointly owned units separately
for energy and the provision of ancillary services. Each operating entity may use
their units as they wish but within their ownership -share capacity. Schedules
can be adjusted in the ISO's HA market, currently 3 -hours prior to the real-time
hour. Each operating entity can decide to leave a portion of their ownership
share available for following load up in real-time. Schedule changes with the
ISO after the close of the HA market are not possible, and the settlement for
uninstructed energy for each unit is the difference between the recorded data
and the HA schedules. By leaving a portion of the unit available, should the
dispatcher move the unit up to follow load, the positive imbalance that results on
the unit would be offset by the negative imbalance of the load, and the net result
is to reduce our net take of uninstructed energy from the ISO. However, this
netting to zero of the uninstructed energy is for the MSS as a whole, not for each
operating entity separately.
To allow each operating entity to utilize the available capacity of their own units,
or their share of the jointly owned units, we propose to create in NCPA's
scheduling system new schedules that represent a change to the ISO hour -ahead
market energy schedule for a particular unit. We are calling these new schedules
the "Final" market energy schedules for the unit. These schedules cannot be sent
to the ISO. They are for internal use only. They are limited in the positive
direction by each operating entity's available capacity taking into consideration
that we cannot schedule into any reserve capacity sold to the ISO. They may
reduce an operating entity's market energy schedule in the negative direction to
zero.
For a jointly owned resource, the final schedules will be aggregated by unit on
their way to the SCADA system; so the dispatcher will get a final market energy
schedule for the unit as a whole. The dispatcher will see the final schedule as the
target for the unit in each interval (plus any ISO A/S instructions). The
dispatcher should only deviate from the final schedule if the load moves in an
unexpected way. The fact that the final schedule is different from the ISO HA
schedule means that at settlement time we will be taking or selling extra
uninstructed energy because the unit will not be run in accordance with the ISO
HA schedule, but as long as the dispatcher is following load, there will be
offsetting uninstructed energy on the load side.
Allocation of Uninstructed Energy to Each Load and Resource
ISO uninstructed energy is separately calculated for each load and each unit, but
then settled with the ISO on a net basis. Even though most of NCPA Pool load
(except Lompoc and possibly Roseville) and SNCL load will be aggregated at the
same point, NCP1, our settlements software automatically assigns uninstructed
energy to NCPA Pool and SNCL based on their separate load schedules and
recorded data. Therefore, the assignment of uninstructed energy to NCPA Pool
and SNCL load is straightforward. Assignment of uninstructed energy to
resources that are not jointly owned is also straightforward.
Assignment of uninstructed energy to each unit that is jointly owned is more
complex, and is done based on each operating entity's ownership rights to the
unit and their final schedules. Each operating entity can schedule part of the unit
to meet load (called market energy schedules), part of the unit can be scheduled
to supply or self -provide ancillary services or supplemental energy and therefore
the unit may be instructed by the ISO, and part of the unit can be left available
for following load up. (Currently we assign uninstructed energy to the joint
operating entities following an allocation basis that is based not on load
following, but on the principal that units are expected to follow their ISO hour -
ahead schedules, and will move up or down only in response to the price of
imbalance energy. Therefore currently, the primary allocation basis for positive
uninstructed energy is unit available capacity.) Going forward we must revise
the allocation scheme to recognize that load following is the reason for moving
units away from the ISO HA schedules, therefore the primary allocation basis for
uninstructed energy are the final market energy schedules, limited by available
capacity.
The enclosed spreadsheet called UnitEnergyAllocation attempts to illustrate the
allocation of uninstructed energy for a single unit. Imbalance energy is
subdivided into instructed energy (IE) and uninstructed energy (UE). IE is
allocated directly to the operating entities based on their a/ s or supplemental
bids. UE is allocated to the final energy schedules, limited by operating entity by
available capacity. Excess UE is allocated first to the operating entity with
available capacity. Excess UE above the project total capacity (actual meter data
can come in above the unit pMax) is allocated on project ownership share.
Final Uninstructed Energy Settlement Between NCPA Pool & SNCL
Once the above process has determined which operating entities have
uninstructed energy, we believe that we need to account for those times when
one operating entity's resource has been used to meet the other's load.
Hopefully because of the final schedule mechanism described above the amount
of this cross -delivery will be minimized. However, some cross -delivery will
occur, particularly because of real-time decisions that will be made to run units
without particular regard to which load is moving, and even more if the
operating entities jointly decide to run a particular unit to follow load because,
for example, it is cheaper, regardless of whose load is being followed.
Tracking this type of cross -delivery is particularly simple. The ISO requires that
HA schedules be in balance, and NCPA-SC requires that each of our internal
accounts have balanced HA schedules. Therefore, it is only necessary to look at
the allocation of uninstructed energy (ISO Settlements Charge Code 407) to each
operating entity to determine if the UE on generation netted with UE on load is
in balance or not.
The net uninstructed energy with the ISO represents the net short or long
position of the MSS as a whole. If either operating entity is surplus when the
MSS as a whole is surplus, then the one that is surplus is selling to the ISO. If
either entity is deficit when the MSS as a whole is taking imbalance energy, then
the one that is deficit is buying from the ISO. The attached spreadsheet called
MSS&PoolBilling demonstrates this arithmetic. These purchases and sales with
the ISO are at ISO imbalance price. As the spreadsheet shows, once the ISO
imbalance energy has been assigned, the entities are in balance as a whole, but
one may be selling to the other. The question then becomes how shall we settle
for this sale between the operating entities? Notice also that we have not yet
identified which resource made the sale, just that one entity sold to the other.
From a process and accounting point of view, the simplest method of settling for
the sale between the operating entities is to establish an appropriate price for the
energy and do a financial settlement for the energy in each period. It is probably
not appropriate to use the ISO imbalance price because the whole idea is to stay
out of the ISO imbalance energy market as much as possible. Pool MCP is
available as a settlement price. Another theory would be to use the cost of the
highest -cost resource actually in use each hour by the operating entity that is
excess, since that is the resource that would have been reduced in real-time had
we not been load following for each -other's load. A new computer program will
do the tracking of the uninstructed energy between the operating entities, once
the final principles are nailed down.
Automated Tracking of the Energy For Each Unit And Each Operating Entity
FA3.03
So far the only unit that has an automated process accounting for its fuel usage
and entitlement is the Collierville Hydro project. FA3.03 is the automated
water -share program that runs in real-time. Assignment of fuel and other
variable costs for the other units is done manually each month, based primarily
on ownership share. To the extent that a sale of power between the operating
entities is determined to be from the hydro project, then adjusting the water
shares to reflect the ultimate consumer of the power is relatively easy.
The FA3.03 water share program runs on the SCADA system in real-time, and
allocates the water between SNCL and Pool each interval (currently half-hourly,
but under ISO protocols this will be hourly). We have recently modified the
FA3.03 computer program to get access to the energy schedules from Aces, in
preparation for our scheduling with the ISO. We will now have to modify it to
read the new final schedules from Aces, and we have yet to modify it to read the
ISO instructions. Basically, the logic of FA3.03 must be made to duplicate the
uninstructed energy logic in the settlements software so that the water shares
between the operating entities are allocated on the same basis as the energy
credit that each receives. Further enhancements to the FA3.03 program will be to
take into account the proper ramping of the units that the ISO expects, and also
the hourly loss -factors (GMM's), both of which are already included in the Aces
energy settlements calculation.
Combustion Turbines
A protocol exists to track the energy and fuel used and allocates to the operating
entities for the simple cycle CT's. Currently this is kept up manually. It might be
possible to adapt this protocol to handle the transactions described here, and this
could be automated, including an hour -by -hour calculation of fuel used based on
unit load and heat rate.
MSS Billing Principles
Before we can run the MSS bill, we must make a sequence of calculations using
the meter data of the cities, to determine that portion of the meter data that
corresponds to the part of our member's recorded load that is scheduled with the
ISO, and that part that was scheduled with PG&E for Western 2948A power.
Meter Data Calculations
The first calculations using meter data has to do with adjustment for losses and
aggregation of meter data following the ISO's approved logical meter
calculations. We must add internal member generation back in to recorded city
gate load. We must apply gmm's to the recorded generation data to adjust to the
ISO grid. We must separate out the recorded generation data that is used to serve
load, as opposed to responding to ISO instructions.
Special treatment is required for Graeagle. We will not schedule for Graeagle
with the ISO because it is too small, and because we have no control over its
output. The ISO will consider Graeagle to be an offset to Plumas load. Because
its output is not owned by Plumas, its will also be added in to Plumas load in
MSS Billing, and MSS Billing will treat it as a separately owned resource.
Allocations of Western 2948A Power
Western 2948A Power will be scheduled with PG&E, not the ISO. We will
schedule 2948A power at the same level of aggregation that we will schedule the
rest of our load with the ISO, namely, by demand zones NCP1 and NCP2, and
Roseville separate (so PG&E can keep Roseville 2948A deliveries off the ISO
grid).
The current logic that we use to allocate 2948A power to the cities will be mostly
preserved. The one difference is that since Lompoc is in a separate zone, and
their Western deliveries must be separately scheduled with PG&E, Lompoc
Western 2948A delivery will be predetermined by their schedules. Western
power within NCP1 will be allocated in the same way the Western power is
allocated today to coincident IA load.
This is the second step in adjusting recorded city load data to produce the
recorded data that represents the portion of our loads that are scheduled with the
ISO.
Pre-processingto o Adjust for Deliveries to/from SNCL and ISO
As was described above, prior to doing any MSS allocations, we already
determined what power was delivered between SNCL and NCPA Pool. Also, as
was stated above, that delivery needs to be settled separately at an appropriate
price. Sales to SNCL are allocated to the resources under the philosophy that the
resources are generating extra to satisfy SNCL. Purchases from SNCL are
allocated to the loads under the philosophy that the loads must buy from SNCL
because there are insufficient resources within the Pool to satisfy the full need.
Now in the MSS Billing process we need to allocate to the MSS operating entites
and take off the top, as an adjustment to the recorded data, any power that might
have flowed between the Pool and Santa Clara, and any actual net imbalance
energy with the ISO. Page 2 of the spreadsheet MSSPoolBilling illustrates these
concepts.
ISO Generation Charges and Revenues Except Energy
All ISO charges and revenues associated with generation, including revenues for
the provision of ancillary services including self -provision, will be allocated
directly to the project owners, as is presently done. The allocation of these
revenues between NCPA Pool, Santa Clara and TID is done based on individual
operating entity schedules including ancillary services or supplemental bids, the
unit capacity schedules for the entities, and project share.
One issue about charges and revenues associated with generation is the
settlement of self -provided a/s. Self -provided a/s as it is done in the ISO world
is not what you would expect. The settlement for self -provision is treated
essentially the same as if we had bid to sell Project a/s to the ISO, and the
generator receives a credit
ISO Demand -based Charges Except Energy
With regard to ISO load based charges to MSS operating entities, most ISO
charges and revenues are allocated within the MSS based on the sum of recorded
load and exports, by zone (NP15 and ZP26). Some ISO charges and revenues
that are specifically mentioned next are allocated within the MSS on a basis other
than recorded load and exports. (One exception to this may be the special
treatment for Roseville that may be arranged because they are directly connected
to the Western transmission grid.)
ISO Import -Export Charges/ Revenues
Members individually subscribe to imports and exports in varying participating
percentages, recorded in the Trade Manager system. Therefore, import -export -
related ISO charges and revenues should be allocated to those members who
participate in each individual deal. The following is a current list of import-
export -related charges/revenues:
• 0407 Import and export deviation (a subset of all 040Ts),
charged as part of the energy settlement, described above
• 0256 HA Interzonal Congestion Debit to SC's
• 0521 Control Area Services Charge due to Exports GMC
• 0522 Interzonal Scheduling GMC on NFU path use
• 0203, 0253 Interzonal Congestion for NFU transmission at tie -
points
0382, 0383 Wheeling (exports only)
ISO Internal Inter -zonal coneestion charees/revenues
Inter -zonal congestion charges across internal paths, such as Path 15, must be
allocated to those members who use the path. Thus, the portion of 0203 and 0253
Interzonal Congestion that is due to using internal paths will be allocated to
those members to the extent they cause the congestion charge or the counter -flow
revenue across each path. Members who use internal interzonal paths will
accrue their portion of 0522 Interzonal Scheduling GMC allocated to internal
paths. Currently this primarily affects Lompoc, which is in zone ZP26. .
Wheeling
Wheeling is the charge for the use of the ISO grid for MSS load (non -PTO
wheeling) and NFU exports from the ISO Grid. This charge is not part of the
ISO's normal automated settlements, primarily because the ISO can not identify,
in all cases, what part of a load is satisfied by deliveries using ISO transmission,
and what part is not.
The ISO requires each SC to do this calculation at the end of each month and
submit the calculation to them. When we calculate the use of ISO transmission
that met our member loads, we will take appropriate credit in our calculation for
power that is delivered over CVP transmission direct to Roseville from COT
(delivered through Tracy). PG&E will continue to honor their obligations under
2948A, which provides for power delivered to city -gate, including transmission.
Our calculation of wheeling costs will not include that part of our load.
Regional and Zonal Allocation and Price Differences
Some ISO charges and revenues are allocated to SC's on a regional or zonal basis,
primarily to recognize the effect of congestion between the zones. Even when
charges are allocated on a regional basis, which means those zones between
which there is no congestion, the charges are presented to NCPA-SC on a zonal
basis. Such charges or revenues have rates that can differ between the zones.
The following is a list of current ISO charges and revenues that are allocated to
NCPA on a zonal basis:
Uninstructed Energy - CT 0407
Ancillary Services Obligation Costs - CT 0111, 0112, 0114, 0115 and 0116
Intra -zonal Congestion - CT 0452
Unaccounted For Energy - CT 0406
Distribution of Preempted Reserve 1061, 1062, 1064, 1065, 1066
Energy Exchange Program Costs - CT 1487
Interzonal Congestion - CT 0203, 0253
Charge type 0256, SC Charge for NFU transmission use when a line is curtailed
between the DA and HA markets, is unique in that it is a charge that is allocated
on a branch group basis, which basically means to the NFU users of a
transmission path. Should we incur this charge for Path 15, we will allocate this
to the users of Path 15, which would be Lompoc if we have no other users of Path
15. If we incur this charge for the NFU use of an external tie, we will allocate this
to the users of that path, based on the individual Pool member's participation
percentage in the NFU imports or exports that were involved.
ISO Prior Period Adjustments
One of the most troublesome issues are the ISO's prior period adjustments. From
time to time the ISO produces prior period adjustments for periods as much as a
year or more in arrears. The format of the ISO's prior period adjustment billing
files is inconsistent with regard to the billing interval (sometimes on a 10 -minute
basis, sometimes on an hourly basis, sometimes on a monthly basis) and format
required in their own specifications. Because of these inconsistencies, we have
not been able to automate the processing of the ISO's prior period adjustments
and a separate and accurate validation and allocation becomes problematic. We
review each billing statement from the ISO on a case-by-case basis, and allocate
prior period adjustments in an appropriate way, normally monthly and based on
the allocation of the original charge or revenue. The timing and presentation of
the prior period adjustments to the Pool members will depend in large part on
when and how the adjustments come to us from the ISO.
APPENDIX E
Unit Energy Allocation Page 1
Energy Allocation For A Unit to its MSS Owners
Allocation basis of imbalance energy (for instructed energy (IE) and uninstructed energy (UE)
Positive UE allocated to energy schedules, limited by available capacity
Excess positive UE allocated first to owner with available capacity, limited by available capacity
Excess UE above project total capacity allocated by ownership share
Negative UE allocated to energy schedules
IE allocated to bids
Note: The blue cells below are the final results
Consider a hypothetical plant of 200 mw
Two owners Own 1 % 0.50 Own 2 %
ISO Instruction 10
Meter Data 105
Owner 1.00
ISO HA Energy Schedule
30.00
ISO A/S Bid
10.00
ISO A/S Energy (IE)
4.00
ISO No Pay
0.00
ISO Available Capacity
60.00
ISO UE 25
0.50
2.00
40.00
15.00
6.00
0.00
45.00 Note: We will not allow an owners capacity to go negative
NCPA Final Schedule
30.00
ISO AIS Bid
10.00
ISO AIS Energy (IE)
4.00
ISO No Pay
0.00
Final Available Capacity
60.00
UE After Final Schedules
0
0.00
65.00
15.00
6.00
0.00
20.00 Note: We will not allow an owners capacity to go negative
APPENDIX E
Unit Energy Allocation Page 2
How Energy and Imbalance Energy Would be Allocated Based on the Original ISO HA Schedules
ISO HA Schedule 30.00 40.00
ISO AIS Energy 4.00 6.00
Alloc of ISO UE:
Alloc 1 to energy schedules
10.71
14.29
Unallocated
Alloc 1 capped by AC
10.71
14.29 UE
0.00
Revised AC
49.29
30.71
Alloc 2 to available capacity
0.00
0.00
Alloc 2 capped by AC
0.00
0.00 UE
0.00
Alloc 3 to ownership share
0.00
0.00 UE
0.00
Total Energy Towards Load
40.71
54.29
Control Balance to Meter
No Pay Penalty Basis
0.00
0.00
Final Energy and Imbalance Energy Allocation Based on Final NCPA
Schedules
ISO HA Schedule
30.00
40.00
Incremental Final Schedule
0.00
25.00 UE
ISO AIS Energy
4.00
6.00
Alloc of UE After Final
Schedules:
Alloc 1 to energy schedules
0.00
0.00
Unallocated
Alloc 1 capped by AC
0.00
0.00 UE
0.00
N OX
! Revised AC 60.00 20.00
Alloc 2 to available capacity 0.00 0.00
Alloc 2 capped by AC 0.00 0.00 UE 0.00
Alloc 3 to ownership share 0.00 0.00 UE 0.00
Total Energy Towards Load 30.00 65.00 Control Balance to Meter 0.00
No Pay Penalty Basis 0.00 0.00
Note: The above rows labeled as UE are those that represent an allocation basis of actual UE from the ISO
Note: This spreadsheet does not include bidding to provide supplemental energy. Supp energy instructions are allocated to the bids just like
ancillary services, but the supp bid does not reduce the owner's available capacity. If the owner is already producing imbalance energy into
that capacity that covers the supp bid & the ISO instructs the unit for supp, the owner would simply get less energy from the unit, and some other unit
would have to be ramped up to cover the owner's load.
This spreadsheet also does not include unit ramping, or loss factors.
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Pos Net UE Means Resources > Loads
Neg Net UE Means Loads > Resources
Allocate ISO UE to the entities as follows:
If Net ISO UE is positive, and only one entity has net positive UE, allocate all to that entity
If Net ISO UE is positive, and both entities have net positive UE, allocate to each pro rata
If NET ISO UE is negative, and only one entity has net negative UE, allocate all to that entity
If NET ISO UE is negative, and both entities have net negative UE, allocate to each pro rata
Results (+ Power Sold, - Power Bought):
Net NCPA UE 8 Net SNCL UE -1
Sold/Bought With ISO 7 Sold/Bought With ISO 0
Sold/Bought With SNCL 1 Sold/Bought With SNCL -1
APPENDIX E
MSS Billing Page 2
NCPA Pool Settlement
Pool settlement will be done based on meter data, after adjustment for the power sold/bought with ISO and SNCL
NCPA
Meter To ISO To SNCL Pool Billing Basis
R1 66 2.98 0.43 62.59
R2 39 1.76 0.25 36.99
R3 50 2.26 0.32 47.42
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APPENDIX F
CAISO SECURITY DEPOSIT
NORTHERN CALIFORNIA POWER AGENCY
ESTIMATED SCHEDULING COORDINATION ISO NCPA BALANCING ACCOUNT
UPDATED AS OF JUNE 18, 2002
PLAN: When PG&E Interconnection Agreement ends, transfer I.A. Security Deposit to NCPA SC.Balancing
Account.
!red by ISO --Place in NCPA/ISO Escrow Account GMC Portion $ 734,671
1 by NCPA (More by ISO if L -T Bond Rating < A-) Balancing Acct Held by NCPA 11,044,004
Total $11.778.675 1
RISK: PG&E does not release I.A. Security Deposit at termination date of I.A. until all liabilities thereunder no
longer exist. If this happens, at least some funding of SC would have to come from members.
ESTIMATED ANNUAL (12 Mos.)
NCPA BAL.
FUNDED BY
ADD -L OR
ISO CHARGES
ACCOUNT
IA SECURITY
(EXCESS)
Participant
%
$
31.7001%
Note A
FUNDING
Alameda
7.7498%
$ 2,699,954 $
747,260
$ 881,322
$ (134,062)
Biggs
0.3461%
120,576
41,778
11,850
29,928
Gridley
0.3460%
120,560
54,501
20,620
33,881
Healdsburg
1.6499%
574,797
157,270
191,795
(34,525)
—
Lodi
11.0178%
3,838,483
1,237,662
536,651
701,011
Lompoc
3.7880%
1,319,718
351,373
192,161
159,212
Palo Alto
2.8894%
1,006,639
457,424
321,467
135,957
Plumas-Sierra
0.7275%
253,458
97,248
42,520
54,728
Roseville
13.1915%
4,595,779
1,642,005
411,518
1,230,487
Santa Clara
56.1350%
19,556,921
6,016,371
-
6,016,371
2.1590% 752,178 241,112 293,096 (51,
100.0000% $ 34,839,062 $ 11,044,004 $ 2,903,000 $8,141
Note C Note B
Note A: NCPA Transmission Project funded the I.A. Security Deposit.
Note B: Stated value of investment maturing October 2, 2002.
Note C: Est'd based on highest three (3) months' ISO costs.
NORTHERN CALIFORNIA POWER AGENCY
"FORECAST OF SCHEDULING COORDINATION FUNDING REQUIREMENTS
UPDATED JUNE 18, 2002
TE ESTIMATED BILL (for 1,2 & 5 above) INCLUDED WITH ESTIMATED MONTHLY POWER BILL PRIOR TO TRADE
ZONAL ESTIMATED BILL SENT APPROX. 15 DAYS AFTER END OF THE TRADE MONTH (for 3 & 4 above and imbalance
r and congestion).
PAYS PRELIMINARY ISO INVOICE 43 BUSINESS DAYS AFTER THE TRADE MONTH.
PAYS FINAL ISO INVOICE 56 BUSINESS DAYS AFTER CLOSE OF THE TRADE MONTH.
ISSUES TRADE MONTH FINAL SETTLEMENT (subject to future ISO prior period adjustments) APPROX. 5 DAYS LATER.
Average
Estimated
TYPE OF SCHEDULING COORDINATION COST
Monthly
Annual"
1. GRID MANAGEMENT CHARGE
$244,890
$2,938,683
2. ISO WHEELING
1,685,034
20,220,408
3. ANCILLARY SERVICES PURCHASED
428,235
5,138,821
4. SPIN & NON -SPIN SELF PROVISION CREDIT
(165,610)
(1,987,316)
5. PG&E RELIABILITY SERVICE CHARGE
710,706
8,528,466
TOTAL AVERAGE MONTHLY BILL
$2,903,255
$34,839,062
TE ESTIMATED BILL (for 1,2 & 5 above) INCLUDED WITH ESTIMATED MONTHLY POWER BILL PRIOR TO TRADE
ZONAL ESTIMATED BILL SENT APPROX. 15 DAYS AFTER END OF THE TRADE MONTH (for 3 & 4 above and imbalance
r and congestion).
PAYS PRELIMINARY ISO INVOICE 43 BUSINESS DAYS AFTER THE TRADE MONTH.
PAYS FINAL ISO INVOICE 56 BUSINESS DAYS AFTER CLOSE OF THE TRADE MONTH.
ISSUES TRADE MONTH FINAL SETTLEMENT (subject to future ISO prior period adjustments) APPROX. 5 DAYS LATER.
Alameda
Biggs
Gridley
Healdsburg
Lodi
Lompoc
Palo Alto
Plumas-Sierra
Roseville
Santa Clara
Turlock
Ukiah
NORTHERN CALIFORNIA POWER AGENCY
SCHEDULING COORDINATION SECURITY DEPOSIT
ORIGINAL
TRANSMISSION
PROJECT
PERCENTAGE
SHARE
30.3590% $
0.4082%
0.7103%
6.6068%
18.4861 %
6.6194%
11.0736%
1.4647%
14.1756%
POOL
SHARE
881,322
11,850
20,620
191,795
536,651
192,161
321,467
42,520
411,518
10.0963% 293,096
100.0000% $ 2,903,000
INTERCONNECTION AGREEMENT
BETWEEN
PACIFIC GAS AND ELECTRIC COMPANY
AND
THE NORTHERN CALIFORNIA POWER AGENCY
AND
CITY OF ALAMEDA,
CITY OF BIGGS,
CITY OF GRIDLEY,
CITY OF HEALDSBURG,
CITY OF LODI,
CITY OF LOMPOC,
CITY OF PALO ALTO,
CITY OF UKIAH,
AND
PLUMAS-SIERRA RURAL ELECTRIC COOPERATIVE
TABLE OF CONTENTS
PREAMBLE ..................................................... 1
RECITALS..................................................... 2
3 AGREEMENT .................................................. 4
4 DEFINITIONS ................................................ 4
4.1
Agreement .........................................
4
4.2
Ancillary Services ................................
4
4.3
Business Day ......................................
4
4.4
Control Area ......................................
4
4.5
Control Area Arrangement ..........................
5
4.6
Control Area Operator .............................
5
4.7
Control Center ....................................
5
4.8
Cost ..............................................
5
4.9
CPUC ..............................................
6
4.10
Demand ............................................
6
4.11
Effective Date ....................................
6
4.12
Electric System ...................................
6
4.13
Emergency or System Emergency .....................
7
4.14
Engineering and Operation Committee ...............
7
4.15
Existing Contracts ................................
7
4.16
Facility Study ....................................
8
4.17
FERC ..............................................
8
4.18
FPA ...............................................
8
4.19
Good Utility Practice .............................
8
4.20
Interconnection Capacity ..........................
8
4.21
Interconnection Facilities ........................
8
4.22
Independent System Operator (ISO) .................
8
4.23
ISO Controlled Grid ...............................
9
4.24
ISO Tariff ........................................
9
4.25
Participating TO ..................................
9
4.26
PG&E Transmission Owner (TO) Tariff ...............
9
4.27
PG&E Wholesale Distribution (WD)Tariff ............
9
4.28
Points Of Interconnection ........................
10
4.29
Remote Telemetry Unit (RTU) ......................
10
4.30
Responsible Meter Party ..........................
10
4.31
Scheduling Coordinator ...........................
10
4.32
Service Area .....................................
10
4.33
System Impact Study ..............................
11
4.34
System Reinforcements ............................
11
4.35
Third Party ......................................
11
4.36
Transfer Capability ..............................
11
4.37
Transmission Arrangement .........................
12
4.38
Transmission Operations Center ...................
12
i
4.39 Transmission Owner (TO) .......................... 12
4.40 Uncontrollable Force ............................. 12
4.41 Upgrade Facility ................................. 12
5 SCOPE ..................................................... 12
5.1 Interconnected Operations .......................... 12
5.2 Effective Date ...................................... 14
5.3 Termination ........................................ 15
6 POWER AND TRANSMISSION ARRANGEMENTS ....................... 16
6.1 Limitation on Parties Obligation ................. 16
6.2 Transmission Arrangements ........................ 16
6.3 Control Area Operations .......................... 17
7 INTERCONNECTIONS .......................................... 18
7.1 Interconnection Capacity ......................... 18
7.2 Establishing or Modifying Point(s) of
Interconnection .................................. 18
7.2.1 New Interconnection Facilities and
Interconnection Facilities Upgrades .............. 19
7.2.2 Construction Plan and Agreement ................... 20
7.3 NCPA Option As To Construction ................... 21
8 SYSTEM PLANNING COORDINATION ............................ 22
8.1 Planning Process .................................... 22
8.2 System Reinforcements ............................... 23
9 OPERATING PROVISIONS ....................................
23
9.1
eneral.............................................
General.... '**********""*'"*** ... "
23
9.2
Power Delivery and Quality Standard .................
24
9.3
Coordination Of Operations ..........................
24
9.4
Relationship To Control Area Operations .............
25
9.5
Separate Control Area ...............................
25
9.6
Reporting Significant Events ........................
25
9.7
Operation Pursuant To Good Utility Practice.........
26
9.8
Engineering And Operating Committee.................27
9.8.1 E&O Committee Operating Procedures........
27
9.8.2 E&O Committee Expenses ....................
28
9.8.3 E&O Committee Meetings ....................
29
9.8.4 E&O Committee Guidelines ..................
30
9.8.5 E&O Committee Authority ...................
32
9.8.6 Settlement of Disputes and
Arbitration . ..............................
32
9.9
Protective Devices .................................
32
9.10
Requirements for Generators Operated by NCPA
that are Connected to PG&E Electric System .......
33
9.11
Continuity Of Service .............................
33
9.11.1 Operation Actions To Maintain
Continuity ................................
33
9.11.2 Unscheduled Interruptions ..................
33
ii
iii
9.11.3 Scheduled Interruptions ...................
34
9.11.4 Interruption By Protective Devices........
35
9.11.5 Jeopardy..................................
35
9.12 Operating Records .................................
37
9.13 Mutual Obligation Communications Protocol ........
37
10
SIGNIFICANT REGULATORY OR OPERATIONAL CHANGE............
38
10.1 Significant Regulatory Change ....................
38
10.2 Significant Operational Change ...................
38
10.3 Change in Functions or Scope .....................
39
10.4 Notification.....................................
39
10.5 Amendment of Agreement ...........................
40
10.6 Studies of Significant Operational Change ........
41
10.7 Mitigation And Costs .............................
42
10.8 Failure To Notify Of Significant Operational
Changes..........................................
44
11
INSTALLATION AND ACCESS .................................
44
12
METERING................................................
45
12.1 Delivery Meters..................................
45
12.2 Requirements For Meters And Meter
Maintenance......................................
46
12.3 NCPA's Obligation To Provide Meter Data To
PG&E.............................................
46
12.4 Consequences of Failing to Provide Meter
Data in a Timely Fashion .........................
47
13
BILLING AND PAYMENT.....................................
47
14
APPENDICES INCLUDED.....................................
48
15
ACCOUNTING..............................................
48
15.1 Accounting Procedures ............................
48
15.2 Audit Rights
.....................................
48
16
ADVERSE DETERMINATION OR EXPANSION OF OBLIGATIONS.......
49
16.1 Adverse Determination ............................49
16.2 Expansion Of Obligations .........................
50
16.3 Renegotiations.....................................
50
17
ASSIGNMENT...............................................
51
17.1 Consent Required...................................
51
17.2 Assignee's Continuing Obligation...................
52
18.
CAPTIONS................................................
52
19.
CONSTRUCTION OF THE AGREEMENT ...........................
52
20.
CONTROL AND OWNERSHIP OF FACILITIES.....................
53
iii
21. COOPERATION AND RIGHT OF ACCESS AND INSPECTION.......... 53
22 DEFAULT .................................................. 54
22.1 Termination For Default ............................ 54
22.2 Other Remedies For Default ........................ 54
23 DISPUTE RESOLUTION....................................... 55
24 Governing Law........................................... 55
25 INDEMNITY............................................... 55
25.1 Definitions........................................ 55
25.1.1Claimant......................................... 55
25.2 Indemnity Duty................................... 56
26 JUDGMENTS AND DETERMINATIONS ............................ 57
27 LIABILITY............................................... 58
27.1 To Third Parties................................. 58
27.2 Between The Parties .............................. 58
27.3 Protection Of A Party's Own Facilities ........... 58
27.4 Liability For Interruptions ...................... 59
28 NO DEDICATION OF FACILITIES ............................. 59
29 NO OBLIGATION TO OFFER SAME SERVICE TO OTHERS........... 59
30 NO PRECEDENT............................................ 60
31 NO TRANSMISSION, DISTRIBUTION, POWER, ENERGY SALES OR
ANCILLARY SERVICES PROVIDED ............................. 60
32 NOTICES................................................. 60
32.1 Written Notices.................................. 60
32.2 Changes Of Notice Recipient ...................... 61
32.3 Routine Notices.................................. 62
32.4 Reliance On Notice ............................... 62
33 RESERVATION OF RIGHTS................................... 62
34 RESPONSIBILITY FOR PAYMENTS ............................. 63
35 RULES AND REGULATIONS................................... 64
36 SEVERABILITY............................................ 64
37 CONTINUING RIGHTS OF NCPA UPON TERMINATION.............. 65
38 RIGHTS OF PG&E UPON TERMINATION ......................... 66
39 UNCONTROLLABLE FORCES................................... 66
iv
40 WAIVER OF RIGHTS ........................................ 66
41 ENTIRE AGREEMENT; AMENDMENTS ............................ 67
42 NO THIRD PARTY RIGHTS OR OBLIGATION ..................... 67
43 WARRANTY OF AUTHORITY ................................... 67
44 EXECUTION ............................................... 68
APPENDIX A - POINT{S} OF INTERCONNECTION
APPENDIX B - DISPUTE RESOLUTION AND ARBITRATION
APPENDIX C - UPGRADE FACILITIES
APPENDIX D - BILLING AND PAYMENT
APPENDIX E - OPERATIONAL COORDINATION
v
INTERCONNECTION AGREEMENT
BETWEEN
PACIFIC GAS AND ELECTRIC COMPANY
AND
THE NORTHERN CALIFORNIA POWER AGENCY
AND
CITY OF ALAMEDA,
CITY OF BIGGS,
CITY OF GRIDLEY,
CITY OF HEALDSBURG,
CITY OF LODI,
CITY OF LOMPOC,
CITY OF PALO ALTO,
CITY OF UKIAH,
AND
PLUMAS-SIERRA RURAL ELECTRIC COOPERATIVE
PREAI4BLE
This Interconnection Agreement is made this 12 day of
July , 2002, by and between Pacific Gas and Electric
Company ("PG&E"), a corporation organized and existing under
the laws of the State of California, and the Northern
California Power Agency("NCPA"), a Joint Powers Agency of the
State of California, and the California Cities of Alameda,
Biggs, Gridley, Healdsburg, Lodi, Lompoc, Palo Alto, Ukiah,
and the Plumas-Sierra Rural Electric Cooperative, Inc.,
(hereinafter referred to collectively as "NCPA Member
Customers"), any or all of which are hereinafter referred to
individually as a "Party" and collectively as "the Parties."
RECITALS
2.1 Whereas, it is the policy of the Federal Energy
Regulatory Commission (FERC) that open and non-discriminatory
access to transmission be provided through transmission
systems comprising as large an area as possible under the
supervision and direction of an Independent System Operator or
a Regional Transmission Organization; and
2.2 Whereas, PG&E is a public utility providing both
wholesale and retail electric power and energy sales and
transmission and distribution services in northern and central
California and owns an extensive electric transmission system
within that area; and
2.3 Whereas, PG&E has transferred operational control of
its transmission system to the California Independent System
Operator (ISO) as part of the ISO Controlled Grid and has
filed a Transmission Owner Tariff (PG&E TO Tariff) as
accepted by FERC providing for access to transmission service
over PG&E's electric system under the administration of the
ISO; and
2.4 Whereas, PG&E is a Participating Transmission Owner
subject to the direction of the ISO in the operation of its
transmission system and provision of transmission access as
part of the ISO Controlled Grid pursuant to the terms of the
ISO Tariff and the PG&E TO Tariff; and
2
2.5 Whereas, NCPA is a public agency engaged in the
generation and transmission of electric power and energy and
created by a joint powers agreement dated July 19, 1968, as
amended, entered pursuant to Chapter 5, Division 7, Title 1 of
the California Government Code commencing with Section 6500;
and
2.6 Whereas, NCPA has entered, or intends to enter, into
certain agreements with the ISO including, but not limited to,
the NCPA MSS AGGREGATOR AGREEMENT to have electric power
delivered to it at each Point of Interconnection using
transmission service available to it;
2.7 Whereas, this Agreement is intended to provide for
the terms and conditions of interconnections between the
Electric Systems of the Parties from and after the termination
and replacement of the existing July 29, 1983 Interconnection
Agreement between them;
2.8 Whereas, the Parties agree to operate their
respective electric systems in accordance with Good Utility
Practice consistent with the requirements of this Agreement;
2.9 Whereas, the Parties intend to cooperate in the
operation of their respective Electric Systems to maximize
their mutual benefits under this Agreement.
3
3 AGREEMENT
NOW, therefore, in consideration of the mutual covenants
herein set forth, the Parties agree as follows:
4 DEFINITIONS
The following terms, when used in this Agreement with the
initial letters capitalized, other than proper names, whether
in the singular, plural or possessive, shall have the meanings
indicated below. Some terms are defined by reference to
definitions in the Master Definitions Supplement, included as
Appendix A to the ISO Tariff.
4.1 Agreement
This Interconnection Agreement between PG&E and
NCPA and its Appendices, as it may be amended.
4.2 Ancillary Services
As defined in the Master Definitions Supplement
to the ISO Tariff.
4.3 Business Day
As defined in the Master Definitions Supplement
to the ISO Tariff.
4.4 Control Area
As defined in the Master Definitions Supplement
to the ISO Tariff.
4
4.5 Control Area Arrangement
Arrangements, which may include an MSS or MSS
Aggregator Agreement as provided for in the ISO tariff or an
Operating Agreement substantially similar to a Metered
Subsystems Agreement between a Party and the Control Area
Operator in which the Party agrees to self provide or procure
the necessary resources and services and perform operations to
meet Control Area operating requirements and to maintain the
operating reliability and integrity of the Control Area's
electric power system in an economic manner consistent with
Good Utility Practice.
4.6 Control Area Operator
The entity that is responsible for operating a
Control Area. For purposes of this Agreement, the Control
Area Operator is the ISO or its successor.
4.7 Control Center
NCPA's electric operations control center that is
staffed at all times and is responsible for, among other
things, its electric system switching operations.
4.8 Cost
All just, reasonable, necessary and prudently
incurred expenses or capital expenditures, including but not
limited to those for operation, maintenance, engineering and
facilities studies, adverse impact identification, adverse
impact mitigation, contract modification, administrative and
5
general expenses, taxes, depreciation, and fees for
consultants, as determined in accordance with the FERC Uniform
System of Accounts as such may be amended or superseded from
time to time, and costs of capital. The appropriate
components of the Cost, as defined herein, shall be applied
for the particular transaction performed.
4.9 CPUC
The California Public Utilities Commission or its
regulatory successor.
4.10 Demand
As defined in the Master Definitions Supplement
to the ISO Tariff.
4.11 Effective Date
The date specified as the Effective Date of this
Agreement in Section 5.2 hereof.
4.12 Electric System
All properties and other assets, now or hereafter
existing, which are leased to, licensed to, owned by, or
controlled by a single person or entity, and used for or
directly associated with the generation, transmission,
transformation, distribution, purchase or sale of electric
power, including all additions, extensions, expansions, and
improvements thereto. To the extent a person or entity is not
the sole owner of an asset or property, only that person's or
that entity's ownership interest in such asset or property
shall be considered to be part of its Electric System. For
purposes of this Agreement, NCPA's Electric System shall
include only the facilities in northern and central California
which are used to serve the NCPA load.
4.13 Emergency or System Emergency
As defined in the Master Definitions Supplement
to the ISO Tariff.
4.14 Engineering and Operation Committee
A joint PG&E and NCPA committee established pursuant to
Section 9.
4.15 Existing Contracts
The contracts between the Parties in existence on
April 1, 1998 (including any contracts entered into pursuant
to such contracts)as may be amended in accordance with their
terms or by agreement between the parties thereto from time to
time or by order or requirement of FERC or any court having
jurisdiction, provided that any contract shall cease to be an
Existing Contract when its initially specified term ends,
unless extended by agreement of the parties thereto or when it
may be earlier terminated; and contracts between PG&E and the
Western Area Power Administration, and contracts between or
tariffs involving PG&E and the Transmission Agency of Northern
California, in which NCPA has a beneficial interest.
7
4.16 Facility Study
An engineering study to determine required
electric system modifications to accommodate a new Point of
Interconnection or a modification of an existing Point of
Interconnection, including the cost and scheduled completion
date for such modifications that will be required to provide
needed services.
4.17 FERC
The Federal Energy Regulatory Commission or its
regulatory successor.
4.18 FPA
The Federal Power Act as it may be amended.
4.19 Good Utility Practice
As defined in the Master Definitions Supplement
to the ISO Tariff
4.20 Interconnection Capacity
The rated maximum capability of Interconnection
Facilities, for power transfers at Points of Interconnection.
4.21 Interconnection Facilities
Electric facilities which establish or modify
Points of Interconnection where PG&E`s Electric System is
connected to the Electric System of NCPA or a Third Party.
4.22 Independent System Operator (ISO)
The California Independent System Operator
Corporation (ISO)or its successor that operates the ISO
A
Control Area and controls the transmission facilities of all
Participating TOs and dispatches certain generating units and
loads.
4.23 ISO Controlled Grid
The system of transmission lines and associated
facilities of all Participating TOs that have been transferred
to the ISO's operational control.
4.24 ISO Tariff
The currently effective California Independent
System Operator Tariff, on file at FERC as FERC Electric
Tariff First Revised Vol. No. 1, as it may be modified or
superseded from time to time.
4.25 Participating TO
As defined in the Master Definitions Supplement
to the ISO Tariff.
4.26 PG&E Transmission Owner (TO) Tariff
PG&E's Transmission Owner Tariff on file with the
FERC as Electric Tariff Volume 5, No. 6 Revised, as it may be
modified from time to time.
4.27 PG&E Wholesale Distribution (WD)Tariff
PG&E's Wholesale Distribution Tariff on file with
the FERC as original Volume 4, as it may be modified from time
to time.
4
4.28 Points Of Interconnection
The physical connections of PG&E's transmission
or distribution lines with NCPA 's Electric System as
specified in Appendix A hereto, as that Appendix may be
modified from time to time.
4.29 Remote Telemetry Unit (RTU)
A device that relays real-time data: kW, War,
voltage, breaker status, etc., to central points designated by
the Parties, generally a control room, for monitoring
purposes.
4.30 Responsible Meter Party
A Party having the responsibility for providing,
installing, owning, operating, testing, servicing and
maintaining meters and associated recording or telemetering
equipment at each Point of Interconnection. Unless otherwise
specified herein, NCPA shall be the Responsible Meter Party
under this Agreement.
4.31 Scheduling Coordinator
As defined in the Master Definitions Supplement
to the ISO Tariff.
4.32 Service Area
That area within the geographic boundaries of the
areas electrically served at retail, now or in the future, by
PG&E or by NCPA.
10
4.33 System Impact Study
An engineering study conducted by PG&E at NCPA's
request to determine System Reinforcements required on PG&E's
Electric System necessary to establish or modify a Point(s) of
Interconnection or to address a Significant Operational Change
pursuant to Section 10.
4.34 System Reinforcements
Reinforcements to PG&E's Electric System,
including but not limited to those identified by a System
Impact Study, necessary to establish or maintain the Transfer
Capability to a Point of Interconnection. System
Reinforcements may be required when a Point of Interconnection
is added or modified, when a Significant Operational Change
pursuant to Section 10 is proposed, or when necessary to serve
electric load reliably, or required by Good Utility Practice.
System Reinforcements are limited to facilities required on
PG&E's Electric System and ordinarily would not include
Interconnection Facilities required at the Point of
Interconnection.
4.35 Third Party
A person or entity other than PG&E or NCPA.
4.36 Transfer Capability
The measure of the capability of interconnected
Electric Systems to move or transfer power in a reliable
11
manner from one point to another over all transmission lines
between those points under specified system conditions.
4.37 Transmission Arrangement
An agreement or tariff, either the ISO Tariff or a
separate contract or tariff which enables NCPA to deliver
Power and energy to meet its electric power requirements
4.38 Transmission Operations Center
PG&E's operations center from which it directs
operations of its transmission system.
4.39 Transmission Owner (TO)
As defined in the Master Definitions Supplement
to the ISO Tariff.
4.40 Uncontrollable Force
As defined in the Master Definitions Supplement
to the ISO Tariff.
4.41 Upgrade Facility
A new or upgraded Interconnection Facility and/or
System Reinforcement constructed or installed pursuant to this
Agreement.
5 SCOPE
5.1 Interconnected Operations
This Agreement governs the interconnected and
coordinated operation of PG&E's Electric System, a portion of
which has been turned over to the operational control of the
12
ISO, and NCPA's Electric System. As of the date of this
Agreement, the ISO operates the Control Area in which the
Parties operate their respective Electric Systems. The Parties
agree that, during the term of this Agreement and unless
otherwise provided for by amendment of this Agreement, that
portion or those portions of the Parties' Electric Systems
that are interconnected shall be operated in parallel pursuant
to the terms and conditions of this Agreement and consistent
with Good Utility Practice and their respective Control Area
Arrangements. Each Party shall at all times to the maximum
extent practicable avoid causing any adverse impact on the
Other Party's Electric System.
Each Party shall at all times either operate its
own Control Area or operate within an established Control Area
consistent with its Control Area Arrangements.
The Parties specifically intend that this
Agreement shall relate only to their rights and obligations
pertaining to the interconnection of their Electric Systems.
Under this Agreement, neither Party undertakes to
provide or make available any Control Area services,
transmission service, distribution service, power or energy
sales or services or Ancillary Services for the other Party or
any Third Party, but this Agreement does not supersede rights
or obligations as provided in Existing Contracts. Nothing in
this Agreement shall prevent either party from seeking an
13
order under Sections 211 and 212 of the FPA subject to the
provisions for use of ISO and TO tariff service of this
section.
Failure by a Party to operate in a Control Area
or to maintain in effect Control Area Arrangements shall be
deemed a material breach of this Agreement and cause for
termination and disconnection, after a fair opportunity is
given to that Party to obtain or reestablish such operation in
a Control Area or Control Area Arrangements. If any Party
operates without being located in an established Control Area
or without Control Area Arrangements in effect, that Party
shall fully indemnify and make whole the other Party for any
costs imposed or other damages caused to the other Party.
5.2 Effective Date
The term "Effective Date" as used in this
Agreement shall mean 0000 hours of September 1, 2002, or the
first day of the first month following the date on which FERC
accepts this Agreement for filing and permits it to be placed
into effect without material change or material new condition
unacceptable to either Party, whichever is later.
If FERC sets this Agreement for hearing to
determine whether it is just and reasonable and otherwise
lawful, then this Agreement shall become effective on the date
it is permitted to be placed into effect and subject to any
conditions imposed by FERC. The ordering of such a hearing in
14
and of itself shall not be considered a material change.
However, in the event FERC makes any material change or
imposes a material new condition unacceptable to either Party,
the Parties shall promptly enter into good faith negotiations
in an attempt to achieve a mutually agreeable modification to
this Agreement to address any such material change or material
new condition.
The Parties agree to work diligently to obtain
timely acceptance of this Agreement and all of its provisions
by FERC, and agree that NCPA shall be entitled to prior review
of PG&E's initial filing with FERC seeking acceptance of this
Agreement for filing.
5.3 Termination
This Agreement shall terminate on : (i) the
occurrence of the fifth anniversary of the Effective Date or
the tenth anniversary of the Effective Date if the Parties
have agreed to such five year extension no later than the
fourth anniversary of the Effective Date; or (ii) the end of
the 12th month following the date on which either Party gives
the other Party written notice that this Agreement shall be
terminated which notice shall not be given prior to the forth
anniversary of the Effective Date; or (iii) as provided in
Section 10.
15
6 POWER AND TRANSMISSION ARRANGEMENTS
6.1 Limitation on Parties Obligation
The Parties acknowledge that this Agreement does
not provide for either Party to furnish energy, transmission,
distribution or Ancillary Services to the other Party, and in
no circumstance shall either Party be responsible under this
Agreement for providing any such services.
6.2 Transmission Arrangements
NCPA is currently a party to several contracts
that, among other things, provide Transmission Arrangements
for the delivery of power to NCPA's Electric System. Nothing
in this Agreement shall interfere with NCPA's rights,
including those for transmission services, under those
contracts provided, this exception shall not apply to the 1982
Interconnection Agreement between the Parties, which shall
terminate on the date this Agreement becomes effective. Both
Parties may make Transmission Arrangements, other than or in
addition to such service from the ISO. Each Party shall act
as its own Scheduling Coordinator or employ a Scheduling
Coordinator to act for it. Neither Party shall have any
obligation under this Agreement to serve as Scheduling
Coordinator for the other Party or take on any other role in
which it acts on behalf of the other Party as to the other
Party's transactions.
16
6.3 Control Area Operations
It is the intent of the Parties that NCPA and
PG&E shall at all times be integrated into the ISO Control
Area, except as provided in Section 9.5, and shall operate in
accordance with Good Utility Practice and in compliance with
applicable requirements of federal, state, and local laws,
licenses, and permits. PG&E has and will have in effect
various existing arrangements with the Control Area Operator.
These arrangements include the Transmission Control Agreement,
the Transmission Owner Tariff, Scheduling Coordinator
Agreements, and UDC Operating Agreement, all of which enable
PG&E to satisfy the obligations of operating within the ISO's
Control Area. This agreement is subject to PG&E's obligations
and responsibilities under those arrangements, and in the
event of any inconsistency between those arrangements and this
Agreement, the former shall control NCPA has entered into a
MSS Aggregator Agreement with the ISO and such agreement
qualifies as a Control Area Arrangement, that may be needed by
the ISO for operation of the Control Area. This agreement is
subject to NCPA's obligations and responsibilities under those
arrangements, and in the event of any inconsistency between
those arrangements and this Agreement, the former shall
control
17
7 INTERCONNECTIONS
Transfer of electric power between the NCPA and PG&E
Electric Systems shall only occur at the Point(s) of
Interconnection identified in Appendix A.
7.1 Interconnection Capacity
Interconnection Capacity is determined by
engineering studies that consider the physical rating of all
equipment installed within the Interconnection Facilities at
the Points of Interconnection. The E&O Committee shall
periodically review the Interconnection Capacity to ensure
that it is sufficiently maintained throughout the term of this
Agreement.
7.2 Establishing or Modifying Point(s) of
Interconnection
Whenever NCPA decides to add or modify a Point of
Interconnection at transmission voltage, 60 kV or more, it
shall so notify the ISO in accordance with the ISO Tariff and
PG&E in accordance with the PG&E TO Tariff. Upon PG&E's
receipt of such notice, the Parties shall follow the
procedures described in Sections 8 through 10 of the PG&E TO
Tariff. Regarding disputes that might arise under this Section
7, if the PG&E TO Tariff conflicts with Section 23 of this
Agreement, the TO Tariff shall govern. If NCPA decides to
either modify or add a Point of Interconnection at
distribution voltage, less than 60 kV, it shall so notify PG&E
M
in accordance with the requirements of the PG&E Wholesale
Distribution Tariff. Upon PG&E's receipt of such
notification, PG&E shall follow the applicable procedures and
requirements of the PG&E Wholesale Distribution Tariff to
determine what Upgrade Facilities, if any, shall be required.
Upgrade Facilities required for the addition or modification
of a Point of Interconnection at distribution voltage shall be
accomplished pursuant to the requirements of the PG&E
Wholesale Distribution Tariff. Regarding disputes that might
arise under this Section 7 as related to service under PG&E WD
Tariff, if the PG&E WD Tariff conflicts with Section 23 of
this Agreement, the WD Tariff shall govern
7.2.1 New Interconnection Facilities and
Interconnection Facilities Upgrades
If Upgrade Facilities are needed as a result of a
NCPA notice to add or modify a Point of Interconnection
pursuant to this Section 7, the Parties shall meet and confer
on a mutually acceptable plan to complete the Upgrade
Facilities. The Cost responsibility for Upgrade Facilities
required as a result of NCPA's notice to add or modify a Point
of Interconnection shall be determined based on the provisions
of Section 8.1.2 of the PG&E TO Tariff or Section 15 of the
PG&E Wholesale Distribution Tariff, as applicable, and
Appendix C of this Agreement.
19
Any dispute regarding the actual capability of
the existing transmission, distribution, or Interconnection
Facilities, or the need for Upgrade Facilities, that will
support the new or upgraded Point of Interconnection, or how
the Cost responsibility for the necessary Upgrade Facilities
should be allocated, shall be resolved through the dispute
resolution procedures as set forth in Section 23.
7.2.2 Construction Plan and Agreement
Unless otherwise provided under the PG&E
WDT or TO Tariff, or otherwise agreed to by the Parties,
within thirty (30) calendar days after completion of a
Facility Study, NCPA shall notify PG&E if it intends to
proceed with the Upgrade Facility. The Parties shall then meet
and confer on a mutually acceptable plan to complete the
Upgrade Facility. If the Parties reach agreement on a plan for
construction or installation of an Upgrade Facility, including
responsibility for payment of the applicable Cost, the Parties
shall enter into a separate agreement pursuant to Appendix C.
If the Parties fail to reach such agreement, the matter should
be resolved through the dispute resolution provisions in
Section 23.
7.2.3 Test Period for Interconnection
The Parties shall cooperate in the
testing of the Point(s) of Interconnection and of the Parties'
20
facilities prior to becoming operable consistent with Good
Utility Practice.
7.3 NCPA Option As To Construction
In any case in which NCPA is to be separately
responsible, in whole or in part, for the Cost of an Upgrade
Facility under this Section 7, or a System Reinforcement under
Section 8, other than proportionately with all transmission
customers, NCPA may elect to specify, in advance of its first
payment of the costs of constructing or reinforcing
facilities, the basis on which payments will be made. The
options available to NCPA will include a refundable advance,
ownership of that portion of the Upgrade Facility or System
Reinforcement for which NCPA is paying, ownership with a
leaseback, and any other method agreed to by the Parties,
including whatever method may be proposed by PG&E. Specific
terms and conditions, including compensation to NCPA
appropriate to the basis of payment selected, will be agreed
to prior to NCPA's first payment. The Parties recognize that
uncertainties in tax treatment of the payments are such that
undesirable tax consequences to PG&E may occur and, therefore,
NCPA will indemnify and hold PG&E harmless from all net tax
liability associated with any such payments. NCPA will be
entitled to participate in the discussions and/or litigation
with the Internal Revenue Service associated with the
determination of such undesirable tax consequences for which
21
NCPA may be an indemnitor. If ownership is chosen by NCPA as
the method of payment, the Control Area Operator, or PG&E, as
appropriate under the terms of the Control Area Arrangements
to which PG&E is a party, shall have complete control over
facilities owned by NCPA and paid for under this provision.
PG&E, in turn, may turn operational control of such facilities
over to the ISO (or such other Control Area Operator as may be
appropriate) under the terms of the Control Area Arrangement
(or any successor agreement) to which PG&E is a party.
8 SYSTEM PLANNING COORDINATION
Pursuant to the ISO Tariff, including Section 3.2, PG&E
conducts planning studies of its Electric System annually to
identify System Reinforcements or other modifications of its
Electric System necessary to determine the Transfer Capability
to reliably serve the expected loads connected to its Electric
System including expected NCPA loads at Point(s) of
Interconnection.
8.1 Planning Process
In order for the Parties to include the effects of
growth of NCPA's Electric System loads in its planning
studies, NCPA shall provide PG&E with NCPA's electric load
planning data by October 15 of each year. Such electric load
planning data shall contain the best estimate of NCPA's
Electric System load for the next five-year period being
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served at Points of Interconnection. The initial forecast
shall be submitted to PG&E within 30 days of the Effective
Date. Both Parties shall be responsible for participating in
planning for the construction of any necessary System
Reinforcements as provided in the PG&E TO Tariff Sections 8
through 10.
8.2 System Reinforcements
If, as a result of its annual planning review
process, PG&E determines, through studies conducted pursuant
to the ISO Tariff, including Section 4.8.1 thereof, and in
accordance with PG&E TO Tariff Section 9, that a need exists
to construct System Reinforcements that will have a direct
effect on NCPA, PG&E shall inform NCPA through a notice
pursuant to Section 32. The Parties shall then follow the
applicable procedures of the PG&E TO Tariff Sections 8 through
10.
9 OPERATING PROVISIONS
9.1 General
The Parties agree to coordinate the operations of
their respective Electric Systems so as to minimize any
adverse impacts to the other Party's Electric System in
accordance with Control Area Arrangements, Good Utility
Practice and Appendix E.
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9.2 Power Delivery and Quality Standard
Power delivered is commonly designated as three
phase alternating current, at nominal 60 Hertz, and at the
nominal voltage described in Appendix A for each Point of
Interconnection. Normal variations in voltage and frequency
shall be permitted pursuant to Good Utility Practice.
9.3 Coordination Of Operations
PG&E and NCPA shall at all times coordinate and
communicate their various outages and other switching
operations which may have an effect on the operations of the
other Party's Electric System and may reasonably be required
to protect the integrity of the Control Area during
Emergencies.
PG&E and NCPA are also responsible for maintenance
and switching operations of their Electric Systems. Both
Parties , consistent with their requirements to maintain and
operate their Electric Systems in accordance with Good Utility
Practice, may from time to time remove various elements of
their Electric Systems from operation or initiate other
actions which may affect operations or transfer of energy
across Points of Interconnection.
The Parties shall endeavor to coordinate their
activities in the operation and maintenance of their Electric
Systems in order to avoid or minimize any adverse effects of
those activities on each other.
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9.4 Relationship To Control Area Operations
NCPA and PG&E currently operate in the ISO Control
Area. The Parties shall operate in accordance with Good
Utility Practice and in compliance with applicable
requirements of federal, state, and local laws, licenses, and
permits. NCPA is a party to an MSS Aggregator Agreement with
the ISO. Should this MSS Aggregator Agreement terminate and
not be replaced with a substantially similar agreement, NCPA
and PG&E shall coordinate the operation of their respective
Electric Systems in accordance with Appendix E except as
otherwise provided in this Agreement. In the event that PG&E
or NCPA makes any changes in its relationship with the ISO,
the Party making the change shall, if practical, give as much
advance notice including 30 days notice if possible to the
other Party.
9.5 Separate Control Area
Nothing in this Agreement shall prevent either
Party from joining or forming a new Control Area. In such
event, this Agreement shall be revised as appropriate to
reflect such change in Control Area operations.
9.6 Reporting Significant Events
Each Party shall promptly, after reporting to the
Control Area Operator, report to the other Party any Emergency
or other significant operating event reasonably likely to
affect operation of the other Party's Electric System at each
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Point(s) of Interconnection. For notice to PG&E, such notice
shall be by telephone to PG&E's Transmission Operations Center
personnel or such other substation or switching center as may
be designated by PG&E. For notice to NCPA, such notice shall
be by telephone to NCPA's Control Center, or as otherwise
designated by NCPA. Each Party, upon request and on a case-
by-case basis for reasonable cause related to operating
conditions, shall, in a timely manner, provide to the other
Party Electric System operating information, such as loading
on lines and equipment and levels of operating voltages and
electric power factors. In the event of interruptions,
including power quality events, of electric service at any
Point of Interconnection, the Party causing the interruption
shall report, in a timely manner if known, to the other Party
the nature and suspected cause of the event, actions being
taken to restore electric service, and the estimated time
until restoration of electric service.
9.7 Operation Pursuant To Good Utility Practice
Good Utility Practice shall be the general
standard for performance related to Electric System operation
by the Parties under this Agreement.
Each Party shall plan and operate its respective
Electric System in accordance with Good Utility Practice and
endeavor to minimize electrical disturbances on the Electric
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System of the other Party. No Party shall be obligated to
operate in a manner contrary to Good Utility Practice.
9.8 Engineering And Operating Committee
NCPA and PG&E shall establish an Engineering and
Operating Committee. This "E&O Committee" shall agree upon
and modify, as necessary, operating procedures and engineering
planning matters required to implement this Agreement
consistent with Good Utility Practice. The E&O Committee
shall consist of two representatives designated in writing by
each Party. Each Party shall also designate an alternate who
may act instead of a representative at the option of that
Party. Either Party may at any time change its
representatives or alternate on the E&O Committee and shall
promptly notify the other Party of any change in designation.
Any representative, by written notice to the other Party, may
authorize its alternate to act temporarily in its place. Each
member of the E&O Committee may invite other members of its
organization or others, as its advisors, to attend meetings of
the E&O Committee. The E&O Committee shall elect a chairman
each year that shall alternate between the Parties.
9.8.1 E&O Committee Operating Procedures
The E&O Committee shall establish
procedures for the coordination and operation of their
Electric Systems. Such procedures shall:
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9.8.1.1 Allow each Party to meet
applicable coordination and operational requirements of the
ISO tariff and protocols including any ISO agreements which it
has entered into, including but not limited to PG&E's
Transmission Control Agreement and any Control Area
Arrangements, including MSS Aggregator Agreements or
Operating Agreements, entered into by NCPA.
9.8.1.2 Allow each party to meet
applicable coordination and operational requirements of the
PG&E Transmission Owner Tariff and the PG&E Wholesale
Distribution Tariff;
9.8.1.3 Provide that PG&E shall report
the procedures adopted by the E&O Committee to the ISO; and
9.8.1.4 Provide for the coordination of
maintenance schedules and operation of the Parties' Electric
Systems as may be required to maintain the reliability and
power quality of the interconnected Electric Systems, reduce
losses, maintain voltage levels, and minimize reactive
interchanges.
9.8.2 E&O Committee Expenses
The expenses of the members of the E&0
Committee, their alternates and advisors shall be borne by the
Party they represent. Expenses incurred by the E&O Committee
in addition to those herein above mentioned shall be shared in
a just and reasonable manner agreed to by the Parties. The
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sharing of such expenses shall be agreed to prior to the time
that such additional expenses are incurred.
9.8.3 E&O Committee Meetings
The E&O Committee shall meet to discuss
the availability of additional or modified interconnection
service requested by NCPA, or proposed by PG&E. Such matters
shall include but not be limited to the following:
a. The E&O Committee shall examine potential
alternatives to provide NCPA's requested
interconnection service.
b. The E&O Committee shall determine the studies that
need to be performed and the manner in which the
Cost of such studies shall be allocated unless the
ISO Tariff, PG&E TO or WDT Tariff provides
otherwise.
c. In the event studies are required as a result of a
NCPA request for interconnection service, NCPA may
elect to make the studies in coordination with PG&E
and the Parties will mutually agree on the
parameters for the studies.
d. For studies conducted by PG&E for which NCPA
provides compensation, PG&E and NCPA will agree
initially on the scope of such studies, study
parameters, and the compensation required from NCPA.
PG&E agrees to provide NCPA with written monthly
29
progress reports, unless agreed otherwise.
Subsequent changes to the study scope will require
NCPA's agreement which shall not be unreasonably
withheld. The E&O Committee shall meet when such
studies are completed and based on these studies,
agree upon a plan for providing NCPA's requested
interconnection service. The criteria for selecting
such a plan shall be the ISO Planning Criteria and
Good Utility Practice.
e. Review the consistency of the Parties' coordination
and operation procedures with the requirements of
Section 9.8.1 and adopt any revisions necessary to
assure such consistency.
9.8.4 E&O Committee Guidelines
The E&O Committee shall meet upon the
call of either Party. From time to time, to meet changing
conditions, the E&O Committee shall be responsible for
reviewing and recommending operating procedures, standard
practices and other matters affecting the interconnected
operation of the Parties' respective Electric Systems. The
E&0 Committee shall meet at least twice per year. Such
matters shall include but not be limited to the following:
a. Examine and make recommendations on future Points Of
Interconnection in order to: (i) ensure that the
proposed Points of Interconnection will be
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consistent with Good Utility Practice,
(ii) determine necessary additions or modifications
to equipment or operating procedures to ensure that
PG&E's and NCPA's Electric System reliability and
service to its customers will not be adversely
affected, and (iii) determine the allocation of
Costs associated with the above additions or
modifications.
b. Review and recommend arrangements for metering,
communication, scheduling, and dispatching that may
be necessary for the interconnected operation of the
Parties' respective Electric Systems.
c. Establish administrative and billing procedures that
may be necessary for implementing various provisions
of this Agreement.
d. Establish a mutual obligation communications
protocol as described in Section 9.13.
e. Review reactive power requirement compliance and any
other power quality issues at Points of
Interconnection.
f. Review annual load forecasts (electric load planning
data) and the results of PG&E's and NCPA's relevant
planning studies.
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g. Review reliability and power quality performance of
PG&E's and NCPA's Electric Systems at Points of
Interconnection.
9.8.5 E&O Committee Authority
The E&O Committee shall have no authority
to modify any of the provisions of this Agreement. All
actions, recommendations and reports shall become effective
when signed, or otherwise approved, by all members of the E&O
Committee if necessary referred to the Parties' respective
managements. Each Party's representatives shall be afforded
ample time to review relevant details prior to finalization of
any action, recommendation or report and may request up to 30
days to review the material to be acted upon.
9.8.6 Settlement of Disputes and Arbitration.
The Parties agree to make best efforts to
settle all disputes between the Parties connected with this
Agreement as a matter of normal business practice under this
Agreement. Any unresolved disputes shall be resolved through
the dispute resolution procedure set forth in Section 23.
9.9 Protective Devices
Both Parties shall, consistent with ISO requirements and
Good Utility Practice, install, modify, set and adjust the
protective relaying equipment associated with facilities
within its respective Electric System. Such settings
adjustments or replacement shall be consistent with settings
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adjustments or replacement made by PG&E to PG&E's protective
relaying equipment. NCPA shall install, modify, set adjust or
replace its protective relaying equipment in the event that
such is required by PG&E's modification of PG&E's Electric
System consistent with ISO requirements and with Good Utility
Practice. Such changes shall be reviewed by the E&O Committee.
9.10 Requirements for Generators Operated by NCPA that
are Connected to PG&E Electric System
NCPA shall enter into a generator
interconnection -type agreement with PG&E substantially
consistent with PG&E's Generation Interconnection Agreement
and consistent with NCPA's MSS Aggregator Agreement for each
new generating facility operated by NCPA, which is connected
to PG&E's Electric System at voltages of 60kV or greater.
9.11 Continuity Of Service
9.11.1 Operation Actions To Maintain Continuity
Each Party shall take actions that are
reasonable and consistent with Control Area Arrangements and
Good Utility Practice as necessary to maintain continuity of
service between the Parties. Such actions may include, but
are not limited to, opening or closing circuit breakers or
other components of the interconnections.
9.11.2 Unscheduled Interruptions
Either Party may temporarily interrupt or
reduce any service, or temporarily separate all or any part of
33
the facilities of its Electric System from the other Party's
Electric System to implement ISO operating orders and their
respective Control Area Arrangements or Good Utility Practice
at any time that: (i) a System Emergency exists; (ii) the
action is necessary or desirable to prevent a hazard to life
or property; or (iii) the operation of the Party's Electric
System is suspended, interrupted or interfered with as a
result of an Uncontrollable Force. Reasonable effort shall be
made to coordinate any such interruption and such interruption
will be immediately communicated to the other Party. In the
event of such interruption or reduction in service, the
Parties shall restore full service on a basis comparable to
the restoration of other public service and safety facilities
and consistent with their respective Control Area
Arrangements.
9.11.3 Scheduled Interruptions
All scheduled interruptions of service
shall be made as mutually agreed by the Parties and in
accordance with Control Area Arrangements and Good Utility
Practice. Whenever possible, the Parties shall endeavor to
give at least 72 hours advance notice of any such
interruption, reduction or separation, and its probable
duration.
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9.11.4 Interruption By Protective Devices
PG&E and NCPA utilize automatic
protective devices in order to assist in maintaining the
integrity and reliability of their respective Electric Systems
and to protect their customers from damage, injury or
prolonged outages. Service on the PG&E and NCPA Electric
Systems is subject to interruption in the event of operation
of such devices. In the event of such interruption, service
will be restored consistent with Good Utility Practice and
Control Area Arrangements. In addition, PG&E and NCPA shall
coordinate such restoration and all installations, upgrades,
and replacements of protective devices at Points of
Interconnection in accordance with Good Utility Practice.
9.11.5 Jeopardy
If at any time continuity of service
within the ISO Control Area is being jeopardized due to
failure of facilities, PG&E and/or NCPA shall coordinate
their responses to the jeopardy, to implement ISO
operating orders in accordance with their respective
Control Area Arrangements, and Good Utility Practice.
Such coordination may include the reduction of load;
provided, except as otherwise set forth in the Parties'
Control Area Arrangements, that such reduction shall
maintain, as far as may be practicable, the relative
35
sizes of load served by each Party in the same proportion
as existed before such reduction.
Either Party may also temporarily interrupt or
reduce deliveries to Points of Interconnection or
separate all or a part of the facilities of its Electric
System from all or a part of the Electric System of the
other Party, or the Electric System which directly or
indirectly serves the other Party, if the first Party
determines that the following conditions exist or that
the described action is necessary: (i) a System
Emergency; (ii) in order to install equipment on, make
repairs or replacements to, make investigations and
inspections of, or perform maintenance or other work on
PG&E's Electric System; (iii) to prevent a hazard to life
or property; (iv) as necessitated by Good Utility
Practice, or (v) where the operation of PG&E's Electric
System is suspended, interrupted or interfered with as a
result of Uncontrollable Force. The Parties understand
and agree that load curtailment under such circumstances
is a matter that should be coordinated among PG&E, NCPA
and the ISO based upon the ISO tariff and any Control
Area Arrangements entered into between PG&E, NCPA and the
ISO. Such interruptions or reductions of deliveries shall
be minimized and implemented after all other practical
remedies have been exhausted.
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9.12 Operating Records
Each Party shall maintain operating records in
accordance with Good Utility Practice. Each Party shall have
reasonable access to such operating records kept by the other
Party which reasonably relate to interconnected operation of
the Parties' Electric Systems; provided, that if requested to
do so by the other Party, a Party requesting such records
shall be required to keep such records confidential to the
extent permitted by applicable law, including, in the case of
NCPA, the Ralph M. Brown Act and the Public Records Act. Such
records shall include, but not be limited to, operating logs,
scheduled transfers through each Point of Interconnection,
line loadings, outage and power quality reports, voltages and
reactive power.
9.13 Mutual Obligation Communications Protocol
The Parties shall establish a mutual obligation
communications protocol that will cover clear and timely
communication between the Parties regarding items such as, but
not limited to (a) complying with maintenance schedules that
conform to Good Utility Practice, and (b) the reporting of
system disturbances. The E&0 Committee shall be the venue for
establishing such a protocol.
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10 SIGNIFICANT REGULATORY OR OPERATIONAL CHANGE
The procedures set forth in this Section 10 shall apply
in the event of a Significant Regulatory Change or a
Significant Operational Change as described below.
10.1 Significant Regulatory Change
A "Significant Regulatory Change," As this term
is used in this Section 10, shall be deemed to occur if FERC,
the CPUC, any other agency or court having jurisdiction, the
California Legislature, or the United States Congress issues
an order or decision or adopts or modifies a tariff or filed
contract, or enacts a law that significantly interferes with
the ability of either Party to perform any of its obligations
under this Agreement.
10.2 Significant Operational Change
A "Significant Operational Change," as this term
is used in this Section 10, shall consist of any of the
following: (i) either Party's making a new interconnection of
its Electric System with the Electric System of a Third Party,
including any generation, which would have the potential for
significantly affecting the operation of the other Party's
Electric System; (ii) installation or operation by either
Party or a Third Party of a generation facility within a
Party's Electric System where power or energy from such
generation is intended to or may possibly flow through a Point
of Interconnection and onto either Party's Electric System; or
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(iii) any other operational change proposed by a Party that
could reasonably be expected to significantly affect the other
Party's Electric System; or (iv) an action taken by the
Control Area Operator which may cause a significant change in
the way a Party operates or must operate its Electric System
or the Points of Interconnection between the Parties.
10.3 Change in Functions or Scope
The Parties recognize that there may be a change
in the functions performed by the ISO or in the scope of the
facilities under the operational control of the ISO, or the
replacement of the ISO with a Regional Transmission
Organization that may perform different functions or have a
different scope than the ISO as of the Effective Date. Such a
change shall not be deemed to be a Significant Regulatory
Change unless the conditions described in Section 10.1 above
are satisfied. Any transfer from PG&E to the ISO of any
functions contemplated in this Agreement can be a Significant
Regulatory Change if the conditions described in Section 10.1
above are satisfied.
10.4 Notification
At any time during the term of this Agreement, if
either Party anticipates the occurrence of a Significant
Regulatory Change or Significant Operational Change, and if
such change may reasonably be expected to materially affect
either or both Parties' obligations or operations under this
39
Agreement, such Party shall provide written notice to the
other Party as soon as practicable. The notice shall contain
a description of the change, including expected time schedules
and of the effect of the significant change to that Party's
Electric System. If the Party giving notice believes that it
will be necessary to amend this Agreement to address the
anticipated change, then the notice to the other Party may
include a proposal that the Parties meet in order to negotiate
an appropriate amendment to this Agreement. The Parties shall
promptly enter into good faith negotiations in an attempt to
achieve a mutually agreeable modification to this Agreement to
address any such significant change.
10.5 Amendment of Agreement
If the Parties agree that an amendment to this
Agreement is necessary to address a significant change, as
discussed in this Section 10, the Parties will proceed to
negotiate such amendment. If the Parties have not reached
agreement within 60 calendar days of the date of the first
meeting, any unresolved issues may be submitted for
resolution through the dispute resolution procedures set forth
in Section 23; provided that both Parties agree to such
procedures. After the 60 day period stated above, either
Party may, but is not required to, unilaterally initiate an
appropriate proceeding respecting this Agreement with FERC
pursuant to Sections 205 or 206 of the FPA, which proceeding
40
could include a request for termination of this Agreement, and
the other Party may exercise its rights under the FPA to
protest or oppose such filing. In the event of filing for
termination, PG&E shall make an appropriate regulatory filing
of a replacement agreement such that the replacement agreement
is effective contemporaneously with the termination date of
this Agreement.
10.6 Studies of Significant Operational Change
If a Party receiving notice from the other Party
of a Significant Operational Change believes that the proposed
change may reasonably be expected to materially affect the
operation of its Electric System, it may request a study of
any such Significant Operational Change to determine the
potential for any adverse impacts and any potential avoidance
or mitigation measures thereto. The Parties shall cooperate
in determining how the study should be conducted and providing
information necessary to conduct such a study.
If it is determined, based on the results of the
study, that, in addition, a Facility Study or System Impact
Study is required, such study shall be performed within the
time and in the manner specified in Section 7 of the PG&E TO
Tariff and as agreed by the Parties. All study Costs
associated with a proposal shall be the responsibility of the
Party whose proposal or actions will cause the Significant
Operational Change, or will be shared equally by the Parties
41
if the ISO is the entity which causes or will cause the
change; provided, that such Costs may be paid by a responsible
Third Party. Any disputes over the necessity of particular
studies or the Cost of such studies shall be resolved through
the dispute resolution procedures set forth in Section 23
unless the dispute resolution procedures of the PG&E TO Tariff
or the PG&E WD Tariff apply. Upon completion of necessary
studies, the Parties will each review the study results and
discuss any recommendations for avoidance and/or mitigation of
adverse impacts.
10.7 Mitigation And Costs
Unless otherwise agreed by the Parties, the Party
whose proposal or action causes the Significant Operational
Change ("Modifying Party") shall be responsible for
compensating the other Party ("Affected Party") for the
reasonable Cost, if any, of mitigating any adverse impact on
the Affected Party's Electric System caused by the change;
provided, that such Costs may be paid by a responsible Third
Party. Any reasonable Cost incurred by the Affected Party in
its cooperation with the Modifying Party shall be reimbursed
by the Modifying Party. All avoidance or mitigation measures
shall be completed before the Significant Operational Change
is made. Any dispute regarding the need for, the nature of,
or the Cost of mitigating adverse impacts or compensating the
Affected Party for those adverse impacts that cannot be
42
mitigated shall be resolved through the dispute resolution
procedures set forth in Section 23.
In the event changes in transmission delivery voltages,
relocation of facilities serving Points of Interconnections or
other changes in transmission facilities are necessary on
PG&E's side of any Point of Interconnection with NCPA because
of changes to PG&E's transmission as a result of Good Utility
Practice or ISO planning requirements, these changes shall be
made by PG&E at its expense. For similar changes made to
NCPA's side of Points of Interconnection, such changes shall
be at NCPA's expense unless the change is made for PG&E's
benefit and at PG&E's sole discretion unless otherwise agreed.
Such change made at PG&E's sole discretion shall be submitted
to the E&O Committee for its determination of the respective
long term benefits of such changes, if any. The E&O Committee
shall allocate the Cost of such changes based on the projected
net long-term benefits to each Party. Changes required on
PG&E's side due to any changes made for NCPA's benefit or
NCPA's sole discretion shall be made at NCPA's expense, unless
submitted to the E&O Committtee for its determination of an
appropriate allocation between the Parties based on projected
net long term benefits to each party.
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10.8 Failure To Notify Of Significant Operational
Changes
Each Party has a duty to provide notice to the
other Party of Significant Operational Changes planned for its
Electric System that could reasonably be expected to have an
adverse impact on the Electric System of the other. If a
Party implements a Significant Operational Change without
providing such notice, the affected Party shall have the right
to open any affected Point(s) of Interconnection if, in its
judgment, it is necessary to protect the integrity of its
Electric System, and the right to file with FERC under
Sections 205 or 206 of the FPA seeking appropriate relief,
including, but not limited to, amendment or termination of
this Agreement.
11 INSTALLATION AND ACCESS
Where it is necessary for either Party to install any of
its facilities on the other Party's premises in order to
accomplish the interconnection or otherwise to perform the
duties contemplated by this Agreement, the Parties hereby
grant to each other, subject to any legal and regulatory
requirements for any specific installation, for the term of
this Agreement: i) the right to make such installation along
the mutually agreed route (subject to each Party's right to
protect its operations or that of its customers in its Service
44
Area) of sufficient width to provide full legal clearance from
all structures on such property; and ii) access to each
Party's premises at all reasonable hours for any purposes
reasonably connected with this Agreement. Neither shall be
allowed or obligated to install such facilities unless and
until all necessary licenses, permits, certificates, or other
governmental authorizations or approvals that may be necessary
are obtained and any necessary easements for the installation
of facilities are granted. Electric facilities belonging to
one Party that are installed on the other Party's premises
will be relocated only with the agreement of the owner of such
facilities, which shall not be unreasonably withheld. The
requesting Party shall pay the Cost, if any, of any such
facility relocation. If such costs are FERC jurisdictional,
PG&E shall request and obtain FERC acceptance to assess such
costs prior to collection.
12 METERING
12.1 Delivery Meters
All real and reactive power deliveries shall be
metered at each Point of Interconnection with meters meeting
the requirements of: (i) the ISO Tariff for interconnections
at 60 kV and above; and (ii) the PG&E WD Tariff for
interconnections below 60 W. Any conflicts with regard to
metering standards that may arise between this Agreement, the
45
PG&E Wholesale Distribution Tariff, or the ISO Tariff shall be
resolved consistent with the applicable tariff. Power
deliveries shall be metered at delivery voltages described in
Appendix A. At a minimum, the Responsible Meter Party shall
meter all power flowing across each interconnection in either
direction.
The Parties shall cooperate in the installation
and provision of access to the meters, as necessary for each
Party to obtain the information needed to perform as
contemplated under this Agreement.
12.2 Requirements For Meters And Meter Maintenance
The Responsible Meter Party is obligated to
install and maintain metering equipment, including where
necessary BTUs, in accordance with ISO standards, at each
Point of Interconnection that shall measure and record real
and reactive power flows and shall be capable of recording
flows in both directions. Such "in" and "out" meters shall be
designed to prevent reverse registration and measure and
continuously record such deliveries.
12.3 NCPA's Obligation To Provide Meter Data To PG&E
NCPA, pursuant to its MSS Aggregator Agreement
with the ISO, subject to any exemptions granted by the ISO,
supplies the ISO with both telemetry and settlement quality
meter data. The telemetry data includes generator status,
voltage and output. NCPA, as the Responsible Meter Party, will
46
grant PG&E access to the same metering data in accordance with
Schedule 15.2 of the NCPA MSS Aggregator Agreement. Should the
MSS Aggregator Agreement terminate for any reason, PG&E will
continue to have the same level of access as it did under
Schedule 15.2. In addition, NCPA will provide PG&E with
necessary schedule data regarding NCPA transactions that
affect PG&E's accurate accounting of the Western Logical Meter
at Tracy, through procedures to be agreed upon between the
Parties.
12.4 Consequences of Failing to Provide Meter Data in a
Timely Fashion
In the event that NCPA, acting as the Responsible
Meter Party, fails to provide to PG&E access to available
meter data in accordance with Section 12.3, PG&E shall be
entitled to make reasonable assumptions necessary for the
operations of its transmission system. The assumptions shall
be based on reasonably available information including, but
not limited to, records of historical usage, available RTU
data and meter readings and general characteristics of NCPA's
operation and facilities
13 BILLING AND PAYMENT
PG&E shall bill NCPA for the Costs of an Upgrade Facility
and/or the monthly ownership Cost of an Upgrade Facility
pursuant to Appendix D. PG&E shall promptly pay NCPA for
47
amounts owed pursuant to this Agreement. Sections D.2 through
D.9 of Appendix D shall hereto apply to PG&E's payment
obligations to NCPA, substituting "NCPA" for "PG&E" and
"PG&E" for "NCPA", respectively.
14 APPENDICES INCLUDED
The following Appendices to this Agreement, as they may
be revised from time to time by written agreement of the
Parties or by order of FERC, are attached hereto and are
incorporated by reference as if fully set forth herein:
Appendix A — Point(s) of Interconnection
Appendix B — Dispute Resolution and Arbitration
Appendix C - Upgrade Facilities
Appendix D - Billing and Payments
Appendix E - Operational Coordination
15 ACCOUNTING
15.1 Accounting Procedures
PG&E and NCPA each shall record relevant Cost(s)
and maintain its accounting records in accordance with
generally accepted accounting practices and FERC Uniform
System of Accounts.
15.2 Audit Rights
For good cause and upon reasonable notice, each
Party shall have the right to audit, at its own expense, the
W.
relevant records of the other Party for the limited purpose of
determining whether the other Party is meeting its obligations
under this Agreement. Such audits shall be limited to only
those records reasonably required to determine compliance with
this Agreement, and each Party agrees to disclose the
information obtained in such audit only to those persons,
whether employed by such Party or otherwise, that are directly
involved in the administration of this Agreement. Each Party
agrees that under no circumstances will it use any information
obtained in such an audit for any commercial purpose or for
any purpose other than assuring enforcement of this Agreement.
The right to audit shall be limited to data for two prior
years from the date of the final billing for a matter or from
the date of the questioned event, as applicable.
16 ADVERSE DETERMINATION OR EXPANSION OF OBLIGATIONS
16.1 Adverse Determination
If, after the Effective Date of this Agreement,
FERC or any other regulatory body, agency or court of
competent jurisdiction determines that all or any part of this
Agreement, its operation or effect is unjust, unreasonable,
unlawful, imprudent or otherwise not in the public interest,
each Party shall be relieved of any obligations hereunder to
the extent necessary to comply with or eliminate such adverse
determination. The Parties shall promptly enter into good
49
faith negotiations in an attempt to achieve a mutually
agreeable modification to this Agreement to address any such
adverse determination.
16.2 Expansion Of Obligations
If, after the Effective Date of this Agreement,
FERC or any other regulatory body, agency or court of
competent jurisdiction orders or determines that this
Agreement should be interpreted, modified, or significantly
extended in such a manner that PG&E or NCPA may be required to
extend its obligations under this Agreement to a Third Party,
or to incur significant new or different obligations to the
other Party or to Third Parties not contemplated by this
Agreement in a manner not anticipated by other agreements,
then the Parties shall be relieved of their obligations to the
extent lawful and necessary to eliminate the effect of that
order or determination, and the Parties shall attempt to
renegotiate in good faith the terms and conditions of the
Agreement to restore the original balance of benefits and
burdens contemplated by the Parties at the time this Agreement
was made.
16.3 Renegotiations
If, within three months after an order or
decision as described in Sections 16.1 and 16.2, the Parties
either: (i) do not agree that a renegotiation is feasible or
necessary; or (ii) the Parties cannot agree to amend or
50
supersede this Agreement, then: (a) either Party may initiate
dispute resolution in accordance with Section 23; (b) PG&E may
unilaterally file an amendment to this Agreement or a
replacement agreement; or (c) NCPA may take any action before
the FERC or elsewhere which it deems appropriate. The effect
of such termination, and the rights of the Parties thereunder,
shall be as provided in Sections 37 and 38. As used in this
Section, the term "Agreement" includes both this Agreement and
any tariff, rate or rate schedule that in whole or in part
results from this Agreement.
17 ASSIGNMENT
17.1 Consent Required
No transfer or assignment of the rights, benefits
or duties of either Party under this Agreement shall be
effective without the prior written consent of the other Party
except as provided herein, which consent shall not be withheld
unreasonably; provided, that this Section 17 shall not apply
to interests that arise by reason of any deed of trust,
mortgage, indenture or security agreement heretofore granted
or executed by any Party. No partial assignment of the
rights, benefits or duties of either Party shall be permitted
under this Agreement unless otherwise agreed to by the other
Party, however such consent shall not be required for an
assignment to a successor in interest in the ownership of all
51
or a significant part of PG&E's transmission system by reason
of a reorganization pursuant to a plan of reorganization
approved by the Bankruptcy Court or any other court having
jurisdiction over PG&E's bankruptcy proceedings so long as the
successor agrees to be, and is bound, by the obligations under
this agreement.
17.2 Assignee's Continuing Obligation
Any successor to or transferee or assignee of the rights or
obligations of a Party, whether by voluntary transfer,
judicial sale, foreclosure sale or otherwise, shall be subject
to all terms and conditions of this Agreement to the same
extent as though such successor, transferee, or assignee were
an original Party.
18. CAPTIONS
All indices, titles, subject headings, section titles and
similar items are provided for the purpose of reference and
convenience and are not intended to affect the meaning of the
contents or scope of the Agreement.
19. CONSTRUCTION OF THE AGREEMENT
Ambiguities or uncertainties in the wording of the
Agreement shall not be construed for or against either Party.
52
20. CONTROL AND OWNERSHIP OF FACILITIES
The Electric System of a Party shall at all times be and
remain in the exclusive ownership, possession and control of
the Party, or licensed or leased to that Party as provided in
the License, and nothing in this Agreement shall be construed
to give the other Party any right of ownership, possession or
control of all or any portion of that Electric System. All
facilities owned and installed by one Party hereunder shall,
unless otherwise agreed by the Parties, at all times be and
remain the property of that Party.
21. COOPERATION AND RIGHT OF ACCESS AND INSPECTION
Each Party shall give to the other all necessary
permission to enable it to perform its obligations under the
Agreement. Each Party shall give the other Party the right to
have its agents, employees and representatives, when
accompanied by the agents, employees and representatives of
the other Party, enter its premises at reasonable times and in
accordance with reasonable rules and regulations for the
purpose of inspecting the property and equipment of the other
Party in a manner which is reasonable for assuring the
performance of the Parties under the Agreement.
53
-3-1 r%,w wTTTT T
22.1 Termination For Default
If either Party breaches its material obligations
under this Agreement, such breach shall constitute an event of
default. If any Party defaults under this Agreement, the
other Party may terminate this Agreement; provided that prior
to such termination the other Party must provide the
defaulting Party with written notice stating: 1) the Party's
intent to terminate; 2) the date of such intended termination;
3) the specific grounds for termination; 4) specific actions
which the defaulting Party must take to cure the default, if
any; and 5) a reasonable period of time, which shall not be
less than 60 calendar days, within which the defaulting Party
may take action to cure the default and avoid termination,
provided there is any action which can be taken to cure the
default. Termination shall not become effective without
approval by FERC. Application of dispute resolution pursuant
to Section 23 with regard to separate disputes shall not be
deemed to limit the right to terminate this Agreement under
this Section 22.1.
22.2 Other Remedies For Default
The remedy under Section 22.1 is not exclusive,
and subject to Section 23 either Party also shall be entitled
to pursue any other legal, equitable or regulatory rights and
54
remedies it may have in response to a default by the other
Party.
23 DISPUTE RESOLUTION
The Parties shall make best efforts to resolve all
disputes arising under this Agreement expeditiously and by
good faith negotiation. Where this Agreement specifically
calls for resolution of disputes pursuant to Section 23, the
Parties shall pursue dispute resolution according to the
provisions of Appendix B.
24 Governing Law
This Agreement shall be interpreted, governed by and
construed under the laws of the State of California, as if
executed and to be performed within the State of California.
25 INDEMNITY
25.1 Definitions
As used in this Section 25, with initial letters
capitalized, whether in the singular or the plural, the
following terms shall have the following meanings:
25.1.1 Claimant
(i) Accidents sustained by a Third Party
("Claimant"), which is an ultimate use customer of a Party;
55
(ii) arises out of delivery of, or curtailment
of, or interruption to electric service, including but not
limited to abnormalities in frequency or voltage; and
following:
(iii) results from either or both of the
a. engineering, design, construction,
repair, supervision, inspection, testing, protection,
operation, maintenance, replacement, reconstruction, use, or
ownership of either Party's Electric System; or
b. the performance or non-performance of
either Party's obligations under the Agreement.
25.2 Indemnity Duty
If a Claimant makes a claim or brings an action
against a Party seeking recovery for loss, damage, costs or
expenses resulting from or arising out of an Accident the
following shall apply:
25.2.1 That Party ("Indemnitee") shall
defend any such claim or action brought against it, except as
otherwise provided in this Section 25.2.
25.2.2 A Party ("Indemnitor") shall hold
harmless, defend and indemnify, to the fullest extent
permitted by law, the other Party, its directors or members of
its governing board, officers and employees ("Indemnitees"),
upon request by the Indemnitee, for claims or actions brought
against the Indemnitee allegedly resulting from Accidents
caused by acts, errors or omissions of the Indemnitor.
25.2.3 No Party shall be obligated to
defend, hold harmless or indemnify the other Party, its
directors or members of its governing board, officers and
employees for Accidents resulting from the latter's gross
negligence or willful misconduct.
25.2.4 In the event a dispute under this
Section 25 is litigated, each Party specifically agrees
to pay its own incurred costs including attorney's fees,
expert and consultant fees, and other costs of
litigation.
26 JUDGMENTS AND DETERMINATIONS
When the terms of this Agreement provide that an action
may or must be taken, or that the existence of a condition may
be established based on a judgment or determination of a
Party, such judgment shall be exercised or such determination
shall be made reasonably and in good faith, and where
applicable in accordance with Good Utility Practice, and shall
not be arbitrary or capricious.
57
27 LIABILITY
27.1 To Third Parties
Nothing in this Agreement shall be construed to
create any duty to, any standard of care with reference to, or
any liability to, any Third Party.
27.2 Between The Parties
Except for its willful action, gross negligence,
or with respect to breach of this Agreement, or with respect
to the indemnity duty under Section 25.2, no Party, nor its
directors or members of its governing board, officers,
employees or agents shall be liable to another Party for any
loss, damage, claim, cost, charge or expense arising from or
related to this Agreement. In the event of breach of this
Agreement, neither Party, nor its directors or members of its
governing board, officers, employees or agents shall be liable
to the other Party for any consequential, special or indirect
damages.
27.3 Protection Of A Party's Own Facilities
Each Party shall be responsible for protecting
its facilities from possible damage by reason of electrical
disturbances or faults caused by the operation, faulty
operation, or non -operation of another Party's facilities, and
such other Party shall not be liable for any such damage so
caused; provided, this limitation on liability shall not
extend to failure to observe the requirements of Section 9.
W
27.4 Liability For Interruptions
Neither Party shall be liable to the other, and
each Party hereby releases the other and its directors,
members of its governing board, officers, employees and agents
from and indemnifies them, to the fullest extent permitted by
law, for any claim, demand, liability, loss or damage, whether
direct, indirect or consequential, incurred by either Party,
which results from the interruption or curtailment in
accordance with i) this Agreement, ii) Good Utility Practice,
or (iii) as directed by the ISO, of power flows through a
Point of Interconnection under this Agreement.
28 NO DEDICATION OF FACILITIES
Any undertaking by either Party under any provision of
this Agreement is rendered strictly as an accommodation and
shall not constitute the dedication by the first Party of any
part or all of its Electric System to the other, the public,
or any Third Party. Any such undertaking by any Party under a
provision of, or resulting from, this Agreement shall cease
upon the termination of that Party's obligations under this
Agreement.
29 NO OBLIGATION TO OFFER SAME SERVICE TO OTHERS
By entering into this Agreement to interconnect with NCPA
or any Third Party at NCPA's request, and filing it with FERC,
59
PG&E does not commit itself to furnish any like or similar
undertaking to any other person or entity.
30 NO PRECEDENT
This Agreement establishes no precedent with regard to
any other entity or agreement. Nothing contained in this
Agreement shall establish any rights to or precedent for other
arrangements as may exist, now or in future, between PG&E and
NCPA for the provision of any interconnection arrangements or
any form of electric service.
31 NO TRANSMISSION, DISTRIBUTION, POWER, ENERGY SALES OR
ANCILLARY SERVICES PROVIDED
Neither Party undertakes under this Agreement to provide
or make available any transmission service, distribution
service, power energy sales or services or Ancillary Services
for the other Party or any Third Party.
32 NOTICES
32.1 Written Notices
Any notice, request, declaration, demand,
information, report, or item otherwise required, authorized or
provided for in this Agreement shall be given in writing,
except as otherwise provided in this Agreement, and shall be
deemed properly given if delivered personally or by facsimile
M
transmission (fax), or sent by first class United States Mail
or overnight or express mail service, postage or fees prepaid,
to each of the persons specified below:
(1) To NCPA:
And
General Manager
Northern California Power Agency
180 Cirby Way
Roseville, CA 95678
Assistant General Manager, Power Contracts
Northern California Power Agency
180 Cirby Way
Roseville, CA 95678
(2) To PG&E:
Senior Vice President, Utility Operations
Pacific Gas and Electric Company
77 Beale Street, Room 3237, B32
P.O. Box 770000
San Francisco, CA 94177
With a copy to:
Director, Interconnection Services Department
Pacific Gas and Electric Company
77 Beale Street, Room 1355, B13J
P.O. Box 770000
San Francisco, CA 94177
32.2 Changes Of Notice Recipient
Either Party may change its designation of the
person who is to receive notices on its behalf by giving the
other Party notice thereof in the manner provided in this
Section 32. No more than two persons shall be designated by a
Party to receive notices.
61
32.3 Routine Notices
Any notice of a routine character in connection
with service under this Agreement or in connection with the
operation of facilities shall be given in such a manner as the
Parties may determine is appropriate from time to time, unless
otherwise provided in this Agreement.
32.4 Reliance On Notice
Each Party shall be entitled under this Agreement
to rely on the other Party's notice when given (or not given,
when a Party fails to provide notice within the time
prescribed) as having all necessary approvals of that other
Party's management, Board of Directors or other governing
body, and any notice (or failure to provide timely notice)
hereunder shall be binding on the noticing Party and shall
obligate that Party to make such payments or to perform such
duties as are necessarily associated with the notice or, if a
Party fails to provide timely notice, that failure to give
notice.
33 RESERVATION OF RIGHTS
Nothing contained herein shall be construed as affecting
in any way the Parties rights under Sections 205 and 206 of
the FPA or the regulations promulgated there under. The term
"rates" as used herein shall mean a statement of rates and
charges for or in connection with the services provided for in
62
this Agreement, and all classifications, practices, rules or
regulations which in any manner affect or relate to such,
rates and charges. PG&E may unilaterally made application to
FERC for a change in rates, including rate methodology and the
terms and conditions of service, under Section 205 of the FPA
and pursuant to FERC's rules and regulations promulgated
thereunder. Either party may seek changes to the terms of this
Agreement pursuant to Section 206 of the FPA. Nothing
contained herein shall be construed as affecting in any way
the right of NCPA to oppose such a change under Section 205 or
FERC's rules and regulations or to exercise its rights under
Section 206 of the FPA or FERC's rules and regulations.
34 RESPONSIBILITY FOR PAYMENTS
Both Parties shall be fully responsible and liable to
each other for payments to be made under this Agreement. The
Parties shall perform unconditionally and fully each and every
obligation which each has under this Agreement; provided, that
this Agreement shall not restrict any right either Party may
otherwise have to pledge any of its revenues, funds, assets,
rights, property or interests therein. The other Party's
status as a creditor shall not be subordinate to the interest
of any creditor, subject to any pledge or debt obligation,
provision of law or existing obligations of a Party.
63
35 RULES AND REGULATIONS
PG&E and NCPA, acting through the E&O Committee, may each
propose, from time to time, changes to such procedures, rules,
or regulations as they shall determine are necessary in order
to establish the methods of operation to be followed in the
performance of this Agreement or requirements of the Control
Area Operator; provided, that any such procedure, rule, or
regulation shall not be inconsistent with the provisions of
this Agreement. If a Party objects to a procedure, rule, or
regulation proposed by the other Party, it will notify the
other Party and the Parties will endeavor to modify the
procedure, rule, or regulation in order to resolve the
objection. No such procedure, rule or regulation shall be
adopted absent the mutual written consent of the Parties.
36 SEVERABILITY
If any term, covenant or condition of this Agreement or
its application is held to be invalid as to any person, entity
or circumstance, by FERC or any other regulatory body, or
agency or court of competent jurisdiction, then such term,
covenant or condition shall cease to have force and effect to
the extent of that holding. In that event, however, all other
terms, covenants and conditions of this Agreement and their
application shall not be affected thereby, but shall remain in
full force and effect unless and to the extent that a
64
regulatory agency or court of competent jurisdiction finds
that a provision is not separable from the invalid
provision(s) of this Agreement.
37 CONTINUING RIGHTS OF NCPA UPON TERMINATION
Upon termination of the Agreement, NCPA shall continue to
have such rights, if any, to be connected to PG&E's Electric
System that are provided by law, regulation or other contract
or agreement; provided, that the existence of this Agreement,
after its termination, shall not be used by either Party to
establish or defeat the existence of any rights provided by
law, regulation or other contract or agreement. Termination
of this Agreement, if accepted or approved by FERC, also shall
terminate any other tariff or rate schedule which in whole or
in part results from this Agreement, to the extent not
inconsistent with a Party's aforementioned rights at law.
After termination of this Agreement and any required FERC
acceptance or approval of such termination, all obligations
and rights provided under this Agreement or such tariff or
rate schedule shall cease, and neither Party shall claim or
assert any continuing right other than as may be provided by
law, regulation or other contract or agreement. Such
termination shall not affect rights and obligations of a
continuing nature or for payment of money for goods or
services provided prior to termination. This Section shall
65
not be construed as a bar to the assertion by NCPA of any
rights it may have to service following termination of this
Agreement, independent and exclusive of the Agreement.
38 RIGHTS OF PG&E UPON TERMINATION
Should FERC deny, condition, suspend or defer PG&E's
notice of termination, PG&E shall under no circumstances be
required to maintain any interconnections or to provide any
services, based in whole or in part on the existence of this
Agreement, beyond the minimum time necessary for compliance
with FERC's denial, condition, suspension or deferral.
39 UNCONTROLLABLE FORCES
A Party shall not be considered to be in default in the
performance of any obligation under the Agreement (other than
an obligation to make payments for bills previously rendered
pursuant to the Agreement) when a failure of performance is
the result of Uncontrollable Forces.
40 WAIVER OF RIGHTS
Any waiver at any time by any Party of its rights with
respect to a default under the Agreement, or with respect to
any other matter arising in connection with the Agreement,
shall not constitute or be deemed a waiver with respect to any
subsequent default or other matter arising in connection with
the Agreement. Any delay, short of the statutory period of
limitations, in asserting or enforcing any right shall not
constitute or be deemed a waiver.
41 ENTIRE AGREEMENT; AMENDMENTS
This Agreement is intended to be the complete and
exclusive statement of the terms of the Parties' agreement
which supersedes all prior and contemporaneous offers,
promises, representations, negotiations, discussions or
communications that may have been made in connection with the
subject matter of this Agreement. No representation,
covenant, or other matter, oral or written, which is not
expressly set forth, incorporated, or referenced in this
Agreement (except for applicable laws and regulations) shall
be a part of, modify, or affect this Agreement. This
Agreement may be modified by written agreement of the Parties.
42 NO THIRD PARTY RIGHTS OR OBLIGATION
No right or obligation contained in this Agreement shall
be applied or used for the benefit of any person or entity not
a Party.
43 WARRANTY OF AUTHORITY
Each Party warrants and represents that this Agreement
has been duly authorized, executed and delivered by such Party
67
and constitutes the legal, valid and binding obligation of
such Party, enforceable against such Party in accordance with
its terms, except as enforcement may be limited by bankruptcy,
insolvency, reorganization, or similar laws effecting the
enforcement of creditor's rights and subject to equitable
principles.
44 EXECUTION
Executed this 12th day of July, 2002 but effective as set
forth above.
-V
NORTHERN CALIFORNIA POWER AGENCY
NCPA
By:
Name:
Title:
As authorized on behalf of the NCPA Members whose
Individual signatures may be added later.
PACIFIC GAS AND ELECTRIC COMPANY
By:
Name:
Title:
CITY OF ALAMEDA
(attest) By
Authorized Representative
CITY OF BIGGS
(attest) By
Authorized Representative
CITY OF GRIDLEY
(attest) By
Authorized Representative
C•
(attest)
CITY OF HEALDSBURG
By
Authorized Representative
CITY OF LODI
(attest) By
Authorized Representative
01
Approved as to fro xf
fZ .
CITY OF LOMPOC ICRY Attorney
(attest) By
Authorized Representative
CITY OF PALO ALTO
(attest) By
Authorized Representative
CITY OF UKIAH
(attest) By
Authorized Representative
PLUMAS-SIERRA RURAL
ELECTRIC COOPERATIVE
(attest) By
Authorized Representative
70
Appendix A
POINTS) OF INTERCONNECTION
Appendix A
POINTS OF INTERCONNECTION
(a)
(b)
(c)
NCPA Member
Customer
Delivery Point
Voltage
(kV)
Alameda
Substation C and/or Substation J
115
Biggs
Biggs Sub
60
Gridley
Gridley Sub
60
Healdsburg
Healdsburg Sub
60
Lodi
Industrial Sub/White Slough
60/12
Lompoc
Lompoc Sub
115
Palo Alto
Palo Alto Sub
115
Plumas-Sierra
Quincy Sub
60
Ukiah
(a)
Ukiah Sub
(b)
115
NCPA Resources
Point of Receipt
Geo Plant 1
Geo Plant 2
Lakeville
Collierville
Bellota
Alameda CTs
Substation C and/or
Substation J
Roseville CTs
Western
Lodi CT
Industrial
Graegle Hydro Project
Quincy Sub
STIG
NCPA STIG Substation
Appendix B
DISPUTE RESOLUTION AND ARBITRATION
Appendix B
DISPUTE RESOLUTION AND ARBITRATION
B.1 NEGOTIATION AND MEDIATION
As provided in Section 23, the Parties agree to seek
settlement of all disputes arising under this Agreement by
good faith negotiation before resorting to other methods of
dispute resolution. In the event that negotiations have
failed, but before initiating arbitration proceedings under
this Appendix B, the Parties may by mutual assent decide to
seek resolution of a dispute through mediation. If this
occurs, the Parties shall meet and confer to establish an
appropriate timetable for mediation, to pick a mediator, and
to decide on any other terms and conditions that will govern
the mediation.
B.2 TECHNICAL ARBITRATION
The Parties agree that it is in the best interest of both
Parties to seek expedited resolution of arbitrable disputes
that are technical in nature. Technical disputes may include,
without limitation, disputes centered on engineering issues
involving technical planning studies, the need for and Cost of
Upgrade Facilities, and the Interconnection Capacity of a
Point of Interconnection. Such technical issues may be
resolved through expert application of established technical
B-1
knowledge and by reference to Good Utility Practice and
industry standards.
The Party initiating arbitration pursuant to Section B.3
below shall indicate in its notice to the other Party whether
it regards the dispute to be technical in nature. If both
Parties agree that a dispute is technical in nature, then the
Parties shall meet and confer to develop an appropriate
timetable and process for expedited resolution of the dispute
by a neutral expert, or "technical arbitrator". If the
Parties cannot agree that a dispute is technical in nature, or
if they cannot agree on a neutral arbitrator, then the Parties
may submit the dispute to arbitration under the procedures set
forth in Appendix B, Section 3 below.
B.3 ARBITRATION
B.3.1 Notices And Selection Of Arbitrators
In the event that a dispute is subject to
arbitration under Section 23, the aggrieved Party shall
initiate arbitration by sending written notice to the other
Party. Such notice shall identify the name and address of an
impartial person to act as an arbitrator. If either party
takes the position that the dispute is not arbitrable, either
party may take the dispute to FERC for resolution. Within ten
(10) business days after receipt of such notice, the other
Party shall, if it agrees that the decision is properly
arbitrable, give a similar written notice stating the name and
B-2
address of the second impartial person to act as an
arbitrator. Each Party shall then submit to the two named
arbitrators a list of the names and addresses of at least
three persons for use by the two named arbitrators in the
selection of the third arbitrator. If the same name or names
appear on both lists, the two named arbitrators shall appoint
one of the persons named on both lists as the third
arbitrator. If no name appears on both lists, the two named
arbitrators shall select a third arbitrator from either list
or independently of either list. Each arbitrator selected
under these procedures shall be a person experienced in the
construction, design, operation or regulation of electric
power transmission facilities, as applicable to the issue(s)
in dispute.
B.4 PROCEDURES
Within fifteen (15) business days after the appointment
of the third arbitrator, or on such other date to which the
parties may agree, the arbitrators shall meet to determine the
procedures that are to be followed in conducting the
arbitration, including, without limitation, such procedures as
may be necessary for the taking of discovery, giving testimony
and submission of written arguments and briefs to the
arbitrators. Unless otherwise mutually agreed by the parties,
the arbitrators shall determine such procedures based upon the
purpose of the Parties in conducting an arbitration under
B-3
Section 23 of the Agreement, specifically, the purpose of
utilizing the least burdensome, least expensive and most
expeditious dispute resolution procedures consistent with
providing each Party with a fair and reasonable opportunity to
be heard. If the arbitrators are unable unanimously to agree
to the procedures to be used in the arbitration, the
arbitration shall be governed by the Commercial Arbitration
Rules of the American Arbitration Association.
B.5 HEARING AND DECISION
After giving the Parties due notice of hearing and a
reasonable opportunity to be heard, the arbitrators shall hear
the dispute(s) submitted for arbitration and shall render
their decision with ninety (90) calendar days after
appointment of the third arbitrator or such other date
selected upon the mutual agreement of the Parties. The
arbitrators' decision shall be made in writing and signed by
any two of the three arbitrators. The decision shall be final
and binding upon the parties subject to rights to appeal the
decision to FERC. Judgment may be entered on the decision in
any court of competent jurisdiction upon the application of
either Party.
B-4
B.6 EXPENSES
Each Party shall bear its own costs and the costs and
expenses of the arbitrators shall be borne equally by the
parties.
B-5
Appendix C
UPGRADE FACILITIES
Appendix C
C.1 UPGRADE FACILITIES
At least 60 calendar days prior to the date on which NCPA
is to commence payment of any Cost as a result of construction
of an Upgrade Facility, as agreed upon in accordance with
section 7.3 of this Agreement, PG&E shall determine and
provide to NCPA: (i) an estimate of all Cost, broken down by
major activities, which PG&E expects to incur; and (ii) a
schedule indicating the approximate dates when PG&E expects to
pay such Cost for each major activity included in the
estimate. PG&E may revise the payment schedule from time to
time as appropriate.
C.1.2 If needed, the Parties will enter into a
Special Facilities Agreement which shall include an estimate
and schedule of Cost and payments as provided by Appendix C,
Section 1, and NCPA shall advance such Cost to PG&E pursuant
to such schedule or any revisions to it.
C.1.3 NCPA's total payments to PG&E for work
performed under this Appendix C, Section 1.3 shall be for the
actual Cost incurred by PG&E. PG&E shall document to NCPA the
actual Cost incurred upon completion, and shall refund any
amount overpaid by, or request any additional payment from,
NCPA, with interest computed as provided in Appendix D,
Section D.6 of this Agreement.
C-1
C.1.4 Should NCPA seek a ruling from the Internal
Revenue Service that NCPA's payments under this subsection
should be treated as non-taxable contributions -in -aid -of -
construction, PG&E shall cooperate reasonably with NCPA in
supporting NCPA's filing with the Internal Revenue Service.
C.1.5 NCPA shall have the right pursuant to Section
15 to review the supporting documents upon which PG&E bases
its estimate of the Cost of work to be advanced by NCPA
pursuant to the Special Facility Agreement, as well as
documents that show the actual Cost incurred by PG&E.
C.2 ASSOCIATED FERC FILINGS
If required by FERC or requested by NCPA, PG&E shall
file, or at its election may file, with FERC a Special
Facility Agreement to document and seek approval of any Cost
charged by PG&E to NCPA associated with any facility
modifications, changes, reinforcements or advances
contemplated by this Agreement. NCPA shall support this
filing by an appropriate submittal to FERC stating its
agreement with the charges; provided, that if the Parties are
unable to agree on the need for an Upgrade Facility or the
Cost of an Upgrade Facility or the amount thereof NCPA shall
be responsible for, NCPA may oppose such PG&E filing.
C-2
Appendix D
BILLING AND PAYMENT
C.3 LIMITATIONS ON RESPONSIBILITY FOR UPGRADE COSTS
C.3.1 No Double Collection
PG&E may not charge NCPA for any Costs
associated with Upgrade Facilities that have already been or
will be collected through rates paid by PG&E retail or
wholesale customers or from a Third Party; provided, that this
Section shall not preclude PG&E charging NCPA where refunds
are made to those who originally paid for such Costs.
C-3
at:
Appendix D
BILLING AND PAYMENT
NCPA shall pay PG&E Costs owed pursuant to this Agreement
Pacific Gas and Electric Company
Payment Processing Center
Research Unit / BSA
P.O. Box 770000
San Francisco, CA 94177
PG&E may change the place where payment is made by giving NCPA
notice thereof as provided in Section 32.
D.1 PG&E shall prepare and submit bills to NCPA on or
after the first business day of each calendar month. The
Payment of any bill shall be due and must be received by PG&E
not later than the 30th calendar day following the day on
which NCPA receives the bill or, if that 30th day is a
Saturday, Sunday or legal holiday, the next business day.
Such date shall be referred to as the Payment Due Date. A
bill shall be deemed delivered on the third business day after
the postmarked date unless a copy of the bill is sent by
electronic facsimile, in which case it shall be deemed
delivered on the same day.
D.2 If charges under this Agreement cannot be determined
accurately for preparing a bill, PG&E may use its best
estimates in preparing the bill and such estimated bill shall
be paid by NCPA. Any estimated charges shall be labeled as
such and PG&E shall, upon request, document the basis for the
D-1
estimate used. Estimated bills shall be prepared and paid in
the same manner as other bills under this Agreement.
D.3 If NCPA disputes all or any portion of a bill
submitted by PG&E to NCPA, it nevertheless shall, not later
than the Payment Due Date of that bill, pay the bill in full.
A dispute between either PG&E or NCPA and any Third Party
shall not be a proper basis for withholding payment. Payments
to PG&E of NCPA's obligations arising under this Agreement are
not subject to any reduction, whether by offset, payments into
escrow, or otherwise, except for routine adjustments or
corrections as may be agreed to by the Parties or as expressly
provided in this Agreement.
D.4 When final and complete billing information becomes
available and a charge is determined accurately or billing
errors are identified and corrected, PG&E shall promptly
prepare and submit an adjusted bill to NCPA, and any
additional payments by NCPA shall be made in accordance with
the provisions of this Section D.4. Refunds by PG&E shall be
paid to NCPA not later than thirty (30) calendar days after
the date of the adjusted bill. All adjustments or corrections
of bills under this Agreement shall be subject to the interest
provisions of paragraphs D.5 and D.6.
D.5 Interest on an additional payment shall accrue from
the Payment Due Date of the applicable bill and interest on a
refund shall accrue from the date payment of the applicable
D-2
bill was received by PG&E.
D.6 Any amount due under this Agreement which is not
timely paid shall accrue interest from the date prescribed in
Appendix D, Section 5 until the date payment is made. The
interest amount shall be determined using the interest rate
applicable to any amount due during a given month and shall be
calculated using the methodology for refunds pursuant to
Section 35.19(a) of FERC's Regulations, 18 C.F.R § 35.19(a).
This interest rate shall not exceed the maximum interest rate
permitted under California law. Interest shall be calculated
for the period during which the payment is overdue or the
period during which the refund is accruing interest.
D.7 As provided in Appendix D, Section 3, if any portion
of a bill is disputed, NCPA shall pay the full amount, without
offset or reduction, by the Payment Due Date, however, NCPA
can challenge the accuracy of a bill even if no dispute was
identified prior to NCPA's payment of the bill and such right
to dispute a bill shall extend to the end of the statutory
period of limitations. In addition, NCPA shall, on or before
the Payment Due Date, notify PG&E, in writing, of the amount
in dispute and the specific basis for the dispute. PG&E and
NCPA shall endeavor to resolve any billing dispute within
thirty (30) calendar days of PG&E's receipt of NCPA's notice
of a dispute (or such extended period as the Parties may
establish). If the Parties cannot agree, either Party may
D-3
initiate dispute resolution pursuant to Section 23.
D.8 If, after NCPA has paid the full amount of a
disputed bill directly to PG&E, the results of dispute
resolution pursuant to Section 23 include a determination that
the amount due was different than the amount paid by NCPA, a
refund by PG&E to NCPA shall include interest for the period
from the date NCPA's overpayment was received by PG&E to the
date the refund is paid to NCPA. Likewise, an additional
payment by NCPA to PG&E shall include interest for the period
from the original Payment Due Date to the date NCPA's
additional payment is received by PG&E. Interest paid
pursuant to this Appendix D, Section 8 shall be at the rate
determined pursuant to Appendix D, Section 6.
D.9 A Party's failure to make any payment on or before
the applicable Payment Due Date shall constitute a material
breach of this Agreement if that failure is not corrected
within seven (7) business days after the other Party delivers
written notice to non-paying Party. In such event, the Party
not receiving payment shall be entitled to pursue any legal,
equitable and regulatory rights and remedies it may have under
this Agreement or otherwise.
D-4
Appendix E
OPERATIONAL COORDINATION
Appendix E
OPERATIONAL COORDINATION
The Parties will perform operational coordination
obligations and responsibilities, which consist of but
are not limited to the following:
E.1 Maintenance Coordination
The Parties shall coordinate, in conformance with their
obligations to the Control Area Operator, on an annual
basis, any maintenance outages of transmission facilities
of their respective systems that may reasonably be
expected to have an impact on the other Party's system.
E.2 Underfrequency Load Shedding (UFLS)
The Underfrequency Load Shedding Schedule shall be
updated from time to time, in conformance with the
obligations of the Parties to the Control Area Operator,
as determined by the E&O Committee.
E.3 Manual Load Sheddin
The Parties agree, in conformance with their obligations
to the Control Area Operator, to implement their
respective manual load shedding programs in a coordinated
manner as system conditions warrant. Any modification to
either Party's manual load shedding program shall be
coordinated through the Parties' E&O Committee.
EA Load Restoration
The Parties shall, in conformance with their obligations
to the Control Area Operator, coordinate the restoration
of load following a system disturbance and agree to do so
in coordination with the Control Area Operator when
required.
E.5 Records, Information and Reports
The Parties' E&O Committee shall agree to required
records, information and reports to be shared between
Parties and shall include, but not be limited to; (i)
records of kW and kVar demands, and kWh for each Point
Interconnection; (ii) transmission outage information
that may reasonably be expected to impact the other
Party; and (iii) provide reports on any transmission
outages that impacted the other Party.
E-1
the
of
EA Reactive Power
The Parties shall maintain reactive power flow at the
transmission Points of Interconnection within the power
factor band set by the Control Area Operator, currently
of 0.97 lag and 0.99 lead. Both Parties will normally
operate their respective systems to minimize War
exchange between them. Operating conditions may require
larger than normal War exchange between both Parties and
any such exchange will be done in accordance with Good
Utility Practice.
E.7 Critical Protective Systems
Should a Party's critical protective system(s) condition
change in such a way as to possibly compromise the safe
and reliable operation of its electric system and such
compromise may reasonably be expected to affect the other
Party, that Party shall notify the Control Area Operator,
and the other as soon as is reasonably practicable to do
SO.
E-2
UNDERFREQUENCY LOAD SHEDDING SCHEDULE
This schedule shall be identical with Schedule 11 -Emergency
Action Plan Attachment A of the NCPA MSS Aggregator Agreement,
which is included by reference herein.
E-3
RESOLUTION NO. 2002-182
A RESOLUTION OF THE LODI CITY COUNCIL
AUTHORIZING THE CITY MANAGER TO EXECUTE NCPA
SCHEDULE COORDINATION SERVICE AGREEMENT
BETWEEN THE CITY OF LODI AND NCPA; AND PG&E
REPLACEMENT INTERCONNECTION AGREEMENT
WITH PG&E AND NCPA AND OTHER CITY MEMBERS
NOW, THEREFORE, BE IT RESOLVED that the Lodi City Council does hereby
authorize the City Manager to execute the following two agreements on behalf of the City
of Lodi:
1) NCPA Schedule Coordination Service Agreement between the City and
NCPA; and
2) PG&E Replacement Interconnection Agreement with PG&E and NCPA and
other City members.
Dated: August 21, 2002
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I hereby certify that Resolution No. 2002-182 was passed and adopted by the City
Council of the City of Lodi in a regular meeting held August 21, 2002, by the following
vote:
AYES:
COUNCIL MEMBERS — Hitchcock, Howard, Land, and Nakanishi
NOES:
COUNCIL MEMBERS — None
ABSENT:
COUNCIL MEMBERS — None
ABSTAIN:
COUNCIL MEMBERS — Mayor Pennino
SUSAN J. B�CKSTON
City Clerk
2002-182