NEW ENGLAND POWER POOL
RESTATED NEW ENGLAND POWER POOL AGREEMENT
FERC ELECTRIC THIRD REVISED RATE SCHEDULE NO. 5
(As amended through the Sixty-Ninth Agreement
Amending New England Power Pool Agreement)
TABLE OF CONTENTS SHEET NO.
PART ONE INTRODUCTION
SECTION 1 DEFINITIONS 1.1 Accepted Electric Industry Practice 1.2 Adjusted Load
1.3 Adjusted Monthly Peak 1.4 Adjusted Net Interchange 1.5 Administrative
Procedures 1.6 AGC Capability 1.7 AGC Entitlement 1.8 Agreement 1.9 Annual
Transmission Revenue Requirements 1.10 Automatic Generation Control or AGC 1.11
Balloting Agent 1.12 Bid Price 1.13 Bilateral Transaction 1.14 Clearing Price
1.15 CMS 1.16 CMS/MSS Effective Date 1.17 Commission 1.18 Congestion 1.19
Congestion Component 1.20 Congestion Cost 1.21 Congestion Revenue 1.22
Congestion Revenue Fund 1.23 Control Area 1.24 Curtailment 1.25 Day-Ahead 1.26
Day-Ahead Market 1.27 Demand Bid 1.28 Demand Bid Price 1.29 Direct Assignment
Facilities 1.30 Dispatch Day 1.31 Dispatchable Load 1.32 Dispatch Price 1.33
Distribution Company 1.34 Distribution Company Load Zone 1.35 EHV PTF 1.36
Electrical Load 1.37 Eligible Customer 1.38 End User Behind-the-Meter Generation
1.39 End User Organization 1.40 End User Participant 1.41 Energy 1.42 Energy
Entitlement 1.43 Entitlement 1.44 Entity 1.45 Excepted Transaction 1.46 External
Node 1.47 Facilities Study 1.48 FCR 1.49 Financial Congestion Right 1.50 Firm
Contract 1.51 First Effective Date 1.52 Governance Only Member 1.53 HQ Contracts
1.54 HQ Energy Banking Agreement 1.55 HQ Interconnection 1.56 HQ Interconnection
Agreement 1.57 HQ Interconnection Capability Credit 1.58 HQ Interconnection
Transfer Capability 1.59 HQ Net Interconnection Capability Credit 1.60 HQ Phase
I Energy Contract 1.61 HQ Phase I Percentage 1.62 HQ Phase I Transfer Credit
1.63 HQ Phase II Firm Energy Contract 1.64 HQ Phase II Gross Transfer
Responsibility 1.65 HQ Phase II Net Transfer Responsibility 1.66 HQ Phase II
Percentage 1.67 HQ Phase II Transfer Credit 1.68 HQ Use Agreement 1.69 Hub 1.70
Hub Price 1.71 Installed Capability 1.72 Installed Capability Entitlement 1.73
Installed Capability Responsibility 1.74 Installed System Capability 1.75
Interchange Transactions 1.76 Internal Point-to-Point Service 1.77 Interruption
1.78 ISO 1.79 Kilowatt 1.80 Large End User 1.81 Liaison Committee 1.82 Load 1.83
Load Asset Contract 1.84 Load Zone 1.85 Local Network 1.86 Local Network Service
1.87 Location 1.88 Locational Price 1.89 Lost Opportunity Cost 1.90 Lower
Voltage PTF 1.91 Marginal Loss 1.92 Marginal Loss Component 1.93 Marginal Loss
Revenue 1.94 Marginal Loss Revenue Fund 1.95 Market Products 1.96 Market Rules
1.97 Markets Committee 1.98 Megawatt 1.99 Monthly 1.100 MSS 1.101 NEPOOL 1.102
NEPOOL Control Area 1.103 NEPOOL Installed Capability 1.104 NEPOOL Installed
Capability Responsibility 1.105 NEPOOL Objective Capability 1.106 NEPOOL Market
1.107 NEPOOL System Rules 1.108 NEPOOL Transmission System 1.109 NERC 1.110 {Net
Hourly Load Obligation for Energy 1.111 New Unit 1.112 No-Load Price 1.113 Nodal
Price 1.114 Node 1.115 Non-Participant 1.116 NPCC 1.117 OASIS 1.118 Operable
Capability 1.119 Operating Reserve 1.120 Operating Reserve Entitlement 1.121
Other HQ Energy 1.122 Participant 1.123 Participants Committee 1.124
Pool-Planned Facility 1.125 Pool-Planned Unit 1.126 Power Year 1.127 Prior
NEPOOL Agreement 1.128 Proxy Unit 1.129 PTF 1.130 Publicly Owned Entity 1.131
Real-Time 1.132 Real-Time Market 1.133 Reference Node 1.134 Regional Network
Service 1.135 Related Person 1.136 Reliability Committee 1.137 Reliability
Standards 1.138 Reliability Must Run 1.139 Reliability Region 1.140 {Reserve
Contract 1.141 {Reserve Price 1.142 Resource 1.143 Review Board43 1.144 RMR
1.145 RMR Charge 1.146 RMR Uplift 1.147 Scheduled Dispatch Period 1.148 Second
Effective Date 1.149 Sector 1.149A Self-Schedule 1.149B Self-Supply 1.150
Service Agreement 1.151 Settlement Obligation 1.152 Shift Factor 1.153 Small End
User 1.154 Standard Offer Obligation 1.155 Start-Up Price 1.156 Summer
Capability 1.157 Summer Period 1.158 Supply Obligation 1.159 Supply Offer 1.160
Supply Offer Price 1.161 System Contract 1.162 System Impact Study 1.163 System
Operator 1.164 Target Availability Rate 1.165 Tariff 1.166 Tariff Committee
1.167 Technical Committees 1.168 Third Effective Date 1.169 Through or Out
Service 1.170 Transition Period 1.171 Transmission Customer 1.172 Transmission
Owner 1.173 Transmission Owners Committee 1.174 Transmission Provider 1.175 Unit
Contract 1.176 Withdrawal Factor 1.177 Winter Capability 1.178 Winter Period
1.179 Zonal Price 1.180 4-Hour Reserve 1.181 4-Hour Reserve Entitlement 1.182
10-Minute Spinning Reserve 1.183 10-Minute Non-Spinning Reserve 1.184 30-Minute
Operating Reserve 1.185 Modification of Certain Definitions When a Participant
Purchases a Portion of Its Requirements from Another Participant Pursuant to
Firm Contract
SECTION 2 PURPOSE; EFFECTIVE DATES
2.1 Purpose
2.2 Effective Dates; Transitional Provisions
SECTION 3 MEMBERSHIP
3.1 Membership
3.2 Operations Outside the Control Area
3.3 Lack of Place of Business in New England
3.4 Obligation for Deferred Expenses
3.5 Financial Security
SECTION 4 STATUS OF PARTICIPANTS
4.1 Treatment of Certain Entities as Single Participant
4.2 Participants to Retain Separate Identities
SECTION 5 NEPOOL OBJECTIVES AND COOPERATION BY PARTICIPANTS
5.1 NEPOOL Objectives
5.2 Cooperation by Participants
PART TWO GOVERNANCE
SECTION 6 COMMITTEE ORGANIZATION AND VOTING 6.1 Principal Committees 6.2 Sector
Representation 6.3 Appointment of Members and Alternates 6.4 Term of Members 6.5
Regular and Special Meetings 6.6 Notice of Meetings 6.7 Attendance 6.8 Quorum
6.9 Voting Definitions 6.10 Voting On Proposed Actions 6.11 Voting On Amendments
6.12 Designated Representatives and Proxies 6.13 Limits on Representatives 6.14
Adoption of Bylaws 6.15 Joint Meetings of Technical Committees
SECTION 7 PARTICIPANTS COMMITTEE
7.1 Officers
7.2 Adoption of Budgets
7.3 Establishing Reliability Standards
7.4 Appointment and Compensation of NEPOOL Personnel
7.5 Duties and Authority
7.6 Attendance of Participants at Committee Meeting
7.7 Appeal of Actions to Review Board
SECTION 8 RELIABILITY COMMITTEE
8.1 Officers
8.2 Notice to Members and Alternates of Participants Committee
8.3 Voting; Appeal of Actions
8.4 Responsibilities
8.5 Establishment of Subcommittees and Task Forces
8.6 Further Powers and Duties
SECTION 9 TARIFF COMMITTEE
9.1 Officers
9.2 Notice to Members and Alternates of Participants Committee
9.3 Voting; Appeal of Actions
9.4 Responsibilities
9.5 Establishment of Subcommittees and Task Forces
9.6 Further Powers and Duties
SECTION 10 MARKETS COMMITTEE
10.1 Officers
10.2 Notice to Members and Alternates of Participants Committee 10.3 Voting;
Appeal of Actions 10.4 Responsibilities 10.5 Establishment of Subcommittees and
Task Forces 10.6 Further Powers and Duties 10.7 Development of Rules Relating to
Non-Participant Supply and Demand-side Resources
SECTION 11 FURTHER RESTRUCTURING
SECTION 11A REVIEW BOARD 11A.1 Organization 11A.2 Composition 11A.3
Qualifications 11A.4 Term 11A.5 Meetings 11A.6 Bylaws
11A.7 Procedure on Appeal of Participant Committee Action or Failure
to Take Action
11A.8 Effect of a Review Board Decision
11A.9
11A.10
11A.11
SECTION 11B TRANSMISSION OWNERS COMMITTEE 11B.1 Organization 11B.2 Membership
11B.3 Appointment of Members and Alternates 11B.4 Term of Members 11B.5 Regular
and Special Meetings 11B.6 Notice of Meetings 11B.7 Attendance 11B.8 Votes 11B.9
Appointment of Task Forces or Working Groups 11B.10 Officers 11B.11 Adoption of
Bylaws 11B.12 Review of Committee Actions
SECTION 11C LIAISON COMMITTEE 11C.1 Organization; Duties 11C.2 Membership 11C.3
Regular and Special Meetings 11C.4 Notice of Meetings 11C.5 Attendance 11C.6
Officers
PART THREE MARKET PROVISIONS
SECTION 12 INSTALLED CAPABILITY OBLIGATIONS AND PAYMENTS 12.0 Continuing
Reliability Measures 12.1 Obligations to Provide Installed Capability 12.2
Computation of Installed Capability Responsibilities
12.3 [Deleted.]
12.4 [Deleted.]
12.5 Consequences of Deficiencies in Installed Capability Responsibility
12.6 [Deleted]
12.7 Payments to Participants Furnishing Installed Capability
SECTION 13 OPERATION, GENERATION, OTHER RESOURCES, AND INTERRUPTIBLE CONTRACTS
13.1 Maintenance and Operation in Accordance with Accepted Electric Industry
Practice 13.2 Central Dispatch 13.3 Maintenance and Repair 13.4 Objectives of
Day-to-Day System Operation 13.5 Satellite Membership
SECTION 14 INTERCHANGE TRANSACTIONS
14.1 Obligation for Energy, Operating Reserve and Automatic Generation Control
14.2 Obligation to Bid or Schedule, and Right to Receive Energy, Operating
Reserve and Automatic Generation Control 14.3 Amount of Energy, Operating
Reserve and Automatic Generation Control Received or Furnished 14.4 Payments by
Participants Receiving Energy Service, Operating Reserve and Automatic
Generation Control 14.5 Payments to Participants Furnishing Energy Service,
Operating Reserve, and Automatic Generation Control 14.6 Energy Transactions
with Non-Participants 14.7 Participant Purchases Pursuant to Firm Contracts and
System Contracts 14.8 Determination of Energy Clearing Price 14.9 Determination
of Operating Reserve Clearing Price 14.10 Determination of AGC Clearing Price
14.11 Funds to or from which Payments are to be Made 14.12 Development of Rules
Relating to Nuclear and Hydroelectric Generating Facilities, Limited-Fuel
Generating Facilities, and Interruptible Loads 14.13 Dispatch and Billing Rules
During Energy Shortages 14.14 Congestion Uplift 14.14A CMS/MSS Implementation
Studies Related to Congestion 14.15 Additional Uplift Charges
SECTION 14A PARTICIPANT MARKET TRANSACTIONS ON AND AFTER THE CMS/MSS EFFECTIVE
DATE 14A.1 Supply Obligations and Settlement Obligations for Energy, Operating
Reserve, 4-Hour Reserve and Automatic Generation Control 14A.2 Right to Receive
Service 14A.3 Participation in the Day-Ahead Market 14A.4 Nature of Demand Bids
and Supply Offers; Limitations; Self-Schedules and Self-Supplies 14A.5
Scheduling Procedures in the Day-Ahead Market 14A.6 Participation in the
Real-Time Market 14A.7 Scheduling Procedures in the Real-Time Market 14A.8
Settlement Obligation Payments for Energy, Operating Reserves, 4-Hour Reserves
and Automatic Generation Control 14A.9 Supply Obligation Payments For Energy,
Operating Reserves, 4-Hour Reserves and Automatic Generation Control 14A.10
Contract and Scheduling Authority 14A.11 Bilateral Transactions and Participant
Transactions with Non- Participants 14A.12 Determination of Locational Prices
14A.13 Determination of Operating Reserve and 4-Hour Reserve Clearing Prices
14A.14 Determination of AGC Clearing Price 14A.15 Funds to or from which
Payments are to Be Made 198WW14A.16 Marginal Losses 14A.17 Congestion Cost and
Revenues 14A.18 Market Monitoring and Reports 14A.19 Additional Uplift
ChargesPART FOUR TRANSMISSION PROVISIONS
SECTION 15 OPERATION OF TRANSMISSION FACILITIES
15.1 Definition of PTF
15.2 Maintenance and Operation in Accordance with Accepted Electric Industry
Practice
15.3 Central Dispatch
15.4 Maintenance and Repair
15.5 Additions to or Upgrades of PTF
SECTION 16 SERVICE UNDER TARIFF
16.1 Effect of Tariff
16.2 Obligation to Provide Regional Service
16.3 Obligation to Provide Local Network Service
16.4 Transmission Service Availability
16.5 Transmission Information
16.6 Distribution of Transmission Revenues
SECTION 17 POOL-PLANNED UNIT SERVICE
17.1 Effective Period
17.2 Obligation to Provide Service
17.3 Rules for Determination of Facilities Covered by Particular Transactions
17.4 Payments for Uses of EHV PTF During the Transition Period
17.5 Payments for Uses of Lower Voltage PTF
17.6 Use of Other Transmission Facilities by Participants
17.7 Limits on Individual Transmission Charges
SECTION 17A TRANSMISSION OWNERS RESERVED RIGHTS
17A.1
17A.2
17A.3
17A.4
17A.5
17A.6
17A.7
17A.8
PART FIVE GENERAL
SECTION 18 GENERATION AND TRANSMISSION FACILITIES 18.1 Designation of
Pool-Planned Facilities 18.2 Construction of Facilities
18.3 Protective Devices for Transmission Facilities and Automatic Generation
Control Equipment
18.4 Review of Participant's Proposed Plans
18.5 Participant to Avoid Adverse Effect
SECTION 19 EXPENSES
19.1 Annual Fee
19.2 NEPOOL Expenses
19.3 Restructuring Costs
SECTION 20 INDEPENDENT SYSTEM OPERATOR
SECTION 21 MISCELLANEOUS PROVISIONS
21.1 Alternative Dispute Resolution
21.2 Payment of Pool Charges; Termination of Status as Participant 21.3
Assignment 21.4 Force Majeure 21.5 Waiver of Defaults 21.6 Other Contracts 21.7
Liability and Insurance 21.8 Records and Information 21.9 Consistency with NPCC
and NERC Standards 21.10 Construction 21.11 Amendment 21.12 Termination 21.13
Notices to Participants, Committees, Committee Members, or the System Operator
21.14 Severability and Renegotiation 21.15 No Third-Party Beneficiaries 21.16
Counterparts
ATTACHMENT A METHODOLOGY FOR DETERMINATION OF TRANSMISSION FLOWS
ATTACHMENT B NEPOOL OPEN ACCESS TRANSMISSION TARIFF
ATTACHMENT C RELIABILITY REGIONS
THIS AGREEMENT dated as of the first day of September, 1971, as amended, was
entered into by the signatories thereto for the establishment by them of a bulk
power pool to be known as NEPOOL and is restated by an amendment dated as of
December 1, 1996 and amended by subsequent amendments.
In consideration of the mutual agreements and undertakings herein, the
signatories hereby agree as follows:
PART ONE
INTRODUCTION
SECTION 1
DEFINITIONS
Whenever used in this Agreement, in either the singular or the plural number,
the terms contained in this Section shall have the meanings set forth herein. If
a term is identified in this Section with an asterisk (*), the definition may be
modified in certain cases pursuant to the last subsection of this Section 1. If
a term includes language in brackets ([ ]), such language shall become effective
automatically on the CMS/MSS Effective Date. Certain definitions are included in
braces ({ }). These definitions are still subject to further modification or
deletion and will not become effective except pursuant to a further Commission
order. To the extent appropriate to reflect the understandings of this
introductory text, future composite copies of this Agreement may remove brackets
([]), and braces ({ }), and part or all of this explanatory introductory
language, and may renumber the definitions, without further specific amendment
to or restatement of this Agreement.
1.1 Accepted Electric Industry Practice shall mean any of the practices,
methods, and acts engaged in or approved by a significant portion of the
electric utility industry during the relevant time period, or any of the
practices, methods, and acts which, in the exercise of reasonable judgement in
light of the facts known at the time the decision was made, could have been
expected to accomplish the desired result at a reasonable cost consistent with
good business practices, reliability, safety and expedition. Accepted Electric
Industry Practice is not limited to a single, optimum practice method or act to
the exclusion of others, but rather is intended to include acceptable practices,
methods, or acts generally accepted in the region.
1.2 Adjusted Load * (not less than zero) of a Participant during any particular
hour is the Participant's Load during such hour less any Kilowatts received (or
Kilowatts which would have been received except for the application of Section
14.7(b)) by such Participant pursuant to a Firm Contract.
1.3 Adjusted Monthly Peak of a Participant for a month is its Monthly Peak,
provided that if there has been a transfer between Participants, in whole or
part, of the responsibilities under this Agreement during such month pursuant to
a Firm Contract, the Adjusted Monthly Peak of each such Participant shall
reflect the effect of such transaction, but the Adjusted Monthly Peak of a
Participant shall not be changed from the Monthly Peak to reflect the effect of
any other transaction.
1.4 Adjusted Net Interchange of a Participant for an hour is (a) the Kilowatts
produced by or delivered to the Participant from its Energy Entitlements or
pursuant to arrangements entered into under Section 14.6, as adjusted in
accordance with Market Rules approved by the Markets Committee to take account
of associated electrical losses, as appropriate, minus (b) the sum of (i) the
Electrical Load of the Participant for the hour, and (ii) the kilowatthours
delivered by such Participant to other Participants pursuant to Firm Contracts
or System Contracts, in accordance with the treatment agreed to pursuant to
Section 14.7(a), together with any associated electrical losses. This section
shall terminate and be of no further force and effect after final settlement
with respect to services rendered until the CMS/MSS Effective Date.
1.5 Administrative Procedures are procedures adopted by the System Operator in
order to fulfill its responsibilities to apply and implement NEPOOL System
Rules.
1.6 AGC Capability of an electric generating unit or combination of units is the
maximum dependable ability of the unit or units to increase or decrease the
level of output within a time frame specified by Market Rules approved by the
Markets Committee, in response to a remote direction from the System Operator in
order to maintain currently proper power flows into and out of the NEPOOL
Control Area and to control frequency.
1.7 AGC Entitlement is the right for the purposes of settlement to all or a
portion of the AGC Capability of a generating unit or units to which an Entity
is entitled as an owner (either sole or in common) or as a purchaser under a
Unit Contract, reduced by any portion thereof which such Entity is selling
pursuant to a Unit Contract. An AGC Entitlement in a generating unit or units
may, but need not, be combined with any other Entitlements relating to such
generating unit or units and may be transferred separately from the related
Installed Capability Entitlement, Energy Entitlement[, 4-Hour Reserve
Entitlement] or Operating Reserve Entitlement.
1.8 Agreement is this restated contract and attachments, including the Tariff,
as amended and restated from time to time.
1.9 Annual Transmission Revenue Requirements of a Participant's PTF or of all
Participants' PTF for purposes of this Agreement are the amounts determined in
accordance with Attachment F to the Tariff.
1.10 Automatic Generation Control or AGC is a measure of the ability of a
generating unit or portion thereof to respond automatically within a specified
time to a remote direction from the System Operator to increase or decrease the
level of output in order to control frequency and to maintain currently proper
power flows into and out of the NEPOOL Control Area.
1.11 Balloting Agent is the Secretary of the Participants Committee.
1.12 Bid Price is the amount which a Participant offers to accept, in a notice
furnished to the System Operator by it or on its behalf in accordance with the
Market Rules approved by the Markets Committee, as compensation for (i)
furnishing Installed Capability to other Participants pursuant to this
Agreement, or (ii) preparing the start up or starting up or increasing the level
of operation of, and thereafter operating, a generating unit or units to provide
Energy to other Participants pursuant to this Agreement, or (iii) having a unit
or units available to provide Operating Reserve to other Participants pursuant
to this Agreement, or (iv) having a unit or units available to provide AGC to
other Participants pursuant to this Agreement, or (v) providing to other
Participants Installed Capability, Energy, Operating Reserve and/or AGC pursuant
to a Firm Contract or System Contract in accordance with Section 14.7. This
definition shall terminate and be of no further force and effect after final
settlement with respect to services rendered before the CMS/MSS Effective Date.
1.13 Bilateral Transaction is a transaction, including a Firm Contract, System
Contract, Load Asset Contract or other contract, between two or more
Participants submitted for the transfer of Settlement Obligations in accordance
with the Market Rules with respect to Installed Capability, Energy at one or
more Locations within the NEPOOL Control Area, Operating Reserve[, 4-Hour
Reserve] and/or AGC. When used in the plural form, it may be any or all such
arrangements or combinations thereof, as the context requires.
1.14 Clearing Price is the amount determined for Energy, Operating Reserve and
AGC pursuant to Sections 14.8, 14.9 and 14.10, respectively, until the CMS/MSS
Effective Date, and thereafter pursuant to Sections 14A.8(a), 14A.8(b) and
14A.8(c), respectively.
1.15 CMS is the Congestion management system under the NEPOOL arrangements,
including Locational Prices for Energy and Financial Congestion Rights.
1.16 CMS/MSS Effective Date is the date on which the provisions of Section 14A
shall become fully effective and supersede the provisions of Section 14. The
CMS/MSS Effective Date shall be a date fixed by the Participants Committee which
occurs after NEPOOL System Rules and computer programs to fully implement
Section 14A of the Agreement and Schedules 13, 14 and 15 of the Tariff are in
place and at least thirty (30) days have elapsed since the Participants
Committee has provided notice to the Commission of the proposed CMS/MSS
Effective Date.
1.17 Commission is the Federal Energy Regulatory Commission.
1.18 Congestion is a condition of the NEPOOL Transmission System in which
transmission limitations prevent unconstrained regional economic dispatch of the
power system. Following the CMS/MSS Effective Date, Congestion is the condition
that results in the Congestion Component of the Locational Price at one Location
being different from the Congestion Component of the Locational Price at another
Location during any given hour of the Dispatch Day in the Day-Ahead Market and
Real-Time Market.
1.19 Congestion Component is the component of the Nodal Price that reflects the
marginal cost of Congestion at a given Node or External Node relative to the
Reference Node. When used in connection with Zonal Price and Hub Price, the term
Congestion Component refers to the Congestion Components of the Nodal Prices
that comprise the Zonal Price and Hub Price averaged or weighted in the same way
that Nodal Prices are averaged or weighted to determine the Zonal Price and Hub
Price, respectively.
1.20 Congestion Cost is the cost of Congestion as defined in Section 14.14 of
the Agreement and Section 24 of the Tariff for services until the CMS/MSS
Effective Date. On and after the CMS/MSS Effective Date, Congestion Cost is the
cost of Congestion as measured by the difference between the Congestion
Components of the Locational Prices at different Locations and/or Reliability
Regions on the NEPOOL Transmission System.
1.21 Congestion Revenue for each hour is the surplus revenue, if any, for each
hour after netting the revenues paid and collected for the Congestion Components
of Locational Price for all Energy transactions on the NEPOOL Transmission
System, including Energy deliveries by Non-Participant Transmission Customers
taking service under the Tariff, as settled in accordance with the Market Rules.
Congestion Revenue is calculated for each hour of the Dispatch Day in the
Day-Ahead Market and Real-Time Market as provided in Section E of Schedule 14 of
the Tariff and the applicable Market Rules.
1.22 Congestion Revenue Fund is the fund of Congestion Revenue administered by
the System Operator in accordance with Section 14A.17 of the Agreement,
Schedules 13 and 14 of the Tariff, and the applicable Market Rules.
1.23 Control Area is an electric power system or combination of electric power
systems to which a common automatic generation control scheme is applied in
order to:
(i) match, at all times, the power output of the generators within the electric
power system(s) and capacity and energy purchased from entities outside the
electric power system(s), with the load within the electric power system(s);
(ii) maintain scheduled interchange with other Control Areas, within the limits
of Accepted Electric Industry Practice;
(iii) maintain the frequency of the electric power system(s) within reasonable
limits in accordance with Accepted Electric Industry Practice and the criteria
of the applicable regional reliability council or the NERC; and
(iv) provide sufficient generating capacity to maintain operating reserves in
accordance with Accepted Electric Industry Practice.
1.24 Curtailment is a reduction in firm or non-firm transmission service in
response to a transmission capacity shortage as a result of system reliability
conditions.
1.25 Day-Ahead is the calendar day immediately preceding a Dispatch Day for
which Participants submit Demand Bids and Supply Offers in accordance with
applicable Market Rules and the System Operator schedules Resources for Energy,
Operating Reserve, 4-Hour Reserve and AGC in accordance with applicable NEPOOL
System Rules.
1.26 Day-Ahead Market is the market provided for in Section 14A and conducted in
the calendar day immediately preceding a Dispatch Day in which Energy, Operating
Reserve, 4-Hour Reserve and AGC are scheduled for a Dispatch Day, based on the
Day-Ahead Demand Bids and Supply Offers and applicable NEPOOL System Rules.
1.27 Demand Bid is a proposal by a Participant to receive and pay for Energy, at
a specified Location and at a specified Demand Bid Price, that is submitted to
the System Operator pursuant to the Agreement and applicable Market Rules, and
includes information with respect to the quantity to be received and paid for
and other matters complying with the Market Rules.
1.28 Demand Bid Price is the price specified by a Participant to the System
Operator in a Demand Bid for Energy at a specified Location.
1.29 Direct Assignment Facilities are facilities or portions of facilities that
are Non-PTF and are constructed for the sole use/benefit of a particular
Transmission Customer requesting service under the Tariff or Generator Owner
requesting an interconnection. Direct Assignment Facilities shall be specified
in a separate agreement with the Transmission Provider whose transmission system
is to be modified to include and/or interconnect with said Facilities, shall be
subject to applicable Commission requirements and shall be paid for by the
Transmission Customer or a Generator Owner in accordance with the separate
agreement and not under the Tariff.
1.30 Dispatch Day is the period beginning at the minute ending 0001 and ending
at 2400 each day.
1.31 Dispatchable Load is any portion of the Electrical Load of a Participant
that meets the requirements of the Market Rules to qualify as Operating Reserve
or 4-Hour Reserve or to have its Energy consumption modified in Real-Time
because of its ability to respond to remote dispatch instructions from the
System Operator. A Demand Bid to receive and pay for Energy at an External Node
shall, if scheduled, be considered a Dispatchable Load for the purposes of the
Day-Ahead Market and the Real-Time Market.
1.32 Dispatch Price of a generating unit or combination of units, or a Firm
Contract or System Contract permitted to be bid to supply Energy in accordance
with Section 14.7(b) until the CMS/MSS Effective Date or permitted to be
included in a Supply Offer for Energy in accordance with 14A.11(b) on and after
the CMS/MSS Effective Date, is the price to provide Energy from the unit or
units or Firm Contract or System Contract, as determined pursuant to the Market
Rules to incorporate the Bid Price or Supply Offer Price, as appropriate, for
such Energy and any loss adjustments, if and as appropriate under applicable
Market Rules.
1.33 Distribution Company has the meaning specified in Section 14A.12(b).
1.34 Distribution Company Load Zone has the meaning specified in Section
14A.12(b).
1.35 EHV PTF are PTF transmission lines which are operated at 230 kV or above
and related PTF facilities, including transformers which link other EHV PTF
facilities, but do not include transformers which step down from 230 kV or a
higher voltage to a voltage below 230 kV.
1.36 Electrical Load (in Kilowatts) of a Participant during any particular hour
is the total during such hour (eliminating any distortion arising out of (i)
Interchange Transactions, or (ii) transactions across the system of such
Participant, or (iii) deliveries between Entities constituting a single
Participant, or (iv) other electrical losses, if and as appropriate), of
(a) kilowatthours provided by such Participant to its retail customers for
consumption, plus
(b) kilowatthours of use by such Participant, plus
(c) kilowatthours of electrical losses and unaccounted for use by the
Participant on its system, plus
(d) kilowatthours used by such Participant for pumping Energy for its
Entitlements in pumped storage hydroelectric generating facilities, plus
(e) kilowatthours delivered by such Participant to Non-Participants, plus
(f) kilowatthours of Electrical Load responsibility incurred due to a transfer
from another Participant pursuant to a Load Asset Contract for Electrical Load,
minus
(g) kilowatthours of Electrical Load responsibility transferred to another
Participant pursuant to a Load Asset Contract for Electrical Load. The
Electrical Load of a Participant may be calculated in any reasonable manner
which substantially complies with this definition.
1.37 Eligible Customer is the following: (i) Any Participant that is engaged, or
proposes to engage, in the wholesale or retail electric power business is an
Eligible Customer under the Tariff. (ii) Any electric utility (including any
power marketer), Federal power marketing agency, or any other entity generating
electric energy for sale or for resale is an Eligible Customer under the Tariff.
Electric energy sold or produced by such entity may be electric energy produced
in the United States, Canada or Mexico. However, with respect to transmission
service that the Commission is prohibited from ordering by Section 212(h) of the
Federal Power Act, such entity is eligible only if the service is provided
pursuant to a state requirement that the Transmission Provider with which that
entity is directly interconnected offer the unbundled transmission service, or
pursuant to a voluntary offer of such service by the Transmission Provider with
which that entity is directly interconnected. (iii) Any end user taking or
eligible to take unbundled transmission service pursuant to a state requirement
that the Transmission Provider with which that end user is directly
interconnected offer the transmission service, or pursuant to a voluntary offer
of such service by the Transmission Provider with which that end user is
directly interconnected, is an Eligible Customer under the Tariff.
1.38 End User Behind-the-Meter Generation is generation that has all three of
the following attributes: (a) it is owned by a Governance Only Member; and (b)
it is used to meet that Governance Only Member's load or, for any hour in which
the output of the End User Behind-the-Meter Generation owned by the Governance
Only Member exceeds its Electrical Load, another Participant which is not a
Governance Only Member is obligated under tariff or contract to report such
excess to the ISO pursuant to applicable Market Rules; and (c) it is delivered
to the Governance Only Member without the use of PTF or another Entity's
transmission or distribution facilities.
1.39 End User Organization is an End User Participant which is (a) a registered
tax-exempt non-profit organization with (i) an organized board of directors and
(ii) a membership (A) of at least 100 Entities that buy electricity at wholesale
or retail in the New England states or (B) with an aggregate peak monthly demand
(non-coincident) for load in New England, including load served by End User
Behind-the-Meter Generation, of at least ten (10) megawatts or (b) a
municipality or other governmental agency located in New England which does not
meet the definition of Publicly Owned Entity.
1.40 End User Participant is a Participant which is a consumer of electricity in
the NEPOOL Control Area that generates or purchases electricity primarily for
its own consumption or a non-profit group representing such consumers.
1.41 Energy is electrical energy, measured in kilowatthours or
megawatthours.
1.42 Energy Entitlement is a right for purposes of settlement to all or a
portion of the electric output of a generating unit at the Node where such unit
is interconnected to the NEPOOL Transmission System to which an Entity is
entitled as an owner (either sole or in common) or as a purchaser pursuant to a
Unit Contract, reduced by any portion thereof which such Entity is selling
pursuant to a Unit Contract. An Energy Entitlement in a generating unit or units
may, but need not, be combined with any other Entitlements relating to such
generating unit or units and may be transferred separately from the related
Installed Capability Entitlement, Operating Reserve Entitlements[, 4-Hour
Reserve Entitlement] or AGC Entitlement.
1.43 Entitlement is an Installed Capability Entitlement, Energy Entitlement,
Operating Reserve Entitlement[, 4-Hour Reserve Entitlement] or AGC Entitlement.
When used in the plural form, it may be any or all such Entitlements or
combinations thereof, as the context requires.
1.44 Entity is any person or organization whether the United States of America
or Canada or a state or province or a political subdivision thereof or a duly
established agency of any of them, a private corporation, a partnership, an
individual, an electric cooperative or any other person or organization
recognized in law as capable of owning property and contracting with respect
thereto that is either:
(a) engaged in the electric power business (the generation and/or transmission
and/or distribution of electricity for consumption by the public or the
purchase, as a principal or broker, of Installed Capability, Energy, Operating
Reserve, [4-Hour Reserve] and/or AGC for resale); or
(b) a consumer of electricity in the NEPOOL Control Area that generates or
purchases electricity primarily for its own consumption or a non-profit group
representing such consumers.
1.45 Excepted Transaction is a transaction specified in Section 25 of the Tariff
for the applicable period specified in that Section, or in Sections 25A and 25B
of the Tariff.
1.46 External Node is a bus or buses used for establishing a Locational Price
for Energy received by Participants from, or delivered by Participants to, a
neighboring Control Area.
1.47 Facilities Study is an engineering study conducted pursuant to this
Agreement or the Tariff by the System Operator and/or one or more affected
Participants to determine the required modifications to the NEPOOL Transmission
System, including the cost and scheduled completion date for such modifications,
that will be required to provide a requested transmission service or
interconnection.
1.48 FCR is a Financial Congestion Right.
1.49 Financial Congestion Right is a financial instrument that evidences the
rights and obligations specified in Schedule 14 of the Tariff.
1.50 Firm Contract is any contract, other than a Unit Contract, for the purchase
of Installed Capability, Energy [at a Location], Operating Reserves[, 4-Hour
Reserves] and/or AGC, pursuant to which the purchaser's right to receive such
Installed Capability, Energy, Operating Reserves[, 4- Hour Reserves] and/or AGC
is subject only to the supplier's inability to satisfy its obligations
thereunder as the result of events beyond the supplier's reasonable control.
1.51 First Effective Date is March 1, 1997.
1.52 Governance Only Member is an End User Participant that participates in
NEPOOL for governance purposes only and elects to be a Governance Only Member
before its application is approved by NEPOOL.
1.53 HQ Contracts are the HQ Interconnection Agreement, the HQ Phase I Energy
Contract, and the HQ Phase II Firm Energy Contract.
1.54 HQ Energy Banking Agreement is the Energy Banking Agreement entered into on
March 21, 1983 by Hydro-Quebec, the Participants, New England Electric
Transmission Corporation and Vermont Electric Transmission Company, Inc., as it
may be amended from time to time.
1.55 HQ Interconnection is the United States segment of the transmission
interconnection which connects the systems of Hydro-Quebec and the Participants.
"Phase I" is the United States portion of the 450 kV HVDC transmission line from
a terminal at the Des Cantons Substation on the Hydro- Quebec system near
Sherbrooke, Quebec to a terminal having an approximate rating of 690 MW at a
substation at the Comerford Generating Station on the Connecticut River. "Phase
II" is the United States portion of the facilities required to increase to
approximately 2000 MW the transfer capacity of the HQ Interconnection, including
an extension of the HVDC transmission line from the terminus of Phase I at the
Comerford Station through New Hampshire to a terminal at the Sandy Pond
Substation in Massachusetts. The HQ Interconnection does not include any PTF
facilities installed or modified to effect reinforcements of the New England AC
transmission system required in connection with the HVDC transmission line and
terminals.
1.56 HQ Interconnection Agreement is the Interconnection Agreement entered into
on March 21, 1983 by Hydro-Quebec and the Participants, as it may be amended
from time to time.
1.57 HQ Interconnection Capability Credit of a Participant for a month during
the Base Term (as defined in Section 1.63) of the HQ Phase II Firm Energy
Contract is the sum in Kilowatts of (1)(a) the Participant's percentage share,
if any, of the HQ Phase I Transfer Capability times (b) the HQ Phase I Transfer
Credit, plus (2)(a) the Participant's percentage share, if any, of the HQ Phase
II Transfer Capability, times (b) the HQ Phase II Transfer Credit. The
Participants Committee shall establish appropriate HQ Interconnection Capability
Credits to apply for a Participant which has such a percentage share (i) during
an extension of the HQ Phase II Firm Energy Contract, and (ii) following the
expiration of the HQ Phase II Firm Energy Contract.
1.58 HQ Interconnection Transfer Capability is the transfer capacity of the HQ
Interconnection under normal operating conditions, as determined in accordance
with Accepted Electric Industry Practice. The "HQ Phase I Transfer Capability"
is the transfer capacity under normal operating conditions, as determined in
accordance with Accepted Electric Industry Practice, of the Phase I terminal
facilities as determined initially as of the time immediately prior to Phase II
of the Interconnection first being placed in service, and as adjusted thereafter
only to take into account changes in the transfer capacity which are independent
of any effect of Phase II on the operation of Phase I. The "HQ Phase II Transfer
Capability" is the difference between the HQ Interconnection Transfer Capability
and the HQ Phase I Transfer Capability. Determinations of, and any adjustment
in, transfer capacity shall be made by the Markets Committee in accordance with
a schedule consistent with that followed by it in its determination of the
Winter Capability and Summer Capability of generating units.
1.59 HQ Net Interconnection Capability Credit of a Participant at a particular
time is its HQ Interconnection Capability Credit at the time in Kilowatts, minus
a number of Kilowatts equal to (1) the percentage of its share of the HQ
Interconnection Transfer Capability committed or used by it for an "Entitlement
Transaction" at the time under the HQ Use Agreement, times (2) its HQ
Interconnection Capability Credit for the current month.
1.60 HQ Phase I Energy Contract is the Energy Contract entered into on March 21,
1983 by Hydro-Quebec and the Participants, as it may be amended from time to
time.
1.61 HQ Phase I Percentage is the percentage of the total HQ Interconnection
Transfer Capability represented by the HQ Phase I Transfer Capability.
1.62 HQ Phase I Transfer Credit is 60/69 of the HQ Phase I Transfer Capability,
or such other fraction of the HQ Phase I Transfer Capability as the Participants
Committee may establish.
1.63 HQ Phase II Firm Energy Contract is the Firm Energy Contract dated as of
October 14, 1985 between Hydro-Quebec and certain of the Participants, as it may
be amended from time to time. The "Base Term" of the HQ Phase II Firm Energy
Contract is the period commencing on the date deliveries were first made under
the Contract and ending on August 31, 2000.
1.64 HQ Phase II Gross Transfer Responsibility of a Participant for any month
during the Base Term of the HQ Phase II Firm Energy Contract (as defined in
Section 1.63) is the number in Kilowatts of (a) the Participant's percentage
share, if any, of the HQ Phase II Transfer Capability for the month times (b)
the HQ Phase II Transfer Credit. Following the Base Term of the HQ Phase II Firm
Energy Contract, and again following the expiration of the HQ Phase II Firm
Energy Contract, the Participants Committee shall establish an appropriate HQ
Phase II Gross Transfer Responsibility that shall remain in effect concurrently
with the HQ Interconnection Capability Credit.
1.65 HQ Phase II Net Transfer Responsibility of a Participant for any month is
its HQ Phase II Gross Transfer Responsibility for the month minus a number of
Kilowatts equal to (1) the highest percentage of its share of the HQ
Interconnection Transfer Capability committed or used by it on any day of the
month for an "Entitlement Transaction" under the HQ Use Agreement, times (2) its
HQ Phase II Gross Transfer Responsibility for the month.
1.66 HQ Phase II Percentageis the percentage of the total HQ Interconnection
Transfer Capability represented by the HQ Phase II Transfer Capability.
1.67 HQ Phase II Transfer Credit is 90/131 of the HQ Phase II Transfer
Capability, or such other fraction of the HQ Phase II Transfer Capability as the
Participants Committee may establish.
1.68 HQ Use Agreement is the Agreement with Respect to Use of Quebec
Interconnection dated as of December 1, 1981 among certain of the Participants,
as amended and restated as of September 1, 1985 and as it may be further amended
from time to time.
1.69 Hub is a specific set of pre-defined Nodes, approved by the Participants
Committee, for which a Locational Price will be calculated and which can be used
to establish a reference price for Energy purchases and the transfer of
Settlement Obligations for Energy and for the designation of FCRs in accordance
with Schedule 14 of the Tariff.
1.70 Hub Price in each hour of the Dispatch Day in the Day-Ahead Market and the
Real-Time Market is the price used for Energy purchases and Settlement
Obligations for Energy which are treated as being transferred at a Hub in the
hour. Hub Prices are calculated in accordance with Section 14A.12 of the
Agreement and Schedule 13 of the Tariff.
1.71 Installed Capability of an electric generating unit or combination of units
during the Winter Period is the Winter Capability of such unit or units and
during the Summer Period is the Summer Capability of such unit or units.
1.72 Installed Capability Entitlement is (a) the right to all or a portion of
the Installed Capability of a generating unit or units to which an Entity is
entitled as an owner (either sole or in common) or as a purchaser pursuant to a
Unit Contract, (b) reduced by any portion thereof which such Entity is selling
pursuant to a Unit Contract, and (c) further reduced or increased, as
appropriate, to recognize rights to receive or obligations to supply Installed
Capability pursuant to Firm Contracts or System Contracts in accordance with
Section 14.7(a). An Installed Capability Entitlement relating to a unit or units
may, but need not, be combined with any other Entitlements relating to such
generating unit or units and may be transferred separately from the related
Energy Entitlement, Operating Reserve Entitlements, or AGC Entitlement.
1.73 Installed Capability Responsibility * of a Participant for any month is the
number of Kilowatts determined in accordance with Section 12.2.
1.74 Installed System Capability of a Participant at a particular time is (i)
the sum of such Participant's Installed Capability Entitlements plus (ii) its HQ
Net Interconnection Capability Credit at the time.
1.75 Interchange Transactions are transactions deemed to be effected under
Section 12 of the Prior NEPOOL Agreement prior to the Second Effective Date, and
transactions deemed to be effected under Section 14 of this Agreement on and
after the Second Effective Date.
1.76 Internal Point-to-Point Service is the transmission service by that name
provided pursuant to Section 19 of the Tariff.
1.77 Interruption
(a) Until the CMS/MSS Effective Date, Interruption is a reduction in non- firm
transmission service due to economic reasons pursuant to Section 28.7 of the
Tariff, other than a reduction which results from a failure to dispatch a
generating resource, including a contract, used in a transaction requiring
Through or Out Service which is out of merit order.
(b) On and after the CMS/MSS Effective Date, Interruption is a reduction in
non-firm transmission service due to economic reasons pursuant to Section 28.7
of the Tariff, other than a reduction which results from a failure to dispatch a
generating resource, including a Supply Offer or a Demand Bid at an External
Node, used in a transaction requiring Through or Out Service which is out of
merit order.
1.78 ISO is the Independent System Operator which is responsible for the
continued operation of the NEPOOL Control Area from the NEPOOL control center
and the administration of the Tariff, subject to regulation by the Commission.
1.79 Kilowatt is a kilowatthour per hour.
1.80 Large End User is an End User Participant which is considered for this
purpose to be (a) a single end user with a peak monthly demand (non- coincident)
for load in New England, including load served by End User Behind-the-Meter
Generation, of at least one (1) megawatt, or (b) a group of two or more
corporate entities each with a peak monthly demand (non- coincident) for load in
New England, including load served by End User Behind-the-Meter Generation, of
at least 0.35 megawatts that together totals at least one (1) megawatt.
1.81 Liaison Committee is the committee whose responsibilities are specified
in Section 11C.
1.82 Load * (in Kilowatts) of a Participant during any particular hour is the
total during such hour (eliminating any distortion arising out of (i)
Interchange Transactions, or (ii) transactions across the system of such
Participant, or (iii) deliveries between Entities constituting a single
Participant, or (iv) other electrical losses, if and as appropriate) of
(a) kilowatthours provided by such Participant to its retail customers for
consumption (excluding any kilowatthours which may be classified as
interruptible under Market Rules approved by the Markets Committee), plus
(b) kilowatthours delivered by such Participant pursuant to Firm Contracts
to its wholesale customers for resale, plus
(c) kilowatthours of use by such Participant, exclusive of use by such
Participant for the operation and maintenance of its generating unit or
units, plus
(d) kilowatthours of electrical losses and unaccounted for use by the
Participant on its system.
The Load of a Participant may be calculated in any reasonable manner which
substantially complies with this definition.
For the purposes of calculating a Participant's Annual Peak, Adjusted Monthly
Peak, Adjusted Annual Peak and Monthly Peak, the Load of a Participant shall be
adjusted to eliminate any distortions resulting from voltage reductions. In
addition, upon the request of any Participant, the Markets Committee shall make,
or supervise the making of, appropriate adjustments in the computation of Load
for the purposes of calculating any Participant's Annual Peak, Adjusted Monthly
Peak, Adjusted Annual Peak and Monthly Peak to eliminate any distortions
resulting from emergency load curtailments which would significantly affect the
Load of any Participant.
1.83 Load Asset Contract is a transaction for the transfer of responsibility for
Electrical Load (and may include Electrical Load qualifying as Dispatchable
Load), Installed Capability, or the rights to compensation for Operating Reserve
to the extent the transfer relates to Dispatchable Load, the terms of which
shall conform to the requirements of applicable Market Rules.
1.84 Load Zone is a Reliability Region, except as otherwise provided in Section
14A.12(b) of the Agreement and Schedule 13 of the Tariff.
1.85 Local Network is the transmission facilities constituting a local network
identified on Attachment E to the Tariff, and any other local network or change
in the designation of a Local Network as a Local Network which the Participants
Committee may designate or approve from time to time. The Participants Committee
may not unreasonably withhold approval of a request by a Participant that it
effect such a change or designation.
1.86 Local Network Service is the service provided, under a separate tariff or
contract, by a Participant that is a Transmission Provider to another
Participant, or other entity connected to the Transmission Provider's Local
Network to permit the other Participant or entity to efficiently and
economically utilize its resources to serve its load.
1.87 Location is a Node, External Node, Load Zone, or Hub.
1.88 Locational Price is the price of Energy at a Location or Reliability
Region, calculated in accordance with Section 14A.12 of the Agreement and
Schedule 13 of the Tariff. The Locational Price for a Node is the Nodal Price at
that Node; the Locational Price for an External Node is the Nodal Price at that
External Node; the Locational Price for a Load Zone or Reliability Region is the
Zonal Price for that Load Zone or Reliability Region, respectively; and the
Locational Price for a Hub is the Hub Price for that Hub.
1.89 Lost Opportunity Cost is the amount determined for a Resource, other than a
Dispatchable Load, in accordance with Section 14A.13(d).
1.90 Lower Voltage PTF are all PTF facilities other than EHV PTF.
1.91 Marginal Loss is the additional Energy required to overcome transmission
losses or the decrease in Energy consumed through losses on the NEPOOL
Transmission System associated with serving a small increment of demand at a
Node or External Node. The cost of Marginal Losses at each Location, relative to
the cost of Marginal Losses at the Reference Node, is reflected in the Marginal
Loss Component of the Locational Price at that Location.
1.92 Marginal Loss Component is the component of the Nodal Price at a given Node
or External Node that reflects the Marginal Loss at that Node or External Node.
When used in connection with Hub Price or Zonal Price, the term Marginal Loss
Component refers to the Marginal Loss Components of the Nodal Prices that
comprise the Hub Price or Zonal Price, which Marginal Loss Components are
averaged or weighted in the same way that Nodal Prices are averaged or weighted
to determine the Hub Price and Zonal Price, respectively.
1.93 Marginal Loss Revenue for each hour is the surplus revenue, if any, that is
collected by the System Operator after netting payments for Energy under
Sections 14A.8 and 14A.9, and subtracting Congestion Revenue, as settled in
accordance with the Market Rules.
1.94 Marginal Loss Revenue Fund is the fund of Marginal Loss Revenue
administered by the System Operator in accordance with Section 14A.16 of the
Agreement, Schedule 13 of the Tariff, and the applicable Market Rules.
1.95 Market Products are Installed Capability, Operable Capability, Energy,
each category of Operating Reserve and AGC.
1.96 Market Rules are the system rules and operating procedures adopted pursuant
to the System Operator Agreement in connection with the administration of the
NEPOOL Market.
1.97 Markets Committee is the committee whose responsibilities are specified in
Section 10 and which may have additional responsibilities under a proper
delegation of authority by the Participants Committee. To the extent
practicable, references in the Agreement to the Markets Committee shall include
the prior Regional Market Operations Committee as the predecessor of the Markets
Committee.
1.98 Megawatt is a measure of the rate at which Energy is produced and is equal
to a megawatthour per hour. Use of the term Megawatt shall be construed to
include fractional Megawatts.
1.99 Monthly Peak of a Participant for a month is the maximum Adjusted Load of
the Participant during any hour in the month.
1.100 MSS is the multi-settlement system provided for in Section 14A.
1.101 NEPOOL is the New England Power Pool, the power pool created under and
governed by this Agreement, and the Entities collectively participating in the
New England Power Pool as Participants.
1.102 NEPOOL Control Area is the integrated electric power system to which a
common Automatic Generation Control scheme and various operating procedures are
applied by or under the supervision of the System Operator in order to:
(i) match, at all times, the power output of the generators within the electric
power system and capacity and Energy purchased from entities outside the
electric power system, with the load within the electric power system;
(ii) maintain scheduled interchange with other interconnected systems, within
the limits of Accepted Electric Industry Practice;
(iii) maintain the frequency of the electric power system within reasonable
limits in accordance with Accepted Electric Industry Practice and the criteria
of the NPCC and NERC; and
(iv) provide sufficient generating capacity to maintain operating reserves in
accordance with Accepted Electric Industry Practice.
1.103 NEPOOL Installed Capability at any particular time is the sum of the
Installed System Capabilities of all Participants at such time.
1.104 NEPOOL Installed Capability Responsibility for any month is the sum of the
Installed Capability Responsibilities of all Participants during that month.
1.105 NEPOOL Objective Capability for any year or period during a year is the
minimum NEPOOL Installed Capability, treating the reliability benefits of the HQ
Interconnection as Installed Capability, as established by the Participants
Committee, required to be provided by the Participants in aggregate for the
period to meet the reliability standards established by the Participants
Committee pursuant to Section 7.5(e).
1.106 NEPOOL Market is the market for electric energy, capacity and certain
ancillary services within the NEPOOL Control Area.
1.107 NEPOOL System Rules are the Market Rules, the NEPOOL Information Policy,
the Administrative Procedures, the Reliability Standards and any other system
rules, procedures or criteria for the operation of the NEPOOL System and
administration of the NEPOOL Market, the NEPOOL Agreement and the NEPOOL Tariff.
1.108 NEPOOL Transmission System is the system of transmission facilities
defined as PTF.
1.109 NERCis the North American Electric Reliability Council.
1.110 {Net Hourly Load Obligation for Energy ("NHLO") of a Participant for an
hour is an amount equal to (i) the Participant's Electrical Load for the hour,
(ii) plus or minus, as appropriate, the Settlement Obligations for Energy which
the Participant transfers to or assumes from another Participant pursuant to a
Bilateral Transaction (other than a Load Asset Contract already reflected in the
determination of the Participant's Electrical Load) in which the quantity of
Settlement Obligation for Energy transferred from the Participant purchaser to
the Participant seller thereunder is expressed in terms of a percentage (with or
without an optional cap on the total transfer) of the Participant purchaser's
Energy obligation, where the obligation is calculated as the Electrical Load of
the Participant purchaser less megawatthours of Energy sales by the Participant
purchaser to Non- Participants. The Bilateral Transaction identified in (ii)
includes a transaction which is submitted in accordance with Market Rule 4,
Appendix 4- D, "Internal Obligation Transfer Contracts" and is described in the
second bullets of Market Rule 12, Appendix 12-A-1, Sections B.IIa.4 and D.II.a4,
as such Market Rules were in effect on December 31, 1999.}
1.111 New Unit is an electric generating unit (including a unit or units owned
by a Non-Participant in which a Participant has an Entitlement under a Unit
Contract) first placed into commercial operation after May 1, 1987 (or, in the
case of a unit or units owned by a Non-Participant, in which a Participant's
Unit Contract Entitlement became effective after May 1, 1987) and not listed on
Exhibit B to the Prior NEPOOL Agreement.
1.112 No-Load Price is the price, in dollars per hour, for a generating unit
that must be paid to Participants with Energy Entitlements in the unit for being
scheduled in the Day-Ahead Market, in addition to the Start-Up Price and Supply
Offer Price for Energy, for each hour that the generating unit is scheduled in
the Day-Ahead Market.
1.113 Nodal Price in each hour of the Dispatch Day in the Day-Ahead Market and
Real-Time Market is the price for Energy received or furnished at a Node or
External Node in the hour, as calculated in accordance with Section 14A.12 of
the Agreement and Schedule 13 of the Tariff.
1.114 Node is a point on the NEPOOL Transmission System where Energy is received
or furnished, and for which Nodal Prices are calculated.
1.115 Non-Participant is any entity which is not a Participant.
1.116 NPCC is the Northeast Power Coordinating Council.
1.117 OASIS is the Open Access Same-Time Information System of the System
Operator.
1.118 Operable Capability of an electric generating unit or units in any hour is
the portion of the Installed Capability of the unit or units which is operating
or available to respond within an appropriate period (as identified in Market
Rules approved by the Markets Committee) to the System Operator's call to meet
the Energy and/or Operating Reserve and/or AGC requirements of the NEPOOL
Control Area during a Scheduled Dispatch Period or is available to respond
within an appropriate period to a schedule submitted by a Participant for the
hour in accordance with Market Rules approved by the Markets Committee.
1.119 Operating Reserve is any or a combination of 10-Minute Spinning Reserve,
10-Minute Non-Spinning Reserve, and 30-Minute Operating Reserve, as the context
requires.
1.120 Operating Reserve Entitlement is the right to all or a portion of the
Operating Reserve of any category which can be provided by a Resource to which
an Entity is entitled as an owner (either sole or in common), as a supplier of
Dispatchable Load, or as a purchaser pursuant to a Unit Contract, reduced by any
portion thereof which such Entity is selling pursuant to a Unit Contract. An
Operating Reserve Entitlement in any category relating to a generating unit or
units may, but need not, be combined with any other Entitlements relating to
such generating unit or units and may be transferred separately from the other
categories of Operating Reserve Entitlements related to such unit or units and
from the related Installed Capability Entitlement, Energy Entitlement[, 4-Hour
Reserve Entitlement] or AGC Entitlement.
1.121 Other HQ Energy is Energy purchased under the HQ Phase I Energy Contract
which is classified as "Other Energy" under that contract.
1.122 Participant is an eligible Entity (or group of Entities which has elected
to be treated as a single Participant pursuant to Section 4.1) which is a
signatory to this Agreement and has become a Participant in accordance with
Section 3.1 until such time as such Entity's status as a Participant terminates
pursuant to Section 21.2.
1.123 Participants Committee is the committee whose responsibilities are
specified in Section 7. To the extent applicable, references in the Agreement to
the Participants Committee shall include the prior Management Committee or
Executive Committee as the predecessor of the Participants Committee.
1.124 Pool-Planned Facility is a generation or transmission facility designated
as "pool-planned" pursuant to Section 18.1.
1.125 Pool-Planned Unit is one of the following units: New Haven Harbor Unit 1
(Coke Works), Mystic Unit 7, Canal Unit 2, Potter Unit 2, Wyman Unit 4, Stony
Brook Units 1, 1A, 1B, 1C, 2A and 2B, Millstone Unit 3, Seabrook Unit 1 and
Waters River Unit 2 (to the extent of 7 megawatts of its Summer Capability and
12 megawatts of its Winter Capability).
1.126 Power Year is (i) the period of twelve (12) months commencing on November
1, in each year to and including 1997; (ii) the period of seven (7) months
commencing on November 1, 1998; and (iii) the period of twelve (12) months
commencing on June 1, 1999 and each June 1 thereafter.
1.127 Prior NEPOOL Agreement is the NEPOOL Agreement as in effect on December 1,
1996.
1.128 Proxy Unit is a hypothetical electric generating unit which possesses a
Winter Capability, equivalent forced outage rate, annual maintenance outage
requirement, and seasonal derating determined in accordance with Section
12.2(a)(2).
1.129 PTF are the pool transmission facilities defined in Section 15.1, and any
other new transmission facilities which the Reliability Committee determines, in
accordance with criteria approved by the Participants Committee and subject to
review by the System Operator, should be included in PTF.
1.130 Publicly Owned Entity is an Entity which is either a municipality or an
agency thereof, or a body politic and public corporation created under the
authority of one of the New England states, authorized to own, lease and operate
electric generation, transmission or distribution facilities, or an electric
cooperative, or an organization of any such entities.
1.131 Real-Time is a current period of a Dispatch Day for which the System
Operator dispatches Resources for Energy and AGC, designates Resources for AGC
and Operating Reserve and, if necessary, activates 4-Hour Reserves.
1.132 Real-Time Market is the market provided for in Section 14A in which
obligations and prices with respect to Energy, Operating Reserve, 4-Hour Reserve
and AGC are determined from the actual dispatch and designations by the System
Operator during a Dispatch Day, based on applicable Demand Bids and Supply
Offers and NEPOOL System Rules.
1.133 Reference Node is the Node identified by the System Operator in accordance
with the NEPOOL System Rules relative to which all mathematical quantities
pertaining to physical operation, including Shift Factors and Withdrawal
Factors, shall be calculated with respect to the dispatch of the system and the
derivation of Locational Prices.
1.134 Regional Network Serviceis the transmission service by that name provided
pursuant to Section 14 of the Tariff.
1.135 Related Personof a Participant is:
(a) for all Participants, either (i) a corporation, partnership, business trust
or other business organization 10% or more of the stock or equity interest in
which is owned directly or indirectly by, or is under common control with, the
Participant, or (ii) a corporation, partnership, business trust or other
business organization which owns directly or indirectly 10% or more of the stock
or other equity interest in the Participant, or (iii) a corporation,
partnership, business trust or other business organization 10% or more of the
stock or other equity interest in which is owned directly or indirectly by a
corporation, partnership, business trust or other business organization which
also owns 10% or more of the stock or other equity interest in the Participant,
or (iv) a natural person, or a member of such natural person's immediate family,
who is, or within the last 12 months has been, an officer, director, partner,
employee, or representative in NEPOOL activities of, or natural person having a
material ongoing business or professional relationship directly related to
NEPOOL activities with, the Participant or any corporation, partnership,
business trust or other business organization related to the Participant
pursuant to clauses (i), (ii) or (iii) of this Section 1.135(a); and
(b) for all End User Participants which are also natural persons, a Related
Person is (i) a member of such End User's immediate family, or (ii) a
Participant and any corporation, partnership, business trust, or other business
organization related to the Participant pursuant to clauses (i), (ii) or (iii)
of Section 1.135(a), of which such End User Participant, or a member of such End
User Participant's immediate family, is, or within the last twelve (12) months
has been, an officer, director, partner, or employee of, or with which an
individual End User Participant has, or within the last twelve (12) months had,
a material ongoing business or professional relationship directly related to
NEPOOL activities, or (iii) another Participant which, within the last twelve
(12) months, has paid a portion of the End User Participant's expenses under
Section 19 of this Agreement, or (iv) a corporation, partnership, business trust
or other business organization in which the End User Participant owns stock
and/or equity with a fair market value in excess of $50,000.
(c) Notwithstanding the foregoing, for the purposes of this definition, an
individual shall not be deemed to have or had a material on-going business
relationship directly related to NEPOOL activities with any corporation,
partnership, business trust, other business organization or Publicly Owned
Entity solely as a result of being served, as a customer, with electricity or
gas.
1.136 Reliability Committee is the committee whose responsibilities are
specified in Section 8 and which may have additional responsibilities under a
proper delegation of authority by the Participants Committee. To the extent
practicable, references in the Agreement to the Reliability Committee shall
include the prior Market Reliability Planning Committee or the prior Regional
Transmission Planning Committee as the predecessor of the Reliability Committee.
1.137 Reliability Standards are those rules, standards, procedures and protocols
approved by the Participants Committee pursuant to Section 7.3, or its
predecessors, that set forth specifics concerning how the System Operator shall
exercise its authority over matters pertaining to the reliability of the bulk
power system.
1.138 Reliability Must Run is a Resource or portion of a Resource that is
scheduled in the Day-Ahead Market by the System Operator out of merit in order
to create sufficient local Operating Reserve to preserve reliability within a
Reliability Region.
1.139 Reliability Region is, as of March 31, 2000, any one of the regions
identified in Attachment C to the Agreement. Subsequent to March 31, 2000, the
System Operator, in a filing with the Commission and following consultation with
the Reliability Committee, may reconfigure Reliability Regions and add or
subtract Reliability Regions as necessary over time to reflect changes to the
grid or changes in patterns of usage and intra-zonal Congestion. Reliability
Regions reflect the operating characteristics of, and the major transmission
constraints on, the NEPOOL Transmission System.
1.140 {Reserve Contract is a contract entered into pursuant to Section 14A.10(c)
between the System Operator and a Participant under which the Participant agrees
to furnish 10-Minute Non-Spinning Reserve, 30-Minute Operating Reserve and/or
4-Hour Reserve.}
1.141 {Reserve Price is the price a Participant agrees to accept in a Reserve
Contract for furnishing 10-Minute Non-Spinning Reserve, 30-Minute Operating
Reserve and/or 4-Hour Reserve.}
1.142 Resource means a generating unit, a Dispatchable Load, or a Supply Offer
to supply service from another Control Area at an External Node.
1.143 Review Boardis the board whose responsibilities are specified in
Section 11A.
1.144 RMR is Reliability Must Run.
1.145 RMR Charge is the charge to Participants pursuant to Section 14A.19(d) to
recover RMR Uplift.
1.146 RMR Uplift is the uplift for RMR determined in accordance with Section
14A.19(d).
1.147 Scheduled Dispatch Period is the shortest period for which the System
Operator performs and publishes a projected dispatch schedule based on projected
Electrical Load and actual Bid Prices and Participant-directed schedules for
Resources submitted in accordance with Section 14.2(d) until the CMS/MSS
Effective Date, and based on projected Electrical Load, Demand Bids, Supply
Offers, and Self-Schedules and Self-Supplies submitted in accordance with
applicable Market Rules for periods on and after the CMS/MSS Effective Date.
1.148 Second Effective Date is May 1, 1999.
1.149 Sector has the meaning specified in Section 6.2.
1.149A Self-Schedule is the action of a Participant in scheduling its Resource,
in accordance with applicable Market Rules, to provide service in an hour,
whether or not in the absence of that action the Resource would have been
scheduled or dispatched to provide the service by the System Operator.
1.149B Self-Supply is the action of a Participant in designating its Resource in
accordance with applicable Market Rules to meet its own service requirements in
whole or in part.
1.150 Service Agreement is the initial agreement and any amendments or
supplements thereto entered into by the Transmission Customer and the System
Operator for service under the Tariff.
1.151 Settlement Obligation prior to the CMS/MSS Effective Date, is an
obligation as defined in Section 14.1(a) for Energy, Section 14.1(b) for
Operating Reserve and Section 14.1(c) for AGC, and all applicable Market Rules
and, on and after the CMS/MSS Effective Date, is an obligation as defined in
Section 14A.1(b) for Energy, Section 14A.1(c) for Operating Reserve, Section
14A.1(d) for 4-Hour Reserve and Section 14A.1(e) for AGC, and all applicable
Market Rules.
1.152 Shift Factor is the factor which relates to the change in power flow over
the PTF that results from an increment of generation at a given Node or External
Node and a corresponding increment of load at the Reference Node, relative to
the size of the increment of generation. Shift Factors are used to calculate
Locational Prices in accordance with Section 14A.12 of the Agreement and
Schedule 13 of the Tariff.
1.153 Small End User is a End User Participant which does not otherwise meet the
definition of Large End User or End User Organization.
1.154 Standard Offer Obligation has the meaning specified in Section
14A.12(b)(ii) of the Agreement and Schedule 13 of the Tariff.
1.155 Start-Up Price is the price, in dollars, that must be paid for a
generating unit to Participants with Energy Entitlements in the unit each time
the unit is scheduled in the Day-Ahead Market to start up.
1.156 Summer Capability of an electric generating unit or combination of units
is the maximum dependable load carrying ability in Kilowatts of such unit or
units (exclusive of capacity required for station use) during the Summer Period,
as determined by the Markets Committee in accordance with Section 10.4(d).
1.157 Summer Period in each Power Year is the four-month period from June
through September.
1.158 Supply Obligation is an obligation as defined in Section 14A.1(a) for
Energy, Operating Reserve, 4-Hour Reserve, and/or AGC.
1.159 Supply Offer is a proposal to furnish Energy at a Node or External Node,
Operating Reserve, 4-Hour Reserve and/or AGC from a Resource that meets the
applicable requirements set forth in the Market Rules that a Participant with
Supply Offer authority for the Resource submits to the System Operator pursuant
to the Agreement and applicable Market Rules, and includes a Supply Offer Price
and information with respect to the quantity proposed to be furnished, technical
parameters for the Resource, timing and other matters.
1.160 Supply Offer Price is the price specified to the System Operator in a
Supply Offer to provide Energy, Operating Reserve, AGC and/or 4-Hour Reserve
from a Resource pursuant to this Agreement and applicable Market Rules.
1.161 System Contract is any contract for the purchase of Installed Capability,
Energy [at a Location], Operating Reserves[, 4-Hour Reserves] and/or AGC, other
than a Unit Contract, pursuant to which the purchaser is entitled to a
specifically determined or determinable amount of such Installed Capability,
Energy, Operating Reserves[, 4-Hour Reserves] and/or AGC.
1.162 System Impact Study is an assessment pursuant to Part V, VI or VII of the
Tariff of (i) the adequacy of the NEPOOL Transmission System to accommodate a
request for the interconnection of a new or materially changed generating unit
or a new or materially changed interconnection to another Control Area or new
Regional Network Service, Internal Point-to-Point Service or Through or Out
Service, and (ii) whether any additional costs may be required to be incurred in
order to provide the interconnection or transmission service.
1.163 System Operator is the central dispatching agency provided for in this
Agreement which has responsibility for the operation of the NEPOOL Control Area
from the NEPOOL control center and the administration of the Tariff. The System
Operator is ISO New England Inc., unless replaced by a substitute independent
system operator, a regional transmission organization or an entity that forms a
part of a regional transmission organization that has, in each case, been
approved by the Commission.
1.164 Target Availability Rate is the assumed availability of a type of
generating unit utilized by the Participants Committee in its determination
pursuant to Section 7.5(e) of NEPOOL Objective Capability.
1.165 Tariff is the NEPOOL Open Access Transmission Tariff set out in Attachment
B to the Agreement, as modified and amended from time to time.
1.166 Tariff Committee is the committee whose responsibilities are specified in
Section 9 and which may have additional responsibilities under a proper
delegation of authority by the Participants Committee. To the extent
practicable, references in the Agreement to the Tariff Committee shall include
the prior Regional Transmission Operations Committee as the predecessor of the
Tariff Committee.
1.167 Technical Committees are the Reliability Committee, the Tariff
Committee and the Markets Committee.
1.168 Third Effective Date is the date on which all Interchange Transactions
shall begin to be effected on the basis of separate Bid Prices for each type of
Entitlement. The Third Effective Date shall be fixed at the discretion of the
Participants Committee to occur within six months to one year after the Second
Effective Date, or at such later date as the Commission may fix on its own or
pursuant to a request by the Participants Committee.
1.169 Through or Out Service is the transmission service by that name provided
pursuant to Section 18 of the Tariff.
1.170 Transition Period is the six- year period commencing on March 1, 1997.
1.171 Transmission Customer is any Eligible Customer that (i) is a Participant
which is not required to sign a Service Agreement with respect to a service to
be furnished to it in accordance with Section 48 of the Tariff or (ii) executes,
on its own behalf or through its Designated Agent, a Service Agreement, or (iii)
requests in writing, on its own behalf or through its Designated Agent, that
NEPOOL file with the Commission a proposed unexecuted Service Agreement in order
that the Eligible Customer may receive transmission service under the Tariff.
1.172 Transmission Owner is a Transmission Provider which makes its PTF
available under the Tariff and owns a Local Network listed in Attachment E to
the Tariff which is not a Publicly Owned Entity, including any affiliate of a
Transmission Provider that owns transmission facilities that are made available
as part of the Transmission Provider's Local Network; provided that if a
Transmission Provider is not listed in Attachment E to the Tariff on May 10,
1999, the Transmission Provider must also (i) own, or lease with rights
equivalent to ownership, PTF with an original capital investment in its PTF as
of the end of the most recent year for which figures are available from annual
reports submitted to the Commission in Form 1 or any similar form containing
comparable annualized data of at least $30,000,000, and (ii) provide
transmission service to non-affiliated customers pursuant to an open access
transmission tariff on file with the Commission.
1.173 Transmission Owners Committee is the committee whose responsibilities are
specified in Section 11B.
1.174 Transmission Provider is the Participants, collectively, which own PTF and
are in the business of providing transmission service or provide service under a
local open access transmission tariff, or in the case of a state or municipal or
cooperatively-owned Participant, would be required to do so if requested
pursuant to the reciprocity requirements specified in the Tariff, or an
individual such Participant, whichever is appropriate.
1.175 Unit Contract is a purchase contract pursuant to which the purchaser is in
effect currently entitled, [at a specified Location], either (i) to a
specifically determined or determinable portion of the capability of a specific
electric generating unit or units, or (ii) to a specifically determined or
determinable amount of Installed Capability, Energy, Operating Reserves[, 4-Hour
Reserves] and/or AGC if, or to the extent that, a specific electric generating
unit or units is or can be operated.
1.176 Withdrawal Factor is the factor which measures the proportion of a small
increment of power injected at a given Node that can be withdrawn at the
Reference Node (with any difference between the amounts injected and withdrawn
attributable to Marginal Losses). Withdrawal Factors are used to calculate
Locational Prices in accordance with Section 14A.12 of the Agreement and
Schedule 13 of the Tariff.
1.177 Winter Capability of an electric generating unit or combination of units
is the maximum dependable load carrying ability in Kilowatts of such unit or
units (exclusive of capacity required for station use) during the Winter Period,
as determined by the Markets Committee in accordance with Section 10.4(d).
1.178 Winter Period in each Power Year is (i) the seven-month period from
November through May and the month of October for the Power Year commencing on
November 1 in 1997 or a prior Power Year; (ii) the seven-month period from
November through May for the Power Year commencing on November 1, 1998; and
(iii) the eight-month period from October through May for the Power Year
commencing on June 1, 1999 and each June 1 thereafter.
1.179 Zonal Price in each hour of the Dispatch Day in the Day-Ahead Market and
the Real-Time Market is the price for Energy received in a Load Zone or
Reliability Region in the hour, as calculated in accordance with Section 14A.12
of the Agreement and Schedule 13 of the Tariff.
1.180 4-Hour Reserve is an option for Energy, which can be called upon by the
System Operator in one or more hours of the Dispatch Day for at least the
minimum period defined in the NEPOOL System Rules and for the number of hours
offered and at Energy prices at least equal to the prices set forth in a Day-
Ahead Supply Offer (unless such prices are reduced in a Real-Time Supply Offer)
and to or from which Energy can be adjusted within four hours in response to
dispatch instructions and in accordance with applicable NEPOOL System Rules,
from one of the following Resources to the extent the Resource providing 4-Hour
Reserve has not been scheduled to provide Energy, Operating Reserve or AGC in
the Day-Ahead Market: (i) a generating unit capable of providing Energy; (ii) a
load capable of reducing its consumption of Energy within four hours, including
Demand Bids at External Nodes; and (iii) to the extent permitted by applicable
NEPOOL System Rules, a Supply Offer to supply Energy from another Control Area
at an External Node.
1.181 4-Hour Reserve Entitlement is the right for the purpose of satisfying a
Supply Obligation for Energy from all or a portion of the 4-Hour Reserve which
can be provided by a Resource to which an Entity is entitled as an owner (either
sole or in common), as a supplier of load or as a purchaser pursuant to a Unit
Contract, reduced by any portion thereof which such Entity is selling pursuant
to a Unit Contract. A 4-Hour Reserve Entitlement in a generating unit or units
may, but need not, be combined with any other Entitlements relating to such
generating unit or units and may be transferred separately from the related
{Installed Capability Entitlement,} Energy Entitlement, Operating Reserve
Entitlement or AGC Entitlement.
1.182 10-Minute Spinning Reserve
(a) Until the CMS/MSS Effective Date, in an hour is the contingency protection
benefit for the system available from the combination of the following Resources
that are designated by the System Operator in accordance with the Market Rules
to be available: (i) the Megawatts available from an electric generating unit or
units that are synchronized to the system (including units outside the NEPOOL
Control Area to the extent permitted by applicable Market Rules), unloaded
during all or part of the hour, and capable of providing contingency protection
by loading to supply Energy immediately on demand, increasing the Energy output
over no more than ten minutes to the full amount of generating capacity so
designated, and sustaining such Energy output for so long as the System Operator
determines in accordance with the Market Rules is necessary; and (ii) any
Dispatchable Load of a Participant that the System Operator is able to verify as
capable of providing contingency protection by immediately on demand reducing
Energy requirements within ten minutes and maintaining such reduced Energy
requirements for so long as the System Operator determines in accordance with
the Market Rules is necessary.
(b) On and after the CMS/MSS Effective Date, in an hour is an option for Energy,
which can be called upon by the System Operator in such hour at Energy prices at
least equal to the prices set forth in a Day-Ahead Supply Offer (unless such
prices are reduced in a Real-Time Supply Offer), from one of the following
Resources to the extent the Resource in the Day-Ahead Market has not been
scheduled or in the Real-Time Market has not been dispatched for Energy and to
or from which Energy can be adjusted within ten (10) minutes in response to
dispatch instructions and sustaining such adjusted level of Energy for so long
as the System Operator determines in accordance with the Market Rules is
necessary: (i) a generating unit that is synchronized to the system; or (ii) a
Dispatchable Load; and (iii) to the extent permitted by applicable Market Rules,
a Supply Offer to supply Energy from another Control Area at an External Node.
1.183 10-Minute Non-Spinning Reserve
(a) Until the CMS/MSS Effective Date, in an hour is the contingency protection
benefit for the system available from the combination of the following Resources
that are designated by the System Operator in accordance with the Market Rules
to be available: (i) the Megawatts available from an electric generating unit or
units that are not synchronized to the system (including units outside the
NEPOOL Control Area to the extent permitted by applicable Market Rules), during
all or part of the hour, and capable of providing contingency protection by
loading to supply Energy within ten minutes to the full amount of generating
capacity so designated, and sustaining such Energy output for so long as the
System Operator determines in accordance with the Market Rules is necessary;
(ii) any Dispatchable Load of a Participant that the System Operator is able to
verify as capable of providing contingency protection by reducing Energy
requirements within ten minutes and maintaining such reduced Energy requirements
for so long as the System Operator determines in accordance with the Market
Rules is necessary; and (3) any other Resources that were able to be designated
for the hour as 10-Minute Spinning Reserve but were not designated by the System
Operator for such purpose in the hour.
(b) On and after the CMS/MSS Effective Date, in an hour is an option for Energy,
which can be called upon by the System Operator in such hour at Energy prices at
least equal to the prices set forth in a Day-Ahead Supply Offer (unless such
prices are reduced in a Real-Time Supply Offer), from one of the following
Resources to the extent the Resource in the Day-Ahead Market has not been
scheduled or in the Real-Time Market has not been dispatched for Energy or for
AGC or 10-Minute Spinning Reserve, and to or from which Energy can be adjusted
within ten (10) minutes in response to dispatch instructions and which is
capable of sustaining such adjusted level of Energy for so long as the System
Operator determines in accordance with Market Rules is necessary: (i) a
generating unit capable of providing such Energy; (ii) a Dispatchable Load; and
(iii) to the extent permitted by applicable Market Rules, a Supply Offer to
supply Energy from another Control Area at an External Node.
1.184 30-Minute Operating Reserve
(a) Until the CMS/MSS Effective Date, in an hour is the contingency protection
benefit for the system available from the combination of the following Resources
that are designated by the System Operator in accordance with the Market Rules
to be available: (i) the Megawatts available from an electric generating unit or
units (including units outside the NEPOOL Control Area to the extent permitted
by applicable Market Rules) that are capable of providing contingency protection
by loading to supply Energy within thirty minutes of demand at an output equal
to its full amount of generating capacity so designated and sustaining Energy
output for so long as the System Operator determines in accordance with the
Market Rules is necessary; (ii) any Dispatchable Load of a Participant that the
System Operator is able to verify as capable of providing contingency protection
by reducing Energy requirements within thirty minutes and maintaining such
reduced Energy requirements for so long as the System Operator determines in
accordance with the Market Rules is necessary; and (3) any other Resources that
were able to be designated for the hour as 10-Minute Spinning Reserve or
10-Minute Non- Spinning Reserve but were not designated by the System Operator
for such purposes in the hour.
(b) On and after the CMS/MSS Effective Date, in an hour is an option for Energy,
which can be called upon by the System Operator in such hour at Energy prices at
least equal to the prices set forth in a Day-Ahead Supply Offer (unless such
prices are reduced in a Real-Time Supply Offer) from one of the following
Resources to the extent the Resource in the Day-Ahead Market has not been
scheduled or in the Real-Time Market has not been dispatched for Energy or
designated for AGC, 10-Minute Spinning Reserve, or 10-Minute Non- Spinning
Reserve, and to or from which Energy can be adjusted in response to dispatch
instructions within thirty (30) minutes and which are capable of sustaining such
adjusted level of Energy for so long as the System Operator determines in
accordance with the Market Rules is necessary: (i) a generating unit capable of
providing such Energy; (ii) a Dispatchable Load; and (iii) to the extent
provided in applicable Market Rules, a Supply Offer to supply Energy from
another Control Area at an External Node.
1.185 Modification of Certain Definitions When a Participant Purchases a
Portion of Its Requirements from Another Participant Pursuant to Firm
Contract.
Definitions marked by an asterisk (*) are modified as follows when a Participant
purchases a portion of its requirements of electricity from another Participant
pursuant to a Firm Contract:
(a) If the Firm Contract limits deliveries to a specifically stated number of
Kilowatts and requires payment of a demand charge thereon (thus placing the
responsibility for meeting additional demands on the purchasing Participant):
(1) in computing the Adjusted Load of the purchasing Participant, the Kilowatts
received pursuant to such Firm Contract shall be deemed to be the number of
Kilowatts specified in the Firm Contract; and
(2) in computing the Load of the supplying Participant, the Kilowatts delivered
pursuant to such Firm Contract shall be deemed to be the number of Kilowatts
specified in the Firm Contract.
(b) If the Firm Contract does not limit deliveries to a specifically stated
number of Kilowatts, but entitles the Participant to receive such amounts of
electricity as it may require to supply its electric needs (thus placing the
responsibility for meeting additional demands on the supplying Participant):
(1) the Installed Capability Responsibility of the purchasing Participant
shall be equal to the amount of its Installed Capability Entitlements;
(2) in computing the Adjusted Load of the purchasing Participant, the Kilowatts
received pursuant to such Firm Contract shall be deemed to be a quantity Rl; and
(3) in computing the Load of the supplying Participant, the Kilowatts delivered
pursuant to such Firm Contract shall be deemed to be a quantity Rl. The quantity
Rl equals (i) the Load of the purchasing Participant less (ii) the amount of the
purchasing Participant's Installed Capability Entitlements multiplied by a
fraction (EQUATION) wherein:
X is the maximum Load of the purchasing Participant in the month, and
Y is the NEPOOL Installed Capability Responsibility multiplied by the purchasing
Participant's fraction P determined pursuant to Section 12.2(a)(1), computed as
if the Firm Contract did not exist.
Terms used in this Agreement that are not defined above, or in the sections in
which such terms are used, shall have the meanings customarily attributed to
such terms in the electric power industry in New England.
[Next Sheet is 58]
SECTION 2
PURPOSE; EFFECTIVE DATES
2.1 Purpose. This Restated NEPOOL Agreement is intended to provide for a
restructuring of the New England Power Pool by modifying the pool's governance
and market provisions to take account of a changed competitive environment, by
modifying the transmission responsibilities of the Participants so that the pool
will perform the functions of a regional transmission group and provide service
to Participants and Non-Participants under a regional open access transmission
tariff, and by providing for the activation of the ISO and the execution of a
contract between the ISO and NEPOOL to define the ISO's responsibilities.
2.2 Effective Dates; Transitional Provisions. The provisions of Parts One, Two,
Four and Five of this Agreement and the Tariff became effective on the First
Effective Date and replaced on the First Effective Date the provisions of
Sections 1-8, inclusive, 10, 11, 13, 14.2, 14.3, 14.4 and 16 of the Prior NEPOOL
Agreement. The provisions of Sections 12.1(a), 12.2, 12.4 (as to Installed
Capability only), 12.5 and 12.7(a) of this Agreement became effective on April
1, 1998 and replaced on such date the provisions of Section 9 of the Prior
NEPOOL Agreement.
The effectiveness of the remaining Sections of this Restated NEPOOL Agreement
shall be delayed pending the preparation of implementing criteria, rules and
standards and computer programs. These Sections became effective on the Second
Effective Date and replaced on the Second Effective Date the remaining
provisions of the Prior NEPOOL Agreement, which continued in effect until the
Second Effective Date.
As provided in Section 14, certain portions of Section 14 which became effective
on the Second Effective Date will be superseded on the Third Effective Date by
other portions of Section 14.
[Next Sheet is 60]
SECTION 3
MEMBERSHIP
3.1 Membership. Those Entities which are Participants in NEPOOL on the First
Effective Date shall continue to be Participants. Any other Entity may, upon
compliance with such reasonable conditions as the Participants Committee may
prescribe, become a Participant by depositing a counterpart of this Agreement as
theretofore amended, duly executed by it, with the Secretary of the Participants
Committee, accompanied by a certified copy of a vote of its board of directors,
or such other body or bodies as may be appropriate, duly authorizing its
execution and performance of this Agreement, and a check in payment of the
application fee described below.
Any such Entity which satisfies the requirements of this Section 3.1 shall
become a Participant, and this Agreement shall become fully binding and
effective in accordance with its terms as to such Entity, as of the first day of
the second calendar month following its satisfaction of such requirements;
provided that an earlier or later effective time may be fixed by the
Participants Committee with the concurrence of such Entity or by the Commission.
The application fee to be paid by each Entity seeking to become a Participant
shall be in addition to the annual fee provided by Section 19.1 and shall be
$500 for an applicant which qualifies for membership only as an End User
Participant, and $5,000 for all other applicants, or such other amount as may be
fixed by the Participants Committee.
3.2 Operations Outside the Control Area. Subject to the reciprocity requirements
of the Tariff, if a Participant serves a Load, or has rights in supply or
demand-side resources or owns transmission and/or distribution facilities,
located outside of the NEPOOL Control Area, such Load and resources shall not be
included for purposes of determining the Participant's rights, responsibilities
and obligations under this Agreement, except that the Participant's Entitlements
in facilities or its rights in demand side- resources outside the NEPOOL Control
Area shall be included in such determinations if, to the extent, and while such
Entitlements are used for retail or wholesale sales within the NEPOOL Control
Area or such Entitlements or rights are designated by a Participant for purposes
of meeting its obligations under Section 12 of this Agreement.
3.3 Lack of Place of Business in New England. If and for so long as a
Participant does not have a place of business located in one of the New England
states, the Participant shall be deemed to irrevocably (1) submit to the
jurisdiction of any Connecticut state court or United States Federal court
sitting in Connecticut (the state whose laws govern this Agreement) over any
action or proceeding arising out of or relating to this Agreement that is not
subject to the exclusive jurisdiction of the Commission, (2) agree that all
claims with respect to such action or proceeding may be heard and determined in
such Connecticut state court or Federal court, (3) waive any objection to venue
or any action or proceeding in Connecticut on the basis of forum non conveniens,
and (4) agree that service of process may be made on the Participant outside
Connecticut by certified mail, postage prepaid, mailed to the Participant at the
address of its member on the Participants Committee as set out in the NEPOOL
roster or at the address of its principal place of business.
3.4 Obligation for Deferred Expenses. NEPOOL may provide for the deferral on the
books of the Participants from time to time of capital or other expenditures,
and the recovery of the deferred expenses in subsequent periods. Any Entity
which becomes a Participant during the recovery period for any such deferred
expenses shall be obligated, together with the continuing Participants, for its
share of the current and deferred expenses pursuant to Section 19.2.
3.5 Financial Security. For an Entity applying to become a Participant or any
continuing Participant that the Participants Committee reasonably determines may
fail to meet its financial obligations under the Agreement, the Participants
Committee may require reasonable credit review procedures which shall be made in
accordance with standard commercial practices. In addition, the Participants
Committee may prescribe for such Entity or Participant a requirement that the
Entity or Participant provide and maintain in effect an irrevocable letter of
credit as security to meet its responsibilities and obligations under the
Agreement, or an alternative form of security proposed by the Entity or
Participant and acceptable to the Participants Committee and consistent with
commercial practices established by the Uniform Commercial Code that protects
the Participants against the risk of non-payment.
[Next Sheet is 64]
SECTION 4
STATUS OF PARTICIPANTS
4.1 Treatment of Certain Entities as Single Participant. All Entities which are
controlled by a single person (such as a corporation or a business trust) which
owns at least seventy-five percent of the voting shares of, or equity interest
in, each of them shall be collectively treated as a single Participant for
purposes of this Agreement, if they each elect such treatment. They are
encouraged to do so. Such an election shall be made in writing and shall
continue in effect until revoked in writing.
In view of the long-standing arrangements in Vermont, Vermont Electric Power
Company, Inc. and any other Vermont electric utilities which elect in writing to
be grouped with it shall be collectively treated as a single Participant for
purposes of this Agreement; provided, however, that any Vermont electric utility
which is a Publicly Owned Entity may elect to join the Publicly Owned Entity
Sector and be treated as a member of that Sector for purposes of governance,
annual fees and NEPOOL expense allocation, without losing the benefits of single
Participant status for any other purpose under this Agreement.
4.2 Participants to Retain Separate Identities. The signatories to this
Agreement shall not become partners by reason of this Agreement or their
activities hereunder, but as to each other and to third persons, they shall be
and remain independent contractors in all matters relating to this Agreement.
This Agreement shall not be construed to create any liability on the part of any
signatory to anyone not a party to this Agreement. Each signatory shall retain
its separate identity and, to the extent not limited hereby, its individual
freedom in rendering service to its customers.
[Next Sheet is 66]
SECTION 5
NEPOOL OBJECTIVES AND COOPERATION BY PARTICIPANTS
5.1 NEPOOL Objectives. The objectives of NEPOOL are, through joint planning,
central dispatching, cooperation in environmental matters and coordinated
construction, central dispatch by the Error! Reference source not found. of the
operation and coordinated maintenance of electric supply and demand-side
resources and transmission facilities, the provision of an open access regional
transmission tariff and the provision of a means for effective coordination with
other power pools and utilities situated in the United States and Canada,
(a) to assure that the bulk power supply of the NEPOOL Control Area conforms
to proper standards of reliability;
(b) to create and maintain open, non-discriminatory, competitive, unbundled
markets for Energy, capacity, and ancillary services that function efficiently
in a changing electric power industry and have access to regional transmission
at rates that do not vary with distance;
(c) to attain maximum practicable economy, consistent with proper standards of
reliability and the maintenance of competitive markets, in such bulk power
supply; and
(d) to provide access to competitive markets within the NEPOOL Control Area
and to neighboring regions;
and to provide for equitable sharing of the resulting responsibilities, benefits
and costs.
5.2 Cooperation by Participants. In order to attain the objectives of NEPOOL set
forth in Section 5.1, each Participant shall observe the provisions of this
Agreement in good faith, shall cooperate with all other Participants and shall
not either alone or in conjunction with one or more other Entities take
advantage of the provisions of this Agreement so as to harm another Participant
or to prejudice the position of any Participant in the electric power business.
PART TWO
GOVERNANCE
SECTION 6
COMMITTEE ORGANIZATION AND VOTING
6.3 Principal Committees. There shall be four principal NEPOOL Committees
(the "Principal Committees"), as follows:
(a) the Participants Committee which shall have the responsibilities
specified in Section 7;
(b) the Reliability Committee which shall have the responsibilities
specified in Section 8;
(c) the Tariff Committee which shall have the responsibilities specified in
Section 9; and
(d) the Markets Committee which shall have the responsibilities specified in
Section 10.
In addition, there shall be a Transmission Owners Committee and a Liaison
Committee, which shall have the responsibilities specified in Sections 11B and
11C, respectively, and such other committees as may be established from time to
time by the Participants Committee.
6.4 Sector Representation. The members of each Principal Committee shall each
belong to a single sector for voting purposes ("Sector"). Each Participant shall
be obligated to designate in a notice to the Secretary of the Participants
Committee a Sector that it or its Related Persons is eligible to join and that
it elects to join for purposes of all of the Principal Committees; provided,
however, that a Participant and the Participants which are its Related Persons
shall not be eligible to join the End User Sector if any one of them is not
eligible to join the End User Sector. A Participant and its Related Persons
shall together be entitled to join only one Sector and shall have no more than
one vote on each Principal Committee.
The Sectors for each Principal Committee, the criteria for eligibility for
membership in each Sector and the minimum requirement which a Participant must
meet as a member of a Sector in order to appoint a voting member of the Sector
and Committee are as follows:
(a) a Generation Sector, which a Participant shall be eligible to join if (i) it
(A) owns or leases with rights equivalent to ownership facilities for the
generation of electric energy that are located within the NEPOOL Control Area
which are currently in operation, or (B) has proposed generation for operation
within the NEPOOL Control Area either which has received approvals under
Sections 18.4 and/or 18.5 within the past two years or for which completed
environmental air or environmental siting applications have been filed or
permits exist, and (ii) it is not a Publicly Owned Entity. Purchasing all or a
portion of the output of a generation facility shall not be sufficient to
qualify a Participant to join the Generation Sector.
A Participant which joins the Generation Sector shall be entitled but not
required to designate an individual voting member of each Principal Committee,
and an alternate to the member, if its operating or proposed generation
facilities in the NEPOOL Control Area have or will have, when placed in
operation, an aggregate Winter Capability of at least 15 MW.
A Participant which joins the Generation Sector but elects not to or is not
eligible to designate an individual voting member, shall be represented by a
group voting member and an alternate to that member for each Principal Committee
(collectively, the "Generation Group Member"). The Generation Group Member shall
be appointed by a majority of the Participants in the Generation Sector electing
or required to be represented by that member. The Generation Group Member shall
have the same percentage of the Sector vote as the individual voting members
designated by other Participants in the Generation Sector which meet the 15 MW
threshold and designate an individual voting member. The Generation Group Member
shall be entitled to split his or her vote.
(b) a Transmission Sector, which a Participant shall be eligible to join if it
is a Transmission Provider and is not a Publicly Owned Entity. Taking
transmission service shall not be sufficient to qualify a Participant to join
the Transmission Sector.
A Participant which joins the Transmission Sector shall be entitled to designate
an individual voting member of each Principal Committee, and an alternate to the
member, if it owns or leases with rights equivalent to ownership PTF with an
original capital investment in its PTF as of the end of the most recent year for
which figures are available from annual reports submitted to the Commission in
Form 1 or any similar form containing comparable annualized data of at least
$30,000,000. A Transmission Provider with facilities which were included as PTF
prior to December 31, 1998 only pursuant to clause (3) of the definition of PTF
pursuant to Section 15.1 shall be entitled to designate an individual voting
member of each Principal Committee, and an alternate to the member, whether or
not PTF which it owns or leases with rights equivalent to ownership which has an
original capital investment of at least $30,000,000, so long as such
Transmission Provider continues to own PTF.
A Participant which joins the Transmission Sector but which is not entitled to
designate an individual voting member of each Principal Committee because (i)
it, together with all of its Related Persons, does not meet the $30,000,000
threshold or (ii) it no longer owns PTF and it does not have a Related Person
that is entitled to designate an individual voting member for each Principal
Committee in another Sector, together with the other Participants in the
Transmission Sector which for the same reasons are unable to designate an
individual voting member, shall be represented by a group voting member of each
Principal Committee (the "Transmission Group Member"), and an alternate to that
member. The Transmission Group Member and alternate shall be appointed by a
majority vote of all Participants in the Transmission Sector required to be
represented by that Member. The Transmission Group Member shall have the same
percentage of the Sector vote as the individual voting members designated by
other Participants in the Transmission Sector which meet the $30,000,000
threshold unless and until the original capital investment in PTF of the
Participants represented by the Transmission Group Member equals or exceeds
twice the $30,000,000 threshold amount. If the aggregate original capital
investment in PTF equals or exceeds twice the $30,000,000 threshold amount, the
percentage of the Sector votes assigned to the Transmission Group Member shall
equal the number of full multiples of the $30,000,000 threshold, provided that
the Transmission Group Member shall in no event be entitled to more than
twenty-five percent (25%) of the Sector vote. For example, if Participants
represented by the Transmission Group Member have an aggregate original capital
investment in PTF in the NEPOOL Control Area totaling $70,000,000, the
Transmission Group Member will have the same percentage of such votes as two
($70,000,000/$30,000,000 Threshold = 2.33) individual voting members designated
by individual Participants, provided that there are at least six other members
in the Sector so the Transmission Group Member does not have more than
twenty-five percent (25%) of the Transmission Sector vote. The Transmission
Group Member shall be entitled to split his or her vote.
(c) a Supplier Sector, which a Participant shall be eligible to join if (i) it
engages in, or is licensed or otherwise authorized by a state or federal agency
with jurisdiction to engage in, power marketing, power brokering or load
aggregation within the NEPOOL Control Area or it had been engaged on and before
December 31, 1998 solely in the distribution of electricity in the NEPOOL
Control Area, and (ii) it is not a Publicly Owned Entity. A Participant which
joins the Supplier Sector shall be entitled to designate a voting member of each
Principal Committee, and an alternate to the member.
(d) a Publicly Owned Entity Sector, which all Participants which are Publicly
Owned Entities are eligible to join and shall join, and which End User
Participants are eligible to join if there is not an activated End User Sector.
A Participant which joins the Publicly Owned Entity Sector shall be entitled to
designate a voting member of each Principal Committee, and an alternate to the
member, except for
End User Participants whose voting interests while they are in the Publicly
Owned Entity Sector are defined in Section 6.2(e) below.
(e) an End User Sector, which an End User Participant is eligible to join
provided all of its Related Persons which are Participants are also eligible to
join the End User Sector. Participants which join the End User Sector shall be
entitled to designate an individual voting member of each Principal Committee
and an alternate to the member; provided, however, that a voting member, and the
alternate to the member, designated by a Small End User shall not be a Related
Person of another Participant in a Sector other than the End User Sector.
Until the total number of End User Participants electing to join the End User
Sector and eligible to designate an individual voting member ("End User Votes")
is at least ten (10), all End User Participants electing to join the End User
Sector shall be members of the Publicly Owned Entity Sector. So long as the
total number of End User Votes is less than three (3), the End User Participants
in the Publicly Owned Entity Sector shall be represented on each Principal
Committee by a single voting member. During such time as there are at least
three (3), but less than ten (10), End User Votes, End User Participants
electing to join the End User Sector shall become a sub- sector of the Publicly
Owned Entity Sector. Such sub-sector shall have twenty percent (20%) of the
Publicly Owned Entity Sector's vote, and each individual voting member of such
sub-sector shall be allocated a per capita share of the sub-sector's vote. The
End User Sector shall become fully operational automatically as soon, and shall
remain operational so long as, there are at least ten (10) End User Votes.
The System Operator shall have the right to designate, by written notice
delivered to the Secretary of the appropriate Principal Committee, a non- voting
member and an alternate to each Principal Committee. All Participants have the
right to join and be a member of a Sector. If a Participant ceases to be
eligible to be a member of the Sector which it previously joined and is not
eligible to join another existing Sector other than the End User Sector, it
shall have the right to remain and vote in the Sector in which the Participant
is currently a member for up to one year. By the end of such year, the NEPOOL
Participants Committee shall make a filing with the Commission pursuant to which
the Participant can join another Sector that either exists or is created
pursuant to the NEPOOL Participants Committee filing. Separate Sectors may be
created, and the membership of existing Sectors may be modified, by amendment of
the Agreement.
6.5 Appointment of Members and Alternates. A Participant or group of
Participants shall designate, by a written notice delivered to the Secretary of
the appropriate Committee, the voting member appointed by it for the Committee
and an alternate of the member. In the absence of the member, the alternate
shall have all the powers of the member, including the power to vote. A
Participant may change the Sector of which it is a member. Other than for Sector
changes required by Section 6.4(c), a change in the Sector in which a
Participant is a member shall become effective beginning on the first annual
meeting of the Participants Committee following notice of such change.
6.6 Term of Members. Each voting member of a Principal Committee shall hold
office until either (a) such member is replaced by the Participant or group of
Participants which appointed the member, or (b) the appointing Participant
ceases to be a Participant, or (c) the appointing Participant (or its Related
Person) is no longer eligible to be in the Sector to which it belongs, but is
eligible to join a different Sector. Replacement of a member shall be effected
by delivery by a Participant or group of Participants of written notice of such
replacement to the Secretary of the appropriate Committee.
6.7 Regular and Special Meetings. Each Principal Committee shall hold its annual
meeting in December or January at such time and place as the Chair shall
designate and shall hold other meetings in accordance with a schedule adopted by
the Committee or at the call of the Chair. Five or more voting members of a
Principal Committee may call subject to the notice provisions of Section 6.6 a
special meeting of the Committee in the event that the Chair fails to schedule
such a meeting within three business days following the Chair's receipt from
such members of a request specifying the subject matters to be acted upon at the
meeting.
6.8 Notice of Meetings. Written or electronic notice of each meeting of a
Principal Committee shall be given to each Participant, whether or not such
Participant is entitled to appoint an individual voting member of the Committee,
not less than three business days prior to the date of the meeting in the case
of the Technical Committees and five business days prior to the date of the
meeting for the Participants Committee.
A notice of meeting shall specify the principal subject matters expected to be
acted upon at the meeting. In addition, such notice shall include, or specify
internet location of, all draft resolutions to be voted at the meeting (which
draft resolutions may be subject to amendment of intent but not subject matter
during the meeting), and all background materials deemed by the Chair or
Secretary to be necessary to the Committee to have an informed opinion on such
matters. Motions raised for which no draft resolutions or background materials
have been provided may not be acted upon at a meeting and shall be deferred to a
subsequent meeting which is properly noticed.
6.9 Attendance. Regular and special meetings may be conducted in person, by
telephone, or other electronic means by means of which all persons participating
in the meeting can communicate in real time with each other. In order to vote
during the course of a meeting, attendance is required in person or by telephone
or other real time electronic means by a voting member or its alternate or a
duly designated agent who has been given, in writing, the authority to vote for
the member on all matters or on specific matters in accordance with Section
6.12.
6.10 Quorum. All actions by a Principal Committee, other than a vote by the
Participants Committee by written ballot to amend the NEPOOL Agreement or
Tariff, shall be taken at a meeting at which the members in attendance pursuant
to Section 6.7 constitute a Quorum. A Quorum requires the attendance by members
which satisfy the Sector Quorum requirements (as defined in Section 6.9) for a
majority of the activated Sectors. No action may be taken by a Principal
Committee unless a Quorum is present; provided, however, that if a Quorum is not
present, the voting members then present shall have the power to adjourn the
meeting from time to time until a Quorum shall be present.
6.11 Voting Definitions. For purposes of this Section 6.9 and Sections 6.10,
6.11 and 6.13, the following terms shall have the following respective meanings:
(a) Sector Voting Share: for each active Sector, is the quotient obtained by
dividing one hundred percent (100%) by the number of active Sectors. For
example, if there are five active Sectors, the Sector Voting Share of each of
the Sectors is twenty percent (20%). The aggregate Sector Voting Shares shall
equal one hundred percent (100%).
(b) Sector Quorum: for a Sector shall be the lesser of (i) fifty percent (50%)
or more (rounded to the next higher whole number) of the voting members of the
Sector, or (ii) five (5) or more voting members of the Sector for the
Participants Committee or three (3) or more voting members of the Sector for the
Technical Committees.
(c) Member Fixed Voting Share: for a Committee voting member, whether or not the
member is in attendance, is the quotient obtained by dividing (i) the Sector
Voting Share of the Sector to which the Participant or group of Participants
which appointed the Committee voting member belongs by (ii) the total number of
Committee voting members appointed by members of that Sector, adjusted, if
necessary, to take into account (A) the manner in which the voting shares of End
User Participants are to be determined while they are members of the Publicly
Owned Entity Sector, and (B) any required change in the voting share of a Group
Member, in each case as determined in accordance with Section 6.2.
(d) Member Adjusted Voting Share: for a Committee voting member which casts an
affirmative or negative vote on a proposed action or amendment and which has
been appointed by a Participant or group of Participants which are members of a
Sector satisfying its Sector Quorum requirement for the proposed action or
amendment, is the quotient obtained by dividing (i) the Sector Voting Share of
that Sector by (ii) the number of voting members appointed by members of that
Sector which cast affirmative or negative votes on the matter, adjusted, if
necessary, for End User Participants and group voting members as provided in the
definition of "Member Fixed Voting Share".
(e) NEPOOL Vote: with respect to a proposed action or amendment is the sum of
(i) the Member Adjusted Voting Shares of the voting members of the Committee
which cast an affirmative vote on the proposed action or amendment and which
have been appointed by a Participant or group of Participants which are members
of a Sector satisfying its Sector Quorum requirements and (ii) the Member Fixed
Voting Shares of the voting members of the Committee which cast an affirmative
vote on the proposed action or amendment and which have been appointed by a
Participant or group of Participants which are members of a Sector which fails
to satisfy its Sector Quorum requirements.
(f) Minimum Response Requirement: with respect to a proposed amendment to this
Agreement or Tariff means that the ballots received by the Balloting Agent from
Participants relating to the proposed amendment before the end of the
appropriate time specified in Section 6.11(c) must satisfy the following
thresholds:
(i) the sum of the Member Fixed Voting Shares of the Participant voting members
whose ballots are received must equal at least fifty percent (50%); and
(ii) the Participants whose voting members timely return ballots for or against
the amendment must include Participants that are represented by voting members
having at least fifty percent (50%) of the Member Fixed Voting Shares in each of
a majority of the activated Sectors.
6.12 Voting On Proposed Actions. All matters to be acted upon by a Principal
Committee shall be stated in the form of a motion by a voting member, which must
be seconded. Only one motion and any one amendment to that motion may be pending
at one time. Passage of a motion requires a NEPOOL Vote as determined pursuant
to Section 6.9 equal to or greater than two thirds of the aggregate Sector
Voting Shares. Voting members not in attendance or represented at a meeting as
specified in Section 6.7 or abstaining shall not be counted as affirmative or
negative votes.
6.13 Voting On Amendments. Subject to Section 21.11 and Section 17A,
amendments to the NEPOOL Agreement or Tariff shall be accomplished as
follows:
(a) Amendments shall be drafted by a standing or ad hoc NEPOOL committee or a
Participant and sent to the Participants Committee for its consideration.
(b) The Participants Committee shall take action pursuant to Section 6.10 to
direct the Balloting Agent to circulate ballots for approval of the draft
Amendment to each Participant for execution by its voting member or alternate on
the Participants Committee or such Participant's duly authorized officer.
(c) In order to be counted, ballots must be executed and returned to the
Balloting Agent for NEPOOL in accordance with the following schedule:
(i) If the ballots are delivered to each Participant by regular mail, properly
executed ballots must be returned to and received by the Balloting Agent within
ten (10) business days after deposit of such ballots in the mail by the
Balloting Agent, and
(ii) If the ballots are delivered to each Participant by overnight delivery,
facsimile, electronic mail or hand delivery, then properly executed ballots must
be returned to and received by the Balloting Agent within five (5) business days
after (A) deposit of such ballots with an overnight delivery courier if
delivered by overnight delivery, or (B) transmission of such ballots by the
Balloting Agent if delivered by facsimile or electronic mail, or (C) receipt by
the Participant if delivered by hand delivery.
(iii) If the Minimum Response Requirement for an amendment has not been received
by the Balloting Agent within the schedule identified in subsection (i) or (ii)
above, the Balloting Agent shall send notice by overnight delivery, facsimile,
electronic mail or hand delivery to all non-responding Participants and shall
count any additional properly executed ballots which it receives within five (5)
business days after such notice. The date by which properly executed ballots
must be returned and received by the Balloting Agent shall be specified by the
Balloting Agent in the notice accompanying such ballots.
(d) A Participant may appeal to the Review Board or submit for resolution
pursuant to the alternative dispute resolution provisions of Section 21.1 a
proposed amendment for which ballots have been circulated, provided that such
appeal is taken or submission is presented before the end of the tenth (10th)
business day after the Participants Committee has taken action to direct the
Balloting Agent to circulate ballots for approval of the draft amendment, by
giving to the Secretary of the Participants Committee a signed and written
notice of appeal or submission. The appeal shall be moot, or submission shall be
deemed withdrawn, if the amendment is not approved in balloting by the
Participants Committee. If the amendment is approved, a valid appeal or
submission shall stay the filing with the Commission of any amendment to the
NEPOOL Agreement or Tariff until either (i) a decision on the appeal by the
Review Board, or (ii) the earlier of resolution pursuant to Section 21.1 or
termination pursuant to Section 21.1.B(2) of the suspension effects of the
submission.
(e) In order for a proposed amendment to the NEPOOL Agreement or Tariff to be
approved by the Participants Committee, the following criteria must be
satisfied:
(i) The Minimum Response Requirement must be satisfied with respect to the
proposed amendment.
(ii) The affirmative ballot votes with respect to the proposed amendment must
equal or exceed two thirds of the aggregate Sector Voting Shares.
6.14 Designated Representatives and Proxies. The vote of any member of a
Principal Committee or the member's alternate, other than a ballot on an
amendment, may be cast by another person pursuant to a written, standing
designation or proxy; provided, however, that the vote of a member or alternate
to that member representing a Small End User may not be cast by a Participant or
a Related Person of a Participant in a Sector other than the End User Sector. A
designation or proxy shall be dated not more than one year previous to the
meeting and shall be delivered by the member or alternate to the Secretary of
the Committee at or prior to any votes being taken at the meeting at which the
vote is cast pursuant to such designation or proxy. A single individual may be
the designated representative of or be given the proxy of the voting members
representing any number of Participants of any one Sector or Participants from
multiple Sectors.
6.15 Limits on Representatives. In the Generation Sector, no one person may
exercise more than twenty-five percent (25%) of that Sector's total Member Fixed
Voting Shares without the unanimous written agreement of all members of the
Generation Sector. In the End User Sector, no one person may vote on behalf of
more than five (5) Small End Users. Except as otherwise provided herein, other
Sectors may by unanimous written agreement elect to impose limits on the voting
power any one individual may have in that
Sector through being the designated representative of multiple voting members or
carrying multiple proxies from voting members of that Sector. Notice of any such
limits on voting power must be posted on the System Operator home page and be
capable of being accessed by all Participants.
6.16 Adoption of Bylaws. The Participants Committee shall adopt bylaws,
consistent with this Agreement, governing procedural matters including the
conduct of its meetings and those of the other Principal Committees. If there is
any conflict between such bylaws and the Agreement, the Agreement shall control.
A Principal Committee may vote to waive its bylaws for a particular meeting,
provided the motion to effect the waiver is approved in accordance with Section
6.10.
6.17 Joint Meetings of Technical Committees. It is recognized that
responsibilities of the Technical Committees may overlap in certain areas. In
areas of overlap, the Reliability Committee is responsible for addressing
reliability matters, the Markets Committee is responsible for addressing market
implications of actions or recommendations, and the Tariff Committee is
responsible for addressing issues relating to transmission and ancillary
services. The Chairs of the Technical Committees, with input from the Liaison
Committee Co-Chairs or entire Liaison Committee, as appropriate, shall
prioritize and sequence Technical Committee activities to ensure full and proper
input by Participants while maximizing the efficiency of the decision making
process. To the extent appropriate and desirable, the Technical Committees are
authorized and encouraged to hold meetings, and to conduct studies and exercise
responsibilities, jointly with other Technical Committees.
[Next Sheet is 90]
SECTION 7
PARTICIPANTS COMMITTEE
7.1 Officers. At its annual meeting, the Participants Committee shall elect from
among its members a Chair and Vice-Chair; it shall also elect a Secretary who
shall not be a member. These officers shall have the powers and duties usually
incident to such offices and as set forth in the Committee bylaws.
7.2 Adoption of Budgets. At each annual meeting, the Participants Committee
shall adopt a NEPOOL budget for the ensuing calendar year. In adopting budgets
the Participants Committee shall give due consideration to the budgetary
requests of each committee. The Participants Committee may modify any NEPOOL
budget from time to time after its adoption.
7.3 Establishing Reliability Standards. It shall be the duty of the Participants
Committee, after review of reports, recommendations and actions of the System
Operator and the Reliability Committee and such other matters as the
Participants Committee deems pertinent, to establish or approve Reliability
Standards for the bulk power supply of NEPOOL. Such Reliability Standards shall
be consistent with the directives of NERC and the NPCC and shall be reviewed
periodically by the Participants Committee and revised as the Participants
Committee deems appropriate.
7.4 Appointment and Compensation of NEPOOL Personnel. The Participants Committee
shall determine what personnel are desirable for the effective operation and
administration of NEPOOL and shall fix or authorize the fixing of the
compensation for such persons. In addition, the Participants Committee shall
determine what resources are desirable for the effective operation of the
Technical Committees and shall, on its own or pursuant to the recommendation of
a Technical Committee, authorize the incurrence of such expenses as may be
required to enable the Technical Committee, or its subgroups, to properly
perform their duties, including, but not limited to, the retention of a
consultant or the procurement of computer time.
7.5 Duties and Authority.
(a) The Participants Committee shall have the duty and requisite authority to
administer, enforce and interpret the provisions of this Agreement and any other
agreement or document approved by the Participants Committee or its predecessor
in order to accomplish the objectives of NEPOOL including the making of any
decision or determination necessary under any provision of this Agreement or any
other agreement or document approved by the Participants Committee or its
predecessor and not expressly specified to be decided or determined by any other
body.
(b) The Participants Committee shall have the authority to provide for such
facilities, materials and supplies as the Participants Committee may determine
are necessary or desirable to carry out the provisions of this Agreement.
(c) The Participants Committee shall have, in addition to the authority provided
in Section 7.3, the authority, after consultation with other NEPOOL committees
and the System Operator, to establish or approve consistent standards with
respect to any aspect of arrangements between Participants and Non-Participants
which it determines may adversely affect the reliability of NEPOOL, and to
review such arrangements to determine compliance with such standards.
(d) The Participants Committee, or its designee, shall have the authority to act
on behalf of all Participants in carrying out any action properly taken pursuant
to the provisions of this Agreement. Without limiting the foregoing general
authority, the Participants Committee, or its designee, shall have the authority
on behalf of all Participants to execute any contract, lease or other instrument
which has been properly authorized pursuant to this Agreement including, but not
limited to, one or more contracts with the System Operator, and to file with the
Commission and other appropriate regulatory bodies: (i) this Agreement and
documents amending or supplementing this Agreement, including the Tariff, (ii)
contracts with Non- Participants or the System Operator, and (iii) related
tariffs, rate schedules and certificates of concurrence. The Participants
Committee shall, in addition, have the authority to represent NEPOOL in
proceedings before the Commission.
(e) The Participants Committee shall have the duty and requisite authority,
after consultation with other NEPOOL committees and the System Operator, to fix
the NEPOOL Objective Capability for each month of each Power Year prior to the
beginning of the Power Year and thereafter to review at least annually the
anticipated Load of the NEPOOL Participants and NEPOOL Installed Capability for
each month of such Power Year and to make such adjustments in the NEPOOL
Objective Capability as the Participants Committee may determine on the basis of
such review. Since changes in the circumstances which must be assumed by the
Participants Committee in fixing NEPOOL Objective Capability for a future period
can significantly affect the required level of NEPOOL Objective Capability for
that period, the Participants Committee shall, where appropriate, also determine
the effect on NEPOOL Objective Capability of significant changes in
circumstances from those assumed, either by fixing alternative NEPOOL Objective
Capabilities, or by adopting adjustment factors or formulas.
(f) The Participants Committee shall have the duty and requisite authority to
establish or approve schedules fixing the amounts to be paid by Participants and
Non-Participants to permit the recovery of expenses incurred in furnishing some
or all of the services furnished by NEPOOL either directly or through the System
Operator.
(g) The Participants Committee shall have the duty and requisite authority to
provide for the sharing by Participants, on such basis as the Participants
Committee may deem appropriate, of payments and costs which are not otherwise
reimbursed under this Agreement and which are incurred by Participants or under
arrangements with Non-Participants and approved or authorized by the Committee
as necessary in order to meet or avoid short-term deficiencies in the amount of
resources available to meet the Pool's reliability objectives.
(h) The Participants Committee shall have the authority, at the time that it
acts on an Entity's application pursuant to Section 3.1 to become a Participant,
to waive, conditionally or unconditionally, compliance by such Entity with one
or more of the obligations imposed by this Agreement if the Participants
Committee determines that such compliance would be unnecessary or inappropriate
for such Entity and the waiver for such Entity will not impose an additional
burden on other Participants.
(i) The Participants Committee shall have the authority to establish standard
conditions and waivers with respect to applications by Entities for membership
in NEPOOL and to modify such standard conditions and waivers as appropriate in
connection with changed circumstances with respect to such applicants, provided
that the Participants Committee determines that the standard conditions and
waivers for such Entities will not impose an additional burden on other
Participants.
(j) The Participants Committee shall have the duty and requisite authority to
act on appeals to it from the actions of other Principal Committees if delegated
to such Committees by the Participants Committee pursuant to Section 7.5(k), to
appoint the Review Board, and to appoint a special committee to administer
NEPOOL's alternate dispute resolution procedures or to take any other action if
it determines that such action is necessary or appropriate to achieve a prompt
resolution of disputes under the provisions of Section 21.1.
(k) The Participants Committee shall have the authority to delegate its powers
and duties to one or more of the Technical Committees, the System Operator, or
other entity as it sees fit provided that (i) such delegation is clearly stated
and approved by a Participant Committee action, (ii) such delegation does not
violate any other provision set forth herein, and (iii) the action of such
entity on any matter delegated to it may be appealed by any Participant to the
Participants Committee provided such an appeal is taken prior to the end of the
tenth business day following the action of the Technical Committee, the System
Operator, or such entity by giving to the Secretary of the Participants
Committee a signed and written notice of appeal, a copy of which the Secretary
shall provide to the System Operator and each member and alternate of the
Participants Committee. Pending action on the appeal by the Participants
Committee, the giving of a notice of appeal as aforesaid shall suspend the
action appealed from.
(l) The Participants Committee shall have the duty and requisite authority to
establish the NEPOOL Information Policy.
(m) The Participants Committee shall have the duty and requisite authority to
adopt and approve, amend and approve or resubmit to one or more Technical
Committees for additional comment, any matter submitted to the Participants
Committee by a Technical Committee.
(n) The Participants Committee shall have such further powers and duties as are
conferred or imposed upon it by other sections of this Agreement.
7.6 Attendance of Participants at Committee Meeting. Each Participant which does
not have the right to designate an individual voting member of the Participants
Committee shall, with the exception of meetings held pursuant to Section 11B.9
and meetings in executive session pursuant to Section 11B.10, be entitled to
attend any meeting of the Committee or any other NEPOOL committee, and shall
have a reasonable opportunity to express views on any matter to be acted upon at
the meeting.
7.7 Appeal of Actions to Review Board. Any Participant which otherwise has the
ability to submit a matter for resolution under Section 21.1 may, in lieu of
submitting a dispute as to a Participants Committee action or failure to take
action for resolution pursuant to Section 21.1, appeal such matter to the Review
Board. Except as otherwise provided in Section 6.11, such an appeal shall be
taken prior to the end of the tenth business day following the meeting of the
Participants Committee to which the appeal relates by giving to the Secretary of
the Participants Committee by hand delivery, facsimile, electronic mail or
regular mail a signed and written notice of appeal, a copy of which the
Secretary shall provide to each Participant. If no appeal of a Participants
Committee action or failure to take action is taken, and the action or failure
to take action is not submitted for resolution pursuant to Section 21.1, within
such time period, that Participants Committee action or failure to take action
shall be final and effective. If an appeal is taken, pending action on the
appeal by the Review Board, the giving of a notice of appeal as aforesaid shall
suspend the action appealed from. To the extent any action taken relates to the
approval of a rule or procedure which must be filed with the Commission, the
rule or procedure shall not be filed until the time for appeal or submission for
dispute resolution has elapsed and, if an appeal has been filed or submission
for dispute resolution has been made, either (i) a decision on the appeal has
been issued by the Review Board, or (ii) the earlier of resolution pursuant to
Section 21.1 of the matter submitted for dispute resolution or the termination
pursuant to Section 21.1.B(2) of the suspension effect of such submission.
[Next Sheet is 100]
SECTION 8
RELIABILITY COMMITTEE
8.1 Officers. The Reliability Committee shall have a Chair, Vice-Chair and
Secretary. The Chair and Secretary of the Reliability Committee shall be
appointed by the System Operator from time to time in accordance with Section
20(j). The Chair will be responsible for presiding at meetings of the Committee
and establishing agendas for its meetings in conjunction with the Vice-Chair and
shall have the powers and duties as set forth in the Committee bylaws. The
Secretary shall have the powers and duties usually incident to such office and
as set forth in the Committee bylaws. The Chair and Secretary shall have no
voting rights. The Vice-Chair shall be elected by the Reliability Committee from
among its voting members from time to time. The Vice-Chair shall have the powers
and duties usually incident to such office and such powers and duties as set
forth in the Committee bylaws, including, without limitation, the responsibility
to develop in conjunction with the Chair, Committee meeting agendas.
8.2 Notice to Members and Alternates of Participants Committee. Prior to the end
of the fifth business day following a meeting of the Reliability Committee, the
Secretary of the Reliability Committee shall give written notice to the System
Operator and each member and alternate of the Participants Committee of any
action taken by the Reliability Committee at such meeting.
8.3 Voting; Appeal of Actions. Votes taken by the Reliability Committee shall be
binding on the Participants only for those matters in which the Committee has
specifically designated authority under this Agreement or has been properly
delegated authority by the Participants Committee pursuant to Section 7.5(k).
Any Participant may appeal to the Participants Committee any binding action
taken by the Reliability Committee. Such an appeal shall be taken prior to the
end of the tenth business day following the meeting of the Reliability Committee
to which the appeal relates by giving to the Secretary of the Participants
Committee a signed and written notice of appeal, a copy of which the Secretary
shall provide to the System Operator and each member and alternate of the
Participants Committee. Pending action on the appeal by the Participants
Committee, the giving of a notice of appeal as aforesaid shall suspend the
action appealed from.
8.4 Responsibilities. The Reliability Committee shall perform the following
functions, in conjunction with the System Operator as appropriate, and shall
recommend action to the System Operator, Participants Committee or Transmission
Owners, as appropriate, with respect thereto:
(a) provide input to the Participants Committee, Transmission Owners, and System
Operator, as appropriate, on transmission facilities and the development of a
regional transmission plan in order to achieve the objectives of NEPOOL;
(b) following appropriate study, recommend NEPOOL Objective Capability for
each Power Year;
(c) periodically review the procedures used to calculate NEPOOL Installed
Capability, NEPOOL Objective Capability and NEPOOL Capability Responsibility;
(d) periodically prepare short and long term load forecasts for use in NEPOOL
studies and operations and to meet requirements of regulatory agencies;
(e) review communications and liaison arrangements between NEPOOL and
governmental authorities on power supply, environmental, load forecasting, and
transmission issues;
(f) coordinate the collection and exchange of necessary system data and future
plans related to reliability for use in NEPOOL planning and to meet requirements
of regulatory agencies;
(g) coordination of studies of, and provide information to Participants on,
maintenance schedules for the supply and demand-side resources and
transmission facilities of the Participants;
(h) based on appropriate studies, recommend for Participants Committee approval
Reliability Standards to assure the reliable operation and facilitate the
efficient operation of the NEPOOL Control Area bulk power system and those
operating rules which guide the implementation of the Reliability Standards.
Such Reliability Standards and operating rules shall include, without
limitation, the following:
(i) standards to determine the current Annual Peak, Adjusted Annual Peak,
Monthly Peak, Adjusted Monthly Peak, and aggregate obligations of the
Participants in each of the NEPOOL Markets;
(ii) standards to establish short and long term load forecasts for use in NEPOOL
operations and to meet requirements of regulatory agencies;
(iii) standards with respect to the administration and enforcement of,
and reporting pursuant to, NERC and NPCC policies and requirements;
(iv) standards for use in planning and design of the NEPOOL interconnected
bulk power system;
(v) standards to ensure the continuous reliability of the bulk power
transmission system, such standards to include, without limitation, criteria and
rules relating to protective equipment, transfer limits, voltage schedules,
voltage guides, operating guides, sub-area reserves, switching, voltage control,
load shedding, emergency and restoration procedures, and the coordination of
scheduling of the operation and maintenance of supply and demand-side resources
and transmission facilities of the Participants;
(vi) standards for determining the capabilities of each electric generating unit
or combination of units in which a Participant has an Entitlement in a uniform
manner applying generally accepted engineering principles; and
(vii) as appropriate, reliability standards for interpool coordination
transactions.
(i) review proposed supply and demand-side resource plans and the proposed
transmission and interconnection plans of Participants pursuant to Section 18.4
and, based on such review, recommend action regarding such proposed plans;
(j) make recommendations regarding procedures for dispatch infrastructure (i.e.
voice and data communications protocols, AGC pulsing arrangements, Energy
Management System and System Control and Data Acquisition interfaces, Satellite
relations, etc.);
(k) provide input and make recommendations with respect to the reliability
considerations of general system operations (i.e. commitment/ decommitment, real
time dispatch, review and approval of distribution of reserves, etc.);
(l) recommend to the Participants Committee the retention of a consultant,
procurement of computer time, or the incurrence of consultant expenses or such
other expenses as may be required to enable the Reliability Committee, its
subcommittees, and task forces properly to perform their duties;
(m) make recommendations to the Participants Committee, Transmission Owners, and
System Operator, as appropriate, with respect to development and amendment of
interconnection procedures and documents related to such procedures; and
(n) to the extent appropriate, develop criteria, guidelines and methodologies to
assure consistency in monitoring and assessing conformance of Participant and
regional transmission plans to accepted reliability criteria.
8.5 Establishment of Subcommittees and Task Forces. The Reliability
Committee shall have the authority to establish subcommittees and task forces
for particular studies.
8.6 Further Powers and Duties. The Reliability Committee shall have such further
powers and duties as are consistent with the duties and responsibilities set
forth herein or as may be properly delegated to it by the Participants
Committee.
[Next Sheet is 108]
SECTION 9
TARIFF COMMITTEE
9.1 Officers. The Tariff Committee shall have a Chair, Vice-Chair and Secretary.
The Chair and Secretary of the Tariff Committee shall be appointed by the System
Operator from time to time in accordance with Section 20(j). The Chair will be
responsible for presiding at meetings of the Committee and establishing agendas
for its meetings in conjunction with the Vice-Chair and shall have the powers
and duties as set forth in the Committee bylaws. The Secretary shall have the
powers and duties usually incident to such office and as set forth in the
Committee bylaws. The Chair and Secretary shall have no voting rights. The
Vice-Chair shall be elected by the Tariff Committee from among its voting
members from time to time. The Vice-Chair shall have the powers and duties
usually incident to such office and such powers and duties as set forth in the
Committee bylaws, including, without limitation, the responsibility to develop
in conjunction with the Chair, Committee meeting agendas.
9.2 Notice to Members and Alternates of Participants Committee. Prior to the end
of the fifth business day following a meeting of the Tariff Committee, the
Secretary of the Tariff Committee shall give written notice to the System
Operator and each member and alternate of the Participants Committee of any
action taken by the Tariff Committee at such meeting.
9.3 Voting; Appeal of Actions. Votes taken by the Tariff Committee shall be
binding on the Participants only for those matters in which the Committee has
specifically designated authority under this Agreement or has been properly
delegated authority by the Participants Committee pursuant to Section 7.5(k).
Any Participant may appeal to the Participants Committee any binding action
taken by the Tariff Committee. Such an appeal shall be taken prior to the end of
the tenth business day following the meeting of the Tariff Committee to which
the appeal relates by giving to the Secretary of the Participants Committee a
signed and written notice of appeal, a copy of which the Secretary shall provide
to the System Operator and each member and alternate of the Participants
Committee. Pending action on the appeal by the Participants Committee, the
giving of a notice of appeal as aforesaid shall suspend the action appealed
from.
9.4 Responsibilities. The Tariff Committee shall perform the following
functions, in conjunction with the System Operator as appropriate, and shall
recommend action to the System Operator, Participants Committee or Transmission
Owners, as appropriate, with respect thereto:
(a) develop appropriate billing procedures for transmission and ancillary
services pursuant to this Agreement and the Tariff;
(b) develop and recommend to the Participants Committee and the Transmission
Owners Committee, as appropriate, (i) amendments, additions and other changes to
the Tariff and (ii) related Tariff rules;
(c) providing input to the System Operator on the development of
Administrative Procedures with respect to the administration of the Tariff
and the OASIS;
(d) to the extent appropriate, conduct and/or review such studies and make such
determinations as are assigned to the Committee pursuant to this Agreement and
the Tariff with respect to financial treatment of additions to or upgrades of
PTF; and
(e) recommend to the Participants Committee the retention of a consultant,
procurement of computer time, or the incurrence of consultant expenses or such
other expenses as may be required to enable the Tariff Committee, its
subcommittees, and task forces properly to perform their duties.
9.5 Establishment of Subcommittees and Task Forces. The Tariff Committee
shall have the authority to establish subcommittees and task forces for
particular studies.
9.6 Further Powers and Duties. The Tariff Committee shall have such further
powers and duties as are consistent with the duties and responsibilities set
forth herein or as may be properly delegated to it by the Participants
Committee.
[Next Sheet is 112]
SECTION 10
MARKETS COMMITTEE
10.1 Officers. The Markets Committee shall have a Chair, Vice-Chair and
Secretary. The Chair and Secretary of the Markets Committee shall be appointed
by the System Operator from time to time in accordance with Section 20(j). The
Chair will be responsible for presiding at meetings of the Committee and
establishing agendas for its meetings in conjunction with the Vice-Chair and
shall have the powers and duties as set forth in the Committee bylaws. The
Secretary shall have the powers and duties usually incident to such office and
as set forth in the Committee bylaws. The Chair and Secretary shall have no
voting rights. The Vice-Chair shall be elected by the Markets Committee from
among its voting members from time to time. The Vice-Chair shall have the powers
and duties usually incident to such office and such powers and duties as set
forth in the Committee bylaws, including, without limitation, the responsibility
to develop in conjunction with the Chair, Committee meeting agendas.
10.2 Notice to Members and Alternates of Participants Committee. Prior to the
end of the fifth business day following a meeting of the Markets Committee, the
Secretary of the Markets Committee shall give written notice to the System
Operator and each member and alternate of the Participants Committee of any
action taken by the Markets Committee at such meeting.
10.3 Voting; Appeal of Actions. Votes taken by the Markets Committee shall be
binding on the Participants only for those matters in which the Committee has
specifically designated authority under this Agreement or has been properly
delegated authority by the Participants Committee pursuant to Section 7.5(k).
Any Participant may appeal to the Participants Committee any binding action
taken by the Markets Committee. Such an appeal shall be taken prior to the end
of the tenth business day following the meeting of the Markets Committee to
which the appeal relates by giving to the Secretary of the Participants
Committee a signed and written notice of appeal, a copy of which the Secretary
shall provide to the System Operator and each member and alternate of the
Participants Committee. Pending action on the appeal by the Participants
Committee, the giving of a notice of appeal as aforesaid shall suspend the
action appealed from.
10.4 Responsibilities. The Markets Committee shall perform the following
functions, in conjunction with the System Operator as appropriate, and shall
recommend action to the System Operator, Participants Committee or Transmission
Owners, as appropriate, with respect thereto:
(a) based on appropriate studies, develop market procedures to assure the
reliable operation and facilitate the efficient operation of the NEPOOL Control
Area bulk power supply;
(b) (i) evaluate studies of the market implications of maintenance schedules for
the supply and demand-side resources and transmission facilities of the
Participants and operable capacity margins, and (ii) develop market procedures
for scheduling maintenance for supply and demand resources and transmission
resources;
(c) to the extent appropriate to assure the efficient operation of the NEPOOL
Markets, develop reasonable standards, criteria and rules relating to protective
equipment, switching, voltage control, load shedding, emergency and restoration
procedures, and the operation and maintenance of supply and demand-side
resources and transmission facilities of the Participants;
(d) develop procedures for determining the market implications of the seasonal
capabilities of each electric generating unit or combination of units in which a
Participant has an Entitlement;
(e) develop procedures for determining as appropriate from time to time the
current Annual Peak, Adjusted Annual Peak, Monthly Peak, Adjusted Monthly Peak,
Installed Capability Responsibility, and obligations for Energy, Operating
Reserve and AGC of each Participant;
(f) develop Market Rules and periodically review and recommend changes thereto
as appropriate. Such Market Rules shall include, without limitation, the
following:
(i) submission of Bid Prices and the determination of prices for each of the
NEPOOL Markets;
(ii) determination for each Participants of its obligations under each of the
NEPOOL Markets;
(iii) establishment or approval of appropriate billing procedures for
market transactions pursuant to this Agreement;
(iv) calculation and equitable apportionment of losses incurred in connection
with Interchange Transactions; and
(v) interpool market contract coordination as appropriate.
(g) develop operating procedures relating to the administration of the
NEPOOL Markets and periodically review and recommend changes thereto as
appropriate; and
(h) recommend the retention of a consultant, procurement of computer time, or
the incurrence of consultant expenses or such other expenses as may be required
to enable the Markets Committee, its subcommittees, and task forces properly to
perform their duties.
10.5 Establishment of Subcommittees and Task Forces. The Markets Committee
shall have the authority to establish subcommittees and task forces for
particular studies.
10.6 Further Powers and Duties. The Markets Committee shall have such further
powers and duties as are consistent with the duties and responsibilities set
forth herein or as may be properly delegated to it by the Participants
Committee.
10.7 Development of Rules Relating to Non-Participant Supply and Demand-side
Resources. It is recognized that arrangements between Participants and Non-
Participants with respect to the Non-Participants' supply and demand-side
resources may create special problems in the application of Sections 12 and 14.
Accordingly, the Markets Committee shall analyze such special problems and
recommend to the Participants Committee appropriate rules for reflecting such
resources in the Installed System Capability of a Participant which enters into
such an arrangement and for the treatment of such arrangements for Energy,
Operating Reserve and AGC purposes. Upon approval by the Participants Committee,
such rules shall supersede the provisions of Sections 12 and 14 (and the related
definitions in Section 1) to the extent of any conflict therewith upon
acceptance by the Commission.
[Next Sheet is 118]
SECTION 11
FURTHER RESTRUCTURING
The NEPOOL Participants undertake to finalize by March 31, 2000 the negotiation
of more comprehensive arrangements for the reassignment of appropriate
administrative responsibilities to the System Operator in the Interim ISO
Agreement.
SECTION 11A
REVIEW BOARD
11A.1 Organization. There shall be a Review Board which, in addition to
responsibility under Section 11B.12, shall be responsible for ruling on appeals
taken from actions of the Participants Committee and for advising the
Participants Committee as to the issues raised on any appeals before it provided
that appeals from actions of the System Operator shall not be taken to the
Review Board. In ruling on appeals, the Review Board shall consider, among other
things, whether the action is consistent with Commission policies. In addition,
if the appeal relates to an amendment to the Agreement or market rule, the
Review Board shall consider the extent to which such amendment imposes a burden
on the Participants which do not vote in favor of the amendment that is
materially greater in degree than that imposed on the Participants which have
voted in favor of the amendment. The Review Board shall not have the right to
review or otherwise participate in actions of the System Operator or to take any
action with respect to any matter involving a dispute between the System
Operator and either NEPOOL or any Participant. The Participants agree that the
process of selecting the Review Board shall commence upon the initial formation
of the Participants Committee. Until the initial organization of the Review
Board is completed, the Board of Directors of the System Operator or a committee
thereof consisting of not less than three System Operator Directors designated
by the System Operator Board of Directors shall perform the functions of the
Review Board, provided that the provisions of Sections 11A.2 through 11A.6 shall
not be applicable to the Board of Directors of the System Operator acting as a
Review Board. All expenses incurred by the System Operator as a result of the
Board of Directors in acting as the Review Board shall be NEPOOL expenses.
11A.2 Composition. The Review Board shall be composed of five members. The
Review Board Members shall initially be selected by the Participants Committee
from a slate of candidates. An independent consultant, retained by the
Participants Committee, shall prepare a list of persons qualified and willing to
serve on the Review Board. A subcommittee appointed by the Participants
Committee shall review the list and distribute to the members of the
Participants Committee a slate from among the list proposed by the independent
consultant, along with information on the background and experience of the
persons on the slate appropriate to evaluating their fitness for service on the
Review Board. If the Participants Committee fails to select a full Review Board
from the slate proposed by the subcommittee, the Committee shall direct the
independent consultant to propose a further list of nominees for consideration
at the next regular meeting of the Participants Committee. Thereafter, prior to
the expiration of a Review Board Member's term, and upon the occurrence of any
vacancy on the Board, the Participants Committee shall select a successor
Member.
11A.3 Qualifications. The Review Board Members shall be independent experts
knowledgeable about issues typically faced by entities engaged in energy
production, transmission, distribution and sale under Federal or State
regulation. A Review Board Member shall not be, and shall not have been at any
time within five years of election to the Review Board, a director, officer or
employee of a Participant or of a Related Person of a Participant. While serving
on the Review Board, a Review Board Member shall have no direct business
relationship or other affiliation with any Participant or its Related Persons
and shall otherwise be subject to the same independence requirements imposed on
Directors of the System Operator Board of Directors.
11A.4 Term. A Review Board Member shall serve for a term of three years;
provided, however, that two of the Review Board Members selected initially shall
be chosen by lot to serve a term of two years, two of the Review Board Members
selected initially shall be chosen by lot to serve a term of three years and the
other Review Board Member selected initially shall serve a term of four years.
11A.5 Meetings. Meetings of the Review Board may be conducted in person or by
telephone or other electronic means by means of which all persons participating
in the meeting can communicate in real time with each other.
11A.6 Bylaws. To the extent not inconsistent with any provision of this
Agreement, the Participants Committee shall adopt bylaws establishing procedures
for the Review Board's activities as it may deem appropriate, including but not
limited to bylaws governing the scheduling, noticing and conduct of meetings of
the Review Board, a code of conduct, selection of a Chair and Vice-Chair of the
Review Board, and action by the Review Board without a meeting. Such bylaws
shall not modify or be inconsistent with any of the rights or obligations
established by this Agreement.
11A.7 Procedure on Appeal of Participant Committee Action or Failure to
Take Action.
(a) Submission of an Appeal: A Participant seeking review ("Appealing Party") by
the Review Board of action of the Participants Committee shall give written
notice of the appeal in accordance with Section 7.7, and the appeal shall have
the suspension effect specified in Section 7.7.
(b) Intervenors and Time Limits: Any other Participant that wishes to
participate in the appeal proceeding hereunder shall give signed written notice
to the Secretary of the Participants Committee no later than ten (10) business
days after the Appealing Party has given notice of appeal and shall upon the
approval of the Review Board be permitted to participate in the appeal.
(c) Procedural Rules: The procedural rules (if any), for the conduct of the
appeal shall be determined by the Review Board in consultation with the
Participants Committee and each Appealing Party on a case-by-case basis.
(d) Pre-hearing Submissions: Each Appealing Party shall provide the Review
Board, within 15 days of the giving of its notice of appeal or such other time
as permitted by the Review Board, a brief written statement of its complaint and
a statement of the remedy or remedies it seeks, accompanied by copies of any
documents or other materials it wishes the Review Board to review. The
Participants Committee and, as appropriate, any other Participant participating
in the appeal will provide the Review Board, within 10 days of the Appealing
Party's submission or such other time as permitted by the Review Board, copies
of the minutes of all NEPOOL committee meetings at which the matter was
discussed and if deemed appropriate by the Participants Committee or otherwise
requested by the Review Board a brief description of the action (or failure to
act) being appealed and a brief statement explaining why the Participants
Committee believes its action (or failure to act) should be upheld by the Review
Board, together with copies of documents or other materials referenced in such
submission for the Review Board to review and materials, if any, which
interested Participants provide to the Secretary of the Participants Committee
and reasonably request be submitted to the Review Board.
In addition, each party shall designate one or more individuals to be available
to answer questions the Review Board may have on the documents or other
materials submitted. The answers to all such questions shall be reduced to
writing by the party providing the answer and a copy shall be made available to
any requesting Participant.
(e) Hearing: A hearing (if any) will be held as soon as is reasonably
practicable.
(f) Decision: The Review Board's decision, to the extent practicable, shall be
due, within ninety (90) days of the giving of notice of the appeal.
11A.8 Effect of a Review Board Decision.
(a) Each Review Board Member shall have one vote and a decision of the Review
Board, either to grant or deny an appeal, shall require affirmative votes by a
majority of the Review Board Members but not less than three (3) such Members.
(i) Appeal denied. If the Review Board denies the appeal, the action of the
Participants Committee will be final and effective, subject to Commission
acceptance if and as required.
(ii) Appeal granted. If the Review Board grants the appeal, the Review Board's
determination (granting the appeal) will be final and the action of the
Participants Committee shall not take effect.
(b) If the Review Board grants an appeal, the Review Board may submit a proposed
resolution of the matter that was the subject of the appeal to the Participants
Committee. The Participants Committee may, but is not required to, take further
action with regard to the matter. If the Participants Committee votes on an
action regarding the matter (including a vote not to act on the matter), the
action or non-action of the Participants Committee shall be subject to further
appeal by any Participant to the Review Board in accordance with Section 7.7.
Any proposed resolution that the Review Board submits to the Participants
Committee is advisory only.
11A.9 An action or failure to act once appealed by a Participant to the Review
Board may not be subject to the alternative dispute resolution provisions of
Section 21.1, regardless of the outcome of the appeal. Conversely, an action or
failure to act submitted for resolution by a Participant pursuant to Section
21.1 may not be brought before the Review Board. If more than one Participant
appeals and/or submits for alternative dispute resolution under Section 21.1 the
same issue, the Participant that first takes such action shall determine whether
the issue is to be heard by the Review Board or considered under Section 21.1;
provided that each Participant challenging an action or failure to take action
shall have the same opportunity to present its case and may not be excluded from
participating under Section 11A.7(b).
11A.10 Any action taken or failure to take action by the Review Board does not
restrict or limit in any way the rights of a Participant to seek review by the
Commission, or a review in any other forum available to the Participant and
there shall be no requirement to submit an appeal to the Review Board concerning
any amendment, action or inaction by the Participants Committee prior to a
Participant exercising any such rights to seek review by the Commission or any
other forum with jurisdiction.
11A.11 The Review Board may not take action that is inconsistent with or
infringes upon any of the rights set forth in Section 17A.
[Next Sheet is 128]
SECTION 11B
TRANSMISSION OWNERS COMMITTEE
11B.1 Organization. There shall be a Transmission Owners Committee established
pursuant to this Section 11B which shall implement the rights reserved to
Transmission Owners by Section 17A.
11B.2 Membership. Membership on the Transmission Owners Committee shall be open
to all Transmission Owners, regardless of their individual choices in Sector
membership under Section 6.2.
11B.3 Appointment of Members and Alternates. A Transmission Owner shall join the
Transmission Owners Committee by written notice delivered to the Secretary of
the Transmission Owners Committee, and shall designate in the notice the initial
member appointed by it for the Committee and an alternate of the member. In the
absence of the member, the alternate shall have all the powers of the member,
including the power to vote.
11B.4 Term of Members. A member of the Transmission Owners Committee appointed
by a Transmission Owner shall serve until replaced by the Transmission Owner
which appointed it or until such Transmission Owner ceases to be a Participant
or otherwise lose its right to appoint the member. Appointment or replacement of
a member shall be effected by a Transmission Owner by giving written notice of
such appointment or replacement to the Secretary of the Transmission Owners
Committee.
11B.5 Regular and Special Meetings. The Transmission Owners Committee shall hold
its annual meeting in December or January at such time and place as the Chair
shall designate and shall hold other meetings in accordance with a schedule
adopted by the Committee or at the call of the Chair. Thirty percent (30%) or
more of the voting members of the Transmission Owners Committee may call a
special meeting of the Committee in the event that the Chair shall fail to call
such a meeting within three business days following the Chair's receipt from
such members of a request specifying the subject matters to be acted upon at the
meeting.
11B.6 Notice of Meetings. Written notice of each meeting of the Transmission
Owners Committee shall be given to each Transmission Owner and to other
Participants not less than five (5) business days prior to the date of the
meeting.
11B.7 Attendance. Regular and special meetings may be conducted in person, by
telephone, or other electronic means by means of which all persons participating
in the meeting can communicate in real time with each other. In order to vote
during the course of a meeting, attendance is required in person or by telephone
or other real time electronic means by a voting member or its alternate or a
duly designated agent who has been given, in writing, the authority to vote for
the member on all matters or the proxy to vote for the member on specific
matters.
11B.8 Votes. Any action taken by the Transmission Owners Committee shall require
the concurrence of:
(i) representatives of at least two-thirds of the Transmission Owners provided
that Transmission Owners that are Related Persons to one another shall together
have a single vote; and
(ii) representatives of Transmission Owners having at least two-thirds of the
Weighted Votes of all Transmission Owners, where each Transmission Owner's
Weighted Vote is equal to its original capital investment in its PTF as of the
end of the most recent year for which figures are available.
Notwithstanding the foregoing, if a vote is taken and paragraph (i) above is
satisfied but paragraph (ii) above is not, the action being voted on by the
Transmission Owners Committee shall pass if (1) there are seven or more
Transmission Owners on the Committee and fewer than three Transmission Owners
oppose the action or (2) there are less than seven Transmission Owners on the
Committee and only one Transmission Owner opposes the action.
11B.9 Appointment of Task Forces or Working Groups. The Transmission Owners
Committee shall have the authority to appoint task forces or working groups to
address matters for which the Committee is responsible. Notwithstanding Section
7.6, such tasks force or working groups may be limited to Transmission Owners
only.
11B.10 Officers. At its annual meeting, the Transmission Owners Committee shall
elect from its members a Chair and a Vice-Chair; it shall also elect a Secretary
who need not be a member of the Committee. These officers shall have the powers
and duties usually incident to such offices, including the right to convene an
executive session of the Transmission Owners Committee to consider and vote upon
submittals to the Commission or litigation strategy.
11B.11 Adoption of Bylaws. The Transmission Owners Committee may adopt bylaws,
consistent with this Agreement, governing procedural matters including the
conduct of its meetings.
11B.12 Review of Committee Actions. To the extent the Commission determines,
pursuant to Section 17A.7, that Transmission Owners have the exclusive right to
make unilateral filings under Section 205 of the Federal Power Act, a
Transmission Owner may either submit a dispute for resolution pursuant to
Section 21.1 or appeal to the Review Board any action taken by the Transmission
Owners Committee with respect to such a Section 205 filing. Such a submission or
appeal shall be taken prior to the end of the tenth business day following the
meeting of the Transmission Owners Committee to which the submission or appeal
relates by giving to the Secretary of the Transmission Owners Committee a signed
and written notice of submission or appeal. Pending action on an appeal by the
Review Board, the giving of a notice of appeal as aforesaid shall suspend the
action appealed from. For purposes of the application of the dispute resolution
process of Section 21.1 and the suspension effect of a submission to alternative
dispute resolution, Section 21.1 shall be applied as if the Transmission Owners
Committee were the Participants Committee.
SECTION 11C
LIAISON COMMITTEE
11C.1 Organization; Duties. There shall be a Liaison Committee which shall be an
advisory committee only responsible to act as a steering committee for managing
NEPOOL business through the committee process and facilitating communications
between NEPOOL and the System Operator and among Participants. The Liaison
Committee's duties as a steering committee include, without limitation,
recommending that matters be assigned to particular committees for action where
the subject matter of a proposed rule or other action potentially falls in the
purview of more than one committee and assuring appropriate input from other
committees as needed.
11C.2 Membership. The Liaison Committee shall have the following members: the
Chair and Vice-Chair of each of the Principal Committees; the Chair of the
Transmission Owners Committee; a Participant representative of each Sector that
is not otherwise represented on the Liaison Committee; the chief executive
officer of the System Operator; and two members of the System Operator's Board
of Directors.
11C.3 Regular and Special Meetings. The Liaison Committee shall hold meetings in
accordance with a schedule adopted by the Committee or at the call of the
Co-Chairs.
11C.4 Notice of Meetings. Written notice of each meeting of the Liaison
Committee shall be given to each member of the Committee and all members of the
Participants Committee not less than five business days prior to the date of the
meeting.
11C.5 Attendance. Regular and special meetings may be conducted in person, by
telephone, or other electronic means by means of which all persons participating
in the meeting can communicate in real time with each other. Participants
Committee members and alternates may attend meetings of the Liaison Committee.
Any individual that is not a member of the Liaison Committee may participate at
a meeting at the invitation of a Co-Chair.
11C.6 Officers. The Co-Chairs of the Liaison Committee shall be the chief
executive officer of the System Operator and the Chair of the Participants
Committee. The Liaison Committee shall elect a Secretary who need not be a
member of the Committee. These officers shall have the powers and duties usually
incident to such offices.
[Next Sheet is 135]
PART THREE
MARKET PROVISIONS
SECTION 12
INSTALLED CAPABILITY
OBLIGATIONS AND PAYMENTS
12.1 Continuing Reliability Measures.
(a) Commencing in 2000 the System Operator shall perform, and furnish to
Participants, an annual, independent "Regional Resource Adequacy Assessment" to
determine whether adequate generation and transmission resources are in place or
under development to assure that regional and subregional reliability standards
established for NEPOOL can be met.
(b) During 2000, the Participants Committee shall commence development of
alternative, market-based reliability assurance mechanisms. A status report on
this development effort shall be submitted to the Commission and furnished to
Participants on or before January 1, 2001
(c) Certain provisions of the Agreement that impose obligations on Participants,
including Participants with generation and transmission resources, were
contained within the Agreement at a time when wholesale power and transmission
services were subject to very different regulatory rules and an Operable
Capability market and Installed Capability auction market were included within
the Agreement. During 2000, concurrent with the review pursuant to Section
12.0(b) and in recognition of the implementation of CMS and MSS, the
Participants Committee shall also identify those of such obligations, if any,
that should be eliminated, modified, or replaced.
12.1 Obligations to Provide Installed Capability. Each Participant shall have
Installed System Capability during each hour of each month at least sufficient
to satisfy its Installed Capability Responsibility for the month.
12.2 Computation of Installed Capability Responsibilities.
(a) (1) At the conclusion of each month, the System Operator under the direction
of the Participants Committee shall determine each Participant's tentative
Installed Capability Responsibility in Kilowatts for such month in accordance
with the following formula:
X = (P(A-N)+Np)(1+T) - C(Dp)
As used in this Section 12.2(a)(1), the symbols used in the formula and the
additional symbols defined below have the following meanings:
X is the Participant's tentative Installed Capability Responsibility for
the month.
P is the value of the Participant's fraction for the month as determined in
accordance with the following formula:
P = (Fp + Dp) / (F + D), wherein:
Fp is the Participant's Adjusted Monthly Peak for the month less any Kilowatts
received by such Participant pursuant to a contract of a type that traditionally
has been treated by NEPOOL as a firm contract for the purposes of this Section
prior to January 1, 1999, but which does not constitute a Firm Contract as
defined in this Agreement.
Dp is the Participant's actual or potential load reduction resulting from its
NEPOOL Interruptible and Dispatchable Loads for the month.
F is the aggregate for the month of the Adjusted Monthly Peaks for all
Participants less any Kilowatts received by any Participant pursuant to a
contract of a type that traditionally has been treated by NEPOOL as a firm
contract for the purposes of this Section prior to January 1, 1999, but which
does not constitute a Firm Contract as defined in this Agreement.
D is the aggregate for the month of the actual or potential load reduction
resulting from all Participants' NEPOOL Interruptible and Dispatchable Loads.
C is the factor, which when multiplied by D in megawatts, results in the
reduction to NEPOOL Objective Capability that would result from including D in
the determination of NEPOOL Objective Capability. The value for C shall be
adopted by the Participants Committee each time it fixes NEPOOL Objective
Capability pursuant to Section 7.5(e).
A is the NEPOOL Objective Capability in megawatts for the month as fixed by the
Participants Committee pursuant to Section 7.
N is the aggregate of the New Unit Adjustments for all Participants for the
month as determined by the Participants Committee in accordance with Section
12.2(a)(2).
Np is the aggregate of the Participant's New Unit Adjustments for the month, as
determined by the Participants Committee, and is equal to the aggregate of the
Participant's adjustments for each New Unit included in its Installed System
Capability during the hour of the coincident peak load of the Participants for
the month. The Participant's adjustment for each New Unit may be positive or
negative and shall be the product of (i) the Participant's Installed Capability
Entitlement in the New Unit during the hour of the coincident peak load of the
Participants for the month, times (ii) the New Unit Adjustment Factor applicable
to the New Unit as determined in accordance with Section 12.2(a)(2).
T is the Participant's Unit Availability Adjustment Factor for the month. T may
be positive or negative and shall be determined in accordance with the following
formula:
T = (I-H) x J x R, wherein:
100
I for the Participant for the month is the percentage which represents the
weighted average (using the Installed Capability of each Installed Capability
Entitlement for such month for the weighting) of the Four Year Installed
Capability Target Availability Rates of the Installed Capability Entitlements
which are included in the Participant's Installed System Capability during the
hour of the coincident peak load of the Participants for the month. The Four
Year Target Availability Rate for an Installed Capability Entitlement for any
month is the average of the monthly Target Availability Rates for the
forty-eight months which comprise the period of four consecutive calendar years
ending within the Power Year which includes such month, as determined on the
basis of the Target Availability Rates for each of the forty-eight months, and
as applied on a basis which is consistent with the fuel or maturity status of
the unit for each of the forty-eight months; provided, however, that for the
purpose of determining the Four Year Target Availability Rate (i) for months
included within the Power Year which commences June 1, 1999, the determination
shall be made for the months of June through October on the basis of the
calendar years 1995 through 1998, and shall be made for the months of November
through May on the basis of the calendar years 1996 through 1999, and (ii) for
months included within the Power Year which commences June 1, 2000, the
determination shall be made on the basis of the calendar years 1996 through
1999. The Target Availability Rates shall be those utilized by the Participants
Committee in its most recent determination of NEPOOL Objective Capability
pursuant to Section 7.
H for the Participant for the month is the percentage which represents the
weighted average (using the Installed Capability of each Installed Capability
Entitlement for such month for the weighting) of the Four Year Actual
Availability Rates of the Installed Capability Entitlements which are included
in the Participant's Installed System Capability during the hour of the
coincident peak load of the Participants for the month. The Four Year Actual
Availability Rate for an Installed Capability Entitlement for any month is the
percentage which represents the average of the amounts determined for H1 for the
four applicable Twelve-Month Measurement Periods within the forty-eight months
which comprise the period of four consecutive calendar years ending within the
Power Year which includes such month; provided, however, that for the purpose of
determining the Four Year Actual Availability Rate (i) for months included
within the Power Year which commences June 1, 1999, the determination shall be
made for the months of June through October on the basis of the calendar years
1995 through 1998, and shall be made for the months of November through May on
the basis of the calendar years 1996 through 1999, and (ii) for months included
within the Power Year which commences June 1, 2000, the determination shall be
made on the basis of the calendar years 1996 through 1999. A Twelve-Month
Measurement Period is a period of twelve sequential months. For purposes of this
sequence, the first month in the four years and the immediately succeeding
months shall be considered to follow the forty-eighth month in the four-year
period. The four applicable Twelve-Month Measurement Periods to be used in the
determination of H1 for an Installed Capability Entitlement shall be the four
sequential Twelve-Month Measurement Periods out of the twelve possible
combinations which yield the highest H1.
H1 for an Installed Capability Entitlement in a unit or combination of units for
a Twelve-Month Measurement Period is its Actual Availability Rate. The Actual
Availability Rate of an Installed Capability Entitlement for a Twelve-Month
Measurement Period is a percentage and shall be the greater of:
(i) the percentage of (a) the amount of generation which could have been
received with respect to the Installed Capability Entitlement if the unit or
combination of units had been fully available at its full Installed Capability
throughout the Twelve-Month Measurement Period, which is represented by (b) the
amount of generation which was actually available during such period, or
(ii) the average Target Availability Rate expressed as a percentage for the
Installed Capability Entitlement for the Twelve-Month Measurement Period less
twenty percentage points. The average Target Availability Rate of an Installed
Capability Entitlement for a Twelve-Month Measurement Period is a percentage and
is the average of the monthly Target Availability Rates for the months which
comprise the Twelve-Month Measurement Period, as determined on the basis of the
Target Availability Rates for each of the twelve months, and as applied on a
basis which is consistent with the fuel or maturity status of the unit or
combination of units for each month in the Twelve-Month Measurement Period. The
Target Availability Rates shall be those utilized by the Participants Committee
in its most recent determination of NEPOOL Objective Capability pursuant to
Section 7.
J for the month is the estimated percentage point change in NEPOOL Objective
Capability which would be required as a result of a one percentage point change
in the weighted average equivalent availability rate of the generating units in
which the Participants have Installed Capability Entitlements. The value for J
shall be adopted by the Participants Committee each time it fixes NEPOOL
Objective Capability pursuant to Section 7.
R for the month is the phase-out factor for the month, which shall be as
follows:
R=0.75 for the Power Year beginning November 1, 1997. R=0.50 for the 12 month
period beginning November 1, 1998. R=0.25 for the 12 month period beginning
November 1, 1999. R=0 for the 12 month period beginning November 1, 2000 and all
subsequent 12 month periods.
(2) A New Unit Adjustment Factor for a New Unit shall be determined to assign
the effects of the New Unit on NEPOOL
Objective Capability to those Participants with Entitlements in the New Unit.
The New Unit Adjustment Factor for each New Unit for each month shall be
determined by the System Operator under the direction of the Participants
Committee in accordance with the following formula:
n = R(K1(c-C) + K2(f-F) + K3(m-M) + K4(d-D) + K5(f-F)c2)
As used in this Section 12.2(a)(2), the symbols used in the formula have the
following meanings:
R is the phase out factor as defined in Section 12.2(a)(1) above.
n is the New Unit Adjustment Factor, expressed as a fraction, for the
month for a New Unit.
c is the Winter Capability of the New Unit.
C is the Winter Capability of the Proxy Unit, which shall be the number of
Kilowatts, as determined by the Participants Committee, which would result in
the NEPOOL Objective Capability being approximately the same if the generating
units in which the Participants have Installed Capability Entitlements were all
units possessing Proxy Unit characteristics.
f is the equivalent forced outage rate of the New Unit, expressed as a fraction
of a year, utilized in the determination by the Participants Committee of NEPOOL
Objective Capability for the month.
F is the equivalent forced outage rate of the Proxy Unit. F, a fraction, shall
be the weighted average equivalent forced outage rate (using the Winter
Capability of each generating unit for such weighting) of the generating units
in which the Participants have Installed Capability Entitlements, adjusted to
compensate for the rounding of the annual maintenance outage requirement of the
Proxy Unit.
m is the four-year average annual maintenance outage requirement of the New
Unit, expressed as a fraction of a year. The data used to determine m shall
include the annual maintenance outage requirements for the current Power Year
and the next three Power Years, as utilized for the New Unit in the most recent
determination by the Participants Committee of NEPOOL Objective Capability
pursuant to Section 7.
M is the annual maintenance outage requirement of the Proxy Unit. M shall be a
fraction, the numerator of which shall be the number of weeks (rounded to the
nearest full number) that most closely approximates the weighted four- year
average annual maintenance outage requirement (using the Winter Capability of
each generating unit for such weighting) for the generating units in which the
Participants have Installed Capability Entitlements, and the denominator of
which shall be 52 weeks.
d is the summer derating of the New Unit, expressed as a fraction of the Winter
Capability of the New Unit.
D is the summer derating of the Proxy Unit. D shall be a fraction and shall be
equal to the weighted average fractional summer derating (using the Winter
Capability of each generating unit for such weighting) of the generating units
in which the Participants have Installed Capability Entitlements.
K1, K2, K3, K4, and K5
are conversion coefficients for each of the Summer and Winter Periods,
determined by regression analysis such that the product for the Installed
Capability of a New Unit times its New Unit Adjustment Factor approximates the
effect on NEPOOL Objective Capability of the New Unit.
Proxy Unit characteristics and conversion coefficients contained in the formula
shall be adopted by the Participants Committee and reviewed every five years (or
more frequently if the Participants Committee determines that exceptional
circumstances require an earlier review) and revised as necessary.
If a New Unit has unique characteristics affecting NEPOOL Objective Capability
which are not adequately reflected in the New Unit Adjustment Factor formula,
the Participants Committee shall determine for such New Unit a New Unit
Adjustment Factor which accounts for the New Unit's unique characteristics.
The New Unit Adjustment Factor for any Restricted Unit (as defined in Section
15.37B of the Prior NEPOOL Agreement) for which proposed plans were submitted
subsequent to November 1, 1990 for review pursuant to Section 18.4 or its
predecessor section in the Prior NEPOOL Agreement (or, in the case of a unit
with a rated capacity of less than 5 MW, for which notification was first given
to NEPOOL subsequent to November 1, 1990) and for the Peabody Municipal Light
Plant's Waters River #2 unit shall be determined in accordance with the formula
previously specified in Section 12.2(a)(2), modified as follows:
n = R(K1(c-C) + K2(f-F) + K3(m-M) + K4(d-D) +K5(f-F)c2) + K6(2500-a)
The symbols used in the above formula, as modified, shall have the meanings
previously specified, except that the symbols "K6" and "a" shall have the
following meanings:
K6 is a scaling factor of 0.0001.
a is as follows:
for units with more than 2500 annual hours available for operation, "a" =
2500,
for units with annual hours available for operation between 500 and 2500,
inclusive, "a" = annual hours available for operation,
and for units with annual hours available for operation less than 500 hours,
"a" = -7500;
provided, however, that a Participant may elect to avoid, in whole or part, the
effect on its Installed Capability Responsibility of a Restricted Unit's
availability being limited to 2500 hours or less a year by agreeing to leave
unfilled a portion of its dispatchable load allocation in accordance with rules
adopted by the Markets Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter.
(b) The tentative Installed Capability Responsibilities of the Participants for
any month, as determined in accordance with Section 12.2(a), shall be adjusted
in accordance with this Section 12.2(b) in the event the value of H for any
Participant for any of the Twelve-Month Measurement Periods applicable to the
Participant for the month is increased in accordance with Section 12.2(a)
because of the application of paragraph (ii) of the definition of H1. In such
event the System Operator under the direction of the Participants Committee
shall determine each Participant's tentative Installed Capability Responsibility
for the month with and without the application of said paragraph (ii). The
difference between the sum of all Participants' tentative Installed Capability
Responsibilities, with and without the application of said paragraph (ii) for
the month, shall be added to the tentative Installed Capability Responsibilities
of the Participants, as determined in accordance with Section 12.2(a), in
proportion to said tentative Installed Capability Responsibilities, thereby
establishing each Participant's adjusted tentative Installed Capability
Responsibility for the month.
(c) For each month, the System Operator under the direction of the Participants
Committee shall determine the sum of all Participants' adjusted tentative
Installed Capability Responsibilities, as initially determined in accordance
with Section 12.2(a) and as adjusted in accordance with Section 12.2(b), if
Section 12.2(b) is applicable for such month. If the sum is less than, or equal
to, the minimum NEPOOL Installed Capability during the month, then the adjusted
tentative Installed Capability Responsibility as determined pursuant to Section
12.2(a) or 12.2(b), whichever is applicable, for each Participant is the final
Installed Capability Responsibility for each Participant. If the sum is greater
than such minimum NEPOOL Installed Capability, then each Participant's final
Installed Capability Responsibility shall be its adjusted tentative Installed
Capability Responsibility as determined pursuant to Section 12.2(a) or 12.2(b),
whichever is applicable, multiplied by the ratio of the minimum NEPOOL Installed
Capability during the month to the sum of the adjusted tentative Installed
Capability Responsibilities for the month.
(d) It is recognized that the treatment of fuel conversions, dual fuel units,
immature units, new Installed Capability Entitlements, cogeneration and small
power-producing facilities, Unit Contracts and other contract arrangements,
units with unusual maintenance cycles, and various other matters can result in
special problems in the determination of Unit Availability Adjustment Factors
and New Unit Adjustments. Accordingly, the Markets Committee shall analyze such
special problems and recommend to the Participants Committee for approval
appropriate Market Rules to be applied in taking such matters into account in
the determination of Unit Availability Adjustment Factors and New Unit
Adjustments.
12.3 [Deleted.].
12.4 [Deleted.].
12.5 Consequences of Deficiencies in Installed Capability Responsibility.
(a) At the conclusion of each month, the System Operator shall determine whether
each Participant has satisfied its Installed Capability Responsibility
obligation for the month. If the minimum monthly Installed System Capability of
a Participant during the month was less than its Installed Capability
Responsibility, the number of Kilowatts of its deficiency shall be computed and
the Participant shall be deemed to purchase from other Participants through
NEPOOL Kilowatts of surplus Installed System Capability equal to the amount of
its deficiency and shall pay to NEPOOL for the month any applicable fees for
services assessed pursuant to Section 19.2 plus the product of its total
Kilowatts of deficiency and the Installed Capability deficiency charge. For
purposes of this Section 12, the minimum monthly Installed System Capability of
a Participant for a month is the Participant's lowest Installed System
Capability for any hour during the month. Retirements made on the last day of
any month shall not be deducted from Installed System Capability for that month.
(b) The Installed Capability deficiency charge shall be an administratively-
determined charge approved by the Participants Committee, except that, if the
Participants Committee is unable to finally approve such a charge on or before
July 28, 2000, the Installed Capability deficiency charge shall be the charge
determined by the System Operator, until such time as the Participants Committee
finally approves a different charge.
(c) The Installed Capability deficiency charge that is to become effective on
August 1, 2000 is subject to the acceptance and/or approval by the Commission of
the materials filed in compliance with the Commission's June 28, 2000 order in
Docket Nos. EL00-62-000, et al. Pending Commission action on such charge, any
collections for deficiencies in Installed Capability on and after August 1, 2000
shall be subject to refund or surcharge back to August 1, 2000 if the deficiency
charge accepted and/or approved by the Commission is different from the charge
identified in the compliance filing.
(d) The Installed Capability Responsibility deficiency charges for each month
shall be divided among and paid to those Participants whose minimum monthly
Installed System Capabilities during such month exceeded their Installed
Capability Responsibilities, in proportion to the amounts of their respective
excesses over their Installed Capability Responsibilities.
12.6 [Deleted].
12.7 Payments to Participants Furnishing Installed Capability. Participants that
are deemed pursuant to Section 12.5 to furnish any surplus in their Installed
System Capability to other Participants shall receive therefor their pro rata
shares on a Kilowatt basis of all payments made by Participants for the month
under Section 12.5, excluding any applicable fees for services assessed pursuant
to Section 19.2. If two or more Participants with excess Installed System
Capability have bid Kilowatts at the Installed Capability Clearing Price, but
not all the excess Installed System Capability bid at such price is required to
meet shortages of Installed System Capability, then the excess Installed System
Capability bid at the Installed Capability Clearing Price that each such
Participant shall be deemed to have furnished shall be the Kilowatts of excess
Installed System Capability bid by the Participant at that price multiplied by
the ratio of (i) the total Kilowatts of excess Installed System Capability bid
at the Installed Capability Clearing Price needed to meet the shortages to (ii)
the total Kilowatts of excess Installed System Capability bid by all
Participants at the Installed Capability Clearing Price.
[Next Sheet is 157]
Sheet 157 is intentionally blank.
[Next Sheet is 158]
SECTION 13
OPERATION, GENERATION, OTHER RESOURCES,
AND INTERRUPTIBLE CONTRACTS
13.1 Maintenance and Operation in Accordance with Accepted Electric Industry
Practice. Each Participant shall, to the fullest extent practicable, cause all
generating facilities and other resources owned or controlled by it to be
designed, constructed, maintained and operated in accordance with Accepted
Electric Industry Practice.
13.2 Central Dispatch. Subject to the following sentence, each Participant
shall, to the fullest extent practicable, subject all generating facilities and
other resources owned or controlled by it to central dispatch by the System
Operator; provided, however, that each Participant shall at all times be the
sole judge as to whether or not and to what extent safety requires that at any
time any of such facilities will be operated at less than full capacity or not
at all. Each Participant may remove from central dispatch a generating facility
or other resources owned or controlled by it if and to the extent such removal
is permitted by rules and standards approved by the Participants Committee
13.3 Maintenance and Repair. Each Participant shall, to the fullest extent
practicable: (a) cause generating facilities and other resources owned or
controlled by it to be withdrawn from operation for maintenance and repair only
in accordance with maintenance schedules reported to and published by the System
Operator from time to time in accordance with procedures established or approved
by the Markets Committee prior to the activation of the Participants Committee
or the Participants Committee thereafter, (b) restore such facilities to good
operating condition with reasonable promptness, and (c) accelerate or delay
maintenance and repair at the reasonable request of the System Operator in
accordance with market operation rules approved by the Markets Committee prior
to the activation of the Participants Committee or the Participants Committee
thereafter.
13.4 Objectives of Day-to-Day System Operation. The day-to-day scheduling and
coordination through the System Operator of the operation of generating units
and other resources shall be designed to assure the reliability of the bulk
power system of the NEPOOL Control Area. Such activity shall:
(a) satisfy the NEPOOL Control Area's Operating Reserve requirements,
including the proper distribution of those Operating Reserves
(b) satisfy the Automatic Generation Control requirements of the NEPOOL
Control Area; and
(c) satisfy the Energy requirements of all Electrical Load of the
Participants,
all at the lowest practicable aggregate dispatch costs to the NEPOOL Control
Area based upon Participant-directed schedules and Bids until the CMS/MSS
Effective Date and based upon Self-Schedules, Self-Supplies, Supply Offers and
Demand Bids on and after that Date.
13.5 Satellite Membership. Each Participant which is responsible for the
operation of transmission facilities rated 69 kV or above in the NEPOOL Control
Area or generating units and other resources which are subject to central
dispatch by NEPOOL, or which is responsible for implementing voltage reduction
and load shedding procedures in the NEPOOL Control Area, shall become a member
of the appropriate satellite dispatching center; provided that by mutual
agreement among the affected Participants and the appropriate satellite, a
Participant may be excused from joining the satellite if it has arranged with a
satellite member to assume responsibility to the satellite for its facilities or
obligations
SECTION 14
INTERCHANGE TRANSACTIONS
14.1 Obligation for Energy, Operating Reserve and Automatic Generation
Control.
This Section 14 shall remain in effect for service under this Agreement until
the CMS/MSS Effective Date and shall be superseded by the provisions of Section
14A of this Agreement for service on and after the CMS/MSS Effective Date.
(a) Each Participant shall have for each hour an Energy obligation equal to its
Electrical Load plus the kilowatthours delivered by such Participant to other
Participants in the hour pursuant to Firm Contracts or System Contracts,
together with any associated electrical losses.
(b) Each Participant shall have for each hour Operating Reserve obligations
equal to its share of the quantity of each category of Operating Reserve
required for the NEPOOL Control Area in the hour.
Subject to adjustment pursuant to Section 14.6, a Participant's share of each
category of Operating Reserve required for any hour shall be determined in
accordance with the following formula:
ORp=SAp + [(OR-SA) (ELp/EL)], wherein
Orp is the Participant's share of that category of Operating Reserve for the
hour.
Sap is the number of Kilowatts, if any, of that category of Operating Reserve
for the hour that the Participants Committee determines should be assigned
specifically to such Participant and not be shared by all Participants.
OR is the aggregate number of Kilowatts of that category of Operating Reserve
determined by the System Operator in accordance with the directions of the
Participants Committee to be required for the NEPOOL Control Area for the hour
that is not assigned to Non-Participants.
SA is the aggregate number of Kilowatts of that category of Operating Reserve
for the hour that the Participants Committee determines should not be shared by
all Participants, but not including Operating Reserve assigned to
Non-Participants.
Elp is the Participant's Electrical Load for the hour.
EL is the sum of ELp for all Participants.
(c) Each Participant shall have for each hour an AGC obligation equal to its
share of AGC required for the NEPOOL Control Area in the hour. Subject to
adjustment pursuant to Section 14.6, a Participant's share of AGC required for
any hour shall be determined in accordance with the following formula:
AGCp=AGC (ELp/EL), wherein
AGCp is the Participant's share of AGC for the hour.
AGC is the total amount of AGC determined by the System Operator in accordance
with market operation rules approved by the Markets Committee prior to the
activation of the Participants Committee or the Participants Committee
thereafter to be required for the NEPOOL Control Area for the hour that is not
assigned to Non-Participants.
ELp and EL are as defined in Section 14.1(b).
14.2 Obligation to Bid or Schedule, and Right to Receive Energy, Operating
Reserve and Automatic Generation Control.
(a) A Participant which has Energy Entitlements shall submit to or have on file
with the System Operator, in accordance with the market operation rules approved
by the Markets Committee prior to the activation of the Participants Committee
or the Participants Committee thereafter, one or more bids for the Energy
Entitlements for which the Participant is permitted to bid specifying the Bid
Price at which it will furnish Energy through NEPOOL to other Participants under
this Agreement or to Non- Participants for ancillary services under the Tariff,
or pursuant to arrangements with Non-Participants entered into under Section
14.6, except to the extent such Entitlements are scheduled by the Participant
consistent with Section 14.2(d).
(b) A Participant which has Operating Reserve Entitlements or AGC Entitlements
shall also submit to or have on file with the System Operator, in accordance
with the market operation rules approved by the Markets Committee prior to the
activation of the Participants Committee or the Participants Committee
thereafter, one or more bids for each such Entitlement for which the Participant
is permitted to bid specifying the Bid Prices at which it will furnish 10-Minute
Spinning Reserve, 10-Minute Non-Spinning Reserve, 30-Minute Operating Reserve
and/or AGC through NEPOOL to other Participants under this Agreement or to
Non-Participants for ancillary services under the Tariff, except to the extent
such Entitlements are scheduled by the Participant consistent with Section
14.2(d).
(c) Except as emergency circumstances may result in the System Operator
requiring load curtailments by Participants, each Participant shall be entitled
to receive from the other Participants (or from the service made available from
Non-Participants pursuant to arrangements entered into under Section 14.6) such
amounts, if any, of Energy, Operating Reserve, and AGC as it requires and
Non-Participants shall be entitled to receive from Participants the amount of
ancillary services to which they are entitled pursuant to the Tariff. If, for
any hour, load curtailments are required, the amount that Participants and
Non-Participants with shortages are entitled to receive shall be proportionally
reduced by the System Operator in a fair and non-discriminatory manner in light
of the circumstances.
(d) All Bid Prices for Entitlements shall be submitted in accordance with market
operation rules approved by the Markets Committee prior to the activation of the
Participants Committee or the Participants Committee thereafter. If a Bid Price
is not submitted for any such Entitlement, the Bid Price shall be deemed to be
zero. For a generating unit in which there are multiple Entitlement holders,
only one Participant shall be permitted to submit Bid Prices for Energy,
Operating Reserve and/or AGC Entitlements for such unit or to direct the
scheduling of the unit for any Scheduled Dispatch Period. The Entitlement
holders in each unit with multiple Entitlement holders shall designate a single
Participant that will be permitted to submit Bid Prices and/or to direct the
scheduling of the unit. In the event that more than one Participant is
designated, or if the Entitlement holders do not designate a single Participant,
then Bid Prices for the unit shall be based on its replacement cost of fuel,
which shall be furnished to the System Operator by the Participant responsible
for furnishing such information as of December 1, 1996. Further, any schedules
for the unit will be submitted to the System Operator by such Participant.
Nothing in this Agreement shall affect the rights of any Entitlement holder
under the contractual arrangements among such Entitlement holders relating to
the unit. Prior to the Third Effective Date, Bid Prices must be submitted for
the next Scheduled Dispatch Period for all Energy, Operating Reserve and AGC
Entitlements in generating unit or units and Energy Entitlements pursuant to
Firm Contracts or System Contracts which may be scheduled by the buyer in
accordance with Section 14.7(b) no later than noon on the preceding day or such
later time as is specified in the market operation rules approved by the Markets
Committee prior to the activation of the Participants Committee or the
Participants Committee thereafter. On and after the Third Effective Date, such
Bid Prices shall be submitted for each hour of the day and the notice period for
such Bid Prices shall be reduced to one hour or such shorter time as the System
Operator determines from time to time is practical while maintaining reliability
and meeting its other obligations to the Participants, except that such notice
period shall be longer than one hour if and to the extent that the System
Operator reasonably determines that such notice is the shortest notice that is
technically feasible at that time to maintain reliability and meet its other
obligations to the Participants. The System Operator shall notify the
Participants following its receipt of all Bid Prices of the expected dispatch
schedule for the next Scheduled Dispatch Period. The System Operator shall
reduce the notice required for Bid Prices and the applicable Scheduled Dispatch
Period to the minimum time technically and practically feasible while
maintaining reliability and meeting its other obligations to the Participants.
Energy, Operating Reserve and/or AGC Entitlements in a generating unit or units
may also be scheduled directly by the Participants permitted to submit Bid
Prices for such Entitlements, but only in accordance with this Section 14.2(d)
and market operation rules approved by the Markets Committee prior to the
activation of the Participants Committee or the Participants Committee
thereafter consistent herewith. Subject to the right of the System Operator to
direct changes to schedules in order to ensure reliability in the NEPOOL Control
Area or any neighboring control area, a Participant permitted to bid its Energy,
Operating Reserve, and/or AGC Entitlements in a generating unit or units, or
required to make Energy deliveries, may submit an hour-to-hour schedule for the
operation or dispatch of such Entitlements during a Scheduled Dispatch Period at
or before the time that Bid Prices are required to be submitted for such period.
In addition, prior to the Third Effective Date, a Participant permitted to bid a
unit or units may submit a short- notice schedule for the operation or dispatch
of any or all of the Energy available from such unit or units during the current
or a subsequent Scheduled Dispatch Period following the time that the System
Operator notifies the appropriate Participants of their expected Entitlement
commitments for that Scheduled Dispatch Period; provided that, for each such
short-notice schedule, the Participant has not been advised by the System
Operator that the Energy, Operating Reserve or AGC Entitlements from the unit or
units covered by the Participant's schedule are expected to be used during the
Scheduled Dispatch Period to meet the region's Energy, Operating Reserve and/or
AGC requirements, and provided further that the Participant short- notice
schedule is only to facilitate transactions during such period from resources or
to load located outside the NEPOOL Control Area; and provided further that such
schedule is furnished at least one hour in advance of the start of the
transaction. In addition, a Participant may, on the same short notice, schedule
System Contracts with Non-Participants from resources or to load located outside
of the NEPOOL Control Area.
14.3 Amount of Energy, Operating Reserve and Automatic Generation Control
Received or Furnished.
(a) For purposes of Sections 14.4, 14.5, and 14.8, the amount of Energy which a
Participant is deemed to receive or furnish in any hour shall be the amount of
its Adjusted Net Interchange. If the Adjusted Net Interchange is negative, the
Participant shall be deemed to be receiving Energy in the hour. If the Adjusted
Net Interchange is positive, the Participant shall be deemed to be furnishing
Energy in the hour.
(b) For purposes of Sections 14.4, 14.5, and 14.9, prior to the Third Effective
Date: the amount of each category of Operating Reserve which a Participant is
deemed to receive in any hour is the Kilowatts of such Operating Reserve
assigned to the Participant for the hour under Section 14.1(b) less any
Kilowatts provided in the hour by the Participant in accordance with the market
operation rules approved by the Markets Committee prior to the activation of the
Participants Committee or the Participants Committee thereafter to meet any
Operating Reserve requirements that were specifically assigned to it and not
shared by all Participants; the amount of Operating Reserve of each category
that the Participant is deemed to have furnished under the Agreement in the hour
is the amount of such Operating Reserve designated by the System Operator to be
provided in the hour by the Participant's applicable Operating Reserve
Entitlements, minus any Kilowatts used in the hour by the Participant in
accordance with the market operation rules to meet any Operating Reserve
requirements that were specifically assigned to it and not shared by all
Participants. For purposes of Sections 14.4, 14.5, and 14.9, on and after the
Third Effective Date, the amount of each category of Operating Reserve which a
Participant is deemed to have received or furnished in any hour is the
difference between the Kilowatts of such Operating Reserve assigned to the
Participant for the hour under Section 14.1(b) and the Kilowatts of such
Operating Reserve designated by the System Operator to be provided in the hour
by the Participant's applicable Operating Reserve Entitlements.
(c) For purposes of Sections 14.4, 14.5, and 14.10, prior to the Third Effective
Date, the amount of AGC which a Participant is deemed to have received in an
hour is the AGC assigned to the Participant for the hour under Section 14.1(c),
and the amount a Participant is deemed to have furnished in the hour is the AGC
designated by the System Operator to be provided in the hour by the
Participant's AGC Entitlements. For purposes of Sections 14.4, 14.5, and 14.10,
on and after the Third Effective Date, the amount of AGC which a Participant is
deemed to have received or furnished in an hour is the difference between the
AGC assigned to the Participant for the hour under Section 14.1(c) and the AGC
designated by the System Operator to be provided in the hour by the
Participant's AGC Entitlements.
14.4 Payments by Participants Receiving Energy Service, Operating Reserve and
Automatic Generation Control.
(a) For every hour in which a Participant's Adjusted Net Interchange is
negative, the number of megawatthours of its Energy deficiency shall be computed
and the Participant shall pay for the hour the product of its total
megawatthours of deficiency and the Energy Clearing Price applicable for the
hour as determined in accordance with Section 14.8, together with any applicable
uplift charges assessed to the Participant under Sections 14.14 and 14.15 of
this Agreement and Section 24 of the Tariff and any applicable fees for services
assessed pursuant to Section 19.2.
(b) For every hour in which a Participant is deemed to receive Operating Reserve
of any category in accordance with Section 14.3(b), the number of Kilowatts it
is deemed to receive for the hour in each category shall be computed. The
Participant shall pay therefor for the hour any applicable uplift charge
assessed under Section 14.15 and any applicable fees for services assessed
pursuant to Section 19.2 plus the product of (i) the aggregate amount paid to
Participants for that category of Operating Reserve for the hour pursuant to
Section 14.5(b) and (ii) a fraction of which the numerator is the Kilowatts of
that category of Operating Reserve deemed under Section 14.3(b) to have been
received by the Participant for the hour and the denominator is the aggregate
Kilowatts of that category of Operating Reserve deemed under Section 14.3(b) to
have been received by all Participants for the hour.
(c) For every hour in which a Participant is deemed under Section 14.3(c) to
have received AGC, the amount it is deemed to receive shall be computed and the
Participant shall pay therefor any applicable uplift charge assessed under
Section 14.15 and any applicable fees for services assessed pursuant to Section
19.2 plus the product of (i) the aggregate amount paid to Participants for AGC
for the hour pursuant to Section 14.5(c) and (ii) a fraction of which the
numerator is the AGC the Participant is deemed under Section 14.3(c) to have
received for the hour and the denominator is the aggregate amount of AGC all
Participants are deemed under Section 14.3(c) to have received for the hour.
14.5 Payments to Participants Furnishing Energy Service, Operating Reserve,
and Automatic Generation Control.
(a) Subject to the provisions of Section 14.12, a Participant that is deemed in
an hour to furnish Energy service to other Participants pursuant to Section
14.3, or to Non-Participants for ancillary services under the Tariff or pursuant
to arrangements entered into under Section 14.6, shall receive for each
megawatthour furnished by it the Energy Clearing Price for the hour determined
in accordance with Section 14.8 or the Bid Price for that megawatthour, if
higher than the Energy Clearing Price and the unit is either within the Energy
Clearing Price Block (as defined in Section 14.8(c)) or is operated out of merit
if such higher Bid Price is appropriately paid pursuant to market operation
rules governing out-of-merit generation approved by the Markets Committee prior
to the activation of the Participants Committee or the Participants Committee
thereafter. In addition, to the extent that the System Operator reduces Energy
production from a generating unit or units in order to provide VAR support,
Participants with Entitlements in such unit or units may receive their lost
opportunity costs if and to the extent provided for by market operation rules
approved by the Markets Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter.
(b) A Participant that is deemed in an hour to furnish Operating Reserve under
the Agreement shall receive for each Kilowatt of each category of Operating
Reserve furnished by it the applicable Operating Reserve Clearing Price as
defined and determined in accordance with Section 14.9 or the Bid Price to
provide such Kilowatt, if higher than the Operating Reserve Selling Price for
the hour.
(c) A Participant that is deemed in an hour to furnish AGC under the Agreement
shall receive therefor an amount calculated as follows:
(i) the AGC Clearing Price for the hour as defined and determined in accordance
with Section 14.10, times the change in AGC output of the Participant's AGC
Entitlements which the System Operator requested in the hour, times an
appropriate unit conversion factor as determined in accordance with market
operation rules approved by the Markets
Committee prior to the activation of the Participants Committee or the
Participants Committee thereafter; plus
(ii) an AGC reservation payment for each AGC Entitlement that the System
Operator designated for AGC in the hour calculated as (A) the AGC Clearing Price
in effect for the hour, times (B) the level of AGC the System Operator
determines to be available in the hour from the Entitlement, times (C) the
portion of the hour during which the System Operator had designated the
Entitlement for AGC; plus
(iii) a payment that compensates the Participant for its lost opportunity cost,
if any, for the operation of the generating unit or combination of units
designated for AGC in the hour below the desired level of output in order to
provide AGC, as determined in accordance with Market Rules approved by the
Markets Committee prior to the activation of the Participants Committee or the
Participants Committee thereafter.
(d) In no event shall Participants be paid for lost opportunity costs resulting
from a generating unit being dispatched down or off to accommodate transmission
constraints, and nothing in this Agreement or the Market Rules shall provide for
any such payment
14.6 Energy Transactions with Non-Participants.
(a) The Participants Committee is authorized to enter into contracts on behalf
of and in the names of all Participants (i) with power pools or other entities
in one or more other control areas to purchase or furnish emergency Energy (and
related services) that is available for the System Operator to schedule in order
to ensure reliability in the NEPOOL Control Area or neighboring control areas,
and (ii) with Non-Participants pursuant to which ancillary services will be
provided by the Participants pursuant to the Tariff. The terms of any such
contractual arrangement shall not require the furnishing of emergency service to
any other control area until the service needs of all Participants have been
provided for with the least expensive resources practicable. Energy purchased in
any hour from Non-Participants under a contract entered into pursuant to this
Section 14.6(a) shall be deemed to be furnished to, and paid for by,
Participants entitled to or requiring such Energy in the hour pursuant to this
Section 14 at the higher of the Energy Clearing Price for the hour or the price
paid to the Non- Participant for the Energy.
(b) The Participants Committee is authorized to provide for the day-to-day
scheduling through the System Operator of the HQ Phase II Firm Energy Contract,
in accordance with the HQ Use Agreement, as if the Contract were a contract
covering Energy transactions with a Non-Participant entered into pursuant to
Section 14.6(a). The HQ Phase II Firm Energy Contract shall not be deemed a Firm
Contract for purposes of this Agreement. Energy received in an hour from
Hydro-Quebec pursuant to the HQ Energy Banking Agreement, and Energy purchased
in any hour from Hydro-Quebec pursuant to the HQ Phase II Firm Energy Contract
or any other HQ Contract shall be deemed to be Energy furnished to each
Participant entitled to such Energy for the hour in the amount reflected for the
Participant in the System Operator's scheduling of Energy deliveries in the hour
from Hydro-Quebec; except that emergency Energy received from Hydro-Quebec under
the HQ Interconnection Agreement shall be deemed to be Energy provided to (and
shall be paid for by) Participants requiring such emergency Energy in the hour.
The System Operator shall schedule such Energy deliveries to accommodate, to the
maximum extent possible, the schedule of Energy deliveries from Hydro-Quebec
requested by the Participant. The Participants deemed to have received such
Energy shall pay therefor the higher of the Energy Clearing Price (together with
any applicable uplift charges under Sections 14.14 and/or 14.15 of this
Agreement and/or Section 24 of the Tariff and any applicable fees for services
assessed pursuant to Section 19.2) or the price paid to Hydro-Quebec for the
Energy (or in the case of Energy received under the HQ Energy Banking Agreement,
the price paid for the related Energy deliveries to Hydro-Quebec under the
Agreement and any amount payable to Hydro-Quebec with respect to the
transaction).
14.7 Participant Purchases Pursuant to Firm Contracts and System Contracts.
(a) A Participant may undertake to transfer all or select portions of its
settlement rights and obligations under this Agreement to or from another
Participant with respect to any of the NEPOOL markets pursuant to a Bilateral
Transaction. Such transfer of settlement rights and obligations under this
Agreement shall be as agreed to between the two parties to the Bilateral
Transaction and shall be submitted to the System Operator in accordance with the
Market Rules. If and to the extent necessary to implement the agreement between
the parties, such Market Rules, upon approval by the Participants Committee,
shall supersede the provisions of the Agreement that otherwise apply for
determination of the respective settlement rights and obligations of the
parties.
(b) In the event a Participant has the right to receive Energy, Operating
Reserve and/or AGC from a Non-Participant under a System Contract or a Firm
Contract, such Contract shall be treated as nearly as possible as if it were a
Unit Contract for an Energy Entitlement, Operating Reserve Entitlement and/or
AGC Entitlement, as applicable, provided that, in the case of Energy, Operating
Reserve, and/or AGC, the System Contract or Firm Contract permits the scheduling
of deliveries of such Energy, Operating Reserve and/or AGC to be subject in
whole or part to central dispatch through the System Operator in accordance with
Market Rules approved by the Markets Committee prior to the activation of the
Participants Committee or the Participants Committee thereafter.
14.8 Determination of Energy Clearing Price. For each hour, the System
Operator shall determine the Energy Clearing Price as follows:
(a) The System Operator shall rank in the order of lowest to highest (i) the
Dispatch Prices derived from the Bid Prices to furnish Energy in the hour and
(ii) the cost to NEPOOL of any Energy received from Non-Participants in the hour
pursuant to contracts referenced in Section 14.6.
(b) The Energy Clearing Price shall be the weighted average of the Dispatch
Prices (or NEPOOL cost) of the "Energy Clearing Price Block" as defined in the
next sentence. The Energy Clearing Price Block shall be identified for each hour
in accordance with market operation rules approved by the Markets Committee
prior to the activation of the Participants Committee or the Participants
Committee thereafter to reflect those resources with the highest Dispatch Prices
or NEPOOL cost that were centrally dispatched by the System Operator for Energy
deemed to have been furnished to the Participants, excluding resources that were
dispatched out of merit as determined in accordance with market operation rules
approved by the Markets Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter.
14.9 Determination of Operating Reserve Clearing Price.
(a) For each hour as necessary, the System Operator shall determine the
Operating Reserve Clearing Price for each category of Operating Reserve as
follows:
(i) The System Operator shall determine the aggregate Kilowatts of the
applicable category of Operating Reserve that are deemed pursuant to Section
14.3(b) to have been received by Participants for the hour.
(ii) For 10-Minute Non-Spinning Reserve and 30-Minute Operating Reserve, the
System Operator shall rank in the order of lowest to highest the Bid Prices of
the resources designated by the System Operator for that category of Operating
Reserve for the hour. The applicable Operating Reserve Clearing Price for
10-Minute Non-Spinning Reserve or 30-Minute Operating Reserve shall be the
weighted average of the highest Bid Prices for the 1000 Kilowatts (or such other
number as may be specified by the Markets Committee prior to the activation of
the Participants Committee or the Participants Committee thereafter) of that
category of Operating Reserve that are designated by the System Operator for use
in the hour.
(iii) For 10-Minute Spinning Reserve the System Operator shall rank in order of
lowest to highest the 10-Minute Spinning Reserve Lost Opportunity Prices (as
defined in Section 14.9(b)) of the resources designated by the System Operator
for the hour. The Operating Reserve Clearing Price for 10- Minute Spinning
Reserve shall be the weighted average for the 1000 Kilowatts (or such other
number as may be specified by the Markets Committee prior to the activation of
the Participants Committee or the Participants Committee thereafter) of the
highest 10-Minute Spinning Reserve Lost Opportunity Prices for the hour of the
Entitlements that were designated by the System Operator for use in the hour.
(b) The System Operator shall determine a 10-Minute Spinning Reserve Lost
Opportunity Price for each hour for use in determining the Operating Reserve
Clearing Price for 10-Minute Spinning Reserve. For the purposes of Section 14.9,
the 10-Minute Spinning Reserve Lost Opportunity Price for a Participant's
resource shall be the amount by which the Energy Clearing Price for the hour
exceeds the resource's Dispatch price (not less than zero), plus the Bid Price
in the hour for each resource to provide 10-Minute Spinning Reserve.
14.10 Determination of AGC Clearing Price. For each hour, the System Operator
shall determine the AGC Clearing Price. The AGC Clearing Price shall be the
weighted average "AGC Capability Price" for the "AGC Clearing Price Block," as
both terms are defined below in this Section 14.10. The AGC Capability Price for
each hour for each AGC Entitlement designated by the System Operator to provide
AGC in the hour shall be a cost per unit of AGC capability based on the Bid
Price for the Entitlement for the hour divided by the amount of AGC available in
the hour from that Entitlement. The AGC Clearing Price Block shall be identified
by the System Operator for each hour in accordance with market operation rules
approved by the Markets Committee prior to the activation of the Participants
Committee or the Participants Committee thereafter to reflect those AGC
resources with the highest Bid Prices that were designated by the System
Operator to provide AGC in the hour and were deemed pursuant to Section 14.3(c)
to have been received by Participants for the hour.
14.11 Funds to or from which Payments are to be Made.
(a) All payments for Energy, Operating Reserves or AGC furnished or received,
all uplift charges paid pursuant to this Section 14 of this Agreement and
Section 24 of the Tariff, and all fees for services paid pursuant to Section
19.2, and any payments by Non-Participants for ancillary services under
Schedules 2-7 to the Tariff or pursuant to arrangements referenced in Section
14.6, shall be allocated each month through the Pool Interchange Fund as
follows:
Step One. For each week in which Energy is delivered or received under the HQ
Energy Banking Agreement, all payments with respect to transactions under that
Agreement shall be made to or from the Energy Banking Fund provided for in
Section 14.11(b).
Step Two. (i) For each week in which Pre-Scheduled Energy (as defined in the HQ
Phase I Energy Contract) is purchased pursuant to the HQ Phase I Energy
Contract, the aggregate amount which is paid pursuant to Section 14.6(b) for
such Energy by each Participant which is a participant in the Phase I
arrangements with Hydro-Quebec shall be determined and paid on the Participant's
account into the Phase I Savings Fund.
(ii) For each week in which Energy is purchased pursuant to the HQ Phase II Firm
Energy Contract, the aggregate amount which is paid pursuant to Section 14.6(b)
for such Energy by each Participant which is a participant in the Phase II
arrangements with Hydro-Quebec shall be determined and paid on the Participant's
account into the Phase II Savings Fund.
Step Three. For each week in which Other HQ Energy is purchased pursuant to the
HQ Phase I Energy Contract or Energy is purchased pursuant to the HQ
Interconnection Agreement, the aggregate amount paid pursuant to Section 14.6(b)
for such Energy shall be determined for each Participant which is a participant
in the Phase I or Phase II arrangements with Hydro-Quebec. Such amount shall be
allocated between the Participant's share of the Phase I Savings Fund and the
Participant's share of the Phase II Savings Fund created under the HQ Use
Agreement in the same ratio as (A) the sum of (x) the number of kilowatthours of
Other HQ Energy deemed to be purchased by the Participant during the week and
(y) the HQ Phase I Percentage of the number of kilowatthours deemed to be
purchased by the Participant under the HQ Interconnection Agreement during the
week, bears to (B) the HQ Phase II Percentage of the number of kilowatthours
purchased under the HQ Interconnection Agreement during the week.
Step Four. The balance remaining in the Pool Interchange Fund after Steps One
through Three shall be retained in the Pool Interchange Fund for the month and
shall be used and disbursed after each month in the following order:
(i) (A) amounts owed to Non-Participants (other than Hydro-Quebec) for the month
under contracts entered into with them pursuant to Section 14.6(a) shall be
paid, and (B) amounts owed to Hydro-Quebec for the month for Energy deemed to be
furnished pursuant to Section 14.6(b) to Participants which are not participants
in the Phase I or Phase II arrangements with Hydro-Quebec shall be paid and, in
the event the price paid by any such Participant for such Energy is the Energy
Clearing Price, the excess, if any, of the Energy Clearing Price over the amount
owed to Hydro-Quebec shall be paid to the Participant;
(ii) amounts paid by Participants for applicable fees for services assessed
pursuant to Section 19.2 shall be used to reduce NEPOOL expenses; and
(iii) amounts owed to Participants for the month pursuant to Section 14.5 shall
then be paid.
(b) HQ Energy Banking Fund. All amounts allocated to the HQ Energy Banking
Fund for each month shall be used and disbursed as follows:
(i) Participants which furnish Energy for delivery to Hydro-Quebec under the HQ
Energy Banking Agreement shall receive therefor from their share of the Energy
Banking Fund the amount to which they are entitled for such service in
accordance with Section 14.5.
(ii) amounts required to be paid to Hydro-Quebec under the HQ Energy Banking
Agreement shall be paid from the shares of the Fund of the Participants engaging
in transactions under the HQ Energy Banking Agreement for the month in
accordance with their respective interests in the transactions for the month. If
there is not enough in any such share, the Participants with the deficient
shares shall be billed and pay into their shares of the Fund the amounts
required for payments to Hydro-Quebec.
(iii) subject to the remaining provisions of this Section, at the end of each
month any balance remaining in each Participant's share of the HQ Energy Banking
Fund shall (I) in the case of any Participant which is not a participant in the
Phase I or Phase II arrangements with Hydro-Quebec, be paid to such Participant,
and (II) in the case of any Participant which is a participant in the Phase I or
Phase II arrangements with Hydro-Quebec, be paid to the Escrow Agent under the
HQ Use Agreement to be held and disbursed by it through the Phase I Savings Fund
and Phase II Savings Fund created under the HQ Use Agreement, and shall be
allocated between the Participant's share of said Funds as follows:
(A) the balance remaining in the Participant's share of the HQ Energy Banking
Fund for the month shall be divided by the number of kilowatthours deemed to be
received by the Participant under the HQ Energy Banking Agreement during the
month to determine an average savings amount per kilowatthour;
(B) for any hour during the month in which the number of kilowatthours received
by NEPOOL under the HQ Energy Banking Agreement exceeded the HQ Phase I Transfer
Capability, an amount equal to (A) the Participant's share of the excess of (1)
the number of kilowatthours received over (2) the HQ Phase I Transfer Capability
times (B) the average savings amount per kilowatthour determined for that
Participant under (i) above shall be allocated to the Phase II Savings Fund; and
(C) the remaining balance of the Participant's share of the HQ Energy Banking
Fund for the month shall be allocated to the Phase I Savings Fund.
It is recognized that, in view of the time which may elapse between the delivery
of Energy to or by Hydro-Quebec in an Energy Banking transaction under the HQ
Energy Banking Agreement and the return of the Energy, the amounts of Energy
delivered to and received from Hydro-Quebec, after adjustment for losses, may
not be in balance at the end of a particular month.
Further, if as of the end of any month and after adjustment for electrical
losses, the cumulative amount of Energy so received from Hydro-Quebec exceeds
the amount so delivered, the aggregate amount paid by Participants for the
excess Energy pursuant to Section 14.6(b) shall be paid to the Energy Banking
Fund. The Escrow Agent under the HQ Use Agreement shall hold and invest these
funds. On the return of the excess Energy to Hydro-Quebec, the amount so held by
the Escrow Agent shall be repaid to Hydro-Quebec and Participants in accordance
with the Energy Banking Agreement.
(c) Phase I HQ Savings Fund. The aggregate amount allocated to each
Participant's share of the Phase I HQ Savings Fund for each month shall be used,
first, to pay to Hydro-Quebec the amount owed to it for the month for Energy
furnished under the Phase I HQ Energy Contract and the HQ Phase I Percentage of
the amount owed to it for the month for Energy furnished to the Participants
under the HQ Interconnection Agreement. The balance of the amount allocated to
the Fund for the month shall be paid to the Escrow Agent under the HQ Use
Agreement to be held and disbursed by it through the Phase I HQ Savings Fund
created thereunder in accordance with each Participant's contribution to such
balance.
(d) Phase II HQ Savings Fund. The aggregate amount allocated to the Phase II HQ
Savings Fund for each month shall be used, first, to pay to Hydro- Quebec the
amount owed to it for the month for Energy deemed to be furnished to the
Participant under the Phase II HQ Firm Energy Contract and the HQ Phase II
Percentage of the amount owed to it for the month for Energy deemed to be
furnished to the Participant under the HQ Interconnection Agreement. The balance
of the amount allocated to the Fund for the month shall be paid to the Escrow
Agent under the HQ Use Agreement to be held and disbursed by it through the
Phase II HQ Savings Fund created thereunder in accordance with each
Participant's contribution to such balance.
14.12 Development of Rules Relating to Nuclear and Hydroelectric
Generating Facilities, Limited-Fuel Generating Facilities, and Interruptible
Loads.
It is recognized that the central dispatch of Energy available from nuclear
generating facilities and from pondage associated with hydroelectric generating
facilities and from interruptible loads and of pumping Energy for pumped storage
hydroelectric generating facilities and other limited-fuel generating facilities
involves special problems which must be resolved to assure fair and
non-discriminatory treatment of Participants having Entitlements in such
generating facilities or having such interruptible loads or any other
Participants involved in such transactions. Accordingly, the Markets Committee
shall analyze such special problems and recommend to the Participants Committee
for approval appropriate rules for dispatching such facilities (including, but
not limited to, bids for dispatchable pumping load at pumped storage
facilities), for handling such interruptible loads and for paying for Energy,
Operating Reserve and AGC involved in such transactions on a basis consistent
with the principles underlying this Section 14; and upon approval by the
Participants Committee such rules shall supersede the provisions of Sections 12
and 14 to the extent of any conflict.
14.13 Dispatch and Billing Rules During Energy Shortages. It is recognized that
Energy shortages can result in special problems which must be resolved to assure
that dispatch and billing provisions do not prevent achievement of the
objectives specified in Section 13.4. Accordingly, the Markets Committee shall
analyze such special problems and recommend to the Participants Committee for
approval appropriate dispatch and billing rules to be applied during periods
when the Participants Committee determines that there is, or is anticipated to
be, an Energy shortage which adversely affects the bulk power supply of the
NEPOOL Control Area and any adjoining areas served by Participants.
Upon approval by the Participants Committee, such rules shall supersede the
economic dispatch and billing provisions of this Agreement to the extent of any
conflict therewith for the duration of such Energy shortage period.
14.14 Congestion Uplift.
(a) It shall be the responsibility of the Participants Committee to review prior
to January 1, 2000 the Congestion Costs incurred with the new market
arrangements contemplated by Section 14 of this Agreement and with retail
access, and to determine whether subsection (b) of this Section, together with
an amendment specifying the rights of Participants and Non-Participants across a
constrained interface within the NEPOOL Control Area and to make other necessary
or appropriate changes in subsection (b), all of the provisions of which shall
be considered for modification, or some other modified or substitute provision
dealing with the allocation of Congestion Costs in a constrained transmission
area, should be made effective on March 1, 2000 and after the preparation of
necessary implementing rules and computer software or on an earlier or later
effective date. If the Participants Committee determines that such a provision
should be made effective, it shall recommend to the Participants any required
amendment to the Agreement and/or the Tariff and a schedule for implementation
which will permit sufficient time for the development of necessary rules and
computer software. If the Participants Committee is unable to agree on such a
determination prior to January 1, 2000 any Participant or group of Participants
may propose such an amendment and schedule in a filing with the Commission.
(b) Commencing on the implementation effective date of an order by the
Commission directing a different allocation of congestion costs, whenever
limitations in available transmission capacity in any hour require that the
System Operator dispatch out-of-merit resources that are bid by the Participants
in any area which is determined to be a constrained transmission area in
accordance with Market Rules, the System Operator shall determine for the
constrained transmission area the aggregate Congestion Costs for the hour.
[Next Sheet is 196]
Such Congestion Costs for each hour shall be allocated to and paid by
Participants and Non-Participants as a congestion uplift as follows:
(i) In accordance with market operation rules approved by the Regional Market
Operations Committee and the Regional Transmission Operations Committee prior to
the activation of the Participants Committee or the Participants Committee
thereafter, the System Operator shall identify for each Participant and
Non-Participant the difference in megawatt hours, if any, between (A) Electrical
Load served by the Participant or Non-Participant in the constrained area and
transactions by the Participant or Non- Participant occurring in the hour which
utilized the constrained interface to move Energy through the constrained area
and (B) the Participant's or Non- Participant's in-merit Energy Entitlements
located in
[Next Sheet is 197]
the constrained area that were used in the hour to serve such Electrical Load,
taking into account Firm Contracts and System Contracts between Participants and
electrical losses, if and as appropriate.
(ii) The System Operator shall identify for each Participant and Non-
Participant the megawatt hours, if any, of the rights of that Participant or
Non-Participant to use the then effective transfer capability across the
constrained interface.
(iii) The System Operator shall identify for each Participant and Non-
Participant the megawatt hours, if any, by which the amount determined pursuant
to clause (i) above for that Participant or Non-Participant exceeds the amount
determined for that Participant or Non-Participant pursuant to clause (ii)
above. If the clause (i) amount exceeds the clause (ii) amount, the Participant
or Non-Participant shall be responsible for paying a share of the aggregate
Congestion Costs in proportion to the Participant's or Non- Participant's share
of the aggregate amount of such excesses for all Participants and
Non-Participants, and such Congestion Costs shall be included, as a transmission
charge, in the Regional Network Service,
Internal Point-to-Point Service or Through or Out Service charge, whichever is
applicable.
(c) As used in this Section 14.14, the "Congestion Cost" of an out-of-merit
resource for an hour means the product of (i) the difference between its
Dispatch Price and the Energy Clearing Price for the hour, times (ii) the number
of megawatt hours of out-of-merit generation produced by the resource for the
hour.
14.14A CMS/MSS Implementation Studies Related to Congestion.
(a) Study of Transmission Constraints and Reliability Regions. The Participants
Committee shall commission a study to determine whether the implementation of
CMS and MSS is likely to result in substantial, adverse impacts on any load
pockets within New England. As an additional component of this study, there
shall be an initial determination of the existence or lack of workable
competition in the NEPOOL Markets in Reliability Regions, Load Zones and any
load pockets. This study shall commence on or before July 1, 2000 and shall be
completed no later than December 31, 2000. If the results of this study
determine that there is likely to be substantial adverse impacts on any load
pocket due to the implementation CMS and MSS, the Participants Committee shall
undertake to develop new measures to mitigate such impacts. Unless or until new
measures are implemented to replace or supplement existing measures, the System
Operator shall apply existing NEPOOL System Rules to mitigate such impacts to
the extent possible and appropriate. In evaluating whether there will be
substantial adverse impacts, the study shall take into account planned
transmission enhancements to increase transfer capability into any load pocket,
the anticipated operation of new or expanded generating units and anticipated
retirements of existing generating units, the anticipated value of FCRs and
revenues from the sale thereof that will be available to load in any load
pocket, the concentration of ownership of generation and responsibilities for
serving load in the load pocket, and the anticipated load response to such
adverse impacts.
(b) Study of Market Rule and Procedure 17 ("Market Rule 17"). Before the CMS/MSS
Effective Date, the System Operator and Participants shall review Market Rule 17
and consider changes, where appropriate, to that Market Rule in light of the
implementation of CMS and MSS. The review shall be supervised and assisted by
persons who have recognized antitrust expertise and experience and are retained
by or on behalf of the Participants Committee. At a minimum, before the CMS/MSS
Effective Date, Market Rule 17 shall be amended to prescribe the process to
determine whether a Reliability Region or load pocket within a Reliability
Region is workably competitive and, if a Reliability Region or load pocket is
determined not to be workably competitive, the types of mitigation measures
available to be applied to remedy such situation.
14.15 Additional Uplift Charges. It is recognized that the System Operator may
be required from time to time to dispatch resources out of merit for reasons
other than those covered by Section 14.14 of this Agreement and Section 24 of
the Tariff. Accordingly, if and to the extent appropriate, feasible and
practical, dispatch and operational costs shall be categorized and allocated as
uplift costs to those Participants and Non-Participants that are responsible for
such costs. Such allocations shall be determined in accordance with Market Rules
that are consistent with this Agreement and any applicable regulatory
requirements and approved by the Regional Market Operations Committee prior to
the activation of the Participants Committee or the Participants Committee
thereafter.
SECTION 14A
PARTICIPANT MARKET TRANSACTIONS
ON AND AFTER THE CMS/MSS EFFECTIVE DATE
This Section 14A shall become effective, and shall supersede Section 14 in its
entirety, for service under this Agreement on and after the CMS/MSS Effective
Date. Certain provisions of this Section 14A are subject to further modification
to comply with requirements of the Commission's June 28, 2000 order in Docket
Nos. EL00-62-000, et al. and further Commission orders with respect thereto.
This Section 14A shall have no effect for service or charges under this
Agreement prior to the CMS/MSS Effective Date unless specific provisions are
made applicable earlier pursuant to the Market Rules. This Section 14A specifies
the rights and obligations of Participants under the Agreement with respect to
the supply of, and payment for, Energy, Operating Reserve, 4-Hour Reserve and
AGC.
14A.1 Supply Obligations and Settlement Obligations for Energy, Operating
Reserve, 4-Hour Reserve and Automatic Generation Control.
(a) Supply Obligation. Each Participant with a Resource or an Entitlement in a
Resource that is scheduled in the Day-Ahead Market by the System Operator, in
accordance with an applicable Supply Offer, Self-Schedule or designation for
Self-Supply, to provide Energy at a Node or External Node, Operating Reserve,
4-Hour Reserve and/or AGC shall have a Day-Ahead Market Supply Obligation for
the service scheduled in the amount so scheduled. The Day-Ahead Market Supply
Obligation shall be satisfied by the Participant for each hour in one of the
following two ways: (i) the Participant shall furnish or cause to be furnished
in Real-Time such service under this Section 14A each hour pursuant to the
schedule; or (ii) the Participant shall pay at the applicable Real-Time Nodal
Price or Clearing Price for such amounts which it has not furnished or caused to
be furnished in accordance with clause (i). Each Participant with a Resource or
an Entitlement in a Resource that is scheduled in the Day-Ahead Market or that
submits a Supply Offer, or that is scheduled pursuant to a Self-Schedule or
designated pursuant to a Self-Supply in the Real-Time Market, for Energy at a
Node or External Node, Operating Reserve or AGC, shall have a Real-Time Market
Supply Obligation for each hour for which it is so scheduled or designated. Its
Real-Time Market Supply Obligation for Energy shall be equal to the amounts of
Energy at a Node or External Node it provides in the Real-Time Market in
response to dispatch instructions by the System Operator (including dispatch
instructions pursuant to a Self-Schedule or Self-Supply). Its Real-Time Market
Supply Obligations for each category of Operating Reserve and/or AGC shall be
equal to the amount of such service it is designated by the System Operator to
provide in the Real-Time Market (including service designated by the Participant
for Self-Supply and accepted by the System Operator).
(b) Energy Settlement Obligation. Each Participant shall have for each hour a
Day-Ahead Market Settlement Obligation for Energy at each Location equal to the
megawatthours, if any, of its Demand Bid accepted by the System Operator in the
Day-Ahead Market for Energy at that Location, adjusted up or down, as
appropriate, to reflect Bilateral Transactions entered into by the Participant
that transfer for the hour all or part of a Day-Ahead Market Settlement
Obligation for Energy at that Location to or from another Participant. Each
Participant also shall have for each hour a Real-Time Market Settlement
Obligation for Energy at each Location equal to the megawatthours, if any, of
its Electrical Load at that Location for the hour, adjusted up or down, as
appropriate, to reflect Bilateral Transactions entered into by the Participant
that transfer for the hour all or part of a Real-Time Market Settlement
Obligation for Energy at that Location to or from another Participant. A
Settlement Obligation for Energy shall require the Participant to pay, or
entitle the Participant to be paid, in accordance with the provisions of Section
14A.8(a) and applicable Market Rules.
(c) Operating Reserve Settlement Obligation. Settlement Obligations for each
category of Operating Reserve for each hour are established by allocating the
total Megawatts of that category designated for the hour in Real-Time by the
System Operator to Participants under the Agreement and to Non-Participants
under the Tariff. Each Participant shall have for each hour a Settlement
Obligation for each category of Operating Reserve that, subject to adjustment
pursuant to Section 14A.11, shall be the number of Megawatts determined in
accordance with the following formula:
ORp = SAp + [(OR-SA) (ELp/EL)] + ADJor, wherein
Orp is the Megawatts of the Participant's Settlement Obligation for that
category of Operating Reserve for the hour.
Sap is the number of Megawatts, if any, of that category of Operating Reserve
for the hour that is determined pursuant to applicable Market Rules as properly
being assigned specifically to such Participant and not shared by all
Participants.
OR is the aggregate number of Megawatts of that category of Operating Reserve
designated by the System Operator in the Real-Time Market in accordance with
applicable NEPOOL System Rules to be required for the NEPOOL Control Area for
the hour.
SA is the aggregate number of Megawatts of that category of Operating Reserve
for the hour that is determined pursuant to applicable Market Rules as properly
not being shared by all Participants, including Operating Reserve assigned to
Non-Participants.
Elp is the Participant's Electrical Load for the hour.
EL is the sum of ELp for all Participants.
ADJor is the adjustment required to reflect the amount of that category of
Operating Reserve that the Participant has Self-Supplied and all Bilateral
Transactions entered into by the Participant that transfer for the hour all or
part of a Settlement Obligation for that category of Operating Reserve to or
from another Participant but have not been reflected in the Participant's
Electrical Load for the hour.
A Settlement Obligation for Operating Reserve shall require the Participant to
pay in accordance with the provisions of Section 14A.8(b) and applicable Market
Rules.
(d) 4-Hour Reserve Settlement Obligation. Each Participant shall have for each
hour a Settlement Obligation for 4-Hour Reserve to the extent provided for in
Section 14A.8(d), adjusted up or down as appropriate to reflect all Bilateral
Transactions entered into by the Participant that transfer all or a part of the
Settlement Obligation for 4-Hour Reserve to or from another Participant. A
Settlement Obligation for 4-Hour Reserve shall require the Participant to pay in
accordance with Section 14A.8(d) and applicable Market Rules.
(e) AGC Settlement Obligation. Settlement Obligations for AGC for each hour are
established by allocating the total AGC designated for the hour in the Real-Time
Market by the System Operator to Participants under the Agreement and
Non-Participants under the Tariff. Each Participant shall have for each hour a
Settlement Obligation for AGC that, subject to adjustment pursuant to Section
14A.11, shall be determined in accordance with the following formula:
AGCp = AGC (ELp/EL) + ADJAGC, wherein
AGCp is the Participant's share of AGC for the hour.
AGC is the total amount of AGC determined by the System Operator in accordance
with applicable NEPOOL System Rules to be required for the NEPOOL Control Area
for the hour that is not assigned to Non-Participants.
ELp and EL are as defined in Section 14A.1(c).
ADJAGC is the adjustment required to reflect all Bilateral Transactions entered
into by the Participant to transfer all or part of a Settlement Obligation for
AGC to or from another Participant but that have not been reflected in the
Participant's Electrical Load for the hour and the amount, if any, that the
Participant has, in accordance with applicable Market Rules, Self-Supplied.
A Settlement Obligation for AGC shall require the Participant to pay in
accordance with Section 14A.8(c) and applicable Market Rules.
14A.2 Right to Receive Service. Except as emergency circumstances may result in
the System Operator requiring load curtailments by Participants, and subject to
the availability of transmission capacity, each Participant shall be entitled to
receive from other Participants (or from the service made available from
Non-Participants pursuant to arrangements entered into under Section 14A.11)
such amounts, if any, of Energy, Operating Reserve, 4-Hour Reserve and AGC as it
requires. If, for any hour, load curtailments or other emergency measures are
required, the amount of services that Participants are entitled to receive shall
be reduced by the System Operator in a fair and non-discriminatory manner in
light of the circumstances and applicable NEPOOL System Rules.
14A.3 Participation in the Day-Ahead Market.
(a) Demand Bids and Supply Offers for the Day-Ahead Market shall be submitted by
Participants for each hour of the Dispatch Day, in accordance with this
Agreement and applicable Market Rules. Such Demand Bids and Supply Offers shall
include the information required by the Market Rules.
(b) Any Participant with authority to submit a Supply Offer in accordance with
Section 14A.4 for a Resource that is eligible to supply Energy at a Node or
External Node, Operating Reserve, 4-Hour Reserve or AGC, or for load that is
capable of reducing its consumption within four hours to supply 4-Hour Reserve,
may submit in the Day-Ahead Market to, or have on file with, the System
Operator, a Supply Offer for each such Resource or load reduction, to the extent
permitted by and in accordance with Section 14A.4 and applicable Market Rules;
provided that as one alternative to submitting Supply Offers for Operating
Reserve and/or 4-Hour Reserve, a Participant desiring to provide such services
may enter into a Reserve Contract with the System Operator pursuant to Section
14A.10(c) covering such services.
(c) Any Participant wishing to purchase Energy in the Day-Ahead Market may
submit to, or have on file with, the System Operator in accordance with
applicable Market Rules a Day-Ahead Demand Bid or Bids specifying Demand Bid
Prices for such Energy in each hour of the Dispatch Day at any Location,
including the Hub.
(d) Any Participant wishing to sell Energy into the Day-Ahead Market from a
Control Area outside the NEPOOL Control Area may do so by submitting a Supply
Offer for Energy in the Day-Ahead Market at an External Node. Participants
wishing to purchase Energy in the Day-Ahead Market for sale outside of the
NEPOOL Control Area may do so by submitting a Demand Bid in the Day-Ahead Market
at an External Node.
(e) Any Participant seeking to Self-Schedule a Resource in the Day-Ahead Market
or to affect its Day-Ahead Settlement Obligation through a Bilateral
Transaction, a Self-Supply of Operating Reserve, or a Self-Supply of AGC to the
extent permitted by applicable Market Rules, shall submit or cause to be
submitted all necessary information with respect thereto to the System Operator
in accordance with Section 14A.4(i) or Section 14A.11 and applicable Market
Rules.
(f) In accordance with Market Rules, any Participant seeking to effect a
transaction that moves Energy through or out of the NEPOOL Control Area by
combining a Demand Bid at an External Node with a Supply Offer at any other Node
may elect to specify the maximum Congestion Cost it is willing to pay to have
its transaction scheduled or, once scheduled, to keep that transaction from
being wholly or partially curtailed.
14A.4 Nature of Demand Bids and Supply Offers; Limitations; Self- Schedules and
Self-Supplies.
(a) Carry Over Procedures: If a Supply Offer or Demand Bid is not submitted for
a Resource in the Day-Ahead Market, the Supply Offer or Demand Bid shall be
deemed to be the last valid Supply Offer or Demand Bid on file with the System
Operator, except for Supply Offers and Demand Bids at External Nodes, which
shall be deemed to be unavailable. If a Supply Offer or Demand Bid for
Dispatchable Load is not submitted for a Resource in the Real-Time Market, the
Supply Offer or Demand Bid shall be deemed to be the Supply Offer or Demand Bid
submitted in the Day-Ahead Market, except for Supply Offers and Demand Bids at
External Nodes which shall not carry over and must be submitted in accordance
with applicable Market Rules.
For a generating unit in which there are multiple Entitlement holders, only one
Participant shall be permitted to submit Supply Offers for such unit. The
Entitlement holders in each unit with multiple Entitlement holders shall
designate a single Participant that will be permitted to submit Supply Offers
and/or to direct the scheduling of the unit. In the event that more than one
Participant is designated, or if the Entitlement holders do not designate a
single Participant, then the Supply Offer Price for Energy for the unit shall be
based on the replacement cost of fuel. Such Supply Offer Price, operational
parameters and other information required under the Market Rules to be furnished
to the System Operator shall be furnished to the System Operator by the
Participant validly furnishing replacement cost of fuel as of December 31, 1996.
Nothing in this Agreement shall affect the rights of any Entitlement holder
under the contractual arrangements among such Entitlement holders relating to a
generating unit.
(b) Each Supply Offer for Energy shall specify the Node or External Node where
the Energy will be provided. Each Demand Bid shall specify the Location where
the Energy will be received. Supply Offers and Demand Bids at External Nodes
shall be adjusted as appropriate by the System Operator to account for
transmission losses on Non-PTF, if any, between the PTF and the transmission
facilities of the neighboring Control Area. Metered values for Electrical Load
on the Non-PTF shall be adjusted as appropriate by the System Operator to
account for transmission losses on the Non-PTF, if any, between the PTF and the
transmission facilities of the neighboring Control Area. The System Operator
shall post on its Internet website loss factors for each External Node.
(c) Each Supply Offer for Energy from a generating unit or Supply Offer at an
External Node in the Day-Ahead Market shall contain the information required by
applicable Market Rules and shall, at a minimum, specify the offered incremental
Energy prices, and may include a Start-Up Price and No- Load Price, if any, and
operational parameters. Each Supply Offer for Energy from Resources in the
Real-Time Market shall specify, in addition to the Node or External Nodes, only
incremental Energy prices. Each Supply Offer Price for incremental Energy from a
segment of a Resource shall be equal to or greater than the Supply Offer Price
for any lesser quantity of Energy.
Each Demand Bid shall contain the information required by the applicable Market
Rules and shall at a minimum state the bid decremental prices of Energy. Each
Demand Bid Price for a block of Energy shall be equal to or less than the Price
for any lesser quantity of Energy.
(d) Supply Offers may be submitted in the Day-Ahead Market for 10-Minute
Spinning Reserve, 10-Minute Non-Spinning Reserve, 30-Minute Operating Reserve,
4-Hour Reserve, and AGC. Each Supply Offer shall specify a separate Supply Offer
Price for the service offered.
(e) Supply Offers for 10-Minute Spinning Reserve, 10-Minute Non-Spinning
Reserve, and/or 30-Minute Operating Reserve may be submitted in the Real-Time
Market only for fast start resources, as defined in the Market Rules. Each
Supply Offer shall specify a separate Supply Offer Price for the service
offered. Supply Offers for AGC also may be submitted in the Real-Time Market
from a generating unit and shall specify the Supply Offer Price for such
service.
(f) To the extent a Resource qualifies to provide Operating Reserve or 4- Hour
Reserve and is not self-scheduled or has not submitted a Supply Offer to provide
such service(s), a Supply Offer to provide Energy from a Resource in any hour in
the Day-Ahead Market may also be considered in accordance with the Market Rules
to be a Supply Offer to provide Operating Reserve or 4-Hour Reserve at the
Resource's Lost Opportunity Cost for such hour based on its Day-Ahead Supply
Offer Price for Energy. The Supply Offer Price for a category of Operating
Reserve or 4-Hour Reserve from a Resource in an hour shall be the greater for
such hour of the submitted Supply Offer Price for such service or the Lost
Opportunity Cost.
Each Supply Offer to provide Energy from a Resource other than a Dispatchable
Load in any hour in the Real-Time Market is also a Supply Offer to provide
Operating Reserve at the Resource's Lost Opportunity Cost for such hour based on
its Real-Time Energy Supply Offer Price if and to the extent such Resource
qualifies to provide Operating Reserve under the applicable Market Rules. For
Resources submitting Supply Offers for Operating Reserve in the Real-Time Market
pursuant to Section 14A.4(e) or as otherwise permitted under the Agreement or
the Market Rules, the Supply Offer Price for service from the
Resource in each hour shall be the greater of the submitted Supply Offer Price
or the Lost Opportunity Cost for such hour.
(g) Each Real-Time Supply Offer Price for Energy from the portion of a Resource
scheduled to provide Operating Reserve, 4-Hour Reserve or AGC in the Day-Ahead
Market shall be less than or equal to the Day-Ahead Supply Offer Price for
Energy for such portion.
Each Real-Time Supply Offer Price for AGC from the portion of a generating unit
eligible to provide AGC and scheduled to provide Energy, Operating Reserve, AGC
or 4-Hour Reserve in the Day-Ahead Market shall be less than or equal to the
Day-Ahead Supply Offer Price for AGC from such generating unit.
Each Real-Time Supply Offer Price for any category of Operating Reserve for the
portion of a Resource scheduled to provide Operating Reserve Day-Ahead and
eligible to submit a Supply Offer Price for that portion of the Resource for
that category of Operating Reserve in the Real-Time Market shall be less than or
equal to the Day-Ahead Supply Offer Price for such category of Operating Reserve
from such portion of that Resource.
(h) If there are multiple Supply Offers for Energy submitted by Participants in
the Day-Ahead or Real-Time Market specifying the same effective Supply Offer
Price (as adjusted for Marginal Losses), and no lower Supply Offer Prices (as
adjusted for Marginal Losses) are available in the applicable Market to meet the
next decrement of load at that Node or External Node, then ties will be broken
in accordance with or scheduled amounts pro rated in accordance with the Market
Rules.
(i) Each Participant with authority to submit Supply Offers for a Resource may
submit a Self-Schedule for Energy from its Resources in either the Day- Ahead or
Real-Time-Market in accordance with applicable Market Rules. The Self-Schedule
defines the Participant's plan to provide Energy from a given generating unit or
to consume Energy for a Dispatchable Load (e.g., a pumped storage facility in
the pumping mode), or to import or export Energy at an External Node. The
Self-Scheduled Energy from a generating unit or consumed by a Dispatchable Load
must satisfy the operating parameters included in the applicable Supply Offer or
Demand Bid. For a Self-Schedule of a Resource other than a Dispatchable Load to
be accepted, the Participant submitting that Self-Schedule must also submit at
least one or more Supply Offer Prices, each equal to or less than zero, for the
Energy associated with the entire Self-Scheduled portion of that Resource.
14A.5 Scheduling Procedures in the Day-Ahead Market.
(a) The System Operator shall perform for each Dispatch Day in accordance with
the NEPOOL System Rules a security constrained unit commitment schedule using a
computer algorithm which simultaneously minimizes the total cost for: (i)
supplying Energy to satisfy accepted Demand Bids in the Day-Ahead Market; (ii)
providing the quantity of Operating Reserves and AGC required by NEPOOL System
Rules; and (iii) providing any necessary 4-Hour Reserves in accordance with
Section 14A.5(f) and applicable NEPOOL System Rules. The schedule shall take
into account all Self-Schedules and Self-Supplies submitted by Participants for
the Day-Ahead Market. In accordance with the NEPOOL System Rules, the schedule
shall also take into account, among other things, phase shifters and other power
flow control devices, transmission system limitations, including but not limited
to internal system limitations and external interface limits, and contingencies
reasonably identified pursuant to criteria posted on the System Operator's
Internet website that may constrain outputs or require additional supply in
specific locations.
(b) The amount of each category of Operating Reserve scheduled in the Day- Ahead
Market by the System Operator shall be in accordance with the NEPOOL System
Rules, shall take into account the grid and generator configuration for the
Dispatch Day, and may be price sensitive in whole or in part such that the
required amount of Operating Reserve decreases as the price for Operating
Reserve increases. Any NEPOOL System Rule in effect before the CMS/MSS Effective
Date designed to maintain reliability while producing just and reasonable
charges and payments for Operating Reserves during times of emergency or
shortages of available Energy and/or Operating Reserves shall remain in effect
on and after the CMS/MSS Effective Date unless and until subsequently amended,
and may be in addition to or in lieu of the establishment of price sensitive
Operating Reserve requirements.
(c) The simultaneous optimization process used to determine schedules in the
Day- Ahead Market shall ensure that all portions of Resources with Supply Offers
not scheduled to provide Energy shall cascade to the markets for AGC, Operating
Reserves and 4-Hour Reserves to the extent such Resources are eligible to
provide those services and consistent with the Supply Offer Prices established
in accordance with Section 14A.4. This process shall also ensure that all
portions of Resources with Supply Offers not scheduled to provide Energy may be
considered for meeting the requirements to provide AGC, Operating Reserves and
4-Hour Reserves.
(d) In the scheduling of Resources for Operating Reserves, 4-Hour Reserves and
AGC in the Day-Ahead Market, the simultaneous optimization process shall use the
following principles: Resources that are Self-Scheduled pursuant to applicable
Market Rules to provide Energy shall be reflected in the schedule in accordance
with the Self-Schedule except as provided below; Resources that are designated
for Self-Supply in accordance with applicable Market Rules shall be reflected in
the schedules to the extent they are so designated except as provided below;
Resources, to the extent not scheduled or Self- Scheduled for Energy or
designated for Self-Supply and eligible to provide Operating Reserve, shall be
scheduled by the System Operator based on the higher of their Lost Opportunity
Costs, if any, or their applicable Day-Ahead Supply Offer Prices; and Resources,
to the extent not scheduled or Self- Scheduled for Energy or designated for
Self-Supply and eligible to provide AGC, shall be scheduled based on their Lost
Opportunity Costs, if any, plus their Day-Ahead Supply Offer Prices for AGC. The
System Operator may direct changes to any Self-Schedule and/or Self-Supply if,
but only to the extent, necessary for reliability.
(e) At the conclusion of the scheduling process set forth in Section 14A.5(a),
the System Operator shall publish each day in accordance with the Market Rules
and in a way that is consistent with the NEPOOL Information Policy the
information required by Section 14A.18. The System Operator's schedule for the
Day-Ahead Market shall identify to each Entitlement holder, the expected start
and shut down times for all of its Resources or Entitlements that are scheduled
in the Day-Ahead Market
(f) If the System Operator's Day-Ahead forecast of the NEPOOL load exceeds the
aggregate of the Participants' Demand Bids accepted in the Day-Ahead Market for
any hour of the Dispatch Day, the System Operator may schedule, in accordance
with the applicable NEPOOL System Rules, 4-Hour Reserves to be available to
cover part or all of the difference.
14A.6 Participation in the Real-Time Market.
(a) Supply Offers and Demand Bids for the Real-Time Market shall be submitted by
Participants for each hour of the Dispatch Day of the Real-Time Market, to the
extent permitted by and in accordance with Section 14A.4 and applicable Market
Rules. Such Supply Offers and Demand Bids shall include the information required
by the Market Rules.
(b) Each Participant with authority to submit a Supply Offer in accordance with
Section 14A.4 for a Resource that is eligible to supply Energy, Operating
Reserve, or AGC, may submit in the Real-Time Market to, or have on file with,
the System Operator, or modify, a Supply Offer for each such Resource, to the
extent permitted by and in accordance with applicable Market Rules and subject
to the limitations of Section 14A.4(g). New or modified Supply Offers may, among
other matters, (i) offer Energy at a Node or External Node, Operating Reserves
and AGC from a generating unit not scheduled in the Day-Ahead Market which can
be dispatched by the System Operator in the Real-Time Market, (ii) increase or
decrease the Supply Offer Price for Energy from a Resource scheduled in the
Day-Ahead Market, (iii) reduce the Supply Offer Price for Energy from a
generating unit scheduled to provide AGC, Operating Reserves, or 4-Hour Reserves
in the Day-Ahead Market, and (iv) propose new Supply Offers and/or Demand Bids
at External Nodes.
(c) Each Participant seeking to Self-Schedule its Resource in the Real-Time
Market or to affect its Real-Time Settlement Obligation through a Bilateral
Transaction, a Self-Supply of Operating Reserve, or a Self-Supply of AGC to the
extent permitted by applicable Market Rules, shall submit or cause to be
submitted all necessary information with respect thereto to the System Operator
in accordance with Section 14A.4(i) or Section 14A.11 and applicable Market
Rules.
14A.7 Scheduling Procedures in the Real-Time Market.
(a) A Participant at its own cost may bring on line a generating unit not
scheduled to operate in the Day-Ahead Market, after giving such notice as is
required by the Market Rules, and receiving the System Operator's approval, so
that the generating unit can be dispatched by the System Operator based on the
Participant's Real-Time Energy Supply Offer. The Participant electing to bring
its generating unit on line in accordance with this Section 14A.7 shall not be
entitled to any uplift under Section 14A.19 with respect to its costs in this
instance, although such Participant may qualify for uplift under other
provisions of this Agreement or applicable Market Rules.
(b) The System Operator shall centrally dispatch all available Resources,
including Self-Scheduled Resources, in Real-Time in accordance with NEPOOL
System Rules, based on the schedule in the Day-Ahead Market, increases or
decreases in load, the occurrence of contingencies, and the submission of new or
modified Real-Time Demand Bids or Supply Offers, new or modified Self- Schedules
and new or modified Self-Supply designations made in accordance with applicable
Market Rules. This dispatch shall also include adjustments to the Day-Ahead
Market schedule to reflect the activation of resources scheduled for 4-Hour
Reserve if necessary to maintain system reliability.
(c) The amount of each category of Operating Reserve designated in the Real-
Time Market by the System Operator shall be in accordance with the NEPOOL System
Rules, shall take into account the grid and generator configuration for the
Dispatch Day, and may be price sensitive in whole or in part such that the
required amount of Operating Reserve decreases as the price for Operating
Reserve increases. Any NEPOOL System Rule in effect before the CMS/MSS Effective
Date designed to maintain reliability while producing just and reasonable
charges and payments for Operating Reserves during times of emergency or
shortages of available Energy and/or Operating Reserves shall remain in effect
on and after the CMS/MSS Effective Date unless and until subsequently amended,
and may be in addition to or in lieu of the establishment of price sensitive
Operating Reserve requirements.
(d) A simultaneous optimization process shall be used to determine the Energy,
AGC and Operating Reserve to be provided by each Resource in the Real-Time
Market. This process shall ensure that all portions of Resources with Supply
Offers not scheduled to provide Energy shall cascade to the markets for AGC and
Operating Reserves to the extent such Resources are eligible to provide those
services and consistent with Supply Offer Prices established in accordance with
Section 14A.4. This process shall also ensure that all portions of Resources
with Supply Offers not dispatched to provide Energy may be considered for
meeting the requirements to provide AGC and Operating Reserves.
(e) In selecting Resources to provide Operating Reserves and AGC in Real- Time,
the simultaneous optimization process shall use the following principles:
Resources that are Self-Scheduled to provide Energy in accordance with
applicable Market Rules shall be reflected in the dispatch to the extent they so
perform, except as provided below; Resources that are permitted by Market Rules
to be designated for Self-Supply and are so designated shall be reflected in the
dispatch to the extent they are so designated and perform or remain available,
except as provided below; Resources, to the extent not scheduled or
Self-Scheduled for Energy or designated for Self-Supply and eligible to provide
10-Minute Spinning Reserve in the Real-Time Market, shall be designated by the
System Operator based on their Lost Opportunity Costs, if any. Resources, to the
extent not scheduled or Self-Scheduled for Energy or designated for Self-Supply
and eligible to provide 10-Minute Non-Spinning Reserves or 30 Minute Operating
Reserves shall be designated based on the higher of their Lost Opportunity
Costs, if any, or their applicable Supply Offer Prices. Generating units, to the
extent they are not scheduled or Self-Scheduled for Energy or designated for
Self-Supply and eligible to provide AGC, shall be designated based on their Lost
Opportunity Costs, if any, plus their Real-Time Supply Offer Prices for AGC. The
System Operator may direct changes to any Self-Schedule and/or Self- Supply if,
but only to the extent, necessary for reliability.
(f) Supply Offers and Demand Bids at External Nodes will be dispatched in the
Real-Time Market based on the Real-Time Supply Offer Price and Demand Bid Price,
respectively, for the hour. If the net aggregate amount of service pursuant to
eligible Supply Offers or Demand Bids at an External Node would exceed the
applicable interface limit, then Supply Offers with the lowest price or the
Demand Bids with the highest price shall be scheduled. If such competing Supply
Offers and/or Demand Bids have the same prices, ties will be broken or
transactions pro rated in accordance with the Market Rules.
14A.8 Settlement Obligation Payments for Energy, Operating Reserves, 4- Hour
Reserves and Automatic Generation Control.
(a) For each hour in which a Participant has a Settlement Obligation for Energy
at a Location in the Day-Ahead Market pursuant to Section 14A.1(b), the
Participant shall pay or receive for the megawatthours of the Settlement
Obligation at that Location at the applicable Day-Ahead Market Locational Price
for that hour, as determined in accordance with Section 14A.12. For each hour in
which a Participant has a Settlement Obligation for Energy at a Location in the
Real-Time Market pursuant to Section 14A.1(b), the Participant either (i) shall
pay the applicable hourly Real-Time Market Locational Price for the number of
megawatthours, if any, by which the Participant's Settlement Obligation for
Energy received at that Location in the Real-Time Market is more than the
Participant's Settlement Obligation for Energy received at that Location in the
Day-Ahead Market, or (ii) shall receive the applicable hourly Real-Time Market
Locational Price for the number of megawatthours, if any, by which the
Participant's Settlement Obligation for Energy received at that Location in the
Real-Time Market is less than the Participant's Settlement Obligation for Energy
received at that Location in the Day-Ahead Market, as determined in accordance
with Section 14A.12. The Participant shall also pay any applicable uplift
charges under Section 14A.19. A Participant shall pay the Zonal Price for Energy
received in a Load Zone unless it elects, in accordance with applicable Market
Rules, to pay the Nodal Price for such Energy.
(b) For each hour in which a Participant has a Settlement Obligation for
Operating Reserve pursuant to Section 14A.1(c), the Participant shall pay for
Operating Reserve in each category in which it has an obligation a percentage
share of the aggregate payments to Participants pursuant to Section 14A.9 for
satisfying their Supply Obligations for each such category of Operating Reserve
for the hour equal to the Participant's percentage share of the total Settlement
Obligations for Operating Reserve of such category for the hour, as determined
pursuant to Section 14A.1(c). In addition, the Participant shall pay any
applicable uplift charge assessed under Section 14A.19.
(c) For each hour in which a Participant has a Settlement Obligation for AGC
pursuant to Section 14A.1(e), the Participant shall pay a percentage of the
aggregate payments to Participants pursuant to Section 14A.9 for satisfying
their Supply Obligations for AGC for the hour equal to the Participant's
percentage share of the total Settlement Obligation for AGC for the hour as
determined pursuant to Section 14A.1(e).
(d) For any hour in which the System Operator schedules 4-Hour Reserves in the
Day-Ahead Market, the aggregate payment to Participants pursuant to Section
14A.9 for satisfying their Supply Obligations for 4-Hour Reserves for the hour
shall be allocated to Participants and paid by them as follows:
Step 1. The hourly per Megawatt cost for 4-Hour Reserve for the hour shall be
determined by dividing the total 4-Hour Reserve payments pursuant to Section
14A.9 for the hour by the number of Megawatts of 4-Hour Reserve scheduled in the
Day-Ahead Market to be available in the hour.
Step 2. If a Participant's Net Hourly Load Obligation for Energy for the hour is
positive and exceeds the Participant's accepted Demand Bids for the hour in the
Day-Ahead Market, it shall pay for each Megawatt of such excess the per Megawatt
cost determined in accordance with Step 1 above, but not more than its pro rata
share of the 4-Hour Reserve cost for the hour.
Step 3. If the allocation in Step 2 above is insufficient to recover the full
4-Hour Reserve cost for the hour, the remaining cost shall be allocated to all
Participants for the hour, including those required to make payments in
accordance with Step 2, in proportion to their shares of the aggregate Net
Hourly Load Obligation for Energy for the hour.
The provisions of Step 2 and Step 3 above are subject to future modifications to
comply with the Commission's June 28, 2000 order in Docket Nos. EL00-62- 000, et
al., and future orders pertaining thereto, with respect to the allocation of
uplift costs and in light of filings concerning the use of Net Hourly Load
Obligation for Energy as an allocation factor, and Steps 2 and 3 do not become
effective except pursuant to a future Commission order.
14A.9 Supply Obligation Payments For Energy, Operating Reserves, 4-Hour Reserves
and Automatic Generation Control.
(a) Subject to the provisions of Section 14A.16, each Participant with a Supply
Obligation for Energy in an hour in the Day-Ahead Market at any Node or External
Node shall receive for each megawatthour scheduled at the Node or External Node
in the Day-Ahead Market the Day-Ahead Nodal Price for the hour at that Node or
External Node, as determined in accordance with Section 14A.12. Subject to the
provisions of Section 14A.16, a Participant with a Supply Obligation for Energy
at any Node or External Node in an hour in the Real-Time Market that is more
than the Participant's Supply Obligation for Energy at that Node or External
Node for the hour in the Day-Ahead Market, shall receive for each additional
megawatthour of such excess the Real-Time Market Nodal Price for the hour at
that Node or External Node, as determined in accordance with Section 14A.12.
Subject to the provisions of Section 14A.16, each Participant with a Supply
Obligation for Energy at any Node or External Node in an hour in the Real-Time
Market that is less than the Participant's Supply Obligation for Energy at that
Node or External Node for the hour in the Day-Ahead Market shall pay for each
megawatthour of such deficiency the Real-Time Market Nodal Price for the hour at
that Node or External Node, as determined in accordance with Section 14A.12. In
addition, Participants may receive or be required to pay applicable uplift
charges, if any, pursuant to Section 14A.19 or the Market Rules and to pay for
4-Hour Reserves pursuant to Section 14A.8(d).
(b) Each Participant with a Supply Obligation for Operating Reserve or 4- Hour
Reserve in an hour in the Day-Ahead Market shall receive for each Megawatt of
each category of Operating Reserve and/or 4-Hour Reserve scheduled the
applicable Day-Ahead Market Operating Reserve Clearing Price or 4-Hour Reserve
Clearing Price, as appropriate, as determined in accordance with Section 14A.13.
For any hour in which the Participant's Supply Obligation for Operating Reserve
of any category in the Real-Time Market exceeds the Participant's Supply
Obligation for such service for the hour in the Day-Ahead Market, the
Participant shall receive for the additional Megawatts the applicable Real-Time
Market Operating Reserve Clearing Price for the hour, as determined in
accordance with Section 14A.13. For any hour in which the Participant's Supply
Obligation for Operating Reserve of any category in the Real-Time Market is less
than the Participant's Supply Obligation for such service for the hour in the
Day-Ahead Market, the Participant shall pay for each Megawatt of such deficiency
the applicable Real-Time Market Operating Reserve Clearing Price for the hour,
as determined in accordance with Section 14A.13. If a Participant has a Supply
Obligation for 4-Hour Reserve in any hour in the Day-Ahead Market and fails to
provide all or a portion of the Energy from its 4-Hour Reserve in response to
the System Operator's dispatch instructions, the Participant shall pay the Real-
Time Market 30-Minute Operating Reserve Clearing Price for each Megawatt not
provided, in addition to any payments required under Section 14A.8(d).
(c) Each Participant with a Supply Obligation for AGC in an hour in the Day-
Ahead Market shall receive for the scheduled amount the Day-Ahead Market AGC
Clearing Price for the hour, as determined in accordance with Section 14A.14.
For any hour in which the Participant's Supply Obligation for AGC in the
Real-Time Market exceeds the Participant's Supply Obligation for AGC for the
hour in the Day-Ahead Market, the Participant shall receive for such excess the
Real-Time Market AGC Clearing Price for the hour, as determined in accordance
with Section 14A.14. For any hour in which the Participant's Supply Obligation
for AGC in the Real-Time Market is less than the Participant's Supply Obligation
for AGC for the hour in the Day-Ahead Market, the Participant shall pay for such
deficiency the Real-Time Market AGC Clearing Price for the hour, as determined
in accordance with Section 14A.14.
(d) In no event shall Participants be paid lost opportunity costs resulting from
a generating unit being dispatched down or off to accommodate transmission
constraints, and nothing in this Agreement or the Market Rules shall provide for
any such payment.
14A.10 Contract and Scheduling Authority.
(a) The Participants Committee is authorized to enter into contracts on behalf
of and in the names of all Participants with Non-Participants to purchase or
furnish emergency Energy that is available for the System Operator to schedule
in order to ensure reliability in the NEPOOL Control Area or neighboring Control
Areas. For sales to another Control Area, the terms of any such contractual
arrangement shall not require the furnishing of such emergency service until the
service needs of all Participants have been provided for with the least
expensive resources practicable. Emergency purchases pursuant to this Section
14A.10 should not be required unless the Participants have been unable to
furnish such Supply Offers as the System Operator determines are required to
ensure reliability. For emergency purchases and sales pursuant to this Section
14A.10, the treatment of the transaction with the Non-Participant in the
determination of a Locational Price shall be in accordance with applicable
Market Rules. Energy (and related services) from any such emergency purchases
shall be deemed to be furnished to and shall be paid for by Participants with
Settlement Obligations in the Real-Time Market, in accordance with this Section
14A.10(a) and applicable Market Rules.
(b) The NEU Management Committee (as defined in the HQ Use Agreement) is
authorized to provide for the day-to-day scheduling through the System Operator
of the HQ Phase II Firm Energy Contract, in accordance with the HQ Use
Agreement, as if the Contract were a contract covering Energy transactions with
a Non-Participant entered into pursuant to Section 14A.10(a). Energy received in
an hour from Hydro-Quebec pursuant to the HQ Energy Banking Agreement, and
Energy purchased in any hour from Hydro-Quebec pursuant to the HQ Phase II Firm
Energy Contract any other HQ Contract shall be deemed to be Energy furnished at
the appropriate External Node to each Participant which has submitted a Supply
Offer at the appropriate External Node for such Energy for the hour in the
amount reflected for the Participant in the System Operator's scheduling of
Energy deliveries in the hour from Hydro-Quebec; except that emergency Energy
received from Hydro-Quebec under the HQ Interconnection Agreement shall be
deemed to be Energy provided to (and shall be paid for by) Participants
requiring such emergency Energy in the hour. The System Operator shall schedule
such Energy deliveries to accommodate, to the extent possible, the schedule of
Energy deliveries from Hydro-Quebec requested by the Participants within their
Supply Offers. The Participants deemed to have received such Energy shall have a
corresponding Supply Obligation and shall satisfy this and all other Supply
Obligations at this External Node and all other Nodes in accordance with Section
14A.1, 14A.8 and 14A.9. The Participants are responsible for paying to
Hydro-Quebec the price for Energy deliveries under the HQ Phase II Firm Energy
Contract and under the HQ Energy Banking Agreement.
(c) The System Operator is authorized in accordance with applicable Market Rules
to enter into Reserve Contracts with individual Participants under which the
System Operator pays for and receives options or rights to all or a portion of
10-Minute Non-Spinning Reserve, 30-Minute Operating Reserve and/or 4-Hour
Reserve from generating units or Dispatchable Loads for forward periods, such as
a week or a month, as determined by the System Operator. Such Reserve Contracts
shall be in accordance with applicable Market Rules and shall be entered into
with Participants which offer the service in response to a request for
proposals, shall include the Reserve Price at which the Operating Reserve or
4-Hour Reserve will be made available and the price at which Energy will be
furnished on the activation of the Operating Reserve or 4-Hour Reserve, and
shall contain standard terms and conditions specified by the System Operator in
accordance with the Market Rules.
14A.11 Bilateral Transactions and Participant Transactions with Non-
Participants.
(a) Two Participants may undertake to transfer all or select portions of the
Settlement Obligations of one of them under this Agreement to the other
Participant with respect to any of the NEPOOL Markets pursuant to a Bilateral
Transaction. Such transfer of Settlement Obligations under this Agreement shall
be as agreed to between the two parties to the Bilateral Transaction and shall
be submitted to the System Operator in accordance with the Market Rules. Each
Bilateral Transaction submitted shall specify whether the transaction is to
settle in the Day-Ahead Market or the Real-Time Market and, if it is for Energy,
a Location.
(b) In the event a Participant has the right to receive Energy, Operating
Reserve, 4-Hour Reserve and/or AGC from a Non-Participant under a System
Contract, such Contract may be submitted to the System Operator in a Supply
Offer as a proposal to furnish Energy, Operating Reserve, 4-Hour Reserve, and/or
AGC, to the extent the System Contract permits central dispatch by the System
Operator in accordance with the Market Rules and otherwise qualifies for such
service.
14A.12 Determination of Locational Prices.
The System Operator shall calculate Locational Prices for the Day-Ahead and
Real-Time Markets as described below.
(a) Nodal Prices. The System Operator shall calculate the Nodal Price at each
Node for each hour of the Dispatch Day for the Day-Ahead Market using the
Day-Ahead unit commitment model, and for the Real-Time Market using the
Real-Time scheduling software. In calculating Nodal Prices the System Operator
shall use the Demand Bids and Supply Offers submitted pursuant to Sections
14A.3, 14A.4 and 14A.6. The Real-Time Nodal Price at each Node for each hour
shall be the time interval weighted-average of the Clearing Prices calculated at
that Node for each time interval within that hour, except as noted in subsection
(d) below with respect to the prices used for Real-Time settlements at External
Nodes.
The System Operator shall calculate Nodal Prices for an hour for the Day- Ahead
Market or the Real-Time Market at a given Node i using the following formula, or
a formula similar in substance and effect:
(EQUATION)
where:
(EQUATION) the Nodal Price at Node i in $/megawatthour;
(EQUATION) the marginal cost in $/megawatthour, based on Demand Bids and
Supply Offers, to serve additional load at the Reference Node;
(EQUATION) the Marginal Loss Component of the Nodal Price at Node i in
$/megawatthour; and
(EQUATION) the Congestion Component of the Nodal Price at Node i in
$/megawatthour.
The Marginal Loss Component of the Nodal Price at any Node i on the NEPOOL
Transmission System is calculated using the equation
(EQUATION)
in which WFi, the Withdrawal Factor at Node i relative to the system Reference
Node, is calculated using the following equation:
(EQUATION)
where:
L = NEPOOL Transmission System losses;
Pi = the net amount of Energy injected into the NEPOOL Transmission System at
Node i; and
(EQUATION) = the ratio of: (1) the amount by which NEPOOL Transmission
System losses occurring in the Day-Ahead Schedule or Real-Time dispatch would
have increased, as calculated by the System Operator's Day-Ahead or Real-Time
computer algorithm, if a very small additional amount of Energy had been
injected at Node i (in addition to the injections and withdrawals already
scheduled to occur on the NEPOOL Transmission System in the Day-Ahead schedule
or occurring on the NEPOOL Transmission System in the Real-Time dispatch), to
(2) the size of the additional injection of Energy at Node i.
The Congestion Component of the Nodal Price at Node i is calculated using the
equation:
(EQUATION),
where:
K = the set of thermal or interface constraints;
GFik = the Shift Factor for the generator at Node i on constraint k in the pre-
or post-contingency case that limits flows across that constraint; and
(EQUATION) = the reduction in system cost that results from an incremental
relaxation of constraint k, expressed in $/megawatthour.
Substituting the equations for calculating the Marginal Loss Component and the
Congestion Component of the Nodal Price for the terms and into the equation for
calculating the Nodal Price for a given Node i yields:
(EQUATION)
(b) Zonal Prices. For Congestion pricing purposes, Load Zones based on
Reliability Regions have been established and Zonal Prices shall be calculated
by the System Operator for each Load Zone. Each Load Zone shall be coterminous
with a Reliability Region, except that a Participant which owns and operates
distribution lines and other facilities used for the distribution of Energy to
retail customers in a single state in New England and which is subject to
regulation by the public utility regulatory authority in that state (a
"Distribution Company"), which (i) serves retail customers in more than one
Reliability Region in a single state and (ii) is subject to a state-imposed
obligation to provide its retail customers with a power supply at fixed prices
for a limited time period following the commencement of retail access ("Standard
Offer Obligation"), may elect, by notice to the System Operator and the
Secretary of the Participants Committee, within the time prescribed by the
Market Rules, to have its entire service territory treated as a single Load Zone
(a "Distribution Company Load Zone") until its Standard Offer Obligation ends.
In addition, Vermont shall be a single Load Zone for those Distribution
Companies in Vermont that maintain their single Participant status for
settlement purposes with other Distribution Companies in Vermont pursuant to
Section 4 of the Agreement even if Vermont spans more than one Reliability
Region. The election by one or more Distribution Companies in Vermont not to be
treated as a single Participant with other Vermont Participants shall not affect
the Load Zone for the remaining Distribution Companies in Vermont maintaining
the single Participant election.
After consulting with the Participants, the System Operator may reconfigure
Reliability Regions and add or subtract Reliability Regions as necessary over
time to reflect changes to the grid, patterns of usage and intrazonal
Congestion. The System Operator shall file any such changes with the Commission.
The System Operator shall calculate Zonal Prices for each Reliability Region for
both the Day-Ahead and Real-Time Markets for each hour using a load- weighted
average of the Nodal Prices for the Nodes within that Reliability Region. The
load weights used in calculating the Day-Ahead Zonal Prices for the Reliability
Region shall be determined in accordance with applicable Market Rules and shall
be based on the Demand Bids for the Nodes that make up that Reliability Region.
The System Operator shall determine, in accordance with applicable Market Rules,
the load weights used in Real-Time based on the calculated Real-Time load
distribution. The System Operator shall calculate Zonal Prices for Reliability
Regions using the following formula, or a formula similar in substance and
effect, where the Zonal Price for a Reliability Region j can be written as:
(EQUATION),
where:
(EQUATION) = Zonal Price for Reliability Region j in $/megawatthour;
(EQUATION) is as defined in Section 14A.12(a);
(EQUATION) is the Marginal Loss Component of the Zonal Price for
Reliability Region j in $/megawatthour;
(EQUATION) is the Congestion Component of the Zonal Price for Reliability
Region j in $/megawatthour;
Nj = the set of Nodes that make up the Reliability Region j; and
Wij = the load-weighting factor for Node i used to calculate the Zonal Price for
Reliability Region j, determined such that the weighting factors for any given
Reliability Region sum to one.
For a Distribution Company Load Zone, the Zonal Price shall be determined by the
weighted average of the Zonal Prices for the Reliability Regions making up the
Load Zone, with the weights equal to that Distribution Company's share of the
load in each of those Reliability Regions. The load weights used in calculating
the Day-Ahead Zonal Prices for the Distribution Company Load Zones shall be
determined in accordance with applicable Market Rules and shall be based on the
Demand Bids for the Nodes that make up the Distribution Company Load Zones.
The System Operator shall determine, in accordance with applicable Market Rules,
the load weights used in Real-Time based on the calculated Real-Time load
distribution. The System Operator shall calculate Zonal Prices for each hour of
the Dispatch Day for Distribution Company Load Zones using the following
formula: Zonal Price equals the Distribution Company's load in each Reliability
Region making up the Distribution Company Load Zone times the Zonal Price for
each such Reliability Region summed for all such Reliability Regions making up
the Distribution Company Load Zone, divided by the sum of the Distribution
Company's load in each Reliability Region making up the Distribution Company
Load Zone. The Congestion and Marginal Loss Components of the Zonal Price for
each Distribution Company Load Zone shall be calculated as the weighted average
of the Congestion and Marginal Loss Components, respectively, of the Zonal
Prices in the Reliability Regions making up that Load Zone, using the same
weights that are used to calculate the Zonal Price for that Distribution Company
Load Zone.
(c) Hub Prices. On behalf of the Participants, the System Operator shall
maintain and facilitate the use of a Hub or Hubs for the Energy market,
comprised of a set of Nodes within NEPOOL, which Nodes shall be identified by
the System Operator on its Internet website. The System Operator has used the
following criteria to establish an initial Hub and shall use the same criteria
to establish any additional Hubs:
(i) each Hub shall contain a sufficient number of Nodes to try to ensure that a
Hub Price can be calculated for that Hub at all times;
(ii) each Hub shall contain a sufficient number of Nodes to ensure that the
unavailability of, or an adjacent line outage to, any one Node or set of Nodes
would have only a minor impact on the Hub Price;
(iii) each Hub shall consist of Nodes with a relatively high rate of service
availability;
(iv) each Hub shall consist of Nodes among which transmission service is
relatively unconstrained; and
(v) no Hub shall consist of a set of Nodes for which directly connected load
and/or generation at that set of Nodes is dominated by any one entity or its
affiliates.
The System Operator shall calculate hourly Hub Prices for both the Day-Ahead and
Real-Time Markets using a fixed-weighted average of the Nodal Prices that
comprise the Hub. The System Operator shall calculate Hub Prices using the
following formula, or a formula similar in substance and effect, where the Hub
Price for a Hub j can be written as:
(EQUATION)
where:
(EQUATION) = Hub Price for Hub j in $/megawatthour;
(EQUATION) is as defined in Section 14A.12(a);
(EQUATION) is the Marginal Loss Component of the Hub Price for Hub j in
$/megawatthour;
(EQUATION) is the Congestion Component of the Hub Price for Hub j in
$/megawatthour;
Hj = the set of Nodes in Hub j; and
WijH = the load weighting factor for Node i used to calculate the Hub Price for
Hub j, determined such that the weighting factors for any given Hub sum to one.
Participants may transfer their Settlement Obligations at the Hub Price in the
Day-Ahead and Real-Time Markets pursuant to Bilateral Transactions. In
accordance with Section 14A.8 of the Agreement, Participants with Settlement
Obligations for Energy at the Hub shall pay or be charged the Hub Price for such
Settlement Obligations.
(d) Nodal Prices for External Nodes. The System Operator shall calculate
Nodal Prices for External Nodes. The External Nodes shall be identified in
applicable Market Rules. External Nodes shall be used for pricing Energy
transactions by
Participants receiving Energy from or delivering Energy to neighboring Control
Areas. The Nodal Prices for External Nodes shall be calculated in the same way
as Nodal Prices for Nodes, with the exception of the calculation of the Marginal
Loss Component of the price.
The Marginal Loss Component of Nodal Prices for External Nodes shall be
calculated so as to ensure that it does not include the effect of withdrawals at
a Node or External Node on the cost of losses incurred outside the NEPOOL
Control Area. In order to accomplish this, a hypothetical transaction will be
modeled, in which an increment of load at each External Node is served by an
increment of generation at the Reference Node. The amount of Energy that would
flow out of the NEPOOL Transmission System over each interconnection point
between the NEPOOL Transmission System and an adjoining Control Area or the
Non-PTF transmission system will be calculated next. Finally, the Marginal Loss
Component of the Nodal Price at each External Node will be calculated as the
weighted average of the Marginal Loss Components at each of the interconnection
points between the NEPOOL Transmission System and an adjoining Control Area or
the Non-PTF transmission system. The weight assigned to each interconnection
will be equal to the proportion of the total amount of Energy delivered off of
the NEPOOL Transmission System in association with this hypothetical transaction
that flows over that interconnection. As a result, the Marginal Loss Component
of the price at each External Node will only include the effects on Marginal
Losses on the NEPOOL Transmission System.
The Shift Factors for each External Node determine the proportion of the Energy
in such a transaction that would flow over each interconnection point between
the NEPOOL Transmission System and external Control Areas or the Non- PTF
transmission system and, therefore, the Marginal Loss Component of the Nodal
Price at an External Node i shall be calculated using the following equation, or
a formula similar in substance and effect:
(EQUATION)
where:
(EQUATION) = the Marginal Loss Component of the Nodal Price at an External Node
i in $/megawatthour;
I = the set of interconnection points between the NEPOOL Transmission
System and adjacent Control Areas or the Non-PTF transmission system;
GFin = Shift Factor at External Node i for the interconnection line that passes
through Node n; and
(WFn - 1) (EQUATION) = the Marginal Loss Component of the Nodal Price at Node n
in $/megawatthour, where WFn is the withdrawal factor at Node n and (EQUATION)
is as defined in Section 14A.12(a).
The price used for Real-Time settlements at External Nodes will be the Real-
Time price as determined based on the Real-Time dispatch except in the
circumstance in which imports or exports were constrained in the hour ahead
scheduling process either by constraints that are not monitored in Real-Time or
by closed interface constraints that are not affected by internal dispatchable
generators. In this special circumstance, the price used for Real-Time
settlements of imports from External Nodes will be the lower of the Real-Time
price at the External Node or the hour ahead price at the External Node.
Similarly, in this situation, the price used for Real-Time settlements of
exports to External Nodes will be the higher of the Real-Time price at the
External Node or the hour ahead price at the External Node.
(e) Additional Rules and Procedures. Consistent with this Section 14A.12,
the implementation of its provisions shall further be detailed, defined and
carried out pursuant to Market Rules.
14A.13 Determination of Operating Reserve and 4-Hour Reserve Clearing
Prices.
(a) Operating Reserve and 4-Hour Reserve shall be scheduled in the Day-Ahead
Market and designated in the Real-Time Market in accordance with the
simultaneous optimization processes described in Sections 14A.5 and 14A.7,
respectively, and the NEPOOL System Rules. As a result, in the Day-Ahead Market
and Real-Time Market, the respective Clearing Price for an hour for 10-Minute
Spinning Reserve shall equal or exceed the Clearing Price for 10-
Minute-Non-Spinning Reserve, which shall equal or exceed the Clearing Price for
30-Minute Operating Reserve, which shall equal or exceed the Clearing Price for
4-Hour Reserve.
(b) For each hour, in accordance with the NEPOOL System Rules, the System
Operator shall calculate the Operating Reserve Clearing Price for each category
of Operating Reserve in the Day-Ahead Market and the Real-Time Market as
follows:
(i) The System Operator shall determine the aggregate Megawatts of the
applicable category of Operating Reserve that are scheduled for the hour in the
Day-Ahead Market or designated for the hour in the Real-Time Market.
(ii) For each category of Operating Reserve in each of the Day-Ahead Market and
Real-Time Market, the System Operator shall rank in the order of lowest to
highest the Reserve Prices, Lost Opportunity Costs and Supply Offer Prices, as
applicable, of the Resources scheduled by the System Operator for that category
of Operating Reserve for the hour for the Day-Ahead Market or designated each
interval during the hour in the Real-Time Market.
(iii) The Operating Reserve Clearing Price per Megawatt for each category of
Operating Reserve in each Market shall be the time-weighted average of the
highest Reserve Prices, Lost Opportunity Costs or Supply Offer Prices, as
applicable, for that category of Operating Reserve that are scheduled for the
hour in the Day-Ahead Market or designated each interval during the hour in the
Real-Time Market by the System Operator, as determined in accordance with the
applicable Market Rules.
(c) For each hour in the Day-Ahead Market for which the System Operator
calculates it requires 4-Hour Reserves, the System Operator shall determine the
4-Hour Reserve Clearing Price as follows:
(i) The System Operator shall determine the aggregate Megawatts of 4-Hour
Reserves scheduled for the hour in the Day-Ahead Market.
(ii) The System Operator shall rank from lowest to highest the Reserve Prices,
Lost Opportunity Costs and Supply Offer Prices, as applicable, of the Resources
scheduled for 4-Hour Reserves for the hour in the Day-Ahead Market.
(iii) The 4-Hour Reserve Clearing Price per Megawatt in the Day-Ahead Market
shall be the highest Reserve Prices, Lost Opportunity Costs or Supply Offer
Prices, as applicable, for 4-Hour Reserves that are scheduled by the System
Operator for the hour in accordance with applicable Market Rules.
(d) The System Operator shall calculate a Lost Opportunity Cost for each hour
for a Resource, other than Dispatchable Load, which shall, for each increment of
Supply Offer Megawatts, be equal to the product of (i) the amount, if any, by
which the Nodal Price for the hour at the Node or External Node where Energy
from the Resource would be supplied in the Day-Ahead Market or Real-Time Market
exceeds the Resource's Energy Supply Offer Price, for that increment of Supply
Offer Megawatts, for that market and (ii) the additional Megawatts, in that
increment of Supply Offer Megawatts, the Resource would have been scheduled or
dispatched to in the Day-Ahead Market or Real-Time Market, respectively, had it
been scheduled or dispatched to supply Energy at the Megawatt level specified in
its Supply Offer relating to its Supply Offer Price and operating parameters.
14A.14 Determination of AGC Clearing Price.
For each hour, the System Operator shall determine an AGC Clearing Price for the
Day-Ahead Market and for the Real-Time Market. In the case of each Market, the
AGC Clearing Price shall be the time-weighted average "AGC Capability Price," as
defined below in this Section 14A.14. The AGC Capability Price for a generating
unit furnishing AGC per the System Operator's schedule for the hour in the
Day-Ahead Market or designated each interval during the hour in the Real-Time
Market shall be equal to (A) the cost per unit of making the AGC capability of a
generating unit available based on the AGC Supply Offer Price for the
Entitlement for the hour, plus any Lost Opportunity Cost, divided by (B) the
amount of AGC scheduled in the hour in the Day-Ahead Market or designated in the
interval in the Real-Time Market from that Resource. The AGC Capability Price
used to determine the AGC Clearing Price shall be the highest AGC Supply Offer
for the generating units that, in the case of the Day-Ahead Market, were
scheduled by the System Operator to provide AGC for the hour, or, in the case of
the Real-Time Market, were designated each interval during the hour to provide
AGC beyond their Supply Obligations for AGC in the Day-Ahead Market.
14A.15 Funds to or from which Payments are to Be Made.
(a) All payments for Energy (except for payments to or from the Congestion
Revenue Fund and the Marginal Loss Revenue Fund), Operating Reserve, 4-Hour
Reserve and AGC furnished or received, all uplift charges paid pursuant to this
Section 14A of this Agreement, and any payments by Non-Participants for
ancillary services under Schedules 2 through 7 to the Tariff or pursuant to
arrangements referenced in Section 14A.10, shall be allocated each month through
the Pool Interchange Fund as follows:
Step One. For each week in which Energy is delivered or received under the HQ
Energy Banking Agreement, all payments with respect to transactions under that
Agreement shall be made to or from the Energy Banking Fund provided for in
Section 14A.15(b).
Step Two. (i) For each week in which Pre-Scheduled Energy (as defined in the HQ
Phase I Energy Contract) is purchased pursuant to the HQ Phase I Energy
Contract, the aggregate amount which is paid pursuant to Section 14A.10(b) for
such Energy by each Participant which is a participant in the Phase I
arrangements with Hydro-Quebec shall be determined and paid on the Participant's
account into the Phase I Savings Fund.
(ii) For each week in which Energy is purchased pursuant to the HQ Phase II Firm
Energy Contract, the aggregate amount which is paid pursuant to Section
14A.10(b) for such Energy by each Participant which is a participant in the
Phase II arrangements with Hydro-Quebec shall be determined and paid on the
Participant's account into the Phase II Savings Fund.
Step Three. For each week in which Other HQ Energy is purchased pursuant to the
HQ Phase I Energy Contract or Energy is purchased pursuant to the HQ
Interconnection Agreement, the aggregate amount paid pursuant to Section
14A.10(b) for such Energy shall be determined for each Participant which is a
participant in the Phase I or Phase II arrangements with Hydro-Quebec. Such
amount shall be allocated between the Participant's share of the Phase I Savings
Fund and the Participant's share of the Phase II Savings Fund created under the
HQ Use Agreement in the same ratio as (A) the sum of (x) the number of
kilowatthours of Other HQ Energy deemed to be purchased by the Participant
during the week and (y) the HQ Phase I Percentage of the number of kilowatthours
deemed to be purchased by the Participant under the HQ Interconnection Agreement
during the week, bears to (B) the HQ Phase II Percentage of the number of
kilowatthours purchased under the HQ Interconnection Agreement during the week.
Step Four. The balance remaining in the Pool Interchange Fund after Steps One
through Three shall be retained in the Pool Interchange Fund for the month and
shall be used and disbursed after each month in the following order:
(i) (A) amounts owed to Non-Participants (other than Hydro-Quebec) for the month
under contracts entered into with them pursuant to Section 14A.10(a) shall be
paid, and (B) amounts owed to Hydro-Quebec for the month for Energy deemed to be
furnished pursuant to Section 14A.10(b) to Participants which are not
participants in the Phase I or Phase II arrangements with Hydro- Quebec shall be
paid and, in the event the price paid by any such Participant for such Energy is
the applicable Locational Price, the excess, if any, of such Locational Price
over the amount owed to Hydro-Quebec shall be paid to the Participant; and
(ii) amounts owed to Participants for the month pursuant to this Section 14A
shall then be paid.
(b) HQ Energy Banking Fund. All amounts allocated to the HQ Energy Banking
Fund for each month shall be used and disbursed as follows:
(i) Participants which furnish Energy for delivery to Hydro-Quebec under the HQ
Energy Banking Agreement shall receive from their share of the Energy Banking
Fund the amount to which they are entitled for such service in accordance with
Section 14A.9.
(ii) amounts required to be paid to Hydro-Quebec under the HQ Energy Banking
Agreement shall be paid from the shares of the Fund of the Participants engaging
in transactions under the HQ Energy Banking Agreement for the month in
accordance with their respective interests in the transactions for the month. If
there is not enough in any such share, the Participants with the deficient
shares shall be billed and pay into their shares of the Fund the amounts
required for payments to Hydro-Quebec.
(iii) subject to the remaining provisions of this Section, at the end of each
month any balance remaining in each Participant's share of the HQ Energy Banking
Fund shall (I) in the case of any Participant which is not a participant in the
Phase I or Phase II arrangements with Hydro-Quebec, be paid to such Participant,
and (II) in the case of any Participant which is a participant in the Phase I or
Phase II arrangements with Hydro-Quebec, be paid to the Escrow Agent under the
HQ Use Agreement to be held and disbursed by it through the Phase I Savings Fund
and Phase II Savings Fund created under the HQ Use Agreement, and shall be
allocated between the Participant's share of said Funds as follows:
(A) the balance remaining in the Participant's share of the HQ Energy Banking
Fund for the month shall be divided by the number of kilowatthours deemed to be
received by the Participant under the HQ Energy Banking Agreement during the
month to determine an average savings amount per kilowatthour;
(B) for any hour during the month in which the number of kilowatthours received
by NEPOOL under the HQ Energy Banking Agreement exceeded the HQ Phase I Transfer
Capability, an amount equal to (a) the Participant's share of the excess of (1)
the number of kilowatthours received over (2) the HQ Phase I Transfer Capability
times (b) the average savings amount per kilowatthour determined for that
Participant under (A) above shall be allocated to the Phase II Savings Fund; and
(C) the remaining balance of the Participant's share of the HQ Energy Banking
Fund for the month shall be allocated to the Phase I Savings Fund.
It is recognized that, in view of the time which may elapse between the delivery
of Energy to or by Hydro-Quebec in an Energy Banking transaction under the HQ
Energy Banking Agreement and the return of the Energy, the amounts of Energy
delivered to and received from Hydro-Quebec, after adjustment for losses, may
not be in balance at the end of a particular month.
Further, if as of the end of any month and after adjustment for electrical
losses, the cumulative amount of Energy so received from Hydro-Quebec exceeds
the amount so delivered, the aggregate amount paid by Participants for the
excess Energy pursuant to Section 14A.10(b) shall be paid to the Energy Banking
Fund. The Escrow Agent under the HQ Use Agreement shall hold and invest these
funds. On the return of the excess Energy to Hydro-Quebec, the amount so held by
the Escrow Agent shall be repaid to Hydro-Quebec and Participants in accordance
with the Energy Banking Agreement.
(c) Phase I HQ Savings Fund. The aggregate amount allocated to each
Participant's share of the Phase I HQ Savings Fund for each month shall be used,
first, to pay to Hydro-Quebec the amount owed to it for the month for Energy
furnished under the Phase I HQ Energy Contract and the HQ Phase I Percentage of
the amount owed to it for the month for Energy furnished to the Participants
under the HQ Interconnection Agreement. The balance of the amount allocated to
the Fund for the month shall be paid to the Escrow Agent under the HQ Use
Agreement to be held and disbursed by it through the Phase I HQ Savings Fund
created thereunder in accordance with each Participant's contribution to such
balance.
(d) Phase II HQ Savings Fund. The aggregate amount allocated to the Phase II HQ
Savings Fund for each month shall be used, first, to pay to Hydro-Quebec the
amount owed to it for the month for Energy deemed to be furnished to the
Participant under the Phase II HQ Firm Energy Contract and the HQ Phase II
Percentage of the amount owed to it for the month for Energy deemed to be
furnished to the Participants under the HQ Interconnection Agreement. The
balance of the amount allocated to the Fund for the month shall be paid to the
Escrow Agent under the HQ Use Agreement to be held and disbursed by it through
the Phase II HQ Savings Fund created thereunder in accordance with each
Participant's contribution to such balance.
14A.16 Marginal Losses.
(a) Marginal Loss Cost. Marginal Loss cost shall be reflected in and recovered
through the Marginal Loss Components of Locational Prices. Participants pay for
Marginal Loss cost by paying the Locational Price for Energy. Locational Prices
shall be calculated in accordance with Section 14A.12 of the Agreement and
Schedule 13 of the Tariff.
(b) Marginal Loss Revenue. To the extent that there is any Marginal Loss Revenue
in any settlement period, such revenue shall be collected in a Marginal Loss
Revenue Fund and allocated to load-serving entities in proportion to their Net
Hourly Load Obligations for Energy in accordance with the Market Rules.
(c) Additional Rules and Procedures. Consistent with this Section 14A.16,
the implementation of its provisions shall further be detailed, defined and
carried out pursuant to Market Rules.
14A.17 Congestion Cost and Revenues.
(a) Congestion Cost. When Congestion exists, Congestion Cost shall be reflected
in and recovered through the Congestion Components of Locational Prices.
Participants pay for Congestion Costs by paying the Locational Price for Energy.
Locational Prices shall be calculated in accordance with Section 14A.12 of the
Agreement and Schedule 13 of the Tariff.
(b) Congestion Revenue. For each hour of the Dispatch Day in the Day-Ahead and
Real-Time Markets, the System Operator shall calculate and collect Congestion
Revenue and maintain a Congestion Revenue Fund.
(c) Additional Rules and Procedures. Consistent with this Section 14A.17,
the implementation of its provisions shall further be detailed, defined and
carried out pursuant to Market Rules.
14A.18 Market Monitoring and Reports.
(a) The System Operator shall complete and circulate to the Participants
Committee and post on its Internet website for each month a market monitoring
report. The monthly report shall be completed no later than sixty (60) days
after the close of the calendar month of market activities covered by the report
and shall contain the following information for each Load Zone and Reliability
Region: (a) separately identified Congestion Costs, RMR Uplift and any other
amounts that are paid for by Load Zone and/or Reliability Region, (b) the number
of Supply Offers from Participants that were not Related Persons of each other
and that were capable of meeting the marginal load within the Load Zone and/or
Reliability Region to the extent that the number falls below limits prescribed
in the Market Rules, (c) the aggregate import limitation to the Load Zone and/or
Reliability Region, (d) the existence and a description of internal transmission
constraints within the Load Zone and/or Reliability Region and (e), to the
extent disclosure can be made consistent with the NEPOOL Information Policy,
patterns of behavior that the System Operator has identified in the course of
market monitoring that may affect price or other charges that are paid for
Energy in the Load Zone and/or Reliability Region in a manner not consistent
with the conditions that would prevail in a competitive market. If the System
Operator has not commenced or taken corrective action with respect to Supply
Offers, Demand Bids, or other behavior inconsistent with the conditions that
would prevail in a competitive market identified in one of its monthly reports
within thirty (30) days of the issuance of that report, any Participant may
commence a complaint proceeding at the Commission to seek remediation of such
behavior. The Participant or Participants initiating such a complaint proceeding
shall, upon the issuance of a protective order by the Commission covering
confidentiality and other relevant matters and subject to the terms of such
protective order, be entitled to access to the data underlying the System
Operator's conclusions as to behavior inconsistent with conditions that would
prevail in a competitive market. The ability to initiate such a complaint
proceeding at the Commission shall not prejudice the ability of such complaining
Participant or Participants to pursue market power issues in any other forum.
Nothing in this section shall preclude any Participant from contesting, in the
context of a proceeding involving the issuance of a protective order by the
Commission, the disclosure or other release of confidential information.
(b) Studies Related to Congestion. The System Operator shall perform, on an
ongoing basis, an evaluation of the effectiveness, efficiency and workability of
the each of the main components of the CMS, including, without limitation, the
system of Locational Prices and FCRs. Within sixty (60) days after the first
anniversary of the CMS/MSS Effective Date, the System Operator shall issue a
written report to the Participants Committee at least ten (10) business days
prior to a Participants Committee meeting for discussion and shall not further
distribute that report publicly until after the Participants Committee meeting.
Such report shall contain in detail the System Operator's evaluations,
conclusions and recommendations, if any, for changes to the CMS. To the extent
practicable, the System Operator shall retain all data necessary to analyze the
CMS.
(c) Day-Ahead Market Information Reports. The System Operator shall make
available as provided below for the Day-Ahead Market each day in accordance with
the Market Rules and in a way that is consistent with the NEPOOL Information
Policy the following items, but not limited to:
(i) Each Participant shall be notified of the following:
(A) The set of accepted Supply Offers for Resources, including Supply Offers at
External Nodes, that will define the prices and quantities of the Participant's
Supply Obligations for the Dispatch Day with respect to Energy, Operating
Reserve, 4-Hour Reserve and AGC for each hour in the Day-Ahead Market. These
schedules shall define expected start-up, loading levels, and shut down
schedules for the Participant's Resources.
(B) The set of accepted Demand Bids, including Demand Bids at External Nodes,
that will define the Participant's Settlement Obligations to pay for a specified
quantity of Energy at each specified Location for each hour in the Day-Ahead
Market.
(ii) the System Operator shall publish on a daily basis the following
information:
(A) Day-Ahead Locational Prices for each hour of the Dispatch Day determined in
accordance with Section 14A.12, as well as all non-confidential data and
assumptions used by the System Operator to calculate each such price. These
prices will include Nodal Prices at all Nodes and External Nodes for Resources,
Zonal Prices for each Load Zone, and Hub Prices for each Hub. In posting
Locational Prices, the System Operator shall include all components of such
prices, including the Nodal Price at the Reference Node, the Marginal Loss
Component, and the Congestion Component.
(B) The aggregate quantities of Supply Offers and Demand Bids accepted in each
hour of the Day-Ahead Market.
(C) Hourly Clearing Prices and the amounts scheduled in the Day-Ahead Market for
Operating Reserves, 4-Hour Reserves, and AGC.
(D) The System Operator's load forecast for each hour of the Dispatch Day
compared to accepted Demand Bids.
(E) The projected Net Supply Offer Shortfall Uplift as determined pursuant to
Section 14A.19(a) and RMR Uplift and costs for voltage support for each
Reliability Region.
(d) Real-Time Market Information Reports. The System Operator shall publish for
the Real-Time Market during the Dispatch Day, in a way that is consistent with
the NEPOOL Information Policy the following items, but not limited to:
(i) Real-Time Market Locational Prices, including the Nodal Prices (including
External Nodes), Zonal Prices, and Hub Prices, as well as all non- confidential
data and assumptions used by the System Operator to calculate each such price.
As far in advance of each hour of the Real-Time Market as is feasible, the
System Operator shall post its estimate of the Locational Prices for the
remainder of the Dispatch Day.
(ii) As far in advance of each hour of the Real-Time Market as is feasible,
updates to the load forecast.
(iii) Hourly Clearing Prices and amounts designated in the Real-Time Market for
Operating Reserves and AGC.
(iv) Actual loads compared to forecasted load and accepted Demand Bids.
(e) Special Reporting. The System Operator shall publish with the Real-Time
Market information the following data concerning emergency purchases and sales
and Reserve Contracts entered into pursuant to Section 14A.10:
(i) The hourly price and schedule for Energy under the emergency purchase or
sale.
(ii) Prices and quantities at which the Operating Reserve or 4-Hour Reserve are
scheduled or designated by the System Operator for the hour pursuant to Reserve
Contracts.
14A.19 Additional Uplift Charges.
(a) Net Supply Offer Shortfall Uplift. It is anticipated that a generating unit
may be scheduled by the System Operator in the Day-Ahead Market for all or part
of a day when the Supply Offer Costs (as defined below) exceed the aggregate
revenues received pursuant to this Section 14A for the generating unit from all
Day-Ahead Markets. A Net Supply Offer Shortfall Uplift shall be calculated as
provided in this Section 14A.19 to provide for payment of this shortfall to the
affected generator and allocation of such difference. Except as provided below,
each generating unit scheduled by the System Operator in the Day-Ahead Market
shall be entitled to receive its Supply Offer Costs, provided that the foregoing
evaluation shall be made only on an aggregate basis for the total hours
scheduled to supply Energy, Operating Reserves, 4-Hour Reserves, and/or AGC in
the Dispatch Day and not on an individual hour-by-hour basis, and shall be made
only on a single Day-Ahead Market basis, so that, for example, the net shortfall
for a unit scheduled for a particular Dispatch Day shall be entitled to this
treatment only for the hours in that first Dispatch Day in that Day-Ahead Market
even if the unit's minimum run time extends beyond the Dispatch Day. Any
shortfall between Supply Offer Costs and aggregate market revenues in the
subsequent period during uninterrupted operation of the Resource for hours that
extend beyond the satisfaction of the Resource's minimum run time, will be
addressed through the Net Supply Offer Shortfall Uplift determined for that
Dispatch Day. Cost responsibility for this difference shall be allocated among
Participants in accordance with subsection (c) of this Section 14A.19 for those
hours in which the generating unit is scheduled to provide service during the
Dispatch Day, with the allocation among such hours determined in accordance with
applicable Market Rules.
For purposes of this Section 14A.19, "Supply Offer Costs" for a generating unit
shall mean the aggregate of the Start-Up Price, if applicable, plus the
summation for the Dispatch Day of the No Load Price in each applicable hour and
the product in each applicable hour of the applicable Supply Offer Prices and
the amounts of Energy, Operating Reserve, 4-Hour Reserve and AGC scheduled from
the unit in the Day-Ahead Market.
The Net Supply Offer Shortfall Uplift is calculated as the Supply Offer Costs of
a generating unit minus the aggregate revenues received by a Participant for the
amounts of Energy, Operating Reserve, 4-Hour Reserve and AGC scheduled from the
unit in the Day-Ahead Market for that Dispatch Day.
A Participant with an Entitlement in a generating unit that is Self-Scheduled in
the Day-Ahead Market shall only be entitled to receive payment of a Net Supply
Offer Shortfall Uplift associated with the unit during hours that the unit is
not Self-Scheduled. The calculation of Net Supply Offer Shortfall Uplift for a
Self Scheduled unit shall exclude No-Load costs for the hours the unit is
Self-Scheduled and include revenues associated with the difference between the
applicable Clearing Price and Supply Offer Price for the service from the unit
beyond the Self-Scheduled service. If the System Operator schedules a generating
unit to start-up and operate in the hours immediately prior to, and/or continue
operation for a period beyond, the hours for which the unit was Self-Scheduled
in the Day-Ahead Market, the Start-Up Price shall not be included in Supply
Offer Costs for the purpose of determining whether the generating unit is
entitled to receive a Net Supply Offer Shortfall Uplift for the hours of the
Dispatch Day for which the unit was not Self-Scheduled.
(i) Real-Time Uplift. There may be circumstances where the Real-Time Nodal Price
for Energy paid to a generating unit in the Real-Time Market is less than the
Real-Time Supply Offer Price for the generating unit. These circumstances may be
caused by the time-weighted averaging calculation of the Real-Time Market Nodal
Prices or as a result of the System Operator dispatching certain fast response
generating units within an hour in response to anticipated system conditions in
that hour. In such circumstances, the generating unit shall receive a Real-Time
Uplift equal to the difference between the Real-Time Nodal Price and the
corresponding Supply Offer Price for those megawatthours produced at the higher
Supply Offer Price but only to the extent those megawatthours were produced
pursuant to the dispatch instructions of the System Operator as described in the
Market Rules.
(ii) Allocation of Net Supply Offer Shortfall Uplift. Where payment is due to a
Participant under Section 14A.19(a), the aggregate amount of such payments shall
be recovered from Participants, including the Participant to which such payment
is made, as an uplift charge to be paid in accordance with this Section
14A.19(c).
Net Supply Offer Shortfall Uplift will first be allocated among the Energy
market and the three Operating Reserve Markets based on cost causation
principles in accordance with applicable Market Rules. Net Supply Offer
Shortfall Uplift will be allocated to specific markets to the extent that the
benefit of incurring the uplift is recognized in that market because incurring
the uplift relieved an otherwise binding constraint affecting the Clearing Price
in that market. To the extent that incurrance of the uplift benefits more than
one market such uplift will be allocated pro rata to all four markets in
accordance with the aggregate Settlemen
Obligations (in dollars) in the Energy and Operating Reserve markets adjusted as
specified in the Market Rules.
Charges for Net Supply Offer Shortfall Uplift allocated to the Day-Ahead Energy
Market ("Regional Energy Uplift") shall be determined for each hour and paid by
each Participant in accordance with the following formula:
(EQUATION)
in which
DACH is the amount to be paid by the Participant pursuant to this Section
14A.19(c) provided that if this amount is negative the Participant shall neither
pay nor receive credit for such amount.
UCa is the sum for the hour of uplift payments to generators made pursuant to
Section 14A.19(a) in the Day-Ahead Market.
XDAi is the Settlement Obligation for Energy of the Participant for the hour in
the Day-Ahead Market adjusted for Bilateral Transactions as to which both the
buyer(s) and the seller(s) elect or have elected to transfer Regional Energy
Uplift obligations in the Day-Ahead Market with respect to any Bilateral
Transaction in accordance with the Market Rules.
XDA is the aggregate Settlement Obligation for Energy of all Participants for
the hour in the Day-Ahead Market adjusted for Bilateral Transactions as to which
both the buyer(s) and the seller(s) elect or have elected to transfer Regional
Energy Uplift obligations in the Day-Ahead Market with respect to any Bilateral
Transactions in accordance with the Market Rules.
SSDAi is the amount of the Participant's Self-Supply of its Day-Ahead Settlement
Obligation for Energy that is actually supplied in the Real-Time Market from the
Self-Scheduled Resources of the Participant.
SSDA is the aggregate of Participants' Self-Supply of their Day-Ahead Settlement
Obligations for Energy that are supplied in the Real-Time Market from the
Self-Scheduled Resources of those Participants.
Charges for Net Supply Offer Shortfall Uplift allocated to each Operating
Reserve Market ("Regional Operating Reserve Uplift") shall be determined for
each hour and paid by each Participant in accordance with an equivalent
calculation to that specified for the Energy Market, as follows. The calculation
for each Operating Reserve Market will be specified in the Market Rules and will
be based on the Settlement Obligation for the relevant category of Operating
Reserve after accounting for those Bilateral Transactions described in the
definitions of XDAi and XDA above with respect to the relevant category of
Operating Reserve.
(iii) Allocation of Real-Time Uplift. Where payment is due to a Participant
under Section 14A.19(b), the aggregate amount of such payments shall be
recovered from Participants, including the Participant to which such payment is
made, as an uplift charge to be paid in accordance with this Section 14A.19(d).
Charges for Real-Time Uplift allocated to Participants in the Real-Time Energy
Market ("Real-Time Energy Uplift") shall be determined for each hour and paid by
each Participant in accordance with the following formula:
(EQUATION)
in which
RTCH is the amount to be paid by the Participant pursuant to this Section
14A.19(d) provided that if this amount is negative the Participant shall neither
pay nor receive credit for such amount.
UCb is the sum for the hour of uplift payments to generators made pursuant to
Section 14A.19(b) in the Real-Time Market.
XRTi is the Settlement Obligation for Energy of the Participant for the hour in
the Real-Time Market adjusted for Bilateral Transactions as to which both the
buyer(s) and the seller(s) elect or have elected to transfer Real-Time Energy
Uplift obligations in the Real-Time Market with respect any Bilateral
Transaction in accordance with the Market Rules.
XRT is the aggregate Settlement Obligation for Energy of all Participants for
the hour in the Real-Time Market adjusted for Bilateral Transactions as to which
both the buyer(s) and the seller(s) elect or have elected to transfer Real-Time
Energy Uplift obligations in the Real-Time Market with respect to any Bilateral
Transactions in accordance with the Market Rules.
SSRTi is the amount of the Participant's Self-Supply of its Real-Time Settlement
Obligation for Energy that is actually supplied in the Real-Time Market from the
Self-Scheduled Resources of the Participant.
SSRT is the aggregate of Participants' Self-Supply of their Real-Time Settlement
Obligations for Energy that are supplied in the Real-Time Market from the
Self-Scheduled Resources of those Participants.
(iv) Uplift Allocation And Pre-Existing Contracts. With respect to any Bilateral
Transaction entered into prior to September 26, 2000 (the "Effective Date"), the
allocation of Regional Energy Uplift cost responsibility, Regional Operating
Reserve Uplift cost responsibility and Real-Time Energy Uplift cost
responsibility provided for in Sections 14A.19(c) and 14A.19(d) shall not alter
the obligations of either the buyer or seller under such Bilateral Transaction
as of the date immediately prior to the Effective Date without the agreement of
both the buyer and seller.
(v) RMR Uplift. It is also anticipated that it may be necessary from time to
time to schedule a Participant's generating unit or Dispatchable Load to provide
Operating Reserve in one or more hours at prices for Operating Reserve that
exceed the applicable Clearing Price for that Operating Reserve service in the
Day-Ahead Market in order to satisfy locational Operating Reserve requirements
in a particular Reliability Region or Reliability Regions in accordance with
applicable Market Rules. When this occurs the Participant providing such service
shall be entitled to receive for the Dispatch Day the aggregate of the
applicable Supply Offer Prices for Operating Reserve to provide the requested
Operating Reserve service for all of the scheduled hours in the Dispatch Day.
This comparison of Supply Offer Price against Clearing Price for the applicable
Operating Reserve products shall be made on an aggregate basis for all hours
scheduled in the Day-Ahead Market for that Dispatch Day, and not on an
individual hour-by-hour basis.
Where payment is made to a Participant under these circumstances, the amount by
which the payment to the Participant exceeds the amount that would be paid if
the Participant had only received the applicable Day-Ahead Market Operating
Reserve Clearing Prices for the scheduled service during the hours in question
shall be recovered as RMR Uplift from Participants which are obligated to pay
under the Settlement Obligations for Operating Reserve associated with load in
the affected Reliability Region or Reliability Regions for the hours during
which the service is scheduled in the Dispatch Day.
Except as provided below, RMR Uplift shall be paid by each Participant for each
hour in accordance with the following formula:
(EQUATION)
in which
CHd is the amount to be paid by a Participant pursuant to this Section 14A.19(f)
for RMR Uplift for the affected Reliability Region(s).
UCd is the aggregate RMR Uplift payments to Participants for the hour for out of
merit services for the affected Reliability Region(s) to be allocated and paid
pursuant to this Section 14A.19(f).
Eli is the number of kilowatthours of Electrical Load of the Participant for the
hour in the affected Reliability Region(s).
ELRR is the aggregate number of kilowatthours of Electrical Load of all
Participants for the hour in the affected Reliability Region(s).
ADJRR is the total uplift charge adjustment for the Participant required to
reflect Operating Reserve that the Participant has Self-Supplied and all
Bilateral Transactions entered into by the Participant for the transfer of
Settlement Obligations for Operating Reserve pursuant to Section 14A.1(c) for
the hours to the extent that each Bilateral Transaction is not reflected in the
Participant's Electrical Load for the hour. The adjustment for each Bilateral
Transaction shall equal the pro rata portion of the transferring Participant's
Operating Reserve Settlement Obligations covered by such Bilateral Transaction.
The adjustment shall be negative for all Bilateral Transactions under which the
Participant transfers its Settlement Obligations for Operating Reserve to
another Participant; the adjustment shall be positive for all Bilateral
Transactions under which the Participant assumes the Settlement Obligations for
Operating Reserve of another Participant.
Notwithstanding the foregoing, the first six million dollars ($6,000,000) of the
RMR Uplift under this Section 14A.19(f) shall be allocated for each hour among
and paid by all Participants which have Settlement Obligations for Operating
Reserve for the hour in accordance with the formula in Section 14A.1(c) for each
of the following two periods:
(i) the twelve-month period commencing on the CMS/MSS Effective Date; and
(ii) the period commencing on the first anniversary of the CMS/MSS Effective
Date and ending on December 31, 2004.
Any such RMR Uplift in excess of six million dollars ($6,000,000) with respect
to either period shall be allocated among and paid by the Participants with
Settlement Obligations for Operating Reserve associated with load in the
affected Reliability Region(s) in accordance with the formula of this Section
14A.19(f).
[Next Sheet is 199]
PART FOUR
TRANSMISSION PROVISIONS
SECTION 15
OPERATION OF TRANSMISSION FACILITIES
15.16 Definition of PTF. PTF or pool transmission facilities are the
transmission facilities owned by Participants rated 69 kV or above required to
allow energy from significant power sources to move freely on the New England
transmission network, and include:
1. All transmission lines and associated facilities owned by Participants rated
69 kV and above, except for lines and associated facilities that contribute
little or no parallel capability to the NEPOOL Transmission System (as defined
in the Tariff). The following do not constitute PTF:
(a) Those lines and associated facilities which are required to serve local load
only.
(b) Generator leads, which are defined as radial transmission from a generation
bus to the nearest point on the NEPOOL Transmission System.
(c) Lines that are normally operated open.
2. Parallel linkages in network stations owned by Participants (including
substation facilities such as transformers, circuit breakers and associated
equipment) interconnecting the lines which constitute PTF.
3. If a Participant with significant generation in its transmission and
distribution system (initially 25 MW) is connected to the New England network
and none of the transmission facilities owned by the Participant qualify to be
included in PTF as defined in (1) and (2) above, then such Participant's
connection to PTF will constitute PTF if both of the following requirements are
met for this connection:
(a) The connection is rated 69 kV or above.
(b) The connection is the principal transmission link between the Participant
and the remainder of the New England PTF network.
4. Rights of way and land owned by Participants required for the installation of
facilities which constitute PTF under (1), (2) or (3) above. The Reliability
Committee shall review at least annually the status of transmission lines and
related facilities and determine whether such facilities constitute PTF and
shall prepare and keep current a schedule or catalogue of PTF facilities.
The following examples indicate the intent of the above definitions:
(i) Radial tap lines to local load are excluded.
(ii) Lines which loop, from two geographically separate points on the NEPOOL
Transmission System, the supply to a load bus from the NEPOOL Transmission
System are included.
(iii) Lines which loop, from two geographically separate points on the NEPOOL
Transmission System, the connections between a generator bus and the NEPOOL
Transmission System are included.
(iv) Radial connections or connections from a generating station to a single
substation or switching station on the NEPOOL Transmission System are excluded,
unless the requirements of paragraph (3) above are met.
Transmission facilities owned by a Related Person of a Participant which are
rated 69 kV or above and are required to allow Energy from significant power
sources to move freely on the New England transmission network shall also
constitute PTF provided (i) such Related Person files with the Secretary of the
Participants Committee its consent to such treatment; and (ii) the Participants
Committee determines that treatment of the facility as PTF will facilitate
accomplishment of NEPOOL's objectives. If a facility constitutes PTF pursuant to
this paragraph, it shall be treated as "owned" by a Participant for purposes of
the Tariff and the other provisions of Part Four of the Agreement.
15.17 Maintenance and Operation in Accordance with Accepted Electric Industry
Practice. Each Participant which owns or operates PTF or other transmission
facilities rated 69 kV or above shall, to the fullest extent practicable, cause
all such transmission facilities owned or operated by it to be designed,
constructed, maintained and operated in accordance with Accepted Electric
Industry Practice.
15.18 Central Dispatch. Each Participant which owns or operates PTF or other
transmission facilities rated 69 kV or above shall, to the fullest extent
practicable, subject all such transmission facilities owned or operated by it to
central dispatch by the System Operator; provided, however, that each
Participant shall at all times be the sole judge as to whether or not and to
what extent safety requires that at any time any of such facilities will be
operated at less than their full capability or not at all.
15.19 Maintenance and Repair. Each Participant shall, to the fullest extent
practicable: (a) cause transmission facilities owned or operated by it to be
withdrawn from operation for maintenance and repair only in accordance with
maintenance schedules reported to and published by the System Operator in
accordance with procedures approved or established by the Tariff Committee from
time to time, (b) restore such facilities to good operating condition with
reasonable promptness, and (c) in emergency situations, accelerate maintenance
and repair at the reasonable request of the System Operator in accordance with
rules approved by the Tariff Committee.
15.20 Additions to or Upgrades of PTF. The possible need for an addition to or
upgrade of PTF may be identified in connection with the planning process of
Section 51 of the Tariff, an application or request for service under the
Tariff, or a request for the installation of or material change to a generation
or transmission facility, or may be separately identified by a NEPOOL committee,
a Participant or the System Operator. In such cases, a study, if necessary, to
assess available transmission capacity and, if necessary, a System Impact Study
and a Facility Study, shall be performed by the affected Participant(s) in whose
Local Network(s) the addition or upgrade would or might be effected or their
designee(s), or the Reliability Committee and/or the System Operator, in the
case of a System Impact Study, or the Committee's or the System Operator's
designee(s), with review of the study by the System Operator if it does not
perform the study. Studies to assess available transmission capacity and System
Impact Studies and Facilities Studies shall be conducted, as appropriate, in
accordance with the affected Participant's Local Network Service Tariff, or in
accordance with the applicable methodology specified in Attachments C and D to
the Tariff, and the provisions of the Local Network Service Tariff or the
applicable provisions of Attachments I and J to the Tariff shall apply, as
appropriate, with respect to the payment of the costs of the study and the other
matters covered thereby.
Responsibility for the costs of new PTF or any modification or other upgrade of
PTF shall be determined, to the extent applicable, in accordance with Parts V
and VI and Schedules 11 and 12 of the Tariff, including without limitation the
provisions relating to responsibility for the costs of new PTF or modifications
or other upgrades to PTF exceeding regional system, regulatory or other public
requirements set forth in Section (3)(b) of Schedule 11 to the Tariff and
Schedule 12 of the Tariff
Sheet 206 is intentionally blank.
SECTION 16
SERVICE UNDER TARIFF
16.1 Effect of Tariff. The Tariff specifies the terms and conditions under which
the Participants will provide regional transmission service through NEPOOL. This
Section 16 specifies various rights and obligations with respect to the revenues
to be collected by NEPOOL for the Participants under the Tariff and related
matters.
16.2 Obligation to Provide Regional Service. The Participants which own PTF
shall collectively provide through NEPOOL regional transmission service over
their PTF facilities, and the facilities of their Related Persons which
constitute PTF in accordance with Section 15.1, to other Participants and other
Eligible Customers pursuant to the Tariff. The Tariff provides open access for
all of the types of regional transmission service required by Participants and
other Eligible Customers over PTF and it is intended to be the only source of
such service, except for service provided for Excepted Transactions.
16.3 Obligation to Provide Local Network Service. Each Participant which owns
transmission facilities other than PTF shall provide service over such
facilities to other Participants or other Eligible Customers connected to the
Transmission Provider's transmission system pursuant to a tariff (a "Local
Network Service Tariff") filed by the Transmission Provider with the Commission.
A Participant is also obligated to provide service under its Local Network
Service Tariff or otherwise (i) to permit a Participant or other Entity with an
Entitlement in a generating unit in the Participant's local network to deliver
the output of the generating unit to an interconnection point on PTF and (ii) to
permit the delivery to an Eligible Customer taking Internal Point-to-Point
Service under the Tariff of the Energy and/or capacity covered by its Completed
Application for that Internal Point-to-Point Service.
A Local Network Service Tariff shall provide:
(i) for a pro rata allocation of monthly revenue requirements not otherwise paid
for through charges to Eligible Customers for Local Point-to-Point Service among
the Transmission Provider's Network Customers receiving service under the tariff
on the basis of their loads during the hour in the month in which the total
connected load to the Local Network is at its maximum, without any adjustment
for credits for generation;
(ii) for the recovery under the Local Network Service Tariff from Eligible
Customers taking Regional Network Service and Internal Point-to-Point Service of
that portion of the Transmission Provider's annual transmission revenue
requirements with respect to PTF which is not recovered through the distribution
of revenues from Regional Network Service or Internal Point-to- Point Service
pursuant to Section 16.6;
(iii) that where all or a part of the load of a Participant or other Eligible
Customers taking service under the tariff is connected directly to PTF, the
Participant or other Eligible Customers receiving the service shall pay each
Year during the Transition Period for such service with respect to the load
directly connected to PTF the percentage specified in the schedule below of the
applicable Local Network Service Tariff charge for service across non-PTF
transmission facilities and shall have no obligation to pay charges for service
across non-PTF transmission facilities with respect to that portion of the
connected load after the Transition Period, but shall continue to pay its share
of any other Local Network Service costs directly associated with the
PTF-connected load; provided that in the event of any inconsistency between the
foregoing provisions and the terms of any Excepted Transaction which is listed
in Attachment G-1 to the Tariff, the Excepted Transaction shall control:
Year One Year Two Year Three Year Four Years Five and Six
% of charge
to be paid 100% 80% 60% 40% 20%
(iv) that if the Transmission Provider receives a distribution pursuant to
Section 16.6 from NEPOOL out of revenues paid for Through or Out Service, the
amounts received shall reduce its Local Network Service revenue requirements;
and
(v) that if the Transmission Provider receives transmission revenues from an
Eligible Customer taking Local Network Service from that Transmission Provider
with respect to an Excepted Transaction, the amounts received shall reduce the
amount due from such Eligible Customer connected to the Transmission Provider's
transmission system for Local Network Service provided thereto by the
Transmission Provider rather than reducing the
Transmission Provider's total cost of service, except that any reductions to the
amount due from Eligible Customers for Excepted Transactions identified in
Section 25(1) and (2) of the Tariff shall be made only for service rendered
through February 28, 1999, and such reductions shall cease and shall be replaced
thereafter in their entirety with the credits under the NEPOOL Tariff, provided
in accordance with Sections 25A and 25B of the Tariff.
16.4 Transmission Service Availability. The availability of transmission
capacity to provide transmission service under the Tariff shall be determined in
accordance with the Tariff. In determining the availability of transmission
capacity, existing committed uses of the Participants' transmission facilities
shall include uses for existing firm loads and reasonably forecasted changes in
such loads, and for Excepted Transactions.
16.5 Transmission Information. Information concerning (i) available transmission
capacity, (ii) transmission rates and (iii) system conditions that may give rise
to Interruptions or Curtailments shall be made available to all Participants and
Non-Participants through the OASIS on a timely and non-discriminatory basis. All
Participants owning PTF or other transmission facilities rated 69 kV or higher
shall make available to the System Operator the information required to permit
the maintenance of the OASIS in compliance with Commission Order 889 and any
other applicable Commission orders; provided that no Participant shall be
required to furnish information which is required to be treated as confidential
in accordance with NEPOOL policy without appropriate arrangements to protect the
confidentiality of such information.
16.6 Distribution of Transmission Revenues. Payments required by the Tariff for
the use of the NEPOOL Transmission System shall be made to NEPOOL and shall be
distributed by it in accordance with this Section 16.6.
A. Regional Network Service Revenues. Revenues received by NEPOOL for providing
Regional Network Service each month during the Transition Period shall be
distributed to those Participants owning PTF or those load-serving Participants
supporting PTF which are obligated to take and pay for Regional Network Service
and/or Internal Point-to-Point Service in accordance with the Tariff, in part on
the basis of allocated flows for the region as determined in accordance with the
methodology specified in Attachment A to this Agreement and in part in
proportion to the respective Annual Transmission Revenue Requirements for PTF of
such owners and supporters, in accordance with the following Schedule:
Year One Year Two Year Three Year Four Year Five Year Six
Allocated
Flows: 25% 20% 15% 10% 5% 2.5%
Annual
Transmission
Revenue
Requirements: 75% 80% 85% 90% 95% 97.5%
Revenues received by NEPOOL for providing Regional Network Service each month
after the Transition Period shall be distributed to the Participants owning or
supporting PTF in proportion to their respective Annual Transmission Revenue
Requirements for PTF.
B. Through or Out Service Revenues. The revenues received by NEPOOL each month
for providing Through or Out Service shall be distributed among the Participants
owning PTF on the basis of allocated flows for the transaction determined in
accordance with the methodology specified in Attachment A to this Agreement;
provided that for service provided during the Transition Period but not
thereafter, for an "Out" transaction which originates on the system of a
Participant which owns the PTF interconnection facilities on the New England
side of the interface with the other Control Area over which the transaction is
delivered, 100% of the megawatt mile flows with respect to the transaction shall
be deemed to occur on such Participant's system.
C. Internal Point-to-Point Service Revenues. The revenues received by NEPOOL
each month for providing Internal Point-to-Point Service shall be distributed
among those load-serving Participants owning or supporting PTF which are
obligated to take and pay for Regional Network Service and/or Internal
Point-to-Point Service in accordance with the Tariff, in proportion to their
respective Annual Transmission Revenue Requirements for PTF under Attachment F
to the Tariff.
D. Ancillary Service Payments. The revenues received by NEPOOL pursuant to
Schedule 1 to the Tariff (scheduling, system control and dispatch service) will
be used to reimburse NEPOOL, the System Operator (if the System Operator does
not receive revenues for that service under a separate tariff) and Participants
for the costs which are reflected in the charges for such service. The revenues
received by NEPOOL pursuant to Schedules 2-7 to the Tariff shall be distributed
prior to the Second Effective Date in accordance with the continuing provisions
of the Prior NEPOOL Agreement and the rules adopted thereunder, and shall be
distributed on or after the Second Effective Date in accordance with Section 14.
E. Congestion Payments. Any congestion uplift charge received as a payment
for transmission service pursuant to Section 24 of the Tariff for any hour
shall be applied in accordance with Section 14.5(a) in payment for Energy
service.
[Next Sheet is 216]
SECTION 17
POOL-PLANNED UNIT SERVICE
17.1 Effective Period. The provisions contained in this Section 17 shall
continue in effect for the period to and including February 28, 2001, and shall
be of no effect after that date.
17.2 Obligation to Provide Service. Until February 28, 2001, each Participant
shall provide service over its PTF facilities under this Section 17 rather than
under the Tariff, for the following purposes:
(a) the transfer to a Participant's system of its ownership interest or its Unit
Contract Entitlement under a contract entered into by it before November 1, 1996
in a Pool-Planned Unit which is off its system;
(b) the transfer to a Participant's system of its Entitlement in a purchase
under a contract entered into by it before November 1, 1996 (including a
purchase under the HQ Phase II Firm Energy Contract) from Hydro-Quebec where the
line over which the transfer is made into New England is the HQ Interconnection;
and
(c) the transfer to a Non-Participant of its Entitlement in a Pool-Planned Unit
pursuant to an arrangement which has been approved prior to November 1, 1996 by
the Participants Committee.
17.3 Rules for Determination of Facilities Covered by Particular Transactions.
It is anticipated that it may be necessary with respect to a particular
transmission use under subsection (a), (b) or (c) of Section 17.2 to determine
whether the transaction is effected entirely over PTF, entirely over facilities
that are not PTF, or partially over each.
The following rules shall be controlling in the determination of the facilities
required to effect the use:
(a) To the extent that EHV PTF is available to effect the transaction, over all
or part of the distance to be covered, the use shall be deemed to be effected on
such EHV PTF over such portion of the distance to be covered.
(b) To the extent that EHV PTF is not available for the entire distance to be
covered by the use, but Lower Voltage PTF is available to cover all or part of
the distance not covered by EHV PTF, the transaction shall be deemed to be
effected on such Lower Voltage PTF.
If a Participant has ownership or contractual rights with respect to an Excepted
Transaction which are independent of this Agreement and the Tariff and are
adequate to provide for a transfer of the types specified in subsections
17.2(a), (b) or (c), and such rights are not limited to the transfer in
question, the transfer shall be deemed to have been effected pursuant to such
rights and not pursuant to the provisions of this Agreement. A copy of each
instrument establishing such rights, or an opinion of counsel describing and
authenticating such rights, shall be filed with the Secretary of the
Participants Committee.
17.4 Payments for Uses of EHV PTF During the Transition Period.
(a) Each Participant shall pay each month for its uses of EHV PTF for transfers
of Entitlements pursuant to subsections (a) or (b) of Section 17.2, one-twelfth
of the NEPOOL EHV PTF Participant Summer or Winter Wheeling Rate in effect for
the calendar year ending December 31, 1996, as determined in accordance with the
Prior NEPOOL Agreement, for each Kilowatt of its current Entitlements which
qualify for transfer pursuant to subsections (a) or (b) of Section 17.2, except
as otherwise provided in Section 17.3; provided that such payment shall be
required with respect to only one-half the Kilowatts covered by a NEPOOL
Exchange Arrangement (as hereinafter defined).
Each Participant which is a party to the HQ Phase II Firm Energy Contract (other
than a Participant (i) whose system is directly interconnected to the HQ
Interconnection or (ii) which has contractual rights independent of this
Agreement and the Tariff which give it direct access to the HQ Interconnection
and which are not limited to transfers of Energy delivered over the HQ
Interconnection) shall also pay each month for the use of EHV PTF for deliveries
under the Phase II Firm Energy Contract during the Base Term of the HQ Phase II
Firm Energy Contract, one-twelfth of the NEPOOL EHV PTF Participant Summer or
Winter Wheeling Rate in effect for the calendar year ending December 31, 1996,
as determined in accordance with the Prior NEPOOL Agreement, for each Kilowatt
of its HQ Phase II Net Transfer Responsibility for the month. If, and to the
extent that, such Responsibility continues for any period by which the term of
said Contract extends beyond the Base Term, each such Participant shall continue
to pay the above rate during the extension period with respect to its continuing
Responsibility. A Participant shall not be deemed to be directly interconnected
to the HQ Interconnection for purposes of this paragraph solely because of its
participation in arrangements for the support and/or use of PTF facilities
installed or modified to effect reinforcements of the New England AC
transmission system required in connection with the HQ Interconnection. A copy
of each contract establishing rights independent of this Agreement and the
Tariff which provides direct access to the HQ Interconnection, or an opinion of
counsel describing and authenticating such rights, shall be filed with the
Secretary of the Participants Committee.
The NEPOOL EHV PTF Participant Summer Wheeling Rate for any calendar year shall
be applicable to the months in the Summer Period.
The NEPOOL EHV PTF Participant Winter Wheeling Rate for any calendar year shall
be applicable to the months in the Winter Period.
A NEPOOL Exchange Arrangement is one entered into by two Participants each of
which has an ownership interest in a Pool-Planned Unit on its own system
pursuant to which each sells out of its ownership interest, a Unit Contract
Entitlement to the other for a period of time which is, in whole or part, the
same for both sales. Such an arrangement shall constitute a NEPOOL Exchange
Arrangement even though the beginning and ending dates of the two Unit Contract
sale periods are different, but only for the period for which both sales are in
effect. If for any period the number of Kilowatts covered by the two Unit
Contract Entitlements of a NEPOOL Exchange Agreement are not the same, the
portion of the larger Entitlement which exceeds the amount of the smaller
Entitlement shall not be deemed to be covered by such NEPOOL Exchange
Arrangement for purposes of this Section 17.4.
(b) Each Participant shall pay each month for its use of EHV PTF for a transfer
of an Entitlement in a Pool-Planned Unit to a Non-Participant pursuant to
Section 17.2(c) such charge as is fixed by the Participants Committee at the
time of its approval of the sale, and filed with the Commission.
(c) Fifty percent of all amounts required to be paid with respect to transfers
by a Participant pursuant to subsection (a) or (b) of Section 17.2 shall be paid
to a pool transmission fund and distributed monthly among the Participants in
proportion to the respective amounts of their costs with respect to EHV PTF for
the calendar year 1996 as determined in accordance with the Prior NEPOOL
Agreement.
(d) The remaining 50% of all amounts required to be paid with respect to
transfers by a Participant pursuant to subsections (a) or (b) of Section 17.2
shall be paid to, and retained by, the Participant on whose system the transfer
originates, or in the event the EHV PTF system of such Participant is supported
in part by other Participants, then to the Participant on whose system the
transfer originates and such other Participants in proportion to the respective
shares of the costs of such EHV PTF system borne by each of them or in such
other manner as the Participants involved may jointly direct; provided that the
Participant on whose system the transfer originates shall have the right to
waive such 50% payment in whole or part as to a particular transfer except that
no such waiver may adversely affect the payments to any other Participant which
is supporting in part the originating system's EHV PTF system.
17.5 Payments for Uses of Lower Voltage PTF. Each Participant which uses another
Participant's Lower Voltage PTF pursuant to this Section 17 shall pay each month
to the owner of such Lower Voltage PTF (1) for each Kilowatt of its use of such
Lower Voltage PTF for transfer of Entitlements pursuant to Subsections 17.2(a),
(b) or (c) during the month, and (2) during the Base Term of the HQ Phase II
Firm Energy Contract (and during any extension of the term of said Contract if
and to the extent its HQ Phase II Net Transfer Responsibility continues during
the extension period) for each Kilowatt of its HQ Phase II Net Transfer
Responsibility for the month, the owner's Lower Voltage PTF Winter Wheeling Rate
or Summer Wheeling Rate for the 1996 calendar year, as determined in accordance
with the Prior NEPOOL Agreement; except that the requirements for such payments
shall terminate on March 1, 1999 for Participants receiving network service
under both the Tariff and applicable Local Network Service Tariff.
17.6 Use of Other Transmission Facilities by Participants. For the period to and
including February 28, 1999, each Participant which has no direct connection
between its system and PTF shall be entitled to use the non-PTF transmission
facilities of any other Participant required to reach its system for any of the
purposes for which PTF may be used under Section 17.2. Such use shall be
effected, and payment made, in accordance with the other Participant's filed
open access tariff.
17.7 Limits on Individual Transmission Charges. Any charges for transmission
service pursuant to this Section 17 by any Participant to another Participant
shall be just, reasonable and not unduly discriminatory or preferential. No
provision of this Section 17 shall be construed to waive the right of any
Participant to seek review of any charge, term or condition applicable to such
transmission service by another Participant by the Commission or any other
regulatory authority having jurisdiction of the transaction.
[Next Sheet is 225]
SECTION 17A
TRANSMISSION OWNERS RESERVED RIGHTS
Notwithstanding any other provision of this Agreement, or any other agreement or
amendment made in connection with the restructuring of NEPOOL, each Transmission
Owner shall retain all of the rights set forth in this Section 17A; provided,
however, that such rights shall be exercised in a manner consistent with the
Transmission Owner's rights and obligations under the Federal Power Act and the
Commission's rules and regulations thereunder.
17A.1 Each Transmission Owner shall have the right at any time unilaterally to
file pursuant to Section 205 of the Federal Power Act to change the revenue
requirements underlying its component of the rates for service under the NEPOOL
Tariff and the transmission-related provisions of this Agreement.
17A.2 Nothing in this Agreement shall restrict any rights, to the extent such
rights exist: (a) of Transmission Owners that are parties to a merger,
acquisition or other restructuring transaction to make a filing under Section
205 of the Federal Power Act with respect to the reallocation or redistribution
of revenues among such Transmission Owners; or (b) of any Transmission Owner to
terminate its participation in NEPOOL pursuant to Section 21.2 of this
Agreement, notwithstanding any effect its withdrawal from NEPOOL may have on the
distribution of transmission revenues among other Transmission Owners. Further,
nothing in this Agreement shall be interpreted to permit the adoption of a rate
design change that is inconsistent with any settlement under the Tariff accepted
by the Commission without the consent of all signatories to the settlement.
17A.3 Each Transmission Owner retains all rights that it otherwise has incident
to its ownership of its assets, including, without limitation, its PTF and
non-PTF, including the right to build, acquire, sell, merge, dispose of, retire,
use as security, or otherwise transfer or convey all or any part of its assets,
including, without limitation, the right, individually or collectively, to amend
or terminate the Transmission Owner's relationship with the ISO in connection
with the creation of an alternative arrangement for the ownership and/or
operation of its transmission facilities on an unbundled basis (e.g., a
transmission company), subject to necessary regulatory approvals and to any
approvals required under applicable provisions of this Agreement. This section
is not intended to reduce or limit any other rights of a Transmission Owner as a
signatory to this Agreement.
17A.4 The obligation of any Transmission Owner to expand or modify its
transmission facilities in accordance with the Tariff shall be subject to the
Transmission Owners' right to recover, pursuant to appropriate financial
arrangements contained in Commission-accepted tariffs or agreements, all
reasonably incurred costs, plus a reasonable return on investment, associated
with constructing and owning or financing such expansions or modifications to
its facilities.
17A.5 Each Transmission Owner shall have the right to adopt and implement
procedures it deems necessary to protect its electric facilities from physical
damage or to prevent injury or damage to persons or property.
17A.6 Each Transmission Owner retains the right to take whatever actions it
deems necessary to fulfill its obligations under local, state or federal law.
17A.7 In addition to having the rights reserved under other provisions of this
Section 17A, all Participants retain the right to take any position before the
Commission, and any appellate court with jurisdiction to review a Commission
determination, or to seek a determination by the Commission, regarding whether,
and the extent to which, the Transmission Owners may retain the exclusive right
to make unilateral filings under Section 205 of the Federal Power Act to amend
the Tariff and the transmission related provisions of this Agreement. If and to
the extent the Commission rules that the Transmission Owners do not retain such
rights, then any such amendment that is not subject to any of Section 17A.1
through 17A.6 may be filed with the Commission only upon the approval by the
Participants Committee of the amendment under Section 6.11, including Section
6.11(d). If and to the extent the Commission rules that the Transmission Owners
do retain such rights, then the Transmission Owners, acting through the
Transmission Owners Committee, shall have the exclusive right to make unilateral
filings under Section 205 of the Federal Power Act to amend the Tariff and the
transmission-related provisions of this Agreement, other than filings subject to
Sections 17A.1 or 17A.2.
17A.8 (a) Notwithstanding anything to the contrary in this Agreement, the rights
of each Participant under the Federal Power Act shall be preserved.
(a) Any dispute over whether a matter falls within the scope of any of the
rights reserved under this Section 17A will be subject to resolution pursuant to
Section 11.A.
(b) No amendment to any provision of this Section 17A or Section 11B may be
adopted without the agreement of the Transmission Owners specified in Section
11B.
(c) Any agreement entered into between NEPOOL and a System Operator shall
require the System Operator to respect the rights reserved under this Section
17A.
[Next Sheet is 230]
PART FIVE
GENERAL
SECTION 18
GENERATION AND TRANSMISSION FACILITIES
18.8 Designation of Pool-Planned Facilities. At the request of a Participant,
the Participants Committee shall designate as "pool-planned" a generating or
transmission facility, for purposes of Chapter 164, Sections 11-22 of the
Massachusetts General Laws, to be constructed by the Participant or its Related
Person if the Participants Committee determines that the facility is consistent
with NEPOOL planning. Designation of a transmission facility as a Pool-Planned
Facility does not determine whether or not the facility is PTF. The Participants
Committee may not unreasonably withhold designation as a Pool-Planned Facility
of a generation unit or other facility proposed by one or more Participants.
18.9 Construction of Facilities. Subject to Sections 13.1, 15.2, 15.5, 18.3,
18.4 and 18.5, and to the provisions of the Tariff, each Participant shall have
the right to determine whether, and to what extent, additions to and
modifications in its generating and transmission facilities shall be made.
However, each Participant shall give due consideration to recommendations made
to it by the Participants Committee or the System Operator for any such
additions or modifications and shall follow such recommendations unless it
determines in good faith that the recommended actions would not be in its best
interest.
18.10 Protective Devices for Transmission Facilities and Automatic Generation
Control Equipment. Each Participant shall install, maintain and operate such
protective equipment and switching, voltage control, load shedding and emergency
facilities as the Participants Committee may determine to be required in order
to assure continuity of service and the stability of the interconnected
transmission facilities of the Participants. Until the Second Effective Date,
each Participant shall also install, maintain and operate such Automatic
Generation Control equipment as the Participants Committee may determine to be
required in order to maintain proper frequency for the interconnected bulk power
system of the Participants and to maintain proper power flows into and out of
the NEPOOL Control Area.
18.11 Review of Participant's Proposed Plans. Each Participant shall submit to
the System Operator, Participants Committee, the Reliability Committee, and the
Markets Committee or the Tariff Committee, as appropriate, for review by them,
in such form, manner and detail as the Participants Committee may reasonably
prescribe, (i) any new or materially changed plan for additions to, retirements
of, or changes in the capacity of any supply and demand-side resources or
transmission facilities rated 69 kV or above subject to control of such
Participant, and (ii) any new or materially changed plan for any other action to
be taken by the Participant which may have a significant effect on the
stability, reliability or operating characteristics of its system or the system
of any other Participant. No significant action (other than preliminary
engineering action) leading toward implementation of any such new or changed
plan shall be taken earlier than sixty days (or ninety days, if the System
Operator or the Participants Committee determines that it requires additional
time to consider the plan and so notifies the Participant in writing within the
sixty days) after the plan has been submitted to the Committees. Unless prior to
the expiration of the sixty or ninety days, whichever is applicable, the
Participants Committee notifies the Participant in writing that it has
determined that implementation of the plan will have a significant adverse
effect upon the reliability or operating characteristics of its system or of the
systems of one or more other Participants, the Participant shall be free to
proceed. The time limits provided by this Section 18.4 may be changed with
respect to any such submission by agreement between the Participants Committee
and the Participant required to submit the plan.
18.12 Participant to Avoid Adverse Effect. If the Participants Committee
notifies a Participant pursuant to Section 18.4 that implementation of the
Participant's plan has been determined to have a significant adverse effect upon
the reliability or operating characteristics of its system or the systems of one
or more other Participants, the Participant shall not proceed to implement such
plan unless the Participant or the Non-Participant on whose behalf the
Participant has submitted its plan takes such action or constructs at its
expense such facilities as the Participants Committee determines to be
reasonably necessary to avoid such adverse effect; provided that if the plan is
for the retirement of a supply or demand-side resource, the Participant may
proceed with its plan only if, after engaging in good faith negotiations with
persons designated by the Participants Committee to address the adverse effects
on reliability or operating characteristics, the negotiations either address the
adverse effects to the satisfaction of the Participants Committee, or no
satisfactory resolution can be achieved on terms acceptable to the parties
within 90 days of the Participant's receipt of the Participants Committee's
notice. Any agreement resulting from such negotiations shall be in writing and
shall be filed in accordance with the Commission's filing requirements if it
requires any payment.
SECTION 19
EXPENSES
19.1 Annual Fee. Each Participant shall pay to NEPOOL in January of each year
an annual fee, which shall be applied toward NEPOOL expenses, as follows:
(a) Each End User Participant which is a Small End User or an End User
Organization shall pay an annual fee of $500.
(b) Each End User Participant which is a Large End User shall pay an annual fee
of $500; plus an additional fee of $500 per megawatt hour of its highest Energy
use during any hour in the preceding year (net of any use of on-site generation)
up to a maximum of $5,000; plus an additional fee of $200 per megawatt hour for
each megawatt hour by which its highest Energy use during any hour in the
preceding year (net of any use of on-site generation during such hour) exceeded
20 megawatt hours.
(c) Each Participant which is a Publicly Owned Entity and a member of the
Publicly Owned Entity Sector shall pay an annual fee of $5,000, except that any
such Participant which is engaged in electricity distribution and had annual
Energy sales of less than 30,000 megawatt hours in the preceding year shall pay
an annual fee of $500, and the difference between $5,000 and $500 for each such
Participant shall be paid, as an additional fee, by the remaining Participants
which are Publicly Owned Entities and members of the Publicly Owned Entity
Sector.
(d) Each Participant other than an End User Participant or a Publicly Owned
Entity shall pay an annual fee of $5,000.
19.2 NEPOOL Expenses. Commencing on January 1, 1999, most expenses of the System
Operator are recovered by it directly from Participants and Non- Participants
under the ISO's Tariff for Transmission Dispatch and Power Administration (the
"ISO Tariff") or through direct charges for services rendered by the ISO, and
have ceased to be NEPOOL expenses. At that time, the payment of a portion of
NEPEX expenses from the Savings Fund in accordance with the Prior NEPOOL
Agreement also terminated.
Further, commencing on January 1, 1999 through June 30, 1999, the balance of
NEPOOL expenses remaining to be paid after the application of (i) the annual fee
to be paid pursuant to Section 19.1 and (ii) any fees or other charges for
services or other revenues received by NEPOOL, or collected on its behalf by the
System Operator, shall, except as otherwise provided in Section 19.3, be
allocated among and paid monthly by the Participants in accordance with their
respective voting shares, as determined in accordance with the Agreement
provisions in effect during such period.
Commencing as of July 1, 1999, such balance of NEPOOL expenses for July and
subsequent months shall be divided equally into as many shares as there are
active Sectors pursuant to Sector 6.2 (other than an End User Sector) and each
Sector's share shall be paid monthly by the Participants in each such Sector
(other than an End User Sector) in such manner as the Participants in each
Sector may determine by unanimous vote and advise the ISO, provided that if the
Participants in a Sector fail to agree unanimously on the allocation of their
Sector's share, the Participants in the Sector shall pay for such Sector share
in the same proportion as the vote they are entitled to in the Sector.
Participants in the Sector that are represented by a group voting member shall
subdivide their portion of the Sector's share of expenses in such a manner as
they may determine by unanimous agreement; provided that if there is not
unanimous agreement among the Participants represented by a group member as to
how to allocate their portion of the Sector's share of expenses, such portion
shall be allocated among the Participants represented by that group member as
follows: (i) for each Participant in the Generation Sector represented by a
group voting member, the portion will be allocated in the same proportion that
the Megawatts of generation owned by the Participants represents of the total
Megawatts owned by Participants represented by the group voting member; and (ii)
for Participants in the Transmission Sector, the portion will be allocated
equally among the Participants represented by the group member. Notwithstanding
the foregoing, no portion of such balance shall be paid by End User Participants
and, until such time as an End User Sector is activated, the monthly share
allocated to the Publicly Owned Entity Sector shall be reduced by one-twelfth of
the aggregate annual fees paid by End Users for the year pursuant to Section
19.1 and one-third of the amount of such reduction shall be allocated to each of
the other three Sectors.
19.3 Restructuring Costs.
(a) The expense of restructuring NEPOOL ("Restructuring Expense"), including but
not limited to (i) software development, hardware and system software costs for
implementation of the Tariff and the new market system, (ii) the costs of the
formation of the Independent System Operator and related separation costs, (iii)
legal and consultant costs related to the amendment of the NEPOOL Agreement
(including the Tariff) and the proceeding with respect thereto at the Federal
Energy Regulatory Commission, and (iv) capital expenditures and capitalized
project costs of the Independent System Operator, shall be funded (to the extent
not already funded or funded separately by the ISO) and amortized according to
this Section 19.3.
(b) The Restructuring Expense incurred (other than certain capital expenditures
and capitalized project costs funded separately by the ISO) before the Second
Effective Date (the "Early Restructuring Expense") has been funded during the
period prior to such date by those entities which have been the Participants
during such period. Commencing at the Second Effective Date, the Early
Restructuring Expense shall be amortized in equal monthly amounts and repaid
over the next 60 months with interest thereon from the date of payment to August
18, 2000 at the rate of 8% per annum, and thereafter at the rate of 10.78% per
annum. Each month during the first twenty months of such period each Participant
shall pay its percentage "X", as determined below, of 1/60th of the Early
Restructuring Expense, plus accumulated interest, and each Participant or other
Entity which previously paid an unreimbursed portion of the aggregate Early
Restructuring Expense shall be entitled to receive each month its percentage
"Y", as determined below, of the aggregate amount to be paid for the month
including accumulated interest. "X" and "Y" shall be determined in accordance
with the following formulas:
(EQUATION) in which
X is the percentage to be paid for a month by a Participant of the aggregate
amount payable pursuant to this subsection (b) by all Participants for the
month.
A is the amount payable by the Participant for the month under Schedule 2
(Energy Administration Services) of the ISO Tariff (as defined in Section 19.2)
as amended or revised from time to time.
A1 is the aggregate amount payable by all Participants for the month under
Schedule 2 (Energy Administration Services) of the ISO Tariff as amended or
revised from time to time.
(EQUATION) in which
Y is the percentage to be received for a month by a Participant or other Entity
of the aggregate amount to be received pursuant to this subsection (b) by all
Participants or other Entities for the month.
B is the amount of Early Restructuring Expense paid by the Participant or other
Entity which has not previously been reimbursed.
B1 is the aggregate amount of Early Restructuring Expense paid by all
Participants and other Entities which has not previously been reimbursed.
Each month commencing on or after January 1, 2001 and continuing until the Early
Restructuring Expense has been fully amortized and repaid (including the payment
of all interest thereon), each Participant shall pay its percentage "W", as
determined below, of 1/60th of the Early Restructuring Expense, plus accumulated
interest, and each Participant or other Entity which previously paid an
unreimbursed portion of the aggregate Early Restructuring Expense shall be
entitled to receive each month its percentage "Y", as determined in accordance
with the formula set forth therefor in this Section 19.3(b), of the aggregate of
the amount paid for the month, including accumulated interest. "W" shall be
determined in accordance with the following formula:
(EQUATION)
W is the percentage to be paid for the month by a Participant of the aggregate
amount payable pursuant to this subsection (b) by all Participants for the
month.
EL is the Participant's total Electrical Load, expressed in total kilowatthours,
for the month.
G is the sum, expressed in total kilowatthours, of (i) the Participant's share
of the amount of energy that is generated in the month by generating units in
which the Participant has a direct ownership interest as a sole or joint owner
and which is subject to NEPOOL central dispatch, (ii) the Participant's share of
the amount of energy generated in the month by generating units in which the
Participant has an indirect ownership interest as a shareholder, as a general or
limited partner or as a member of a limited liability company and which is
subject to NEPOOL central dispatch, provided that the corporation, partnership
or limited liability company is not itself a Participant, (iii) the
Participant's share of the amount of energy generated in the month by any other
generating unit in which the Participant has an interest under a lease or other
contractual arrangement, provided that the other party to the arrangement is
itself not a Participant, (iv) the share of any Related Person of the
Participant of the amount of energy generated in the month by any other
generating unit which is subject to NEPOOL central dispatch in which such
Related Person has one of the interests described in clauses (i), (ii) and (iii)
above, provided that such Related Person is not itself a Participant, and (v)
the amount of energy imported into the NEPOOL Control Area in the month by the
Participant or any Related Person of the Participant, provided that the Related
Person is not itself a Participant (the items described in this subparagraph are
collectively referred to as a Participant's "Generating Shares"); provided,
however, that if two or more Participants have entered into a Unit Contract for
Energy, the purchasing Participant(s), and not the selling Participant(s),
thereunder shall be credited with the amount of energy to which the purchasing
Participant(s) are entitled under that Unit Contract for purposes of calculating
the Generating Shares of each such Participant.
PEL is the maximum Electrical Load, expressed in total kilowatts, of the
Participant during any hour in the month (the "Peak Electrical Load").
GP is the maximum Generating Shares, expressed in total kilowatts, of the
Participant during any hour in the month (the "Generating Peak").
EL1 is the aggregate Electrical Load, expressed in total kilowatts, of all
Participants for the month.
G1 is the aggregate Generating Shares, expressed in total kilowatthours, of all
Participants for the month.
PEL1 is the aggregate Peak Electrical Load, expressed in total kilowatts, of all
Participants for the month.
GP1 is the aggregate Generating Peak, expressed in total kilowatts, of all
Participants for the month.
[Next Sheet is 241
(c) The Restructuring Expense incurred on the Second Effective Date and to but
not including January 1, 2000 or thereafter shall be funded each month by the
Participants in proportion to the Member Fixed Voting Shares (as defined in
Section 6.9(c)) of each Participant as in effect at the beginning of the month
provided, however, that in calculating the allocation of this portion of the
Restructuring Expense, the Member Fixed Voting Shares of End User Participants
that participate in NEPOOL for governance purposes only in accordance with
NEPOOL's Standard Membership Conditions, Waivers and Reminders ("Governance Only
End User Participants") shall not be included in such calculations and the
amounts that would otherwise have been payable by such Governance Only End User
Participants will be allocated to all of the other Participants on the basis of
their Member Fixed Voting Shares.
(d) The Restructuring Expense incurred on or after January 1, 2000 (the "Late
Restructuring Expense") shall be funded for each month, on an as incurred basis,
by the Participants to the extent that the ISO does not obtain an alternative
source of funds for certain portions of the Late Restructuring Expense. In 2000,
such Late Restructuring Expense shall initially be funded for each month by the
Participants in proportion to their charges under the ISO Tariff for the prior
month. In 2001 and thereafter, on an as-incurred basis, the ISO shall allocate
the incrementally incurred Late Restructuring Expense among the various
schedules to the ISO Tariff that is in effect at that time in a manner that best
matches the elements comprising the incrementally incurred Late Restructuring
Costs to the types of service to be covered by each schedule to the ISO Tariff,
and the portion of the Late Restructuring Expense to be funded by the
Participants that has been allocated to each such schedule to the ISO Tariff for
such year shall be funded in each month by the Participants in proportion to
their charges under such schedule for the prior month; provided, however, that
in the event that the Commission accepts (i) an amendment to the ISO Agreement
(as defined in Section 20(a) hereof) providing that in the event of a
termination or resignation of the ISO, all assets purchased by the ISO with
funds provided by the Participants for which the Participants have not been
reimbursed shall be transferred without further consideration to the
Participants or their designee (which amendment shall be mutually acceptable to
the ISO and the Participants Committee) and (ii) an amendment to the ISO Tariff
or a separate tariff for the ISO pursuant to which the ISO collects certain
portions of the Late Restructuring Expense thereunder, such portions of the Late
Restructuring Expense shall be funded directly under the ISO Tariff or such
separate tariff for the ISO and shall not be initially collected hereunder. Each
item of the Late Restructuring Expense funded by the Participants in each
calendar year (either hereunder, under the ISO Tariff or under a separate tariff
for the ISO) shall be amortized in equal monthly amounts and repaid over a
period of time determined by the ISO in accordance with generally accepted
accounting principles in effect at the time of determination and taking into
consideration the depreciation period, if any, of the particular asset giving
rise to such item of the Late Restructuring Expense, such repayment to include
interest thereon from the date of payment at the rate of 10.78% per annum. For
each item of the Late Restructuring Expense funded by the Participants
(regardless of whether it was incurred before, on or after January 1, 2001 and
whether it was funded hereunder, under the ISO Tariff or under a separate tariff
for the ISO) and during the time in which amounts are being amortized and repaid
for such item, the ISO shall determine to which schedule or schedules of the
then effective ISO Tariff such item relates, and the ISO, acting as agent for
the Participants initially providing the funding for such item, shall recover
the amounts being repaid that are associated with such item plus accrued
interest from the Participants using the allocation methodology set forth in
such schedule or schedules to the ISO Tariff. The ISO shall provide the amounts
recovered to the applicable Participants according to which Participants funded
the item of the Late Restructuring Expense for which the subject amounts have
been recovered.
(e) The funding methodology set forth in subsection (d) shall terminate
automatically upon the implementation of a permanent restructuring funding
methodology acceptable to the Participants Committee and the ISO, to the extent
superseded by such permanent restructuring funding methodology.
SECTION 20
INDEPENDENT SYSTEM OPERATOR
(a) The Participants Committee is authorized and directed to approve one or more
agreements to be entered into with the ISO (the "ISO Agreement") and any
amendments to the ISO Agreement which the Committee may deem necessary or
appropriate from time to time. The ISO Agreement shall specify the rights and
responsibilities of NEPOOL and the ISO, for the continued operation of the
NEPOOL control center by the ISO as the control center operator for the NEPOOL
Control Area and the administration of the Tariff. In addition, the ISO shall be
responsible for the furnishing of billing and other services required by NEPOOL.
(b) The fees and charges of the ISO (other than those recovered under the ISO
Tariff, as defined in Section 19.2, and fees and charges for services which are
separately billed), and any indemnification payable under the ISO Agreement,
shall be shared by the Participants in accordance with Section 19.
(c) The Participants shall provide to the ISO the financial support, information
and other resources necessary to enable the ISO to provide the services
specified in the ISO Agreement, or in this Agreement, in accordance with
Accepted Electric Industry Practice and subject to the budgeting, approval and
dispute resolution provisions of the ISO Agreement and this Agreement.
(d) The Participants shall provide appropriate funding for the acquisition of
land, structures, fixtures, equipment and facilities, and other capital
expenditures and capitalized project expenditures for the ISO, which are
included in the annual budget for the ISO in accordance with the provisions of
the ISO Agreement, or otherwise specifically approved by the Participants
Committee, but only to the extent that the ISO does not obtain such funding from
other sources. All such land, structures, fixtures, equipment and facilities,
and other capital assets, and all software or other intellectual property or
rights to intellectual property or other assets acquired or developed by the ISO
with funding provided by the Participants pursuant to this Agreement in order to
carry out its responsibilities under the ISO Agreement shall be the property of
the Participants or shall be acquired by the Participants under lease in
accordance with arrangements approved by the Participants Committee. For those
Participants subject to the Public Utility Holding Company Act of 1935
("PUHCA"), any such acquisition by those
Participants is subject to PUHCA approval to the extent such acquisition
requires approval under PUHCA. Unless otherwise agreed by the Participants, any
funding by the Participants of the acquisition, or lease, of land, structures,
fixtures, equipment and facilities, and other capital and/or capitalized project
related expenditures, or the acquisition of other assets, and the ownership
thereof, or the obligations of Participants as lessees, shall be in accordance
with Section 19.3 of this Agreement, the ISO Tariff or a separate tariff for the
ISO. The Participants shall make all such assets (including the assets of the
existing NEPOOL headquarters and control center) available for use by the ISO in
carrying out its responsibilities under the ISO Agreement. The ISO Agreement
shall require the ISO, on behalf of the Participants, to maintain and care for,
insure as appropriate, and pay any property taxes relating to, assets made
available for its use.
(e) The ISO Agreement shall require the ISO to refrain from any action that
would create any lien, security interest or encumbrance of any kind upon the
facilities, equipment or other assets of any Participant, or upon anything that
becomes affixed to such facilities, equipment or other assets. The Participants
and the ISO shall include in the ISO Agreement a provision that, upon the
request of an Participant, the ISO shall (i) provide a written statement that it
has taken no action that would create any such lien, security interest or
encumbrance, and (ii) take all actions within the control of the ISO, at the
direction and expense of the requesting Participant, required for compliance by
such Participant with the provisions of its mortgage relating to such
facilities, equipment or other assets.
(f) The ISO shall have the right to appoint a non-voting member and an alternate
to each NEPOOL committee other than the Participants Committee. The member
appointed to each committee shall have all of the rights of any other member of
the committee except the right to vote.
(g) The ISO shall have the same rights as a Participant to appeal to the
Participants Committee any action taken by any other NEPOOL committee, and shall
be entitled to appear before the Participants Committee on any such appeal.
Further, the ISO shall be entitled to submit any dispute with respect to a vote
of the Participants Committee to approve, modify, or reject a proposed action to
resolution in accordance with Section 21.1, whether or not the action could have
been submitted by a Participant in accordance with Section 21.1A. In addition,
the ISO shall be entitled to submit any dispute with respect to a vote of the
Participants Committee which denies an appeal to the Participants Committee by
the ISO or which takes action on any rulemaking issue to the Board of Directors
of the ISO for determination, subject to the right of the Participants Committee
to seek a review in accordance with the Alternate Dispute Resolution procedures
or by the Commission. The ISO shall give notice of any such submission to the
Secretary of the Participants Committee within ten days of the action of the
Participants Committee and shall mail a copy of such notice to each member of
the Participants Committee. Pending final action on the submission in accordance
with Section 21.1 or by the Board of Directors of the ISO or the Commission, as
appropriate, the giving of notice of the submission shall suspend the
Participants Committee's action. Unless the Board of Directors of the ISO acts
within 60 days of the ISO's notice to the Participants Committee, the
Participants Committee action will be deemed to be approved.
(h) The ISO Agreement shall specify the ISO's independent authority with respect
to rulemaking.
(i) NEPOOL and its committees and the ISO shall consult and coordinate from time
to time with the relevant state regulatory, siting and other authorities of the
six New England states on operating, planning and other issues of concern to the
states. The New England Conference of Public Utilities Commissioners, Inc.
("NECPUC") or its designee shall be furnished notices of meetings of all NEPOOL
committees and the Board of Directors of the ISO, and minutes of their meetings.
NECPUC and other state authorities shall be provided an appropriate opportunity
to appear at meetings of the NEPOOL committees and the Board of Directors of the
ISO and to present their views. Representatives of NEPOOL and the ISO shall be
designated to attend meetings of NECPUC or any committee or task force of
NECPUC, to the extent NECPUC or its committee or task force may deem such
attendance appropriate.
(j) Appointment of Technical Committee Officers. The System Operator shall,
after its chief executive officer has conferred with the Participant members of
the Liaison Committee regarding such appointment(s), appoint the Chair and
Secretary of each of the Technical Committees. Each individual appointed by the
System Operator shall be an independent person not affiliated with any
Participant. Before appointing an individual to the position of Chair or
Secretary, the System Operator shall notify the Committee to which such officer
is being appointed of the proposed assignment and, consistent with its personnel
practices, provide any other information about the individual reasonably
requested by the Committee. In the event that a Technical Committee determines
that the performance of the Chair or Secretary of the Committee is not
satisfactory, the Committee shall provide notice to the System Operator that
such performance deficiencies must be corrected within 60 days. If the Committee
determines that the performance deficiencies have not been corrected within the
60-day period, the Committee may vote to remove the officer, subject to appeal
to the Participants Committee. A vote of the Technical Committee to remove its
officer shall be immediately effective and binding on the System Operator and
shall cause the System Operator to appoint a replacement officer in accordance
with the provisions of this Section 20(j) unless an appeal to the Participants
Committee has been taken prior to the end of the tenth business day following
the vote to remove the officer in which case the vote for removal shall be
subject to the outcome of such appeal. A vote of the Participants Committee with
respect to any such appeal shall be immediately effective and binding on the
System Operator and not subject to any further appeals.
SECTION 21
MISCELLANEOUS PROVISIONS
21.1 Alternative Dispute Resolution.
A. General:
If the ISO is aggrieved by a vote of the Participants Committee to approve,
modify or reject a proposed action under this Agreement, including the Tariff,
it may submit the matter for resolution hereunder. If the Participants Committee
is aggrieved by an action of the ISO Board of Directors ("ISO Board") under this
Agreement, including the Tariff or the ISO Agreement (as defined in Section
20(a)), the Participants Committee may submit the matter for resolution
hereunder; provided, however, that if the action of the ISO relates to
rulemaking, the Participants Committee may submit the matters for resolution
under this Section 21.1 only with the concurrence of the ISO. Any Participant
which is aggrieved by a vote of the Participants Committee to approve, modify or
reject a proposed action under this Agreement, including the Tariff, may, as
provided below, submit the matter for resolution hereunder if the vote:
(1) requires such Participant to make a payment or to take any action
pursuant to this Agreement; or
(2) reduces the amount of any receipt or forbids, pursuant to this
Agreement, the taking of any action by the Participant; or
(3) fails to afford it any right to which it is entitled under the provisions of
this Agreement or imposes on it a burden to which it is not subject under the
provisions of this Agreement; or
(4) results in the termination of the Participant's status as a Participant
or imposes any penalty on the Participant; or
(5) results in an allocation of transmission or other facilities support
obligations; or
(6) fails to grant in full an application for transmission service pursuant
to the Tariff.
No legal or regulatory proceeding (except those reasonably necessary to toll
statutes of limitations, claims for laches or other bars to later legal or
regulatory action) shall be initiated by any Participant with respect to any
such matter while proceedings are pending under this Section with respect to the
matter.
B. Procedure:
(1) Submission of a Dispute: The ISO or a Participant seeking review of a vote
of the Participants Committee shall give written notice to the Secretary of the
Participants Committee within ten business days of the vote, and shall mail or
telecopy a copy of its notice to each member of the Participants Committee.
Where the Participants Committee is seeking review of an action of the ISO
Board, the Participants Committee shall give written notice to the Secretary of
the ISO Board. The provider of notice under this Section shall be referred to
herein as the "Aggrieved Party."
(2) Suspension of Action: If the ISO seeks review of a vote of the Participants
Committee pursuant to this Section, the vote to be reviewed shall be suspended
pending resolution of such review by the arbitrator or the Commission if raised
in regulatory proceedings. If a Participant seeks such a review, the vote to be
reviewed shall be suspended for up to 90 days following the giving of the
Participant's notice pending resolution of any arbitration proceeding unless the
Participants Committee determines that the suspension will imperil the stability
or reliability of the NEPOOL Control Area bulk power supply.
(3) Aggrieved Party Options: (i) If the notice is to seek review of a vote of
the Participants Committee, the Aggrieved Party's notice to the Participants
Committee shall invoke arbitration as described herein in its notice pursuant to
paragraph B(1), and may also initiate mediation with the agreement of the
Participants Committee, while reserving such Party's right to proceed with the
arbitration if mediation does not resolve the matter within 20 days of the
giving of the Party's notice or such longer period as may be fixed by mutual
agreement of the Participants Committee and the Aggrieved Party. Notwithstanding
the initiation of mediation, the arbitration proceeding shall proceed
concurrently with the selection of the arbitrator pursuant to paragraph C(1) of
this Section 21.1.
(i) If the notice is to seek review of an ISO action, the Participants
Committee's notice to the ISO Board shall (subject to the concurrence of the ISO
for actions relating to rulemaking as provided in Section 21.1A) invoke
arbitration as described herein in its notice pursuant to paragraph B(1), and
may also initiate mediation with the agreement of the ISO Board, while reserving
the Participants Committee's right to proceed with the arbitration if mediation
does not resolve the matter within 20 days of the giving of the Participants
Committee's notice or such longer period as may be fixed by mutual agreement of
the ISO Board and the Participants Committee. Notwithstanding the initiation of
mediation, the arbitration proceeding shall proceed concurrently with the
selection of the arbitrator pursuant to paragraph C(1) of this Section 21.1.
(4) Mediation Positions not to be Used Elsewhere: All mediation proceedings
pursuant to this Section are confidential and shall be treated as compromise and
settlement negotiations for purposes of applicable rules of evidence.
(5) Time Limits; Duration: Any other Participant that wishes to participate in
an arbitration proceeding hereunder shall give signed written notice to the
Secretary of the Participants Committee, and to the Secretary of the ISO Board
if the ISO is involved in such arbitration, no later than ten calendar days
after the giving of the notice of arbitration. The arbitration procedure shall
not exceed 90 calendar days from the date of the Aggrieved Party's notice
invoking arbitration to the arbitrator's decision unless the parties agree upon
a longer or shorter time. All agreements by the ISO or the aggrieved Participant
and the Participants Committee to use mediation shall establish a schedule which
will control unless later changed by mutual agreement.
C. Arbitration:
(1) Selection of Arbitrator: The ISO or the aggrieved Participant and the
Participants Committee shall attempt to choose by mutual agreement a single
neutral arbitrator to hear the dispute. If the ISO or the Participant and the
Participants Committee fail to agree upon a single arbitrator within ten
calendar days of the giving of notice of arbitration to the Secretary of the
Participants Committee or the Secretary of the ISO Board, as the case may be,
the American Arbitration Association shall be asked to appoint an arbitrator. In
either case, the arbitrator shall be knowledgeable in matters involving the
electric power industry, including the operation of control areas and bulk power
systems, and shall not have any substantial business or financial relationships
with the ISO, NEPOOL or its Participants (other than previous experience as an
arbitrator) unless otherwise mutually agreed by the ISO or the aggrieved
Participant and the Participants Committee.
(2) Costs: NEPOOL shall be responsible for all of the costs of the proceeding if
it is initiated by the ISO or by the Participants Committee. If a proceeding is
initiated by an aggrieved Participant, each party shall be responsible for the
following costs, if applicable:
(i) its own costs incurred during the arbitration process (except that this does
not preclude billing the aggrieved Participant for its share of NEPOOL Expenses
that may include the Participants Committee's arbitration costs); plus
(ii) One half of the common costs of the arbitration including, but not limited
to, the arbitrator's fee and expenses, the rental charge for a hearing room and
the cost of a court reporter and transcript, if required.
(3) Hearing Location: Unless otherwise mutually agreed, the site for all
arbitration hearings shall be NEPOOL counsel's office.
D. Rules and Procedures:
(1) Procedure and Discovery: The procedural rules (if any), the conduct of the
arbitration and the availability, extent and duration of pre-hearing discovery
(if any), which shall be limited to the minimum necessary to resolve the matters
in dispute, shall be determined by the arbitrator in his/her sole discretion at
or prior to the initial hearing.
(2) Pre-hearing Submissions: The Aggrieved Party shall provide the arbitrator
with a brief written statement of its complaint and a statement of the remedy or
remedies it seeks, accompanied by copies of any documents or other materials it
wishes the arbitrator to review. The Participants Committee will provide the
arbitrator with a copy of this Agreement and all relevant implementing
documents, a brief description of the action being arbitrated, copies of the
minutes of all NEPOOL committee meetings at which the matter was discussed, a
brief statement explaining why the Participants Committee believes its decision
should be upheld by the arbitrator, and copies of any documents or other
materials the Participants Committee wishes the arbitrator to review. If the
Participants Committee is the Aggrieved Party, the ISO Board will provide copies
of minutes of the ISO Board meetings at which the matter was discussed, a brief
statement explaining why the ISO Board believes its decision should be upheld by
the arbitrator, and copies of any documents or other materials the ISO Board
wishes the arbitrator to review. These submissions shall be made within five
days after the selection of the arbitrator.
In addition, each party shall designate one or more individuals to be available
to answer questions the arbitrator may have on the documents or other materials
submitted by that party. The answers to all such questions shall be reduced to
writing by the party providing the answer and a copy shall be furnished to the
other party.
(3) Initial Hearing: An initial hearing will be held no later than 10 days after
the selection of the arbitrator and shall be limited to issues raised in the
pre-hearing filings. The scheduling of further hearings at the request of either
party or on the arbitrator's own motion shall be within the sole discretion of
the arbitrator.
(4) Decision: The arbitrator's decision shall be due, unless the deadline is
extended by mutual agreement of the ISO or the aggrieved Participant and the
Participants Committee, within sixty days of the initial hearing or within
ninety days of the Aggrieved Party's initiation of arbitration, whichever occurs
first. The arbitrator shall be authorized only to interpret and apply the
provisions of this Agreement and the arbitrator shall have no power to modify or
change the Agreement in any manner.
(5) Effect of Arbitration Decision: The decision of the arbitrator will be
conclusive in a subsequent regulatory or legal proceeding as to the facts
determined by the arbitrator but will not be conclusive as to the law or
constitute precedent on issues of law in any subsequent regulatory or legal
proceedings.
An aggrieved party may initiate a proceeding with a court or with the Commission
with respect to the arbitration or arbitrator's decision only:
if the arbitration process does not result in a decision within the time period
specified and the proceeding is initiated within thirty days after the
expiration of such time period; or
on the grounds specified in Sections 10 and 11 of Title 9 of the United States
Code for judicial vacation or modification of an arbitration award and the
proceeding is initiated within thirty days of the issuance of the arbitrator's
decision.
(6) Other Disputes: In the event a dispute arises with a Non-Participant which
receives or is eligible to receive service under this Agreement or the Tariff
with respect to such service, the Non-Participant shall have the right to have
the dispute considered by the Participants Committee. In the event the
Non-Participant is aggrieved by the Participants Committee's vote on the
dispute, and the vote has any of the effects specified in paragraph A of this
Section 21.1, the aggrieved Non-Participant may require that the dispute be
resolved in accordance with this Section 21.1. To the extent that NEPOOL
provides services to Non-Participants under separate agreements, the
Participants Committee shall incorporate the provisions of this Section by
reference in any such agreement, in which case the term "Participant" shall be
deemed for purposes of the dispute resolution provisions to include such
Non-Participant purchasers of NEPOOL services.
21.2 Payment of Pool Charges; Termination of Status as Participant.
(a) Any Participant shall have the right to terminate its status as a
Participant upon no less than six months' prior written notice given to the
Secretary of the Participants Committee.
(b) If at any time during the term of this Agreement a receiver or trustee of a
Participant is appointed or a Participant is adjudicated bankrupt or an order
for relief is entered under the Federal Bankruptcy Code against a Participant or
if there shall be filed against any Participant in any court (pursuant to the
Federal Bankruptcy Code or any statute of Canada or any state or province) a
petition in bankruptcy or insolvency or for reorganization or for appointment of
a receiver or trustee of all or a portion of the Participant's property, and
within ninety days after the filing of such a petition against the Participant,
the Participant shall fail to secure a discharge thereof, or if any Participant
shall file a petition in voluntary bankruptcy or seeking relief under any
provision of any bankruptcy or insolvency law or shall make an assignment for
the benefit of creditors, the Participants Committee may terminate such
Participant's status as a Participant as of any time thereafter.
(c) Each Participant is obligated to pay when due in accordance with NEPOOL
procedures all amounts invoiced to it by NEPOOL, or by the ISO on behalf of
NEPOOL. If the Participant fails to meet this requirement for continuation of
service, the actions described in subsection (d) of this Section 21.2 may be
taken. If a Participant disputes a NEPOOL invoice with respect to charges for
transmission service in whole or part, it shall be entitled to continue to
receive service under the Agreement and the Tariff, so long as the Participant
(i) continues to make all payments not in dispute, and (ii) pays into an
independent escrow account the portion of the invoice in dispute, pending
resolution of the dispute.
(d) In the event a Participant fails to pay when due in accordance with NEPOOL
System Rules (including, without limitation, the NEPOOL Billing Policy attached
to the Tariff (the "Billing Policy")) all amounts invoiced to it by NEPOOL, or
by the ISO on behalf of NEPOOL (a "Payment Default"), or the Participant fails
to comply with the Financial Assurance Policy for NEPOOL Members attached to the
Tariff (the "Member Financial Assurance Policy"), or the Participant fails to
perform any other obligations under the Agreement or the Tariff, and such
failure continues for at least ten days, NEPOOL, or the ISO on behalf of NEPOOL,
may (but shall not be required to) notify such Participant in writing,
electronically and by first class mail sent in each case to such Participant's
member or alternate on the Participants Committee or billing contact, that it is
in default, and NEPOOL may initiate a proceeding before the Commission to
terminate such Participant's status as a Participant. Either simultaneously with
the giving of the notice described in the preceding sentence or within ten days
thereafter (unless the default or failure giving rise to such notice is cured
during such period), NEPOOL, or the ISO on behalf of NEPOOL, shall notify each
other member and alternate on the Participants Committee and each Participant's
billing contact of the identity of the Participant receiving such notice,
whether such notice relates to a Payment Default, to a failure to comply with
the Member Financial Assurance Policy, or to another failure to perform
obligations under the Agreement or the Tariff, and the actions the ISO plans to
take and/or has taken in response to such default or failure. Pending Commission
action on such termination, NEPOOL may suspend service, in whole or part, to the
Participant on or after 50 days after the giving of notice and the initiation of
such proceeding, in accordance with
[Next Sheet is 265]
Commission policy, unless the Participant cures the default within such 50- day
period.
(e) If the status of a Participant as a Participant is terminated pursuant to
this Section 21.2 or any other provision of this Agreement, such former
Participant's generation and transmission facilities shall continue to be
subject to such NEPOOL or other requirements relating to reliability as the
Commission may approve in acting on the termination, for so long as the
Commission may direct. Further, if any of such former Participant's transmission
facilities are required in order to permit transactions among any of the
remaining Participants pursuant to this Agreement or the Tariff, all pending
requests for transmission service under the Tariff relating to such
Participant's facilities shall be followed to completion under the Participant's
own tariff and all existing service over the Participant's facilities shall
continue to be provided under the Tariff for a period of three years. It is the
intent of this subsection that no such termination should be allowed to
jeopardize the reliability of the bulk power facilities of any remaining
Participant or should be allowed to impose any unreasonable financial burden on
any remaining Participant.
(f) No such termination of a Participant's status as a Participant shall affect
any obligation of, or to, such former Participant incurred prior to the
effective time of such termination.
21.3 Assignment. The Agreement shall inure to the benefit of, and shall be
binding upon, the successors and assigns of the respective signatories hereto,
but no assignment of a signatory's interests or obligations under the Agreement
or any portion thereof shall be made without the written consent of the
Participants Committee, except as otherwise permitted by the Tariff, or except
in connection with a sale, merger, or consolidation which results in the
transfer of all or a portion of a signatory's generation or transmission assets
to, and the assumption of all of the obligations of the signatory under this
Agreement (or in the case of a transfer of a portion of a signatory's generation
or transmission assets, the assumption of obligations of the signatory under
this Agreement with respect to such assets) by, an acquiring or surviving Entity
which either is, or concurrently becomes, a Participant, or agrees to assume
such of the signatory's obligations with respect to such assets as the
Participants Committee may reasonably require, or except in connection with the
grant of a security interest in a Participant's assets as security for bonds or
other financing.
21.4 Force Majeure. A Participant shall not be considered to be in default in
respect of any obligation hereunder if prevented from fulfilling such obligation
by an event of Force Majeure. An event of Force Majeure means any act of God,
labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm
or flood, explosion, breakage or accident to machinery or equipment, any
Curtailment, any order, regulation or restriction imposed by a court or
governmental military or lawfully established civilian authorities, or any other
cause beyond a Participant's control, provided that no event of Force Majeure
affecting any Participant shall excuse that Participant from making any payment
that it is obligated to make under this Agreement. A Participant whose
performance under this Agreement is hindered by an event of Force Majeure shall
make all reasonable efforts to perform its obligations under this Agreement, and
shall promptly notify the Participants Committee of the commencement and end of
any event of Force Majeure.
21.5 Waiver of Defaults. No waiver of the performance by a Participant of any
obligation under this Agreement or with respect to any default or any other
matter arising in connection with this Agreement shall be effective unless given
by the Participants Committee. Any such waiver by the Participants Committee in
any particular instance shall not be deemed a waiver with respect to any
subsequent performance, default or matter.
21.6 Other Contracts. No Participant shall be a party to any other agreement
which in any manner is inconsistent with its obligations under this Agreement.
21.7 Liability and Insurance.
(a) Each Participant will indemnify and save each of the other Participants, its
officers, directors and Related Persons (each an "Indemnified Party") harmless
from and against all actions, claims, demands, costs, damages and liabilities
asserted by a third party against the Indemnified Party seeking indemnification
and arising out of or relating to bodily injury, death or damage to property
caused by or sustained on facilities owned or controlled by such Participant
that are the subject of this Agreement, or caused by a failure to act in
accordance with this Agreement by the Participant from which indemnification is
sought, except (i) to the extent that such liabilities result from the
negligence or willful misconduct of the Participant seeking indemnification, and
(ii) each Participant shall be responsible for all claims of its own employees,
agents and servants growing out of any workmen's compensation law. The amount of
any indemnity payment under the provisions of this Section 21.7 shall be reduced
(including, without limitation, retroactively) by any insurance proceeds or
other amounts actually recovered by the Indemnified Party in respect of the
indemnified action, claim, demand, cost, damage or liability. Notwithstanding
the foregoing, no Participant shall be liable to any Indemnified Party for any
claim for loss of profits or revenues, attorneys' fees or costs, cost of capital
or financing, loss of goodwill or cost of replacement power arising from a
Participant's carrying out, or failing to carry out, any obligations
contemplated by this Agreement or for any other indirect, incidental, special,
consequential, punitive, or multiple damages or loss; provided, however, that
nothing herein shall reduce or limit the obligations of any Participant to
Non-Participants.
(b) Each Participant shall furnish, at its sole expense, such insurance coverage
as the Participants Committee may reasonably require with respect to its
obligation pursuant to Section 21.7(a).
21.8 Records and Information. Each Participant shall keep such records as may
reasonably be required by a NEPOOL committee or the System Operator, and shall
furnish to such committee or the System Operator such records, reports and
information (including forecasts) as it may reasonably require, provided the
confidentiality thereof is protected in accordance with NEPOOL's information
policy.
21.9 Consistency with NPCC and NERC Standards. The standards, criteria and rules
adopted by NEPOOL committees under this Agreement shall be consistent with those
adopted by the NPCC and NERC or any successor to either.
21.10 Construction.
(a) The Table of Contents contained in this Agreement and the headings of the
Sections of this Agreement are intended for convenience only and shall not be
deemed to be part of this Agreement or considered in construing it.
(b) This Agreement shall be interpreted, construed and governed in accordance
with the laws of the State of Connecticut.
21.11 Amendment. Subject to Section 17A and the provisions of this Section, this
Agreement, including the Tariff, and any attachment or exhibit hereto may be
amended from time to time by vote of the Participants in accordance with Section
6.11.
Any amendment to this Agreement approved in accordance with Section 6.11 and/or
Section 17A shall be in writing and shall become effective, and shall bind all
Participants regardless of whether they have executed a ballot in favor of such
amendment, on the date specified in the amendment, subject to acceptance or
approval by the Commission. Nothing herein shall be construed to prevent any
Participant from challenging any proposed amendment before a court or regulatory
agency on the ground that the proposed amendment or its application to the
Participant is in violation of law or of this Agreement.
21.12 Termination. This Agreement shall continue in effect until terminated, in
accordance with the Commission's regulations, by Participants represented by
members of the Participants Committee having Member Fixed Voting Shares equal to
at least 70% of the Member Fixed Voting Shares of all Participants. No such
termination shall relieve any party of any obligation arising prior to the
effective time of such termination.
21.13 Notices to Participants, Committees, Committee Members, or the
System Operator.
(a) Any notice, demand, request or other communication required or authorized by
this Agreement to be given to any Participant shall be in writing, and shall be
(1) personally delivered to the Participants Committee member or alternate
representing that Participant; (2) mailed, postage prepaid, to the Participant
at the address of its member on the Participants Committee as set out in the
NEPOOL roster; (3) sent by facsimile ("faxed") to the Participant at the fax
number of its member on the Participants Committee as set out in the NEPOOL
roster; or (4) delivered electronically to the Participant at the electronic
mail address of its member on the Participants Committee or at the address of
its principal office. The designation of any such address may be changed at any
time by written notice delivered to the Secretary of the Participants Committee,
who shall cause such change to be reflected in the NEPOOL roster.
(b) Any notice, demand, request or other communication required or authorized by
this Agreement to be given to any NEPOOL committee shall be in writing and shall
be delivered to the Secretary of the committee. Each such notice shall either be
personally delivered to the Secretary, mailed, postage prepaid, or sent by
facsimile ("faxed") to the Secretary at the address or fax number set out in the
NEPOOL roster, or delivered electronically to the Secretary. The designation of
such address may be changed at any time by written notice delivered to each
Participant.
(c) Any notice, demand, request or other communication required or authorized by
this Agreement to be given to a member or alternate to that member of a
Principal Committee (for the purposes of this Section 21.13, individually or
collectively, the "Committee Member") shall be (1) personally delivered to the
Committee Member; (2) mailed, postage prepaid, to the Committee Member at the
address of the Committee Member set out in the NEPOOL roster; (3) sent by
facsimile ("faxed") to the Committee Member at the fax number of the Committee
Member set out in the NEPOOL roster; or (4) delivered electronically to the
Committee Member at the electronic mail address of the Committee Member set out
in the NEPOOL roster. The designation of any such address may be changed at any
time by written notice delivered to the Secretary of the Principal Committee on
which the Committee Member serves, who shall cause such change to be reflected
in the NEPOOL roster.
(d) Any notice, demand, request or other communication required or authorized by
this Agreement to be given to the System Operator shall be in writing, and shall
be (1) personally delivered to the Participants Committee member or alternate
appointed by the System Operator; (2) mailed, postage prepaid, to the System
Operator at the address of its member on the Participants Committee as set out
in the NEPOOL roster; (3) sent by facsimile ("faxed") to the System Operator at
the fax number of its member on the Participants Committee as set out in the
NEPOOL roster; or (4) delivered electronically to the System Operator at the
electronic mail address of its member on the Participants Committee or at the
address of its principal office. The designation of any such address may be
changed at any time by written notice delivered to the Secretary of the
Participants Committee, who shall cause such change to be reflected in the
NEPOOL roster.
(e) To the extent that the Participants Committee is required to serve upon any
Participant a copy of any document or correspondence filed with the Commission
under the Federal Power Act or the Commission's rules and regulations
thereunder, by or on behalf of any Principal Committee, such service may be
accomplished by electronic delivery to the Participant at the electronic mail
address of its Participants Committee member and alternate. The designation of
any such address may be changed at any time by written notice delivered to the
Secretary of the Participants Committee.
(f) Any such notice, demand or request so addressed and mailed by registered or
certified mail shall be deemed to be given when so mailed. Any such notice,
demand, request or other communication sent by regular mail or by facsimile
("faxed") or delivered electronically shall be deemed given when received by the
Participant, Committee Member, System Operator, or Secretary of the NEPOOL
committee, whichever is applicable.
21.14 Severability and Renegotiation. If any provision of this Agreement is held
by a court or regulatory authority of competent jurisdiction to be invalid, void
or unenforceable, the remainder of the terms, provisions, covenants and
restrictions of this Agreement shall continue in full force and effect and shall
in no way be affected, impaired or invalidated, except as otherwise explicitly
provided in this Section.
If any provision of this Agreement is held by a court or regulatory authority of
competent jurisdiction to be invalid, void or unenforceable, or if the Agreement
is modified or conditioned by a regulatory authority exercising jurisdiction
over this Agreement, the Participants shall endeavor in good faith to negotiate
such amendment or amendments to this Agreement as will restore the relative
benefits and obligations of the Participants under this Agreement immediately
prior to such holding, modification or condition. If after sixty days such
negotiations are unsuccessful the Participants may exercise their withdrawal or
termination rights under this Agreement.
21.15 No Third-Party Beneficiaries. Except for the provisions of this Agreement
and the Tariff which provide for service to Non-Participants, this Agreement is
intended to be solely for the benefit of the Participants and their respective
successors and permitted assigns and, unless expressly stated herein, is not
intended to and shall not confer any rights or benefits on any third party
(other than successors and permitted assigns) not a signatory hereto.
21.16 Counterparts. This Agreement may be executed in any number of
counterparts, and each executed counterpart shall have the same force and effect
as an original instrument and as if all the parties 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.
IN WITNESS WHEREOF, the signatories have caused this Agreement to be executed by
their duly authorized officers or representatives.
Sheet Nos. 279 through 299 are reserved for future use.
ATTACHMENT A
METHODOLOGY FOR
DETERMINATION OF
TRANSMISSION FLOWS
The methodology for determining parallel path transmission flows to be used in
determining the distribution of revenues received for Regional Network Service
provided during the Transition Period, or for Through or Out Service, is as
follows, and shall be determined (1) on the basis of the flows for all
transactions in the NEPOOL Control Area ("Regional Flows") for the purpose of
allocating during the Transition Period Regional Network Service revenues, and
(2) on the basis of the flows for the particular transaction ("Transaction
Flows") for the purpose of allocating revenues during or after the Transition
Period from the furnishing of Through or Out Service:
A. Responsibility for Calculations
The calculation of megawatt mile allocations in accordance with this methodology
shall be performed under the direction of the Reliability Committee.
B. Periodic Review
Calculations of MW-Mile allocations shall be performed whenever significant
changes to the transmission system load flows, as determined by the Reliability
Committee, occur.
C. Facilities Included in the Analysis
1. Transmission Lines
A calculation of MW-miles shall be determined for all PTF lines.
2. Generators
The analysis shall include all generators with a Winter Capability equal to or
greater than 10.0 MW. Multiple generators connected to a single bus with a total
Winter Capability equal to or greater than 10.0 MW shall also be included.
3. Transformers
All transformers connecting PTF transmission lines shall be included in the
analysis.
D. Determination of Rate Distribution
1. General
Modeling of the transmission system shall be performed using a system simulation
program and associated cases as approved by the Reliability Committee.
2. Determination of Regional Flows
The change in real power flow (MW) over each transmission line and transformer
shall be determined for each generator (or group of generators on a single bus)
by determining the absolute value of the difference between the flows on each
facility with the generator(s) modeled off and while operating at its net Winter
Capability. In addition, a generator shall be simulated at each transmission
line tie to the NEPOOL Control Area and changes in flow determined for this
generator off or while generating at a level of 100 MW. Loads throughout the
NEPOOL Control Area shall be proportionally scaled to account for differences in
generator output and electrical losses. The changes in flow shall be multiplied
by the length of each respective line. Changes in flow through transformers
shall be multiplied by a factor of five. Changes in flow through phase-shifting
transformers shall be multiplied by a factor of ten. The resulting values
represent the MW-miles associated with each facility.
3. Determination of Transaction Flows
a. Definition of Supply and Receipt Areas
For the purposes of these calculations, areas of supply and receipt shall be
determined by the Reliability Committee.
These areas shall be based on the system boundaries of each Local Network.
b. Calculation of MW-Miles
The change in real power flow (MW) over each transmission line and transformer
shall be determined for each combination of supply and receipt areas by
determining the absolute value of the difference between the flows on each
facility following a scaled increase of the supplying areas generation by 100
MW. Loads in the area of receipt shall be scaled to account for changes in
generation and electrical losses. In instances where the areas of supply and/or
receipt are outside the NEPOOL Control Area, the changes in real power flow will
be determined only for facilities within the NEPOOL Control Area. The changes in
flow shall then be multiplied by the length of each respective line. Changes in
flow through transformers shall be multiplied by a factor of five.
Changes in flow through phase-shifting transformers shall be multiplied by a
factor of ten. The resulting values represent the MW-miles associated with each
facility.
4. Assignment of MW-Miles to Participants
Each Participant shall have assigned to it the MW-miles associated with each PTF
facility for which it has full ownership and for which there are no arrangements
in effect by which other Participants support the facility. For facilities that
are jointly owned and/or supported, each Participant shall be assigned MW-miles
in proportion to the percentage of its ownership of jointly-owned facilities
and/or the percentage of its support for facilities that are jointly supported
to the extent such support payments are included in the determination of Annual
Transmission Revenue Requirements
ATTACHMENT B
NEPOOL OPEN ACCESS TRANSMISSION TARIFF
See FERC Electric Tariff, Fourth Revised Volume 1.
ATTACHMENT C
RELIABILITY REGIONS
NEW ENGLAND POWER POOL
RESTATED NEPOOL OPEN ACCESS
TRANSMISSION TARIFF
FERC ELECTRIC TARIFF, FOURTH REVISED VOLUME NO. 1
(As amended through the Sixty-Ninth Agreement
Amending New England Power Pool Agreement)
I. COMMON SERVICE PROVISIONS
1 Definitions
1.1 Administrative Costs
1.2 Agreement
1.3 Ancillary Services
1.4 Annual Transmission Revenue Requirements
1.5 Application
1.6 ARR
1.7 ARR Allocation
1.8 Auction Revenue Right
1.9 Auction Revenue Right Holder
1.10 Backyard Generation
1.11 Business Day
1.12 CMS
1.13 CMS/MSS Effective Date
1.14 Commission
1.15 Completed Application
1.16 Compliance Effective Date
1.17 Congestion
1.18 Congestion Component
1.19 Congestion Cost
1.20 Congestion Paying Entity
1.21 Congestion Revenue
1.22 Congestion Revenue Fund
1.23 Congestion Revenue Shortfall
1.24 Congestion Revenue Surplus
1.25 Control Area
1.26 Curtailment
1.27 Day-Ahead
1.28 Day-Ahead Market
1.29 Delivering Party
1.30 Demand Bid
1.31 Demand Bid Price
1.32 Designated Agent
1.33 Direct Assignment Facilities
1.34 Direct Interconnection Transmission Costs
1.35 Dispatch Day
1.36 Distribution Company
1.37 Distribution Company Load Zone
1.38 Economic Upgrade
1.39 Elective Transmission Upgrade
1.40 Eligible Customer
1.41 Energy
1.42 Energy Imbalance Service
1.43 Entitlement
1.44 Excepted Transaction
1.45 External Node
1.46 Facilities Study
1.47 FCR
1.48 FCR Auction
1.49 FCR Auction Revenue
1.50 FCR Auction Revenue Fund
1.51 FCR Holder
1.52 FCR Payment
1.53 Financial Congestion Right
1.54 Firm Contract
1.55 Firm Point-To-Point Transmission Service
1.56 Firm Transmission Service
1.57 Generator Interconnection Related Upgrade
1.58 Generator Owner
1.59 Good Utility Practice
1.60 Hub
1.61 Hub Price
1.62 HQ Interconnection
1.63 HQ Phase II Firm Energy Contract
1.64 Import Transaction
1.65 Interchange Transactions
1.66 Interest
1.67 Internal Point-to-Point Service
1.68 Internal Point-to-Point Service Rate
1.69 Interruption
1.70 ISO
1.71 Load Asset Contract
1.72 Load Ratio Share
1.73 Load Shedding
1.74 Load Zone
1.75 Local Network
1.76 Local Network Service
1.77 Local Point-To-Point Service
1.78 Location
1.79 Locational Price
1.80 Long-Term Firm Service
1.81 Marginal Loss
1.82 Marginal Loss Component
1.83 Marginal Loss Revenue
1.84 Marginal Loss Revenue Fund
1.85 Market Rules
1.85 A Merchant Transmission Facility
1.86 Minimum Interconnection Standard
1.87 Monthly Network Load
1.88 Monthly Peak
1.89 Monthly Peak Load
1.90 Native Load Customers
1.91 NEMA
1.92 NEMA ARRs
1.93 NEMA Contract
1.94 NEMA LSE
1.95 NEMA or "Northeast Massachusetts" Upgrade
1.96 NEPOOL
1.97 NEPOOL Control Area
1.98 NEPOOL System Rules
1.99 NEPOOL Transmission Plan
1.100 NEPOOL Transmission System
1.101 NERC
1.102 Network Customer
1.103 Network Integration Transmission Service
1.104 Network Load
1.105 Network Operating Agreement
1.106 Network Operating Committee
1.107 Network Resource
1.108 Network Upgrades
1.109 Nodal Price
1.110 Node
1.111 Non-Firm Point-To-Point Transmission Service
1.112 Non-Participant
1.113 Non-PTF
1.114 Northeast Massachusetts Upgrade
1.115 NPCC
1.116 Open Access Same-Time Information System (OASIS) 1.117 Operating Reserve -
10-Minute Non-Spinning Reserve Service 1.118 Operating Reserve - 10-Minute
Spinning Reserve Service 1.119 Operating Reserve - 30-Minute Reserve Service
1.120 Participant 1.121 Participant RNS Rate 1.122 Participants Committee 1.123
Point(s) of Delivery 1.124 Point(s) of Receipt 1.125 Point-To-Point Transmission
Service 1.126 Pool-Planned Unit 1.127 Pool PTF Rate 1.128 Pool RNS Rate 1.129
Pool-Supported PTF 1.130 Power Purchaser 1.131 Prior NEPOOL Agreement 1.132 PTF
or Pool Transmission Facilities 1.133 Pre-1997 PTF Rate 1.134 Publicly Owned
Entity 1.135 Quick Fix Upgrade 1.136 Reactive Supply and Voltage Control From
Generation Sources Service 1.137 Real-Time 1.138 Real-Time Market 1.139
Receiving Party 1.140 Reference Node 1.141 Regional Network Service 1.142
Regulation and Frequency Response Service 1.143 Reliability Region 1.144
Reliability Upgrade 1.145 Reserved Capacity 1.146 Scheduling, System Control and
Dispatch Service 1.147 Second Effective Date 1.148 Service Agreement 1.149
Service Commencement Date 1.150 Settlement Obligation 1.151 Shift Factor 1.152
Short-Term Firm Service 1.153 Standard Offer Obligation 1.154 Supply Obligation
1.155 Supply Offer 1.156 System Contract 1.157 System Impact Study 1.158 System
Operator 1.159 Target FCR Payment 1.160 Tariff 1.161 Third-Party Sale 1.162
Through or Out Service 1.163 Third Effective Date 1.164 Ties 1.165 Transition
Period 1.166 Transmission Customer 1.167 Transmission Owner 1.168 Transmission
Owners Committee 1.169 Transmission Provider 1.170 Transmission System Upgrade
1.171 Unit Contract 1.172 Use 1.173 Withdrawal Factor 1.174 Year 1.175 Zonal
Price 2 Purpose of This Tariff 3 Initial Allocation and Renewal Procedures 3.1
Initial Allocation of Available Transmission Capability 3.2 Reservation Priority
for Existing Firm Service Customers 3.3 Initial Election of Optional Internal
Point-to-Point Service 4 Ancillary Services 4.1 Scheduling, System Control and
Dispatch Service 4.2 Reactive Supply and Voltage Control from Generation Sources
Service 4.3 Regulation and Frequency Response Service 4.4 Energy Imbalance
Service 4.5 Operating Reserve - 10-Minute Spinning Reserve Service 4.6 Operating
Reserve - 10-Minute Non-Spinning Reserve Service 4.7 Operating Reserve -
30-Minute Reserve Service 4.8 System Restoration and Planning Service 5 Open
Access Same-Time Information System (OASIS) 6 Local Furnishing and Other
Tax-Exempt Bonds 6.1 Participants That Own Facilities Financed by Local
Furnishing or Other Tax-Exempt Bonds 6.2 Alternative Procedures for Requesting
Transmission Service - Local Furnishing Bonds 6.3 Alternative Procedures for
Requesting Transmission Service - Other Tax-Exempt Bonds 7 Reciprocity 8 Billing
and Payment; Accounting 8.1 Participant Billing Procedure 8.2 Non-Participant
Billing Procedure 8.3 Interest on Unpaid Balances 8.4 Customer Default 8.5 Study
Costs and Revenues 9 Regulatory Filings 10 Force Majeure and Indemnification
10.1 Force Majeure 10.2 Indemnification 11 Creditworthiness 12 Dispute
Resolution Procedures 12.1 Internal Dispute Resolution Procedures 12.2 Rights
Under The Federal Power Act 13 Stranded Costs 13.1 General 13.2 Commission
Requirements 13.3 Wholesale Contracts 13.4 Right to Seek or Contest Recovery
Unimpaired II. REGIONAL NETWORK SERVICE (NETWORK INTEGRATION TRANSMISSION
SERVICE) 14 Nature of Regional Network Service 14.1 Rules for Import
Transactions Conducted in Conjunction with Regional Network Service: 15
Availability of Regional Network Service 15.1 Provision of Regional Network
Service 15.2 Eligibility to Receive Regional Network Service 16 Payment for
Regional Network Service 17 Procedure for Obtaining Regional Network Service
III. THROUGH OR OUT SERVICE; INTERNAL POINT-TO-POINT SERVICE 18 Through or Out
Service 18.1 Provision of Through or Out Service 18.2 Use of Through or Out
Service 19 Internal Point-to-Point Service 19.1 Provision of Internal
Point-to-Point Service 19.2 Use of Internal Point-to-Point Service 19.3 Use by a
Transmission Customer 20 Payment for Through or Out Service 21 Payment for
Internal Point-to-Point Service 22 Reservation of Capacity for Point-to-Point
Transmission Service IV. SERVICE DURING THE TRANSITION PERIOD; CONGESTION COSTS;
EXCEPTED TRANSACTIONS 23 Transition Arrangements 24 Congestion Costs and
Congestion Revenue 25 Excepted Transactions 25A Phase I Credit and Uplift Charge
With Respect to Excepted Transactions 25B Phase II Credit and Uplift Charge With
Respect to Certain Excepted Transactions V. POINT-TO-POINT TRANSMISSION SERVICE
Preamble 26 Scope of Application of Part V 27 Nature of Firm Point-To-Point
Transmission Service 27.1 Term 27.2 Reservation Priority 27.3 Use of Firm
Point-To-Point Transmission Service by the Participants That Own PTF 27.4
Service Agreements 27.5 Transmission Customer Obligations for Facility Additions
or Redispatch Costs 27.6 Curtailment of Firm Transmission Service 27.7
Classification of Firm Point-To-Point Transmission Service 27.8 Scheduling of
Firm Point-To-Point Transmission Service 28 Nature of Non-Firm Point-To-Point
Transmission Service 28.1 Term 28.2 Reservation Priority 28.3 Use of Non-Firm
Point-To-Point Transmission Service by the Transmission Provider 28.4 Service
Agreements 28.5 Classification of Non-Firm Point-To-Point Transmission Service
28.6 Scheduling of Non-Firm Point-To-Point Transmission Service 28.7 Curtailment
or Interruption of Service 29 Service Availability 29.1 General Conditions 29.2
Determination of Available Transmission Capability 29.3 Initiating Service in
the Absence of an Executed Service Agreement 29.4 Obligation to Provide
Transmission Service that Requires Expansion or Modification of the Transmission
System 29.5 Deferral of Service 29.6 Real Power Losses 29.7 Load Shedding 30
Transmission Customer Responsibilities 30.1 Conditions Required of Transmission
Customers 30.2 Transmission Customer Responsibility for Third-Party Arrangements
31 Procedures for Arranging Firm Point-To-Point Transmission Service 31.1
Application 31.2 Completed Application 31.3 Deposit 31.4 Notice of Deficient
Application 31.5 Response to a Completed Application 31.6 Execution of Service
Agreement 31.7 Extensions for Commencement of Service 32 Procedures for
Arranging Non-Firm Point-To-Point Transmission Service 32.1 Application 32.2
Completed Application 32.3 Reservation of Non-Firm Point-To-Point Transmission
Service 32.4 Determination of Available Transmission Capability 33 Additional
Study Procedures For Firm Point-To-Point Transmission Service Requests 33.1
Notice of Need for System Impact Study 33.2 System Impact Study Agreement and
Cost Reimbursement 33.3 System Impact Study Procedures 33.4 Facilities Study
Procedures 33.5 Facilities Study Modifications 33.6 Due Diligence in Completing
New Facilities 33.7 Partial Interim Service 33.8 Expedited Procedures for New
Facilities 34 Procedures if New Transmission Facilities for Firm Point-To-Point
Transmission Service Cannot be Completed 34.1 Delays in Construction of New
Facilities 34.2 Alternatives to the Original Facility Additions 34.3 Refund
Obligation for Unfinished Facility Additions 35 Provisions Relating to
Transmission Construction and Services on the Systems of Other Utilities 35.1
Responsibility for Third-Party System Additions 35.2 Coordination of Third-Party
System Additions 36 Changes in Service Specifications 36.1 Modifications on a
Non-Firm Basis 36.2 Modification on a Firm Basis 37 Sale, Assignment or Transfer
of Transmission Service 37.1 Procedures for Sale, Assignment or Transfer of
Service 37.2 Limitations on Assignment or Transfer of Service 37.3 Information
on Assignment or Transfer of Service 38 Metering and Power Factor Correction at
Receipt and Delivery Points(s) 38.1 Transmission Customer Obligations 38.2
NEPOOL Access to Metering Data 38.3 Power Factor 39 Compensation for New
Facilities and Redispatch Costs VI. REGIONAL NETWORK SERVICE (NETWORK
INTEGRATION TRANSMISSION SERVICE) 40 Nature of Regional Network Service 40.1
Scope of Service 40.2 Transmission Provider Responsibilities 40.3 Network
Integration Transmission Service 40.4 Secondary Service 40.5 Real Power Losses
40.6 Restrictions on Use of Service 41 Initiating Service 41.1 Condition
Precedent for Receiving Service 41.2 Application Procedures 41.3 Technical
Arrangements to be Completed Prior to Commencement of Service 41.4 Network
Customer Facilities 41.5 Filing of Service Agreement 42 Network Resources 42.1
Designation of Network Resources 42.2 Designation of New Network Resources 42.3
Termination of Network Resources 42.4 Network Customer Redispatch Obligation
42.5 Transmission Arrangements for Network Resources Not Physically
Interconnected With The NEPOOL Transmission System 42.6 Limitation on
Designation of Resources 42.7 Use of Interface Capacity by the Network Customer
43 Designation of Network Load 43.1 Network Load 43.2 New Network Loads
Connected With the NEPOOL Transmission System 43.3 Network Load Not Physically
Interconnected with the NEPOOL Transmission System 43.4 New Interconnection
Points 43.5 Changes in Service Requests 43.6 Annual Load and Resource
Information Updates 44 Additional Study Procedures For Network Integration
Transmission Service Requests 44.1 Notice of Need for System Impact Study 44.2
System Impact Study Agreement and Cost Reimbursement 44.3 System Impact Study
Procedures 44.4 Facilities Study Procedures 45 Load Shedding and Curtailments
45.1 Procedures 45.2 Transmission Constraints 45.3 Cost Responsibility for
Relieving Transmission Constraints 45.4 Curtailments of Scheduled Deliveries
45.5 Allocation of Curtailments 45.6 Load Shedding 45.7 System Reliability 46
Rates and Charges 46.1 Determination of Network Customer's Monthly Network Load
47 Operating Arrangements 47.1 Operation under The Network Operating Agreement
47.2 Network Operating Agreement 47.3 Network Operating Committee 48 Scope of
Application of Part VI to Participants VII. TRANSMISSION PLANNING, ADDITIONS AND
MODIFICATIONS 49 General 50 Interconnection Procedures and Requirements 50.1
Interconnection of Generating Unit Under the Minimum Interconnection Standard
50.2 Interconnection of Elective Transmission Upgrades 51 Regional Transmission
Planning and Expansion 51.1 General 51.2 Responsibilities of the Transmission
Expansion Advisory Committee, Transmission Planning Committee and System
Operator 51.3 NEPOOL Transmission Plan: Principles, Scope, and Contents 51.4
Procedures for Developing a NEPOOL Transmission Plan 51.5 Procedures for the
Conduct of Enhancement and Expansion Studies 51.6 Request for Proposals ("RFP")
Process For Upgrades 51.7 Obligations of Transmission Owners to Build 51.8
Merchant Transmission Facilities; Compliance 51.9 Alternative Remedies 52 "Quick
Fix" Measures SCHEDULE 1 Scheduling, System Control and Dispatch Service
SCHEDULE 2 Reactive Supply and Voltage Control from Generation Sources Service
SCHEDULE 3 Regulation and Frequency Response Service (Automatic Generation
Control) SCHEDULE 4 Energy Imbalance Service SCHEDULE 5 Operating Reserve -
10-Minute Spinning Reserve Service SCHEDULE 6 Operating Reserve - 10-Minute
Non-Spinning Reserve Service SCHEDULE 7 Operating Reserve - 30-Minute Reserve
Service SCHEDULE 8 Through or Out Service - The Pool PTF Rate SCHEDULE 9
Regional Network Service SCHEDULE 10 Internal Point-to-Point Service SCHEDULE 11
Generator Interconnection Related Upgrade Costs SCHEDULE 12 Reliability Upgrade,
Economic Upgrade and Elective Transmission Upgrade Costs SCHEDULE 13 Locational
Prices; Congestion Cost; Congestion Revenue; Marginal Loss Cost; Marginal Loss
Revenue
A. Calculation of Locational Prices
B. Congestion Cost
C. Congestion Revenue
D. Marginal Loss Cost and Marginal Loss Revenue
E. Additional Rules and Procedures
SCHEDULE 14 Financial Congestion Rights ("FCRs")
A. FCR Holder Status and Transfer of FCRs
B. FCR Designation and Simultaneous Feasibility
C. FCR Payments
D. FCR Settlements
E. Congestion Revenue Shortfalls or Surpluses
F. FCR Auctions
G. FCRs as Options
H. Additional Rules and Procedures
SCHEDULE 15 Auction Revenue Rights
A. First Stage of ARR Allocation
B. Second Stage of ARR Allocation
C. Third Stage of ARR Allocation
D. Fourth Stage of ARR Allocation
E. Payments to ARR Holders
F. Annual and Monthly ARR Adjustments
G. Incremental ARRs
H Additional Rules and Procedures
SCHEDULE 16 System Restoration and Planning Service from Generators ATTACHMENT A
Form of Service Agreement for Through or Out Service or Internal Point-To-Point
Service ATTACHMENT B Form Of Service Agreement For Regional Network Service
ATTACHMENT C Methodology To Assess Available Transmission Capability ATTACHMENT
D Methodology for Completing a System Impact Study ATTACHMENT E Local Networks
ATTACHMENT F Annual Transmission Revenue Requirements ATTACHMENT G: List of
Excepted Transaction Agreements ATTACHMENT G-1: List of Excepted Agreements
ATTACHMENT G-2: List of Certain Arrangements over External Ties ATTACHMENT H
Form of Network Operating Agreement ATTACHMENT I Form of System Impact Study
Agreement ATTACHMENT J Form of Facilities Study Agreement ATTACHMENT K 1997
Twelve CP Network Load Data NEPOOL 1997 12 CP Network Load ATTACHMENT L
Financial Assurance Policy for NEPOOL Members ATTACHMENT M Financial Assurance
Policy for NEPOOL Non-Participant Transmission Customers ATTACHMENT N New
England Power Pool Billing Policy IMPLEMENTATION RULE - SCHEDULE 1 Scheduling,
System Control and Dispatch Service IMPLEMENTATION RULE - SCHEDULE 2 Reactive
Supply and Voltage Control from Generation Sources Service IMPLEMENTATION RULE -
ATTACHMENT F Annual Transmission Revenue Requirements
I. COMMON SERVICE PROVISIONS
1 Definitions
Whenever used in this Tariff, in either the singular or the plural number, the
terms contained in this Section shall have the meanings set forth herein. If a
term includes language in brackets ([ ]), such language shall become effective
automatically on the CMS/MSS Effective Date. Certain definitions and language
within definitions are included in braces ({ }). Such definitions and language
are still subject to further modification or deletion and will not become
effective except pursuant to a further Commission order. To the extent
appropriate to reflect the understandings of this introductory text, future
composite copies of this Tariff may remove brackets ([ ]), braces ({ }) and text
included therein, and this explanatory introductory language, and may renumber
the definitions, without further specific amendment to or restatement of this
Tariff. Terms used in this Tariff that are not defined in this Tariff shall have
the meanings customarily attributed to such terms by the electric utility
industry in New England.
1.1 Administrative Costs: Those costs incurred in connection with the
review of Applications for transmission service and the carrying out of
System Impact Studies and Facilities Studies.
1.2 Agreement: The Restated New England Power Pool Agreement dated as of
September 1, 1971, as amended and restated from time to time, of which this
Tariff forms a part.
1.3 Ancillary Services: Those services that are necessary to support the
transmission of electric capacity and energy from resources to loads while
maintaining reliable operation of the NEPOOL Transmission System in accordance
with Good Utility Practice.
1.4 Annual Transmission Revenue Requirements: The annual revenue requirements of
a Participant's PTF or of all Participants' PTF for purposes of this Tariff
shall be the amount determined in accordance with Attachment F to this Tariff.
1.5 Application: A written request by an Eligible Customer for transmission
service pursuant to the provisions of this Tariff.
1.6 ARR: An Auction Revenue Right.
1.7 ARR Allocation: The allocation of ARRs described in Schedule 15.
1.8 Auction Revenue Right: The right to receive FCR Auction Revenues in
accordance with Schedule 15 and Section 49 of the Tariff.
1.9 Auction Revenue Right Holder: An entity which is the record holder of
an Auction Revenue Right in the register maintained by the System Operator.
1.10 Backyard Generation: Generation which interconnects directly with
distribution facilities dedicated solely to load not designated as Network Load.
Any distribution facilities which are shared with Network Load will not qualify.
1.11 Business Day: Any day other than a Saturday or Sunday or a national or
Massachusetts holiday.
1.12 CMS: The Congestion management system under the NEPOOL arrangements,
including Locational Prices for Energy and Financial Congestion Rights.
1.13 CMS/MSS Effective Date: The date on which the provisions of Section 14A of
the Agreement shall become fully effective and supersede the provisions of
Section 14 of the Agreement. The CMS/MSS Effective Date shall be a date fixed by
the Participants Committee which occurs after NEPOOL System Rules and computer
programs to fully implement Section 14A of the Agreement and Schedules 13, 14
and 15 of the Tariff are in place and at least thirty (30) days have elapsed
since the Participants Committee has provided notice to the Commission of the
proposed CMS/MSS Effective Date.
1.14 Commission: The Federal Energy Regulatory Commission.
1.15 Completed Application: An Application that satisfies all of the
information and other requirements of this Tariff, including any required
deposit.
1.16 Compliance Effective Date: October 1, 1998.
1.17 Congestion: A condition of the NEPOOL Transmission System in which
transmission limitations prevent unconstrained regional economic dispatch of the
power system. Following the CMS/MSS Effective Date, Congestion is the condition
that results in the Congestion Component of the Locational Price at one Location
being different from the Congestion Component of the Locational Price at another
Location during any given hour of the Dispatch Day in the Day-Ahead Market and
Real-Time Market.
1.18 Congestion Component: The component of the Nodal Price that reflects the
marginal cost of Congestion at a given Node or External Node relative to the
Reference Node. When used in connection with Zonal Price and Hub Price, the term
Congestion Component refers to the Congestion Components of the Nodal Prices
that comprise the Zonal Price and Hub Price averaged or weighted in the same way
that Nodal Prices are averaged or weighted to determine the Zonal Price and Hub
Price, respectively.
1.19 Congestion Cost: The cost of Congestion as defined in Section 14.14 of the
Agreement and Section 24 of the Tariff for services until the CMS/MSS Effective
Date. On and after the CMS/MSS Effective Date, Congestion Cost is the cost of
Congestion as measured by the difference between the Congestion Components of
the Locational Prices at different Locations and/or Reliability Regions on the
NEPOOL Transmission System.
1.20 Congestion Paying Entity: For the purpose of the allocation of FCR Auction
Revenues to ARR Holders as provided for in Schedule 15, a Participant, other
than a Transmission Customer, that is responsible for paying for both (i) the
Congestion Cost associated with supplying Energy to serve load, and (ii) the RMR
Charge for RMR Uplift (as defined in Section 14A.19 of the Agreement) associated
with serving load. The term Congestion Paying Entity shall be deemed to include,
but not be limited to, the Load Asset Contract purchaser.
1.21 Congestion Revenue: For each hour is the surplus revenue, if any, for each
hour after netting the revenues paid and collected for the Congestion Components
of Locational Price for all Energy transactions on the NEPOOL Transmission
System, including Energy deliveries by Non-Participant Transmission Customers
taking service under the Tariff, as settled in accordance with the Market Rules.
Congestion Revenue is calculated for each hour of the Dispatch Day in the
Day-Ahead Market and Real-Time Market as provided in Section E of Schedule 14 of
the Tariff and the applicable Market Rules.
1.22 Congestion Revenue Fund: The fund of Congestion Revenue administered by the
System Operator in accordance with Section 14A.17 of the Agreement, Schedules 13
and 14 of the Tariff, and the applicable Market Rules.
1.23 Congestion Revenue Shortfall: The amount, if any, by which Congestion
Revenues collected by the System Operator in a month are less than the sum of
the Target FCR Payments for that month. A Congestion Revenue Shortfall is
managed in accordance with Schedule 14.
1.24 Congestion Revenue Surplus: The amount, if any, by which Congestion
Revenues collected by the System Operator in a month exceed the sum of the
Target FCR Payments for that month. A Congestion Revenue Surplus is managed in
accordance with Schedule 14.
1.25 Control Area: An electric power system or combination of electric
power systems to which a common automatic generation control scheme is
applied in order to:
(1) match, at all times, the power output of the generators within the electric
power system(s) and capacity and energy purchased from entities outside the
electric power system(s), with the load within the electric power system(s);
(2) maintain scheduled interchange with other Control Areas, within the
limits of Good Utility Practice;
(3) maintain the frequency of the electric power system(s) within reasonable
limits in accordance with Good Utility Practice and the criteria of the
applicable regional reliability council or the North American Electric
Reliability Council; and
(4) provide sufficient generating capacity to maintain operating reserves in
accordance with Good Utility Practice.
1.26 Curtailment: A reduction in firm or non-firm transmission service in
response to a transmission capacity shortage as a result of system reliability
conditions.
1.27 Day-Ahead: The calendar day immediately preceding a Dispatch Day for which
Participants submit Demand Bids and Supply Offers in accordance with applicable
NEPOOL System Rules and the System Operator schedules Resources for Energy,
Operating Reserve, 4-Hour Reserve and AGC (as defined in the Agreement) in
accordance with applicable NEPOOL System Rules.
1.28 Day-Ahead Market: The market provided for in Section 14A of the Agreement
and conducted in the calendar day immediately preceding a Dispatch Day in which
Energy, Operating Reserve, 4-Hour Reserve and AGC (as defined in the Agreement)
are scheduled for a Dispatch Day, based on the Day-Ahead Demand Bids and Supply
Offers and applicable NEPOOL System Rules.
1.29 Delivering Party: The entity supplying capacity and/or energy to be
transmitted at Point(s) of Receipt under this Tariff.
1.30 Demand Bid: A proposal by a Participant to receive and pay for Energy, at a
specified Location and at a specified Demand Bid Price, that is submitted to the
System Operator pursuant to the Agreement and applicable Market Rules, and
includes information with respect to the quantity to be received and paid for
and other matters complying with the Market Rules.
1.31 Demand Bid Price: The price specified by a Participant to the System
Operator in a Demand Bid for Energy at a specified Location.
1.32 Designated Agent: Any entity that performs actions or functions
required under the Tariff on behalf of NEPOOL, an Eligible Customer, or a
Transmission Customer.
1.33 Direct Assignment Facilities: Facilities or portions of facilities that are
Non-PTF and are constructed for the sole use/benefit of a particular
Transmission Customer requesting service under this Tariff or a Generator Owner
requesting an interconnection. Direct Assignment Facilities shall be specified
in a separate agreement with the Transmission Provider whose transmission system
is to be modified to include and/or interconnect with said Facilities, shall be
subject to applicable Commission requirements and shall be paid for by the
Transmission Customer or a Generator Owner or in accordance with the separate
agreement and not under this Tariff.
1.34 Direct Interconnection Transmission Costs: Has the meaning specified
in Section 2 of Schedule 11 of the Tariff.
1.35 Dispatch Day: The period beginning at the minute ending 0001 and
ending at 2400 each day.
1.36 Distribution Company: Has the meaning specified in Section (A)(2) of
Schedule 13.
1.37 Distribution Company Load Zone: Has the meaning specified in Section
(A)(2) of Schedule 13.
1.38 Economic Upgrade: Those additions and upgrades that are not related to the
interconnection of a generator, and are designed to reduce or eliminate
Congestion Cost, where the net present values of the reduction in, or
elimination of, Congestion Cost exceeds the net present value of the cost of the
transmission addition or upgrade.
1.39 Elective Transmission Upgrade: An addition to or modification of the NEPOOL
Transmission System that is not: (i) a Generator Interconnection Related
Upgrade; (ii) a Reliability Upgrade (including a NEMA Upgrade, as appropriate);
(iii) an Economic Upgrade (including a NEMA Upgrade, as appropriate); (iv) a
Quick Fix Upgrade; or (v) initially proposed in an Elective Transmission Upgrade
Application filed with the System Operator in accordance with Section 50.2 on a
date after the addition or modification already has been otherwise identified in
the current NEPOOL Transmission Plan (other than as an Elective Transmission
Upgrade) in publication as of the date of that application. An Elective
Transmission Upgrade may increase transfer capability of the NEPOOL Transmission
System, may increase the reliability or stability of the NEPOOL Transmission
System above the requirements and criteria established by NERC, NPCC or the
NEPOOL Reliability Committee, or may reduce Congestion Costs into Load Zones or
at Nodes into or within the NEPOOL Control Area.
1.40 Eligible Customer: (i) Any Participant that is engaged, or proposes to
engage, in the wholesale or retail electric power business is an Eligible
Customer under the Tariff. (ii) Any electric utility (including any power
marketer), Federal power marketing agency, or any other entity generating
electric energy for sale or for resale is an Eligible Customer under the Tariff.
Electric energy sold or produced by such entity may be electric energy produced
in the United States, Canada or Mexico. However, with respect to transmission
service that the Commission is prohibited from ordering by Section 212(h) of the
Federal Power Act, such entity is eligible only if the service is provided
pursuant to a state requirement that the Transmission Provider with which that
entity is directly interconnected offer the unbundled transmission service, or
pursuant to a voluntary offer of such service by the Transmission Provider with
which that entity is directly interconnected. (iii) Any end user taking or
eligible to take unbundled transmission service pursuant to a state requirement
that the Transmission Provider with which that end user is directly
interconnected offer the transmission service, or pursuant to a voluntary offer
of such service by the Transmission Provider with which that end user is
directly interconnected, is an Eligible Customer under the Tariff.
1.41 Energy: Is electrical energy measured in kilowatthours or
megawatthours.
1.42 Energy Imbalance Service: This service is the form of Ancillary
Service described in Schedule 4.
1.43 Entitlement: An Installed Capability Entitlement, Energy Entitlement,
Operating Reserve Entitlement[, 4-Hour Reserve Entitlement], or AGC Entitlement,
in each case as defined in the Agreement. When used in the plural form, it may
be any or all such Entitlements or combinations thereof, as the context
requires.
1.44 Excepted Transaction: A transaction specified in Section 25 for the
applicable period specified in that Section, or in Sections 25A and 25B.
1.45 External Node: A bus or buses used for establishing a Locational Price
for Energy received by Participants from, or delivered by Participants to, a
neighboring Control Area.
1.46 Facilities Study: An engineering study conducted pursuant to the Agreement
or this Tariff by the System Operator and/or one or more affected Participants
to determine the required modifications to the NEPOOL Transmission System,
including the cost and scheduled completion date for such modifications, that
will be required to provide a requested transmission service or interconnection.
1.47 FCR: A Financial Congestion Right.
1.48 FCR Auction: The periodic auction of FCRs conducted by the System Operator
or another authorized agent of the NEPOOL Participants in accordance with
Schedule 14.
1.49: The revenue collected from the sale of FCRs in FCR Auctions. FCR Auction
Revenue is payable to FCR Holders who submit their FCRs for sale in the FCR
Auction in accordance with Schedule 14 and to ARR Holders in accordance with
Schedule 15.
1.50 FCR Auction Revenue Fund: The fund containing the FCR Auction Revenue.
1.51 FCR Holder: An entity that acquires an FCR through the FCR Auction or a
subsequent bilateral arrangement pursuant to Schedule 14 of the Tariff and
registers with the System Operator as the holder of the FCR in accordance with
Schedule 14 of the Tariff and applicable NEPOOL System Rules.
1.52 FCR Payment: The payment made either from the Congestion Revenue Fund to an
FCR Holder or to the Congestion Revenue Fund by an FCR Holder in accordance with
Schedule 14 of the Tariff and applicable NEPOOL System Rules.
1.53 Financial Congestion Right: A financial instrument that evidences the
rights and obligations specified in Schedule 14 of the Tariff.
1.54 Firm Contract: Any contract, other than a Unit Contract, for the purchase
of Installed Capability, Energy [at a Location], Operating Reserves[, 4-Hour
Reserves], and/or AGC (as defined in the Agreement) pursuant to which the
purchaser's right to receive such Installed Capability, Energy, Operating
Reserves[, 4-Hour Reserves] and/or AGC is subject only to the supplier's
inability to make deliveries thereunder as the result of events beyond the
supplier's reasonable control.
1.55 Firm Point-To-Point Transmission Service: Point-To-Point Transmission
Service which is reserved and/or scheduled between specified Points of Receipt
and Delivery in accordance with the applicable procedure specified in Part V of
this Tariff.
1.56 Firm Transmission Service: Service for Native Load Customers, firm
Regional Network Service (Network Integration Transmission Service), service
for Excepted Transactions, Firm Internal Point-To-Point Transmission Service,
or Firm Through or Out Service.
1.57 Generator Interconnection Related Upgrade: An addition to or modification
of the NEPOOL Transmission System pursuant to Section 50.1 to effect the
interconnection of a new generating unit or an existing generating unit whose
capacity is being materially changed and increased, whether or not the
interconnection is being effected to meet the Minimum Interconnection Standard.
As to Category A Projects (as defined in Schedule 11), a Generator
Interconnection Related Upgrade also includes an upgrade beyond that required to
satisfy the Minimum Interconnection Standard for which the Generator Owner has
committed to pay prior to October 29, 1998.
1.58 Generator Owner: Any Participant or Non-Participant that owns, in whole or
part, a generating unit whether located within or outside the NEPOOL Control
Area. As used in Section 50 and Schedules 11 and 12 of this Tariff, Generator
Owner also includes any Participant or Non-Participant that proposes to site a
new generating unit at a site owned or controlled by it, or which it has the
right to acquire or control, located in the NEPOOL Control Area.
1.59 Good Utility Practice: Any of the practices, methods and acts engaged in or
approved by a significant portion of the electric utility industry during the
relevant time period, or any of the practices, methods and acts which, in the
exercise of reasonable judgment in light of the facts known at the time the
decision was made, could have been expected to accomplish the desired result at
a reasonable cost consistent with good business practices, reliability, safety
and expedition. Good Utility Practice is not intended to be limited to the
optimum practice, method, or act to the exclusion of all others, but rather
includes all acceptable practices, methods, or acts generally accepted in the
region.
1.60 Hub: A specific set of pre-defined Nodes, approved by the Participants
Committee, for which a Locational Price will be calculated and which can be used
to establish a reference price for Energy purchases and the transfer of Energy
Settlement Obligations and for the designation of FCRs in accordance with
Schedule 14.
1.61 Hub Price: In each hour of the Dispatch Day in the Day-Ahead Market and the
Real-Time Market is the price used for Settlement Obligations for Energy which
are treated as being transferred at a Hub in the hour. Hub Prices are calculated
in accordance with Section 14A.12 of the Agreement and Schedule 13 of the
Tariff.
1.62 HQ Interconnection: The United States segment of the transmission
interconnection which connects the systems of Hydro-Quebec and the Participants.
"Phase I" is the United States portion of the 450 kV HVDC transmission line from
a terminal at the Des Cantons Substation on the Hydro- Quebec system near
Sherbrooke, Quebec to a terminal having an approximate rating of 690 MW at a
substation at the Comerford Generating Station on the Connecticut River. "Phase
II" is the United States portion of the facilities required to increase to
approximately 2000 MW the transfer capacity of the HQ Interconnection, including
an extension of the HVDC transmission line from the terminus of Phase I at the
Comerford Station through New Hampshire to a terminal at the Sandy Pond
Substation in Massachusetts. The HQ Interconnection does not include any PTF
facilities installed or modified to effect reinforcements of the New England AC
transmission system required in connection with the HVDC transmission line and
terminals.
1.63 HQ Phase II Firm Energy Contract: The Firm Energy Contract dated as of
October 14, 1985 between Hydro-Quebec and certain of the Participants, as it may
be amended from time to time.
1.64 Import Transaction: An energy delivery originating outside the NEPOOL
Control Area that uses the PTF to deliver energy to Network Load within the
NEPOOL Control Area, except for a delivery that uses a direct interconnection
between the NEPOOL Control Area and the Hydro-Quebec transmission system that
existed as of January 1, 2000.
1.65 Interchange Transactions: Are transactions deemed to be effected under
Section 14 of the Agreement prior to the CMS/MSS Effective Date, and under
Section 14A on and after the CMS/MSS Effective Date.
1.66 Interest: Interest calculated in the manner specified in Section 8.3.
1.67 Internal Point-to-Point Service:
(1) Until the CMS/MSS Effective Date, Point-to-Point Transmission Service with
respect to a transaction where the Point of Receipt is at the boundary of or
within the NEPOOL Transmission System and the Point of Delivery is within the
NEPOOL Transmission System.
(2) On and after the CMS/MSS Effective Date, Internal Point-to-Point Service is
Point-to-Point Transmission Service with respect to a transaction where the
Point of Receipt is within the NEPOOL Transmission System and the Point of
Delivery is within the NEPOOL Transmission System.
1.68 Internal Point-to-Point Service Rate: The rate applicable to Internal
Point-to-Point Service, which shall be equal for each delivery to the
Participant RNS Rate per Kilowatt for the current Year for the Participant which
owns the Local Network from which the Customer's load is served.
1.69 Interruption: A reduction in non-firm transmission service due to
economic reasons pursuant to Section 28.7.
1.70 ISO: The Independent System Operator which is responsible for the continued
operation of the NEPOOL Control Area from the NEPOOL control center and the
administration of this Tariff, subject to regulation by the Commission.
1.71 Load Asset Contract: A transaction for the transfer of responsibility for
Electrical Load (and may include Electrical Load qualifying as Dispatchable
Load), Installed Capability, or the rights to compensation for Operating Reserve
to the extent the transfer relates to Dispatchable Load, the terms of which
shall conform to the requirements of applicable Market Rules.
1.72 Load Ratio Share: Ratio of a Transmission Customer's most recently reported
Monthly Network Load in the case of Network Customers and including where
applicable Point-to-Point Customers' Reserved Capacity, to the total load of
Network Customers and Point-to-Point customers, computed in accordance with Part
VI of the Tariff.
1.73 Load Shedding: The systematic reduction of system demand by temporarily
decreasing load in response to transmission system or area capacity shortages,
system instability, or for voltage control considerations under Part VI of the
Tariff.
1.74 Load Zone: A Reliability Region, except as otherwise provided in
Section 14A.12(b) of the Agreement and Schedule 13 of the Tariff.
1.75 Local Network: The transmission facilities constituting a local network
identified on Attachment E, and any other local network or change in the
designation of a Local Network as a Local Network which the Management Committee
may designate or approve from time to time. The Management Committee may not
unreasonably withhold approval of a request by a Participant that it effect such
a change or designation.
1.76 Local Network Service: Local Network Service is the service provided, under
a separate tariff or contract, by a Participant that is a Transmission Provider
to another Participant or other entity connected to the Transmission Provider's
Local Network to permit the other Participant or entity to efficiently and
economically utilize its resources to serve its load.
1.77 Local Point-To-Point Service: Local Point-To-Point service is Point-
to-Point Transmission Service provided, under a separate tariff or contract, by
a Participant that is a Transmission Provider over Non-PTF or distribution
facilities to permit deliveries to or from an interconnection point on the
NEPOOL Transmission System.
1.78 Location: A Node, External Node, Load Zone, or Hub.
1.79 Locational Price: The price of Energy at a Location or Reliability Region,
calculated in accordance with Section 14A.12 of the Agreement and Schedule 13 of
the Tariff. The Locational Price for a Node is the Nodal Price at that Node; the
Locational Price for an External Node is the Nodal Price at that External Node;
the Locational Price for a Load Zone or Reliability Region is the Zonal Price
for that Load Zone or Reliability Region, respectively; and the Locational Price
for a Hub is the Hub Price for that Hub.
1.80 Long-Term Firm Service: Firm Transmission Service with a term of one
year or more.
1.81 Marginal Loss: The additional Energy required to overcome transmission
losses or the decrease in Energy consumed through losses on the NEPOOL
Transmission System associated with serving a small increment of demand at a
Node or External Node. The cost of Marginal Losses at each Location, relative to
the cost of Marginal Losses at the Reference Node, is reflected in the Marginal
Loss Component of the Locational Price at that Location.
1.82 Marginal Loss Component: The component of the Nodal Price at a given Node
or External Node that reflects the Marginal Loss at that Node or External Node.
When used in connection with Hub Price or Zonal Price, the term Marginal Loss
Component refers to the Marginal Loss Components of the Nodal Prices that
comprise the Hub Price or Zonal Price, which Marginal Loss Components are
averaged or weighted in the same way that Nodal Prices are averaged or weighted
to determine the Hub Price and Zonal Price, respectively.
1.83 Marginal Loss Revenue: For each hour is the surplus revenue, if any, after
netting the revenues paid and collected for the Marginal Loss Components of
Locational Prices for all Energy transactions on the NEPOOL Transmission System,
including Energy deliveries by Non-Participant Transmission Customers taking
service under this Tariff, as settled in accordance with the Market Rules.
1.84 Marginal Loss Revenue Fund: The fund of Marginal Loss Revenue administered
by the System Operator in accordance with Section 14A.16 of the Agreement,
Schedule 13 of the Tariff, and the applicable Market Rules.
1.85 Market Rules: Are the system rules and operating procedures adopted
pursuant to the System Operator Agreement in connection with the
administration of the NEPOOL Market.
1.85A Merchant Transmission Facility: Has the meaning specified in Section
51.8.
1.86 Minimum Interconnection Standard: Has the meaning specified in Section
50.1.
1.87 Monthly Network Load: Has the meaning specified in Section 46.1.
1.88 Monthly Peak: Has the meaning specified in Section 46.1.
1.89 Monthly Peak Load: For purposes of Schedule 15, the Monthly Peak Load of
the Transmission Customer is the Transmission Customer's Monthly Peak less any
portion of such Monthly Peak served by a Congestion Paying Entity. For purposes
of Schedule 15, the Monthly Peak Load of a Congestion Paying Entity includes the
portion of any Transmission Customer's Monthly Peak served by the Congestion
Paying Entity.
1.90 Native Load Customers: The wholesale and retail power customers of a
Participant or other entity which is a Transmission Provider on whose behalf the
Participant or other entity, by statute, franchise, regulatory requirement, or
contract, has undertaken an obligation to construct and operate its system to
meet the reliable electric needs of such customers.
1.91 NEMA: The Northeast Massachusetts Reliability Region.
1.92 NEMA ARRs: The ARRs allocated in accordance with Schedule 15 to certain
entities serving load in NEMA.
1.93 NEMA Contract: A contract described in Section C of Schedule 15 and listed
in Attachment 1 to Schedule 15.
1.94 NEMA LSE: A NEMA LSE is a Transmission Customer or Congestion Paying
Entity that serves load within NEMA.
1.95 NEMA or "Northeast Massachusetts" Upgrade: Is an addition to or
modification of the NEPOOL Transmission System into or within the Northeast
Massachusetts Reliability Region that is not, as of December 31, 1999, the
subject of a System Impact Study or application filed pursuant to Section 18.4
of the Restated NEPOOL Agreement; that is not related to generation
interconnections; and that will be completed and placed in service by June 30,
2004. Such upgrades include, but are not limited to, new transmission facilities
and related equipment and/or modifications to existing transmission facilities
and related equipment.
1.96 NEPOOL: The New England Power Pool, the power pool created under and
governed by the Agreement, and the entities collectively participating in the
New England Power Pool.
1.97 NEPOOL Control Area: The Control Area (as defined in Section 1.25)
for NEPOOL.
1.98 NEPOOL System Rules: The Market Rules, the NEPOOL Information Policy, the
Administrative Procedures, the Reliability Standards and any other system rules,
procedures or criteria for the operation of the NEPOOL System and administration
of the NEPOOL Market, the NEPOOL Agreement and the NEPOOL Tariff.
1.99 NEPOOL Transmission Plan: A five-year plan for the expansion or
modification of the NEPOOL Transmission System which has been developed pursuant
to Section 51.
1.100 NEPOOL Transmission System: The PTF transmission facilities.
1.101 NERC: The North American Electric Reliability Council.
1.102 Network Customer: A Participant or Non-Participant receiving transmission
service pursuant to the terms of the Network Integration Transmission Service
under Part II and Part VI of the Tariff.
1.103 Network Integration Transmission Service: Regional Network Service, which
may be used with respect to Network Resources or Network Load not physically
interconnected with the NEPOOL Transmission System.
1.104 Network Load: The load that a Network Customer designates for Network
Integration Transmission Service under Part II and Part VI of the Tariff. The
Network Customer's Network Load shall include all load designated by the Network
Customer (including losses) and shall not be credited or reduced for any
behind-the-meter generation. A Network Customer may elect to designate less than
its total load as Network Load but may not designate only part of the load at a
discrete Point of Delivery. Where an Eligible Customer has elected not to
designate a particular load at discrete Points of Delivery as Network Load, the
Eligible Customer is responsible for making separate arrangements under Part III
and Part V of the Tariff for any Point-to-Point Transmission Service that may be
necessary for such non-designated load.
1.105 Network Operating Agreement: An executed agreement in the form of
Attachment H, or any other form that is mutually agreed to, that contains the
terms and conditions under which the Network Customer shall operate its
facilities and the technical and operational matters associated with the
implementation of Network Integration Transmission Service under Part II and
Part VI of this Tariff. The Agreement and the rules adopted thereunder shall
constitute the Network Operating Agreement for Participants.
1.106 Network Operating Committee: A group made up of representatives from the
Network Customer(s) and the System Operator established to coordinate operating
criteria and other technical considerations required for implementation of
Network Integration Transmission Service under Part II and Part VI of this
Tariff. The Network Operating Committee for Network Customers that are
Participants shall be the NEPOOL Regional Transmission Operations Committee and
the NEPOOL Regional Transmission Planning Committee, meeting jointly in a
meeting designated as the annual Network Operating Committee meeting. Notice of
each meeting of the Committee pursuant to Section 47.3 shall be given to each
Non-Participant receiving Regional Network Service under this Tariff and the
Non-Participant shall have the right to be represented at each of such meetings.
1.107 Network Resource: (a) With respect to Participants, (i) any generating
resource located in the NEPOOL Control Area which has been placed in service
prior to the Compliance Effective Date (including a unit that has lost its
capacity value when its capacity value is restored and a deactivated unit which
may be reactivated without satisfying the requirements of Section 49 of this
Tariff in accordance with the provisions thereof) until retired; (ii) any
generating resource located in the NEPOOL Control Area which is placed in
service after the Compliance Effective Date until retired, provided that (1) the
Generator Owner has complied with the requirements of Section 49 of the Tariff,
and (2) the output of the unit shall be limited in accordance with Section 49,
if required; and (iii) any generating resource or combination of resources
(including bilateral purchases) located outside the NEPOOL Control Area for so
long as any Participant has an Entitlement in the resource or resources which is
being delivered to it in the NEPOOL Control Area to serve Network Load located
in the NEPOOL Control Area or other designated Network Loads contemplated by
Section 43.3 of this Tariff taking Regional Network Service. (b) With respect to
Non-Participant Network Customers, any generating resource owned, purchased or
leased by the Network Customer which it designates to serve Network Load.
1.108 Network Upgrades: Modifications or additions to transmission-related
facilities that are integrated with and support the overall NEPOOL Transmission
System for the general benefit of all users of such Transmission System.
1.109 Nodal Price: In each hour of the Dispatch Day in the Day-Ahead Market and
Real-Time Market is the price for Energy received or furnished at a Node or
External Node in the hour, as calculated in accordance with Section 14A.12 of
the Agreement and Schedule 13 of the Tariff.
1.110 Node: A point on the NEPOOL Transmission System where Energy is received
or furnished, and for which Nodal Prices are calculated.
1.111 Non-Firm Point-To-Point Transmission Service: Point-To-Point Transmission
Service under this Tariff that is subject to Curtailment or Interruption under
the circumstances specified in Section 28.7 of this Tariff.
1.112 Non-Participant: Any entity that is not a Participant.
1.113 Non-PTF: The transmission facilities owned by the Participants that
do not constitute PTF.
1.114 Northeast Massachusetts Upgrade: Has the meaning specified in
Schedule 12.
1.115 NPCC: The Northeast Power Coordinating Council.
1.116 Open Access Same-Time Information System (OASIS): The NEPOOL
information system and standards of conduct responding to requirements of 18
C.F.R. 37 of the Commission's regulations and all additional requirements
implemented by subsequent Commission orders dealing with OASIS.
1.117 Operating Reserve - 10-Minute Non-Spinning Reserve Service: This service
is the form of Ancillary Service described in Schedule 6.
1.118 Operating Reserve - 10-Minute Spinning Reserve Service: This
service is the form of Ancillary Service described in Schedule 5.
1.119 Operating Reserve - 30-Minute Reserve Service: This service is the
form of Ancillary Service described in Schedule 7.
1.120 Participant: A participant in NEPOOL under the Agreement.
1.121 Participant RNS Rate: The rate applicable to Regional Network Service to
effect a delivery to load in a particular Local Network, as determined in
accordance with Schedule 9 to this Tariff.
1.122 Participants Committee: The committee whose responsibilities are specified
in Section 7 of the Agreement. To the extent applicable, references in the
Tariff to the Participants Committee shall include the prior Management
Committee or Executive Committee as the predecessor of the Participants
Committee if not inconsistent with Section 17A of the Agreement.
1.123 Point(s) of Delivery: Point(s) where capacity and/or energy transmitted by
the Participants will be made available to the Receiving Party under this
Tariff. Until the CMS/MSS Effective Date, but not thereafter, the Point of
Delivery may be designated as the NEPOOL power exchange. The Point(s) of
Delivery shall be specified in the Service Agreement, if applicable, for
Long-Term Firm Point-to-Point Transmission Service.
1.124 Point(s) of Receipt: Point(s) of interconnection where capacity and/or
energy to be transmitted by the Participants will be made available to NEPOOL by
the Delivering Party under this Tariff. Until the CMS/MSS Effective Date, but
not thereafter, the Point of Receipt may be designated as the NEPOOL power
exchange in circumstances where the System Operator does not require greater
specificity. The Point(s) of Receipt shall be specified in the Service
Agreement, if applicable, for Long-Term Firm Point-To-Point Transmission
Service.
1.125 Point-To-Point Transmission Service: The transmission of capacity and/or
energy on either a firm or non-firm basis from the Point(s) of Receipt to the
Point(s) of Delivery under this Tariff. NEPOOL Point-to-Point Transmission
Service includes both Internal Point-to-Point Service and Through or Out
Service.
1.126 Pool-Planned Unit: One of the following units: New Haven Harbor Unit 1
(Coke Works), Mystic Unit 7, Canal Unit 2, Potter Unit 2, Wyman Unit 4, Stony
Brook Units 1, 1A, 1B, 1C, 2A and 2B, Millstone Unit 3, Seabrook Unit 1 and
Waters River Unit 2 (to the extent of 7 megawatts of its Summer Capability and
12 megawatts of its Winter Capability).
1.127 Pool PTF Rate: The transmission rate determined in accordance with
Schedule 8 to this Tariff.
1.128 Pool RNS Rate: The transmission rate determined in accordance with
paragraph (2) of Schedule 9 to this Tariff.
1.129 Pool-Supported PTF: (i) PTF first placed in service prior to January 1,
2000; (ii) Generator Interconnection Related Upgrades with respect to Category A
and B Projects (as defined in Schedule 11), but only to the extent not paid for
by the interconnecting Generator Owner; (iii) Quick Fix Upgrades, in accordance
with Section 52; and (iv) other PTF upgrades, but only to the extent the costs
therefor are determined to be Pool-Supported PTF in accordance with Schedule 12.
1.130 Power Purchaser: The entity that is purchasing the capacity and/or
energy to be transmitted under the Tariff.
1.131 Prior NEPOOL Agreement: The NEPOOL Agreement as in effect on
December 1, 1996.
1.132 PTF or Pool Transmission Facilities: (i) The transmission facilities owned
by the Participants and their Related Persons which constitute PTF pursuant to
the Agreement, and (ii) the static VAR compensator installed at Chester, Maine
at the request of the Participants.
1.133 Pre-1997 PTF Rate: The transmission rate of a Participant determined in
accordance with paragraph (5) of Schedule 9 to this Tariff.
1.134 Publicly Owned Entity: An Entity which is either a municipality or an
agency thereof, or a body politic and public corporation created under the
authority of one of the New England states, authorized to own, lease and operate
electric generation, transmission or distribution facilities, or an electric
cooperative, or an organization of any such entities.
1.135 Quick Fix Upgrade: Has the meaning specified in Section 52.
1.136 Reactive Supply and Voltage Control From Generation Sources
Service: This service is the form of Ancillary Service described in Schedule
2.
1.137 Real-Time: A current period of a Dispatch Day for which the System
Operator dispatches Resources for Energy and AGC, designates Resources for AGC
and Operating Reserve and, if necessary, activates 4-Hour Reserves.
1.138 Real-Time Market: The market provided for in Section 14A of the Agreement
in which obligations and prices with respect to Energy, Operating Reserve,
4-Hour Reserve and AGC are determined from the actual dispatch and designations
by the System Operator during a Dispatch Day, based on applicable Demand Bids
and Supply Offers and NEPOOL System Rules.
1.139 Receiving Party: The entity receiving the capacity and/or energy
transmitted to Point(s) of Delivery under this Tariff.
1.140 Reference Node: The Node identified by the System Operator in accordance
with the NEPOOL System Rules relative to which all mathematical quantities
pertaining to physical operation, including Shift Factors and Withdrawal
Factors, shall be calculated with respect to the dispatch of the system and the
derivation of Locational Prices.
1.141 Regional Network Service: The transmission service described in
Part II and Part VI of this Tariff.
1.142 Regulation and Frequency Response Service: This service is the
form of Ancillary Service described in Schedule 3.
1.143 Reliability Region: As of March 31, 2000, any one of the regions
identified in Attachment C to the Agreement. Subsequent to March 31, 2000, the
System Operator, in a filing with the Commission and following consultation with
the NEPOOL Reliability Committee, may reconfigure Reliability Regions and add or
subtract Reliability Regions as necessary over time to reflect changes to the
grid or changes in patterns of usage and intra-zonal Congestion. Reliability
Regions reflect the operating characteristics of, and the major transmission
constraints on, the NEPOOL Transmission System.
1.144 Reliability Upgrade: Those additions and upgrades not required by the
interconnection of a generator that are nonetheless necessary to ensure the
continued reliability of the NEPOOL system, taking into account load growth and
known resource changes, and include those upgrades necessary to provide
acceptable stability response, short circuit capability and system voltage
levels, and those facilities required to provide adequate thermal capability and
local voltage levels that cannot otherwise be achieved with reasonable
assumptions for certain amounts of generation being unavailable (due to
maintenance or forced outages) for purposes of long-term planning studies. Good
Utility Practice, applicable reliability principles, guidelines, criteria,
rules, procedures and standards of NERC and NPCC and any of their successors,
applicable publicly available local reliability criteria, and the NEPOOL System
Rules, as they may be amended from time to time, will be used to define the
system facilities required to maintain reliability in evaluating proposed
Reliability Upgrades.
1.145 Reserved Capacity: The maximum amount of capacity and energy that is
committed to the Transmission Customer for transmission over the NEPOOL
Transmission System between the Point(s) of Receipt and the Point(s) of Delivery
under Part V of this Tariff. Reserved Capacity shall be expressed in terms of
whole kilowatts on a sixty-minute interval (commencing on the clock hour) basis.
1.146 Scheduling, System Control and Dispatch Service: This service is
the form of Ancillary Service described in Schedule 1.
1.147 Second Effective Date: May 1, 1999.
1.148 Service Agreement: The initial agreement and any amendments or
supplements thereto entered into by the Transmission Customer and the System
Operator for service under this Tariff.
1.149 Service Commencement Date: The date service is to begin pursuant to the
terms of an executed Service Agreement, or the date service begins in accordance
with Section 29.3 or Section 41.1 under this Tariff, or in the case of Regional
Network Service which is not required to be furnished under a Service Agreement
pursuant to Section 48 of this Tariff, the date service actually commences.
1.150 Settlement Obligation Prior to the CMS/MSS Effective Date, an obligation
as defined in Section 14.1(a) of the Agreement for Energy, Section 14.1(b) of
the Agreement for Operating Reserve and Section 14.1(c) of the Agreement for
AGC, and all applicable Market Rules and, on and after the CMS/MSS Effective
Date, an obligation as defined in Section 14A.1(b) of the Agreement for Energy,
Section 14A.1(c) of the Agreement for Operating Reserve, Section 14A.1(d) of the
Agreement for 4-Hour Reserve and Section 14A.1(e) of the Agreement for AGC, and
all applicable Market Rules.
1.151 Shift Factor: The factor which relates to the change in power flow over
the PTF that results from an increment of generation at a given Node or External
Node and a corresponding increment of load at the Reference Node, relative to
the size of the increment of generation. Shift Factors are used to calculate
Locational Prices in accordance with Section 14A.12 of the Agreement and
Schedule 13 of the Tariff.
1.152 Short-Term Firm Service: Firm Transmission Service with a term of less
than one year.
1.153 Standard Offer Obligation: Has the meaning specified in Section
14A.12(b)(ii) of the Agreement and Schedule 13 of the Tariff.
1.154 Supply Obligation: Is an obligation as defined in Section 14A.1(a) of
the Agreement for Energy, Operating Reserve, 4-Hour Reserve, and/or AGC.
1.155 Supply Offer: A proposal to furnish Energy at a Node or External Node,
Operating Reserve, 4-Hour Reserve and/or AGC (as defined in the Agreement) from
a Resource that meets the applicable requirements set forth in the Market Rules
that a Participant with Supply Offer authority for the Resource submits to the
System Operator pursuant to the Agreement and applicable Market Rules, and
includes a price for the Supply Offer and information with respect to the
quantity proposed to be furnished, technical parameters for the Resource, timing
and other matters.
1.156 System Contract: Any Contract for the purchase of Installed Capability,
Energy [at a Location], Operating Reserves[, 4-Hour Reserves] and/or AGC (as
defined in the Agreement), other than a Unit Contract, pursuant to which the
purchaser is entitled to a specifically determined or determinable amount of
such Installed Capability, Energy, Operating Reserves[, 4-Hour Reserves] and/or
AGC.
1.157 System Impact Study: An assessment pursuant to Part V, VI or VII of this
Tariff of (i) the adequacy of the NEPOOL Transmission System to accommodate a
request for the interconnection of a new or materially changed generating unit
or a new or materially changed interconnection to another Control Area or new
Regional Network Service, Internal Point-to-Point Service or Through or Out
Service, and (ii) whether any additional costs may be required to be incurred in
order to provide the interconnection or transmission service.
1.158 System Operator: The central dispatching agency provided for in the
Agreement which has responsibility for the operation of the NEPOOL Control Area
from the control center and the administration of this Tariff. The System
Operator is the ISO.
1.159 Target FCR Payment: The amount of an FCR Payment that an FCR Holder is
entitled to in the absence of a Congestion Revenue Shortfall when the Congestion
Component of the Locational Price at the Location and/or Reliability Region of a
given FCR's Point of Delivery is higher than the Congestion Component of the
Locational Price at the Location and/or Reliability Region of the given FCR's
Point of Receipt. Target FCR Payments are calculated and Congestion Revenue
Shortfalls are managed in accordance with Schedule 14.
1.160 Tariff: This NEPOOL Open Access Transmission Tariff and accompanying
schedules and attachments, as modified and amended from time to time.
1.161 Third-Party Sale: Any sale for resale in interstate commerce to a Power
Purchaser that is not designated as part of Network Load under the Regional
Network Service.
1.162 Through or Out Service: Point-to-Point Transmission Service provided by
NEPOOL with respect to a transaction which requires the use of PTF and which
goes through the NEPOOL Control Area, as, for example, from the Maine Electric
Power Company line or New Brunswick to New York, or from one point on the NEPOOL
Control Area boundary with New York to another point on the Control Area
boundary with New York, or with respect to a transaction which goes out of the
NEPOOL Control Area from a point in the NEPOOL Control Area, as, for example,
from Boston to New York.
1.163 Third Effective Date: The date on which all Interchange Transactions shall
begin to be effected on the basis of separate Bid Prices for each type of
Entitlement. The Third Effective Date shall be fixed at the discretion of the
Management Committee to occur within six months to one year after the Second
Effective Date, or at such later date as the Commission may fix on its own or
pursuant to a request by the Management Committee.
1.164 Ties: (i) The PTF lines and facilities which connect the NEPOOL
Transmission System to the transmission line owned by Maine Electric Power
Company, which is in turn connected to the transmission system in New Brunswick,
(ii) the PTF lines and facilities which connect the NEPOOL Transmission System
to the transmission system in New York and (iii) any new PTF lines and
facilities which connect the NEPOOL Transmission System to the transmission
system in another Control Area.
1.165 Transition Period: The six-year period commencing on March 1, 1997.
1.166 Transmission Customer: Any Eligible Customer that (i) is a Participant
which is not required to sign a Service Agreement with respect to a service to
be furnished to it in accordance with Section 48 of this Tariff, or (ii)
executes, on its own behalf or through its Designated Agent, a Service
Agreement, or (iii) requests in writing, on its own behalf or through its
Designated Agent, that NEPOOL file with the Commission, a proposed unexecuted
Service Agreement in order that the Eligible Customer may receive transmission
service under this Tariff. This term is used in Part I to include customers
receiving transmission service under this Tariff.
1.167 Transmission Owner: A Transmission Provider that makes its PTF available
under the Tariff and owns a Local Network listed in Attachment E to the Tariff
which is not a Publicly Owned Entity and includes any affiliate of a
Transmission Provider that owns transmission facilities that are made available
as part of the Transmission Provider's Local Network; provided that if a
Transmission Provider is not listed in Attachment E to the Tariff on May 10,
1999, the Transmission Provider must also (1) own, or lease with rights
equivalent to ownership, PTF with an original capital investment in its PTF of
at least $30,000,000, and (2) provide transmission service to non- affiliated
customers pursuant to an open access transmission tariff on file with the
Commission.
1.168 Transmission Owners Committee: The committee established pursuant to
Section 11B of the Agreement.
1.169 Transmission Provider: The Participants, collectively, which own PTF and
are in the business of providing transmission service or provide service under a
local open access transmission tariff, or in the case of a state or municipal or
cooperatively-owned Participant, would be required to do so if requested
pursuant to the reciprocity requirements specified in the Tariff, or an
individual such Participant, whichever is appropriate.
1.170 Transmission System Upgrade: Has the meaning specified in Section 51.
1.171 Unit Contract: A purchase contract pursuant to which the purchaser is in
effect currently entitled, at a specified Location, either (i) to a specifically
determined or determinable portion of the capacity of a specific electric
generating unit or units, or (ii) to a specifically determined or determinable
amount of Installed Capability, Energy, Operating Reserves and/or AGC (as
defined in the Agreement) if, or to the extent that, a specific electric
generating unit or units is or can be operated.
1.172 Use: For a Transmission Customer which has exercised its option to take
Internal Point-to-Point Service to serve all or a portion of its load at any
Point of Delivery, the greater for the hour of (i) the maximum amount of Energy
that it will receive in any hour, as determined from meters and adjusted for
losses, plus, in the case of a Participant, the maximum amount of Operating
Reserve assigned to the Participant by the System Operator in any hour during
the month, at that Point of Delivery from the resources covered by its Completed
Applications and from Interchange Transactions, or (ii) the portion of its
Installed Capability Responsibility which must be satisfied with the resources
covered by its Completed Applications and from Interchange Transactions. Use
shall be expressed in terms of whole Kilowatts on a sixty-minute interval
(commencing on the clock hour) basis.
1.173 Withdrawal Factor: The factor which measures the proportion of a small
increment of power injected at a given Node that can be withdrawn at the
Reference Node (with any difference between the amounts injected and withdrawn
attributable to Marginal Losses). Withdrawal Factors are used to calculate
Locational Prices in accordance with Section 14A.12 of the Agreement and
Schedule 13 of the Tariff.
1.174 Year: A period of 365 or 366 days, whichever is appropriate, commencing
on, or on the anniversary of March 1, 1997. Year One is the Year commencing on
March 1, 1997, and Years Two and higher follow it in sequence.
1.175 Zonal Price: In each hour of the Dispatch Day in the Day-Ahead Market and
the Real-Time Market, the price for Energy received in a Load Zone or
Reliability Region in the hour, as calculated in accordance with Section 14A.12
of the Agreement and Schedule 13 of the Tariff.
3 Purpose of This Tariff
This Tariff, together with the transmission provisions in Part Four of the
Agreement, is intended to provide a regional arrangement which will cover new
uses of the NEPOOL Transmission System. The arrangement is designed and shall be
operated in such a manner as to encourage and promote competition in the
electric market to the benefit of ultimate users of electric energy. New uses of
transmission facilities which require the use of a single Participant Local
Network will continue to be provided in part under that Participant's filed
tariff. Any new regional use of the NEPOOL Transmission System must be obtained
from NEPOOL pursuant to this Tariff and not from individual Participants.
Ancillary Services will be supplied in accordance with Section 4 of this Tariff.
A five-year transitional arrangement, which is described in Part IV of this
Tariff, and continuing service for Excepted Transactions, have been negotiated
to phase in the financial impacts of the change from the historic regime in
which uses of the NEPOOL Transmission System had to be obtained and paid for
under the individual tariffs of the Participants to a regime in which the
service will be obtained from the Participants through NEPOOL at a rate which
will not vary with distance. This Tariff is intended to provide for comparable,
non-discriminatory treatment of all similarly situated Transmission Providers
and all Participants and Non-Participants that are transmission users, and it
shall be construed in the manner which best achieves this objective.
This Tariff, and the provisions of Part Four of the Agreement, provide for a
two-tier transmission arrangement integrating regional service which is provided
under this Tariff, and local service which is provided under the Participants'
individual system tariffs.
This Tariff is also intended to provide a system of Congestion management.
4 Initial Allocation and Renewal Procedures
4.1 Initial Allocation of Available Transmission Capability: For purposes of
determining whether existing capability on the NEPOOL Transmission System is
adequate to accommodate a request for new Through or Out Service under Part V of
this Tariff, all Completed Applications for new service received during the
initial sixty-day period of the Transition Period will be deemed to have been
filed simultaneously. A lottery system conducted by an independent accounting
firm shall be used to assign priorities for Completed Applications filed
simultaneously. All Completed Applications for Through or Out Service received
after the initial sixty-day period shall be assigned a priority pursuant to
Section 27.2.
4.2 Reservation Priority for Existing Firm Service Customers: Existing firm
service customers receiving service with respect to Excepted Transactions and
any other existing firm service customers of the Participants (wholesale
requirements customers and transmission-only customers) with a contract term of
one year or more have the right to continue to take transmission service at the
same or a reduced level under this Tariff at the time when the existing contract
terminates during or after the Transition Period. This transmission reservation
priority is independent of whether the existing customer continues to purchase
capacity and energy from its existing supplier or elects to purchase capacity
and energy from another supplier. If, at the end of the contract term, the
NEPOOL Transmission System cannot accommodate all of the requests for
transmission service, the existing firm service customer must agree to accept a
contract term at least equal to a competing request by any new Eligible Customer
and to pay the current just and reasonable rate, filed with the Commission, for
such service. This transmission reservation priority for existing firm service
customers is an ongoing right that may be exercised as to any firm contract with
a term of one year or longer by filing an Application in accordance with this
Tariff at least sixty days in advance of the first day of the calendar month in
which the existing contract term is to terminate.
4.3 Initial Election of Optional Internal Point-to-Point Service: Participants
and Non-Participants receiving Regional Network Service under the Tariff on the
Compliance Effective Date shall have sixty days to make an initial election to
receive Internal Point-to-Point Service in lieu of, in whole or part, Regional
Network Service. The election shall take effect as to such service at the end of
such sixty-day period and shall be made by delivering an application to the
System Operator, together with a deposit, if required, pursuant to Part V of
this Tariff.
Participants and Non-Participants receiving Regional Network Service which do
not make such an initial election within such sixty-day period shall continue to
receive Regional Network Service, subject to their right to elect at any time
later to receive Internal Point-to-Point Service.
5 Ancillary Services
Ancillary Services are needed with transmission service to maintain reliability
within the NEPOOL Control Area. The Participants are required to provide through
NEPOOL, and the Transmission Customer is required to purchase from NEPOOL,
Scheduling, System Control and Dispatch Service, and Reactive Supply and Voltage
Control from Generation Sources Service. The Participants offer to provide or
arrange for, through NEPOOL, the following Ancillary Services, but only to a
Transmission Customer serving load within the NEPOOL Control Area (i) Regulation
and Frequency Response (Automatic Generator Control), (ii) Energy Imbalance,
(iii) Operating Reserve - 10-Minute Spinning, (iv) Operating Reserve - 10-Minute
Non-Spinning and (v) Operating Reserve - 30-Minute. A Participant or other
Transmission Customer serving load within the NEPOOL Control Area is required to
provide these Ancillary Services, whether from the System Operator, from a third
party, or by self- supply. A Transmission Customer may not decline NEPOOL's
offer of these Ancillary Services unless the Transmission Customer demonstrates
to the System Operator that the Transmission Customer has acquired Ancillary
Services of equal quality from another source. The Transmission Customer that is
not a Participant must list in its Application which Ancillary Services it will
purchase through NEPOOL.
In the event of an unauthorized use of any Ancillary Service by the Transmission
Customer, the Transmission Customer will be required to pay 200% of the charge
which would otherwise be applicable.
The specific Ancillary Services, prices and/or compensation methods are
described on the Schedules that are attached to and made a part of this Tariff.
Three principal requirements apply to discounts for Ancillary Services provided
by NEPOOL in conjunction with its provision of transmission service as follows:
(1) any offer of a discount made by NEPOOL must be announced to all Eligible
Customers solely by posting on the OASIS, (2) any customer-initiated requests
for discounts (including requests for use by one's wholesale merchant or an
affiliate's use) must occur solely by posting on the OASIS, and (3) once a
discount is negotiated, details must be immediately posted on the OASIS. A
discount agreed upon for an Ancillary Service must be offered for the same
period to all Eligible Customers on the NEPOOL Transmission System. Sections 4.1
through 4.7 below list the seven Ancillary Services.
5.1 Scheduling, System Control and Dispatch Service: The rates and/or
methodology are described in Schedule 1.
5.2 Reactive Supply and Voltage Control from Generation Sources Service: The
rates and/or methodology are described in Schedule 2.
5.3 Regulation and Frequency Response Service: Where applicable, the rates
and/or methodology are described in Schedule 3.
5.4 Energy Imbalance Service: Where applicable, the rates and/or methodology
are described in Schedule 4.
5.5 Operating Reserve - 10-Minute Spinning Reserve Service: Where applicable,
the rates and/or methodology for this service are described in Schedule 5.
5.6 Operating Reserve - 10-Minute Non-Spinning Reserve Service: Where
applicable, the rates and/or methodology for this service are described in
Schedule 6.
5.7 Operating Reserve - 30-Minute Reserve Service: Where applicable, the
rates and/or methodology for this service are described in Schedule 7.
5.8 System Restoration and Planning Service: Where applicable, the rates
and/or methodology for this service are described in Schedule 16.
6 Open Access Same-Time Information System (OASIS)
Terms and conditions regarding the NEPOOL Open Access Same-Time Information
System and standards of conduct are set forth in 18 C.F.R. 37 of the
Commission's regulations (Open Access Same-Time Information System and Standards
of Conduct for Public Utilities). In the event available transmission
capability, as posted on OASIS, is insufficient to accommodate a request for
firm transmission service, additional studies may be required as provided by
this Tariff pursuant to Sections 33 and 44.
7 Local Furnishing and Other Tax-Exempt Bonds
7.1 Participants That Own Facilities Financed by Local Furnishing or Other
Tax-Exempt Bonds: This provision is applicable only to Participants that have
financed facilities for the local furnishing of electric energy with tax-exempt
bonds, as described in Section 142(f) of the Internal Revenue Code ("local
furnishing bonds") or other tax-exempt bonds, as described in Section 103(b) of
the Internal Revenue Code ("other tax-exempt bonds"). Notwithstanding any other
provision of this Tariff, a Participant shall not be required to provide service
to any Eligible Customer pursuant to this Tariff if the provision of such
transmission service would jeopardize the tax-exempt status of any local
furnishing bond(s) or other tax-exempt bonds used to finance the Participant's
facilities that would be used in providing such Transmission Service.
7.2 Alternative Procedures for Requesting Transmission Service - Local
Furnishing Bonds:
(i) If a Participant determines that the provision of transmission service to be
provided under this Tariff would jeopardize the tax-exempt status of any local
furnishing bond(s) used to finance the Participant's facilities that would be
used in providing such transmission service, the Management Committee shall be
advised within thirty days of receipt of a Completed Application by an Eligible
Customer requesting such service, or the date on which this Tariff becomes
effective, whichever is applicable.
(ii) If an Eligible Customer thereafter renews its request for the same
transmission service referred to in (i) by tendering an application under
Section 211 of the Federal Power Act, or the Management Committee tenders such
an application requesting that service be provided under this Tariff, the
Participant, within ten days of receiving a copy of the Section 211 application,
will waive its rights to receive a request for service under Section 213(a) of
the Federal Power Act and to the issuance of a proposed order under Section
212(c) of the Federal Power Act. The Commission, upon receipt of the
Transmission Provider's waiver of its rights to a request for service under
Section 213(a) of the Federal Power Act and to the issuance of a proposed order
under Section 212(c) of the Federal Power Act, shall issue an order under
Section 211 of the Federal Power Act. Upon issuance of the order under Section
211 of the Federal Power Act, the Transmission Provider shall be required to
provide the requested transmission service in accordance with the terms and
conditions of this Tariff.
7.3 Alternative Procedures for Requesting Transmission Service - Other Tax-
Exempt Bonds: If a Participant determines that the provision of transmission
service to be provided under the Tariff would jeopardize the tax-exempt status
of any other tax-exempt bonds used to finance the Participant's facilities that
would be used in furnishing such transmission service, it shall notify the
Management Committee within thirty days of the date on which this Tariff becomes
effective, and shall elect in its notice either to comply with the procedure
specified in Section 6.2(ii) or to make its facilities unavailable under the
Tariff and thereby waive its right to share in the distribution of revenues
received under the Tariff derived from such facilities. Any such election may be
changed at any time.
8 Reciprocity
A Transmission Customer receiving transmission service under this Tariff,
whether a Participant or a Non-Participant, agrees to provide comparable
transmission service that it is capable of providing to the Participants on
similar terms and conditions over facilities used for the transmission of
electric energy in Canada or used for such transmission in the United States and
that are owned, controlled or operated by, or on behalf of the Transmission
Customer and over facilities used for the transmission of electric energy owned,
controlled or operated by the Transmission Customer's corporate affiliates.
Transmission of power on the Transmission Customer's system to the border of the
NEPOOL Control Area and transfer of ownership at that point shall not satisfy,
or relieve the Transmission Customer of, the obligation to provide reciprocal
service.
This reciprocity requirement applies not only to the Transmission Customer that
obtains transmission service under the Tariff, but also to all parties to a
transaction that involves the use of transmission service under the Tariff,
including the power seller, buyer and any intermediary, such as a power
marketer. This reciprocity requirement also applies to any Eligible Customer
that owns, controls or operates transmission facilities that uses an
intermediary, such as a power marketer, to request transmission service under
the Tariff. If the Transmission Customer does not own, control or operate
transmission facilities, the Transmission Customer must include in its
Application a sworn statement of one of its duly authorized officers or other
representatives that the purpose of its Application is not to assist an Eligible
Customer to avoid the requirements of this provision.
9 Billing and Payment; Accounting
9.1 Participant Billing Procedure: Billings to Transmission Customers shall be
made in accordance with this Section 8 and the NEPOOL Billing Policy set forth
in Attachment N hereto, as such Billing Policy with respect to Participants may
be amended, modified or supplemented by other billing procedures established
pursuant to the Agreement.
9.2 Non-Participant Billing Procedure: Within a reasonable time after the first
day of each month, the System Operator will submit on behalf of the Participants
an invoice to each Non-Participant Transmission Customer for the charges for all
services furnished under this Tariff during the preceding month. The invoice
shall be paid by the Non-Participant Transmission Customer to the System
Operator for NEPOOL within ten days of receipt. All payments shall be made, in
accordance with the procedure specified by the System Operator, in immediately
available funds payable to the System Operator or by wire transfer to a bank
account designated by the System Operator.
9.3 Interest on Unpaid Balances: Interest on any unpaid amounts (including
amounts placed in escrow) will be calculated in accordance with the methodology
specified for interest on refunds in 18 C.F.R. 35.19a(a)(2)(iii) of the
Commission's regulations. Interest on delinquent amounts will be calculated from
the due date of the bill to the date of payment. When payments are made by mail,
bills will be considered as having been paid on the date of receipt of payment
by the System Operator or by the bank designated by the System Operator.
9.4 Customer Default: In the event a Non-Participant Transmission Customer fails
to make payment to the ISO on or before the due date as described above, and
such failure of payment is not corrected within thirty calendar days after the
ISO notifies the Transmission Customer to cure such failure, a default by the
Transmission Customer will be deemed to exist. Upon the occurrence of a default,
NEPOOL may initiate a proceeding with the Commission to terminate service but
shall not terminate service until the Commission approves such termination. In
the event of a billing dispute between NEPOOL and the Transmission Customer,
service will continue to be provided under the Service Agreement and service
termination proceedings will not be initiated as long as the Transmission
Customer continues to make all payments invoiced by NEPOOL, including any
disputed amounts, subject to resolution of such dispute in favor of such
Transmission Customer. If the Transmission Customer fails to meet this
requirement for continuation of service, then the ISO may provide notice to the
Transmission Customer of NEPOOL's intention to suspend service in sixty days, in
accordance with applicable Commission rules and regulations, and may proceed
with such suspension.
In the event a Transmission Customer that is a Participant fails to perform its
obligations under the Tariff, Section 21.2 of the Agreement shall be applicable
to that failure. That section of the Agreement addresses defaults under both the
Tariff and the Agreement and also addresses termination of an entity's status as
a Participant.
9.5 Study Costs and Revenues: A Participant which is a Transmission Provider
shall (i) include in a separate operating revenue account or subaccount the
revenues, if any, it receives from transmission service when making Third-Party
Sales under Part V of this Tariff, and (ii) include in a separate transmission
operating expense account or subaccount, costs properly chargeable to expense
that are incurred to perform any System Impact Studies or Facilities Studies
which the Transmission Provider conducts to determine if it must construct new
transmission facilities or upgrades necessary for its own uses, including
Third-Party Sales, if any, under this Tariff; and include in a separate
operating revenue account or subaccount the revenues received for System Impact
Studies or Facilities Studies performed when such amounts are separately stated
and identified in a billing under the Tariff.
10 Regulatory Filings
Nothing contained in this Tariff or any Service Agreement shall be construed as
affecting in any way the right of the Participants to file with the Commission
under Section 205 of the Federal Power Act and pursuant to the Commission's
rules and regulations promulgated thereunder for a change in any rates, terms
and conditions, charges, classification of service, Service Agreement, rule or
regulation.
Nothing contained in this Tariff or any Service Agreement shall be construed as
affecting in any way the ability of any Transmission Customer receiving service
under this Tariff or for an Excepted Transaction to exercise its rights under
the Federal Power Act and pursuant to the Commission's rules and regulations
promulgated thereunder.
11 Force Majeure and Indemnification
11.1 Force Majeure: An event of Force Majeure means any act of God, labor
disturbance, act of the public enemy, war, insurrection, riot, fire, storm or
flood, explosion, breakage or accident to machinery or equipment, any
Curtailment, any order, regulation or restriction imposed by a court or
governmental military or lawfully established civilian authorities, or any other
cause beyond a party's control. A Force Majeure event does not include an act of
negligence or intentional wrongdoing. Neither the Participants, NEPOOL, the
System Operator nor the Transmission Customer will be considered in default as
to any obligation under this Tariff if prevented from fulfilling the obligation
due to an event of Force Majeure; provided that no event of Force Majeure
affecting any entity shall excuse that entity from making any payment that it is
obligated to make hereunder or under a Service Agreement. However, an entity
whose performance under this Tariff is hindered by an event of Force Majeure
shall make all reasonable efforts to perform its obligations under this Tariff,
and shall promptly notify the System Operator or the Transmission Customer,
whichever is appropriate, of the commencement and end of each event of Force
Majeure.
11.2 Indemnification: The Transmission Customer shall at all times indemnify,
defend, and save harmless the System Operator, NEPOOL and each Participant from
any and all damages, losses, claims, including claims and actions relating to
injury to or death of any person or damage to property, demands, suits,
recoveries, costs and expenses, court costs, attorney fees, and all other
obligations by or to third parties, arising out of or resulting from the
performance by the System Operator, NEPOOL or any Participant of their
obligations under this Tariff on behalf of the Transmission Customer, except in
cases of negligence or intentional wrongdoing by the System Operator, NEPOOL or
a Participant, as the case may be.
12 Creditworthiness
For the purpose of determining the ability of a Transmission Customer which is a
Non-Participant to meet its obligations related to service hereunder, NEPOOL may
require reasonable credit review procedures. This review shall be made in
accordance with standard commercial practices. In addition, NEPOOL may require
the Transmission Customer to provide and maintain in effect during the term of
the Service Agreement an irrevocable letter of credit as security to meet its
responsibilities and obligations under this Tariff, or an alternative form of
security proposed by the Transmission Customer and acceptable to NEPOOL and
consistent with commercial practices established by the Uniform Commercial Code
that protects the Participants against the risk of non-payment. The Financial
Assurance Policy for NEPOOL Non-Participant Transmission Customers set forth in
Attachment M hereto provides in greater detail NEPOOL's credit review procedures
and the types of security that are acceptable to NEPOOL to protect against the
risk of non-payment.
13 Dispute Resolution Procedures
13.1 Internal Dispute Resolution Procedures: Any dispute between an Eligible
Customer or Transmission Customer which is a Participant and NEPOOL involving
transmission service under the Tariff may be submitted to mediation and/or
arbitration and resolved in accordance with the alternate dispute resolution
procedures set forth in Section 21.1 of the Agreement. Any dispute between a
Non-Participant Eligible Customer or Transmission Customer and NEPOOL involving
this Tariff (excluding applications for rate changes or other changes to this
Tariff, or to any Service Agreement entered into under this Tariff, which shall
be presented directly to the Commission for resolution) shall be referred to a
designated senior representative of the Eligible Customer or Transmission
Customer and a representative of the Management Committee for resolution on an
informal basis as promptly as practicable. In the event the designated
representatives are unable to resolve the dispute within thirty days or such
other period as the parties may fix by mutual agreement, such dispute may be
submitted to mediation and/or arbitration and resolved in accordance with the
alternate dispute resolution procedures set forth in Section 21.1 of the
Agreement, with any Non-Participant being treated as if it were a Participant
for purposes of such procedures.
13.2 Rights Under The Federal Power Act: Nothing in this section shall restrict
the rights of any party to file a complaint with the Commission, or seek any
other available remedy, under relevant provisions of the Federal Power Act.
14 Stranded Costs
14.1 General: This Tariff shall not be used to evade or enhance in whole or in
part the stranded cost policies or charges established by law or by the
regulatory commission with jurisdiction.
14.2 Commission Requirements: A Participant which seeks to recover stranded
costs from a Transmission Customer pursuant to this Tariff may do so in
accordance with the terms, conditions and procedures in the Commission's Order
No. 888 or other relevant Commission orders. However, the Participant must
separately file any specific proposed stranded cost charge under Section 205 of
the Federal Power Act.
14.3 Wholesale Contracts: Nothing in this Section 13 is intended to affect or
alter the rights or obligations of parties under wholesale requirements
contracts.
14.4 Right to Seek or Contest Recovery Unimpaired: No provision in this Tariff
shall impair a Participant's right to seek stranded cost relief from the
appropriate regulatory body or court or the right of any Participant or other
entity to contest such relief.
II. REGIONAL NETWORK SERVICE (NETWORK INTEGRATION TRANSMISSION SERVICE) Regional
Network Service or Network Integration Transmission Service will be provided by
the Participants through NEPOOL during and after the Transition Period to
Transmission Customers pursuant to the applicable terms and conditions of this
Tariff. Local Network Service will be provided during and after the Transition
Period pursuant to the applicable terms and conditions of tariffs filed by an
individual Participant that is a Transmission Provider and/or pursuant to an
agreement between a Participant that is a Transmission Provider and a
Transmission Customer. This Tariff does not prescribe the methodology to be used
by the individual Participant in developing its Local Network Service rate, but
the Agreement prescribes certain requirements with respect thereto.
15 Nature of Regional Network Service
Regional Network Service or Network Integration Transmission Service is the
service provided under Parts II and VI of this Tariff over the NEPOOL
Transmission System which is provided to Network Customers to serve their loads.
It includes firm transmission service for the delivery to a Network Customer of
its energy and capacity in Network Resources and secondary service for the
delivery to or by Network Customers of energy and capacity in Interchange
Transactions.
1.1 Rules for Import Transactions Conducted in Conjunction with Regional
Network Service:
For purposes of scheduling and curtailment of Import Transactions over
interconnections between the NEPOOL Control Areas and neighboring Control Areas,
the following rules shall apply:
(a) Excepted Transactions, and those service agreements covering the importation
over the PTF of the allocation of New York Power Authority power and energy that
were in effect as of the date that the NEPOOL Tariff became effective, shall
have highest priority, and shall be scheduled first and curtailed last;
(b) other than as provided in 14.1(a), Import Transactions shall, to the maximum
extent practicable, be scheduled and curtailed on the basis of economic merit
order and in accordance with NEPOOL System Rules, except that Short Notice
External Transactions (as defined in the Market Rules) shall be scheduled and
curtailed in accordance with the Market Rules governing such transactions;
(c) other than as provided in 14.1(a), to the extent that Import Transactions
cannot be scheduled and curtailed on the basis of economic merit order, such
transactions shall be scheduled in order of submittal time (first submitted,
first served) and curtailed in reverse order of submittal time (last submitted,
first curtailed);
(d) to the extent that multiple schedules for Import Transactions submitted at
the same time have the same economic merit order, the System Operator shall
curtail the schedules on a non-discriminatory basis in accordance with NEPOOL
System Rules; and
(e) market participants wishing to schedule Import Transactions shall comply
with applicable NEPOOL System Rules. The System Operator shall apply the
above-listed rules consistent with maintaining the reliability of the NEPOOL
Transmission System. The System Operator shall develop and post procedures on
its Internet website reflecting the above-listed Import Transaction rules.
16 Availability of Regional Network Service
16.1 Provision of Regional Network Service: Regional Network Service shall be
provided by the Participants through NEPOOL, and shall be available to each
Eligible Customer.
16.2 Eligibility to Receive Regional Network Service: Regional Network Service
shall be taken and paid for by (i) each Eligible Customer which has a load
within the NEPOOL Control Area and has not elected to take Internal
Point-to-Point Service at all of its Point(s) of Delivery, and (ii) each Non-
Participant which is an Eligible Customer and has a load within the NEPOOL
Control Area unless such Non-Participant operates its own Control Area or has
elected to take Internal Point-to-Point Service at all of its Point(s) of
Delivery. Participants and Non-Participants which take Regional Network Service
must also take Local Network Service except as otherwise provided in Section 25.
17 Payment for Regional Network Service
Each Participant or Non-Participant which has a load in the NEPOOL Control Area
and takes Regional Network Service for a month shall pay to NEPOOL for such
month an amount equal to its Monthly Network Load for the month times the
applicable Participant RNS Rate, and shall pay in addition any amount which it
is required to pay for the service pursuant to Section 43.3 of this Tariff. It
shall also be obligated to pay any ancillary service charges and any applicable
congestion or other uplift charge required to be paid pursuant to Sections 24,
25A and 25B of this Tariff. The applicable Participant RNS Rate shall be the
rate, determined in accordance with Schedule 9, which is applicable to a
delivery to load in the particular Local Network in which the load served by the
Participant or Non-Participant is located. In the event the Participant or
Non-Participant serves Network Load located on more than one Local Network, the
amount to be paid by it shall be separately computed for the Network Load
located on each Local Network.
18 Procedure for Obtaining Regional Network Service
A Participant or Non-Participant which takes Regional Network Service shall be
subject to the applicable provisions of Part II and Part VI of this Tariff,
except to the extent otherwise specifically provided in Section 48 of this
Tariff
III. THROUGH OR OUT SERVICE; INTERNAL POINT-TO-POINT SERVICE
Point-to-Point Transmission Service as Through or Out Service or Internal
Point-to-Point Service will be provided during and after the Transition Period
pursuant to the applicable terms and conditions of this Tariff.
19 Through or Out Service
19.1 Provision of Through or Out Service: Through or Out Service shall be
provided by the Participants through NEPOOL, and shall be available to any
Participant and to any Non-Participant which is an Eligible Customer.
19.2 Use of Through or Out Service: A Participant or Non-Participant shall take
Through or Out Service as Firm or Non-Firm Point-To-Point Transmission Service
for the transmission of any Unit Contract Entitlement or System Contract
transaction with respect to a transaction which requires the use of PTF if
either (i) the transaction goes through the NEPOOL Control Area and the Point(s)
of Receipt for NEPOOL are at one point on the NEPOOL Control Area boundary and
the Point(s) of Delivery for NEPOOL are at another point on the NEPOOL Control
Area boundary, as, for example, from the Maine Electric Power Company line or
New Brunswick to New York or from one point on the NEPOOL Control Area boundary
with New York to another point on the Control Area boundary with New York, or
(ii) the transaction goes out of the NEPOOL Control Area and the Point(s) of
Receipt are within the NEPOOL Control Area and the Point(s) of Delivery for
NEPOOL are at a NEPOOL Control Area boundary, as, for example, from Boston to
New York.
20 Internal Point-to-Point Service
20.1 Provision of Internal Point-to-Point Service: Internal Point-to-Point
Service shall be provided by the Participants through NEPOOL, and shall be
available to any Participant and to any Non-Participant which is an Eligible
Customer.
20.2 Use of Internal Point-to-Point Service: A Participant or Non-Participant
which is an Eligible Customer may take Internal Point-to-Point Service as Firm
or Non-Firm Point-to-Point Transmission Service with respect to any transaction
if the Point(s) of Receipt are at the NEPOOL Control Area boundary or within the
NEPOOL Control Area, and the Point(s) of Delivery are within the NEPOOL Control
Area, including Interchange Transactions meeting these requirements. Non-Firm
Internal Point-to-Point Service shall be available to an entity to serve its
load only if the entity (i) demonstrates to the satisfaction of the System
Operator a physical ability to interrupt its receipt of energy and/or capacity
and (ii) gives the System Operator physical control over such an interruption.
20.3 Use by a Transmission Customer: If a Transmission Customer elects to take
Internal Point-to-Point Service with respect to any Points of Delivery, it may
reserve transmission capacity for the service to cover both the delivery to it
of Energy and capacity covered by the Entitlements or System Contracts
designated by it in Completed Applications and the delivery to or from it in
Interchange Transactions of Energy and/or capacity. A transmission Customer
which takes Internal Point-to-Point Service to serve its load must also take
point-to-point service under the applicable Local Network Service tariff. A
load-serving Participant or Non-Participant which takes Internal Point-to-Point
Service in this manner must reserve each month sufficient Reserved Capacity,
after adjusting for any Backyard Generation, at a Point of Delivery to cover (i)
the maximum amount of Energy that it will receive in any hour, as determined
from meters and adjusted for losses, plus, in the case of a Participant, the
maximum amount of Operating Reserve assigned to that Participant by the System
Operator in any hour during the month, or (ii) the portion of its Installed
Capability Responsibility which must be satisfied with the resources covered by
its Completed Applications and from Interchange Transactions if such portion
exceeds the amount determined in accordance with clause (i) of this sentence.
Any load-serving entity may use Internal Point-to-Point Service to effect sales
in bilateral arrangements, whether or not it elects to take Point-to-Point
Service to serve its load.
21 Payment for Through or Out Service
Each Participant or Non-Participant which takes Firm or Non-Firm Through or Out
Service shall pay to NEPOOL a charge per Kilowatt of Reserved Capacity based on
an annual rate (the "T or O Rate") which shall be the highest of (i) the Pool
PTF Rate, or (ii) a rate which is derived from the annual incremental cost, not
otherwise borne by the Transmission Customer or a Generation Owner, of any new
facilities or upgrades that would not be required but for the need to provide
the requested service or (iii) a rate which is equal to the Pool's opportunity
cost (if and when available) capped at the cost of expansion. If at any time
NEPOOL proposes to charge a rate based on opportunity cost, it shall first file
with the Commission procedures for computing opportunity cost pricing for all
Transmission Customers. The Transmission Customer shall also be obligated to pay
any ancillary service charge and any applicable congestion or other uplift
charge required to be paid pursuant to Section 24 of this Tariff. The rate for
Firm Through or Out Service shall be as follows:
Per year - the T or O Rate
Per month - the T or O Rate divided by 12
Per week - the T or O Rate divided by 52
Per day - the T or O Rate "per week" divided by 5; provided that
the rate for 5 to 7 consecutive days may not exceed the "per
week" rate.
The rate for Non-Firm Through or Out Service shall be as follows:
Per year - the T or O Rate
Per month - the T or O Rate divided by 12
Per week - the T or O Rate divided by 52
Per day - the T or O Rate "per week" divided by 7;
Per hour - the Non-Firm T or O Rate "per day" divided by 24.
The Pool PTF Rate shall be the Rate determined annually in accordance with
paragraph (2) of Schedule 8.
22 Payment for Internal Point-to-Point Service
Each Participant or Non-Participant which takes firm or non-firm Internal
Point-to-Point Service shall pay to NEPOOL a charge per Kilowatt of Reserved
Capacity based on an annual rate (the "IPTP Charge") which shall be the Internal
Point-to-Point Service Rate; provided that if either or both (i) a rate which is
derived from the annual incremental cost, not otherwise borne by the
Transmission Customer or a Generator Owner, of any new facilities or upgrades
that would not be required but for the need to provide the requested service, or
(ii) a rate which is equal to the Pool's opportunity cost (if and when
available) capped at the cost of expansion is greater than the Pool PTF Rate,
the IPTP Charge shall be the higher of such amounts; provided further that no
such charge shall be payable with respect to the use of Internal Point-to-Point
Service to effect a delivery to the NEPOOL power exchange in an Interchange
Transaction. If at any time NEPOOL proposes to charge a rate based on
opportunity cost, it shall first file with the Commission procedures for
computing opportunity cost pricing for all Transmission Customers. The
Transmission Customer shall also be obligated to pay any ancillary service
charges and any applicable congestion or other uplift charge required to be paid
pursuant to Sections 24, 25A and 25B of this Tariff. The charge for firm
Internal Point-to-Point Service shall be as follows:
Per year - the IPTP Charge
Per month - the IPTP Charge divided by 12
Per week - the IPTP Charge divided by 52
Per day - the IPTP Charge "per week" divided by 5; provided that
the rate for 5 to 7 consecutive days may not exceed the "per
week" rate.
The rate for non-firm Internal Point-to-Point Service shall be as follows:
Per year - the IPTP Charge
Per month - the IPTP Charge divided by 12
Per week - the IPTP Charge divided by 52
Per day - the IPTP Charge "per week" divided by 7;
Per hour - the non-firm IPTP Charge "per day" divided by 24.
If several power marketers or other entities are involved in a series of sales
of the same energy and/or capacity, transmission service shall be required only
with respect to the delivery to the ultimate wholesale buyer, and if an Internal
Point-to-Point Service charge is payable with respect to the transaction, the
charge shall be paid only with respect to the delivery to, and absent other
arrangements the charge shall be paid by, the ultimate wholesale buyer.
23 Reservation of Capacity for Point-to-Point Transmission Service Compliance
with the applicable requirements of Part V of this Tariff is required for the
initiation of Through or Out Service or Internal Point-to- Point Service.
IV. SERVICE DURING THE TRANSITION PERIOD; CONGESTION COSTS; EXCEPTED
TRANSACTIONS
The six-year Transition Period, and additional arrangements to be in effect
during the succeeding five-year period, will permit the phase-in on a negotiated
basis of the Tariff rates.
24 Transition Arrangements
The transition arrangements include (i) the treatment provided for certain
Excepted Transactions in Section 25, (ii) the provisions in Schedule 9 for the
phase-in of the rates for Regional Network Service, and (iii) the rules provided
in Sections 16.3 and 16.6 of the Agreement for the distribution and application
of revenues received by NEPOOL on behalf of the Participants from the payment of
the Tariff rates.
25 Congestion Costs and Congestion Revenue
(1) Until the earlier of the CMS/MSS Effective Date or the implementation
effective date of an order issued by the Commission directing a different
allocation of Congestion Costs, if limitations in available transmission
capacity over any interface within the NEPOOL Control Area in any hour require
that the System Operator dispatch resources out-of-merit, the System Operator
shall determine for the affected area or areas the aggregate of the Congestion
Costs for all such out-of-merit resources for the hour. The Congestion Costs for
each hour in any month shall be paid as a transmission charge and included in
the charge for Regional Network Service or Internal Point-to-Point Service or
Through or Out Service, whichever is applicable, by those Participants and
Non-Participants which are obligated to pay a Regional Network Service, Internal
Point-to-Point Service or Through or Out Service charge for the month, in
accordance with the following formula:
(EQUATION)
in which
CH = the amount to be paid by a Participant or Non-Participant for the hour;
CC = the Congestion Costs for the hour to be allocated and paid pursuant to
this Section 24(a);
HLi = the Network Load of the Participant or Non-Participant for the hour, if it
is obligated to pay a Regional Network Service charge for the month;
HL = the aggregate of the Network Loads for the hour of all Participants and
Non-Participants which are obligated to pay a Regional Network Service charge
for the month;
RCi = the Reserved Capacity, if any, for Internal Point-to-Point Service or
Through or Out Service of the Participant or Non-Participant for the hour; and
RC = the aggregate Reserved Capacity, if any, for Internal Point-to-Point
Service or Through or Out Service of all Participants and Non-Participants for
the hour.
This Section 24(a) shall terminate on the implementation effective date of an
order issued by the Commission directing a different allocation of Congestion
Costs.
As used in this Section 24(a), the "Congestion Cost" of an out-of-merit resource
for an hour means the product of (i) the difference between its Dispatch Price
and the Energy Clearing Price for the hour, times (ii) the number of megawatt
hours of out-of-merit generation produced by the resource for the hour. The
"Dispatch Price" of an out-of-merit resource for an hour is the price to provide
energy from the resource, as determined pursuant to market operation rules
approved by the NEPOOL Regional Market Operations Committee to incorporate the
Bid Price for such energy and any loss adjustments, if and as appropriate under
such market operation rules. The "Energy Clearing Price" for an hour is the
price determined for the hour in accordance with Section 14.8 of the Agreement.
26 (b) On and after the CMS/MSS Effective Date, when Congestion exists, the
Congestion Cost shall be reflected in Locational Prices calculated in accordance
with Section 14A.12 of the Agreement and Schedule 13 of the Tariff.
Congestion Cost shall be recovered from Non-Participant Transmission Customers
taking service under the Tariff in accordance with Schedule 13 of the Tariff.
Congestion Cost shall be recovered from Participants in accordance with Section
14A.17 of the Agreement.
Congestion Revenue shall be collected and maintained in a Congestion Revenue
Fund in accordance with Section E of Schedule 14 of the Tariff.
A system of Financial Congestion Rights shall be implemented and administered in
accordance with Schedule 14 of the Tariff.
A system of Auction Revenue Rights shall be implemented and administered in
accordance with Schedule 15 of the Tariff.
27 Excepted Transactions
Notwithstanding any other section of the Tariff but except as otherwise provided
in Section 25A or 25B of this Tariff, the power transfers and other uses of the
NEPOOL Transmission System effected under the transmission agreements in effect
on November 1, 1996 specified below ("Excepted Transactions") will continue to
be effected under such agreements for the respective periods specified below
rather than under this Tariff, but not thereafter, and such transfers and other
uses will continue to be effected after such period, if still occurring, under
this Tariff. Participants receiving service under the agreements listed in
Attachment G-1 shall not be required to take Local Network Service for such
transfers and other uses. The period for which each Excepted Transaction will
continue to be effected under such existing transmission agreements shall be:
(1) for the period to and including February 28, 2001, the following transfers
pursuant to Section 17 of the Agreement:
(a) the transfer to a Participant's system within the NEPOOL Control Area of
its ownership interest in a Pool-Planned Unit which is off its system;
(b) the transfer to a Participant's system within the NEPOOL Control Area of its
Unit Contract Entitlement, under a contract entered into by it on or before
November 1, 1996, in a Pool-Planned Unit which is off its system; and
(c) the transfer to a Participant's system within the NEPOOL Control Area of its
Entitlement in a purchase (including a purchase under the HQ Phase II Firm
Energy Contract) from Hydro-Quebec under a contract entered into by it on or
before November 1, 1996, where the line over which the transfer is made into New
England is the HQ Interconnection;
(2) for the period to and including February 28, 2001, the transfer to a
Participant's system within the NEPOOL Control Area of its Unit Contract
Entitlement in the Vermont Yankee Nuclear Power Corporation unit or the Pilgrim
1 unit; provided the transfer is pursuant to a transmission agreement in effect
on November 1, 1996 and is to the entity which was receiving the service on
November 1, 1996; and
(3) for the period from the effective date of the Tariff until the termination
of the transmission agreement:
(a) transfers and other uses within the NEPOOL Control Area, as of November 1,
1996, of the NEPOOL Transmission System under the support or exchange agreements
specified in Attachment G;
(b) transfers and other uses within the NEPOOL Control Area, as of November 1,
1996, of the NEPOOL Transmission System under the comprehensive network service
agreements specified in Attachment G-1; and
(c) transfers and other uses within the NEPOOL Control Area, as of November 1,
1996, of the NEPOOL Transmission System under the other transmission agreements
or tariff service agreements specified in Attachment G.
The Management Committee is authorized to add additional agreements to
Attachment G if they have been inadvertently omitted. Except as otherwise
provided in Sections 25A or 25B below, the transfers or other uses under any of
the transmission agreements covering the transfers referred to in paragraphs
(1), (2) and (3) above shall be in accordance with the terms of the transmission
agreement as in effect on November 1, 1996, or a modification of the terms which
is expressly provided for in the agreement as in effect on November 1, 1996 and
is accomplished without amendment of the agreement or by an amendment entered
into after November 1, 1996 that does not extend the term of the agreement or
increase the amount of the service. Further, except as otherwise provided in
Sections 25A or 25B below, and notwithstanding the foregoing restriction on the
amendment after November 1, 1996 of transmission agreements with respect to
Excepted Transactions, the transmission arrangements for the Masspower and
Altresco facilities may continue as Excepted Transactions in accordance with
transmission agreement amendments or memoranda of understanding entered into as
of December, 1996 which do not extend the term of the agreements.
For the purpose of determining priorities under this Tariff, Excepted
Transactions shall have the same priority as Firm Point-To-Point Transmission
Service transactions for resources in existence on the effective date of this
Tariff which are effected as Regional Network Service or as Internal Point-
to-Point Service or as Through or Out Service.
When the transfers and other uses effected under the transmission agreements
that are Excepted Transactions cease to be Excepted Transactions before the end
of their term, except as therein provided in Sections 25A or 25B below the
transactions shall be effected under this Tariff and under any applicable Local
Network Service Tariff, to the extent appropriate, but the transactions shall
continue to have a priority not less than the priority that they would have had
if Regional Network Service had been used for the transactions from the
effective date of this Tariff. New transactions entered into after November 1,
1996 under umbrella tariff agreements then in effect will not be Excepted
Transactions.
Notwithstanding the foregoing or any other section of the Tariff, existing
agreements which provide for the support of the costs of transmission facilities
or for the interconnection of transmission facilities shall continue in effect
until the termination of the agreement to provide for such support or for the
rights and obligations of the parties with respect to the interconnection
arrangements. Attachment G-2 lists certain additional agreements covering
transactions, the status of which is described in the Attachment.
25A Phase I Credit and Uplift Charge With Respect to Excepted Transactions
Notwithstanding the provisions of any other Section of this Tariff, the
following Participants will receive a total credit of $12,012,000 to settle
certain disputes regarding Excepted Transactions, allocated as set forth below
(defined for purposes of this Section 25A only as the Participant's "Phase I
Credit"):
Bangor Hydro-Electric Company $ 896,000
Massachusetts Municipal
Wholesale Electric Company
clients $ 6,182,400
Braintree Electric Light
Department $ 666,400
Reading Municipal Light
Department $ 1,430,240
Taunton Municipal Lighting
Plant $ 479,360
United Illuminating Company $ 280,000
Fitchburg Gas and Electric
Light Company $ 117,600
Unitil Power Corporation $ 1,960,000
The Phase I Credit for each of the Participants identified above shall be
provided as reductions in each entity's NEPOOL bill equal to one-twelfth (1/12)
of the amount identified above commencing with and including the bill covering
the period June 1 - 30, 1999 and ending with the bill covering the period May 1
- - May 31, 2000.
The total $12,012,000 Phase I Credit shall be funded with twelve equal monthly
uplift charges (the "Phase I Uplift") which will be in effect for the twelve
month period beginning June 1, 1999 and continuing through May 31, 2000, and
which will be included in the bills corresponding to this time period. Each RNS
and Internal Point-to-Point Transmission Customer under the NEPOOL Tariff shall
pay the monthly Phase I Uplift charge determined as follows:
1) A Transmission Customer's monthly share of the Phase I Uplift charge shall be
determined in accordance with the following formula:
PIU = $998,387 x [(ULi + URCi + UAUi) / (UL + URC + UAU)]
Where:
PIU = The Phase I Uplift Charge for the Participant or Non-Participant per
month.
$998,387 = The total monthly Phase I Uplift charge, exclusive of Taunton's
portion of the charge, calculated as follows: ($12,012,000 / 12) - $2,613.
ULi = Monthly Uplift Network Load of a Participant or Non-Participant
for the month
UL = Aggregate of the Uplift Network Loads of all Participants or
Non-Participants for the month
URCi = The sum of a Participant's or Non-Participant's Maximum Reserved Capacity
for Internal Point-to-Point Service for each load served within a Local Network
or Network(s) during the month
URC = Aggregate of URCi for all Participants and Non-Participants
UAUi = The sum of a Participant's or Non-Participant's Maximum Unauthorized Use
associated with Internal Point-to-Point Service for each load served within a
Local Network or Network(s) during the month
UAU = Aggregate of UAUi for all Participants and Non-Participants
The monthly Uplift Network Load (ULi) for each Non-Participant shall be its
Network Load for the month.The monthly Uplift Network Load (ULi) for each
Participant shall be the "1998 12 CP Network Load" identified in connection with
the determination of the Pool PTF Rate to become effective June 1, 1999, on a
basis comparable to the "1997 12 CP Network Load" reflected in Attachment K of
this Tariff, except as follows:
1) The total Uplift Load (ULi + URCi + UAUi) for the Vermont Electric Power
Company shall be zero.
2) The total Uplift Load (ULi + URCi + UAUi) for Bangor Hydro-Electric Company
shall be 50 MW.
3) The monthly Uplift Network Load (ULi) for Commonwealth Electric Company and
Cambridge Electric Light Company shall be one half of the value reflected in the
"1998 12 CP Network Load" for such companies (excluding the load for Nantucket).
4) The monthly Uplift Network Load (ULi) for Montaup Electric Company and the
affiliated Eastern Utilities Associates Operating Companies shall be one half of
the value reflected in the "1998 12 CP Network Load" for "Eastern Utilities
Associates."
5) The Taunton Municipal Lighting Plant's monthly payment for the Phase I Uplift
shall be limited to $2,613.
25B Phase II Credit and Uplift Charge With Respect to Certain Excepted
Transactions Notwithstanding the provisions of any other Section of this Tariff,
the Participants identified in Section 25A of this Tariff receiving a Phase I
Credit as set forth in that Section, so long as they remain RNS Transmission
Customers under the Tariff, shall receive a credit (defined for purposes of this
Section 25B only as a "Phase II Credit") to their NEPOOL transmission bills
equal to the amounts they are assessed under the contracts and arrangements for
the month within the scope of Sections 25(1) and 25(2) of the NEPOOL Tariff
(specifically PPU, Yankee, Pilgrim and HQ II), for all charges assessed during
the period March 1, 1999 through and including February 28, 2001 (defined for
purposes of this Section 25B only as "Phase II").
The Phase II Credit for each of the Participants that are to receive the Phase
II Credit shall be provided as reductions in that Participant's NEPOOL bill
commencing with and including the bill covering the period beginning March 1,
1999 and terminating with the bill for the period through February 28, 2001.
The total Phase II Credit shall be funded with a monthly uplift charge (the
"Phase II Uplift") which will be in effect for the twenty-four-month period
beginning June 1, 1999 and continuing through May 31, 2001, and which will be
included in the bills corresponding to this time period. Each RNS and Internal
Point-to-Point Transmission Customer under the NEPOOL Tariff shall pay a share
of the monthly Phase II Uplift charge, determined as follows:
PIIUi = $Y x [(PIILi + URCi + UAUi) / (PIIL + URC + UAU)]
Where:
PIIUi = The Phase II Uplift charge for the Participant or Non-Participant
for the month
$Y = Sum of the EHV PTF, Vermont Yankee and Pilgrim transmission charges for the
month for Bangor Hydro-Electric Company, Massachusetts Municipal Wholesale
Electric Company, Braintree Electric Light Department, Reading Municipal Light
Department and Taunton Municipal Lighting Plant, the United Illuminating Company
and Unitil Power Corp.
PIILi = Phase II Uplift Network Load of a Participant or Non-Participant
for the month
UL = Aggregate of the Phase II Uplift Network Loads of all Participants
or Non-Participants for the month
URCi = The sum of a Participant's or Non-Participant's maximum Reserved Capacity
for Internal Point-to-Point Service for each load served within a Local Network
or Network(s) during the month
URC = Aggregate of URCi for all Participants and Non-Participants
UAUi = The sum of a Participant's or Non-Participant's Maximum Unauthorized Use
associated with Internal Point-to-Point Service for each load served within a
Local Network or Network(s) during the month
UAU = Aggregate of UAUi for all Participants and Non-Participants
The Phase II Uplift Network Load (PIIli) of a Transmission Customer in a month
shall be its Network Load in that month, except as follows:
1) The Phase II Uplift Network Load (PIILi) for the Vermont Electric Power
Company shall be zero.
2) The Phase II Uplift Network Load (PIILi) for Central Maine Power Company
shall be zero.
3) The Phase II Uplift Network Load (PIIli) for Bangor Hydro-Electric Company
shall be 50 MW.
4) The total Phase II Uplift Load (PIILi) and URCi) shall be one half of the sum
of the Network Load and Reserved Capacity for Internal Point-to-Point Service
for the following Transmission Customers:
Commonwealth Electric Company
Cambridge Electric Company
Canal Electric Company
Montaup Electric Company on its own behalf and on behalf of the operating
affiliates of Eastern Utilities Associates
All Internal Point-to-Point Service shall be deemed to be under the NEPOOL and
LNS Tariffs rather than under an Excepted Transaction.
V. POINT-TO-POINT TRANSMISSION SERVICE
Preamble
Firm or Non-Firm Point-to-Point Transmission Service shall be reserved by all
Transmission Customers, whether Participants or Non-Participants, for all new
transfers to be effected as Internal Point-to-Point Service or as Through or Out
Service, pursuant to the applicable terms and conditions of Part III and this
Part V of the Tariff. Point-to-Point Transmission Service is the service
required for the receipt of capacity and/or energy at designated Point(s) of
Receipt and the transmission of such capacity and/or energy to designated
Point(s) of Delivery.
28 Scope of Application of Part V
Except for the deposit and creditworthiness requirement of Section 31.3, which
will apply only to Non-Participants, all of the requirements of this Part V
shall be fully applicable to both Participants and Non-Participants requesting
Internal Point-to-Point Service or Through or Out Service. Alternative deposit
and creditworthiness requirements are applicable to Participants under the
Financial Assurance Policy for NEPOOL Members which is set forth in Attachment L
hereto. Reservations under the Tariff shall not be required for the use of
Internal Point-to-Point Service for deliveries to the NEPOOL power exchange in
Interchange Transactions from a Point of Receipt within the NEPOOL Control Area,
but are required for the use of In Service for such deliveries from a Point of
Receipt at the NEPOOL Control Area boundary.
29 Nature of Firm Point-To-Point Transmission Service
29.1 Term: The minimum term of Firm Point-To-Point Transmission Service shall be
one day and the maximum term shall be that specified in the Service Agreement.
29.2 Reservation Priority: Long-Term Firm Point-To-Point Transmission Service
shall be available to Participants and Non-Participants on a first-come,
first-served basis, i.e., in the chronological sequence in which each
Transmission Customer's application for reserved service is received by the
System Operator pursuant to Section 31. Reservations for Short-Term Firm
Point-To-Point Transmission Service will be conditional based upon the length of
the requested transaction. If the NEPOOL Transmission System becomes
oversubscribed, requests for longer term service may preempt requests for
shorter term service up to the following deadlines: one day before the
commencement of daily service, one week before the commencement of weekly
service, and one month before the commencement of monthly service. Before the
conditional reservation deadline, if available transmission capability is
insufficient to satisfy all Applications, an Eligible Customer with a
reservation for shorter term service has the right of first refusal to match any
longer term reservation before losing its reservation priority. A longer term
competing request for Short-Term Firm Point-To-Point Transmission Service will
be granted if the Eligible Customer with the right of first refusal does not
agree to match the competing request within 24 hours (or earlier if necessary to
comply with the scheduling deadlines provided in Section 27.8) from being
notified by the System Operator of a longer-term competing request for
Short-Term Firm Point-To-Point Transmission Service. After the conditional
reservation deadline, service will commence pursuant to the terms of Part III of
this Tariff. Firm Point-To-Point Transmission Service will always have a
reservation priority over non-firm Point-To-Point Transmission Service under the
Tariff. All Long-Term Firm Point-To-Point Transmission Service will have
reservation priority equal to Native Load Customers, Network Customers and
customers for Excepted Transactions. Reservation priorities for existing firm
service customers, including customers receiving service with respect to
Excepted Transactions, are provided in Section 3.2.
29.3 Use of Firm Point-To-Point Transmission Service by the Participants That
Own PTF: A Transmission Provider that owns PTF will be subject to the rates,
terms and conditions of this Tariff when making Third-Party Sales to be
transmitted as Point-to-Point Transmission Service under (i) agreements executed
after November 1, 1996 or (ii) agreements executed on or before November 1, 1996
to the extent that the Commission requires them to be unbundled, by the date
specified by the Commission. A Transmission Provider that owns PTF will maintain
separate accounting, pursuant to Section 8, for any use of Firm Point-To-Point
Transmission Service to make Third-Party Sales to the extent not paid for under
this Tariff.
29.4 Service Agreements: A standard form Firm Point-To-Point Transmission
Service Agreement (Attachment A) will be offered to an Eligible Customer when it
submits a Completed Application for Long-Term or Short-Term Firm Point-To- Point
Transmission Service to be transmitted pursuant to this Tariff. Executed Service
Agreements that contain the information required under this Tariff will be filed
with the Commission in compliance with applicable Commission regulations.
29.5 Transmission Customer Obligations for Facility Additions or Redispatch
Costs: In cases where it is determined that the NEPOOL Transmission System is
not capable of providing new Firm Point-To-Point Transmission Service without
(1) degrading or impairing the reliability of service to Native Load Customers,
Network Customers, customers taking service for Excepted Transactions and other
Transmission Customers taking Firm Point-To-Point Transmission Service, or (2)
interfering with a Participant's ability to meet prior firm contractual
commitments to others, the Transmission Providers will be obligated to arrange
to expand or upgrade PTF for Long-Term Firm Service pursuant to the terms of
Section 33. The Transmission Customer must agree to compensate the Transmission
Providers or any other entity designated to effect construction through the
System Operator for any necessary transmission facility additions or upgrades
pursuant to the terms of Section 39. To the extent the System Operator can
relieve any system constraint more economically by redispatching the
Participants' resources, rather than through construction of additions or
upgrades, it shall do so, provided that the Eligible Customer agrees to
compensate the Participants pursuant to the terms of Section 39. Any redispatch,
addition or upgrade or Direct Assignment Facilities costs to be charged to the
Transmission Customer on an incremental basis under this Tariff will be
specified in the Service Agreement prior to initiating service.
29.6 Curtailment of Firm Transmission Service: In the event that a Curtailment
on the NEPOOL Transmission System, or a portion thereof, is required to maintain
reliable operation of the system, the Curtailment will be made on a
non-discriminatory basis to the transaction(s) that effectively relieve the
constraint. If multiple transactions require Curtailment, to the extent
practicable and consistent with Good Utility Practice, the System Operator will
curtail service to Network Customers and Transmission Customers taking Firm
Point- To-Point Transmission Service on a non-discriminatory basis. All
Curtailments will be made on a non-discriminatory basis; however, Non-Firm
Point-To-Point Transmission Service shall be subordinate to Firm Transmission
Service. When the System Operator determines that an electrical emergency exists
on the NEPOOL Transmission System and implements emergency procedures to effect
a Curtailment of Firm Transmission Service, the Transmission Customer shall make
the required reductions upon the System Operator's request. However, NEPOOL
reserves the right to effect a Curtailment, in whole or in part, of any Firm
Transmission Service provided under this Tariff when, in the System Operator's
sole discretion, an emergency or other unforeseen condition impairs or degrades
the reliability of the NEPOOL Transmission System. The System Operator will
notify all affected Transmission Customers in a timely manner of any scheduled
Curtailments. In the event the System Operator exercises its right to effect a
Curtailment, in whole or part, of Firm Point-to-Point Transmission Service, no
credit or other adjustment shall be provided as a result of the Curtailment with
respect to the charge payable by the Customer.
29.7 Classification of Firm Point-To-Point Transmission Service:
(a) A Transmission Customer taking Firm Point-To-Point Transmission Service may
(1) change its Points of Receipt and Delivery to obtain service on a non- firm
basis consistent with the terms of Section 36.1 or (2) request a modification of
the Points of Receipt or Delivery on a firm basis pursuant to the terms of
Section 36.2; provided that if any Transmission Provider or its designee
constructed new facilities or upgraded facilities to accommodate the original
firm service, such Transmission Provider or its designee shall continue to be
compensated for its facility costs by the Transmission Customer.
(b) A Transmission Customer may purchase transmission service to make sales from
multiple generating units or contracts that are on the NEPOOL Transmission
System. For such purchase of transmission service the Transmission Customer
shall specify a Location for each generating unit or contract.
(c) Deliveries will be provided from the Point(s) of Receipt to the Point(s) of
Delivery. Each Point of Receipt and Point of Delivery at which firm transmission
capacity is reserved for Long-Term Firm Point-to-Point Transmission Service by
the Transmission Customer shall be set forth in the Service Agreement for such
Service along with a corresponding capacity reservation. The greater of either
(1) the sum of the capacity reservations at the Point(s) of Receipt, or (2) the
sum of the capacity reservations at the Point(s) of Delivery shall be the
Transmission Customer's Reserved Capacity. The Transmission Customer will be
billed for its Reserved Capacity under the terms of Section 20 or Section 21,
whichever is applicable. The Transmission Customer's Use may not exceed its firm
capacity reserved at each Point of Receipt and each Point of Delivery except as
otherwise specified in Section 36. In the event that the Use by a Transmission
Customer (including Third-Party Sales by the Participants) exceeds that
Transmission Customer's Reserved Capacity at any Point of Receipt or Point of
Delivery in any hour, it shall pay 200% of the charge which is otherwise
applicable for each Kilowatt of the excess. In addition, the System Operator
will record all instances in which a Transmission Customer's Use exceeds that
Transmission Customer's firm Reserved Capacity, and if in any calendar year more
than 10 such instances occur with respect to any single Transmission Customer,
then the System Operator may require such Transmission Customer to apply for
additional Firm Point-to-Point Transmission Service under the Tariff in an
amount equal to the greatest amount of the excess of such Transmission
Customer's Use over its firm Reserved Capacity for the remainder of that
calendar year. Charges for such additional Firm Point-to-Point Transmission
Service will relate back to the first day of the month following the month in
which the System Operator notifies such Transmission Customer that it is subject
to the provisions of this paragraph.
29.8 Scheduling of Firm Point-To-Point Transmission Service:
(a) Until the CMS/MSS Effective Date, unless other schedules are permitted
pursuant to NEPOOL System Rules, schedules for the Transmission Customer's Firm
Point-To-Point Transmission Service (including schedules for resources to be
self scheduled) must be submitted to the System Operator no later than noon of
the day prior to commencement of such service. In the cases which are bid into
the power exchange, the Energy bid price must be submitted to the System
Operator by the noon deadline. Hour-to-hour schedules of any capacity and energy
that is to be delivered must be stated in increments of 1000 kW per hour.
Transmission Customers with multiple requests for Firm Point-To-Point
Transmission Service at a Point of Receipt, each of which request is under 1000
kW per hour, may consolidate their service requests at a common Point of Receipt
into units of 1000 kW per hour for scheduling and billing purposes. Scheduling
changes will be permitted up to thirty-five minutes before the start of the next
clock hour, provided that the Delivering Party and Receiving Party also agree to
the schedule modification. The System Operator will furnish to the Delivering
Party's system operator hour-to-hour schedules equal to those furnished by the
Receiving Party (unless reduced for losses) and will deliver the capacity and
energy provided by such schedules. Should the Transmission Customer, Delivering
Party or Receiving Party revise or terminate any schedule, such party shall
immediately notify the System Operator, and the System Operator will have the
right to adjust accordingly the schedule for capacity and energy to be received
and to be delivered.
(b) On and after the CMS/MSS Effective Date, unless other schedules are
permitted pursuant to the NEPOOL System Rules, Day-Ahead Market schedules for
the Transmission Customer's Firm Point-To-Point transmission service must be
submitted to the System Operator no later than noon of the day prior to the
Dispatch Day. The Supply Offers and Demand Bids must be submitted to the System
Operator by the noon deadline. The System Operator will furnish to the
Delivering Party's system operator hour-to-hour schedules equal to those
furnished by the Receiving Party and will deliver the capacity and Energy
provided by such schedules. Should the Transmission Customer, Delivering Party
or Receiving Party revise or terminate any schedule, such party shall
immediately notify the System Operator, and the System Operator will have the
right to adjust accordingly the schedule for capacity and Energy to be received
and to be delivered.
On and after the CMS/MSS Effective Date, unless other schedules are
permitted pursuant to the NEPOOL System Rules, Real-Time Market schedules for
the Transmission Customer's Firm Point-To-Point transmission service must be
submitted to the System Operator in accordance with the NEPOOL System Rules. The
Supply Offers and Demand Bids must be submitted to the System Operator in
accordance with the NEPOOL System Rules. Scheduling changes will be permitted up
to thirty-five minutes before the start of the next clock hour, provided that
the Delivering Party and Receiving Party also agree to the schedule
modification. The System Operator will furnish to the Delivering Party's system
operator hour-to-hour schedules equal to those furnished by the Receiving Party
and will deliver the capacity and Energy provided by such schedules. Should the
Transmission Customer, Delivering Party or Receiving Party revise or terminate
any schedule, such party shall immediately notify the System Operator, and the
System Operator will have the right to adjust accordingly the schedule for
capacity and Energy to be received and to be delivered.
30 Nature of Non-Firm Point-To-Point Transmission Service
30.1 Term: Non-Firm Point-To-Point Transmission Service will be available for
periods ranging from one hour to one month. However, a Purchaser of Non-Firm
Point-To-Point Transmission Service will be entitled to reserve a sequential
term of service (such as a sequential monthly term without having to wait for
the initial term to expire before requesting another monthly term) so that the
total time period for which the reservation applies is greater than one month,
subject to the requirements of Section 32.3.
30.3 Reservation Priority: Non-Firm Point-To-Point Transmission Service shall be
available from transmission capability in excess of that needed for reliable
service to Native Load Customers, Network Customers, customers for Excepted
Transactions and other Transmission Customers taking Long-Term and Short-Term
Firm Point-To-Point Transmission Service. A higher priority will be assigned to
reservations with a longer duration of service. In the event the NEPOOL
Transmission System is constrained, competing requests of equal duration will be
prioritized based on the highest price offered by the Eligible Customer for the
Transmission Service, or in the event the price for all Eligible Customers is
the same, will be prioritized on a first-come, first-served basis i.e., in the
chronological sequence in which each Customer has reserved service. Eligible
Customers that have already reserved shorter term service have the right of
first refusal to match any longer term reservation before being preempted. A
longer term competing request for Non- Firm Point-To-Point Transmission Service
will be granted if the Eligible Customer with the right of first refusal does
not agree to match the competing request: (a) immediately for hourly Non-Firm
Point-To-Point Transmission Service after notification by the System Operator;
and (b) within 24 hours (or earlier if necessary to comply with the scheduling
deadlines provided in Section 28.6) for Non-Firm Point-To-Point Transmission
Service other than hourly transactions after notification by the System
Operator. Secondary transmission service for Network Customers pursuant to
Section 40.4 will have a higher priority than any Non-Firm Point-To-Point
Transmission Service. Non-Firm Point-To-Point Transmission Service over
secondary Point(s) of Receipt and Point(s) of Delivery will have the lowest
reservation priority under this Tariff.
30.4 Use of Non-Firm Point-To-Point Transmission Service by the Transmission
Provider: A Transmission Provider will be subject to the rates, terms and
conditions of this Tariff when making Third-Party Sales to be transmitted as
Non-Firm Point-to-Point Transmission Service under (i) agreements executed after
November 1, 1996 or (ii) agreements executed on or before November 1, 1996 to
the extent that the Commission requires them to be unbundled, by the date
specified by the Commission. A Transmission Provider will maintain separate
accounting, pursuant to Section 8, for any use of Non-Firm Point-To- Point
Transmission Service to make Third-Party Sales, to the extent not paid for under
this Tariff.
30.5 Service Agreements: The System Operator shall offer a standard form
Point-To-Point Transmission Service Agreement (Attachment A, modified to cover
non-firm service) to an Eligible Customer when the Eligible Customer first
submits a Completed Application for Non-Firm Point-To-Point Transmission Service
pursuant to the Tariff. Executed Service Agreements that contain the information
required under this Tariff shall be filed with the Commission in compliance with
applicable Commission regulations.
30.6 Classification of Non-Firm Point-To-Point Transmission Service: Non-Firm
Point-To-Point Transmission Service shall be offered under applicable terms and
conditions contained in Part III of this Tariff. The NEPOOL Participants
undertake no obligation under this Tariff to plan the NEPOOL Transmission System
in order to have sufficient capacity for Non-Firm Point-To-Point Transmission
Service. Parties requesting Non-Firm Point-To-Point Transmission Service for the
transmission of firm power do so with the full realization that such service is
subject to availability and to Curtailment or Interruption under the terms of
this Tariff. In the event that the Use by a Transmission Customer (including
Third-Party Sales by a Participant) exceeds that Transmission Customer's
non-firm Reserved Capacity at any Point of Receipt or Point of Delivery, it
shall pay 200% of the charge which is otherwise applicable for each Kilowatt of
the excess. In addition, the System Operator will record all instances in which
a Transmission Customer's Use exceeds that Transmission Customer's non-firm
Reserved Capacity, and if in any calendar year more than 10 such instances occur
with respect to any single Transmission Customer, then the System Operator may
require such Transmission Customer to apply for additional Non-Firm
Point-to-Point Transmission Service under the Tariff in an amount equal to the
greatest amount of the excess of such Transmission Customer's Use over its
non-firm Reserved Capacity for the remainder of that calendar year. Charges for
such additional Non-Firm Point-to-Point Transmission Service will relate back to
the first day of the month following the month in which the System Operator
notifies such Transmission Customer that it is subject to the provisions of this
paragraph.
(a) Non-Firm Point-To-Point Transmission Service shall include transmission of
energy on an hourly basis and transmission of scheduled short-term capacity and
energy on a daily, weekly or monthly basis, but not to exceed one month's
reservation for any one Application.
(b) Each Point of Receipt at which non-firm transmission capacity is reserved by
the Transmission Customer shall be set forth in the Application along with a
corresponding capacity reservation associated with each Point of Receipt.
30.7 Scheduling of Non-Firm Point-To-Point Transmission Service:
(a) Until the CMS/MSS Effective Date, unless other schedules are permitted
pursuant to NEPOOL System Rules, schedules for Non-Firm Point-To-Point
Transmission Service must be submitted to the Transmission Provider no later
than noon of the day prior to commencement of such service. Schedules submitted
after noon will be accommodated, if practicable. Hour-to-hour schedules of
energy that is to be delivered must be stated in increments of 1,000 kW per
hour. Transmission Customers within the NEPOOL Control Area with multiple
requests for Transmission Service at a Point of Receipt, each of which is under
1,000 kW per hour, may consolidate their schedules at a common Point of Receipt
into units of 1,000 kW per hour. Scheduling changes will be permitted up to
thirty-five minutes before the start of the next clock hour provided that the
Delivering Party and Receiving Party also agree to the schedule modification.
The System Operator will furnish to the Delivering Party's system operator,
hour-to-hour schedules equal to those furnished by the Receiving Party (unless
reduced for losses) and shall deliver the capacity and energy provided by such
schedules. Should the Transmission Customer, Delivering Party or Receiving Party
revise or terminate any schedule, such party shall immediately notify the System
Operator, and the System Operator shall have the right to adjust accordingly the
schedule for capacity and energy to be received and to be delivered.
(b) On and after the CMS/MSS Effective Date, unless other schedules are
permitted pursuant to the NEPOOL System Rules, Day-Ahead Market schedules for
Non-Firm Point-To-Point Transmission Service must be submitted to the
Transmission Provider no later than noon of the day prior to the Dispatch Day.
The Supply Offers and Demand Bids must be submitted to the System Operator by
the noon deadline. The System Operator will furnish to the Delivering Party's
system operator hour-to-hour schedules equal to those furnished by the Receiving
Party and shall deliver the capacity and Energy provided by such schedules.
Should the Transmission Customer, Delivering Party or Receiving Party revise or
terminate any schedule, such party shall immediately notify the System Operator,
and the System Operator shall have the right to adjust accordingly the schedule
for capacity and Energy to be received and to be delivered.
On and after the CMS/MSS Effective Date, unless other schedules are
permitted pursuant to the NEPOOL System Rules, Real-Time Market schedules for
Non-Firm Point-To-Point Transmission Service must be submitted to the
Transmission Provider in accordance with the NEPOOL System Rules. The Supply
Offers and Demand Bids must be submitted to the System Operator in accordance
with the Market Rules. Scheduling changes will be permitted up to thirty-five
minutes before the start of the next clock hour provided that the Delivering
Party and Receiving Party also agree to the schedule modification. The System
Operator will furnish to the Delivering Party's system operator hour-to-hour
schedules equal to those furnished by the Receiving Party and shall deliver the
capacity and Energy provided by such schedules. Should the Transmission
Customer, Delivering Party or Receiving Party revise or terminate any schedule,
such party shall immediately notify the System Operator, and the System Operator
shall have the right to adjust accordingly the schedule for capacity and Energy
to be received and to be delivered.
30.8 Curtailment or Interruption of Service: The System Operator reserves the
right to effect a Curtailment, in whole or in part, of Non-Firm Point-To-Point
Transmission Service provided under this Tariff for reliability reasons when an
emergency or other unforeseen condition threatens to impair or degrade the
reliability of the NEPOOL Transmission System. The System Operator reserves the
right to effect an Interruption, in whole or in part, of Non-Firm Point-To-Point
Transmission Service provided under this Tariff for economic reasons in order to
accommodate (1) a request for Firm Transmission Service, (2) a request for
Non-Firm Point-To-Point Transmission Service of greater duration, or (3)
transmission service for Network Customers. The System Operator also will
discontinue or reduce service to the Transmission Customer to the extent that
deliveries for transmission are discontinued or reduced at the Point(s) of
Receipt. Where required, Curtailments or Interruptions will be made on a
non-discriminatory basis to the transaction(s) that effectively relieve the
constraint; however, Non-Firm Point-To-Point Transmission Service shall be
subordinate to Firm Transmission Service. If multiple transactions require
Curtailment or Interruption, to the extent practicable and consistent with Good
Utility Practice, Curtailments or Interruptions will be made to transactions of
the shortest term (e.g., hourly non-firm transactions will be Curtailed or
Interrupted before daily non-firm transactions and daily non-firm transactions
will be Curtailed or Interrupted before weekly non-firm transactions).
Transmission service for Network Customers will have a higher priority than any
Non-Firm Point-To-Point Transmission Service under this Tariff. Non-Firm
Point-To- Point Transmission Service furnished over secondary Point(s) of
Receipt and Point(s) of Delivery will have a lower priority than any other
Non-Firm Point-To-Point Transmission Service under this Tariff. The System
Operator will provide advance notice of Curtailment or Interruption where such
notice can be provided consistent with Good Utility Practice. In the event the
System Operator exercises its right to effect a Curtailment, in whole or part,
of Non-Firm Point-to-Point Transmission Service, no credit or other adjustment
shall be provided as a result of the Curtailment with respect to the charge
payable by the Customer. In the event the System Operator exercises its right to
effect an Interruption, in whole or part, of Non-Firm Point-to-Point
Transmission Service, the charge payable by the Customer shall be computed as if
the term of service actually rendered were the term of service reserved;
provided that an adjustment of the charge shall be made only when the
Interruption is initiated by the System Operator, not when the Customer fails to
deliver energy to NEPOOL.
31 Service Availability
31.1 General Conditions: Firm Point-To-Point Transmission Service over, on or
across the NEPOOL Transmission System is available to any Transmission Customer
that has met the applicable requirements of Section 31.
31.2 Determination of Available Transmission Capability: A description of
NEPOOL's specific methodology for assessing available transmission capability
posted on the NEPOOL OASIS(Section 5) is contained in Attachment C of this
Tariff. In the event sufficient transmission capability may not exist to
accommodate a service request, a System Impact Study will be performed.
31.3 Initiating Service in the Absence of an Executed Service Agreement: If the
System Operator and the Transmission Customer requesting Firm Point-To- Point
Transmission Service cannot agree on all the terms and conditions of the
applicable Service Agreement, the System Operator will file with the Commission,
within thirty days after the date the Transmission Customer provides written
notification directing the System Operator to file, an unexecuted Service
Agreement containing terms and conditions deemed appropriate by the System
Operator for such requested transmission service. The service will be commenced
subject to the Transmission Customer agreeing to (i) pay whatever rate the
Commission ultimately determines to be just and reasonable, and (ii) comply with
the terms and conditions of this Tariff including providing appropriate security
deposits in accordance with the terms of Section 31.3.
31.4 Obligation to Provide Transmission Service that Requires Expansion or
Modification of the Transmission System: If it is determined that the service
requested in a Completed Application for Long-Term Firm Point-To- Point
Transmission Service cannot be provided because of insufficient capability on
the NEPOOL Transmission System, one or more Transmission Providers or other
entities will be designated to use due diligence to expand or modify the NEPOOL
Transmission System to provide the requested Long-Term Firm Point-To-Point
Transmission Service, provided that the Transmission Customer agrees to
compensate the Transmission Providers or other entities that will be responsible
for the construction of any new facilities or upgrades for the costs of such new
facilities or upgrades pursuant to the terms of Section 39. The System Operator
and the designated Transmission Providers or other entities will conform to Good
Utility Practice in determining the need for new transmission facilities or
upgrades and in coordinating the design and construction of such facilities.
This obligation applies only to those facilities that the designated
Transmission Providers or other entities have the right to expand or modify.
31.5 Deferral of Service: Long-Term Firm Point-To-Point Transmission Service may
be deferred until the designated Transmission Providers or other entities
complete construction of new transmission facilities or upgrades needed to
provide such service whenever it is determined that providing the requested
service would, without such new facilities or upgrades, impair or degrade
reliability to any existing Firm Transmission Service.
31.6 Real Power Losses: Real power losses are associated with all transmission
service. The Transmission Provider is not obligated to provide real power
losses. Until the CMS/MSS Effective Date, to the extent PTF losses are not
specifically allocated through the market procedures provided for in Section 14
of the Agreement, point-to-point losses will be allocated on the basis of PTF
average losses as established by the System Operator. The System Operator shall
post on the OASIS the PTF average loss, which is initially set at 1.13% but
shall be adjusted by the System Operator from time to time. The applicable real
power loss factor shall be determined on the basis of PTF average losses.
Average PTF losses shall be determined initially on an estimated basis, pending
the accumulation of metered data needed to determine actual average PTF losses.
On and after the CMS/MSS Effective Date, the cost of PTF losses shall be
recovered through the Marginal Loss cost recovery mechanisms provided for in
Section 14A.16 of the Agreement and Schedule 13 of the Tariff.
31.7 Load Shedding: To the extent that a system contingency exists on the NEPOOL
Transmission System and the System Operator determines that it is necessary for
the Participants and the Transmission Customer to shed load, the Parties shall
shed load in accordance with the procedures under the Agreement and the rules
adopted thereunder, or in accordance with other mutually agreed-to provisions.
32 Transmission Customer Responsibilities
32.2 Conditions Required of Transmission Customers: Firm Point-To-Point
Transmission Service will be provided only if the following conditions are
satisfied by the Transmission Customer:
a. The Transmission Customer has pending a Completed Application for
service;
b. In the case of a Non-Participant, the Transmission Customer meets the
creditworthiness criteria set forth in Section 11;
c. The Transmission Customer will have arrangements in place for any other
transmission service necessary to effect the delivery from the generating source
to the Point of Receipt prior to the time service under the Tariff commences;
d. The Transmission Customer agrees to pay for any facilities or upgrades
constructed or any redispatch costs chargeable to such Transmission Customer
under this Tariff, whether or not the Transmission Customer takes service for
the full term of its reservation; and
e. The Transmission Customer has executed a Service Agreement or has agreed
to receive service pursuant to Section 29.3.
32.3 Transmission Customer Responsibility for Third-Party Arrangements: Any
scheduling arrangements that may be required by other electric systems shall be
the responsibility of the Transmission Customer requesting service. (If Local
Network Service will be required, the System Operator shall notify the
Transmission Customer and the affected Participants.) The Transmission Customer
shall provide, unless waived by the System Operator, notification to the System
Operator identifying such other electric systems and authorizing them to
schedule the capacity and energy to be transmitted pursuant to this Tariff on
behalf of the Receiving Party at the Point of Delivery or the Delivering Party
at the Point of Receipt. The System Operator will undertake reasonable efforts
to assist the Transmission Customer in making such arrangements, including
without limitation, providing any information or data required by such other
electric system pursuant to Good Utility Practice.
33 Procedures for Arranging Firm Point-To-Point Transmission Service
33.1 Application: A request for Firm Point-To-Point Transmission Service for
periods of one year or longer must be made in an Application, delivered to ISO
New England Inc., One Sullivan Road, Holyoke, MA 01040-2841 or such other
address as may be specified from time to time. The request should be delivered
at least sixty days in advance of the calendar month in which service is
requested to commence. The System Operator will consider requests for such firm
service on shorter notice when practicable. Requests for firm service for
periods of less than one year will be subject to expedited procedures that will
be negotiated between the System Operator and the party requesting service
within the time constraints provided in Section 27.8. All Firm Point-To-Point
Transmission Service requests should be submitted by transmitting the Completed
Application to NEPOOL by mail or telefax. Each of these methods will provide a
time-stamped record for establishing the priority of the Application.
33.2 Completed Application: A Completed Application for Firm Point-To-Point
Transmission Service shall provide all of the information included at 18 C.F.R.
2.20 of the Commission's regulations, including but not limited to the
following:
(i) The identity, address, telephone number and facsimile number of the
entity requesting service;
(ii) A statement that the entity requesting service is, or will be upon
commencement of service, an Eligible Customer under this Tariff;
(iii) The location of the Point(s) of Receipt and Point(s) of Delivery and
the identities of the Delivering Parties and the Receiving Parties;
(iv) The location of the generating facility(ies) supplying the capacity and
energy, and the location of the load ultimately served by the capacity and
energy transmitted. The System Operator will treat this information as
confidential in accordance with the NEPOOL information policy except to the
extent that disclosure of this information is required by this Tariff, by
regulatory or judicial order, or for reliability purposes pursuant to Good
Utility Practice. The System Operator will treat this information consistent
with the standards of conduct contained in 18 C.F.R. Part 37 of the Commission's
regulations;
(v) A description of the supply characteristics of the capacity and energy
to be delivered;
(vi) An estimate of the capacity and energy expected to be delivered to the
Receiving Party;
(vii) The Service Commencement Date and the term of the requested
transmission service; and
(viii) The transmission capacity requested for each Point of Receipt and each
Point of Delivery on the NEPOOL Transmission System; customers may combine their
requests for service in order to satisfy the minimum transmission capacity
requirement.
The System Operator will treat this information consistent with the standards of
conduct contained in 18 C.F.R. Part 37 of the Commission's regulations.
33.3 Deposit: A Completed Application for Firm Point-To-Point Transmission
Service by a Non-Participant shall also include a deposit of either one month's
charge for Reserved Capacity or the full charge for Reserved Capacity for
service requests of less than one month. If the Application is rejected by the
System Operator because it does not meet the conditions for service as set forth
herein, or in the case of requests for service arising in connection with losing
bidders in a request for proposals (RFP), the deposit will be returned with
Interest, less any reasonable Administrative Costs incurred by the System
Operator or any affected Participants in connection with the review of the
Application. The deposit also will be returned with Interest less any reasonable
Administrative Costs incurred by the System Operator or any affected
Participants if the new facilities or upgrades needed to provide the service
cannot be completed. If an Application is withdrawn or the Eligible Customer
decides not to enter into a Service Agreement for the Service, the deposit will
be refunded in full, with Interest, less reasonable Administrative Costs
incurred by the System Operator or any affected Participants to the extent such
costs have not already been recovered from the Eligible Customer. The System
Operator will provide to the Eligible Customer a complete accounting of all
costs deducted from the refunded deposit, which the Eligible Customer may
contest if there is a dispute concerning the deducted costs. Deposits associated
with construction of new facilities or upgrades are subject to the provisions of
Section 33. If a Service Agreement for Firm Point-To-Point Transmission Service
is executed, the deposit, with interest, will be returned to the Transmission
Customer upon expiration or termination of the Service Agreement. Applicable
Interest will be calculated from the day the deposit is credited to the System
Operator's account.
33.4 Notice of Deficient Application: If an Application fails to meet the
requirements of this Tariff, the System Operator will notify the entity
requesting service within fifteen days of the System Operator's receipt of the
Application of the reasons for such failure. The System Operator will attempt to
remedy minor deficiencies in the Application through informal communications
with the Eligible Customer. If such efforts are unsuccessful, the System
Operator will return the Application, along with any deposit (less the
reasonable Administrative Costs incurred by the System Operator or any affected
Participants in connection with the Application), with Interest. Upon receipt of
a new or revised Application that fully complies with the requirements of this
Tariff, the Eligible Customer will be assigned a new priority based upon the
date of receipt by the System Operator of the new or revised Application.
33.5 Response to a Completed Application: Following receipt of a Completed
Application for Firm Point-To-Point Transmission Service, a determination of
available transmission capability will be made pursuant to Section 29.2. The
Eligible Customer will be notified as soon as practicable, but not later than
thirty days after the date of receipt of a Completed Application, if required,
that either (i) service will be provided without performing a System Impact
Study, or (ii) such a study is needed to evaluate the impact of the Application
pursuant to Section 33.1. Responses by the System Operator must be made as soon
as practicable to all Completed Applications and the timing of such responses
must be made on a non-discriminatory basis.
33.6 Execution of Service Agreement: Whenever the System Operator determines
that a System Impact Study is not required and that the requested service can be
provided, it will notify the Eligible Customer as soon as practicable but no
later than thirty days after receipt of the Completed Application, and will
tender a Service Agreement to the Eligible Customer. Failure of an Eligible
Customer to execute and return the Service Agreement or request the filing of an
unexecuted Service Agreement pursuant to Section 29.3, within fifteen days after
it is tendered by the System Operator shall be deemed a withdrawal and
termination of the Application and any deposit (less the reasonable
Administrative Costs incurred by the System Operator and any affected
Participants in connection with the Application) submitted will be refunded with
Interest. Nothing herein limits the right of an Eligible Customer to file
another Application after such withdrawal and termination. Where a System Impact
Study is required, the provisions of Section 33 will govern the execution of a
Service Agreement.
33.7 Extensions for Commencement of Service: The Transmission Customer can
obtain up to five one-year extensions for the commencement of service. The
Transmission Customer may postpone service by paying a non-refundable annual
reservation fee equal to one-month's charge for Firm Point-To-Point Transmission
Service for each year or fraction thereof. If during any extension for the
commencement of service an Eligible Customer submits a Completed Application for
Firm Point-To-Point Transmission Service, and such request can be satisfied only
by releasing all or part of the Transmission Customer's Reserved Capacity, the
original Reserved Capacity will be released unless the following condition is
satisfied: within thirty days, the original Transmission Customer agrees to pay
the applicable rate for Firm Point-To- Point Transmission Service for its
Reserved Capacity for the period that its reservation overlaps the period
covered by such Eligible Customer's Completed Application. In the event the
Transmission Customer elects to release the Reserved Capacity, the reservation
fees or portions thereof previously paid will be forfeited.
34 Procedures for Arranging Non-Firm Point-To-Point Transmission Service
34.1 Application: Eligible Customers seeking Non-Firm Point-To-Point
Transmission Service must submit a Completed Application to the System Operator.
Applications should be submitted by entering the information listed below on the
NEPOOL OASIS.
34.2 Completed Application: A Completed Application shall provide all of the
information included in 18 C.F.R. 2.20 including but not limited to the
following:
(i) The identity, address, telephone number and facsimile number of the
entity requesting service;
(ii) A statement that the entity requesting service is, or will be upon
commencement of service, an Eligible Customer under this Tariff;
(iii) The Point(s) of Receipt and the Point(s) of Delivery;
(iv) The maximum amount of capacity requested at each Point of Receipt and
Point of Delivery; and
(v) The proposed dates and hours for initiating and terminating
transmission service hereunder.
In addition to the information specified above, when required to properly
evaluate system conditions, the System Operator also may ask the Transmission
Customer to provide the following:
(vi) The electrical location of the initial source of the power to be
transmitted pursuant to the Transmission Customer's request for service; and
(vii) The electrical location of the ultimate load.
The System Operator will treat this information in (vi) and (vii) as
confidential at the request of the Transmission Customer except to the extent
that disclosure of this information is required by this Tariff, by regulatory or
judicial order, or for reliability purposes pursuant to Good Utility Practice.
The System Operator shall treat this information consistent with the standards
of conduct contained in Part 37 of the Commission's regulations.
34.3 Reservation of Non-Firm Point-To-Point Transmission Service: Requests for
monthly service shall be submitted no earlier than sixty days before service is
to commence; requests for weekly service shall be submitted no earlier than
fourteen days before service is to commence; requests for daily service shall be
submitted no earlier than five days before service is to commence; and requests
for hourly service shall be submitted no earlier than 9:00 a.m. the second day
before service is to commence. Requests for service received later than noon of
the day prior to the day service is scheduled to commence will be accommodated
if practicable.
34.4 Determination of Available Transmission Capability: Following receipt of a
tendered schedule the System Operator will make a determination on a
non-discriminatory basis of available transmission capability pursuant to
Section 29.2. Such determination shall be made as soon as reasonably practicable
after receipt, but not later than the following time periods for the following
terms of service (i) thirty-five minutes for hourly service, (ii) thirty-five
minutes for daily service, (iii) four hours for weekly service, and (iv) two
days for monthly service.
35 Additional Study Procedures For Firm Point-To-Point Transmission Service
Requests
35.1 Notice of Need for System Impact Study: After receiving a request for Firm
Point-To-Point Transmission Service, the System Operator will review the effect
of the proposed service on the reliability requirements to meet existing and
pending obligations of the Participants and Non-Participants, and the
obligations of the particular Participants whose PTF facilities will be impacted
by the proposed service and determine on a non-discriminatory basis whether a
System Impact Study is needed. A description of the methodology for completing a
System Impact Study is provided in Attachment D. If the System Operator
determines that a System Impact Study is necessary to accommodate the requested
service, as soon as practicable thereafter the System Operator will so inform
the Eligible Customer and any affected Participants if the System Impact Study
is to be performed by the Participants. If the likely result of the study is
that a Direct Assignment Facility will be required, the study shall be performed
by the affected Participants, subject to review by the System Operator. In such
cases, the System Operator will within thirty days of receipt of a Completed
Application, tender a System Impact Study agreement in the form of Exhibit I to
this Tariff, or in any other form that is mutually agreed to, pursuant to which
the Eligible Customer shall agree to reimburse the System Operator and any
affected Participants for performing the required System Impact Study. For a
service request to remain a Completed Application, the Eligible Customer shall
execute the System Impact Study agreement and return it to the System Operator
within fifteen days. If the Eligible Customer elects not to execute a System
Impact Study agreement, its application shall be deemed withdrawn and its
deposit (less the reasonable Administrative Costs incurred by the System
Operator and any affected Participants in connection with the Application), will
be returned with Interest.
35.2 System Impact Study Agreement and Cost Reimbursement:
(i) The System Impact Study agreement shall clearly specify the System
Operator's estimate of the actual cost, and time for completion of the System
Impact Study. The charge shall not exceed the actual cost of the study. In
performing the System Impact Study, the System Operator and any affected
Participants will rely, to the extent reasonably practicable, on existing
transmission planning studies. The Eligible Customer shall not be assessed a
charge for such existing studies; however, the Eligible Customer shall be
responsible for charges associated with any modifications to existing planning
studies that are reasonably necessary to evaluate the impact of the Eligible
Customer's request for service on the NEPOOL Transmission System.
(ii) If in response to multiple Eligible Customers requesting service in
relation to the same competitive solicitation, a single System Impact Study is
sufficient for the System Operator to accommodate the requests for service, the
costs of that study will be equitably prorated among the Eligible Customers.
(iii) For System Impact Studies that the System Operator and any affected
Participants conduct on behalf of the Transmission Providers, the Participants
will record the cost of the System Impact Studies pursuant to Section 8.5.
35.3 System Impact Study Procedures: Upon receipt of an executed System Impact
Study agreement, the System Operator and any affected Participants will use due
diligence to complete the required System Impact Study within a sixty-day
period. The System Impact Study, if required, shall identify any system
constraints and redispatch options and the need for additional Direct Assignment
Facilities or facility additions or upgrades required to provide the requested
service. In the event that the required System Impact Study cannot be completed
within such time period, the System Operator will so notify the Eligible
Customer and provide an estimated completion date along with an explanation of
the reasons why additional time is required to complete the required study and
an estimate of any increase in cost which will result from the delay. A copy of
the completed System Impact Study and related work papers shall be made
available to the Eligible Customer. The System Operator will use the same due
diligence in completing the System Impact Study for an Eligible Customer that is
a Non-Participant as it uses when completing studies for the Participants. The
System Operator will notify the Eligible Customer immediately upon completion of
the System Impact Study if the NEPOOL Transmission System will be adequate to
accommodate all or part of a request for service or that no costs are likely to
be incurred for new transmission facilities or upgrades. Within fifteen days of
completion of the System Impact Study, the Eligible Customer must execute a
Service Agreement or request the filing of an unexecuted Service Agreement
pursuant to Section 29.3, or the Application shall be deemed terminated and
withdrawn.
35.4 Facilities Study Procedures: If a System Impact Study indicates that
additions or upgrades to the NEPOOL Transmission System are needed to supply the
Eligible Customer's service request, the System Operator, within thirty days of
the completion of the System Impact Study, will tender to the Eligible Customer
a Facilities Study agreement in the form of Attachment J to this Tariff, or in
any other form that is mutually agreed to, which is to be entered into by the
Eligible Customer and the System Operator and, if deemed necessary by the System
Operator, by one or more affected Transmission Provider(s) and pursuant to which
the Eligible Customer shall agree to reimburse the System Operator and any
affected Transmission Providers or other entity designated by the System
Operator for performing any required Facilities Study. For a service request to
remain a Completed Application, the Eligible Customer shall execute the
Facilities Study agreement and return it to the System Operator within fifteen
days. If the Eligible Customer elects not to execute the Facilities Study
agreement, its application shall be deemed withdrawn and its deposit, if any
(less the reasonable Administrative Costs incurred by the System Operator and
any affected Participants in connection with the Application), will be returned
with Interest. Upon receipt of an executed Facilities Study agreement, the
System Operator and any affected Transmission Provider(s) or other designated
entity will use due diligence to cause the required Facilities Study to be
completed within a sixty-day period. If a Facilities Study cannot be completed
in the allotted time period, the System Operator will notify the Transmission
Customer and provide an estimate of the time needed to reach a final
determination and any resulting increase in the cost, along with an explanation
of the reasons that additional time is required to complete the study. When
completed, the Facilities Study shall include a good faith estimate of (i) the
cost of Direct Assignment Facilities to be charged to the Transmission Customer,
or (ii) the Transmission Customer's appropriate share of the cost of any
required additions or upgrades, and (iii) the time required to complete such
construction and initiate the requested service. The Transmission Customer shall
provide a letter of credit or other reasonable form of security acceptable to
the Transmission Providers or other entities that will be responsible for the
construction of the new facilities or upgrades equivalent to the costs of the
new facilities or upgrades and consistent with relevant commercial practices, as
established by the Uniform Commercial Code. The Transmission Customer shall have
thirty days to execute a Service Agreement, if required, or request the filing
of an unexecuted Service Agreement with the Commission and provide the required
letter of credit or other form of security or the request will no longer be a
Completed Application and shall be deemed terminated and withdrawn.
In addition to the foregoing, each Facilities Study shall contain a non-
binding estimate from the System Operator of the incremental FCRs and associated
ARRs, if any, resulting from the construction of the new facilities. After
completion of the transmission upgrade or expansion, the System Operator shall
determine the incremental FCRs and associated ARRs, if any, resulting from the
upgrade or expansion.
35.5 Facilities Study Modifications: Any change in design arising from inability
to site or construct proposed facilities will require development of a revised
good faith estimate. New good faith estimates also will be required in the event
of new statutory or regulatory requirements that are effective before the
completion of construction or other circumstances beyond the control of the
Transmission Providers or other entities that are responsible for the
construction of the new facilities or upgrades and that significantly affect the
final cost of the new facilities or upgrades to be charged to the Transmission
Customer pursuant to the provisions of this Tariff.
35.6 Due Diligence in Completing New Facilities: The System Operator will use
due diligence to designate Transmission Providers or other entities to add
necessary facilities or upgrade the NEPOOL Transmission System within a
reasonable time. A Transmission Provider or other entity will have no obligation
to upgrade its existing or planned transmission system in order to provide the
requested Firm Point-To-Point Transmission Service if doing so would impair
system reliability or otherwise impair or degrade existing firm service.
35.7 Partial Interim Service: If the System Operator determines that there will
not be adequate transmission capability to satisfy the full amount of a
Completed Application for Long-Term Firm Point-To-Point Transmission Service,
the portion of the requested Service that can be accommodated without addition
of any facilities or upgrades and through redispatch will be offered and
provided. However, there shall be no obligation to provide the incremental
amount of requested Long-Term Firm Point-To-Point Transmission Service that
requires the addition of facilities or upgrades to the NEPOOL Transmission
System until such facilities or upgrades have been placed in service.
35.8 Expedited Procedures for New Facilities: In lieu of the procedures set
forth above, the Eligible Customer shall have the option to expedite the process
by requesting the System Operator to tender at one time, together with the
results of required studies, an "Expedited Service Agreement" pursuant to which
the Eligible Customer would agree to pay for all costs incurred pursuant to the
terms of this Tariff. In order to exercise this option, the Eligible Customer
shall request in writing an Expedited Service Agreement covering all of the
above-specified items within thirty days of receiving the results of the System
Impact Study identifying the need for facility additions or upgrades and costs
to be incurred in providing the requested service. While the System Operator, on
behalf of the Transmission Providers or other entities that will be responsible
for constructing the new facilities or upgrades, agrees to provide the Eligible
Customer with its best estimate of the new facility costs and other charges that
may be incurred, such estimate shall not be binding and the Eligible Customer
shall agree in writing to pay for all costs incurred pursuant to the provisions
of this Tariff. The Eligible Customer shall execute and return such an Expedited
Service Agreement within fifteen days of its receipt or the Eligible Customer's
request for service will cease to be a Completed Application and will be deemed
terminated and withdrawn.
36 Procedures if New Transmission Facilities for Firm Point-To-Point
Transmission Service Cannot be Completed
36.1 Delays in Construction of New Facilities: If any event occurs that will
materially affect the time for completion of new facilities for Firm
Point-To-Point Service, or the ability to complete such facilities, the System
Operator will promptly notify the Transmission Customer. In such circumstances,
the System Operator will within thirty days of notifying the Transmission
Customer of such delays, convene a technical meeting with the Transmission
Customer and any affected Transmission Providers or other entities responsible
for construction to evaluate the alternatives available to the Transmission
Customer. The System Operator and the affected Transmission Providers or other
entities will make available to the Transmission Customer studies and work
papers related to the delay, including all information that is in the possession
of the System Operator or the Transmission Providers or other entities that are
responsible for the construction of the new facilities or upgrades that is
reasonably needed by the Transmission Customer to evaluate any alternatives.
36.2 Alternatives to the Original Facility Additions: When the review process of
Section 34.1 determines that one or more alternatives exist to the originally
planned construction project, the System Operator will present such alternatives
for consideration by the Transmission Customer. If, upon review of any
alternatives, the Transmission Customer desires to proceed with its Completed
Application subject to construction of the alternative facilities, it may
request the System Operator to submit a revised Service Agreement. If the
alternative approach solely involves Non-Firm Point-To-Point Transmission
Service, the System Operator will promptly tender a Service Agreement for
Non-Firm Point-To-Point Transmission Service providing for such service. In the
event the System Operator and the affected Participants or other entities
responsible for construction conclude that no reasonable alternative exists and
the Transmission Customer disagrees, the Transmission Customer may seek relief
under the dispute resolution procedures pursuant to Section 12 or it may refer
the dispute to the Commission for resolution.
36.3 Refund Obligation for Unfinished Facility Additions: If the System
Operator, the affected Transmission Providers or other entities responsible for
construction and the Transmission Customer mutually agree that no other
reasonable alternatives exist and the requested service cannot be provided out
of existing capability under the conditions of this Tariff, the obligation to
provide the requested Firm Point-To-Point Transmission Service shall terminate
and any deposit made by the Transmission Customer shall be returned, with
Interest. The Transmission Customer shall be responsible for all costs prudently
incurred by the System Operator and by the Transmission Providers or other
entities that have been responsible for the construction of the new facilities
or upgrades through the date that any required regulatory approval is denied or
construction is suspended and for cost of removal, if necessary, of facilities
constructed prior to suspension.
37 Provisions Relating to Transmission Construction and Services on the
Systems of Other Utilities
37.1 Responsibility for Third-Party System Additions: Neither the System
Operator nor any Participant which is not the Transmission Customer will be
responsible for making arrangements for any necessary engineering, permitting,
and construction of transmission or distribution facilities on the system(s) of
any other entity or for obtaining any regulatory approval for such facilities.
The System Operator will undertake reasonable efforts to assist the Transmission
Customer in obtaining such arrangements, including without limitation, providing
any information or data required by such other electric system pursuant to Good
Utility Practice.
37.2 Coordination of Third-Party System Additions: In circumstances where the
need for transmission facilities or upgrades is identified pursuant to the
provisions of this Tariff, and if such upgrades further require the addition of
transmission facilities on third-party systems, the System Operator and the
Transmission Providers or other entities that are responsible for the
construction of any new facilities or upgrades on the NEPOOL Transmission System
will have the right to coordinate construction on the NEPOOL Transmission System
with the construction required by the third parties. The System Operator and the
Transmission Providers or other entities that are responsible for the
construction of any new facilities or upgrades on the NEPOOL Transmission System
may, after consultation with the Transmission Customer and representatives of
such other systems, defer construction of new transmission facilities or
upgrades on the NEPOOL Transmission System if the new transmission facilities on
another system cannot be completed in a timely manner. The System Operator will
notify the Transmission Customer in writing of the basis for any decision to
defer construction and the specific problems that must be resolved before the
construction of new facilities will be initiated or resumed. Within sixty days
of receiving written notification by the System Operator of a decision to defer
construction pursuant to this section, the Transmission Customer may challenge
the decision in accordance with the dispute resolution procedures contained in
Section 12 or it may refer the dispute to the Commission for resolution.
38 Changes in Service Specifications
38.1 Modifications on a Non-Firm Basis: The Transmission Customer taking Firm
Point-To-Point Transmission Service may submit a request to the System Operator
for transmission service on a non-firm basis over Point(s) of Receipt and
Point(s) of Delivery other than those specified in the Service Agreement
("Secondary Receipt and Delivery Points"), in amounts not to exceed the
Transmission Customer's firm capacity reservation, without incurring an
additional Non-Firm Point-to-Point Transmission Service charge or executing a
new Service Agreement, subject to the following conditions:
(a) service provided over Secondary Receipt and Delivery Points will be non-firm
only, on an as-available basis, and will not displace any firm or non-firm
service reserved or scheduled by Participants or Non-Participants under this
Tariff or by the Participants on behalf of their Native Load Customers or
Excepted Transactions;
(b) the sum of all Firm Point-To-Point Transmission Service and Non-Firm
Point-To-Point Transmission Service provided to the Transmission Customer at any
time pursuant to this section shall not exceed the Reserved Capacity specified
in the relevant Service Agreement under which such services are provided;
(c) the Transmission Customer shall retain its right to schedule Firm
Point-To-Point Transmission Service at the Point(s) of Receipt and Point(s) of
Delivery specified in the relevant Service Agreement in the amount of the
Transmission Customer's original capacity reservation; and
(d) service over Secondary Receipt and Delivery Points on a non-firm basis shall
not require the filing of an Application for Non-Firm Point-to-Point
Transmission Service under the Tariff. However, all other requirements of this
Tariff (except as to transmission rates) shall apply to transmission service on
a non-firm basis over Secondary Receipt and Delivery Points.
38.2 Modification on a Firm Basis: Any request by a Transmission Customer to
modify Point(s) of Receipt and Point(s) of Delivery on a firm basis shall be
treated as a new request for service in accordance with Section 31, except that
such Transmission Customer shall not be obligated to pay any additional deposit
if the capacity reservation does not exceed the amount reserved in the existing
Service Agreement. While such new request is pending, the Transmission Customer
shall retain its priority for service at the firm Receipt Point(s) and Delivery
Point(s) specified in the Transmission Customer's Service Agreement.
39 Sale, Assignment or Transfer of Transmission Service
39.1 Procedures for Sale, Assignment or Transfer of Service: Subject to
Commission action on any necessary filings, a Transmission Customer may sell,
assign, or transfer all or a portion of its rights under its Service Agreement,
but only to another Eligible Customer (the "Assignee"). The Transmission
Customer that sells, assigns or transfers its rights under its Service Agreement
is hereafter referred to as the "Reseller." Compensation to the Reseller shall
not exceed the higher of (i) the original rate paid by the Reseller, (ii) the
maximum applicable rate on file under this Tariff at the time of the assignment,
or (iii) the Reseller's opportunity cost capped at the Participants' cost of
expansion. If the Assignee does not request any change in the Point(s) of
Receipt or the Point(s) of Delivery, or a change in any other term or condition
set forth in the original Service Agreement, the Assignee shall receive the same
services as did the Reseller and the priority of service for the Assignee shall
be the same as that of the Reseller. A Reseller shall notify the System Operator
as soon as possible after any sale, assignment or transfer of service occurs,
but in any event, notification must be provided prior to any provision of
service to the Assignee. The Assignee shall be subject to all terms and
conditions of this Tariff. If the Assignee requests a change in service, the
reservation priority of service will be determined by the System Operator
pursuant to Section 27.2.
The sale, resale or assignment of FCRs is governed by Schedule 14 of the
Tariff, and this Section 37.1 is not applicable to such sales, resales and
assignments.
39.2 Limitations on Assignment or Transfer of Service: If the Assignee requests
a change in the Point(s) of Receipt or Point(s) of Delivery, or a change in any
other specifications set forth in the original Service Agreement, the System
Operator will consent to such change subject to the provisions of this Tariff,
provided that the change will not impair the operation and reliability of the
Participants' generation, transmission, or distribution systems. The Assignee
shall compensate the System Operator and any affected Participants for
performing any System Impact Study needed to evaluate the capability of the
NEPOOL Transmission System to accommodate the proposed change and any additional
costs resulting from such change. The Reseller shall remain liable for the
performance of all obligations under the Service Agreement, except as
specifically agreed to by the System Operator, the Reseller and the Assignee
through an amendment to the Service Agreement.
39.3 Information on Assignment or Transfer of Service: In accordance with
Section 5, Transmission Customers may use the NEPOOL OASIS to post information
regarding transmission capacity available for resale.
40 Metering and Power Factor Correction at Receipt and Delivery Points(s)
40.1 Transmission Customer Obligations: Unless the System Operator otherwise
agrees, the Transmission Customer shall be responsible for installing and
maintaining compatible metering and communications equipment to accurately
account for the capacity and energy being transmitted under this Tariff and to
communicate the information to the System Operator. Unless otherwise agreed,
such equipment shall remain the property of the Transmission Provider.
40.2 NEPOOL Access to Metering Data: The System Operator will have access to
such metering data as may reasonably be required to facilitate measurements and
billing under the Service Agreement.
40.3 Power Factor: Unless otherwise agreed, the Transmission Customer is
required to maintain a power factor within the same range as the Participants
maintain pursuant to Good Utility Practice and applicable NEPOOL requirements.
The power factor requirements are specified in the Service Agreement, where
applicable.
41 Compensation for New Facilities and Redispatch Costs
Whenever a System Impact Study performed in connection with the provision of
Firm Point-To-Point Transmission Service identifies the need for new facilities
or upgrades, the Transmission Customer shall be responsible for such costs to
the extent they are consistent with Commission policy. Whenever a System Impact
Study identifies capacity constraints that may be relieved more economically by
redispatching the Participants' resources than by building new facilities or
upgrading existing facilities to eliminate such constraints, the Transmission
Customer shall be responsible for the redispatch costs to the extent consistent
with applicable Commission policy.
VI. REGIONAL NETWORK SERVICE (NETWORK INTEGRATION TRANSMISSION SERVICE)
The Participants will provide NEPOOL Regional Network Service (Network
Integration Transmission Service), as described in Part II of this Tariff to
Participants and Non-Participants pursuant to the applicable terms and
conditions contained in this Tariff. Part II of this Tariff specifies certain
terms and conditions which are generally applicable to the receipt of Regional
Network Service by both Participants and Non-Participants. This Part VI
specifies additional provisions with respect to the provision of Regional
Network Service.
42 Nature of Regional Network Service
42.1 Scope of Service: Regional Network Service (Network Integration
Transmission Service) is the transmission service described in Section 14 that
allows Network Customers to efficiently and economically utilize their resources
and Interchange Transactions to serve their Network Load located in the NEPOOL
Control Area and any additional load that may be designated pursuant to Section
43.3 of this Tariff. The Network Customer taking Regional Network Service must
obtain or provide Ancillary Services pursuant to Section 4.
42.2 Transmission Provider Responsibilities: The NEPOOL Participants will plan,
construct, operate and maintain the NEPOOL Transmission System in accordance
with Good Utility Practice in order to provide the Network Customer with
Regional Network Service over the NEPOOL Transmission System. Subject to Section
48, each Participant which is individually a Transmission Provider, on behalf of
its Native Load Customers, shall be required to designate resources and loads in
the same manner as any Network Customer under Part VI of this Tariff. This
information must be consistent with the information used by the Transmission
Provider to calculate available transmission capacity. The Participants shall
include the Network Customer's Network Load in NEPOOL Transmission System
planning and shall, consistent with Good Utility Practice, endeavor to construct
and place into service sufficient transmission capacity to deliver Network
Resources to serve the Network Customer's Network Load on a basis comparable to
the Participants' delivery of their own generating and purchased resources to
their Native Load Customers.
42.3 Network Integration Transmission Service: The Participants that are
individually Transmission Providers will provide firm transmission service over
the NEPOOL Transmission System to the Network Customer for the delivery of
energy and/or capacity from its resources to service its Network Loads on a
basis that is comparable to the Participants' use of the NEPOOL Transmission
System to reliably serve their Native Load Customers.
42.4 Secondary Service: The Network Customer may use the NEPOOL Transmission
System to deliver energy and/or capacity to its Network Loads from resources
that have not been designated as Network Resources. Such energy and capacity
shall be transmitted, on an as-available basis, at no additional charge, except
for any applicable charges for Congestion Cost and/or Marginal Loss cost
recovery, which are recovered from Non-Participants as part of Regional Network
Service and from Participants under the Agreement. Deliveries from resources
other than Network Resources will have a higher priority than any Non-Firm
Point-to-Point Transmission Service under this Tariff.
42.5 Real Power Losses: Real Power Losses are associated with all transmission
service. The Transmission Provider is not obligated to provide Real Power
Losses. To the extent PTF losses are not specifically allocated through the
market procedures provided for in Section 14 of the Agreement, total remaining
PTF losses, minus point-to-point losses, shall be allocated to all load on a
load ratio basis.
42.6 Restrictions on Use of Service: The Network Customer is entitled to use
Regional Network Service for any of the uses specified in Part II of this
Tariff.
43 Initiating Service
43.1 Condition Precedent for Receiving Service: Subject to the terms and
conditions of Parts II and VI of this Tariff, the Participants will provide
Regional Network Service to any Eligible Customer, provided that, except as
otherwise provided in Section 48, (i) the Eligible Customer completes an
Application for service as provided under Part VI of this Tariff, (ii) the
Eligible Customer and the System Operator complete the technical arrangements
set forth in Sections 41.3 and 41.4, (iii) the Eligible Customer executes a
Service Agreement in the form of Attachment B for service under Part VI of this
Tariff or requests in writing that the Transmission Provider file a proposed
unexecuted Service Agreement with the Commission, and (iv) the Eligible Customer
executes a Network Operating Agreement in the form of Exhibit H to this Tariff,
or in any other form that is mutually agreed to, with the Transmission Provider.
43.2 Application Procedures: Except as otherwise provided in Section 48, an
Eligible Customer requesting Network Integration Transmission Service under this
Tariff must submit an Application, with a deposit approximating the charge for
one month of service, to the System Operator as far as possible in advance of
the month in which service is to commence. Completed Applications for Network
Integration Transmission Service will be assigned a priority according to the
date and time the Application is received, with the earliest Application
receiving the highest priority. Applications should be submitted by entering the
information listed below on the NEPOOL OASIS to the extent feasible. A Completed
Application shall provide all of the information included in 18 CFR 2.20
including but not limited to the following:
(i) The identity, address, telephone number and facsimile number of the
party requesting service;
(ii) A statement that the party requesting service is, or will be upon
commencement of service, an Eligible Customer under this Tariff;
(iii) A description of the Network Load at each delivery point. This description
should separately identify and provide the Eligible Customer's best estimate of
the total loads to be served at each transmission voltage level, and the loads
to be served from each Transmission Provider substation at the same transmission
voltage level. The description should include a ten-year forecast of summer and
winter load resource requirements beginning with the first year after the
service is scheduled to commence;
(iv) The amount and location of any interruptible loads included in the Network
Load. This shall include the summer and winter capacity requirements for each
interruptible load (had such load not been interruptible), that portion of the
load subject to Interruption, the conditions under which an Interruption can be
implemented and any limitations on the amount and frequency of Interruptions. An
Eligible Customer should identify the amount of interruptible customer load (if
any) included in the ten-year load forecast provided in response to (iii) above;
(v) A description of Network Resources (current and ten-year projection), which
shall include, for each Network Resource, if not otherwise available to the
System Operator:
- - Unit size and amount of capacity from that unit to be designated as
Network Resource
- - VAR capability (both leading and lagging) of all generators
- - Operating restrictions
- - Any periods of restricted operations throughout the year
- - Maintenance schedules
- - Minimum loading level of unit
- - Normal operating level of unit
- - Any must-run unit designations required for system reliability or contract
reasons
- - Approximate variable dispatch price ($/MWH) for redispatch computations
- - Arrangements governing sale and delivery of power to third parties from
generating facilities located in the NEPOOL Control Area, where only a portion
of unit output is designated as a Network Resource
- - Description of external purchased power designated as a Network Resource
including source of supply, Control Area location, transmission arrangements and
delivery point(s) to the Transmission Provider's Transmission System;
(vi) Description of Eligible Customer's transmission system:
- - Load flow and stability data, such as real and reactive parts of the load,
lines, transformers, reactive devices and load type, including normal and
emergency ratings of all transmission equipment in a load flow format compatible
with that used by the Participants
- - Operating restrictions needed for reliability
- - Operating guides employed by system operators
- - Contractual restrictions or committed uses of the Eligible Customer's
transmission system, other than the Eligible Customer's Network Loads and
Resources
- - Location of Network Resources described in subsection (v) above
- - ten-year projection of system expansions or upgrades
- - Transmission System maps that include any proposed expansions or upgrades
- - Thermal ratings of Eligible Customer's Control Area ties with other
Control Areas; and
(vii) Service Commencement Date and the term of the requested Network
Integration Transmission Service. The minimum term for Network Integration
Transmission Service is one year.
Unless the Eligible Customer and the System Operator agree to a different time
frame, the System Operator must acknowledge the request within ten days of
receipt. The acknowledgment must include a date by which a response, including a
Service Agreement, will be sent to the Eligible Customer. If an Application
fails to meet the requirements of this section, the System Operator shall notify
the Eligible Customer requesting service within fifteen days of receipt and
specify the reasons for such failure. Wherever possible, the System Operator
will attempt to remedy deficiencies in the Application through informal
communications with the Eligible Customer. If such efforts are unsuccessful, the
System Operator shall return the Application without prejudice to the Eligible
Customer, who may thereafter file a new or revised Application that fully
complies with the requirements of this section. The Eligible Customer will be
assigned a new priority consistent with the date of the new or revised
Application. The System Operator shall treat this information consistent with
the standards of conduct contained in Part 37 of the Commission's regulations.
43.3 Technical Arrangements to be Completed Prior to Commencement of Service:
Except as otherwise provided in Section 48, Regional Network Service shall not
commence until the Participants and the Network Customer, or a third party, have
completed installation of all equipment specified under a Network Operating
Agreement consistent with Good Utility Practice and any additional requirements
reasonably and consistently imposed to ensure the reliable operation of the
NEPOOL Transmission System. The Participants shall exercise reasonable efforts,
in coordination with the Network Customer, to complete such arrangements as soon
as practicable taking into consideration the Service Commencement Date.
43.4 Network Customer Facilities: The provision of Regional Network Service
shall be conditioned upon the Network Customer's constructing, maintaining and
operating the facilities on its side of each delivery point or interconnection
necessary to reliably deliver capacity and energy from the NEPOOL Transmission
System to the Network Customer. The Network Customer shall be solely responsible
for constructing or installing and operating and maintaining all facilities on
the Network Customer's side of each such delivery point or interconnection.
43.5 Filing of Service Agreement: The System Operator will file Service
Agreements with the Commission in compliance with applicable Commission
regulations.
44 Network Resources
44.1 Designation of Network Resources: The designation of generation resources
as Network Resources shall be effected automatically in accordance with the
definition thereof for Participant Network Customers. A Network Customer shall
designate to the System Operator those Network Resources which are owned,
purchased or leased by it. The Network Resources so designated may not include
resources, or any portion thereof, that are committed for sale to non-designated
third party load or otherwise cannot be called upon to meet the Network
Customer's Network Load on a non-interruptible basis, or to the extent that the
resource is being delivered directly to a load being served with Internal
Point-to-Point Service. Any owned, purchased or leased resources that were
serving the Network Customer's loads under firm agreements entered into on or
before the Compliance Effective Date shall be deemed to continue to be so owned,
purchased or leased by it until the Network Customer informs the System Operator
of a change. Nothing in this Section is intended to relieve any customer of its
obligation to pay the charge for Internal Point-to-Point Service deliveries of
Network Resources to it.
44.2 Designation of New Network Resources: The Network Customer shall identify
the Network Resources which are owned, purchased or leased by it to the System
Operator with as much advance notice as practicable. A designation of a Network
Resource as owned, purchased or leased by the Customer must be made by a notice
to the System Operator.
44.3 Termination of Network Resources: The Network Customer may terminate the
designation of all or part of a Network Resource as owned, purchased or leased
by it at any time but should provide notification to the System Operator as soon
as reasonably practicable.
44.4 Network Customer Redispatch Obligation: As a condition to receiving Network
Integration Transmission Service, the Network Customer agrees to redispatch its
Network Resources as requested by the System Operator pursuant to Section 45.2.
To the extent practical, the redispatch of resources pursuant to this section
shall be on a least cost, non-discriminatory basis between all Network Customers
and the Participants.
44.5 Transmission Arrangements for Network Resources Not Physically
Interconnected With The NEPOOL Transmission System: The Network Customer shall
be responsible for any arrangements necessary to deliver capacity and energy
from a Network Resource not physically interconnected with the NEPOOL
Transmission System. The System Operator will undertake reasonable efforts to
assist the Network Customer in obtaining such arrangements, including without
limitation, providing any information or data required by such other entity
pursuant to Good Utility Practice.
44.6 Limitation on Designation of Resources: The Network Customer must
demonstrate that it owns, leases or has committed to purchase an Entitlement in
a generation resource pursuant to an executed contract in order to designate the
generating resource to serve its Network Load. Alternatively, the Network
Customer may establish that execution of a contract is contingent upon the
availability of transmission service under Part II of this Tariff.
44.7 Use of Interface Capacity by the Network Customer: There is no limitation
upon a Network Customer's use of the NEPOOL Transmission System at any
particular interface to integrate the Network Customer's resources (or
substitute purchases in Interchange Transactions) with its Network Loads.
However, a Network Customer's use of the NEPOOL total interface capacity with
other transmission systems to serve its Network Load may not exceed the Network
Customer's load.
45 Designation of Network Load
45.1 Network Load: Except as otherwise provided in Section 48, the Network
Customer must designate the individual Network Loads on whose behalf the
Participants will provide through NEPOOL Network Integration Transmission
Service. The Network Loads shall be specified in the Service Agreement.
45.2 New Network Loads Connected With the NEPOOL Transmission System: The
Network Customer shall provide the System Operator with as much advance notice
as reasonably practicable of the designation of new Network Load that will be
added to the NEPOOL Transmission System. A designation of new Network Load must
be made through a modification of service pursuant to a new Application. The
Participants will use due diligence to install or cause to be installed any
transmission facilities required to interconnect a new Network Load designated
by the Network Customer. The costs of new facilities required to interconnect a
new Network Load shall be determined in accordance with the procedures provided
in Section 44.4 and shall be charged to the Network Customer in accordance with
Commission policy and Schedule 11.
45.3 Network Load Not Physically Interconnected with the NEPOOL Transmission
System: This section applies to both initial designation pursuant to Section
43.1 and the subsequent addition of new Network Load not physically
interconnected with the NEPOOL Transmission System. To the extent that the
Network Customer desires to obtain transmission service for a load outside the
NEPOOL Control Area, the Network Customer shall have the option of (1) electing
to include the entire load as Network Load for all purposes under Part VI of
this Tariff and designating resources to serve such additional Network Load, or
(2) excluding that entire load from its Network Load. To the extent that the
Network Customer gives notice of its intent to add a new Network Load as part of
its Network Load pursuant to this section the request must be made through a
modification of service pursuant to a new Application, and shall be available
only so long as a scheduling and interconnection agreement acceptable to the
System Operator shall be required to be in effect with the Control Area in which
the load is located. Charges for such portion of the service shall be based on
the Through or Out Service rate applied to the amount reserved for the Network
Load which is not physically interconnected with the NEPOOL Transmission System.
45.4 New Interconnection Points: To the extent the Network Customer desires to
add a new Delivery Point or interconnection point between the NEPOOL
Transmission System and a Network Load, the Network Customer shall provide the
System Operator with as much advance notice as reasonably practicable.
45.5 Changes in Service Requests: Under no circumstances shall the Network
Customer's decision to cancel or delay a requested change in Network Integration
Transmission Service (the addition of a new Network Resource, if any, or
designation of a new Network Load) in any way relieve the Network Customer of
its obligation to pay the costs of transmission facilities constructed by the
Participants and charged to the Network Customer as reflected in the Service
Agreement or other appropriate agreement. However, the System Operator must
treat any requested change in Network Integration Transmission Service in a
non-discriminatory manner.
45.6 Annual Load and Resource Information Updates: The Network Customer shall
provide the System Operator with annual updates of Network Load and Network
Resource forecasts consistent with those included in its Application under Part
VI of this Tariff. The Network Customer also shall provide the System Operator
with timely written notice of material changes in any other information provided
in its Application relating to the Network Customer's Network Load, Network
Resources, its transmission system or other aspects of its facilities or
operations affecting the Participants' ability to provide reliable service.
46 Additional Study Procedures For Network Integration Transmission Service
Requests
46.1 Notice of Need for System Impact Study: After receiving a request for
service, the System Operator shall review the effect of the requested service on
the reliability requirements to meet existing and pending obligations of the
Participant(s) and on the obligations of the particular Participant(s) whose PTF
facilities will be impacted by the proposed service and shall determine on a
non-discriminatory basis whether a System Impact Study is needed. A description
of the methodology for completing a System Impact Study is provided in
Attachment D. If the System Operator determines that a System Impact Study is
necessary to accommodate the requested service, it shall as soon as practicable
inform the Eligible Customer and any affected Participant(s) if the System
Impact Study is to be performed by the Participant(s). If the likely result of
the study is that a Direct Assignment Facility will be required, the study shall
be performed by the affected Participant(s), subject to review by the System
Operator. In such cases, the System Operator shall within thirty days of receipt
of a Completed Application, tender a System Impact Study agreement in the form
of Attachment I to this Tariff, or in any other form that is mutually agreed to,
pursuant to which the Eligible Customer shall agree to reimburse the System
Operator and any affected Participant for performing the required System Impact
Study. For a service request to remain a Completed Application, the Eligible
Customer shall execute a System Impact Study agreement and return it to the
System Operator within fifteen days. If the Eligible Customer elects not to
execute a System Impact Study agreement, its Application shall be deemed
withdrawn and its deposit (less the reasonable Administrative Costs incurred by
the System Operator and any affected Participant(s)) shall be returned with
Interest.
46.2 System Impact Study Agreement and Cost Reimbursement:
(i) The System Impact Study agreement, whether in the form detailed in
Attachment I or in any other form that is mutually agreed to, will clearly
specify the System Operator's actual estimate of the actual cost, and time for
completion of the System Impact Study. The actual charge shall not exceed the
actual cost of the study. In performing the System Impact Study, the System
Operator and the affected Participants shall rely, to the extent reasonably
practicable, on existing transmission planning studies. The Eligible Customer
will not be assessed a charge for such existing studies; however, the Eligible
Customer will be responsible for charges associated with any modifications to
existing planning studies that are reasonably necessary to evaluate the impact
of the Eligible Customer's request for service on the NEPOOL Transmission
System.
(ii) If in response to multiple Eligible Customers requesting service in
relation to the same competitive solicitation, a single System Impact Study is
sufficient for the System Operator and the affected Participants to accommodate
the service requests, the costs of that study shall be prorated among the
Eligible Customers.
(iii) For System Impact Studies that the System Operator and any affected
Participants conduct on behalf of a Participant which is a Transmission
Provider, the Participant will record the cost of the System Impact Studies
pursuant to Section 8.5.
46.3 System Impact Study Procedures: Upon receipt of an executed System Impact
Study agreement, the System Operator and any affected Participants will use due
diligence to complete the required System Impact Study within a 60-day period.
The System Impact Study, if required, shall identify any system constraints,
redispatch options, or the need for additional Direct Assignment Facilities or
other facility additions or upgrades to provide the requested service. In the
event that the System Operator and any affected Participants are unable to
complete the required System Impact Study within such time period, the System
Operator shall so notify the Eligible Customer and provide an estimated
completion date along with an explanation of the reasons why additional time is
required to complete the required studies and an estimate of any increase in
cost which will result from the delay. A copy of the completed System Impact
Study and related work papers shall be made available to the Eligible Customer.
The System Operator will use the same due diligence in completing the System
Impact Study for an Eligible Customer as it uses when completing studies for the
Participants. The System Operator shall notify the Eligible Customer immediately
upon completion of the System Impact Study if the NEPOOL Transmission System
will be adequate to accommodate all or part of a request for service or that no
costs are likely to be incurred for new transmission facilities or upgrades. In
order for a request to remain a Completed Application, within fifteen days of
completion of the System Impact Study the Eligible Customer must execute a
Service Agreement or request the filing of an unexecuted Service Agreement, or
the Application shall be deemed terminated and withdrawn.
46.4 Facilities Study Procedures: If a System Impact Study indicates that
additions or upgrades to the NEPOOL Transmission System are needed to supply the
Eligible Customer's service request, the System Operator, within thirty days of
the completion of the System Impact Study, shall tender to the Eligible Customer
a Facilities Study agreement in the form of Attachment J to this Tariff, or in
any other form that is mutually agreed to, which is to be entered into by the
Eligible Customer and the System Operator and, if deemed necessary by the System
Operator, by one or more affected Transmission Provider(s) and pursuant to which
the Eligible Customer shall agree to reimburse the System Operator and any
affected Transmission Provider(s) for performing the required Facilities Study.
For a service request to remain a Completed Application, the Eligible Customer
shall execute the Facilities Study agreement and return it to the System
Operator within fifteen days. If the Eligible Customer elects not to execute a
Facilities Study agreement, its Application shall be deemed withdrawn and its
deposit, if any (less the reasonable Administrative Costs incurred by the System
Operator and any affected Transmission Provider(s)), shall be returned with
Interest. Upon receipt of an executed Facilities Study agreement, the System
Operator and any affected Transmission Provider(s), will use due diligence to
complete the required Facilities Study within a sixty-day period. If the System
Operator and any affected Transmission Provider(s) are unable to complete the
Facilities Study in the allotted time period, the System Operator shall notify
the Eligible Customer and provide an estimate of the time needed to reach a
final determination and any resulting increase in the cost, along with an
explanation of the reasons that additional time is required to complete the
study. When completed, the Facilities Study will include a good faith estimate
of (i) the cost of Direct Assignment Facilities to be charged to the Eligible
Customer, (ii) the Eligible Customer's appropriate share of the cost of any
required Network Upgrades, and (iii) the time required to complete such
construction and initiate the requested service. The Eligible Customer shall
provide a letter of credit or other reasonable form of security acceptable to
the affected Transmission Provider(s) or other entities that will be responsible
for the construction of the new facilities or upgrades equivalent to the costs
of new facilities or upgrades consistent with commercial practices as
established by the Uniform Commercial Code. The Eligible Customer shall have
thirty days to execute a Service Agreement or request the filing of an
unexecuted Service Agreement and provide the required letter of credit or other
form of security or the request no longer will be a Completed Application and
shall be deemed terminated and withdrawn.
In addition to the foregoing, each Facilities Study shall contain a non-
binding estimate from the System Operator of the incremental FCRs and associated
ARRs, if any, resulting from the construction of the new facilities. After
completion of the transmission upgrade or expansion, the System Operator shall
determine the incremental FCRs and associated ARRs, if any, resulting from the
upgrade or expansion.
47 Load Shedding and Curtailments
47.1 Procedures: Prior to the Service Commencement Date, the System Operator and
the Network Customer shall establish Load Shedding and Curtailment procedures
pursuant to the Network Operating Agreement with the objective of responding to
contingencies on the NEPOOL Transmission System. The parties will implement such
programs during any period when the System Operator determines that a system
contingency exists and such procedures are necessary to alleviate such
contingency. The System Operator will notify all affected Network Customers in a
timely manner of any scheduled Curtailment.
47.2 Transmission Constraints: During any period when the System Operator
determines that a transmission constraint exists on the NEPOOL Transmission
System, and such constraint may impair the reliability of the NEPOOL
Transmission System, the System Operator will take whatever actions, consistent
with Good Utility Practice, that are reasonably necessary to maintain the
reliability of the system. To the extent the System Operator determines that the
reliability of the System can be maintained by redispatching resources, the
System Operator will initiate procedures pursuant to a Network Operating
Agreement to redispatch all the Network Customer's resources and the
Participants' own resources on a least-cost basis without regard to the
ownership of such resources. Any redispatch under this section may not unduly
discriminate between the Participants' use of the NEPOOL Transmission System on
behalf of their Native Load Customers and any Network Customer's use of the
Transmission System to serve its designated Network Load.
47.3 Cost Responsibility for Relieving Transmission Constraints:
(a) Until the earlier of the CMS/MSS Effective Date or the implementation
effective date of an order issued by the Commission directing a different
allocation of Congestion Costs, to the extent not otherwise covered under the
Network Operating Agreement, whenever the System Operator implements least- cost
redispatch procedures in response to a transmission constraint, the customers
taking Internal Point-to-Point Service and/or Through or Out Service and Network
Customers will each bear a proportionate share of the total redispatch cost.
(b) On and after the CMS/MSS Effective Date, to the extent not otherwise covered
under the Network Operating Agreement, whenever the System Operator implements
least-cost redispatch procedures in response to a transmission constraint, the
customers taking Internal Point-to-Point Service and/or Through or Out Service
and Network Customers will each bear a share of the total redispatch cost in
accordance with Section 14A.12 and 14A.17 of the Agreement and Schedule 13 of
the Tariff.
47.4 Curtailments of Scheduled Deliveries: If a transmission constraint on the
NEPOOL Transmission System cannot be relieved through the implementation of
least-cost redispatch procedures and the System Operator determines that it is
necessary to effect a Curtailment of scheduled deliveries, such schedule shall
be curtailed in accordance with the Network Operating Agreement.
47.5 Allocation of Curtailments: The System Operator shall on a non-
discriminatory basis, effect a Curtailment of the transaction(s) that
effectively relieve the constraint. However, to the extent practicable and
consistent with Good Utility Practice, any Curtailment will be shared by the
customers taking Internal Point-to-Point Service and/or Through or Out Service
and Network Customers on a non-discriminatory basis. The System Operator shall
not direct the Network Customer to effect a Curtailment of schedules to an
extent greater than the System Operator would effect a Curtailment of the
Participants' schedules under similar circumstances. Notwithstanding the
preceding provisions of this Section, Import Transactions shall be scheduled and
curtailed in accordance with Section 14.1.
47.6 Load Shedding: To the extent that a system contingency exists on the NEPOOL
Transmission System and the System Operator determines that it is necessary for
the customers taking Internal Point-to-Point Service and/or Through or Out
Service and Network Customers to shed load, the Parties shall shed load in
accordance with previously established procedures under the Network Operating
Agreement, or in accordance with other mutually agreed-to provisions.
47.7 System Reliability: Notwithstanding any other provisions of this Tariff,
the System Operator reserves the right, consistent with Good Utility Practice
and on a not unduly discriminatory basis, to effect a Curtailment of Network
Integration Transmission Service without liability on the part of the System
Operator or the Participants for the purpose of making necessary adjustments to,
changes in, or repairs on the Participants' lines, substations and facilities,
and in cases where the continuance of Network Integration Transmission Service
would endanger persons or property. In the event of any adverse condition(s) or
disturbance(s) on the NEPOOL Transmission System or on any other system(s)
directly or indirectly interconnected with the NEPOOL Transmission System, the
System Operator, consistent with Good Utility Practice, also may effect a
Curtailment of Network Integration Transmission Service in order to (i) limit
the extent or damage of the adverse condition(s) or disturbance(s), (ii) prevent
damage to generating or transmission facilities, or (iii) expedite restoration
of service. The System Operator will give the Network Customer as much advance
notice as is practicable in the event of such Curtailment. Any Curtailment of
Network Integration Transmission Service will be not unduly discriminatory
relative to the Participants' use of the Transmission System on behalf of their
Native Load Customers. The Network Operating Agreement shall specify the rate
treatment and all related terms and conditions applicable in the event that the
Network Customer fails to respond to established Load Shedding and Curtailment
procedures.
48 Rates and Charges
The Network Customer shall pay Transmission Providers for any Direct Assignment
Facilities and its share of the cost of any required Network Upgrades and
applicable study costs consistent with Commission policy, along with the payment
to the System Operator of the charges for Ancillary Services and the charge for
Regional Network Service provided under this Tariff.
48.1 Determination of Network Customer's Monthly Network Load: The Network
Customer's "Monthly Network Load" is its hourly load (including its designated
Network Load not physically interconnected with the Transmission Provider under
Section 43.3) coincident with the coincident aggregate load of the Participants
and other Network Customers served in each Local Network in the hour in which
the coincident load is at its maximum for the month ("Monthly Peak").
49 Operating Arrangements
49.1 Operation under The Network Operating Agreement: The Network Customer shall
plan, construct, operate and maintain its facilities in accordance with Good
Utility Practice and in conformance with the Network Operating Agreement which
shall be in the form of Exhibit H to this Tariff, or in any other form that is
mutually agreed to.
49.2 Network Operating Agreement: The terms and conditions under which the
Network Customer shall operate its facilities and the technical and operational
matters associated with the implementation of Part VI of the Tariff shall be
specified in the Network Operating Agreement. The Network Operating Agreement
shall provide for the Parties to (i) operate and maintain equipment necessary
for integrating the Network Customer within the NEPOOL Transmission System
(including, but not limited to, remote terminal units, metering, communications
equipment and relaying equipment), (ii) transfer data between the System
Operator and the Network Customer (including, but not limited to, heat rates and
operational characteristics of Network Resources, generation schedules for units
outside the NEPOOL Transmission System, interchange schedules, unit outputs for
redispatch required under Section 45, voltage schedules, loss factors and other
real time data), (iii) use software programs required for data links and
constraint dispatching, (iv) exchange data on forecasted loads and resources
necessary for long-term planning, and (v) address any other technical and
operational considerations required for implementation of Part VI of this
Tariff, including scheduling protocols. The Network Operating Agreement will
recognize that the Network Customer shall either (i) operate as a Control Area
under applicable guidelines of the North American Electric Reliability Council
(NERC) and the Northeast Power Coordinating Council (NPCC), (ii) satisfy its
Control Area requirements, including all necessary Ancillary Services, by
contracting with the System Operator and the Participants, or (iii) satisfy its
Control Area requirements, including all necessary Ancillary Services, by
contracting with another entity, consistent with Good Utility Practice, which
satisfies NERC and NPCC requirements. The System Operator shall not unreasonably
refuse to accept contractual arrangements with another entity for Ancillary
Services.
49.3 Network Operating Committee: A Network Operating Committee (Committee)
shall be established to coordinate operating criteria for the Parties'
respective responsibilities under the Network Operating Agreement, where the
Network Customer is not a Participant. Each Network Customer shall be entitled
to have at least one representative on the Committee. The Committee shall meet
from time to time as need requires, but no less than once each calendar year.
50 Scope of Application of Part VI to Participants
(a) All Participants which are receiving Regional Network Service on the
Compliance Effective Date shall be deemed to have requested to continue Regional
Network Service and to have identified as their Network Resources and Network
Load all of their resources and load as of the Compliance Effective Date, unless
they elect in accordance with Section 3.3 of this Tariff to receive Internal
Point-to-Point Service at one or more Point(s) of Delivery from one or more
Point(s) of Receipt.
(b) In view of the operational, informational and financial obligations imposed
on Participants by the Agreement, the NEPOOL Financial Assurance Policy (which
is set forth in Attachment L hereto) and NEPOOL rules, the following
requirements shall not be applicable to Participants:
(1) the Application requirement specified in Sections 41.1(i) and 42 of this
Tariff;
(2) the deposit requirement specified in Section 41.2 of this Tariff;
(3) the requirement that a Network Customer execute a Service Agreement, as
specified in Section 41.1 (iii) of this Tariff; provided that a Service
Agreement shall be required (i) for any Participant initially taking Regional
Network Service after the Compliance Effective Date, (ii) if a Participant
serves load not physically interconnected with the NEPOOL Transmission System
pursuant to Section 43.3 of this Tariff or (iii) if a new facility or upgrade is
to be constructed pursuant to Section 44.4 of this Tariff;
(4) the requirement that a Network Customer execute a Network Operating
Agreement, as specified in Section 41.1(iv) of this Tariff; provided that a
Network Operating Agreement shall be required if a Participant serves load not
physically interconnected with the NEPOOL Transmission System pursuant to
Section 43.3 of this Tariff; and
(5) the requirement that a Network Customer provide an annual update of Network
Load and Network Resource forecasts, as specified in Section 43.6 of the Tariff.
Notwithstanding the foregoing, if the System Operator determines at any time
that it requires information from a Participant which would be contained in an
Application submitted pursuant to Section 41.2 or an annual update of Network
Load and Network Resource forecasts provided pursuant to Section 43.6, it has
the right to require that the Customer provide the information.
VII. TRANSMISSION PLANNING, ADDITIONS AND MODIFICATIONS
51 General
Additions to or modifications of the NEPOOL Transmission System may be required
or permitted under this Tariff, and be subject to related rights, obligations
and procedures, in any of the following circumstances:
(a) An addition or modification may be required under Part V or Part VI of the
Tariff in order to meet a new request for Point-to-Point Service or Regional
Network Service. Where such an addition or modification is to be effected, the
rights and obligations of the System Operator, the Transmission Providers and
Transmission Customers shall be determined in accordance with the applicable
provisions of Parts V and VI.
(b) An addition or modification may be required to permit the interconnection of
a new or modified generating unit or the interconnection of an Elective
Transmission Upgrade. Where such an addition or modification is to be effected,
the rights and obligations of the System Operator, the Transmission Owners, and
the Generator Owner or applicant for an Elective Transmission Upgrade, shall be
determined in accordance with Section 50 and Schedules 11 and 12.
(c) A Reliability Upgrade, an Economic Upgrade or a NEMA Upgrade may be required
or proposed pursuant to a NEPOOL Transmission Plan. Where a Reliability Upgrade,
an Economic Upgrade, or a NEMA Upgrade is to be effected, the rights and
obligations of the System Operator, the Transmission Owners and other
Participants shall be determined in accordance with Schedule 12.
(d) A Quick Fix Upgrade may be identified for implementation in 2000 or 2001.
Where a Quick Fix Upgrade is to be effected, the rights and obligations of the
System Operator, the Transmission Owners and other Participants shall be
determined in accordance with Section 52.
(e) Consistent with reliability and safety standards, Transmission Owners, the
operators of affected satellites in the NEPOOL Control Area and the System
Operator will coordinate scheduled generation and transmission facility outages
so as to minimize, to the extent practicable, Congestion and RMR-related costs.
The System Operator shall provide Transmission Owners and the operators of the
affected satellites with such information as is necessary to enable them to
perform this function. Any information provided to Transmission Owners and the
operators of the affected satellites pursuant to this provision will be subject
to all the applicable requirements of the Commission's Order 889.
These provisions for PTF additions and modifications are not intended to be
exclusive.
Nothing in this Tariff is intended to preclude any entity from identifying and
constructing Elective Transmission Upgrades on a merchant or other basis, so
long as it obtains all required legal rights and approvals and satisfies
applicable System Operator, NEPOOL, and Transmission Owner requirements relating
to such facilities.
An addition or modification which constitutes PTF under the Agreement and the
Tariff shall become part of the NEPOOL Transmission System and shall be fully
subject to this Tariff, whether or not all or any part of the costs of the
addition or modification are included in Pool-Supported PTF costs. The
priorities, if any, with respect to the use of the addition or modification as
among the owner and supporters of the addition or modification and other
Transmission Customers shall be determined under Parts I to VI, inclusive, of
this Tariff.
To the extent that a Generator Owner is responsible for the costs of a Generator
Interconnection Related Upgrade or Elective Transmission Upgrade, or an entity
other than a Generator Owner is responsible for costs of any other system
upgrade, the Generator Owner or entity which supports part or all of the costs
of the addition or modification shall be entitled to a share of any associated
ARRs equivalent to the share of the total costs of such upgrade which it
supports, as assigned and allocated in accordance with Schedules 14 and 15. Any
incremental FCRs resulting from Generator Interconnection Related Upgrades or
other upgrades shall be auctioned along with other FCRs in accordance with
Schedule 14.
Nothing in this Tariff is intended to waive the legal rights of any person or
the rights of the Transmission Owners under Section 17A of the Agreement.
If issues of cost allocation arise with respect to the recovery of any of the
costs provided for in this Part VII, or in Schedules 11 or 12, such issues shall
be subject to determination by the Commission in the appropriate proceeding.
52 Interconnection Procedures and Requirements
52.1 Interconnection of Generating Unit Under the Minimum Interconnection
Standard: Any Generator Owner that proposes after the Compliance Effective Date
(i) to place in service a new generating unit at a site which the Generator
Owner owns or controls, or which it has the right to acquire or control, and
that will interconnect to the NEPOOL Transmission System, or (ii) to materially
change and increase the capacity of an existing generating unit located in the
NEPOOL Control Area shall be obligated to:
(a) complete and submit to the System Operator a standard application, which is
available from the System Operator ("Interconnection Application"), along with
the administrative fee and description of its proposal and site information
required by the Interconnection Application, as well as any additional
information that may be reasonably required by the System Operator;
(b) within fifteen (15) days of its tender by the System Operator (which tender
shall occur no later than thirty (30) days following System Operator's receipt
of a complete Interconnection Application), enter into an agreement with the
System Operator and, if deemed necessary by the System Operator, one or more
affected Transmission Owners to provide for the conduct of a System Impact Study
to determine what additions or modifications to the NEPOOL Transmission System
and to the Non-PTF system are required in order to permit its generating unit to
interconnect in a manner that avoids any significant adverse effect on system
reliability, stability, and operability, including protecting against the
degradation of transfer capability for interfaces affected by the unit ("Minimum
Interconnection Standard"). If the Generator Owner does not enter into the
System Impact Study agreement within the above time period, its Interconnection
Application shall be deemed terminated and withdrawn. The System Impact Study
shall be conducted in accordance with the procedures, and subject to the
obligations, specified in Sections 33.2 and 33.3 and Attachment D of this Tariff
and using the form of agreement specified in Attachment I of this Tariff, except
that: (1) references therein to transmission service shall be deemed to refer to
interconnection; (2) references therein to Eligible Customer or Transmission
Customer shall be deemed to refer to the Generator Owner; (3) Attachment D shall
be applied so that the interconnection is studied on a Minimum Interconnection
Standard basis; and (4) any references to, or requirements for, a Service
Agreement in Section 33.3 shall be inapplicable;
(c) if a System Impact Study indicates that additions or modifications to the
NEPOOL Transmission System are required in order to permit the Generator Owner's
generating unit to be interconnected with the NEPOOL Transmission System on a
basis satisfying the Minimum Interconnection Standard, within fifteen (15) days
of its tender by the System Operator (which tender shall occur no later than
thirty (30) days following the completion of the System Impact Study), enter
into an agreement with the System Operator and, if deemed necessary by the
System Operator, one or more affected Transmission Owners to provide for the
conduct of a Facilities Study. The Facilities Study shall be conducted in
accordance with the procedures, and subject to the obligations, specified in
Sections 33.4 and 33.5 of this Tariff, and using the form of agreement specified
in Attachment J of this Tariff, except that: (1) references therein to
transmission service shall be deemed to refer to interconnection; (2) references
therein to Eligible Customer or Transmission Customer shall be deemed to refer
to the Generator Owner; and (3) any references to, or requirements for, a
Service Agreement in Section 33.4 shall be inapplicable. In lieu of a Facilities
Study, if transmission system additions or modifications are required, within
forty-five (45) days of submission of the final System Impact Study report to
the Generator Owner, the Generator Owner, the affected Transmission Owner(s)
and, when necessary, the System Operator may establish an agreement for
expedited interconnection. While the Transmission Owner(s) or other entities
that will be responsible for constructing the new facilities or modifications
pursuant to an expedited interconnection agreement will provide the Generator
Owner with its best estimate of the new facility costs and other charges that
may be incurred, such estimate shall not be binding and the Generator Owner
shall agree in writing to pay for all applicable costs ultimately incurred. If
the Generator Owner does not enter into the Facilities Study or expedited
interconnection agreement within the above time periods, its Interconnection
Application shall be deemed terminated and withdrawn;
(d) if the System Impact Study indicates that no additions or modifications are
required, work with the interconnecting Transmission Owner(s) to establish
appropriate interconnection agreements and provide the security, credit
assurances and/or deposits that the Transmission Owner determines is necessary
to ensure payment within ninety (90) days following issuance of a final System
Impact Study report. If the studies conducted pursuant to this Section indicate
that additions or modifications to PTF or Non-PTF are required: (i) the
Generator Owner and the interconnecting Transmission Owner(s) shall enter into
appropriate interconnection agreements, including security and deposit
provisions, or the Generator Owner may request, upon providing the security,
credit assurances, and/or deposits required by the Transmission Owner, the
filing with the Commission by the Transmission Owner of an unexecuted agreement;
and (ii) within ninety (90) days following issuance of the final Facilities
Study report, or within ninety (90) days following execution of an agreement for
expedited interconnection, the Generator Owner shall provide the security,
credit assurances, and/or deposits that the Transmission Owner determines is
necessary to ensure payment to the extent not already provided under (i) above;
and (iii) the Transmission Owner or its designee designated to perform the
construction of the additions or modifications shall, in accordance with the
terms of the arrangements described in this paragraph and subject to Sections
18.4 and 18.5 of the Agreement, use due diligence to design and effect the
proposed construction. If the Generator Owner fails to enter into an
interconnection agreement or to request the filing of an unexecuted agreement
within ninety (90) days following issuance of the final Facilities Study report,
or if it fails to provide the security, credit assurances and/or deposits
required by the Transmission Owner, its Interconnection Application shall be
deemed terminated and withdrawn. Sections 34.1, 34.2 (other than those sentences
referring to Service Agreements), 34.3 and 35 of the Tariff shall be applicable
to the facilities construction or modification, except that: (1) references
therein to transmission service shall be deemed to refer to interconnection; and
(2) references therein to Eligible Customer or Transmission Customer shall be
deemed to refer to the Generator Owner.
(e) satisfy any applicable requirements under the applicable tariff of the
relevant Transmission Owner on file with the Commission (except for those
relating to System Impact Studies and Facilities Studies, which will be
performed on a unified basis by the System Operator in accordance with this
Section) in the event that transmission service will be needed across Non-PTF of
the Transmission Owner; and
(f) submit its proposal for review in accordance with Section 18.4 of the
Agreement and related NEPOOL System Rules and thereafter take any action
required pursuant to Section 18.5 of the Agreement as a result of such Section
18.4 review.
Upon the satisfaction of the obligations described in (a), (b), (c), (d), (e),
and (f) above, and subject to all necessary legal rights and approvals being
obtained, the Generator Owner's unit shall have the right to be interconnected
with the NEPOOL Transmission System.
A Generator Owner proposing the interconnection of a new or materially changed
generating unit shall be responsible for the costs of any required Generator
Interconnection Related Upgrades which do not constitute costs of Pool-Supported
PTF in accordance with Schedule 11, and shall comply with the Transmission
Owner's requirements with respect to security, credit assurances and/or deposits
in accordance with Schedule 11.
With respect to upgrades required to meet the Minimum Interconnection Standard,
and consistent with reliability and safety standards, Transmission Owners, the
interconnecting Generator Owner and the System Operator shall jointly use their
best reasonable efforts to develop Congestion and RMR- related cost estimates
and construction schedules designed to minimize, to the extent practicable, the
financial impact of the upgrade-related transmission outages on all affected
parties. The development of the aforementioned construction schedule shall
include consultation with any affected existing Generator Owner. To the extent
it is possible to implement a procedure that facilitates the ability of
interconnecting Generator Owners and Transmission Owners to minimize, to the
extent reasonably practicable, the associated RMR and Congestion cost exposure
prior to implementation of CMS, the parties agree to continue the use of the
procedure after the implementation of CMS to the extent that such procedures are
consistent with CMS. There shall be no payment under this Tariff of lost
opportunity costs to Generator Owners for generating units that are dispatched
down or dispatched off. In connection with the consultation required by this
paragraph, the affected parties shall, as necessary, enter into non- disclosure
agreements protecting commercially sensitive information from unlimited
disclosure in order to facilitate the development of construction schedules
designed to minimize the financial impact on the affected parties.
For purposes of determining whether a generating unit is to be deemed a new
generating unit placed in service after the Compliance Effective Date so that it
is obligated to satisfy the requirements of this Section, any unit which, on
January 1, 1999, was in active or deactivated status, as classified in the April
1998 NEPOOL Capacity, Energy, Loads and Transmission Report and any other
generating unit in active status on that date which may receive deactivated
status after that date, subject to criteria developed by the appropriate NEPOOL
committee, may retain this status for a period not to exceed three (3) years
from the date the unit receives deactivated status and shall not be obligated to
comply with this Section if it is reactivated during such period, but if not
reactivated during such period shall be deemed retired at the end of such period
for purposes of this Section. Notwithstanding the foregoing, if a proposal is
submitted and approved under Section 18.4 of the Agreement during the three-year
period to 1) reactivate, 2) materially modify and reactivate or 3) replace the
deactivated unit, the unit may be reactivated without material modification
without compliance with this Section. Further, notwithstanding the foregoing,
any unit in deactivated status prior to January 1, 1999 shall be entitled to
retain such status through December 31, 2001 whether or not a submission is made
under Section 18.4 during such period.
52.2 Interconnection of Elective Transmission Upgrades: Any Participant or
Non-Participant may undertake the design, construction and interconnection of an
Elective Transmission Upgrade ("Elective Transmission Upgrade Applicant"). In
undertaking the design, construction and interconnection of an Elective
Transmission Upgrade, the Elective Transmission Upgrade Applicant shall
undertake, as a condition to its right to place the Elective Transmission
Upgrade in service, the following procedures and otherwise comply with the
relevant NEPOOL System Rules:
(a) complete and submit to the System Operator a standard application, which is
available from the System Operator, along with the administrative fee, that
describes the Elective Transmission Upgrade in sufficient detail to enable the
System Operator to identify the location of the upgrade, affected Transmission
Owners, and the purpose of the Elective Transmission Upgrade;
(b) if required by the System Operator, enter into a System Impact Study
Agreement with the System Operator and, if deemed necessary by the System
Operator, one or more affected Transmission Owners to determine the effects, if
any, of the upgrade on the NEPOOL Transmission System and Non-PTF. The System
Operator may permit the Elective Transmission Upgrade Applicant to undertake on
its own a System Impact Study in consultation with the System Operator and
affected Transmission Owner(s).
(c) upon receipt of the completed System Impact Study, notify the System
Operator whether it will seek approval of the Elective Transmission Upgrade
pursuant to Section 18.4 of the Agreement and, if so, submit its proposal for
review in accordance with Section 18.4 of the Agreement and relevant rules and
procedures of NEPOOL and the System Operator; and
(d) after obtaining approval for the Elective Transmission Upgrade, or after the
time periods set forth in Section 18.4 of the Agreement have passed without the
Elective Transmission Upgrade Transmission Applicant receiving notice in writing
that its proposed upgrade will have a significant adverse effect upon the
reliability or operating characteristics of its system or the system of one or
more Participants, the Elective Transmission Upgrade Applicant shall enter into
an interconnection agreement with the affected Transmission Owners. To the
extent necessary and appropriate, the Elective Transmission Upgrade Applicant
shall also enter into support agreements with the affected Transmission Owners.
The Elective Transmission Upgrade Applicant also may request, upon providing the
security, credit assurances, and/or deposits required by the affected
Transmission Owners, the filing with the Commission by the Transmission Owner of
unexecuted interconnection and support agreements. The Elective Transmission
Upgrade Applicant shall obtain all necessary legal rights and approvals for the
construction and maintenance of the upgrade and shall cooperate with
Transmission Owners in obtaining all necessary legal rights and approvals for
the construction and maintenance of additions or modifications, if any, required
in conjunction with the upgrade.
Upon satisfaction of the obligations described in (a), (b), (c), and (d) above,
subject to all necessary legal rights and approvals being obtained, and upon
satisfaction of any conditions placed on the Elective Transmission Upgrade
Applicant pursuant to Sections 18.4 and 18.5 of the Agreement, the Elective
Transmission Upgrade shall have the right to be interconnected with the NEPOOL
Transmission System.
The Participant or Non-Participant that constructs and/or maintains the Elective
Transmission Upgrade shall be responsible for 100% of all of the costs of said
upgrade and of any additions to or modifications of the NEPOOL Transmission
System and Non-PTF that are required to accommodate the Elective Transmission
Upgrade. A request for rate treatment of an Elective Transmission Upgrade, if
any, shall be determined by the Commission in the appropriate proceeding.
The completion of a System Impact Study for an Elective Transmission Upgrade and
the construction of an Elective Transmission Upgrade shall not delay the
completion of a System Impact Study or Facilities Study for a Generator Owner
applying to interconnect under the Minimum Interconnection Standard and shall
not delay the construction of upgrades for a generating unit interconnecting
under the Minimum Interconnection Standard.
53 Regional Transmission Planning and Expansion
53.1 General: Commencing with the NEPOOL Transmission Plan that will be
effective for the period 2001 and beyond, and subject to the final outcome of
rehearing requests and any appeals with respect to the Commission's June 28,
2000 CMS/MSS Order issued in Docket Nos. EL00-62-000 et al., and subject to any
changes resulting from compliance with the requirements of Commission Order No.
2000, the process defined in this Section 51, as amended from time to time,
shall be utilized for regional transmission planning. No provisions of this
Section 51 reflect or are intended to reflect agreement among the Participants
as to the ownership of any Upgrades to the NEPOOL Transmission System built
pursuant to an RFP under Section 51.6.
The NEPOOL Transmission Plan and transmission enhancement and expansion
studies shall be completed with the involvement of the Transmission Expansion
Advisory Committee and the Transmission Planning Committee. These two committees
shall be established in accordance with the provisions of Section 51.2, and
shall be responsible for the functions identified in that Section.
53.2 Responsibilities of the Transmission Expansion Advisory Committee,
Transmission Planning Committee and System Operator:
(a) A Transmission Expansion Advisory Committee shall be established to perform
the functions set forth in subsection (b) below. This Committee shall not be
subject to the governance provisions of the Agreement nor shall it have any of
the authority conferred by those provisions. It shall have a Chair and
Secretary, who shall be appointed by the chief executive officer of the System
Operator after consultation with the Participant members of the Liaison
Committee established pursuant to Section 11C of the Agreement. Before
appointing an individual to the position of the Chair or Secretary, the System
Operator shall notify the Committee of the proposed assignment and, consistent
with its personnel practices, provide any other information about the individual
reasonably requested by the Committee. The chief executive officer of the System
Operator shall consider the input of the members of the Committee in selecting,
removing or replacing such officers. If members of the Committee representing
five or more entities conclude that the performance of the Chair or Secretary is
not satisfactory, they may identify their concerns to the System Operator. If
after 30 days their concerns have not been reasonably addressed, they may
request that the Participants Committee consider a resolution to remove the
officer. A vote of the Participants Committee to remove an officer of the
Transmission Expansion Advisory Committee shall be immediately effective and
binding on the System Operator and not subject to any appeal. If the
Participants Committee votes to remove an officer of the Transmission Expansion
Advisory Committee, the System Operator shall appoint a replacement officer in
accordance with this subsection.
(b) The Transmission Expansion Advisory Committee shall be responsible for
providing input to and feedback for both the development of the NEPOOL
Transmission Plan and the conduct of enhancement and expansion studies. Such
input and feedback may include comment on policy issues, objectives, study
scope, and solutions and alternatives for consideration in the development of
the NEPOOL Transmission Plan. Any entity may designate a member to the
Transmission Expansion Advisory Committee by providing written notice to the
Secretary of that Committee identifying the name of the entity represented by
the member and the member's name, address, telephone number, facsimile number
and electronic mail address. The entity may remove or replace such member at any
time by written notice to the Secretary of the Transmission Expansion Advisory
Committee.
(c) A Transmission Planning Committee shall be established to perform the
functions set forth in subsection (d) below. This Committee shall not be subject
to the governance provisions of the Agreement nor shall it have any of the
authority conferred by those provisions. It shall have a Chair and Secretary,
who shall be appointed by the chief executive officer of the System Operator
after consultation with the members of the Committee. The Chair shall be an
employee of the System Operator. Before an individual is appointed to the
position of the Chair or Secretary, the System Operator shall, consistent with
its personnel practices, provide any information about the individual reasonably
requested by members of the Transmission Planning Committee. The chief executive
officer of the System Operator shall consider the input of the members of this
Committee in selecting, removing or replacing such officers.
(d) The Transmission Planning Committee shall be responsible for providing the
data, information and analytical support necessary to perform studies as
required, and shall identify engineering and technical issues and engineering
and technical solutions and alternatives with respect to the work within the
scope of the NEPOOL Transmission Plan. The Transmission Planning Committee shall
be comprised of at least one representative from the System Operator and from
each of the Transmission Owners. The Transmission Owners' representatives must
be "transmission function employees" subject to the code of conduct requirements
of 18 C.F.R. 37.4, as such requirements may be amended or superseded from time
to time. The System Operator may, after notice to the Transmission Planning
Committee, invite representatives of other entities to attend a discussion by
the Transmission Planning Committee of an Upgrade proposed by such entities,
provided such representatives either are by confidentiality agreement or
otherwise, subject to the same limitations on the use and disclosure of
information as, "transmission function employees" subject to the standards of
conduct requirements of 18 C.F.R. 37.4, as such requirements may be amended or
superseded from time to time. The Transmission Planning Committee shall not be
subject to the requirements of Section 7.6 of the Agreement and, except as
provided above, attendance at any meeting shall be restricted solely to members
of that Committee.
(e) In addition to the responsibilities specifically assigned to the System
Operator in other Sections of this Section 51, those NEPOOL Transmission System
planning functions required by this Section 51 that are not functions of the
Transmission Expansion Advisory Committee, the Transmission Planning Committee
or another NEPOOL Committee or entity under other provisions of the Agreement or
this Tariff, shall be the sole responsibility of the System Operator; provided,
that the assignment of any technical, engineering or analytical planning
function to the Transmission Planning Committee is not intended to preclude the
performance of any technical, engineering or analytical planning function by the
System Operator. For Upgrades proposed to reduce Congestion Costs, the System
Operator also shall perform and publish analysis that identifies the costs and
benefits of the Upgrade and, to the extent feasible, the distribution of such
benefits in the region.
53.3 NEPOOL Transmission Plan: Principles, Scope, and Contents:
(a) The NEPOOL Transmission Plan shall conform to Good Utility Practice,
applicable reliability principles, guidelines, criteria, rules, procedures and
standards of NERC and NPCC and any of their successors, applicable publicly
available local reliability criteria, and the NEPOOL System Rules, as they may
be amended from time to time.
(b) The NEPOOL Transmission Plan shall consolidate regional transmission needs
into a single plan which is assessed on the basis of maintaining the NEPOOL
Control Area's reliability while accounting for economic and environmental
considerations. The NEPOOL Transmission Plan shall be based on the results of a
comprehensive transmission expansion and enhancement study conducted at least
once every three years in accordance with Section 51.5. The NEPOOL Transmission
Plan shall also account for at least the ensuing five year load and capacity
forecasts, proposed generation additions and retirements, proposed Merchant
Transmission Facility additions, and the requirements for system restoration
services (but will not include development of a system restoration plan). Based
on the foregoing requirements and considerations, the NEPOOL Transmission Plan
shall identify for at least each of the ensuing five years a list of proposed
enhancements and expansions to the NEPOOL Transmission System not otherwise
proposed as Merchant Transmission Facilities that are determined to be
appropriate at the time of the issuance of the Plan (collectively referred to as
"Upgrades"). That list of Upgrades is subject to adjustment in accordance with
subsection (c) of Section 51.4 and, accordingly, an Upgrade included in a Plan
may subsequently be removed from the Plan and not be constructed. The NEPOOL
Transmission Plan shall also identify any projected need for Transfer Capability
during or before the five-year period, based on information at that time, for
which Upgrades have not been identified.
(c) The NEPOOL Transmission Plan shall be designed (i) to avoid unnecessary
duplication of facilities; (ii) to avoid the imposition of unreasonable costs
upon any Transmission Owner, Transmission Customer or other user of a
transmission facility; (iii) to take into account the legal and contractual
rights and obligations of the Transmission Owners and the transmission-related
legal and contractual rights and obligations of any other entity; and (iv) to
provide for coordination with existing transmission systems and with appropriate
interregional and local expansion plans.
53.4 Procedures for Developing a NEPOOL Transmission Plan:
(a) An initial draft of a five-year NEPOOL Transmission Plan for the years
2001-2005 (the "2000 Plan") shall be assembled and provided to Participants as
soon as reasonably practicable. The 2000 Plan shall reflect the list of
additions and modifications to the NEPOOL Transmission System that have been
identified by the System Operator and by Transmission Owners for their
individual systems or that have been jointly planned by Transmission Owners by
December 31, 2000. The 2000 Plan shall reflect the results of
reliability-related studies including those already identified in Form 715
filings with the Commission as of March 31, 2000; provided that the 2000 Plan
may also reflect studies completed after March 31, 2000 and prior to December
31, 2000. The 2000 Plan shall be issued by December 31, 2000 and shall be deemed
to be the NEPOOL Transmission Plan referred to in Section (3) of Schedule 12.
(b) The starting point for the NEPOOL Transmission Plan for the years 2002-2006
(the "2001 Plan") and each subsequent NEPOOL Transmission Plan shall be the list
of Upgrades included in the prior Plan, as updated, that have not been completed
at that time. The 2001 Plan and each subsequent Plan shall include for each year
covered by that Plan on a coordinated regional basis a list of additional
Upgrades identified in enhancement and expansion studies performed pursuant to
Section 51.5. That list shall identify separately (i) Reliability Upgrades, (ii)
Economic Upgrades, (iii) Generator Interconnection Related Upgrades to be
effected pursuant to Section 50 to accommodate new generation interconnections
that have satisfied the requirements under Sections 18.4 and 18.5 of the
Agreement, and (iv) NEMA Upgrades as appropriate. The Plan shall also include a
description of the reasons for any new Upgrades proposed in the Plan, including
the information identified in subsection (g) below, or for any removal of
Upgrades from the Plan pursuant to subsection (c) below.
(c) An Upgrade may be added to the NEPOOL Transmission Plan at any time in a
given year, provided there has been consultation with and consideration of input
from the Transmission Expansion Advisory Committee and the Transmission Planning
Committee, within the scope of their respective functions as specified in
subsections (b) and (d) of Section 51.2. Similarly, provided there has been
consultation with and consideration of input from the Transmission Expansion
Advisory Committee and the Transmission Planning Committee, within the scope of
their functions as specified in subsections (b) and (d) of Section 51.2, the
NEPOOL Transmission Plan may be revised to remove a proposed Upgrade if the
market responds by proposing alternative generation projects, Merchant
Transmission Facilities in accordance with Section 51.8, or demand-side
projects, or other circumstances arise such that the need for the Upgrade no
longer exists; provided that the entity responsible for the construction of the
Upgrade is reimbursed for any costs prudently incurred or prudently committed to
be incurred in connection with the planning, preparation for construction,
and/or construction of the Upgrades proposed for removal from the Plan. All
Upgrades proposed to be added or removed during this planning process must meet
the requirements of subsection (a) of Section 51.3.
(d) The Transmission Owners, those entities requesting transmission service or
interconnection, and any other entities proposing to provide facilities to be
integrated into the NEPOOL Control Area or alternatives to such facilities shall
supply upon request and subject to applicable confidentiality requirements of
the NEPOOL Information Policy any information and data reasonably required to
prepare a NEPOOL Transmission Plan or to perform a transmission enhancement and
expansion study. Any confidential cost estimate for a proposed Upgrade to the
NEPOOL Transmission System that is or may be subject to subsection (a) of
Section 51.6 shall be considered by the System Operator to be competitively
sensitive, confidential information and shall be considered the estimator's
confidential information under the NEPOOL Information Policy, and shall not be
disclosed by the System Operator to other entities that may be eligible to
submit a proposal in accordance with Section 51.6, including, without
limitation, other Transmission Owners. Any other information or data provided
shall be subject to the rights and obligations of the NEPOOL Information Policy.
(e) The NEPOOL Transmission Plan shall be developed in coordination with the
transmission systems of the surrounding Control Areas and the regional
reliability councils, as appropriate.
(f) At the initiation of an effort to update a Plan or develop a new Plan, the
System Operator shall solicit input for the updated or new Plan from members of
the Transmission Expansion Advisory Committee and Transmission Planning
Committee. These Committees shall meet to perform their respective functions in
connection with the preparation of the NEPOOL Transmission Plan, as specified in
subsections (b) and (d) of Section 51.2. Thereafter, drafts of the NEPOOL
Transmission Plan shall be provided to the Transmission Expansion Advisory
Committee and input from that Committee shall be received and considered in
preparing and revising subsequent drafts. Before a final draft of any proposed
NEPOOL Transmission Plan is presented to the System Operator's Board of
Directors for approval, a subcommittee of that Board shall hold a public meeting
to receive input directly and to discuss any proposed revisions to the draft.
(g) For potential Upgrades proposed to be included in the NEPOOL Transmission
Plan, the System Operator (in connection with the preparation of the NEPOOL
Transmission Plan) shall identify, to the extent practicable, the anticipated
benefits of the proposed Upgrade. To the extent an Upgrade is proposed to reduce
Congestion Costs, the System Operator shall publish data and information, in a
manner that does not violate the Information Policy, that would reasonably
permit entities to calculate the costs and economic benefits of such an Upgrade
and, to the extent feasible, the distribution of such benefits within the
region. Such information shall be published so as to permit analysis for a
reasonably limited period of time (generally ten years or less), and shall
include the effects of (i) all projects for which applications have been
received for approval under Section 18.4 of the Restated NEPOOL Agreement,
including but not limited to proposed generation projects and Merchant
Transmission Facilities and (ii) demand-side projects planned within the NEPOOL
Control Area and identified to the System Operator.
(h) Any entity with a representative on the Transmission Expansion Advisory
Committee may request that specific proposals for alternative solutions or
facilities, including but not limited to generation projects, transmission
projects, and/or demand-side projects, be accounted for in the development of
the NEPOOL Transmission Plan. The recommended draft of a NEPOOL Transmission
Plan shall account for such proposals where appropriate provided that the
recommended Plan shall not include in the list of Upgrades any proposed resource
participating in competitive electricity markets or Merchant Transmission
Facilities. If a proposal is not accounted for in the draft Plan to be
recommended to the System Operator's Board of Directors, the recommendation to
the Board shall include a written explanation of why such proposal(s) were not
accounted for in the recommended Plan, which shall be made public.
(i) A draft of a recommended NEPOOL Transmission Plan shall be presented at
least annually to the System Operator's Board of Directors for approval. At
least every three years, a draft shall reflect the results of a new
comprehensive transmission planning and expansion study conducted pursuant to
Section 51.5. In other years, the draft may be only an update to a prior
approved Plan. The draft shall be presented to the System Operator's Board of
Directors no later than September 30 of each year and shall be acted on by the
Board within 60 days of receipt. The Board of Directors may approve the
recommended Plan as submitted, modify the Plan or remand all or any portion of
it back with guidance for development of a revised recommendation in accordance
with this Section 51.4. The Board of Directors may consider the Plan in
executive session, and shall consider in its deliberations the views of the
subcommittee of the Board reflecting the public meeting held pursuant to
subsection (f) of Section 51.4.
(j) The cost responsibility for each Upgrade that is listed in the NEPOOL
Transmission Plan shall be determined in accordance with this Tariff, including
Schedule 11 or 12 of this Tariff, as applicable.
53.5 Procedures for the Conduct of Enhancement and Expansion Studies: From time
to time in connection with the development of a NEPOOL Transmission Plan or any
updates thereto, transmission enhancement and expansion studies may be desired
or necessary. Such studies shall be conducted in accordance with the following
procedures:
(a) The System Operator shall initiate a comprehensive transmission enhancement
and expansion study at least once every three years. A more limited study shall
be conducted if (i) a need for additional transfer capability is identified by
the System Operator in its evaluation of requests for firm transmission service
with a term of one year or more or as a result of the System Operator's on-going
evaluation of the bulk power supply system's adequacy and performance; (ii) a
need for additional transfer capability is identified as a result of the NERC
and/or NPCC reliability assessment or more stringent publicly available local
reliability criteria, if any; or (iii) constraints or available transfer
capability limitations are identified as a result of generation additions or
retirements, evaluation of load forecasts or proposals for the addition of
transmission facilities in the NEPOOL Control Area. A transmission enhancement
and expansion study may also be initiated for any other circumstances which may
warrant such a study.
(b) Written notice of the initiation of a transmission enhancement and expansion
study shall be provided to all members of the Transmission Expansion Advisory
Committee and Transmission Planning Committee. That notice shall identify the
needs supporting the initiation of the study. Meetings of these two Committees
shall be convened thereafter to identify additional considerations relating to
such a transmission enhancement and expansion study that were not identified in
support of initiating the study, and to provide input on the study's scope,
assumptions and procedures, consistent with the respective responsibilities of
these Committees as set forth in Section 51.2.
(c) The results of the enhancement and expansion study, along with a discussion
of the study assumptions and input, shall be made public.
53.6 Request for Proposals ("RFP") Process For Upgrades:
(a) Except as otherwise provided in subsections (e) or (f) of this Section 51.6
below, the System Operator shall circulate a request for proposals ("RFP")
inviting any entity or entities to build an Upgrade included in the NEPOOL
Transmission Plan. The RFP shall be prepared by the System Operator which shall,
to the extent necessary, consult with the Transmission Owner(s) to obtain
necessary data, information and technical specifications that the System
Operator requires to prepare the RFP. The RFP shall include appropriate
requirements to safeguard the confidential nature of information provided by a
Transmission Owner in accordance with applicable commercial practices, the
requirements of the NEPOOL Information Policy and the requirements of any
applicable Commission order. Each such RFP shall require that respondents meet
specified technical and financial qualifications and submit proposals (i) that
conform with all the requirements of subsection (a) of Section 51.3 and
reasonable Transmission Owner requirements and specifications identified in the
RFP which are not inconsistent with Commission policy, (ii) that are consistent
with other applicable accepted engineering practices, governmental, technical,
and financial requirements, and (iii) that do not use a Transmission Owner's
facilities, rights-of-way or other property, provided that the affected
Transmission Owner may voluntarily agree, in its own discretion, to the use of
its property in connection with a proposal.
(b) The System Operator shall develop selection criteria in consultation with
the Transmission Expansion Advisory Committee and post the criteria on the
System Operator's website before it issues the RFP. The evaluation criteria may
consider any or all of the following non-exclusive factors: (i) the
qualifications of the entity that would be responsible for implementing the
proposal to build the proposed Upgrade; (ii) the estimated financial and
reliability impacts on Transmission Customers and load during and after
construction and installation of the proposed Upgrade if the proposal is
accepted and implemented; (iii) the timing for completion of the proposal; (iv)
the assurance that the entity responsible for implementing the proposal is able
to perform; and (v) the mobilization or demobilization of facilities affected by
the building of the proposed Upgrade during construction and installation.
(c) The issuance of an RFP for an Upgrade shall not preclude the modification of
a NEPOOL Transmission Plan in accordance with Section 51.4(c), including,
without limitation, a modification that eliminates such Upgrade from the
recommended plan.
(d) Any entity whose proposal is accepted by the System Operator in accordance
with subsection (b) shall be compensated in accordance with the terms of its
accepted proposal.
(e) An RFP shall not be required for an Upgrade under this Section 51.6 if the
Upgrade is initially included in the 2000 Plan or its estimated cost is less
than $10 million. In such circumstances, the Transmission Owner or Owners on
whose system(s) the proposed Upgrade in the Plan is located, or its/their
designee(s), shall be designated as the appropriate entity responsible for
completion of that Upgrade, in accordance with the requirements of Section 51.7.
(f) No proposed Merchant Transmission Facility and no Upgrade that uses the
facilities, rights-of-way or other property of a Transmission Owner, except as
the affected Transmission Owner may voluntarily agree, in its own discretion, to
such use, shall be the subject of the RFP process of this Section 51.6. No
provision of Section 51 affects any obligations to interconnect new customers to
the NEPOOL Transmission System imposed by other provisions of this Tariff or the
Federal Power Act.
53.7 Obligations of Transmission Owners to Build:
(a) If a Transmission Owner is responsible for completion of an Upgrade
identified in a NEPOOL Transmission Plan in accordance with subsection (e) of
Section 51.6, or the Upgrade is a Reliability Upgrade and construction is not
being accomplished in accordance with a proposal accepted by the System Operator
in accordance with subsection (b) of Section 51.6, or if the Transmission Owner
is otherwise required to complete an Upgrade in accordance with provisions of
Part III, V or VI of the Tariff or applicable regulations or statutes, the
Transmission Owner shall use its reasonable efforts to design, construct and
place the proposed Upgrade into service or enter into appropriate contracts to
fulfill such obligations, subject to a Transmission Owner's ability to: (i)
satisfy the requirements of applicable law, government regulations and
approvals, including, without limitation, requirements to obtain any necessary
state or local siting, construction and operating permits; (ii) obtain required
financing; (iii) acquire necessary rights-of-way; (iv) recover, pursuant to
appropriate financial arrangements and tariffs or contracts, all reasonably
incurred costs, plus a reasonable return on investment; and (v) comply with
Sections 18.4 and 18.5 of the Agreement.
(b) Any Transmission Owner may seek recovery for the costs of an Upgrade for
which it is responsible under this Section 51.7 on any basis it determines
appropriate, including on an incremental cost basis; provided that rates,
charges and terms and conditions for such recovery are accepted or approved by
the Commission. Nothing herein shall prohibit or otherwise restrict the ability
of affected entities to protest, challenge, comment upon or object to efforts by
any Transmission Owner to obtain regulatory approval of any proposed mechanism
for recovery by such Owner of the costs of such Upgrade.
53.8 Merchant Transmission Facilities; Compliance:
(a) Subject to compliance with the requirements of Section 18.4 and 18.5 of the
Agreement and any other applicable requirements with respect to the
interconnection of bulk power facilities with the NEPOOL Transmission System,
any entity shall have the right to propose and construct the addition of
transmission facilities outside the Plan, none of the costs of which shall be
Pool-Supported PTF or covered under Schedule 11 or 12 of this Tariff ("Merchant
Transmission Facilities"). Any such Merchant Transmission Facilities shall be
subject to the requirements of subsection (b) below. In performing studies in
connection with the NEPOOL Transmission Plan, the prospect that proposed
Merchant Transmission Facilities will be completed shall be accounted for on the
same basis as the prospect that proposed generating units will be completed.
(b) All Merchant Transmission Facilities shall comply with Sections 18.4 and
18.5 of the Agreement and shall be subject to: (i) agreements between the
proposed owner of such Merchant Transmission Facilities and the affected
Transmission Owners covering the interconnection of the Merchant Transmission
Facilities, said agreement not to be unreasonably withheld; (ii) agreements with
one or more Transmission Owners or the System Operator establishing
responsibility for the operation and maintenance of the Merchant Transmission
Facilities; (iii) agreements with any affected Transmission Owner or other
entity for access to and/or use of the property of such entity, as may be
necessary for the completion and operation of the Merchant Transmission
Facilities; (iv) if any such owner of the Merchant Transmission Facilities is
not a Participant, an agreement (A) to transfer to the System Operator
operational authority of any facilities rated 69 kV or above which constitute
part of the Merchant Transmission Facilities that are to be integrated with, or
that will affect, the NEPOOL Transmission System and (B) that comply with the
requirements of Sections 13, 21.3 and 21.7 of the Agreement, to the same extent
if such owner were a Participant; and (v) taking such other action as may be
required to make the facility available for use as part of the NEPOOL
Transmission System. A Transmission Owner shall have the right to require that
any agreement providing for the interconnection of any Merchant Transmission
Facilities with its own facilities includes requirements that the Merchant
Transmission Facilities' owner provide security, credit assurances and/or
deposits deemed necessary by the Transmission Owner, subject to Commission
acceptance or approval.
53.9 Alternative Remedies: Nothing herein shall limit in any way the right
of any entity to seek any available relief pursuant to the provisions of the
Federal Power Act.
1 "Quick Fix" Measures
Commencing as promptly as possible in 2000, and to the extent practicable,
Transmission Owners and the System Operator shall recommend cost effective
"quick fix" measures that they reasonably believe can be constructed/installed
in less than thirty (30) days and that reduce the likelihood of Congestion or
the running of generation resources out of merit order. These measures shall
include, but are not limited to, resagging transmission lines, relay changes or
additions, raising transmission structures, better coordination of maintenance
outages between the System Operator, Transmission Owners and the Satellites,
using temperature sensitive ratings, replacing limiting equipment such as
wavetraps and disconnect switches, transferring load, installing reactors and
capacitors, and sectionalizing lines. The Transmission Owners and the System
Operator shall recommend cost effective "quick fix" measures during 2000 and
2001. All expenses and capital investments incurred during 2000 and 2001 that
are related to these measures shall constitute Pool-Supported PTF costs and
shall be recovered through NEPOOL transmission charges, including the Post-1996
Pool PTF Rate. The System Operator and Transmission Owners will report to the
Participant Committee quarterly beginning in March 2000 as to which measures
have been completed or if any difficulties are occurring that prevent the
identification or implementation of such measures.
SCHEDULE 1
Scheduling, System Control and Dispatch Service
Scheduling, System Control and Dispatch Service is the service required to
schedule at the pool level the movement of power through, out of, within, or
into the NEPOOL Control Area. Local level service is provided under the Local
Network Service tariffs of the Participants which are the individual
Transmission Providers. For transmission service under this Tariff, this
Ancillary Service can be provided only by the System Operator and the
Transmission Customer must purchase this service from the System Operator.
Charges for Scheduling, System Control and Dispatch Service are to be based on
the expenses incurred by the System Operator, and by the individual Transmission
Providers in the operation of satellite dispatch centers or otherwise, to
provide these services. Effective as of January 1, 1999, or such other date as
the Commission may determine, the expenses incurred by the System Operator in
providing these services are to be recovered under its Tariff for Transmission
Dispatch and Power Administration Services, which has been filed in Docket No.
ER98-3554-000. A surcharge for the expenses incurred by Participants in the
provision of these services will be added to the Internal Point-to-Point Service
rate, to the Through or Out Service rate and to the Regional Network Service
rate.
The expenses incurred in providing Scheduling, System Control and Dispatch
Service for each Participant will be determined by an annual calculation based
on the previous calendar year's data as shown, in the case of Transmission
Providers which are subject to the Commission's jurisdiction, in the
Participants' FERC Form 1 report for that year, and shall be based on actual
data in lieu of allocated data if specifically identified in the Form 1 report.
This amended Schedule 1 shall be effective as of January 1, 1999, or such other
date as the Commission may determine. The surcharge shall be redetermined
annually as of June 1 in each year and shall be in effect for the succeeding
twelve months. The rate surcharge per kilowatt for each month is one-twelfth of
the amount derived by dividing the total annual Participant expenses for
providing the service by the sum of the average of the coincident Monthly Peaks
(as defined in Section 46.1) of all Local Networks for the prior calendar year.
Each Participant or Non-Participant which is obligated to pay the rate for
Regional Network Service for a month shall pay the surcharge on the basis of the
number of kilowatts of its Monthly Network Load (as defined in Section 46.1) for
the month. Each Participant or Non-Participant which is obligated to pay the
rate for Internal Point-to-Point Service or Through or Out Service for the
applicable period shall pay the surcharge on the basis of the highest amount of
its Reserved Capacity for each transaction scheduled as Internal Point-to-Point
Service and/or Through or Out Service for such period.
The revenues received under this Schedule 1 to cover the expenses incurred by
Participants for providing Scheduling, System Control and Dispatch Service shall
be allocated each month among the Participants whose satellite or other costs
are reflected in the computation of the surcharge for the service in proportion
to the costs for each which are reflected in the computation of the surcharge.
The details for implementation of Schedule 1 shall be established in accordance
with a rule approved by the Regional Transmission Operations Committee which
shall be filed with the Commission and considered a supplement to this Tariff.
SCHEDULE 2
Reactive Supply and Voltage Control from
Generation Sources Service
In order to maintain transmission voltages on the NEPOOL Transmission System
within acceptable limits, generation facilities are operated to produce (or
absorb) reactive power. Thus, Reactive Supply and Voltage Control from
Generation Sources Service must be provided for each transaction on the NEPOOL
Transmission System. The amount of Reactive Supply and Voltage Control from
Generation Sources Service that must be supplied with respect to a Transmission
Customer's transaction will be determined based on the reactive power support
necessary to maintain transmission voltages within limits that are generally
accepted in the region and consistently adhered to by the Participants.
Reactive Supply and Voltage Control from Generation Sources Service is to be
provided through the Participants and the System Operator and the Transmission
Customer must purchase this service from the Participants through the System
Operator when the System Operator (or applicable satellite dispatching center)
determines, in the exercise of its discretion, that it is necessary to direct a
generating unit to alter its operations in an hour in order to provide such
service. The charge for each hour for such service, when required by the System
Operator (or satellite dispatching center) as set forth above, shall be paid by
each Participant or Non-Participant which receives either Regional Network
Service or Internal Point-to-Point Service or Through or Out Service and shall
be determined in accordance with the following formula:
The formula in Schedule 2 is amended to read as follows:
(EQUATION)
in which
CH = the amount to be paid by the Participant or Non-Participant for
the hour;
CC = the capacity costs for the hour, which shall be stated in an
informational filing with the Commission;
LOC = the lost opportunity costs for the hour to be paid to Participants
who provide VAR support;
PC = the portion of the amount paid to Participants for the hour for Energy
produced by a generating unit that is considered under the applicable
Implementation Rule to be paid for VAR support;
SCL = the cost of energy used in the hour by generating facilities, synchronous
condensers or static controlled VAR regulators in order to provide VAR support
to the transmission system;
HL1 = the Network Load of the Participant or Non-Participant for the
hour;
HL = the aggregate of the Network Loads of all Participants and Non-
Participants for the hour;
RC1 = the Reserved Capacity for Internal Point-to-Point Service and/or
Through or Out Service of the Participant or Non-Participant for the hour; and
RC = the aggregate Reserved Capacity for Internal Point-to-Point Service and/or
Through or Out Service of all Participants and Non-Participants for the hour.
SCHEDULE 3
Regulation and Frequency Response Service
(Automatic Generation Control)
Regulation and Frequency Response Service (Automatic Generation Control or AGC)
is necessary to provide for continuous balancing of resources (generation and
interchange) with load, and for maintaining scheduled interconnection frequency
at sixty cycles per second (60 Hz). Regulation and Frequency Response Service
(Automatic Generation Control) is accomplished by dispatching on-line resources
whose output is raised or lowered (predominantly through the use of automatic
generating control equipment) as necessary to follow the moment-by-moment
changes in load. The obligation to maintain this balance between resources and
load lies with the System Operator and this service will be available to all
Participants and other entities that serve load within the NEPOOL Control Area
either under the Agreement for Participants or pursuant to Service Agreements
with Non- Participants entered into under the Tariff. The Transmission Customer
must either take this service from the System Operator pursuant to the Tariff or
under the Agreement or make alternative comparable arrangements to satisfy its
Regulation and Frequency Response Service (Automatic Generation Control)
obligation.
Until the CMS/MSS Effective Date, charges for this Service will be determined on
the basis of bids submitted by Participants in accordance with Section 14 of the
Agreement and applicable Market Rules. After the CMS/MSS Effective Date, charges
for this Service will be determined on the basis of Supply Offer Prices
submitted by Participants in accordance with Section 14A of the Agreement and
applicable Market Rules. In either case, the per unit charge for this service to
Non-Participants shall be the same as determined for Participants under Section
14.10 of the Agreement prior to the CMS/MSS Effective Date, and under Section
14A.8(c) of the Agreement and applicable Market Rules on and after the CMS/MSS
Effective Date.
The transmission service required with respect to Regulation and Frequency
Response Service (Automatic Generation Control) will be paid for as part of
Regional Network Service or Internal Point-to-Point Service by all Participants
and other entities serving load in the NEPOOL Control Area. The charge for
Regional Network Service is determined in accordance with Schedule 9 of the
Tariff. The charge for Internal Point-to-Point Service is determined in
accordance with Schedule 10 of the Tariff.
Sheet No. 204 is intentionally blank.
SCHEDULE 4
Energy Imbalance Service
Energy Imbalance Service is the service provided when a difference occurs
between the scheduled and the actual delivery of energy to a load located within
the NEPOOL Control Area during a single hour. The Transmission Customer may
either supply its load from its own resources or through bilateral arrangements
or obtain the service under the Agreement. This service will be available to all
Participants and other entities that serve load within the NEPOOL Control Area
either under the Agreement for Participants or pursuant to Service Agreements
with Non-Participants entered into under the Tariff. The prices for such service
will be determined in accordance with Section 14 of the Agreement and applicable
Market Rules until the CMS/MSS Effective Date, and will be the applicable
Locational Prices determined pursuant to Section 14A.12 of the Agreement and
applicable Market Rules on and after the CMS/MSS Effective Date.
The transmission service required with respect to Energy Imbalance Service under
the Agreement will be furnished as part of Regional Network Service or Internal
Point-to-Point Service to all Participants and other entities serving load in
the NEPOOL Control Area. The charges for Regional Network Service are determined
in accordance with Schedule 9 of the Tariff. The charges for Internal
Point-to-Point Service are determined in accordance with Schedule 10 of the
Tariff.
SCHEDULE 5
Operating Reserve - 10-Minute Spinning Reserve Service
10-Minute Spinning Reserve Service is a service needed to serve load immediately
in the event of a system contingency. This service will be available to all
Participants and other entities that serve load within the NEPOOL Control Area.
The Transmission Customer may either supply this service with its own resources
or through bilateral arrangements, or obtain the service either under the
Agreement for Participants or pursuant to Service Agreements with
Non-Participants entered into under the Tariff.
The total of each category of Operating Reserve requirements for the NEPOOL
Control Area in each hour is determined by the System Operator in accordance
with applicable NEPOOL System Rules. The currently applicable NEPOOL System
Rule, Operating Procedure No. 8, is on file with the Commission as a supplement
to the Tariff.
Under Section 14 of the Agreement, until the CMS/MSS Effective Date, the price
to be paid for Operating Reserve Service received in any hour will be the
Operating Reserve Clearing Price for the hour for that category of reserve
service, as determined on the basis of bids to provide the service plus any
applicable uplift charge.
On and after the CMS/MSS Effective Date, the price to be paid for Operating
Reserve Service shall be determined in accordance with Section 14A.8(b) of the
Agreement. In accordance with Section 14A.1(c) of the Agreement, Participants
and Non-Participant Transmission Customers shall be assigned Settlement
Obligations by the System Operator, which are used to allocate among the
Participants and Non-Participant Transmission Customers cost responsibility for
each category of Operating Reserve that is not self- supplied. The allocated
costs that must be paid for each category of Operating Reserve following the
CMS/MSS Effective Date are determined in accordance with Sections 14A.1(c) and
14A.8(c) of the Agreement.
The transmission service required with respect to Operating Reserve will be paid
for as part of Regional Network Service or Internal Point-to-Point Service by
all Participants and other entities serving load in the NEPOOL Control Area. The
charge for Regional Network Service is determined in accordance with Schedule 9
of the Tariff. The charge for Internal Point-to- Point Service is determined in
accordance with Schedule 10 of the Tariff.
SCHEDULE 6
Operating Reserve - 10-Minute Non-Spinning Reserve Service
10-Minute Non-Spinning Reserve Service is a service needed to serve load in the
event of a system contingency. This service will be available to all
Participants and other entities that serve load within the NEPOOL Control Area.
The Transmission Customer may either supply this service with its own resources
or through bilateral arrangements, or obtain the service either under the
Agreement for Participants or pursuant to Service Agreement with
Non-Participants entered into under the Tariff.
The total of each category of Operating Reserve requirements for the NEPOOL
Control Area in each hour is determined by the System Operator in accordance
with applicable NEPOOL System Rules. The currently applicable NEPOOL System
Rule, Operating Procedure No. 8, is on file with the Commission as a supplement
to the Tariff.
Under Section 14 of the Agreement, until the CMS/MSS Effective Date, the price
to be paid for Operating Reserve Service received in any hour will be the
Operating Reserve Clearing Price for the hour for that category of reserve
service, as determined on the basis of bids to provide the service plus any
applicable uplift charge.
On and after the CMS/MSS Effective Date, the price to be paid for Operating
Reserve Services shall be determined in accordance with Section 14A.8(b) of the
Agreement. In accordance with Section 14A.1(c) of the Agreement, Participants
and Non-Participant Transmission Customers shall be assigned Settlement
Obligations by the System Operator, which are used to allocate among the
Participants and Non-Participant Transmission Customers cost responsibility for
each category of Operating Reserve that is not self- supplied. The allocated
costs that must be paid for each category of Operating Reserve following the
CMS/MSS Effective Date are determined in accordance with Sections 14A.1(c) and
14A.8(c) of the Agreement.
The transmission service required with respect to Operating Reserve will be
furnished as part of Regional Network Service or Internal Point-to-Point Service
to all Participants and other entities serving load in the NEPOOL Control Area.
The charge for Regional Network Service is determined in accordance with
Schedule 9 of the Tariff. The charge for Internal Point-to- Point Service is
determined in accordance with Schedule 10 of the Tariff.
SCHEDULE 7
Operating Reserve - 30-Minute Reserve Service
30-Minute Reserve Service is a service needed to serve load in the event of a
system contingency. This service will be available to all Participants and other
entities that serve load within the NEPOOL Control Area. The Transmission
Customer may either supply this service with its own resources or through
bilateral arrangements, or obtain the service either under the Agreement for
Participants or pursuant to Service Agreements with Non- Participants entered
into under the Tariff.
The total of each category of Operating Reserve requirements for the NEPOOL
Control Area in each hour is determined by the System Operator in accordance
with applicable NEPOOL System Rules. The currently applicable NEPOOL System
Rule, Operating Procedure No. 8, is on file with the Commission as a supplement
to the Tariff.
Under Section 14 of the Agreement, until the CMS/MSS Effective Date, the price
to be paid for Operating Reserve Service received in any hour will be the
Operating Reserve Clearing Price for the hour for that category of reserve
service, as determined on the basis of bids to provide the service plus any
applicable uplift charge.
On and after the CMS/MSS Effective Date, the price to be paid for Operating
Reserve Service shall be determined in accordance with Section 14A.8(b) of the
Agreement. In accordance with Section 14A.1(c) of the Agreement, Participants
and Non-Participant Transmission Customers shall be assigned Settlement
Obligations by the System Operator, which are used to allocate among the
Participants and Non-Participant Transmission Customers cost responsibility for
each category of Operating Reserve that is not self- supplied. The allocated
costs that must be paid for each category of Operating Reserve following the
CMS/MSS Effective Date are determined in accordance with Sections 14A.1(c) and
14A.8(c) of the Agreement.
The transmission service required with respect to Operating Reserve will be
furnished as part of Regional Network Service or Internal Point-to-Point Service
to all Participants and other entities serving load in the NEPOOL Control Area.
The charge for Regional Network Service is determined in accordance with
Schedule 9 of the Tariff. The charge for Internal Point-to- Point Service is
determined in accordance with Schedule 10 of the Tariff.
SCHEDULE 8
Through or Out Service -
The Pool PTF Rate
(1) A Transmission Customer shall pay to NEPOOL for firm or non-firm Through or
Out Service reserved for it in accordance with Section 19 of the Tariff the
highest of (a) the Pool PTF Rate or (b)a rate which is derived from the annual
incremental cost, not otherwise borne by the Transmission Customer or a
Generator Owner, of any new facilities or upgrades that would not be required
but for the need to provide the requested service or (c) a rate which is equal
to NEPOOL's opportunity cost (if and when available) capped at the cost of
expansion, as determined for the period of service in accordance with Section 20
of this Tariff. If at any time NEPOOL proposes to charge a rate based on
opportunity cost, it shall first file with the Commission procedures for
computing opportunity cost pricing for all Transmission Customers. The
Transmission Customer shall also be obligated to pay any applicable ancillary
service charges and any congestion or other uplift charge required to be paid
pursuant to Section 24 of this Tariff.
(2) The Pool PTF Rate in effect at any time shall be determined annually on the
basis of the information for the most recent calendar year contained in Form 1
filings (or similar information on the books of Transmission Providers that are
not required to submit a Form 1 filing) and shall be changed annually effective
as of June 1 in each year. The Pool PTF rate shall be equal to (i) the sum for
all Participants of Annual Transmission Revenue Requirements determined in
accordance with Attachment F divided by (ii) the sum of the coincident Monthly
Peaks (as defined in Section 46.1) of all Local Networks, excluding from the
Monthly Peak for each Local Network as applicable the loads at each applicable
Point of Delivery of each Participant or Non-Participant which has elected to
take Internal Point-to-Point Service in lieu of Regional Network Service at one
or more Points of Delivery; plus the Long-Term Firm Reserved Capacity amount for
each such Participant or Non- Participant which has elected to take Firm
Internal Point-to-Point Service in lieu of Regional Network Service at one or
more Points of Delivery plus the Long-Term Reserved Capacity amount for each
Participant or Non-Participant for Firm Through or Out Service. Revenues
associated with Short-Term Point- to-Point reservations will be credited to the
sum of all Participants' Annual Transmission Revenue Requirements referred to in
(i) above.
(3) Discounts: Three principal requirements apply to discounts for Through or
Out Service as follows (1) any offer of a discount made by the Participants must
be announced to all Eligible Customers solely by posting on the OASIS, (2) any
customer-initiated requests for discounts (including requests for use by one's
wholesale merchant or an affiliate's use) must occur solely by posting on the
OASIS, and (3) once a discount is negotiated, details must be immediately posted
on the OASIS. For any discount agreed upon for service on a path, from Point(s)
of Receipt to Point(s) of Delivery, the Participants must offer the same
discounted transmission service rate for the same time period to all Eligible
Customers on all unconstrained transmission paths that go to the same Point(s)
of Delivery on the NEPOOL Transmission System.
SCHEDULE 9
Regional Network Service
(1) A Transmission Customer which serves a Network Load in the NEPOOL Control
Area shall pay to NEPOOL each month for Regional Network Service the amount
determined in accordance with the following formula:
A = 1/12 (R . L)
in which
A = the amount to be paid
R = the Participant RNS Rate per Kilowatt for the current Year for the
Participant which owns the Local Network from which the Customer's load is
served
L = the Customer's Monthly Network Load for the month
It shall also be obligated to pay any ancillary charges and any applicable
congestion or other uplift charge required to be paid pursuant to Sections 24,
25A and 25B of this Tariff.
Each Participant RNS Rate is to be determined in accordance with the remaining
provisions of this Schedule 9. The Participants intend that the rate will be
determined by looking separately at the costs associated with facilities which
are in service at December 31, 1996, and the costs associated with new
facilities which are placed in service after December 31, 1996. Costs of new
facilities are to be shared regionally on a per Kilowatt basis in determining
the rates of each of the Participants with a Local Network, unless otherwise
allocated to a particular entity pursuant to this Tariff.
Costs of existing facilities are to be determined separately for each
Participant and reflected in the rate for service to Transmission Customers
serving load in the Participant's Local Network. This is initially subject to a
band width which limits the variation of the Participant per Kilowatt cost from
the average per Kilowatt cost for all Participants to not less than 70%, or more
than 130%, of the average cost.
(2) The Pool RNS Rate per Kilowatt is $1 in Year One, $4 in Year Two, $7 in Year
Three, $10 in Year Four and $13 in Years Five and Six and the period from the
end of Year Six to the next succeeding June 1, and is equal to the Pool PTF Rate
for each Year thereafter.
(3) The Participant RNS Rate for a Participant for a Year shall be a percentage
of the Pool RNS Rate for the year and shall be equal to the Pool RNS Rate after
the end of the transitional period described in paragraph (4) of this Schedule.
The percentage for each Participant for each Year shall equal the percentage
which the sum of (i) the Participant's pre-1997 Participant RNS Rate and (ii)
the post-1996 Pool PTF Rate represents of (iii) the Pool PTF Rate for the Year.
(4) The pre-1997 Participant RNS Rate for each Participant shall be determined
by comparing its individual pre-1997 PTF Rate, for the most recent calendar year
for which information is available from Form 1 filings or otherwise to the
pre-1997 Pool PTF Rate for the same calendar year. If the Participant's
individual pre-1997 PTF Rate for a Year is less than the pre- 1997 Pool PTF
Rate, its pre-1997 Participant RNS Rate for the Year shall be the rate
determined by reducing the pre-1997 Pool PTF Rate by the percentage which the
Participant's pre-1997 PTF Rate is less than the pre-1997 Pool PTF Rate;
provided that in no event shall its pre-1997 Participant RNS Rate be less than
70% of the pre-1997 Pool PTF Rate, until the end of Year Five, and thereafter
shall be no less than 50% of the pre-1997 Pool PTF Rate for Year Six through
Year Eleven, and shall be equal to the pre-1997 Pool PTF Rate for Year Twelve
and thereafter. If the Participant's individual pre-1997 PTF Rate is greater
than the pre-1997 Pool PTF Rate, its pre-1997 Participant RNS Rate shall be the
rate determined by increasing the pre-1997 Pool PTF Rate by the percentage which
its pre-1997 Participant PTF Rate is greater than the pre-1997 Pool PTF Rate;
provided that in no event shall its pre-1997 Participant RNS Rate be greater
than 130% of the pre-1997 Pool PTF Rate until the end of Year Six, and
thereafter shall be no greater than 127% of the pre- 1997 Pool PTF Rate for Year
Six, 123% of the pre-1997 Pool PTF Rate for Year Eight, 118% of the pre-1997
Pool PTF Rate for Year Nine, 112% of the pre-1997 Pool PTF Rate for Year Ten,
105% of the pre-1997 Pool PTF Rate for Year Eleven, and shall be equal to the
pre-1997 Pool PTF Rate for Year Twelve and thereafter. If for any Year the
revenues to be received from the payment by Participants or other Transmission
Customers of their respective applicable Participant RNS Rates will average more
or less than the Pool PTF Rate per Kilowatt for the Year, each Participant RNS
Rate will be increased or decreased, as appropriate, so that the revenues to be
received per Kilowatt per Year will equal the Pool PTF Rate per Kilowatt for the
Year.
(5) The individual pre-1997 PTF Rate of a Participant which owns a Local Network
for a year is the amount derived annually by dividing its Annual Transmission
Revenue Requirements for the most recent calendar year for which information is
available from Form 1 filings (or similar information on the books of
Transmission Providers that are not required to submit a Form 1 filing) with
respect to PTF placed in service before January 1, 1997, as determined in
accordance with Attachment F to this Tariff, by the average for the twelve
months of the calendar year on which the rate is based of the sum of the
coincident Monthly Peaks for the Local Network, as adjusted each month for
losses, excluding from the Monthly Peak the load at each applicable Point of
Delivery of each Participant or Non-Participant which has elected to take
Internal Point-to-Point Service in lieu of Regional Network Service at one or
more Points of Delivery; plus the Long-Term Firm Reserved Capacity amount for
each such Participant or Non-Participant which has elected to take Firm Internal
Point-to-Point Service in lieu of Regional Network Service at one or more Points
of Delivery.
(6) The pre-1997 Pool PTF Rate shall be determined in accordance with the
following formula:
(EQUATION)
and the post-1996 Pool PTF Rate shall be determined in accordance with the
following formula:
(EQUATION)
in which
R = the pre-1997 Pool PTF Rate
R' = the post-1996 Pool PTF Rate
ATRR = the aggregate of the Annual Transmission Revenue Requirements of the
Participants with respect to PTF placed in service before January 1, 1997, as
determined in accordance with Attachment F to this Tariff.
ATRR' = the aggregate of the Annual Transmission Revenue Requirements of the
Participants with respect to PTF placed in service on or after January 1, 1997,
including upgrades, modifications or additions to PTF placed in service before
January 1, 1997, as determined in accordance with Attachment F to this Tariff.
ARNL = the average for the twelve months of the calendar year on which the rate
is based of the sum of the coincident Monthly Peaks for all Local Networks, as
adjusted each month for NEPOOL losses, excluding from the Monthly Peak for each
Local Network as applicable the load at each applicable Point of Delivery of
each Participant or Non-Participant which has elected to take Internal
Point-to-Point Service in lieu of Regional Network Service at one or more Points
of Delivery; plus the Long-Term Firm Reserved Capacity amount for each such
Participant or Non-Participant which has elected to take Firm Internal
Point-to-Point Service in lieu of Regional Network Service at one or more Points
of Delivery plus the Long-Term Reserved Capacity amount for each Participant or
Non-Participant for Firm Through or Out Service.
(7) As used in this Schedule, "Monthly Peak" and "Monthly Network Load" each has
the meaning specified in Section 46.1 of this Tariff.
(8) With the exception of any provision of this Schedule relating to the
determination or application of the post-1996 Pool PTF Rate and technical
changes to the last sentence of paragraph (4) of this Schedule 9 to allocate
costs as necessary to keep Participants within the band widths identified in
that paragraph, the provisions of this Schedule 9 shall not be amended for
service rendered under the NEPOOL Tariff through December 31, 2003, except by
agreement in writing of the parties executing the Settlement Agreement in FERC
Docket Nos. OA97-237-000 et al. and compliance with the applicable requirements
of the Restated NEPOOL Agreement.
SCHEDULE 10
Internal Point-to-Point Service
(1) A Transmission Customer shall pay to NEPOOL for firm or non-firm Internal
Point-to-Point Service reserved for it in accordance with Section 19 of the
Tariff a charge per Kilowatt, as determined for the period of the service in
accordance with Section 21 of this Tariff, equal to the Internal Point-to-Point
Service Rate; provided if either or both (i) a rate which is derived from the
annual incremental cost not otherwise borne by the Transmission Customer or a
Generator Owner, of any new facilities or upgrades that would not be required
but for the need to provide the requested service or (ii) a rate which is equal
to NEPOOL's opportunity cost (if and when available) capped at the cost of
expansion, is greater than the Pool PTF Rate the charge shall be the higher of
such amounts; provided further that no such charge shall be payable with respect
to the use of Internal Point-to-Point Service to effect a delivery to the NEPOOL
power exchange in an Interchange Transaction. If at any time NEPOOL proposes to
charge a rate based on opportunity cost, it shall first file with the Commission
procedures for computing opportunity cost pricing for all Transmission
Customers. The Customer shall also be obligated to pay any applicable ancillary
service charge and any applicable congestion or other uplift charge required to
be paid pursuant to Sections 24, 25A and 25B of this Tariff.
(2) Discounts: Three principal requirements apply to discounts for Internal
Point-to-Point Service as follows (1) any offer of a discount made by the
Participants must be announced to all Eligible Customers solely by posting on
the OASIS, (2) any customer-initiated requests for discounts (including requests
for use by one's wholesale merchant or an affiliate's use) must occur solely by
posting on the OASIS, and (3) once a discount is negotiated, details must be
immediately posted on the OASIS. For any discount agreed upon for service on a
path, from Point(s) of Receipt to Point(s) of Delivery, the Participants must
offer the same discounted transmission service rate for the same time period to
all Eligible Customers on all unconstrained transmission paths that go to the
same Point(s) of Delivery on the NEPOOL Transmission System.
SCHEDULE 11
Generator Interconnection Related Upgrade Costs
(1) Classification of Generating Projects. The treatment for purposes of this
Tariff of the Generator Interconnection Related Upgrade costs with respect to
the facilities needed for the interconnection of a particular new or modified
generating unit project in accordance with Section 50 of the Tariff depends on
whether the project is a Category A Project, a Category B Project or a Category
C Project, as follows:
(a) A Category A Project is one whose Generator Owner committed to pay for
upgrade costs prior to October 29, 1998 and has filed a petition with the
Commission requesting that the costs associated with the interconnection of its
generation project be determined in accordance with Schedule 11 of the Tariff,
as filed with the Thirty-Sixth Agreement Amending the Restated NEPOOL Agreement.
Subject to the outcome of proceedings pending before the Commission in Docket
No. ER98-3853, including all appeals, and consistent with the Commission's June
28, 2000 order in Docket Nos. EL00-62-000, et al., and further Commission orders
with respect thereto, the following projects have been identified as potentially
being Category A Projects:
EMI Dighton
EMI Tiverton
EMI Rumford
Polsky AEC
Millennium Power Partners, L.P.
PDC Berkshire
Duke, Bridgeport Energy
Duke, Maine Independence
(b) A Category B Project is any one, other than a Category A Project, on which
the Generator Owner had expended at least $5,000,000, including amounts due
under irrevocable commitments, as of June 22, 1999 with respect to the project.
The Category B Projects are:
Sithe, Mystic Station Expansion Sithe Edgar Station Expansion, Fore River Sithe,
West Medway PG&E, Generating Lake Road Generating PDC, Milford Power PDC,
Meriden Power Reliant Energy, Hope Rhode Island IDC FPL, Bellingham
Constellation, Merrimack (Nickel Hill) Energy Project SEI, Canal Re-powering
ANP, Bellingham ANP, Blackstone Cabot, Island End Calpine, Westbrook Power HQ,
Bucksport AES, Londonderry ConEd, Newington
(c) A Category C Project is any project which is not a Category A Project or
a Category B Project.
(2) Direct Interconnection Transmission Costs. Direct Interconnection
Transmission Costs shall mean the cost of facilities constructed for sole use of
the Generator Owner that are not PTF. One hundred percent of Direct
Interconnection Transmission Costs shall be the responsibility of the Generator
Owner whether the Generator Owner's project is a Category A Project, a Category
B Project or a Category C Project.
(3) Treatment of Category A Project Transmission Costs. The allocation of
costs of Generator Interconnection Related Upgrades for Category A Projects
will be determined as follows:
(a) One-half of the Shared Amount (as defined below) of the capital cost of the
PTF upgrade shall constitute Pool-Supported PTF and be included in Annual
Transmission Revenue Requirements under Attachment F. The Generator Owner shall
be obligated to pay, in addition to the Direct Interconnection Transmission
Costs, the other half of the Shared Amount of the capital cost of the PTF
upgrade and all of the capital costs in excess of the Shared Amount, and any
applicable tax gross-up amounts, and such amounts to be paid by the Generator
Owner shall not be included in Annual Transmission Revenue Requirements under
Attachment F. Following completion of the construction or modification of the
Generator Interconnection Related Upgrade, the Generator Owner shall be
obligated to pay its pro rata share of all of the annual costs (including cost
of capital, federal and state income taxes, O&M and A&G expenses, annual
property taxes and other related costs) which are allocable to such upgrade,
pursuant to the interconnection agreement with the individual Transmission Owner
or its designee which is responsible for the construction or modification, which
agreement may be filed with the Commission by the Transmission Owner unsigned
either on its own or at the request of the Generator Owner.
(b) In determining the cost responsibilities related to a Generator
Interconnection Related Upgrade to PTF, the Participants Committee may determine
that all or a portion of the proposed facilities exceed regional system,
regulatory or other public requirements. In such a case, the Participants
Committee shall determine the amount of the excess costs of the Generator
Interconnection Related Upgrade which shall be borne by the entity which is
responsible for requiring such excess costs, and the excess costs shall not be
included in the calculation of the Shared Amount.
(c) The Shared Amount of the capital cost of the Generator Interconnection
Related Upgrade of PTF shall be initially determined as of the time that the
System Impact Study agreement is executed by all parties and the Generator Owner
has paid the cost of the study (such initial determination to be based on the
estimated cost of the Generator Interconnection Related Upgrade, subject to
later adjustment as set forth below) subject to truing up the KW element of the
following formula upon completion of the Generator Interconnection Upgrade, and
shall be the lesser of (1) the full actual capital cost of the Generator
Interconnection Related Upgrade of PTF (excluding any costs which are determined
to be excess costs in accordance with paragraph (b) above) or (2) the amount
determined in accordance with the following formula:
(EQUATION)
in which:
P is the maximum amount to be shared;
KW in the case of a generating unit, is the actual demonstrated net capability
of the new generating unit or increase in the capacity of an existing generating
unit corrected to 50*F in kilowatts. If winter operating conditions are shown in
the System Impact Study and/or application under Section 18.4 of the Agreement
to require additional transmission reinforcements beyond those reinforcements
required for summer operating conditions, the net capability of the unit will be
corrected to an ambient air temperature of 0*F;
R is the Pool PTF Rate in effect on the Compliance Effective Date, which is
$15.57 per kilowatt year, adjusted to reflect compliance with the April 5, 1999
Settlement Agreement, approved by the Commission by order dated July 30, 1999 in
Docket Nos. OA97-237-000, et al.; and
C is the weighted average carrying charge factor of all of the Transmission
Providers which own PTF, determined, as of the Compliance Effective Date, in
accordance with Attachment F to the Tariff, which is 15.87 percent, adjusted to
reflect compliance with the April 5, 1999 Settlement Agreement, approved by the
Commission by order dated July 30, 1999 in Docket Nos. OA97-237-000, et al.
(d) All payments required hereunder shall be determined initially on an
estimated basis, and then adjusted after the appropriate portion of the
construction or modification costs has been reflected in Tariff rates in the
first adjustment of Tariff rates after the upgrade has been placed in commercial
operation.
(e) The provisions in this Section (3) with respect to allocation of costs for
Generator Interconnection Related Upgrades of PTF for Category A projects are
subject to further clarifications and/or modifications to reflect the outcome of
proceedings in Commission Docket Nos. ER98-3853 (including any court appeals)
and EL00-62-000, et al., and further Commission orders with respect thereto.
(4) Treatment of Category B Project Transmission Costs. If, and to the extent
capital costs for, a Generator Interconnection Related Upgrade are required to
be incurred in order to satisfy the Minimum Interconnection Standard in
connection with a Category B Project, and would not have been required but for
the interconnection of the generator, one-half of such capital cost of the
Generator Interconnection Related Upgrade, other than Direct Interconnection
Transmission Costs and any excess costs as described below, up to a maximum of
two million dollars ($2,000,000) (or one-half of $4,000,000), shall constitute
Pool-Supported PTF costs and shall be included in Annual Transmission Revenue
Requirements under Attachment F of the Tariff. The Generator Owner shall be
obligated to pay the remaining costs of the Generation Interconnection Related
Upgrade required to be incurred to meet the Minimum Interconnection Standard for
the Category B Project that would not be needed but for the interconnection of
that Generator (including all Direct Interconnection Transmission Costs, any
excess costs as described below, and any applicable tax gross-up amounts) and to
pay the entire costs of any Elective Transmission Upgrade requested by such
Generator Owner (including all Direct Interconnection Transmission Costs, any
excess costs as described below, and any applicable tax gross-up amounts); and
such amounts to be paid by the Generator Owner shall not be included in Annual
Transmission Revenue Requirements under Attachment F. Following completion of
the construction or modification of the Generator Interconnection Related
Upgrade, the Generator Owner shall be obligated to pay its pro rata share of all
of the annual costs (including cost of capital, federal and state income taxes,
O&M and A&G expenses, annual property taxes and other related costs) which are
allocable to such upgrade, pursuant to the interconnection agreement with the
individual Transmission Owner or its designee which is responsible for the
construction or modification, which agreement may be filed with the Commission
by the Transmission Owner unsigned either on its own or at the request of the
Generator Owner.
In determining the cost responsibilities related to a Generator
Interconnection Related Upgrade for a particular Category B Project, the
Participants Committee may determine that all or a portion of the proposed
facilities exceed regional system, regulatory or other public requirements. In
such a case, the Participants Committee shall determine the amount of the excess
costs of the Generator Interconnection Related Upgrade which shall be borne by
the entity which is responsible for requiring such excess costs, and the excess
costs shall not be included in the calculation of the amount of the capital
costs to be shared as discussed above. All payments required hereunder shall be
determined initially on an estimated basis, and then adjusted after the
appropriate portion of the construction or modification costs has been reflected
in Tariff rates in the first adjustment of Tariff rates after the upgrade has
been placed in commercial operation.
(5) Treatment of Category C Project Transmission Costs. If a Generator
Interconnection Related Upgrade is required in order to satisfy the Minimum
Interconnection Standard in connection with a Category C Project, the Generator
Owner shall be obligated to pay all of the cost of such upgrade, including all
Direct Interconnection Transmission Costs and any applicable tax gross-up
amounts, to the extent such costs would not have been incurred but for the
interconnection. Following completion of the construction or modification, the
Generator Owner shall be obligated to pay all of the annual costs (including
federal and state income taxes, O&M and A&G expenses, annual property taxes and
other related costs) which are allocable to the Generator Interconnection
Related Upgrade, pursuant to the interconnection agreement (or support
agreement) with the individual Transmission Owner or its designee which is
responsible for the construction or modification, which agreement may be filed
with the Commission by the Transmission Owner either signed by both parties or
unsigned at the request of the Generator Owner.
(6) Treatment of Elective Transmission Upgrades for Generating Units. If a
Generator Owner has requested an Elective Transmission Upgrade pursuant to
Section 50.2 of this Tariff in connection with a new or materially changed
generation unit, the Generator Owner shall be subject to the cost, credit
assurance and contract obligations set forth in Section 50.2 and Schedule 12 for
Elective Transmission Upgrades.
(7) Contract and Credit Requirements. If a Generator Interconnection Related
Upgrade is required, the Generator Owner requesting such upgrade, at the request
of the Transmission Owner or its designee responsible for effecting the
construction or modification, shall be obligated to pay to the Transmission
Owner or its designee responsible for effecting the Generator Interconnection
Related Upgrade an amount equal to its share of the estimated cost of the
construction at one time or in monthly or other periodic installments,
including, without limitation, all costs associated with acquiring land, rights
of way easements, purchasing equipment and materials, installing, constructing,
interconnecting, and testing the facilities; O&M and engineering costs; all
related overheads; and any and all associated taxes and government fees. In
addition to, or in lieu of said payment, the affected Transmission Owner or its
designee may require the Generator Owner to provide, as security for its
obligation to pay any unfunded balance of the construction costs, a letter of
credit or other reasonable form of security acceptable to the Transmission Owner
or its designee that will be responsible for the construction equivalent to the
cost of the upgrade including taxes and consistent with relevant commercial
practices, as established by the Uniform Commercial Code. As soon as reasonably
practical, but in any event within 180 days after completion of the construction
or modifications, or as otherwise mutually agreed, the Transmission Owner or its
designee responsible for the construction or modification will determine the
difference, if any, between the estimated cost already paid by the Generator
Owner to the Transmission Owner or its designee responsible for the construction
or modification and its share of the actual cost of the construction or
modification, and will either receive from the Generator Owner, with Interest
(if the sum paid is insufficient) or pay to the Generator Owner, with Interest
(if the sum paid is surplus) the difference; provided that if, at the time such
determination is made, items of construction that remain to be completed and/or
some construction costs have not been invoiced and paid, the Transmission Owner
or its designee responsible for the construction or modification shall continue
to be entitled to recover from the Generator Owner the Generator Owner's share
of the costs of such remaining items and may retain a reserve to cover such
items. Furthermore, the Transmission Owner shall release any letter of credit or
other security instrument received by the Transmission Owner, up to the amount
allowed to be recovered through the Transmission Owner's Annual Transmission
Revenue Requirement for Category A and B Projects, no later than sixty (60) days
after the later of the reflection of such costs in the Pool rates and the
commercial operation of the generation addition or modification. To the extent
Generator Interconnection Related Upgrades, or any portion thereof, are
completed in a calendar year, Transmission Owners will use their best efforts to
reflect such facilities in their Annual Transmission Revenue Requirements
calculated on the basis of that year. That portion of the construction or
modification costs or deposit paid by the Generator Owner may, by mutual
agreement of the Transmission Owner and the Generator Owner, either be retained
by the Transmission Owner, or be refunded to the Generator Owner upon the
Generator Owner executing a contract with the Transmission Owner obligating the
Generator Owner to pay the Transmission Owner the ongoing transmission revenue
requirement associated with its share of the Generator Interconnection Related
Upgrade, including but not limited to cost of capital, federal and state income
taxes, O&M and A&G costs, annual property taxes and all other related costs, and
providing the Transmission Owner with an irrevocable letter of credit or other
form of security acceptable to the Transmission Owner. In the event the
Generator Owner's portion of the construction or modification costs is retained
by the Transmission Owner or its designee in accordance with the preceding
sentence, the Generator Owner will be obligated (i) to pay the federal and state
income taxes required to be paid by the Transmission Owner with respect to the
retained amount, and (ii) to pay annually its percentage of the O&M and A&G
costs, annual property taxes and all other related costs, except for those costs
required to be paid under (i) or any costs that are retained by the Transmission
Owner in accordance with the interconnection agreement. If the Generator Owner
for whatever reason goes out of business, or otherwise abandons its generation
project and the Generator Interconnection Related Upgrade has already been
partially or completely constructed, the Generator Owner shall be responsible
for all of the unrecovered ongoing costs of the upgrade that would not have been
incurred but for the proposed generation project. Nothing contained herein shall
prevent the Transmission Owner or its designee responsible for the construction
or modification and the Generator Owner from negotiating other methods for
providing financial security associated with the cost of an upgrade deemed
acceptable to the Transmission Owner or other entity. Subject to the foregoing,
the interconnection and support agreements for a Generation Interconnection
Related Upgrade may specify the basis for continued support of such upgrade in
the event of a termination of NEPOOL, the cancellation of the project due to a
failure to obtain regulatory approvals or permits or required rights of way or
other property, or action to terminate the project before its completion for
whatever reason and any other matters.
Interest payable hereunder shall be calculated in accordance with Section 8.3 of
the Tariff.
SCHEDULE 12
Reliability Upgrade, Economic Upgrade
and Elective Transmission Upgrade Costs
(1) Allocation and Recovery of Costs for Reliability Upgrades and Economic
Upgrades Associated with the NEPOOL Transmission Plan. All costs of Merchant
Transmission Facilities shall be recovered in accordance with the recovery
mechanism for those facilities that is filed with and accepted by the
Commission. All costs associated with Upgrades for the interconnection of
Merchant Transmission Facilities shall be treated in the same fashion and
subject to the same rights and obligations as Generator Interconnection Related
Upgrade Costs for Category C Projects under Schedule 11 of this Tariff,
including the provisions of Sections (5), (6) and (7) of that Schedule. To the
extent not otherwise covered above or by Part III or Schedule 11 of the Tariff
or Sections (2) or (3) of this Schedule 12 below, the costs of a Reliability
Upgrade and Economic Upgrade shall be allocated as follows:
(a) If entities have agreed to bear some or all of the cost responsibility for
an Upgrade, the Upgrade costs shall be allocated to such entities in accordance
with that agreement.
(b) To the extent there are Reliability Upgrade or Economic Upgrade costs that
are not allocated in accordance with other arrangements as identified in the
introductory language of this Section (1) or subparagraph (a) above, such costs
shall be allocated utilizing an appropriate cost causation and cost benefit
methodology to be specified in NEPOOL System Rules, which are to be a supplement
to the Tariff and are filed with, and accepted by, the Commission. Any
allocation to a specific entity or entities or a Reliability Region or Region(s)
pursuant to such Rules over which there is a dispute shall be filed with the
Commission and shall become effective on the date specified by the Commission.
(c) To the extent there still remain Reliability Upgrade or Economic Upgrade
costs that are not allocated in accordance with other arrangements as identified
in the introductory language of this Section (1) or subparagraphs (a) or (b)
above, or the cost allocation determined in accordance with subparagraph (b) has
not yet become effective, such costs shall be treated as Pool-Supported PTF
costs recoverable under Attachment F to this Tariff.
(2) Elective Transmission Upgrade Costs. The capital and annual costs of
Elective Transmission Upgrades and of any additions to or modifications of the
NEPOOL Transmission System that are required to accommodate the Elective
Transmission Upgrades shall not constitute Pool-Supported PTF costs and shall
not be included in Annual Transmission Revenue Requirements under Attachment F,
except to the extent approved pursuant to the Agreement. Until further review by
the NEPOOL Reliability Committee and amendment of this Tariff, contract and
credit requirements for an Elective Transmission Upgrade shall be governed by
the provisions of Section 50.2 of this Tariff.
(3) Northeast Massachusetts Upgrade Costs. In recognition of the unique
Congestion situation in the Northeast Massachusetts Reliability Region, as
identified in Attachment B to the Agreement, up to thirty-five million dollars
($35,000,000) of the capital costs of Northeast Massachusetts Upgrades shall
constitute Pool-Supported PTF costs and shall be included in Annual Transmission
Revenue Requirements under Attachment F.
A "Northeast Massachusetts Upgrade" is an addition to or modification of the
NEPOOL Transmission System into or within the Northeast Massachusetts
Reliability Region that is not, as of December 31, 1999, the subject of a System
Impact Study or application filed pursuant to Section 18.4 of the Restated
NEPOOL Agreement; that is not related to generation interconnections; and that
will be completed and placed in service by June 30, 2004. Such upgrades include,
but are not limited to, new transmission facilities and related equipment and/or
modifications to existing transmission facilities and related equipment. Any
Northeast Massachusetts Upgrade will be identified within a reasonable period of
time and included in the NEPOOL Transmission Plan to be completed on or about
September 1, 2000. A Northeast Massachusetts Upgrade also must satisfy one of
the following three criteria:
(a) The addition or modification qualifies as an Economic Upgrade. If an
addition or modification meets these requirements, the full estimated capital
cost of the upgrade shall be taken into account for purposes of the $35,000,000
aggregate limit specified above.
(b) The addition or modification qualifies as a Reliability Upgrade meet a
future reliability need within the five years covered by the NEPOOL Transmission
Plan, and the net present value of the expected benefit advancing the
construction of the addition or modification exceeds the incremental cost of
advancing the in-service date of the addition or modification. The incremental
cost of the advancement shall qualify as a cost of Pool-Supported PTF pursuant
to this Section and only the incremental cost shall be taken into account for
purposes of the $35,000,000 aggregate limit specified above. The remaining cost
of the addition or modification shall qualify as the Pool-Supported PTF cost of
a Reliability Upgrade.
(c) The addition or modification is in construction as of January 1, 2000 or
planned for construction in 2000 and would qualify as an Economic Upgrade except
for the fact that it has not yet been included in a NEPOOL Transmission Plan. If
an addition or modification meets this requirement, the full estimated capital
cost of the addition or modification shall be taken into account for purposes of
the $35,000,000 aggregate limit specified above.
The aggregate capital costs of the Northeast Massachusetts Upgrades which
qualify as Pool-Supported PTF costs shall not exceed $35,000,000. If there are
multiple proposed additions or modifications which satisfy the criteria
specified in paragraphs (a), (b), or (c) above, and the aggregate cost of such
proposed additions or modifications to be taken into account for purposes of the
$35,000,000 limit specified above exceeds $35,000,000, the proposed additions or
modifications meeting the criteria specified in paragraph (a) or (b) above with
the highest benefit/cost ratios shall be given priority. For this purpose, the
benefit/cost ratio of an addition or modification is the net present value of
the benefit of the addition or modification divided by the net present value of
the cost of the addition or modification.
In considering whether to undertake a proposed addition or modification which
might otherwise qualify under this Subsection (3), the Transmission Owners and
the System Operator shall not limit their consideration of alternative means of
Congestion relief to transmission additions or modifications.
SCHEDULE 13
Locational Prices; Congestion Cost; Congestion Revenue;
Marginal Loss Cost; Marginal Loss Revenue
A. Calculation of Locational Prices: When Congestion exists on the NEPOOL
Transmission System, Congestion Cost and Marginal Loss cost shall be recovered,
pursuant to Section B below, from Non-Participant Transmission Customers taking
service under the Tariff. Congestion Cost and Marginal Loss Cost are derived
from the Congestion Components and Marginal Loss Components of Locational Prices
calculated as described below.
(1) Nodal Prices for Nodes and External Nodes. The System Operator shall
calculate the Nodal Price at each Node for each hour of the Dispatch Day for the
Day-Ahead Market using the Day-Ahead unit commitment model, and for the
Real-Time Market using the Real-Time scheduling software. In calculating Nodal
Prices the System Operator shall use the Demand Bids and Supply Offers submitted
pursuant to Sections 14A.3, 14A.4 and 14A.6 of the Agreement. The Real-Time
Nodal Price at each Node for each hour shall be the time interval
weighted-average of the Clearing Prices calculated at that Node for each time
interval within that hour, except as noted in Section A(4) below with respect to
the prices used for Real-Time settlements at External Nodes.
The System Operator shall calculate Nodal Prices for an hour for the Day-Ahead
Market or the Real-Time Market at a given Node i using the following formula, or
a formula similar in substance and effect:
(EQUATION)
where:
(EQUATION) the Nodal Price at Node i in $/megawatthour;
(EQUATION) the marginal cost in $/megawatthour, based on Demand Bids and
Supply Offers, to serve additional load at the Reference Node;
(EQUATION) the Marginal Loss Component of the Nodal Price at Node i in
$/megawatthour; and
(EQUATION) the Congestion Component of the Nodal Price at Node i in
$/megawatthour.
The Marginal Loss Component of the Nodal Price at any Node i on the NEPOOL
Transmission System is calculated using the equation
(EQUATION)
in which WFi, the Withdrawal Factor at Node i relative to the system
Reference Node, is calculated using the following equation:
where:
(EQUATION)
L = NEPOOL Transmission System losses;
Pi = the net amount of Energy injected into the NEPOOL Transmission System
at Node i; and
(EQUATION) = the ratio of: (1) the amount by which NEPOOL Transmission System
losses occurring in the Day-Ahead Schedule or Real-Time dispatch would have
increased, as calculated by the System Operator's Day-Ahead or Real-Time
computer algorithm, if a very small additional amount of Energy had been
injected at Node i (in addition to the injections and withdrawals already
scheduled to occur on the NEPOOL Transmission System in the Day-Ahead schedule
or occurring on the NEPOOL Transmission System in the Real-Time dispatch), to
(2) the size of the additional injection of Energy at Node i.
The Congestion Component of the Nodal Price at Node i is calculated using
the equation:
(EQUATION)
where:
K = the set of thermal or interface constraints;
GFik = the Shift Factor for the generator at Node i on constraint k in the pre-
or post-contingency case that limits flows across that constraint; and
(EQUATION) the reduction in system cost that results from an incremental
relaxation of constraint k, expressed in $/megawatthour.
Substituting the equations for calculating the Marginal Loss Component and
the Congestion Component of the Nodal Price for the terms and into the equation
for calculating the Nodal Price for a given Node i yields:
(2) Zonal Prices. For Congestion pricing purposes, Load Zones based on
Reliability Regions have been established and Zonal Prices shall be calculated
by the System Operator for each Load Zone. Each Load Zone shall be coterminous
with a Reliability Region, except that a Participant which owns and operates
distribution lines and other facilities used for the distribution of Energy to
retail customers in a single state in New England and which is subject to
regulation by the public utility regulatory authority in that state (a
"Distribution Company") which (i) serves retail customers in more than one
Reliability Region in a single state and (ii) is subject to a state-imposed
obligation to provide its retail customers with a power supply at fixed prices
for a certain time period ("Standard Offer Obligation"), may elect, by notice to
the System Operator and the Secretary of the Participants Committee, within the
time prescribed by the Market Rules, to have its entire service territory
treated as a single Load Zone (a "Distribution Company Load Zone") until its
Standard Offer Obligation ends. In addition, Vermont shall be a single Load Zone
for those Distribution Companies in Vermont that maintain their single
Participant status for settlement purposes with other Distribution Companies in
Vermont pursuant to Section 4 of the Agreement even if Vermont spans more than
one Reliability Region. The election by one or more Distribution Companies in
Vermont not to be treated as a single Participant with other Vermont
Participants shall not affect the Load Zone for the remaining Distribution
Companies in Vermont maintaining the single Participant election.
After consulting with the Participants, the System Operator may reconfigure
Reliability Regions and add or subtract Reliability Regions as necessary over
time to reflect changes to the grid, patterns of usage and intrazonal
Congestion. The System Operator shall file any such changes with the Commission.
The System Operator shall calculate a Zonal Price for each Reliability
Region for both the Day-Ahead and Real-Time Markets for each hour using a
load-weighted average of the Nodal Prices for the Nodes within that Reliability
Region. The load weights used in calculating the Day-Ahead Zonal Prices for the
Reliability Region shall be determined in accordance with applicable Market
Rules and shall be based on the Demand Bids for the Nodes that make up that
Reliability Region. The System Operator shall determine, in accordance with
applicable Market Rules, the load weights used in Real-Time based on calculated
load distribution. The System Operator shall calculate Zonal Prices for
Reliability Regions using the following formula, or a formula similar in
substance and effect, where the Zonal Price for a Reliability Region j can be
written as:
(EQUATION)
where:
(EQUATION) = Zonal Price for Reliability Region j in $/megawatthour;
(EQUATION) is the Marginal Loss Component of the Zonal Price for
Reliability Region j in $/megawatthour;
(EQUATION) is the Congestion Component of the Zonal Price for Reliability
Region j in $/megawatthour;
Nj = the set of Nodes that make up the Reliability Region j; and
Wij = the load-weighting factor for Node i used to calculate the Zonal Price for
Reliability Region j, determined such that the weighting factors for any given
Reliability Region sum to one.
For a Distribution Company Load Zone, the Zonal Price shall be determined
by the weighted average of the Zonal Prices for the Reliability Regions making
up the Load Zone, with the weights equal to that Distribution Company's share of
the load in each of those Reliability Regions. The load weights used in
calculating the Day-Ahead Zonal Prices for the Distribution Company Load Zones
shall be determined in accordance with applicable Market Rules and shall be
based on the Demand Bids for the Nodes that make up the Distribution Company
Load Zones. The System Operator shall determine, in accordance with applicable
Market Rules, the load weights used in Real-Time based on the calculated
Real-Time load distribution. The System Operator shall calculate Zonal Prices
for each hour of the Dispatch Day for Distribution Company Load Zones using the
following formula: Zonal Price equals the Distribution Company's load in each
Reliability Region making up the Distribution Company Load Zone times the Zonal
Price for each such Reliability Region summed for all such Reliability Regions
making up the Distribution Company Load Zone, divided by the sum of the
Distribution Company's load in each Reliability Region making up the
Distribution Company Load Zone. The Congestion and Marginal Loss Components of
the Zonal Price for each Distribution Company Load Zone shall be calculated as
the weighted average of the Congestion and Marginal Loss Components,
respectively, of the Zonal Prices in the Reliability Regions making up that Load
Zone, using the same weights that are used to calculate the Zonal Price for that
Distribution Company Load Zone.
(3) Hub Prices. On behalf of the Participants, the System Operator shall
maintain and facilitate the use of a Hub or Hubs for the Energy market,
comprised of a set of Nodes within NEPOOL, which Nodes shall be identified by
the System Operator on its Internet website. The System Operator has used the
following criteria to establish an initial Hub and shall use the same criteria
to establish any additional Hubs:
(i) each Hub shall contain a sufficient number of Nodes to try to ensure
that a Hub Price can be calculated for that Hub at all times;
(ii) each Hub shall contain a sufficient number of Nodes to ensure that the
unavailability of, or an adjacent line outage to, any one Node or set of Nodes
would have only a minor impact on the Hub Price;
(iii) each Hub shall consist of Nodes with a relatively high rate of service
availability;
(iv) each Hub shall consist of Nodes among which transmission service is
relatively unconstrained; and
(v) no Hub shall consist of a set of Nodes for which directly connected load
and/or generation at that set of Nodes is dominated by any one entity or its
affiliates.
The System Operator shall calculate hourly Hub Prices for both the Day-Ahead and
Real-Time Markets using a fixed-weighted average of the Nodal Prices that
comprise the Hub. The System Operator shall calculate Hub Prices using the
following formula, or a formula similar in substance and effect, where the Hub
Price for a Hub j can be written as:
(EQUATION)
where:
(EQUATION) = Hub Price for Hub j in $/megawatthour;
(EQUATION) is as defined in Section A(1);
(EQUATION) is the Marginal Loss Component of the Hub Price for Hub j in
$/megawatthour;
(EQUATION) is the Congestion Component of the Hub Price for Hub j in
$/megawatthour;
Hj = the set of Nodes in Hub j; and
WijH = the load weighting factor for Node i used to calculate the Hub Price for
Hub j, determined such that the weighting factors for any given Hub sum to one.
Participants may acquire FCRs to and from the Hub in accordance with Schedule 14
of the Tariff.
(4) Nodal Prices for External Nodes. The System Operator shall calculate Nodal
Prices for External Nodes. The External Nodes shall be identified in applicable
Market Rules. External Nodes shall be used for pricing Energy that is received
from or delivered to neighboring Control Areas. The Nodal Prices for External
Nodes shall be calculated in the same way as Nodal Prices for Nodes, with the
exception of the calculation of the Marginal Loss Component of the price.
The Marginal Loss Component of Nodal Prices for External Nodes shall be
calculated so as to ensure that it does not include the effect of withdrawals at
a Node or External Nodes on the cost of losses incurred outside the NEPOOL
Control Area. In order to accomplish this, a hypothetical transaction will be
modeled, in which an increment of load at each External Node is served by an
increment of generation at the Reference Node. The amount of Energy that would
flow out of the NEPOOL Transmission System over each interconnection point
between the NEPOOL Transmission System and an adjoining Control Area or the
Non-PTF transmission system will be calculated next. Finally, the Marginal Loss
Component of the Nodal Price at each External Node will be calculated as the
weighted average of the Marginal Loss Components at each of the interconnection
points between the NEPOOL Transmission System and an adjoining Control Area or
the Non-PTF transmission system. The weight assigned to each interconnection
will be equal to the proportion of the total amount of Energy delivered off of
the NEPOOL Transmission System in association with this hypothetical transaction
that flows over that interconnection. As a result, the Marginal Loss Component
of the price at each External Node will only include the effects on Marginal
Losses on the NEPOOL Transmission System.
The Shift Factors for each External Node determine the proportion of the Energy
in such a transaction that would flow over each interconnection point between
the NEPOOL Transmission System and external Control Areas or the Non- PTF
transmission system and, therefore, the Marginal Loss Component of the Nodal
Price at an External Node i shall be calculated using the following equation, or
a formula similar in substance and effect:
(EQUATION)
where:
(EQUATION) = the Marginal Loss Component of the Nodal Price at an External
Node i in $/megawatthour;
I = the set of interconnection points between the NEPOOL Transmission System
and adjacent Control Areas or the Non-PTF transmission system;
GFin = Shift Factor at External Node i for the interconnection line that
passes through Node n; and
(WFn - 1) = the Marginal Loss Component of the Nodal Price at Node n in
$/megawatthour, where WFn is the withdrawal factor at Node n and (EQUATION)
is as defined in Section A(1).
The price used for Real-Time settlements at External Nodes will be the Real-
Time price as determined based on the Real-Time dispatch except in the
circumstance in which imports or exports were constrained in the hour ahead
scheduling process either by constraints that are not monitored in Real-Time or
by closed interface constraints that are not affected by internal dispatchable
generators. In this special circumstance, the price used for Real-Time
settlements of imports from External Nodes will be the lower of the Real-Time
price at the External Node or the hour ahead price at the External Node.
Similarly, in this situation, the price used for Real-Time settlements of
exports to External Nodes will be the higher of the Real-Time price at the
External Node or the hour ahead price at the External Node.
B. Congestion Cost:
(1) Congestion Cost. Congestion Cost shall be recovered under this Section B
from each Non-Participant Transmission Customer taking service under the Tariff
when the Congestion Component of the Locational Price at the Point of Delivery's
Location exceeds the Congestion Component of the Locational Price at the Point
of Receipt's Location for the transaction. In accordance with NEPOOL System
Rules, each Transmission Customer may elect to specify a maximum Congestion Cost
that it is willing to pay to have its transaction scheduled or to keep its
transaction from being wholly or partially curtailed.
The System Operator shall calculate Congestion Cost to be recovered from such
customers for each hour of the Dispatch Day in which Congestion exists in the
Day-Ahead and the Real-Time Markets. Such Congestion Cost recovered with respect
to Day-Ahead transmission service scheduling shall equal (1) the amount (in
$/megawatthour) by which the Congestion Component of the Day-Ahead Locational
Price at the Point of Delivery's Location exceeds the Congestion Component of
the Day-Ahead Locational Price at the Point of Receipt's Location; multiplied by
(2) the quantity of Energy scheduled by the Transmission Customer for that hour.
Such Congestion Cost recovered with respect to Real-Time transmission service
scheduling shall equal (1) the amount (in $/megawatthour) by which the
Congestion Component of the Real-Time Locational Price at the Point of
Delivery's Location exceeds the Congestion Component of the Real-Time Locational
Price at the Point of Receipt's Location; multiplied by (2) the quantity of
Energy scheduled by the Transmission Customer for that hour, minus the quantity
of Energy that Transmission Customer scheduled for that hour in its Day-Ahead
transmission service scheduling.
(2) Congestion Cost Relief. Each Non-Participant Transmission Customer taking
Through or Out or Point-to-Point Service shall be paid or be credited for
Congestion relief when the Congestion Component of the Locational Price at the
Point of Receipt's Location exceeds the Congestion Component of the Locational
Price at the Point of Delivery's Location for the transaction.
The System Operator shall calculate and allocate such payments or credits to
such customers for each hour of the Dispatch Day in which Congestion exists in
the Day-Ahead and the Real-Time Markets. Such payments or credits made with
respect to the Day-Ahead transmission service scheduling shall equal (i) the
amount (in $/megawatthour) by which the Congestion Component of the Day- Ahead
Locational Price at the Point of Receipt's Location exceeds the Congestion
Component of the Day-Ahead Locational Price at the Point of Delivery's Location;
multiplied by (ii) the quantity of Energy scheduled by the Transmission Customer
for that hour. Such payments or credits made with respect to the Real-Time
Market shall equal (i) the amount (in $/megawatthour) by which the Congestion
Component of the Real-Time Locational Price at the Point of Receipt's Location
exceeds the Congestion Component of the Real-Time Locational Price at the Point
of Delivery's Location; multiplied by (ii) the quantity of Energy scheduled by
the Transmission Customer for that hour, minus the quantity of Energy that
Transmission Customer scheduled for that hour in its Day-Ahead transmission
service scheduling.
C. Congestion Revenue: For each hour the System Operator shall calculate
and collect Congestion Revenue and maintain a Congestion Revenue Fund in
accordance with Section E of Schedule 14.
D. Marginal Loss Cost and Marginal Loss Revenue:
(1) Marginal Loss Cost. Marginal Loss cost shall be recovered under this Section
D from each Non-Participant Transmission Customer taking service under the
Tariff when the Marginal Loss Component of the Locational Price at the Point of
Delivery's Location exceeds the Marginal Loss Component of the Locational Price
at the Point of Receipt's Location for the transaction.
The System Operator shall calculate Marginal Loss cost to be recovered from such
customers for each hour of the Dispatch Day. Such costs shall equal the amount
(in $/megawatthour) of the Marginal Loss Component of the Real-Time Locational
Price at the Point of Delivery's Location minus the Marginal Loss Component of
the Real-Time Locational Price at the Point of Receipt's Location, multiplied by
the amount of Energy scheduled for the transaction in that hour.
Each Non-Participant Transmission shall be paid or credited when the Marginal
Loss Component of the Real-Time Locational Price at the Point of Receipt's
Location exceeds the Marginal Loss Component of the Real-Time Locational Price
at the Point of Delivery's Location for the transaction. Such Marginal Loss
payment or credit shall equal the amount (in $/megawatthour) of the Marginal
Loss Component of the Real-Time Locational Price at the Point of Receipt's
Location minus the Marginal Loss Component of the Real-Time Locational Price at
the Point of Delivery's Location, multiplied by the amount of Energy scheduled
for the transaction in that hour.
(2) Marginal Loss Revenue. To the extent that there is any Marginal Loss Revenue
in any settlement period, such revenue shall be collected in a Marginal Loss
Revenue Fund and allocated in accordance with the Market Rules to load serving
entities paying for Energy during such settlement period.
E. Additional Rules and Procedures: Consistent with this Schedule 13, the
implementation of its provisions shall further be detailed, defined and carried
out pursuant to the Agreement and Market Rules.
SCHEDULE 14
Financial Congestion Rights ("FCRs")
The System Operator shall implement and administer a system of Financial
Congestion Rights ("FCRs") as provided for below.
A. FCR Holder Status and Transfer of FCRs: FCRs shall be awarded to winning
bidders in the mandatory FCR Auctions pursuant to Section F below and may be
acquired in the subsequent bilateral market from FCR Holders. An entity that
acquires an FCR through the FCR Auction shall automatically be recognized by the
System Operator as the registered FCR Holder of that FCR, subject to having
already met the eligibility criteria for bidding in the FCR Auction. The
registered FCR Holder shall be entitled to receive or be obligated to make FCR
Payments arising from such FCR in accordance with Section C.
An entity that acquires an FCR through the FCR Auction or through a subsequent
bilateral transaction may elect to hold it, sell it in the FCR Auction or sell
it bilaterally. The registered FCR Holder of an FCR sold in a bilateral
transaction will continue to be the FCR Holder for that FCR unless it submits a
confirmation of the sale to the System Operator in accordance with the Market
Rules. The System Operator upon receipt of such a confirmation will transfer
record ownership on its register. The purchaser of an FCR in a bilateral
transaction that is not recorded on the System Operator's register receives only
a contractual right against the seller of the FCR and has no rights or
obligations in settlement or in the Energy market. An entity who subsequently
acquires an FCR from an FCR Holder through a bilateral transaction must meet
applicable criteria established by the Participants Committee, including
creditworthiness criteria, to be the FCR Holder of that FCR and secure the
associated rights and obligations. The System Operator shall settle FCRs only
with the registered FCR Holders. At any given time, each FCR shall have only one
registered FCR Holder.
B. FCR Designation and Simultaneous Feasibility: FCRs shall be unidirectional,
financial transmission rights based on the transfer capability of the NEPOOL
Transmission System, denominated in Megawatts, designated to and from specified
Locations and/or Reliability Regions, and lasting for a certain term. To the
extent feasible, FCRs valid for on-peak and/or off-peak periods shall be
available in the FCR Auctions and shall be accommodated in the FCR settlement
process by the System Operator.
Each FCR shall be designated to and from specified Locations and/or Reliability
Regions for the purpose of determining FCR Payments. Each FCR shall also have a
specified origin and destination Node that shall be used to determine to which
new Load Zone and/or Reliability Region an existing FCR would be assigned if and
when a Load Zone and/or Reliability Region were reconfigured.
The System Operator shall determine, initially and periodically thereafter in
conjunction with the FCR Auctions, the FCRs that can be made available based on
a simultaneous feasibility test. The purpose of the test shall be to determine
whether the NEPOOL Transmission System, under security constrained conditions,
could accommodate all the potential transactions represented by a defined set of
FCRs.
The System Operator shall maintain a record of the FCRs, containing such
information as is necessary to administer the system of FCRs including, but not
limited to, each FCR's designated origin and destination Nodes and settlement
Locations and/or Reliability Regions, Megawatt amount, registered Holder, and
the period during which the FCR is valid. FCR Holders shall provide the System
Operator with such information regarding the FCRs as is reasonably requested by
the System Operator for the administration of the system of FCRs.
An FCR Holder may, to the extent permitted by the Market Rules, subdivide FCRs
into individually transferable components representing the intermediate points
of injection and withdrawal contained within the FCR's path, such that an FCR
from point A to point C, for example, may be subdivided prior to transfer based
on the intermediate point B, resulting in two individually transferable FCRs,
one from point A to point B, and one from point B to point C. Likewise, the
Holder of an FCR that is valid for more than one hour may, to the extent
permitted by the Market Rules, subdivide that FCR into individually transferable
components representing subsets of those hours. For example, an FCR valid during
January and February may be subdivided into an FCR valid during January and an
FCR valid during February, each of which would be individually transferable.
FCRs awarded in the FCR Auction or acquired through subsequent bilateral
transactions may be reconfigured, but only through the System Operator. The
System Operator shall facilitate the transfer and reconfiguration of FCRs,
ensure their simultaneous feasibility, and register the FCR Holders of the
reconfigured FCRs.
In effecting the award or transfer of any FCR that can be subdivided into any of
the following general and specific components, the System Operator shall
subdivide the FCR into its general and specific components and record the FCR as
having such components. The general components are Load Zone and/or Reliability
Region to Load Zone and/or Reliability Region, Hub to Load Zone and/or
Reliability Region, Load Zone and/or Reliability Region to Hub. The specific
components are Node or External Node to Load Zone and/or Reliability Region in
which the Node or External Node is located, Load Zone and/or Reliability Region
to Node or External Node contained in the Load Zone and/or Reliability Region,
and Node or External Node to Node or External Node contained in the same Load
Zone and/or Reliability Region.
Each FCR shall be designated to and from specified Locations and/or Reliability
Regions for the purpose of determining FCR Payments. Each FCR shall also have a
specified origin and destination Node that shall be used to determine to which
new Load Zone and/or Reliability Region an existing FCR would be assigned if and
when a Load Zone and/or Reliability Region were reconfigured.
The System Operator shall determine, initially and periodically thereafter in
conjunction with the FCR Auctions, the FCRs that can be made available based on
a simultaneous feasibility test. The purpose of the test shall be to determine
whether the NEPOOL Transmission System, under security constrained conditions,
could accommodate all the potential transactions represented by a defined set of
FCRs.
The System Operator shall maintain a record of the FCRs, containing such
information as is necessary to administer the system of FCRs including, but not
limited to, each FCR's designated origin and destination Nodes and settlement
Locations and/or Reliability Regions, Megawatt amount, registered Holder, and
the period during which the FCR is valid. FCR Holders shall provide the System
Operator with such information regarding the FCRs as is reasonably requested by
the System Operator for the administration of the system of FCRs.
An FCR Holder may, to the extent permitted by the Market Rules, subdivide FCRs
into individually transferable components representing the intermediate points
of injection and withdrawal contained within the FCR's path, such that an FCR
from point A to point C, for example, may be subdivided prior to transfer based
on the intermediate point B, resulting in two individually transferable FCRs,
one from point A to point B, and one from point B to point C. Likewise, the
Holder of an FCR that is valid for more than one hour may, to the extent
permitted by the Market Rules, subdivide that FCR into individually transferable
components representing subsets of those hours. For example, an FCR valid during
January and February may be subdivided into an FCR valid during January and an
FCR valid during February, each of which would be individually transferable.
FCRs awarded in the FCR Auction or acquired through subsequent bilateral
transactions may be reconfigured, but only through the System Operator. The
System Operator shall facilitate the transfer and reconfiguration of FCRs,
ensure their simultaneous feasibility, and register the FCR Holders of the
reconfigured FCRs.
In effecting the award or transfer of any FCR that can be subdivided into any of
the following general and specific components, the System Operator shall
subdivide the FCR into its general and specific components and record the FCR as
having such components. The general components are Load Zone and/or Reliability
Region to Load Zone and/or Reliability Region, Hub to Load Zone and/or
Reliability Region, Load Zone and/or Reliability Region to Hub. The specific
components are Node or External Node to Load Zone and/or Reliability Region in
which the Node or External Node is located, Load Zone and/or Reliability Region
to Node or External Node contained in the Load Zone and/or Reliability Region,
and Node or External Node to Node or External Node contained in the same Load
Zone and/or Reliability Region.
C. FCR Payments: Except as provided in Section E below, each FCR Holder shall be
entitled to receive for each hour of the Dispatch Day for which that FCR is
valid an FCR Payment for an FCR when the Congestion Component of the Locational
Price at the FCR's specified destination Location and/or Reliability Region
exceeds the Congestion Component of the Locational Price at the FCR's specified
origin Location and/or Reliability Region. Such FCR Payment shall equal the
amount (in $/megawatthour) by which the Congestion Component of the Locational
Price at the FCR's specified destination Location and/or Reliability Region
exceeds the Congestion Component of the Locational Price at the FCR's specified
origin Location and/or Reliability Region, multiplied by the Megawatt
designation of the FCR for that hour. The FCR Holder shall be entitled to
receive such FCR Payments independent of the FCR Holder's actual use of the
NEPOOL Transmission System.
In the event that in any hour of the Dispatch Day in which an FCR is valid the
Congestion Component of the Locational Price at an FCR's specified origin
Location and/or Reliability Region exceeds the Congestion Component of the
Locational Price at the FCR's specified destination Location and/or Reliability
Region, the FCR Holder of that FCR shall be obligated to make an FCR Payment.
Such FCR Payment shall equal the amount (in $/megawatthour) by which the
Congestion Component of the Locational Price at the FCR's specified origin
Location exceeds the Locational Price at the FCR's specified destination
Location, multiplied by the Megawatt designation of the FCR, for that hour. The
FCR Holder shall be obligated to make such FCR Payments independent of the FCR
Holder's actual use of the NEPOOL Transmission System.
D. FCR Settlements: FCRs may be acquired from: Node to Node, Node to External
Node, Node to Hub, Node to Load Zone, Node to Reliability Region; External Node
to Node, External Node to External Node, External Node to Hub, External Node to
Load Zone, External Node to Reliability Region; Hub to Node, Hub to External
Node, Hub to Hub (if multiple Hubs are established), Hub to Load Zone, Hub to
Reliability Region; Load Zone to Hub, Load Zone to Node, Load Zone to External
Node, Load Zone to Load Zone, Load Zone to Reliability Region; Reliability
Region to Node, Reliability Region to External Node, Reliability Region to Hub,
Reliability Region to Load Zone, and Reliability Region to Reliability Region.
Each FCR shall be settled based on its designated settlement Locations and/or
Reliability Regions.
FCRs shall be settled for the Day-Ahead Market not the Real-Time Market. FCRs
shall be settled based on the difference between the Congestion Components of
the relevant Locational Prices at the origin and destination Locations and/or
Reliability Regions.
E. Congestion Revenue Shortfalls or Surpluses: There may be instances (resulting
from physical conditions on the NEPOOL Transmission System or other reasons) in
which the total Congestion Revenue collected by the System Operator will be less
or more than the sum of all Target FCR Payments, creating Congestion Revenue
Shortfalls or Surpluses. A cash reserve in the Congestion Revenue Fund shall be
established and maintained by the System Operator so as to minimize the impact
on FCR Holders of Congestion Revenue Shortfalls. During each month, a Congestion
Revenue Surplus would increase the cash reserve, and a Congestion Revenue
Shortfall would decrease the cash reserve.
The System Operator shall calculate the Congestion Revenue collected and the
total Target FCR Payments on an hourly basis. The System Operator shall
determine total Target FCR Payments by summing the Target FCR Payments in a
given hour over all FCRs. The actual Congestion Revenue collections in each hour
shall be calculated through the following steps:
(1) multiplying the withdrawals at each Location and/or Reliability Regions
by the Congestion Component of the Locational Price applying to that withdrawal;
(2) summing the calculation in Step 1 over all withdrawals;
(3) multiplying the injections at each Node by the Congestion Component of
the Nodal Price applying to that injection;
(4) summing the calculation in Step 3 over all injections; and
(5) subtracting the total calculated in Step 4 from the total calculated in
Step 2.
If the actual Congestion Revenue collected in each hour, summed over all hours
in a billing month, exceeds the total Target FCR Payments for each hour, summed
over all hours in that billing month, then the difference will constitute a
Congestion Revenue Surplus for that billing month. All Congestion Revenue
Surpluses will be added to the Congestion Revenue Fund, and all FCR Payments
made from the Congestion Revenue Fund to FCR Holders for that billing month
shall be equal to the Target FCR Payments to those FCR Holders.
If the actual Congestion Revenue collected in each hour, summed over all hours
in a billing month, is less than the total Target FCR Payments for each hour,
summed over all hours in that billing month, then the difference will constitute
a Congestion Revenue Shortfall for that billing month. If there is a Congestion
Revenue Shortfall for that billing month, but that Congestion Revenue Shortfall
is not greater than the balance of the Congestion Revenue Fund cash reserve
entering the month, then the Congestion Revenue Shortfall shall be deducted from
the Congestion Revenue Fund, and all FCR Payments made from the Congestion
Revenue Fund to FCR Holders for that billing month shall be equal to the Target
FCR Payments to those FCR Holders.
If the Congestion Revenue Shortfall for a month is greater than the balance of
the Congestion Revenue Fund cash reserve entering the month, then that balance
as of the conclusion of that month shall be set to zero, and the funds in the
Congestion Revenue Fund will be used to make FCR Payments to FCR Holders.
However, these funds, in combination with the Congestion Revenue collected in
that billing month, will not be sufficient to permit the FCR Payment to each FCR
Holder to be equal to the Target FCR Payment to that FCR Holder for every hour
in that billing month. Consequently, each FCR Payment made by the Congestion
Revenue Fund to an FCR Holder for an hour in that month shall be set equal to
the Target FCR Payment that would have been payable to that FCR Holder for that
hour multiplied by a proportionality factor. This proportionality factor (which
shall be the same for all hours and all FCRs) shall be the number that makes the
sum of all FCR Payments made by the Congestion Revenue Fund for that billing
month equal to the sum of: (1) the balance of the Congestion Revenue Fund at the
beginning of that billing month; (2) the Congestion Revenue collected for that
billing month; (3) the FCR Payments made by FCR Holders to the Congestion
Revenue Fund for that billing month; and (4) the amount paid, if any and to the
extent provided for in the Market Rules, by generators interconnecting with the
NEPOOL Transmission System for redispatch caused by interconnecting such
generators.
When an FCR Holder is obligated to make an FCR Payment in accordance with
Section C above, the FCR Holder shall be obligated to make a payment to the
Congestion Revenue Fund equal to the Target FCR Payment. This obligation shall
not be affected by the existence of a Congestion Revenue Shortfall or Surplus.
At the end of each calendar year, the balance of the Congestion Revenue fund
will first be used to pay the holder of any FCR who received less than the
Target FCR Payment with respect to that FCR in a month during the calendar year.
To the extent that the balance is not sufficient to pay all such Target FCR
Payment shortfalls, the shortfalls will be multiplied by a proportionality
factor that makes the sum of all shortfalls equal to the balance in the
Congestion Revenue fund. To the extent that the balance exceeds the amount
required to pay all shortfalls, any remaining balance, with the exception of any
amount that is retained in the Congestion Revenue Fund pursuant to the Market
Rules, shall be allocated to those entities who paid for Congestion Cost either
under the Agreement or the Tariff. Such allocation shall be in accordance with
the Market Rules.
F. FCR Auctions: Prior to the implementation of CMS, and on an annual and
monthly basis following the CMS/MSS Effective Date, the System Operator shall
perform a simultaneous feasibility test using appropriate power flow models of
security-constrained dispatch to determine the feasible set of simultaneous FCRs
that can be offered in the annual and monthly FCR Auctions. Such test shall take
into account already awarded FCRs (following the first FCR Auction), and outages
of both individual generation units and transmission facilities. Such tests
shall be based on reasonable assumptions about the configuration and
availability of transmission capability during the period covered by the FCR
Auction. The System Operator shall perform the simultaneous feasibility test
with the purpose of ensuring that there will be adequate Congestion Revenue
under expected conditions to fund FCR Payments made to the purchasers of FCRs
sold in the FCR Auction.
FCRs shall be reconfigured and awarded in the FCR Auction to maximize the
valuation of the awarded FCRs (based on buyers' bids) net of the value of the
offered FCRs (based on sellers' reservation prices in the case of previously
awarded FCRs offered for sale, or based on a zero price in the case of FCRs
supporting payments to ARR Holders), subject to the constraint that the awarded
FCRs must be simultaneously feasible in a security constrained dispatch in
conjunction with all FCRs already awarded in the FCR Auction or acquired through
subsequent bilateral transactions and held by FCR Holders and not offered into
the auction.
Based on the outcome of the System Operator's simultaneous feasibility tests,
FCRs shall be made available to Eligible FCR Bidders through periodic FCR
Auctions conducted by the System Operator or another authorized agent of the
NEPOOL Participants. An "Eligible FCR Bidder" is an entity that has satisfied
the reasonable creditworthiness criteria set by the Participants Committee, and
shall not include the Auctioneer, its affiliates, and their officers, directors,
employees, consultants and other representatives.
FCR Auctions shall initially be held on both a biannual and a monthly basis. In
the initial biannual FCR Auction, the maximum term of the awarded FCRs shall be
six months. Ten percent of the transfer capacity of the NEPOOL Transmission
System will be made available to support the sale in this initial auction of
FCRs with a term of six months. During the second biannual FCR Auction,
twenty-five percent of the transfer capacity of the NEPOOL Transmission System
will be made available to support FCRs with a term of six months. During this
initial twelve-month period, following each biannual FCR Auction, the remaining
transfer capability of the NEPOOL Transmission System will be made available to
support the sale of FCRs with a term of one month in the monthly FCR Auctions.
Following the initial auctions, FCR Auctions shall be held on both an annual and
a monthly basis. Fifty percent of the feasible FCRs that can be made available
with a term of one (1) year to five (5) years (in one-year increments for the
five calendar years immediately subsequent to the FCR Auction) shall be made
available in the annual FCR Auction conducted in accordance with the Market
Rules.
Each Eligible FCR Bidder may submit bids in the annual FCR Auction for FCRs for
a single year or for multiple years in the five-year period covered by the
auction. Each Eligible FCR Bidder in the annual FCR Auction shall specify the
year or years for which it wishes to purchase a specified FCR.
After the annual FCR Auction has been conducted, the remaining feasible FCRs,
each having a term of one month, shall be made available in monthly FCR Auctions
conducted in accordance with the Market Rules.
After each auction of monthly FCRs is complete, a residual FCR sale mechanism
shall be established pursuant to the Market Rules, in which any FCR that is
simultaneously feasible in conjunction with all outstanding FCRs may be
purchased on a daily, peak and off-peak basis for any day of the next month.
Each offer to sell a previously awarded FCR shall identify the FCR by Megawatt
quantity and the FCR's origin and destination Locations and/or Reliability
Regions and other pertinent information as required by the Market Rules. An
offer to sell a specified Megawatt quantity of FCRs shall be deemed an offer to
sell a quantity of FCRs equal to or less than the specified quantity. An offer
to sell may not specify a minimum quantity being offered. Each offer to sell a
previously awarded FCR may specify a reservation price, below which the offeror
will not sell the FCR.
Each bid to buy an FCR shall specify the Megawatt quantity, price per Megawatt,
and specific origin and destination Locations and/or Reliability Regions of the
FCR and other pertinent information as required by the Market Rules. A bid to
purchase a specified Megawatt quantity of FCRs shall be deemed a bid to purchase
a quantity of FCRs equal to or less than the specified quantity. A bid to
purchase may not specify a minimum quantity that the bidder wishes to purchase.
A bid to purchase may specify any origin and destination Locations and/or
Reliability Regions for which the System Operator calculates Locational Prices.
Offers and bids in the FCR Auction may specify on-peak and off-peak time periods
of the Dispatch Day for which an FCR will be valid.
The System Operator shall model all existing FCRs not offered into the FCR
Auction in the simultaneous feasibility test as fixed injections and withdrawals
on the NEPOOL Transmission System for their remaining term, thereby in effect
reserving the transfer capability required to honor the existing FCR. FCRs to
and from a Hub shall be treated in the simultaneous feasibility test as
injections and withdrawals at each Node comprising that Hub, with the amount
injected or withdrawn at each such Node corresponding to the weight assigned by
the System Operator to that Node when calculating the Hub Price at that Hub in
the Day-Ahead Market. FCRs to and from Load Zones and/or Reliability Regions
shall be treated in the simultaneous feasibility test as injections and
withdrawals at each Node in that Load Zone and/or Reliability Regions, with the
amount injected or withdrawn at each such Node corresponding to the weights
assigned by the System Operator to that Node when calculating the Zonal Price
for that Load Zone and/or Reliability Regions in the Day-Ahead Market. The
System Operator's simultaneous feasibility test shall also test for revenue
adequacy under future Load Zone and/or Reliability Regions definitions through a
second test in which FCRs with a term of one year or more to and from Load Zones
and/or Reliability Regions would be treated as injections and withdrawals at the
designated origin and destination Locations and/or Reliability Regions for each
FCR.
Each winning bidder for an FCR in an FCR Auction shall pay the market- clearing
price as determined by the FCR Auction, for the awarded FCR when that price is
positive. If the market-clearing price for the awarded FCR is negative, the
winning bidder for that FCR shall receive a payment equal to the absolute value
of the market-clearing price for that FCR. Each seller of an FCR in the FCR
Auction shall be paid the market-clearing price, as determined by the FCR
Auction, for the FCR sold when that price is positive. If the market-clearing
price for the FCR sold is negative, the seller of that FCR shall make a payment
equal to the absolute value of the market-clearing price for that FCR. As soon
as feasible and in accordance with the Market Rules, the System Operator shall
post on its Internet website the market- clearing price of each FCR sold in the
FCR Auction.
Revenues from the FCR Auctions shall be collected by the System Operator or
another authorized agent of the NEPOOL Participants and held in the Auction
Revenue Fund. FCR Auction Revenue shall be allocated to FCR Holders who sell
their FCRs in the FCR Auction and to Auction Revenue Rights Holders as described
in Schedule 15 and Section 49.
G. FCRs as Options: To the extent feasible, as determined by the Participants
Committee and the System Operator, FCRs in the form of financial options shall
be available through the FCR Auctions. The rules governing such option type
FCRs, if such FCRs have been determined feasible, shall be stated in the Tariff
and detailed in the NEPOOL System Rules.
H. Additional Rules and Procedures: Consistent with this Schedule 14,
the implementation of its provisions shall further be detailed, defined and
carried out pursuant to the Market Rules.
SCHEDULE 15
Auction Revenue Rights
Auction Revenue Rights ("ARRs") are rights to receive FCR Auction Revenues from
the sale of FCRs other than FCRs sold by FCR Holders. ARRs shall be determined
and allocated to Congestion Paying Entities, Transmission Customers and NEMA
LSEs (including any of the foregoing that are parties to Excepted Transactions
that are included in the list of transactions in Attachments G and G-2 of the
Tariff), using a four-stage process as described below (the "ARR Allocation").
A. First Stage of ARR Allocation
(1) Excepted Transactions. In the first stage of each ARR Allocation, each
entity serving load to which Energy is delivered pursuant to an Excepted
Transaction included in the list of transactions in Attachments G and G-2 of the
Tariff, and which is the party responsible for paying Congestion Cost associated
with Energy purchased under the Excepted Transaction shall have the option to be
allocated ARRs from the generator to the location of the load. Alternatively,
each seller delivering Energy pursuant to an Excepted Transaction to an entity
serving load and which seller is the party responsible for paying Congestion
Cost associated with Energy purchased under the Excepted Transaction shall have
the option to be allocated ARRs from the generation source to the load.
In order to be eligible to receive ARRs in association with an Excepted
Transaction, each entity to which Energy is delivered pursuant to an Excepted
Transaction or which delivers Energy pursuant to an Excepted Transaction must
request that it be allocated ARRs pursuant to this section prior to the second
stage of the ARR Allocation. The first-stage ARR Allocation to an entity serving
load to which Energy is delivered pursuant to an Excepted Transaction who makes
such a request shall be equal to the number of Megawatts of Energy to be
delivered to that customer under the Excepted Transaction. The origin Node or
External Node for those ARRs shall match the generation source for any such
Excepted Transaction and the destination Locations and/or Reliability Regions
for those ARRs shall match the location of the load served by those Excepted
Transactions. The first-stage ARR Allocation to an entity selling Energy to an
entity serving load to which Energy is delivered pursuant to an Excepted
Transaction who makes such a request shall be equal to the number of Megawatts
of Energy to be delivered by that selling entity under the Excepted Transaction.
The origin Node or External Node for those ARRs shall match the generation
source for any such Excepted Transaction and the destination Locations and/or
Reliability Regions for those ARRs shall match the Locations and/or Reliability
Regions of the load served by those Excepted Transactions.
Each entity shall be entitled to make requests for ARRs under the terms of this
section until the Excepted Transaction has terminated, or ten years from the
CMS/MSS Effective Date, whichever is earlier.
(2) Transmission Customers and Congestion Paying Entities. ARRs shall be
allocated to each Congestion Paying Entity and Transmission Customer from each
NEPOOL generator and tie line source in proportion to the capacity of the
generator and tie line source and in proportion to the Monthly Peak Load served
by that Congestion Paying Entity or Transmission Customer, provided, however,
that the allocation of first-stage ARRs to Transmission Customers under this
Section A(2) shall be in proportion to: (i) the Transmission Customer's Monthly
Peak Load not served by a Congestion Paying Entity, less (ii) any portion of the
Transmission Customer's or Congestion Paying Entity's load for which ARRs have
been allocated pursuant to the Excepted Transaction election described above.
The determination of the first-stage ARR Allocation to Transmission Customers
and Congestion Paying Entities shall be performed using the following formula:
Nijkt = Git * (Ljkt/Lt),
where:
Nijkt = the amount of ARRs from Node or External Node i to Reliability Region j
awarded to Transmission Customer or Congestion Paying Entity k for month t;
Git = the total rated capacity for month t of generators or the capacity
during month t-1 of tie line capacity located at node i;
Ljkt= the Monthly Peak Load of Transmission Customer or Congestion Paying Entity
k calculated on the basis of its Monthly Peak Load during the same month t of
the prior year in Reliability Region j, less any portion of that Monthly Peak
Load (up to a maximum of the total Monthly Peak Load) for which ARRs have been
allocated in association with Excepted Transactions as described above; and
Lt = total Monthly Peak Load during month t of the prior year.
The total quantity of ARRs assigned pursuant to this Section A(2) to
Transmission Customer or Congestion Paying Entity k in month t shall be:
(EQUATION)
B. Second Stage of ARR Allocation: The amount of ARRs allocated to each entity
in the first stage of each ARR Allocation may be modified in the second stage of
that ARR Allocation. The second stage of each ARR Allocation shall determine the
final allocation of ARRs to all ARR Holders for that FCR Auction, except for
NEMA LSEs. Allocations of ARRs to NEMA LSEs may be modified in the third and
fourth stages of the ARR Allocation for each FCR Auction.
The second stage of each ARR Allocation shall be performed using the following
procedure, which will be adjusted on an annual and monthly basis to account for
changes in available transmission capacity, load ratio shares, transfer of load
obligations and the termination or expiration of Excepted Transactions. The
System Operator shall make such adjustments in accordance with the allocation
methodology described below, the Agreement, and NEPOOL System Rules.
Step 1: Begin with the combination of all ARRs included in the first-stage ARR
Allocation described in Section A above. This set of ARRs almost certainly will
not be simultaneously feasible.
Step 2: Hold the FCR Auction as described in Section F of Schedule 14.
Step 3: Through the following steps, eliminate ARRs having a negative value in
the FCR Auction and then reduce the set of remaining ARRs defined in Step 1
proportionately on a per Megawatt of constraint impact basis as necessary to
arrive at a set of ARRs that is simultaneously feasible in a contingency
constrained dispatch.
3(a): Identify all ARRs determined in Step 1 that receive a positive value
(in $/Megawatt) in the FCR Auction.
3(b): Test whether the ARRs identified in Step 3(a) are simultaneously
feasible.
3(c): If the ARRs identified in Step 3(a) are simultaneously feasible, go to
Step 4.
3(d): If the ARRs identified in Step 3(a) are not simultaneously feasible,
calculate the pre- and post-contingency power flows associated with dispatching
the system to honor the ARRs defined in Step 3(a).
3(e): Identify the constraint whose relief would require the largest
proportionate reduction in all of the ARRs defined in Step 3(a) that increase
flows over that constraint. Reduce proportionately on a per Megawatt of
constraint impact basis all ARRs defined in Step 3(a) that increase flows over
this constraint until the constraint is relieved.
3(f): Test whether the ARRs identified in Step 3(e) are simultaneously feasible.
If the set of ARRs defined in Step 3(e) is simultaneously feasible, proceed to
Step 4.
3(g): Otherwise, calculate the pre- and post-contingency power flows associated
with dispatching the system to honor the ARRs defined in Step 3(e).
3(h): Identify the constraint whose relief would require the largest
proportionate reduction in all of the ARRs defined in Step 3(e) that increase
flows over that constraint. Reduce proportionately on a per Megawatt of
constraint impact basis all ARRs defined in Step 3(e) that increase flows over
this constraint until the constraint is relieved.
3(i) Repeat Steps 3(f) through 3(h) as necessary until a simultaneously
feasible set of ARRs is obtained.
3(j) If as a result of the application of Steps 3(e) through 3(i) any of the
constraints over which ARRs were reduced in Steps 3(e) through 3(i) is no longer
binding, ARRs defined in Step 3(a) that have been reduced in Steps 3(e) through
3(i) and do not exacerbate any binding transmission constraint would be
proportionately scaled up until a transmission constraint becomes binding.
The allocation process ends here if NEMA is not significantly constrained and
the ARRs allocated at the conclusion of Step 3(j) constitute the final
allocation of ARRs.
Step 4. The ARR Allocation determined in the preceding steps shall be divided
into two sets: ARRs allocated to entities that are not NEMA LSEs, and ARRs
allocated to NEMA LSEs.
NEMA LSEs are Transmission Customers and Congestion Paying Entities that serve
load within NEMA.
C. Third Stage of ARR Allocation. The ARRs allocated to NEMA LSEs, as determined
in the first two stages of each ARR Allocation, may be modified further in the
third and fourth stages of the ARR Allocation. The third and fourth stages of
any ARR Allocation shall not change the amount or origin Nodes or External Nodes
or destination Locations and/or Reliability Regions of any ARRs allocated to
entities that are not NEMA LSEs as of the conclusion of the second stage of that
ARR Allocation.
For the purposes of this stage, a set of "Stage 3 ARRs" shall be defined as
follows: Certain NEMA LSEs which have long-term purchase contracts in effect as
of November 1, 1999 for generation resources with delivery points in NEMA,
excluding long-term purchase contracts covered by Excepted Transactions, ("NEMA
Contracts") shall be allocated Stage 3 ARRs. The NEMA Contracts for these NEMA
LSEs' respective generation resources and entitlements, which entitle them to
Stage 3 ARRs subject to verification that the NEMA Contracts meet the criteria
specified in the preceding sentence, are listed in Attachment 1 to this Schedule
15. Each NEMA LSE listed in Attachment 1 shall provide by October 1, 2000 to the
System Operator and shall make available upon request to each NEMA LSE, copies
of its NEMA Contract(s) in the form that such contracts existed as of November
1, 1999, together with copies of any subsequent modifications or amendments, any
notices of termination, and any notices or elections shortening the term or
reducing the amount of power to be purchased under its NEMA Contract(s). For as
long as a NEMA LSE listed in Attachment 1 has a right to request Stage 3 ARRs,
it shall have an ongoing obligation to provide, in a timely manner, each NEMA
LSE and the System Operator with copies of any further modifications or
amendments, any notices of termination, and any notices or elections shortening
the term or reducing the amount of power to be purchased under its NEMA
Contract. The amount of Stage 3 ARRs that will be allocated to each NEMA LSE
shall be equal to the sum of the Megawatts of entitlement specified in each NEMA
LSE's NEMA Contract(s) calculated based on the winter capability period (the
period from the beginning of October through the end of May) capacity during
months of the winter capability period and the summer capability period (the
period from the beginning of June through the end of September) capacity during
the months of the summer capability period subject to the limitation that the
Stage 3 ARRs allocated to each NEMA LSE shall not exceed that NEMA LSE's Monthly
Peak Load during that month of the prior year, as defined in the NEPOOL Tariff.
The origin Node or External Node for the Stage 3 ARRs allocated to NEMA LSEs
shall match the Node or External Node where Energy was purchased in association
with the NEMA Contracts listed in Attachment 1, and the destination Location for
the Stage 3 ARRs allocated to NEMA LSEs shall match the Location of the load
served by that NEMA LSE in association with that contract.
The NEMA LSEs identified in Attachment 1 to this Schedule 15 shall be entitled
to make requests for Stage 3 ARRs under the terms of this section until the
earlier of the expiration of the term of each of its NEMA Contract(s) in effect
as of November 1, 1999, but excluding any optional extensions which had not been
exercised as of November 1, 1999, or until NEMA is no longer significantly
constrained. To the extent that such a NEMA LSE transfers to other another
entity the responsibility under the Agreement or the Tariff for paying for the
Congestion Cost and RMR Charge, resulting from the NEMA LSE's NEMA Contract, the
entity assuming such responsibility shall receive the entitlement to the NEMA
LSE's Stage 3 ARRs in lieu of the NEMA LSE receiving that entitlement.
The third stage of each ARR Allocation shall be performed using the following
procedure, which will be adjusted on an annual and monthly basis to account for
changes in available transmission capacity, load ratio shares, transfer of load
obligations, reductions in or resale of purchase amounts under NEMA Contracts,
and the termination of the NEMA Contract(s) or expiration of the term of the
NEMA Contract(s) in effect as of November 1, 1999, but excluding any optional
extensions which had not been exercised as of November 1, 1999. The System
Operator shall make such adjustments in accordance with the allocation
methodology described below, the Agreement, and the NEPOOL System Rules:
Step 1: Begin with the set of all Stage 3 ARRs.
Step 2: Through the following steps, eliminate Stage 3 ARRs having a negative
value in the FCR Auction and then reduce the set of remaining Stage 3 ARRs
proportionately on a per Megawatt of constraint impact basis as necessary to
arrive at a set of ARRs that is simultaneously feasible in a contingency
constrained dispatch.
2(a): Identify all ARRs determined in Step 1 that receive a positive value (in
$/Megawatt) in the FCR Auction. Then add the set of all non-NEMA ARRs as
determined in Step 4 of Stage 2 to the remaining Stage 3 ARRs.
2(b): Test whether the ARRs identified in Step 2(a) are simultaneously
feasible.
2(c): If the ARRs identified in Step 2(a) are simultaneously feasible, go to
Step 3.
2(d): If the ARRs identified in Step 2(a) are not simultaneously feasible,
calculate the pre- and post-contingency power flows associated with dispatching
the system to honor the ARRs defined in Step 2(a).
2(e): Identify the constraint whose relief would require the largest
proportionate reduction in all of the Stage 3 ARRs defined in Step 2(a) that
increase flows over that constraint. Reduce proportionately on a per Megawatt of
constraint impact basis all Stage 3 ARRs defined in Step 2(a) that increase
flows over this constraint until the constraint is relieved.
2(f): Test whether the ARRs identified in Step 2(e) are simultaneously feasible.
If the set of ARRs defined in Step 2(e) is simultaneously feasible, proceed to
Step 3.
2(g): Otherwise, calculate the pre- and post-contingency power flows associated
with dispatching the system to honor the ARRs defined in Step 2(e).
2(h): Identify the constraint whose relief would require the largest
proportionate reduction in all of the Stage 3 ARRs defined in Step 2(e) that
increase flows over that constraint. Reduce proportionately on a per Megawatt of
constraint impact basis all Stage 3 ARRs defined in Step 2(e) that increase
flows over this constraint until the constraint is relieved.
2(i) Repeat Steps 2(f) through 2(h) as necessary until a simultaneously
feasible set of ARRs is obtained.
2(j) If as a result of the application of Steps 2(e) through 2(i) any of the
constraints over which ARRs were reduced in Steps 2(e) through 2(i) is no longer
binding, ARRs defined in Step 2(a) that have been reduced in Steps 2(e) through
2(i) and do not exacerbate any binding transmission constraint would be
proportionately scaled up until a transmission constraint becomes binding.
Step 3. Remove the non-NEMA ARRs. The remaining ARRs will be the ARRs for
the NEMA Contracts.
D. Fourth Stage of ARR Allocation. The fourth stage of the ARR Allocation shall
determine the final allocation of ARRs for a given FCR Auction. The fourth stage
shall only affect the allocation of ARRs to NEMA LSEs. For the purposes of this
step, a set of "Stage 4 ARRs" shall be defined. Each NEMA LSE shall be allocated
Stage 4 ARRs, using the following formula:
Nikt = Aikt * Xkt
where:
Nikt = the amount of Stage 4 ARRs from Node or External Node i to the Locations
within NEMA allocated to NEMA LSE k for month t;
Aikt = the amount of ARRs from Node i to NEMA that had been allocated to NEMA
LSE k for month t as of the conclusion of the second stage of the ARR
Allocation; and
Xkt = the ratio of (the Monthly Peak Load of NEMA LSE k calculated on the basis
of its Monthly Peak Load during the same month t of the prior year less the
allocation of ARRs for NEMA Contracts to NEMA LSE k for month t) to the Monthly
Peak Load of NEMA LSE k in month t of the prior year.
The fourth stage of each ARR Allocation shall be performed using the following
procedure, which will be adjusted on an annual and monthly basis to account for
changes in available transmission capacity, load ratio shares, transfer of load
obligations, reductions in purchase amounts under NEMA Contracts, and the
termination of the NEMA Contract(s) or expiration of the term of the NEMA
Contract(s) in effect as of November 1, 1999, but excluding any optional
extensions which had not been exercised as of November 1, 1999. The System
Operator shall make such adjustments in accordance with the allocation
methodology described below, the Agreement, and NEPOOL System Rules:
Step 1: Begin with the set of all Stage 4 ARRs.
Step 2: Through the following steps, eliminate negatively-valued Stage 4 ARRs
and then reduce the set of remaining Stage 4 ARRs proportionately on a per
Megawatt of constraint impact basis as necessary to arrive at a set of ARRs that
is simultaneously feasible in a contingency constrained dispatch.
2(a): Identify all ARRs determined in Step 1 that receive a positive value (in
$/Megawatt) in the FCR Auction. Then add the set of all non-NEMA ARRs and all
ARRs for NEMA Contracts to the remaining Stage 4 ARRs.
2(b): Test whether the ARRs identified in Step 2(a) are simultaneously
feasible.
2(c): If the ARRs identified in Step 2(a) are simultaneously feasible, go to
Step 3.
2(d): If the ARRs identified in Step 2(a) are not simultaneously feasible,
calculate the pre- and post-contingency power flows associated with dispatching
the system to honor the ARRs defined in Step 2(a).
2(e): Identify the constraint whose relief would require the largest
proportionate reduction in all of the Stage 4 ARRs defined in Step 2(a) that
increase flows over that constraint. Reduce proportionately on a per Megawatt of
constraint impact basis all Stage 4 ARRs defined in Step 2(a) that increase
flows over this constraint until the constraint is relieved.
2(f): Test whether the ARRs identified in Step 2(e) are simultaneously
feasible. If the set of ARRs defined in Step 2(e) is simultaneously feasible,
proceed to Step 3.
2(g): Otherwise, calculate the pre- and post-contingency power flows
associated with dispatching the system to honor the ARRs defined in Step
2(e).
2(h): Identify the constraint whose relief would require the largest
proportionate reduction in all of the Stage 4 ARRs defined in Step 2(e) that
increase flows over that constraint. Reduce proportionately on a per Megawatt of
constraint impact basis all Stage 4 ARRs defined in Step 2(e) that increase
flows over this constraint until the constraint is relieved.
2(i) Repeat Steps 2(f) through 2(h) as necessary until a simultaneously
feasible set of ARRs is obtained.
2(j) If as a result of the application of Steps 2(e) through 2(i) any of the
constraints over which ARRs were reduced in Steps 2(e) through 2(i) is no longer
binding, ARRs defined in Step 2(a) that have been reduced in Steps 2(e) through
2(i) and do not exacerbate any binding transmission constraint would be
proportionately scaled up until a transmission constraint becomes binding.
Step 3. The remaining ARRs constitute the final allocation of ARRs. Holders of
ARRs in this allocation shall be deemed ARR Holders.
E. Payments to ARR Holders. Each ARR Holder shall be entitled to receive a share
of the Auction Revenues from each annual or monthly FCR Auction reflecting the
value in that auction of FCRs, other than those sold by FCR Holders,
corresponding to its ARRs, whether or not such specific FCRs are actually sold.
This share shall equal the amount of ARRs (quantified in Megawatts) received in
the final allocation of ARRs with specified origin Nodes or External Nodes and
destination Locations and/or Reliability Regions that it holds which cover the
period for which FCRs were sold in that auction, multiplied by the value
determined in that FCR Auction for FCRs with the same origin Nodes or External
Nodes and destination Locations and/or Reliability Regions as the ARRs. The
determination of the FCRs awarded in each FCR Auction shall be subject to a
simultaneous feasibility test in accordance with Schedule 14. The amount of
feasible FCRs available in the FCR Auction (and the corresponding Auction
Revenues and payments to ARR Holders) will vary depending on transmission system
conditions.
F. Annual and Monthly ARR Adjustments. ARR Holders who receive a share of the
Auction Revenues from FCRs sold in the annual FCR Auction and whose load serving
responsibility (as reflected in the NEPOOL market settlement system) decreases
in subsequent months in the same year shall retain the annual ARR payments, but
shall be allocated a smaller share of ARRs, in proportion to their decrease in
load ratio share, to the monthly Auction Revenues.
G. Incremental ARRs. An entity who pays for new transmission upgrades which
increase transfer capability on the NEPOOL Transmission System, making it
possible for the System Operator to award additional FCRs in the FCR Auction,
shall be awarded ARRs. The amount of ARRs awarded to such an entity, and the
origin and destination Locations and/or Hubs for those ARRs, shall be consistent
with the FCRs that were made possible by the transmission upgrade, as determined
by the System Operator and the FCRs awarded in the auction. The award shall be
in direct proportion to the percentage of the costs of the upgrade paid by such
entity, and shall continue for so long as the entity supports the costs of the
upgrade. ARRs awarded to an entity who pays for transmission upgrades will not
be subject to reduction in Stages 2, 3 and 4 of the ARR Allocation process
described above. To the extent that transmission upgrades resulting in new
transfer capability are paid for through the Pool RNS Rate, any Auction Revenue
Rights associated with the sale of FCRs made possible by such upgrades, other
than FCRs sold by FCR Holders, shall be allocated to Transmission Customers and
Congestion Paying Entities on a Monthly Peak Load basis.
H. Additional Rules and Procedures. Consistent with this Schedule 15, the
implementation of its provisions shall further be detailed, defined and carried
out pursuant to Market Rules.
ATTACHMENT 1 TO SCHEDULE 15
TABLE 1
NEMA CONTRACTS
NEMA Load-Serving Entity NEMA Contract Entitlements(FN1)
Danvers 1. Millstone 3 (.263%)
2. Seabrook (1.12%)
3. Stony Brook Combined Cycle
(8.457%)
4. Stony Brook 2A (11.555%)
5. Stony Brook 2B (11.555%)
6. Vermont Yankee (1.08 MW)
7. Hydro Quebec (2.93 MW
(winter))
8. NYPA (2.44 MW)
Georgetown 1. Millstone 3 (.021%)
2. Seabrook (.096%)
3. Stony Brook Combined Cycle
(.736%)
- ------
(FN1) NEMA Contract entitlements are stated by percentage in case of unit
entitlements held on percentage basis, and by megawatts (MW) where contract
states entitlement in MW.
4. Stony Brook 2A (1.014%)
5. Stony Brook 2B (1.014%)
6. Vermont Yankee (.144 MW)
7. System Power (Select Energy)
(2.0 MW)
8. Hydro Quebec (.280 MW
(winter))
9. NYPA (.620 MW)
Ipswich 1. Millstone 3 (.061%)
2. Seabrook (.107%)
3. Stony Brook Combined Cycle
(.293%)
4. Vermont Yankee (.522 MW)
5. NYPA (1.35 MW)
Marblehead 1. Millstone 3 (.154%)
2. Seabrook (.135%)
3. Stony Brook Combined Cycle
(2.64%)
4. Stony Brook 2A (1.598%)
5. Stony Brook 2B (1.598%)
6. Wyman 4 (.279%)
7. Vermont Yankee (.655 MW)
8. Hydro Quebec (1.040 MW
(winter))
9. NYPA (2.140 MW)
Middleton 1. Millstone 3 (.044%)
2. Seabrook (.328%)
3. Stony Brook Combined Cycle
(.878%)
4. Stony Brook 2A (1.892%)
5. Stony Brook 2B (1.892%)
6. Wyman 4 (.101%)
7. Vermont Yankee (.213%)
8. System Power (NU) (10.5 MW)
9. Hydro Quebec (.580 MW
(winter))
10. NYPA (.6 MW)
Peabody 1. Millstone 3 (.297%)
2. Seabrook (1.13%)
3. Stony Brook Combined Cycle
(13.052%)
4. Vermont Yankee (1.693 MW)
5. Hydro Quebec (3.480 MW
(winter))
6. NYPA (4.860 MW)
Reading 1. Millstone 3 (.404%)
2. Seabrook (.635%)
3. Stony Brook Combined Cycle
(14.453%)
4. Stony Brook 2A (19.516%)
5. Stony Brook 2B (19.516%)
6. System Power (NU) 15 MW
(out of a total of 30 -
remaining 15 MW are
Excepted Transactions)
7. Hydro Quebec (5.710 MW
(winter))
Wakefield 1. Millstone 3 (.206%)
2. Seabrook (.387%)
3. Stony Brook (3.993%)
4. Stony Brook 2A (6.379%)
5. Stony Brook 2B (6.379%)
6. Wyman 4 (.440%)
7. Vermont Yankee (.885 MW)
8. Hydro Quebec (1.520 MW
(winter))
9. NYPA (2.230 MW)
Concord 1. Hydro Quebec (.890 MW
(winter))
Groveland 1. System Power (NU) (6.1 MW)
2. NYPA (.510 MW)
Merrimac 1. System Power (NU) (4.9 MW)
2. NYPA (.520 MW)
Rowley 1. System Power (NU) (6.7 MW)
2. Hydro Quebec (.2 MW (winter))
3. NYPA (.510)
SCHEDULE 16
System Restoration and Planning Service from Generators
System Restoration and Planning Service is necessary to ensure the continued
reliable operation of the New England Transmission System. System Restoration
and Planning Service enables the System Operator to designate specific
generators interconnected to the transmission or distribution system at
strategic locations capable of supplying load to re-energize the transmission
system following a system-wide blackout. These designated generators are able to
start without an outside electrical supply and are otherwise known as "Black
Start Capable." The planning and maintenance of adequate capability for
restoration of the NEPOOL Control Area following a blackout represents a benefit
to all entities using the power system. Therefore, this service must be taken
from the System Operator. In contrast to the System Restoration and Planning
Service described herein, the actual supply of power that would allow a power
producer to restart its own generating units may itself be self-supplied or
purchased from another power producer independent of the NEPOOL Control Area
arrangements formulated by the System Operator. The Black Start Capability
intrinsic of System Restoration and Planning Service is to be provided by
designated Participants through the System Operator.
I. Rate Formulas
A Transmission Customer Purchasing either Regional Network Service under
Schedule 9 of this Agreement or Internal Point to Point Service under Schedule
10 of this Agreement, or a Transmission Customer making Unauthorized Use shall
be required to pay NEPOOL for its share of Black Start Restoration and Planning
Service ("Black Start Responsibility") as determined in accordance with the
following formulas:
MRSR = (EQUATION)
Where:
MRSR = The Transmission Customers' Monthly Restoration Service Rate.
NL = The aggregate of the individual sums of each Participant's or Non-
Participant's Network Load for the billing month.
IPP = The aggregate of the individual sums of each Participant's or Non-
Participant's maximum Reserved Capacity for Internal Point-to-Point Service for
each load served within a Local Network or Network(s) during the billing month.
UAU = The aggregate of the individual sums of each Participant's or Non-
Participant's Maximum Unauthorized Use associated with Internal Point-to- Point
Service for each load served within a Local Network or Network(s) during the
month.
C = The annual cost of Service as determined from Supplement 1.
Each individual Participant's or Non-Participant's charge in any billing month
would be calculated by the following formula:
MC = (MRSR)(NLi + IPPi + UAUi)
Where
MC = The Monthly Charge.
NLi = The sum of a Participant's or Non-Participant's Network Load for the
billing month.
IPPi = The sum of a Participant's or Non-Participant's maximum Reserved Capacity
for Internal Point-to-Point Service for each load served within a Local Network
or Network(s) during the billing month.
UAUi = The sum of a Participant's or Non-Participant's Maximum Unauthorized Use
associated with Internal Point-to-Point Service for each load served within a
Local Network or Network(s) during the month.
A separate charge for this service based upon the above rates will be added to
the Transmission Customer's monthly bill. The above rates are based upon
generator expense as determined by Supplement 1.
II.
III. Compensation to Generators
A. Eligibility. In order to be designated as a "Black Start Generator"
providing System Restoration Service and to be eligible for compensation
under this Schedule 16 of the NEPOOL Open Access Transmission Tariff, a
generator must meet the following criteria:
1. The unit is "Black Start Capable" in that it has the ability of being started
without energy from other NEPOOL generating units in such a way that it meets
all of the requirements stated in Operating Procedure 11 (Black Start Capability
Eligibility & Testing Requirements); and
2. The unit owner, NEPOOL, and the System Operator agree that the unit should be
designated Black Start Capable and accordingly is listed as a Black Start unit
in Operating Procedure 11.
Each generator which is eligible for and seeks compensation under the NEPOOL
Open Access Transmission Tariff for providing System Restoration Service shall
execute an agreement with NEPOOL.
III. Effective Date. This Schedule 16 shall be effective as of September 1,
1998.
Supplement 1
To Schedule 16
System Restoration and Planning Service Revenue Requirement
The annual Revenue Requirement for System Restoration and Planning Service will
be the sum of the annual revenue requirements for each generator which is
designated in NEPOOL Operating Procedure 11 as providing Black Start Service and
which has provided to the System Operator, along with work papers and supporting
documents, a calculation of its annual Revenue Requirement, determined in
accordance with this Supplement 1.
Each Black Start Generator's Revenue Requirement will reflect the generator's
costs for its Black Start equipment as listed in Exhibit 1. Each Generator's
Revenue Requirement will be an annual calculation based on the previous calendar
year's data and supplied to the ISO in time for a June 1 informational filing.
The calculation is set forth below:
The Generator's Revenue Requirement shall equal the sum of generator's (A)
Return and Associated Income Taxes, (B) Black Start Plant Depreciation Expense,
(C) Black Start Related Amortization of Loss on Reacquired Debt, (D) Black Start
Related Amortization of Investment Tax Credits, (E) Black Start Related
Municipal Tax Expense, (F) Black Start Operation and Maintenance Expense, and
(G) Black Start Related Administrative and General Expense.
A. Return and Associated Income Taxes shall equal the product of the Black
Start Plant Investment Base and the Cost of Capital Rate.
1. The Black Start Plant Investment Base will consist of (a) Black Start Plant
in FERC 345 or equivalent accounts, plus (b) Related General Plant in FERC 244
or equivalent accounts, less (c) Related Depreciation Reserve, less (d) Related
Accumulated Deferred Taxes, plus (e) Related Loss on Reacquired Debt, plus (f)
other regulatory assets, plus (g) Prepayments, plus (h) Materials and Supplies,
plus (i) Related Cash Working Capital.
a. Black Start Plant will equal the calculated average balance of generator's
investment in the Exhibit 1 facilities based upon GAAP records and engineering
studies and evaluations categorized similar in principal to FERC 345 or
equivalent accounts.
b. Black Start Related General Plant shall equal generator's calculated average
balance of investment in general plant based upon GAAP records and engineering
studies and evaluations categorized similar in principal to FERC 244 or
equivalent accounts multiplied by the ratio of Black Start related wages and
salaries utilizing a standard labor rate to the generator's total wages and
salaries of the black start facilities, and excluding administrative and general
wages and salaries ("Black Start Allocation Factor").
c. Black Start Related Depreciation Reserve shall equal the average balance of
total Black Start depreciation reserve for the Black Start Plant plus the
average balance of Black Start Related General Plant depreciation reserve. The
Black Start Plant depreciation reserve shall be the average balance of the total
Black Start Plant depreciation recovered by the generator for providing system
restoration services. Black Start Related General Plant depreciation reserve
shall equal the product of the Black Start General Plant reserve and the Black
Start Allocation Factor.
d. Black Start Related Accumulated Deferred Taxes shall equal generator's
average balance of total accumulated deferred income taxes, multiplied by the
ratio of total investment in Black Start Plant plus Black Start Related General
Plant to total plant in service excluding general plant ("Plant Allocation
Factor").
e. Black Start Related Loss on Reacquired Debt shall equal generator's average
balance of total loss on reacquired debt multiplied by the Plant Allocation
Factor described in Section (A) (1) (d).
f. Other Regulatory Assets shall equal generator's average balance of FAS 106
multiplied by the Black Start Allocation Factor described in Section (A) (1) (b)
above and the balance of FAS 109, net of FAS 109 liability multiplied by the
Plant Allocation Factor described in Section (A) (1) (d) above.
g. Black Start Prepayments shall equal generator's average balance of
prepayments multiplied by the Black Start Allocation Factor described in Section
(A) (1) (b) above.
h. Black Start Materials and Supplies shall equal generator's average balance of
plant materials and supplies multiplied by the Plant Allocation Factor described
in Section (A) (1) (d) above or the actual materials and supplies utilized in
the operation and maintenance of Black Start equipment.
i. Black Start Related Cash Working Capital shall be a 12.5% allowance (45 days
/ 360 days) of Black Start operation and maintenance expense and related
administrative and general expense.
2. The Cost of Capital Rate shall equal (a) the Weighted Cost of Capital,
plus (b) Federal Income Taxes, plus (c) State Income Taxes.
a. The Weighted Cost of Capital will be the weighted average cost of debt and
common equity, using a proxy capital structure based upon a 50% debt and 50%
equity split.
i) The Return on Equity Component shall be the average of the NEPOOL
Transmission Providers' return on equity pursuant to the NEPOOL Tariff.
ii) The Cost of Debt component shall equal the current interest rate of a
30-year U.S. Treasury Bond.
b. Federal Income Taxes shall equal
(EQUATION)
where FT is the federal income tax rate (35%) and A is the Return on Equity
Component, as determined in Section (A) (2) (a) (i).
c. State Income Taxes shall equal
(A + Federal Income Tax)(ST)
1 - ST
Where ST is the state income tax rate for the applicable state and A is the
Return on Equity Component, as determined in Section (A) (2) (a) (i), and
Federal Income Tax is the rate determined in Section (A) (2) (b) above.
B. Black Start Depreciation Expense shall equal the sum of depreciation expense
for Black Start Plant plus an allocation of general plant depreciation expense
calculated by multiplying general plant depreciation expense by the Black Start
Allocation Factor, described in Section (A) (1) (b) above.
C. Black Start Related Amortization of Loss on Reacquired Debt shall equal
generator's amortization of loss on reacquired debt multiplied by the Plant
Allocation Factor described in Section (A) (1) (d) above.
D. Black Start Related Amortization of Investment Tax Credits shall equal
generator's amortization of investment tax credits multiplied by the Plant
Allocation Factor described in Section (A) (1) (d) above.
E. Black Start Related Municipal Tax Expense shall equal generator's total
municipal tax expense multiplied by the Plant Allocation Factor described in
Section (A) (1) (d) above.
F. Black Start Operation and Maintenance Expense shall equal all expenses
charged directly to Black Start equipment.
G. Black Start Related Administrative and General Expenses shall equal
generator's administrative and general expenses, plus payroll taxes, multiplied
by the Black Start Allocation Factor described in Section (A) (1) (b) above.
Exhibit 1 to Supplement 1
Additional Black Start Cost of Service Methodology Details
The objective of this methodology is to apply cost of service principles to
determine the amount of compensation providers of black start service receive.
Black Start Generators are only compensated for the incremental costs that are
incurred in making and maintaining a unit black start capable and do not include
any other costs. Generators shall not recover those black start costs for which
they are otherwise compensated through other rate schedules or divestiture
contracts.
O&M includes equipment wear and tear, training, black start labor costs
associated with testing, and periodic maintenance. It is assumed that there are
25 worker-hours per black start unit per year of training. Wear and tear
associated with testing black start units will be prorated based on number of
hours between maintenance activities. For example, if a maintenance activity
occurs every 1,000 hours, and black start testing lasts 1 hour per year, than
0.1% of the costs associated with that maintenance activity will be recovered
through black start charges.
Fuel costs are those actual, average in tank fuel costs including emission
allowances/credits used in testing Black Start Generators and their actual use
in system restoration. Fuel costs include fuel consumed due to minimum run
requirements.
Cash and Working Capital include spare parts associated with the equipment that
makes a generating unit black start capable.
The list of equipment below is equipment commonly associated with making
generating units Black Start Capable. The exact equipment varies depending on
the specific generator. In addition, some generating units are made Black Start
Capable by having a stand alone generating unit that is not connected to the
bulk power system (and therefore cannot participate in any of the NEPOOL
markets). This stand-alone generating unit provides the means by which the black
start generating unit is Black Start Capable.
(FN1) The following equipment is assumed to be depreciated over the
following number of years (unless a different depreciation is required by FERC):
Air compressors 10 years
Air tanks 30 years
Batteries/Chargers 10 years
DC motors 25 years
DC Controllers 25 years
DC/AC Inverters 10 years
- ----
(FN 1) These depreciation times are intended to be consistent with FERC policy
and need to be verified as such. If they are not consistent, they will be made
so.
Supplement 2
To Schedule 16
Black Start System Restoration and Planning Service Terms and Conditions
1. Definition of System Restoration and Planning Service. A unit is defined
to provide "System Restoration and Planning Service" if both of the following
conditions are met:
A. The unit is "Black Start Capable" in that it has the ability of being started
without energy from other NEPOOL generating units in such a way that it meets
all of the requirements stated in Operating Procedure 11 (Black Start Capability
Eligibility & Testing Requirements); and
B. The unit owner, NEPOOL, and the System Operator agree that the unit
should be designated Black Start Capable.
2. Generator Owner's commitment to provide System Restoration and Planning
Service:
A. Generators need to commit initially for at least three years to provide
System Restoration and Planning Service from the date of the last
black-start/system restoration study. The most recent study was conducted in
October 1998.
B. All succeeding commitments must be at least for three years.
C. Generators may, and are encouraged to, commit to provide System
Restoration and Planning Service for periods greater than three years with
System Operator and NEPOOL concurrence.
D. Generators need to give at least one-year notice that they will no longer be
able to provide System Restoration and Planning Service. This one-year notice
cannot truncate the generator's commitment to provide System Restoration and
Planning Service except as noted in item 2(E) or 2(F) below.
E. If due to an event of Force Majeure a Generator Owner cannot provide System
Restoration and Planning Service, the above notification requirements stated in
items 2(A) and 2(B) are not binding.
F. If an owner of a generation unit that is designated Black Start Capable
decides to retire that unit, then the three year requirement to provide System
Restoration and Planning Service from that unit is not binding. The one-year
notice, however, is binding.
3. Performance obligations of generators that are providing System
Restoration and Planning Service:
A. Generators that are providing System Restoration and Planning Service will be
tested in accordance with Operating Procedure 11 or its successor, which may be
revised from time to time.
B. Units that are providing System Restoration and Planning Service must start-
up within the prescribed time stipulated in Operating Procedure 11 (Black Start
Capability Eligibility & Testing Requirements). Not all unmanned units that are
providing System Restoration and Planning Service will be asked to start-up at
the same time.
C. If a unit fails a System Restoration and Planning Service test, the owner
must incur the necessary costs to make that unit capable of passing the test
within a reasonable amount of time. Until the unit passes another System
Restoration and Planning Service test, it would not be compensated for providing
System Restoration and Planning Service. All costs associated with System
Restoration and Planning Service unit re-tests are at the owner's expense.
4. Obligations by System Operator and NEPOOL to generators that are
providing System Restoration and Planning Service:
A. Generators that commit to provide System Restoration and Planning Service
will not have their Black Start Capable designation terminated within the time
period of their commitment.
B. The System Operator and NEPOOL must provide at least one-year notice to the
owner or owners of generation units that are providing System Restoration and
Planning Service prior to terminating that unit's designation as Black Start
Capable.
C. There are no additional restrictions on generation maintenance of designated
Black Start Capable units beyond what exists for non-Black Start units except
that designated Black Start generation units cannot take seasonal outages.
If a Generator Owner makes System Operator and NEPOOL approved capital
investments necessary to System Restoration and Planning Service, then that
owner will recover all of the associated costs of that investment, including on
and of capital, unless the owner voluntary removes that unit from providing
System Restoration and Planning Service prior to the recovery of its investment
costs in accordance with the cost-of-service methodology approved for the
recovery of System Restoration and Planning Service costs. If a Generator Owner
voluntary removes a unit from providing System Restoration and Planning Service
prior to the recovery of all of its investment costs, then that owner only
receives that portion of its investment cost that was recovered during the
period that its unit was providing System Restoration and Planning Service.
The System Operator or its designated agent shall have the right to
independently audit the accounts and records of each generator receiving
payments under this rate schedule. The generator shall make its accounts and
records available at its offices at a mutually agreeable time for this audit.
Such audit shall extend only to those areas relating specifically to this rate
schedule. Any errors identified as a result of such audit shall be corrected
with interest in accordance with FERC policy with refunds and surcharges, as
appropriate, for any amounts previously over- or under-charged due to such
errors.
ATTACHMENT A
Form of Service Agreement for
Through or Out Service or
Internal Point-To-Point Service
1.0 This Service Agreement, dated as of , is entered into, by and between the
NEPOOL Participants acting through (the "System Operator") and ("Transmission
Customer").
2.0 The Transmission Customer has been determined by the System Operator to have
a Completed Application for Firm [Non-Firm] Transmission Service under this
Tariff.
3.0 If required, the Transmission Customer has provided to the System Operator
an Application deposit in accordance with the provisions of this Tariff.
4.0 Service under this Service Agreement shall commence on the later of (1) the
requested service commencement date, or (2) the date on which construction or
any Direct Assignment Facilities and/or facility additions or upgrades are
completed, or (3) such other date as it is permitted to become effective by the
Commission. Service under this Service Agreement shall terminate on such date as
is mutually agreed upon by the parties.
[The Service Agreement may be a blanket agreement for non-firm service.]
5.0 The Participants agree to provide, and the Transmission Customer agrees to
take and pay for, Transmission Service in accordance with the provisions of the
Tariff and this Service Agreement.
6.0 Any notice or request made to or by either party regarding this Service
Agreement shall be made to the representative of the other party as indicated
below.
NEPOOL Participants:
New England Power Pool
One Sullivan Road
Holyoke, MA 01040-2841
Transmission Customer:
7.0 The Tariff is incorporated in this Service Agreement and made a part
hereof.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be
executed by their respective authorized officials.
NEPOOL Participants:
By [System Operator]
By:
Name
Title
Date
Transmission Customer:
By:
Name
Title
Date
Specifications For Through or Out Service
or Internal Point-to-Point Service
1.0 Term of Transaction:
Start Date:
Termination Date:
2.0 Description of capacity and energy to be transmitted by Participants
including the electric Control Area in which the transaction originates.
3.0 Point(s) of Receipt:
Delivering party:
4.0 Point(s) of Delivery:
Receiving party:
5.0 Maximum amount of capacity and energy to be transmitted (Reserved
Capacity):
6.0 Designation of party(ies) or other entity(ies) subject to reciprocal
service obligation:
7.0 Name(s) of any intervening systems providing transmission
service:
8.0 Service under this Service Agreement may be subject to some combination of
the charges detailed below. (The appropriate charges for individual transactions
will be determined in accordance with the terms and conditions of this Tariff.)
8.1 Transmission Charge:
8.2 System Impact Study and/or Facilities Study Charge(s):
8.3 direct assignment expansion charge [Need to define or reference upgrade
costs]:
ATTACHMENT B
Form Of Service Agreement For
Regional Network Service
1.0 This Service Agreement, dated as of , is entered into, by
and between the NEPOOL Participants acting through
(the "System Operator"), and
("Transmission Customer").
2.0 The Transmission Customer has been determined by the System Operator to be a
Transmission Customer under the Tariff and has requested Regional Network
Service under the Tariff.
3.0 Regional Network Service (including, if requested, Network Integration
Transmission Service) under this Agreement shall be provided by the NEPOOL
Participants upon request by an authorized representative of the Transmission
Customer.
4.0 The Transmission Customer agrees to supply information the System Operator
deems reasonably necessary in accordance with Good Utility Practice in order for
it to provide the requested service.
5.0 The Participants agree to provide and the Transmission Customer agrees to
take and pay for Regional Network Service in accordance with the provisions of
the Tariff and this Service Agreement.
6.0 Any notice or request made to or by either party regarding this Service
Agreement shall be made to the representative of the other party as indicated
below.
NEPOOL Participants:
New England Power Pool
One Sullivan Road
Holyoke, MA 01040-2841
Transmission Customer:
7.0 The Tariff is incorporated herein and made a part hereof.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be
executed by their respective authorized officials.
Transmission Customer:
By:
Name
Title
Date
NEPOOL Participants:
By: [System Operator]
By:
Name
Title
Date
ATTACHMENT C
Methodology To Assess Available Transmission Capability
Available Transmission Capability (ATC) will be assessed based on industry-
accepted standards; currently, ATC will be established by reducing the
determined Total Transfer Capability (TTC) by the Transmission Reliability
Margin (TRM) and by transmission commitments.
Total Transfer Capability (TTC) is the determined amount of electric power that
can be reliably transferred over the network consistent with the following:
Good utility practice
NERC standards, guides, and procedures;
NPCC criteria and guidelines;
New England criteria, rules, procedures, and reliability standards;
Applicable guides, standards, and criteria of the affected Transmission
Owner(s), whether Participant or Non-Participant; Other applicable
guidelines and standards which may need to be established from time to
time.
As such, TTC will be determined at a level which maintains all of the following:
All equipment within its applicable capabilities;
Voltages and reactive reserves within acceptable levels;
Stability maintained with adequate levels of damping;
Frequency (Hz) within acceptable levels.
TTC will be evaluated using appropriate and suitable tools, data, and
information, considering the physical impacts of electric power transfers on the
interconnected transmission network. It will reflect anticipated system
conditions and equipment status to the degree practicable.
The Transmission Reliability Margin (TRM) will be established at a level which
incorporates the uncertainties and continued variability of system conditions
and the practical limitations of system control.
Transmission commitments include existing and pending requests for transmission
service and obligations of other existing contracts under which transmission
service is provided.
ATTACHMENT D
Methodology for Completing a System Impact Study
The system impact study will be performed to evaluate the impact of the
requested service on the reliability and operating characteristics of the bulk
power system, consistent with:
Good utility practice
NERC standards, guides, and procedures;
NPCC criteria and guidelines;
New England criteria, rules, procedures, and reliability standards;
Applicable guides, standards, and criteria of the impacted Transmission
Owner(s), whether Participant or Non-Participant; Other applicable
guidelines and standards which may need to be established from time to
time.
As such, the study will examine the impact on the New England regional bulk
power system and its component systems and neighboring and external systems.
Consistent with the aforementioned, the ability to operate the system subject to
the following will be considered:
All equipment within its applicable capabilities;
Voltages and reactive reserves within acceptable levels;
Stability maintained with adequate levels of damping;
Frequency (Hz) within acceptable levels.
The study will consider the reliability requirements to meet existing and
pending obligations of the Participants and the obligations of the impacted
Transmission Owner(s).
The study will be performed using appropriate and suitable analysis tools and
modeling data consistent with the nature and duration of the requested service.
It is expected that the Eligible Customer will provide the information as
prescribed in Exhibit 1 of Attachment I, and such other information as may be
reasonably required and associated with the requested service and necessary for
its study. It is also recognized that it may be determined that additional or
specialized analysis tools or computer software are necessary for the study. The
responsibility for the provision of these items will be subject to the System
Impact Study Agreement.
The study will identify if the requested service or a portion of it can be
provided without adverse impact on the reliability and operating characteristics
of the system. The study will also identify if it appears that modification of
the system is necessary to provide the service.
ATTACHMENT E
Local Networks
The Local Networks, as of the effective date of this Tariff, are those of the
following:
1. Bangor Hydro-Electric Company
2. Boston Edison Company
3. Central Maine Power Company
4. the Commonwealth Energy System companies
5. the Eastern Utility Associates companies
6. the New England Electric System companies
7. the Northeast Utilities companies
8. The United Illuminating Company
9. Vermont Electric Power Company and the entities which are grouped with it
as a single Participant.
ATTACHMENT F
Annual Transmission Revenue Requirements
The Transmission Revenue Requirements for each Participant will reflect the
Participant's costs with respect to Pool-Supported PTF. The Transmission Revenue
Requirements will be an annual calculation based on the previous year's calendar
data as shown, in the case of Transmission Providers which are subject to the
Commission's jurisdiction, in the Participants' FERC Form 1 report for that
year, and shall be based on actual data in lieu of allocated data if
specifically identified in the Form 1 report in accordance with the following
formula:
I. The Transmission Revenue Requirement shall equal the sum of the Transmission
Provider's (A) Return and Associated Income Taxes, (B) Transmission Depreciation
Expense, (C) Transmission Related Amortization of Loss on Reacquired Debt, (D)
Transmission Related Amortization of Investment Tax Credits, (E) Transmission
Related Municipal Tax Expense, (F) Transmission Related Payroll Tax Expense, (G)
Transmission Operation and Maintenance Expense, (H) Transmission Related
Administrative and General Expense, (I)
Transmission Related Integrated Facilities Charges, minus (J) Transmission
Support Revenue, plus (K) Transmission Support Expense, plus (L) Transmission
Related Expense from Generators, plus (M) Transmission Related Taxes and Fees
Charge, minus (N) Revenue for Short-Term Transmission Service under the NEPOOL
Tariff and (O) Transmission Rents Received from Electric Property.
The details for implementation of Attachment F, as well as the definitions of
the terms used in the Attachment F formula, shall be established in accordance
with the applicable rule set forth in the Settlement Agreement entered into in
FERC Dockets OA97-237-000, et al. Any changes to that rule must be approved by
the Regional Transmission Operations Committee. The rule and any changes thereto
shall be filed with the Commission and considered a supplement to this Tariff.
ATTACHMENT G: List of Excepted Transaction Agreements
(Table)
Attachment G is a listing of transmission agreements pertaining to certain
point-to-point wheeling transactions across or out of a Local Network. In
accordance with Sections 25, 25A and 25B of the Tariff, these agreements will
continue to be in effect at the rates and terms thereunder rather than under the
Tariff.
Notes to Attachments G, G-1 and G-2
1. NEP's long-term Point-to-Point transmission services will be grandfathered at
a fixed rate of $17.00/kW-yr. Distribution, transformation, and metering
surcharges when applicable, will be subject to NEP's applicable point-to-point
tariffs.
2. See FERC Contract for specific details of agreement. In general, 100MW's
until transmission upgrades are complete. This item is still under review and is
subject to further review dependent upon outcome of Congestion Pricing.
3. Excepted status applies to transmission by CMP. Transmission by others
(MEPCO, NBP, MPS) remains under the rates, terms and conditions of applicable
agreements.
4. This Transmission Service Agreement is governed in part by a memorandum
of understanding, filed 6/13/97 in Docket nos. EC90-10-007, ER93-294-000,
ER95-1686-000, ER96-496-000, OA97-237-000, and ER97-1079-000.
ADDENDUM TO ATTACHMENTS G, G-1 AND G-2
Pursuant to the terms of a settlement agreement (the "Settlement Agreement")
reached in FERC Dockets OA97-237-000, et al., the parties to the Excepted
Transaction Agreements specifically identified below have reached the following
agreements with respect to those Excepted Transaction Agreements. In addition to
the items specifically identified below, other Excepted Transaction Agreements
listed in Attachment G, G-1 and G-2 to this Tariff may also be affected more
generally by the terms of that Settlement Agreement.
NEPOOL Tariff Attachment G, Item 1
If the Settlement Agreement is approved in its entirety and takes effect as to
all signatories, Unitil and CMP agree as follows: This Transmission Service
Agreement between Unitil and CMP (the "Unitil/CMP Agreement") will continue in
effect without modification until that date on which the revenues received by
CMP, pursuant to the terms and conditions of the Unitil/CMP Agreement, as
calculated prospectively from March 1, 1999, equals Three Hundred Thousand
Dollars ($300,000.00). Such date is anticipated to be December 13, 1999. On that
date, the said Unitil/CMP Agreement will terminate, and any rights and
obligations enjoyed by CMP and Unitil under the terms of the Unitil/CMP
Agreement will cease. Any issues involving the revenues received prior to March
1, 1999 by CMP from Unitil pursuant to the Unitil/CMP Agreement have been
resolved in accordance with the terms of the Settlement Agreement, Section G.
Unitil and CMP each agree to waive any claims against the other arising prior to
March 1, 1999, whether identified previously or not, that are based on or in any
way relate to the terms and conditions of the Unitil/CMP Agreement.
NEPOOL Tariff Attachment G, Item 4
Phase I payments will be made according to the Settlement Agreement, Section G.
This Excepted Transaction will be terminated effective March 1, 1999.
NEPOOL Tariff Attachment G, Items 7 and 8
From March 1, 1999 forward the service under the Excepted Transaction will be
terminated and will be subject to NEPOOL Tariff and, if applicable, the NEP LNS
Tariff.
NEPOOL Tariff Attachment G, Item 10
Phase I payments will be made according to the Settlement Agreement, Section G.
This Excepted Transaction will be terminated effective March 1, 1999.
NEPOOL Tariff Attachment G, Item 11
Phase I payments will be made according to the Settlement Agreement, Section G.
This Excepted Transaction will be terminated effective March 1, 1999.
NEPOOL Tariff Attachment G, Item 12
Phase I payments will be made according to the Settlement Agreement, Section G.
This Excepted Transaction will be terminated effective March 1, 1999.
NEPOOL Tariff Attachment G, Item 13
Phase I payments will be made according to the Settlement Agreement, Section G.
This Excepted Transaction will be terminated effective March 1, 1999. As a
clarification, Maine Yankee has been retired and swapped for Vermont Yankee.
Therefore, retroactively, the refunds apply to both Maine and Vermont Yankee and
prospectively the transmission of Vermont Yankee is terminated.
NEPOOL Tariff Attachment G, Item 15
This contract has been terminated and Holyoke is receiving service under NU's
Open Access Tariff.
NEPOOL Tariff Attachment G, Items 17, 19 and 46
These arrangements will continue for the life of the Unit Contract at a rate of
$6.50 per kw-year.
NEPOOL Tariff Attachment G, Item 18
NU, UI and Unitil agree that Item 19, which is a contract for corridor
transmission service between NU and UI (the "NU-UI Agreement") that was entered
into as a settlement of prior disputes, will remain in effect in accordance with
its terms. The parties further agree that the Purchased Power Agreement between
UI and Unitil for power from Bridgeport Harbor Station Unit No. 3 (the
"UI-UNITIL Agreement") shall remain in effect subject to the terms of that
agreement for its full term at the rate stated therein. NU shall pay Unitil an
amount equal to one-third of the transmission charges Unitil pays to reimburse
UI for the costs UI incurs for the transmission of Unitil's power in connection
with the UI-UNITIL agreement for the period between March 1, 1999 and October
31, 2003. From November 1, 2003 to October 31, 2005, NU shall pay Unitil an
amount equal to 100% of the transmission charges Unitil pays UI to reimburse UI
for the costs UI incurs for the transmission of Unitil's power in connection
with the UI-UNITIL Agreement. NU, UI and Unitil agree that the foregoing
arrangements satisfy any claims of double charges under the NU-UI Agreement and
the UI-UNITIL Agreement.
NEPOOL Tariff Attachment G, Item 20
This contract will remain in force according to its terms at a rate of $6.50 per
kw-year.
NEPOOL Tariff Attachment G, Item 21 and 23
The transmission contract between NUSCO and MASSPOWER will remain in effect for
its full term. The MASSPOWER transmission contract (and the contract between
NUSCO and Pittsfield) will remain under the NU System Companies' Tariff No. 9,
subject to the settlement among MASSPOWER, Pittsfield and the NU System
Companies that is currently pending the Commission in Dockets ER93- 545-000 and
ER93-219-000. The parties in those dockets who are also signatories to this
Settlement Agreement will withdraw their opposition to the settlement pending in
those dockets.
NEPOOL Tariff, Attachment G, Items 24 and 25
The parties to these Excepted Transactions, which are contracts for transmission
service by NU over the New York tie, have agreed that these contracts for
transmission service will remain in effect for their full term at a rate of
$6.50 per kw-year.
NEPOOL Tariff Attachment G, Item 32
NU and Reading have agreed that the transmission rate applicable to this
Attachment G contract will be one-half of the current transmission charge paid
by Reading under such contract from March 1, 1999 through the remainder of its
term. This Attachment G contract will remain in effect in accordance with its
current terms. Reading will continue to be billed and pay for service in
accordance with the pre-existing negotiated rates in this Attachment G contract
and such bills will include a line item reflecting the cost of transmission
based on the NU Tariff 9 rate in effect for the applicable billing period.
Monthly adjustments in the transmission portion of the bill will be made
separately by NU's transmission group to account for the difference between the
Tariff 9 rate used for billing purposes and the settlement rate of one-half the
current transmission charge paid by Reading under this contract such that
Reading will pay a net transmission charge of one-half the current transmission
charge paid by Reading under this contract.
NEPOOL Tariff Attachment G, Items 33, 34, 35, 39, 40, 41, 42, 43 and 45
NU and the MMWEC parties have agreed that the transmission rate applicable to
these Attachment G contracts will be $6.50/kw-year from March 1, 1999 through
the remainder of their terms. These Attachment G contracts will remain in effect
in accordance with their current terms. The customers will continue to be billed
and pay for service in accordance with the pre-existing negotiated rates in
those contracts and such bills will include a line item reflecting the cost of
transmission based on the NU Tariff 9 rate in effect for the applicable billing
period. Monthly adjustments in the transmission portion of the bill will be made
separately by NU's transmission group to account for the difference between the
Tariff 9 rate used for billing purposes and the settlement rate of $6.50/kw-year
such that the MMWEC parties will pay a net transmission charge of $6.50/kw-year.
NEPOOL Tariff Attachment G, Item 38
This contract ended by its terms in 1998.
NEPOOL Tariff Attachment G, Items 55 and 56
Montaup, as Transmission Provider, and MASSPOWER and Pittsfield, as Transmission
Customers, and all other Parties agree that these Excepted Transactions shall
not be affected by this Settlement Agreement and shall remain in full force and
effect in accordance with their terms.
NEPOOL Tariff Attachment G, Items 57, 58, 60 and 61
Non-firm wheeling of Cleary 9 power by Montaup to North Attleboro, Hudson Light
& Power and Hingham will continue at 50% of the current contract transmission
rate until February 28, 2001, after which date it will terminate. Non-firm
wheeling of Cleary 9 power by Montaup to Braintree terminated as of February 28,
1999.
NEPOOL Tariff Attachment G, Item 59
Firm wheeling of NYPA power by Montaup for Braintree and Reading will continue
at 50% of the current contract transmission rate until the expiration of the
existing contract. Firm wheeling by Montaup for Hingham, Hull, Wellesley,
Belmont and Concord under the same transaction will continue at 50% of the
current transmission rate until February 28, 2001 after which date it terminates
subject to extension upon agreement of the parties.
NEPOOL Tariff Attachment G, Item 63
Firm wheeling of NYPA power by Montaup for Pascoag Fire District will continue
at 50% of the current transmission rate until February 28, 2001 after which date
it terminates, subject to extension upon agreement of the parties.
NEPOOL Tariff Attachment G, Item 68
From March 1, 1999 to the expiration of the contract, BECO will not bill
Braintree, Reading, Hingham and Hull, and BECO will bill Concord, Wellesley and
Belmont at 50% of the contract rate.
NEPOOL Tariff Attachment G, Item 69
CVPS and Unitil are currently engaged in an arbitration with respect to this
Excepted Transaction. This Settlement Agreement has no impact on arbitration
findings for payments due prior to March 1, 1997. For purposes of this
Settlement Agreement, CVPS and Unitil agree as follows: If Unitil prevails at
the arbitration, Unitil will owe nothing to CVPS. If CVPS prevails, then Unitil
will pay 75% of the amount of the award related to the period March 1, 1997
through February 28, 1999, plus 100% of any interest. The transmission component
of this contract shall be null and void going forward from February 28, 1999.
Unitil shall continue to take and pay for capacity and energy for the term of
the contract, consistent with the existing terms of the agreement. Neither CVPS
nor Unitil shall communicate any aspect of this Settlement Agreement, or side
agreement between them, to the arbitrator prior to the rendering of his
decision.
NEPOOL Tariff Attachment G-1, Items 1 and 2
NEP and NU will terminate items 1 and 2 in Attachment G-1 to the NEPOOL Tariff
and both services will transfer to the respective LNS Tariffs as of April 1,
1999.
NEPOOL Tariff Attachment G-1, Item 10
This contract has been terminated.
ATTACHMENT H
Form of
Network Operating Agreement
1.0 Preamble
This Network Operating Agreement is entered into by and between the NEPOOL
Participants (the "Transmission Provider") acting through (the "System
Operator") and (the "Transmission Customer") as an implementing agreement for
the NEPOOL Open Access Transmission Tariff and is subject to and in accordance
with the NEPOOL Open Access Transmission Tariff. All definitions and other terms
and conditions of the NEPOOL Open Access Transmission Tariff are incorporated
herein by reference. The Transmission Provider may designate a satellite
dispatch center and/or one or more Participants to act for it under this
Agreement.
2.0 General Terms and Conditions
The Transmission Provider agrees to provide transmission service to the
Transmission Customer's equipment or facilities, etc., subject to the
Transmission Customer operating its facilities in accordance with applicable
NEPOOL and NPCC criteria, rules, standards, procedures, or guidelines as they
may be adopted and/or amended from time to time. In addition to the provisions
defined in those documents, service to the Transmission Customer's equipment or
facilities, etc. is provided subject to the following specified terms and
conditions.
2.1 Electrical Supply: The electrical supply to the Point(s) of Delivery
shall be in the form of three-phase sixty-hertz alternating current at a
voltage class determined by mutual agreement of the parties.
2.2 Coordination of Operations: The Transmission Provider shall consult the
Transmission Customer and/or its Designated Agent regarding timing of scheduled
maintenance of the Transmission System and the Transmission Provider shall
schedule any shutdown or withdrawal of facilities to coincide with the
Transmission Customer's equipment or facilities, etc. scheduled outages of the
Transmission Customer's resources, to the extent practicable. In the event the
Transmission Provider is unable to schedule the shutdown of its facilities to
coincide with Transmission Customer's schedule, the Transmission Provider shall
notify the Transmission Customer and/or its Designated Agent, in advance if
feasible, of reasons for the shutdown, the time scheduled for it to take place,
and its expected duration. The Transmission Provider shall use due diligence to
resume delivery of electric power as quickly as possible.
2.3 Reporting Obligations: The Transmission Customer shall be responsible for
all information required by NPCC or NEPOOL. The Transmission Customer shall
respond promptly and completely to the Transmission Provider's reasonable
requests for information, including but not limited to, data necessary for
operations, maintenance, regulatory requirements and analysis. In particular,
that information may include:
For Network Loads:
- - 10-year coincident, seasonal (summer, winter) Annual Peak Load forecast,
aggregated by geographic distribution area
- - Load Power Factor performance by geographic distribution area
- - Underfrequency load shedding capability aggregated by geographic
distribution area
- - Block load shedding capability aggregated by geographic distribution area
- - Disturbance/interruption reports
- - Protection system setting conformance
- - Protection system testing and maintenance conformance
- - Planned changes to protection systems
- - Metering testing and maintenance conformance
- - Planned changes in transformation capability
- - Conformance to harmonic and voltage fluctuation limits
- - Dead station tripping conformance
- - Voltage reduction capability conformance
For Network Resources and interconnected generators:
- - 10-year forecast of generation capacity retirements and additions, if
applicable
- - Generator reactive capability verification
- - Generator underfrequency relaying conformance
- - Protection system testing and maintenance conformance
- - Planned changes to protection system
- - Planned changes to generation parameters
- - Metering testing and maintenance conformance
Failure by the Transmission Customer to do so may constitute default.
Delinquency in responding by the Transmission Customer will result in a fine as
described in 5.0 below.
The Transmission Customer shall supply accurate and reliable information to the
system operators regarding metered values for MW, MVAR, volt, amp, frequency,
breaker status indication, and all other information deemed necessary by the
Transmission Provider for reliable operation. Information shall be gathered for
electronic communication using one or more of the following: supervisory control
and data acquisition (SCADA), remote terminal unit (RTU) equipment, and remote
access pulse recorders (RAPR). All equipment used for metering, SCADA, RTU,
RAPR, and communications must be approved by the Transmission Provider.
2.4 Operational Obligations: The Transmission Customer shall request permission
from the system operators prior to opening and/or closing circuit breakers per
applicable switching and operating procedures. The Transmission Customer shall
carry out all switching orders from the Transmission Provider, the System
Operator or the Transmission Provider's designee in a timely manner.
The Transmission Customer shall balance the load at the Point(s) of Delivery
such that the difference in the individual phase currents are acceptable to the
Transmission Provider.
The Transmission Customer's equipment shall conform with harmonic distortion and
voltage fluctuation standards of the Transmission Provider.
The Transmission Customer's equipment must comply with all environmental
requirements to the extent they impact the operation of the Transmission
Provider's system.
The Transmission Customer shall operate all of its equipment and facilities
connected to the Transmission Provider's system in a safe and efficient manner
and in accordance with manufacturers' recommendations, Good Utility Practice,
applicable regulations, and requirements of the Transmission Provider, the
System Operator, and NPCC.
2.5 Notice of Transmission Service Interruptions: If at any time, in the
reasonable exercise of the system operator's judgement, operation of the
Transmission Customer's equipment adversely affects the quality of service or
interferes with the safe and reliable operation of the system, the Transmission
Provider may discontinue transmission service until the condition has been
corrected. Unless the system operators perceive that an emergency exists or the
risk of one is imminent, the system operators shall give the Transmission
Customer and/or its Designated Agent reasonable notice of its intention to
discontinue transmission service and, where practical, allow suitable time for
the Transmission Customer to remove the interfering condition. The Transmission
Provider's judgement with regard to the discontinuance of service under this
paragraph shall be made in accordance with Good Utility Practice. In the case of
such discontinuance, the Transmission Provider shall immediately confer with the
Transmission Customer regarding the conditions causing such discontinuance and
its recommendation concerning timely correction thereof. Failure by a Customer
to shed load would be subject to an additional charge of 10/kWh for every kWh
the Customer failed to shed.
2.6 Access and Control: Properly accredited representatives of the Transmission
Provider shall at all reasonable times have access to the Transmission
Customer's facilities to make reasonable inspections and obtain information
required in connection with this Tariff. Such representatives shall make
themselves known to the Transmission Customer's personnel, state the object of
their visit, and conduct themselves in a manner that will not interfere with the
construction or operation of the Transmission Customer's facilities. The
Transmission Provider or its designee will have control such that it may open or
close the circuit breaker or disconnect and place safety grounds at the Point(s)
of Delivery, or at the station, if the Point(s) of Delivery is remote from the
station.
2.7 Point(s) of Delivery: Network Integration Transmission Service will be
delivered by the Transmission Provider at the Point(s) of Delivery as specified
in the customer's Service Agreement, and as amended from time to time. Each
Point of Delivery shall have a unique identifier, meter location, meter number,
metered voltage, terms on meter compensation and, the actual, or if not
currently in service, the projected in-service year.
2.8 Maintenance of Equipment: The Transmission Customer shall maintain all of
its equipment and facilities connected to the Transmission Provider's system in
a safe and efficient manner and in accordance with manufacturers'
recommendations, Good Utility Practice, applicable regulations, and requirements
of NEPOOL, and NPCC.
The Transmission Provider may request that the Transmission Customer test,
calibrate, verify or validate the data link, metering, data acquisition,
transmission, protective, or other equipment or software consistent with the
Transmission Customer's routine obligation to maintain its equipment and
facilities or for the purposes of trouble shooting problems on the network
facilities. The Transmission Customer will be responsible for the cost to test,
calibrate, verify or validate the equipment or software.
The Transmission Provider shall have the right to inspect the tests,
calibrations, verifications and validations of the data link, metering, data
acquisition, transmission, protective, or other equipment or other software
connected to the Transmission Provider's system.
The Transmission Customer, at the Transmission Provider's request, shall
supply the Transmission Provider with a copy of the installation, test, and
calibration records of the data link, metering, data acquisition, transmission,
protective or other equipment or software connected to the Transmission
Provider's system.
The Transmission Provider shall have the right, at the Transmission
Customer's expense, to monitor the factory acceptance test, the field acceptance
test, and the installation of any metering, data acquisition, transmission,
protective or other equipment or software connected to the Transmission
Provider's system.
2.9 Emergency System Operations: The Transmission Customer's equipment and
facilities, etc. shall be subject to all applicable emergency operation
standards required of and by the Transmission Provider to operate in an
interconnected transmission network.
The Transmission Provider reserves the right to have the system operators
take whatever actions or inactions they deem necessary during emergency
operating conditions to: (i) preserve the integrity of the Transmission System,
(ii) limit or prevent damage, (iii) expedite restoration of service, or (iv)
preserve public safety.
2.10 Cost Responsibility: The Transmission Customer shall be responsible for all
costs incurred by the Transmission Provider relative to the Transmission
Customer's facilities. Some costs may be allocated to several Transmission
Customers. If the method for allocating costs is not clearly defined, then the
method for allocation will be at the Transmission Provider's discretion.
3.0 Service For a Network Resource
The following Terms and Conditions are specific to Service for a generator
Network Resource.
3.1 Voltage or Reactive Control Requirements: Unless directed otherwise, the
Transmission Customer will operate its existing interconnected generation
facility(ies) with an automatic voltage regulator(s). The voltage regulator will
control voltage at the Point(s) of Receipt consistent with the range of voltage
scheduled by the System Operator.
At the discretion of the Transmission Provider, the Transmission Customer
may be directed to deactivate the automatic voltage regulator and to supply
reactive power per a schedule provided by the Transmission Provider.
If the Transmission Customer has not installed capacity sufficient to
operate its generation facility consistent with recommendations of the
Transmission Provider resulting from the System Impact and Facilities Studies or
fails to operate at such capacity, the Transmission Provider may install, at the
Transmission Customer's expense, reactive compensation equipment necessary to
ensure the proper voltage or reactive supply at the Point(s) of Receipt.
3.2 Station Service: When the Transmission Customer's generation facility is
producing electricity, the Customer must supply its own station service power.
If and when the Transmission Customer's generation facility is not producing
electricity, the Customer must obtain station service capacity and energy from
another supplier or another of its resources.
3.3 Protection Requirements: Protection requirements are defined in NEPOOL
and NPCC documents as may be adopted or amended from time to time.
3.4 Operational Obligations: The Transmission Provider may require the
generator to be equipped for Automatic Generation Control (AGC). The
Transmission Customer will be responsible for all costs associated with
installing and maintaining an AGC system on the generator(s).
The Transmission Provider retains the right to require reduced generation
at times when system conditions present transmission restrictions or otherwise
adversely affect the Transmission Provider's other customers. The Transmission
Provider will use due diligence to resolve the problems to allow the generator
to return to the operating level prior to the Transmission Provider's notice to
reduce generation.
All operations (including start-up, shutdown and determination of hourly
generation) will be coordinated by the Transmission Provider.
3.5 Coordination of Operations: The Transmission Customer shall furnish the
Transmission Provider with generator annual maintenance schedules, advise the
Transmission Provider if its Network Resource is capable of participation in
system restoration and/or if it has black start capability.
The Transmission Provider reserves the right to specify turbine and/or
generator control (e.g., droop) settings as determined by the System Impact or
Facilities Study or subsequent studies. The Transmission Customer agrees to
comply with such specifications by the Transmission Provider at the Transmission
Customer's expense.
If the generator is not dispatchable by the Transmission Provider, the
Transmission Customer shall notify the Transmission Provider at least 48 hours
in advance of its intent to take its resource temporarily off-line and its
intent to resume generation. In circumstances such as forced outages, the
Transmission Customer shall notify the Transmission Provider as promptly as
possible of the Network Resource's temporary interruption of generation and/or
transmission.
4.0 Service for Delivery to Load
The following Terms and Conditions are specific to Service for Delivery to Load.
4.1 Power Factor Requirement: The Transmission Customer agrees to maintain an
overall Load Power Factor and reactive power supply within predefined sub-areas
as measured at the Point(s) of Delivery within ranges specified by the
Transmission Provider or NEPOOL criteria, rules and standards which identify the
power factor levels that must be maintained throughout the applicable sub-area
for each anticipated level of total NEPOOL load. The Transmission Customer
agrees to maintain Load Power Factor and reactive power requirements within the
range specified by the Transmission Provider for the sub-area based on total
NEPOOL load during that hour. NEPOOL may revise the power factor limits required
from time to time. If the Transmission Customer lacks the capability to maintain
the Load Power Factor within the ranges specified, the Transmission Provider
may:
a) install, at the Transmission Customer's expense, reactive compensation
equipment necessary to ensure proper load power factor at the Point(s) of
Delivery;
b) charge the Transmission Customer per the Tariff.
4.2 Protection Requirements: The Transmission Customer's relay and protection
systems must comply with all applicable NEPOOL and NPCC criteria, rules,
procedures, guidelines, standards or requirements as may be adopted or amended
from time to time.
4.3 Operational Obligations: The Transmission Customer shall be responsible for
operating and maintaining security of its electric system in a manner that
avoids adverse impact to the Transmission Provider's or others' interconnected
systems and complies with all applicable NEPOOL, and NPCC operating criteria,
rules, procedures, guidelines and interconnection standards as may be amended or
adopted from time to time. These actions include, but are not limited to:
- - Voltage Reduction Load Shedding
- - Underfrequency Load Shedding
- - Block Load Shedding
- - Dead Station Tripping
- - Transferring Load Between Point(s) of Delivery
- - Implementing Voluntary Load Reductions Including Interruptible Customers
- - Starting Stand-by Generation
- - Permitting Transmission Provider Controlled Service Restoration Following
Supply Delivery Contingencies on Transmission Provider Facilities
5.0 Default
If the Transmission Customer's equipment fails to perform consistent with the
Terms and Conditions of this agreement, then the Transmission Customer will be
deemed to be in default and service may be suspended immediately and subject to
a termination through a FERC filing. If the Transmission Customer fails to
provide the information required in Section 2.3 in a timely manner, the
Transmission Provider shall be permitted to assess a penalty of $100 per day
until such information is provided in its entirety to the Transmission Provider.
The Parties whose authorizing signatures appear below warrant that they will
abide by the foregoing terms and conditions.
NEPOOL Participants
By (System Operator)
(Transmission Customers)
By:
By:
Title:
Title:
Date:
Date:
ATTACHMENT I
Form of
System Impact Study Agreement
This Agreement dated , is entered into by (the "Transmission Customer") and the
NEPOOL Participants (the "Transmission Provider") acting through (the "System
Operator"), for the purpose of setting forth the terms, conditions and costs for
conducting a System Impact Study relative to ,in accordance with the NEPOOL Open
Access Transmission Tariff ("Tariff"). All definitions and other terms and
conditions of that Tariff are incorporated herein by reference. The Transmission
Provider may designate one or more Participants or the System Operator to act
for it under this Agreement.
1. The Transmission Customer agrees to provide, in a timely and complete manner,
the information and technical data specified in Exhibit 1 to this Agreement and
reasonably necessary for the Transmission Provider to conduct the System Impact
study. The Transmission Customer understands that it must provide all such
information and data prior to the Transmission Provider's commencement of the
Study. Such information and technical data is specified in Exhibit 1 to this
Agreement.
2. All work pertaining to the System Impact Study that is the subject of this
Agreement will be approved and coordinated only through designated and
authorized representatives of the Transmission Provider and the Transmission
Customer. Each party shall inform the other in writing of its designated and
authorized representative.
3. The Transmission Provider will advise the Transmission Customer of any
additional information as it may in its sole reasonable discretion deem
necessary to complete the study. Any such additional information shall be
obtained only if required by Good Utility Practice and shall be subject to the
Transmission Customer's consent to proceed, such consent not to be unreasonably
withheld.
4. The Transmission Provider contemplates that it will require to complete the
System Impact Study. Upon completion of the Study by the Transmission Provider,
the Transmission Provider will provide a report to the Transmission Customer
based on the information provided and developed as a result of this effort. If,
upon review of the Study results, the Transmission Customer decides to pursue ,
the Transmission Provider will, at the Transmission Customer's direction, tender
a Facilities Study Agreement within thirty (30) days. The System Impact and
Facilities Studies, together with any additional studies contemplated in
Paragraph 3, shall form the basis for the Transmission Customer's proposed use
of the Transmission Provider's transmission system and shall be furthermore
utilized in obtaining necessary third-party approvals of any interconnection
facilities and requested transmission services. The Transmission Customer
understands and acknowledges that any use of study results by the Transmission
Customer or its agents, whether in preliminary or final form, prior to NEPOOL
l8.4 approval, is completely at the Transmission Customer's risk and that the
Transmission Provider will not guarantee or warrant the completeness, validity
or utility of study results prior to NEPOOL 18.4 approval.
5. The estimated costs contained within this Agreement are the Transmission
Provider's good faith estimate of its costs to perform the System Impact Study
contemplated by this Agreement. The Transmission Provider's estimates do not
include any estimates for wheeling charges that may be associated with the
transmission of facility output to third parties or with rates for station
service. The actual costs charged to the Transmission Customer by the
Transmission Provider may change as set forth in this Agreement. Prepayment will
be required for all study, analysis, and review work performed by the
Transmission Provider or its Designated Agent, all of which will be billed by
the Transmission provider to the Transmission Customer in accordance with
Paragraph 6 of this Agreement.
6. The payment required is $ from the Transmission Customer to the Transmission
Provider for the primary system analysis, coordination, and monitoring of the
System Impact Study. The Transmission Provider will, in writing, advise the
Transmission Customer in advance of any cost increases for work to be performed
if total amount increases by 10% or more. Any such changes to the Transmission
Provider's costs for the study work shall be subject to the Transmission
Customer's consent, such consent not to be unreasonably withheld. The
Transmission Customer shall, within thirty (30) days of the Transmission
Provider's notice of increase, either authorize such increases and make payment
in the amount set forth in such notice, or the Transmission Provider will
suspend the System Impact Study and this Agreement will terminate if so
permitted by the Federal Energy Regulatory Commission. In the event this
Agreement is terminated for any reason, the Transmission Provider shall refund
to the Transmission Customer the portion of the above credit or any subsequent
payment to the Transmission Provider by the Transmission Customer that the
Transmission provider did not expend in performing its obligations under this
Agreement. Any additional billings under this Agreement shall be subject to an
interest charge computed in accordance with the provisions of the Tariff.
Payments for work performed shall not be subject to refunding except in
accordance with Paragraph 7 below.
7. If the actual costs for the work exceed prepaid estimated costs, the
Transmission Customer shall make payment to the Transmission Provider for such
actual costs within thirty (30) days of the date of the Transmission Provider's
invoice for such costs. If the actual costs for the work are less than those
prepaid, the Transmission Provider will credit such difference toward
Transmission Provider costs unbilled, or in the event there will be no
additional billed expenses, the amount of the overpayment will be returned to
the Transmission Customer with interest computed as stated in Paragraph 6 of
this Agreement, from the date of reconciliation.
8. Nothing in this Agreement shall be interpreted to give the Transmission
Customer immediate rights to wheel over or interconnect with the Transmission
Provider's transmission or distribution system. Such rights shall be provided
for under separate agreement and in accordance with the Transmission Provider's
open access tariff.
9. Within one (1) year following the Transmission Provider's issuance of a final
bill under this Agreement, the Transmission Customer shall have the right to
audit the Transmission Provider's accounts and records at the offices where such
accounts and records are maintained, during normal business hours; provided that
appropriate notice shall have been given prior to any audit and provided that
the audit shall be limited to those portions of such accounts and records that
relate to service under this Agreement. The Transmission Provider reserves the
right to assess a reasonable fee to compensate for the use of its personnel time
in assisting any inspection or audit of its books, records or accounts by the
Transmission Customer or its Designated Agent.
10. Each party agrees to indemnify and hold the other party and its Related
Persons of each of them (collectively "Affiliates") harmless from and against
any and all damages, costs (including attorney's fees), fines, penalties and
liabilities, in tort, contract, or otherwise (collectively "Liabilities")
resulting from claims of third parties arising, or claimed to have arisen as a
result of any acts or omissions of either party under this Agreement. Each party
hereby waives recourse against the other party and its Related Persons for, and
releases the other party and its Related Persons from, any and all Liabilities
for or arising from damage to its property due to a performance under this
Agreement by such other party except in cases of negligence or intentional
wrongdoing by either party.
11. If either party materially breaches any of its covenants hereunder, the
other party may terminate this Agreement by filing a notice of intent to
terminate with the Federal Energy Regulatory Commission and serving notice of
same on the other party to this Agreement. This remedy is in addition to any
other remedies available to the injured party.
12. This Agreement shall be construed and governed in accordance with the
laws of the State of Connecticut and with Part II of the Federal Power Act, 16
U.S.C. 824d et seq., and with Part 35 of Title 18 of the Code of Federal
Regulations, 18 C.F.R. 35 et seq.
13. All amendments to this Agreement shall be in written form executed by
both parties.
14. The terms and conditions of this Agreement shall be binding on the
successors and assigns of either party.
15. This Agreement will remain in effect for a period of up to two years from
its effective date as permitted by the Federal Energy Regulatory Commission, and
is subject to extension by mutual agreement. Either party may terminate this
Agreement by thirty (30) days' notice except as is otherwise provided herein. If
this Agreement expires by its own terms, it shall be the Transmission Provider's
responsibility to make such filing. Transmission Customer:
Name:
Title:
Date:
NEPOOL Participants
By (System Operator)
Name:
Title:
Date:
EXHIBIT 1
Information to be Provided to the Transmission Provider
by the Transmission Customer for System Impact Study
1.0 Facilities Identification
1.1 Requested capability in MW and MVA; summer and winter
1.2 Site location and plot plan with clear geographical references
1.3 Preliminary one-line diagram showing major equipment and extent of
Transmission Customer ownership
1.4 Auxiliary power system requirements
1.5 Back-up facilities such as standby generation or alternate supply
sources
2.0 Major Equipment
2.1 Power transformer(s): rated voltage, MVA and BIL of each winding, LTC and or
NLTC taps and range, Z1 (positive sequence) and Zo (zero sequence) impedances,
and winding connections. Provide normal, long-time emergency and short-time
emergency thermal ratings.
2.2 Generator(s): rated MVA, speed and maximum and minimum MW output, reactive
capability curves, open circuit saturation curve, power factor (V) curve,
response (ramp) rates, H (inertia), D (speed damping), short circuit ratio, X1
(leakage), X2:(negative sequence), and Xo (zero sequence) reactances and other
data:
Direct Quadrature
Axis Axis
Saturated synchronous reactance Xdv Xqv
unsaturated synchronous reactance Xdi Xqt
saturated transient reactance X'dv X'qv
unsaturated transient reactance X'di X'qi
saturated subtransient reactance X"dv X"qv
unsaturated subtransient reactance X"di X"qi
transient open-circuit time constant T'do T'qo
transient short-circuit time constant T"d T"q
subtransient open-circuit time constant T"do T"qo
subtransient short-circuit time constant T"d T"q
2.3 Excitation system, power system stabilizer and governor: manufacturer's
data in sufficient detail to allow modeling in transient stability simulations.
2.4 Prime mover: manufacturer's data in sufficient detail to allow modeling
in transient stability simulations, if determined necessary.
2.5 Busses: rated voltage and ampacity (normal, long-time emergency and
short-time emergency thermal ratings), conductor type and configuration.
2.6 Transmission lines: overhead line or underground cable rated voltage and
ampacity (normal, long-time emergency and short-time emergency thermal ratings),
Z1 (positive sequence) and Zo (zero sequence) impedances, conductor type,
configuration, length and termination points.
2.7 Motors greater than 150 kW 3-phase or 50 kW single-phase: type (induction or
synchronous), rated hp, speed, voltage and current, efficiency and power factor
at 1/2, 3/4 and full load, stator resistance and reactance, rotor resistance and
reactance, magnetizing reactance.
2.8 Circuit breakers and switches: rated voltage, interrupting time and
continuous, interrupting and momentary currents. Provide normal, long-time
emergency and short-time emergency thermal ratings.
2.9 Protective relays and systems: ANSI function number, quantity manufacturer's
catalog number, range, descriptive bulletin, tripping diagram and three-line
diagram showing AC connections to all relaying and metering.
2.10 CT's and VT's: location, quantity, rated voltage, current and ratio.
2.11 Surge protective devices: location, quantity, rated voltage and energy
capability.
3.0 Other
3.1 Additional data reasonably necessary to perform the System Impact Study will
be provided by the Transmission Customer as requested by the Transmission
Provider.
3.2 The Transmission Provider reserves the right to require that the
Transmission Customer accept the use in the study of specific equipment settings
or characteristics necessary to meet NEPOOL and NPCC criteria and standards.
ATTACHMENT J
Form of
Facilities Study Agreement
This agreement dated , is entered into by (the Transmission Customer) and the
NEPOOL Participants (the "Transmission Operator") acting through the ("System
Provider"), for the purpose of setting forth the terms, conditions and costs for
conducting a Facilities Study relative to , in accordance with the NEPOOL Open
Access Transmission Tariff ("Tariff"). All definitions and other terms and
conditions of that Tariff are incorporated herein by reference. The Transmission
Provider may designate one or more Participants or the System Operator to act
for it under this Agreement. The Facilities Study will determine the detailed
engineering, design and cost of the facilities necessary to satisfy the
Transmission Customer's request for service over the NEPOOL Transmission System.
1. The Transmission customer agrees to provide, in a timely complete manner,
the information and technical data specified in Exhibit 1 to this Agreement and
reasonably necessary for the Transmission Provider to conduct the
Facilities Study. Where such information and technical data was provided for the
System Impact Study, it should be reviewed and updated with current information,
as required.
2. All work pertaining to the Facilities Study that is the subject of this
Agreement will be approved and coordinated only through designated and
authorized representatives of the Transmission Provider and the Transmission
Customer. Each party shall inform the other in writing of its designated and
authorized representative.
3. The Transmission Provider will advise the Transmission Customer of additional
information as may be reasonably deemed necessary to complete the study by the
Transmission Provider. Any such additional information shall be obtained only if
required by Good Utility Practice and shall be subject to the Transmission
Customer's consent to proceed, such consent not to be unreasonably withheld.
4. The Transmission Provider contemplates that it will require ____ days to
complete the Facilities Study. Upon completion of the study by the Transmission
Provider, the Transmission Provider will provide a report to the Transmission
Customer based on the information provided and developed as a result of this
effort. If, upon review of the study results, the Transmission Customer decides
to pursue its transmission service request, the Transmission Customer must sign
a supplemental Service Agreement with the Transmission Provider under the
Tariff. The System Impact and Facilities Studies, together with any additional
studies contemplated in Paragraph 3, shall form the basis for the Transmission
Customer's proposed use of the Transmission Provider's Transmission System and
shall be furthermore utilized in obtaining necessary third-party approvals of
any facilities and requested transmission services. The Transmission Customer
understands and acknowledges that any use of the study results by the
Transmission Customer or its agents whether in preliminary or final form, prior
to approval under Section 18.4 of the Restated NEPOOL Agreement, is completely
at the Transmission Customer's risk and that the Transmission Provider will not
guarantee or warrant the completeness, validity or utility of the study results
prior to NEPOOL 18.4 approval.
5. The estimated costs contained within this Agreement are the Transmission
Provider's good faith estimate of its costs to perform the Facilities Study
contemplated by this Agreement. The Transmission Provider's estimates do not
include any estimates for wheeling charges that may be associated with the
transmission of facility output to third parties or with rates for station
service. The actual costs charged to the Transmission Customer by the
Transmission Provider may change as set forth in this Agreement. Prepayment will
be required for all study, analysis, and review work performed by the
Transmission Provider's or its Designated Agent's personnel, all of which will
be billed by the Transmission Provider to the Transmission Customer in
accordance with Paragraph 6 of this Agreement.
6. The payment required is $ from the Transmission Customer to the Transmission
Provider for the primary system analysis, coordination, and monitoring of the
Facilities Study to be performed by the Transmission Provider for the
Transmission Customer's requested service. The Transmission Provider will, in
writing, advise the Transmission Customer in advance of any cost increases for
work to be performed if the total amount increases by 10% or more. Any such
changes to the Transmission Provider's costs for the study work to be performed
shall be subject to the Transmission Customer's consent, such consent not to be
unreasonably withheld. The Transmission Customer shall, within thirty (30) days
of the Transmission Provider's notice of increase, either authorize such
increases and make payment in the amount set forth in such notice, or the
Transmission Provider will suspend the study and this Agreement will terminate
if so permitted by the Federal Energy Regulatory Commission.
In the event this Agreement is terminated for any reason, the Transmission
Provider shall refund to the Transmission Customer the portion of the above
credit or any subsequent payment to the Transmission Provider by the
Transmission Customer that the Transmission Provider did not expend in
performing its obligations under this Agreement. Any additional billings under
this Agreement shall be subject to an interest charge computed in accordance
with the provisions of the Tariff. Payments for work performed shall not be
subject to refunding except in accordance with Paragraph 7 below.
7. If the actual costs for the work exceed prepaid estimated costs, the
Transmission Customer shall make payment to the Transmission Provider for such
actual costs within thirty (30) days of the date of the Transmission Provider's
invoice for such costs. If the actual costs for the work are less than that
prepaid, the Transmission Provider will credit such difference toward
Transmission Provider's costs unbilled, or in the event there will be no
additional billed expenses, the amount of the overpayment will be returned to
the Transmission Customer with interest computed in accordance with the
provisions of the Tariff.
8. Nothing in this Agreement shall be interpreted to give the Transmission
Customer immediate rights to interconnect to or wheel over the NEPOOL
Transmission System. Such rights shall be provided for under separate agreement.
9. Within one (1) year following the Transmission Provider's issuance of a final
bill under this Agreement, the Transmission Customer shall have the right to
audit the Transmission Provider's accounts and records at the offices where such
accounts and records are maintained during normal business hours; provided that
appropriate notice shall have been given prior to any audit and provided that
the audit shall be limited to those portions of such accounts and records that
relate to service under this Agreement. The Transmission Provider reserves the
right to assess a reasonable fee to compensate for the use of its personnel time
in assisting any inspection or audit of its books, records or accounts by the
Transmission Customer or its Designated Agent.
10. Each party agrees to indemnify and hold the other party and its Related
Persons harmless from and against any and all damages, costs (including
attorney's fees), fines, penalties and liabilities, in tort, contract, or
otherwise (collectively "Liabilities") resulting from claims of third parties
arising, or claimed to have arisen as a result of any acts or
omissions of either party under this Agreement. Each party hereby waives
recourse against the other party and its Related Persons for, and releases the
other party and its Related Persons from, any and all Liabilities for or arising
from damage to its property due to performance under this Agreement by such
other party except in cases of negligence or intentional wrongdoing by either
party.
11. If any party materially breaches any of its covenants hereunder, the other
party may terminate this Agreement by filing a notice of intent to terminate
with the Federal Energy Regulatory Commission and serving notice of same on the
other party to this Agreement. This remedy is in addition to any other remedies
available for the injured party.
12. This agreement shall be construed and governed in accordance with the laws
of the State of Connecticut and with Part II of the Federal Power Act, 16 U.S.C.
Sections 824d et seq., and with Part 35 of Title 18 of the Code of Federal
Regulations, 18 C.F.R. Sections 35 et seq.
13. All amendments to this Agreement shall be in written form executed by
both parties.
14. The terms and conditions of this Agreement shall be binding on the
successors and assigns of either party.
15. This Agreement will remain in effect for a period of two years from its
effective date as permitted by the Federal Energy Regulatory Commission, and is
subject to extension by mutual agreement.
Either party may terminate this Agreement by thirty (30) days' notice
except as is otherwise provided herein. If this Agreement expires by its own
terms, it shall be the Transmission Provider's responsibility to make such
filing.
Transmission Customer:
Name:
Title:
Date:
NEPOOL Participants
By (System Operator)
Name:
Title:
Date:
ATTACHMENT K
1997 Twelve CP Network Load Data
NEPOOL 1997 12 CP Network Load
NEPOOL 1997 12CP Network Loads
NEPOOL
Local Networks - 1997 1997 12CP
Network Load (MW)
Boston Edison Co. 3,023.024
Bangor Hydro Electric 255.589
Commonwealth Energy Systems 601.023
Central Maine Power 1,464.781
Eastern Utilities Associates 885.357
New England Electric System 3,957.775
Northeast Utilities 6,332.724
United Illuminating 677.367
Vermont Electric Light Co. 796.881
TOTAL 17,994.521
Boston Edison Company
Network Load Customer 1997 12CP
Network
Load (MW)
Boston Edison Co.** 2,383.727
Braintree 58.395
Cambridge*** 216.966
Concord (PASNY) 1.690
Hingham 25.083
Hull 6.139
MBTA 7.283
Norwood (NYPA) 2.635
Norwood (NEP Tariff 1) 48.448
Quincy/Weymouth (Retail Wheeling-MECO) 0.000
Quincy/Weymouth (NEP Tariff 1) 185.693
Reading 82.333
Wellseley (PASNY) 2.335
Belmont (PASNY) 2.297
Total 3,023.024
Bangor Hydro Electric Company
Network Load Customer 1997 12CP
Network
Load (NW)
Bangor Hydro Electric 255.589
Total 255.589
Commonwealth Electric Company
Network Load Customer 1997 12CP
Network
Loan (MW)
Commonwealth Electric Company 585.283
Nantucket (NEP Tariff 1) 15.740
Nantucket (Retail Wheeling) 0.000
Total 601.023
Central Maine Power
Network Load Customer 1997 12CP
Network
Loan (MW)
Central Maine Power 1,407.939
Fox Island 1.491
Kennebunk 15.024
Madison 40.327
Total 1,464.781
Eastern Utilities Associates
Network Load Customer 1997 12CP
Network
Loan (MW)
Eastern Utilities Associates** 756.175
Middleborough 22.967
Pascoag, RI 1.592
Taunton 90.940
Tiverton (Retail Wheeling - NECO) 0.000
Tiverton (NEP Tariff 1) 13.683
Total 885.357
New England Power
Network Load Customer 1997 12CP
Network
Loan (MW)
New England Power** 3,287.945
Granite State Electric (Retail Wheeling) 2.307
Massachusetts Electric (Retail Wheeling) 43.397
Narragansett Electric (Retail Wheeling) 2.750
Ashburnham 4.540
Boylston 3.930
Central Vermont Public Service 8.234
Danvers 52.435
Fitchburg Gas & Electric 72.331
French King 11.341
Georgetown 6.805
Green Mountain Power (Except Stamford) 59.480
Groton, MA 8.281
Groveland (NYPA Load) 0.510
Holden 15.199
Hudson 47.500
Ispwich 14.670
Littleton, MA 26.751
Mansfield 31.725
MBTA 5.851
Marblehead 17.121
Massachusetts Governors Land Bank 2.127
Merrimac (NYPA) 0.525
Middleton 14.928
N. Attleboro 36.158
Paxton 3.069
Network Load Customer 1997 12CP
Network
Loan (MW)
Peabody 73.540
Princeton 2.388
Rowley 5.305
Shrewsbury 43.113
Sterling 6.673
Templeton 8.902
Wakefield 28.317
W. Boylston 9.627
Total 3,957.775
Northeast Utilities
Network Load Customer 1997 12CP
Network
Loan (MW)
Northeast Utilities** 5,377.920
Bolt Hill 34.630
Chicopee 64.539
Conn. Municipal Electric Energy Co-op 268.199
Holyoke Gas & Electric 48.541
SBNG (Retail Wheeling - MECO)*** 0.000
SBNG (NEP Tariff 1)*** 84.184
S. Hadley 21.182
The Six United Illuminating Substations 218.535
UNITIL 164.297
Westfield 50.697
Total 6,332.724
United Illuminating Company
Network Load Customer 1997 12CP
Network
Loan (MW)
United Illuminating 677.367
Total 677.367
Vermont Electric Power Co.
Network Load Customer 1997 12CP
Network
Loan (MW)
Vermont Electric Light Co. 796.881
Total 796.881
Total of all Transmission Providers 12CP = 17,994.521
ATTACHMENT L
Financial Assurance Policy for NEPOOL Members
This Financial Assurance Policy for NEPOOL Members ("Policy") shall become
effective January 1, 1999 (the "Policy Effective Date"). (FN1)
The purpose of this Policy is (i) to establish a financial assurance policy for
NEPOOL members ("Participants") that includes commercially reasonable credit
review procedures to assess the financial ability of an applicant for membership
in NEPOOL ("Applicant") or of a Participant to pay for service transactions
under the Restated NEPOOL Agreement and the NEPOOL Open Access Transmission
Tariff (the "Tariff") and to pay its share of NEPOOL expenses, including amounts
owed to the ISO under its tariff, (ii) to set forth requirements for alternative
forms of security that will be deemed acceptable to NEPOOL and consistent with
commercial practices established by the Uniform Commercial Code that protects
the Participants against the risk of non- payment by other, defaulting
Participants, (iii) to set forth the conditions under which NEPOOL will conduct
business so as to avoid the possibility of failure of payment for services
rendered under the Tariff or the Restated NEPOOL Agreement, and (iv) to collect
amounts past due, collect amounts payable upon billing adjustments, make up
shortfalls in payments, and terminate membership of defaulting Participants.
In accordance with Sections 3.5 and 7.5 of the Restated NEPOOL Agreement, NEPOOL
requires the following procedures and requirements to apply to all Applicants
and Participants. Generally, any Applicant or Participant that does not have an
investment grade rating by either Standard & Poor's, Moody's, Duff & Phelps, or
Fitch (or in the case of Applicants or Participants that are not rated
themselves, any Applicant or Participant that does not have outstanding debt
with such a rating) will be required to provide financial assurances, as
described in detail below.
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(FN1) Capitalized terms used but not defined in this Policy are intended to have
the meanings given to such terms in Section 1 of the Restated NEPOOL Agreement
or Section 1 of the Restated NEPOOL Open Access Transmission Tariff (the
"Tariff"), as amended.
GENERAL REQUIREMENTS
Each Applicant or Participant must comply with the following general
requirements. In the case of a group of members that are treated as a single
Participant pursuant to Section 4.1 of the Restated NEPOOL Agreement, the group
members shall be deemed to have elected to be jointly and severally liable for
all debts to NEPOOL of any of the group members unless (i) charges of an
individual member can be tracked and allocated to the member incurring such
charges by the System Operator (FN1) utilizing all information available to the
System Operator determined by it to be reliable, including information from
Participants or from a single Participant's representative, (ii) an alternate
form of financial assurance is provided as set forth below, (iii) the group
members agree to allocate amongst themselves responsibility for payment of group
member charges on a percentage basis in a manner acceptable to NEPOOL, with
additional financial assurance to be provided by those members, if any, that do
not satisfy the minimum corporate debt rating, or (iv) the group members when
evaluated as a whole (at their expense by one of the above rating agencies)
satisfy the minimum corporate debt rating requirement set forth above and, in
addition, provide a corporate guaranty from a parent or other responsible
affiliate, which parent or affiliate satisfies the minimum corporate debt
rating. For the fourth type of consolidated Participant, NEPOOL will conduct a
financial assurances review based on the credit rating of only the rated members
of the group.
For the purposes of these financial assurance provisions, the term "Participant"
shall, in the case of a group of members that are treated as a single
Participant pursuant to Section 4.1 of the Restated NEPOOL Agreement, be deemed
to refer to the group of members as a whole unless the group members have
affirmatively indicated to NEPOOL, and NEPOOL has agreed, that they are to be
treated pursuant to options (i) or (iii) above, in which case the term
"Participant" shall be deemed to refer to each individual group member and not
to the aggregate of such group; and the terms "charges" and fees" shall,
likewise, be deemed to refer to the charges and fees allocable to the individual
group member as opposed to the aggregate of such group.
- --------
(FN1) The System Operator will act as NEPOOL's agent in managing and enforcing
this Policy with the exception of termination of membership issues, which are
specifically reserved to the NEPOOL Participants and will be addressed by the
NEPOOL Executive Committee Membership Subcommittee, subject to appeal to the
Management Committee. Accordingly, all financial information required pursuant
to this Policy is to be provided to the System Operator, which will keep all
such information confidential in accordance with the provisions of Section 2 of
NEPOOL Criteria, Rules and Standards No. 45.
Proof of Financial Viability
Each Applicant must with its application submit proof of financial viability, as
described below, satisfying NEPOOL requirements to demonstrate the Applicant's
ability to meet its obligations, or must provide prior to its membership
becoming effective financial assurance in the form of a cash deposit, letter of
credit or performance bond as set forth below. An Applicant that chooses to
provide a cash deposit, letter of credit or performance bond will not be
required to provide financial information to NEPOOL.
Generally, each Applicant must submit a current rating agency report, which
report must indicate an investment grade rating by either Standard & Poor's,
Moody's, Duff & Phelps, or Fitch for the Applicant or, if the Applicant itself
is not rated, for the Applicant's outstanding rated debt, in order for the
Applicant to be considered as a candidate for NEPOOL membership without
furnishing additional financial assurances as described below.
Current Participants must also provide a current rating agency report by the
Policy Effective Date, as well as any of the financial statements and
information set forth below if and as requested by NEPOOL within ten (10) days
of such request. Those Participants that do not satisfy the rating requirement
as set forth above must provide instead on the Policy Effective Date one form of
the financial assurances set forth below. A Participant's failure to meet these
requirements may result in termination proceedings by NEPOOL.
Financial Statements
Each Applicant must submit, if and as requested by NEPOOL and within ten (10)
days of such request, audited financial statements for at least the immediately
preceding three years, or the period of its existence, if shorter, including,
but not limited to, the following information:
Balance Sheets
Income Statements
Statements of Cash Flows
Notes to Financial Statements
Additionally, the following information for at least the immediately preceding
three years, if available, must be submitted if and as requested by NEPOOL and
within ten (10) days of such request:
Annual and Quarterly Reports
10-K, 10-Q and 8-K Reports
Where the above financial statements are available on the Internet, the
Applicant may provide instead a letter to NEPOOL stating where such statements
may be located and retrieved by NEPOOL.
Each Applicant may also be required to provide at least one bank reference and
three (3) Utility credit references. In those cases where an Applicant does not
have three (3) Utility credit references, three (3) trade payable vendor
references may be substituted.
Each Applicant may also be required to include information as to any known or
anticipated material lawsuits, as well as any prior bankruptcy declarations by
the Applicant, or by its predecessor(s), if any.
In the case of certain Applicants, some of the above financial submittals may
not be applicable, and alternate requirements may be specified by NEPOOL.
Ongoing Financial Review
Each Participant that has not provided a cash deposit, letter of credit,
performance bond, or corporate guaranty must submit its current rating agency
report promptly upon the request of NEPOOL, and 8-K Reports promptly upon their
issuance.
In addition, each Participant is responsible for informing NEPOOL in writing
within ten (10) business days of any material change in its financial status. A
material change in financial status includes, but is not limited to, the
following: a downgrade to a below investment grade rating of senior long term
debt by a major rating agency, being placed on credit watch with negative
implication by a major rating agency if senior long term debt does not have an
investment grade rating, a bankruptcy filing, insolvency, a report of a
significant quarterly loss or decline of earnings, the resignation of key
officer(s), and/or the filing of a material lawsuit that could materially
adversely impact current or future financial results. A Participant's failure to
provide this information may result in termination proceedings by NEPOOL.
If there is a material adverse change in the financial condition of the
Participant, NEPOOL may require the Participant to provide one of the forms of
other financial assurances set forth below. If the Participant fails to do so,
NEPOOL may initiate termination proceedings in accordance with the procedure set
forth in Section 21.2(d) of the Restated NEPOOL Agreement.
OTHER FINANCIAL ASSURANCES
Applicants or Participants that do not satisfy the rating requirement or
NEPOOL's credit review process must submit instead one of the following
additional financial assurances, depending on the type of transactions they
anticipate engaging in as Participants. Each financial assurance for monthly
charges, unless replaced in accordance with the terms hereof or no longer
required pursuant to the terms hereof, shall remain in effect for one hundred
twenty days after termination of the Participant's membership, provided, however
that financial assurances required by this Financial Assurance Policy related to
potential billing adjustments chargeable to a terminated Participant shall
remain in effect until such billing adjustment request is finally resolved in
accordance with the provisions of the NEPOOL Billing Policy.
In general, Participants must provide additional financial assurance in the
following amounts, based on their average or expected monthly charges for
interchange and transmission service under the Tariff (which would include
charges for Regional Network Service or Through or Out Service) and the Restated
NEPOOL Agreement (which would include energy and other services received through
NEPOOL) and NEPOOL expenses for services, including amounts owed to ISO New
England Inc. under its tariff (collectively the "NEPOOL Charges"):
Monthly NEPOOL Charges Financial Assurance Requirement
$0 - $15,000 0 months' NEPOOL Charges
$15,001 - $30,000 1 month's NEPOOL Charges
$30,001 - $50,000 2 months' NEPOOL Charges
$50,001 or more 3 1/2 months' NEPOOL Charges
The three and one-half months is based on the time required for a FERC filing
made by NEPOOL to suspend service to be effective.
Therefore, a Participant with $32,000 in monthly NEPOOL Charges that does not
satisfy the rating requirement or NEPOOL credit review process must provide
additional financial assurances in the amount of $64,000 to NEPOOL.
In the case of new Participants, the additional financial assurance requirement
will be based on estimated monthly NEPOOL Charges, which estimate NEPOOL has the
right to adjust in light of subsequent experience as to actual monthly NEPOOL
Charges.
Furthermore and without limiting the generality of the foregoing, if a
Participant that has received from one or more other Participants or Non-
Participant Transmission Customers an amount the payment of which is the subject
of a dispute, an amount equal to 100% of such amount in dispute shall be
included in determining that Participant's overall financial assurance
requirement. Any additional financial assurance provided under this paragraph
shall not be terminated or returned prior to the resolution of the dispute
requiring such additional financial assurance, even if the Participant providing
such additional financial assurance is terminated or withdraws from NEPOOL and
otherwise satisfies all of its obligations to NEPOOL. As used herein, the term
"Financial Assurance Requirement" shall include 100% of such amount in dispute,
in addition to the other amounts included in such Financial Assurance
Requirement for the relevant Participant.
In addition, and without limiting the foregoing, any Participant that does not
satisfy the rating requirement or NEPOOL's credit review process and that has
monthly NEPOOL Charges (determined as set forth above) in excess of $15,000
shall not at any time have net NEPOOL Charges (regardless of whether such
charges have actually become due and owing or not) in excess of the amount of
the additional financial assurance provided by such Participant. Any Participant
that does not satisfy the rating requirement or NEPOOL's credit review process
but is exempt from providing additional financial assurance by virtue of having
monthly NEPOOL charges of $15,000 or less shall not at any time have net NEPOOL
Charges (regardless of whether such charges have actually become due and owing
or not) in excess of $15,000 unless such Participant provides the additional
financial assurance described herein in an amount not less than such net NEPOOL
Charges. If a Participant that does not satisfy the rating requirement or
NEPOOL's credit review process exceeds the limits for net NEPOOL Charges set
forth for it in this paragraph, NEPOOL may initiate termination proceedings. A
Participant that does not satisfy the rating requirement or NEPOOL's credit
review process and knows or reasonably should know that it has exceeded the
limits for net NEPOOL Charges set forth for it in this paragraph shall notify
the ISO immediately that it has exceeded such limits.
Cash Deposit
A cash deposit for the full value of the Financial Assurance Requirement, as
determined by NEPOOL, provides an acceptable form of financial assurance to
NEPOOL.
If the amount of the deposit is below the required level, the Participant shall
immediately replenish or increase the deposit to the required level; otherwise,
NEPOOL may initiate termination proceedings. In the event that actual NEPOOL
Charges exceed those anticipated, the anticipated charges will be increased
accordingly and the Participant must augment its cash deposit to reach the
required level.
The cash deposit will be invested by NEPOOL in investments as may be designated
by the Participant in direct obligations of the United States or its agencies
and interest earned will be paid to the Participant. NEPOOL may sell or
otherwise liquidate such investments at its discretion to meet the Participant's
obligations to NEPOOL.
The requirement to continue the deposit may be reviewed by NEPOOL after one
year. Consideration will be given to replacing the cash deposit with a corporate
guaranty if certain conditions are met, as discussed below in the Corporate
Guaranty section.
Letter of Credit
An irrevocable standby letter of credit for the full value of the Financial
Assurance Requirement, as determined by NEPOOL, provides an acceptable form of
financial assurance to NEPOOL. The letter of credit will renew automatically
unless the issuing bank provides notice to NEPOOL at least ninety (90) days
prior to the letter of credit's expiration of the bank's decision not to renew
the letter of credit.
If the letter of credit amount is below the required level, the Participant
shall immediately replenish or increase the letter of credit amount; otherwise,
NEPOOL may initiate termination proceedings. If actual NEPOOL Charges exceed
those anticipated, the Participant must obtain a substitute letter of credit
that equals the actual NEPOOL Charges.
The form, substance, and provider of the letter of credit must all be acceptable
to NEPOOL. The letter of credit should clearly state the full names of the
"Issuer," "Account Party" and "Beneficiary" (NEPOOL), the dollar amount
available for drawings, and should include a statement required on the drawing
certificate and other terms and conditions that should apply. It should also
specify that funds will be disbursed, in accordance with the instructions,
within one (1) business day after due presentation of the drawing certificate.
The bank issuing the letter of credit must have a minimum corporate debt rating
of an "A-" by Standard & Poor's, or "A3" by Moody's, or "A-" by Duff & Phelps,
or "A-" by Fitch, or an equivalent short term debt rating by one of these
agencies.
Please refer to Attachment 1, which provides an example of a generally
acceptable sample "clean" letter of credit. All costs associated with obtaining
financial security and meeting the Policy provisions are the responsibility of
the Applicant or Participant.
The requirement to continue to provide a letter of credit may be reviewed by
NEPOOL after one year. Consideration will be given to replacing the letter of
credit with a corporate guaranty if certain conditions are met, as discussed
below in the Corporate Guaranty section.
Performance Bond
A performance bond complying with the requirements set forth herein provides an
acceptable form of financial assurance to NEPOOL. The penal sum of such
performance bond shall be in an amount equal to the full value of the Financial
Assurance Requirement, as determined by NEPOOL, and shall automatically be
adjusted to reflect any adjustment in such Financial Assurance Requirement. The
bond shall permit suit thereunder until two years after the date that all of the
Applicant's or Participant's obligations to NEPOOL expire.
If the amount of the penal sum of the performance bond available to NEPOOL is
below the required level, the Participant shall immediately replenish or
increase the amount of the penal sum; otherwise, NEPOOL may initiate termination
proceedings. If actual NEPOOL Charges exceed those anticipated, the Participant
must either cause the penal sum of such performance bond to be increased
accordingly or must obtain a substitute performance bond in the appropriate
amount.
The form, substance and provider of the performance bond must be acceptable to
NEPOOL. The performance bond should clearly state the full names of the
"Principal," the "Surety" and the "Obligee" (NEPOOL) and the penal sum and
should include a clear statement that the surety will promptly and faithfully
perform the Participant's obligations to NEPOOL if the Participant fails to do
so. The insurance company issuing the performance bond must be rated "A" or
better by A.M. Best & Co.
Please refer to Attachment 2, which provides an example of a generally
acceptable sample performance bond. All costs associated with obtaining
financial security and meeting the Policy provisions, including without
limitation the cost of the premiums for such performance bond, are the
responsibility of the Applicant or Participant.
The requirement to continue to provide a performance bond may be reviewed by
NEPOOL after one year. Consideration will given to replacing the performance
bond with a corporate guaranty if certain conditions are met, as discussed below
in the Corporate Guaranty section.
Weekly Payments
A Participant that does not satisfy the rating requirement may request that, in
lieu of providing one of the additional financial assurances set forth above, a
weekly billing schedule be implemented for it. NEPOOL may, in its discretion,
agree to such a request; provided, however, that any weekly billing arrangement
will terminate no more than six months after the date on which such arrangement
begins unless the Participant requests an extension of such arrangement and
demonstrates to NEPOOL's satisfaction in its sole discretion that the
termination of such arrangement and compliance with the other provisions of this
Policy (including providing another form of financial assurance, if required)
will impose a substantial hardship on the Participant. Such demonstration of a
substantial hardship shall be made every six months after the initial
demonstration, and a Participant's weekly billing arrangement will be terminated
if it fails to demonstrate to NEPOOL's satisfaction in its sole discretion at
any such six month interval that compliance with the other provisions of this
Policy will impose a substantial hardship on it.
If NEPOOL agrees to implement a weekly billing schedule for a Participant, the
Participant shall be billed weekly in arrears on an estimated basis for all
amounts owed to NEPOOL and the System Operator for the week, with an adjustment
for each month as part of the regular NEPOOL monthly billing to reflect any
under or over collection for the month. The Participant shall be obligated to
pay each such weekly bill within five business days after it is received. The
Participant shall pay with respect to each weekly bill an administrative fee,
determined by the System Operator, to reimburse the System Operator for the
costs it incurs as a result of that Participant's weekly billing arrangement.
If a weekly billing schedule is implemented for a Participant in lieu of
requiring the Participant to provide an additional financial assurance, the
Participant may be required to provide an additional financial assurance at any
time if the Participant fails to pay when due any weekly bill. In addition, upon
the termination of a Participant's weekly billing arrangement, the Participant
shall either satisfy the rating requirement set forth herein or provide one of
the other forms of financial assurance set forth herein.
Use of Transaction Setoffs
Under certain conditions, NEPOOL may be obligated to make payments to a
Participant. In this event, the amount of the cash deposit, letter of credit or
performance bond required for financial assurance for the contemplated
transactions may be reduced ("setoff") by an amount equal to NEPOOL's unpaid
balance or expected billing under the other transactions. The terms and the
amount of the setoff must be approved by NEPOOL.
Corporate Guaranty
An irrevocable corporate guaranty obtained from a Participant's affiliated
company ("Guarantor") for the full value of the Financial Assurance Requirement,
as determined by NEPOOL, may provide an acceptable form of financial assurance
to NEPOOL.
If actual NEPOOL Charges exceed those anticipated, the Participant must provide
a substitute corporate guaranty that equals the actual NEPOOL Charges.
A Participant for which a letter of credit, performance bond or cash deposit was
initially required may have the opportunity to substitute a corporate guaranty
if the following conditions are met:
1. NEPOOL determines that the Participant has satisfactorily met its payment
obligations in NEPOOL for at least one-year, which one-year period may in whole
or in part pre-date the Policy Effective Date;
2. NEPOOL determines that the financial condition of the Guarantor meets the
requirements of this Policy; and 3.
3. The form and substance of the corporate guaranty are acceptable to
NEPOOL.
Upon NEPOOL's written authorization, the Participant may substitute a corporate
guaranty that is issued by the Guarantor for a cash deposit, bank letter of
credit or performance bond when it has satisfied the conditions stipulated
above. The corporate guaranty is considered to be a lesser form of financial
assurance than a cash deposit, letter of credit or performance bond, and
therefore is allowed as an acceptable form of financial assurance only to those
Participants that have satisfied their payment obligations to NEPOOL in a timely
manner for at least one year.
The corporate guaranty may only be used if the Participant is affiliated with a
Guarantor that has greater financial assets, a strong balance sheet and income
statements, and at minimum an investment grade rating by either Standard &
Poor's, Moody's, Duff & Phelps, or Fitch.
The corporate guaranty should clearly state the identities of the "Guarantor,"
"Beneficiary" and "Obligor," and the relationship between the Guarantor and the
Participant Obligor. The corporate guaranty must be duly authorized by the
Guarantor, must be signed by an officer of the Guarantor, and must be furnished
with either an opinion satisfactory to NEPOOL of the Guarantor's counsel with
respect to the enforceability of the guaranty or accompanied by a certificate of
corporate guarantee that includes a seal of the corporation with the signature
of the corporate secretary. Additionally, adequate documentation regarding the
signature authority of the person signing the corporate guaranty must be
provided with the corporate guaranty.
A corporate guaranty must also obligate the Guarantor to submit a current rating
agency report promptly upon the request of NEPOOL, to submit 8-K Reports
promptly upon their issuance, to submit financial reports if and as requested by
NEPOOL within ten (10) days of such request, and to inform NEPOOL in writing
within ten (10) business days of any material change in its financial status. A
material change in financial status includes, but is not limited to, the
following: a downgrade to a below investment grade rating of senior long term
debt by a major rating agency, being placed on credit watch with negative
implication by a major rating agency if senior long term debt does not have an
investment grade rating, a bankruptcy filing, insolvency, a report of a
significant quarterly loss or decline of earnings, the resignation of key
officer(s), and/or the filing of a material lawsuit that could materially
adversely impact current or future financial results. A Guarantor's failure to
provide this information may result in proceedings by NEPOOL to terminate the
Participant Obligor. If there is a material adverse change in the financial
condition of the Guarantor, NEPOOL may require the Participant Obligor to
provide another form of financial assurance, either a cash deposit or a letter
of credit or a performance bond.
Non-payment of Amounts Due
If a Participant does not pay amounts billed when due and as a result a letter
of credit or cash deposit is drawn down or a performance bond is paid on, then
the Participant must immediately replenish the letter of credit or cash deposit
to the required amount or cause the penal sum of the performance bond to be
increased to equal the required amount plus all amounts paid thereunder. If a
Participant fails to do so, NEPOOL may initiate termination proceedings against
the Participant in accordance with the procedure set forth in Section 21.2(d) of
the Restated NEPOOL Agreement.
In order to encourage prompt payment by Participants of amounts owed to NEPOOL
and the ISO, if a Participant is delinquent two or more times within any period
of twelve months in paying on time its NEPOOL Charges, the Participant shall
pay, in addition to interest on each late payment, a late payment charge for its
second failure to pay on time, and for each subsequent failure to pay on time,
within the same twelve-month period, in an amount equal to the greater of (i)
two percent (2%) of the total amount of such late payment or (ii) $250.00.
In the case of a former Participant that applies again for membership in NEPOOL,
a determination of delinquency shall be based on the Participant's history of
payment of its NEPOOL Charges in its last twelve (12) months of membership.
Financial Assurance upon Termination of Membership
Upon termination of membership in NEPOOL, a Participant must provide financial
assurance in the amount of all potential billing adjustments chargeable to such
Participant for all unresolved billing disputes in existence on the date of
termination of such Participant's membership. Such financial assurance must be
in the form of a cash deposit, a letter of credit, an affiliate guaranty, or a
performance bond meeting the requirements of this policy. The amount of such
financial assurance shall be reduced to the extent any billing dispute is
resolved and the former Participant pays the billing adjustments or no billing
adjustment is chargeable to the former Participant.
Notification of Default
In the event that a Participant fails to comply with this Financial Assurance
Policy (including, without limitation, a failure by such Participant (i) to
provide NEPOOL with the required information, (ii) to maintain its additional
financial assurance at the required level, (iii) to notify NEPOOL of a material
adverse change in the financial condition of such Participant or its Guarantor,
or (iv) to notify NEPOOL of such Participant's net Monthly Charges exceeding the
limits set forth above) (a "Financial Assurance Default") and such failure
continues for at least ten days, NEPOOL may (but shall not be required to)
notify such Participant in writing, electronically and by first class mail sent
in each case to such Participant's member or alternate on the NEPOOL
Participants Committee or billing contact (it being understood that NEPOOL will
use reasonable efforts to contact all three), of such Financial Assurance
Default. Either simultaneously with the giving of the notice described in the
preceding sentence or within the ten days thereafter (unless the Financial
Assurance Default is cured during such period), NEPOOL shall notify each other
member and alternate on the NEPOOL Participants Committee and each Participant's
billing contact of the identity of the Participant receiving such notice,
whether such notice relates to a Financial Assurance Default, and the actions
NEPOOL plans to take and/or has taken in response to such Financial Assurance
Default.
No remedy for a Financial Assurance Default is or shall be deemed to be
exclusive of any other available remedy or remedies. Each such remedy shall be
distinct, separate and cumulative, shall not be deemed inconsistent with or in
exclusion of any other available remedy, and shall be in addition to and
separate and distinct from every other remedy.
ATTACHMENT 1
SAMPLE LETTER OF CREDIT
[DATE PROVIDED]
IRREVOCABLE STANDBY LETTER OF CREDIT NO.
[EXPIRATION DATE] AT OUR COUNTERS [unless an evergreen l/c is obtained]
WE DO HEREBY ISSUE AN IRREVOCABLE NON-TRANSFERABLE STANDBY LETTER OF CREDIT BY
ORDER OF AND FOR THE ACCOUNT OF ON BEHALF OF [PARTICIPANT] ("ACCOUNT PARTY") IN
FAVOR OF THE PARTICIPANTS IN THE NEW ENGLAND POWER POOL ("NEPOOL") IN AN AMOUNT
NOT EXCEEDING US$ .00 (UNITED STATES DOLLARS
AND 00/100) AGAINST PRESENTATION TO US OF A DRAWING CERTIFICATE SIGNED
BY A PURPORTED OFFICER OR AUTHORIZED AGENT OF NEPOOL AND DATED THE DATE OF
PRESENTATION CONTAINING THE FOLLOWING STATEMENT:
"THE UNDERSIGNED HEREBY CERTIFIES TO [BANK] ("BANK"), WITH REFERENCE TO
IRREVOCABLE NON-TRANSFERABLE STANDBY LETTER OF CREDIT NO. ISSUED BY [BANK] IN
FAVOR OF THE PARTICIPANTS IN THE NEW ENGLAND POWER POOL ("NEPOOL") THAT
[PARTICIPANT] HAS FAILED TO PAY NEPOOL IN ACCORDANCE WITH THE TERMS AND
PROVISIONS OF THE RESTATED NEPOOL AGREEMENT BETWEEN [PARTICIPANT] AND THE OTHER
NEPOOL MEMBERS , AND THUS NEPOOL IS DRAWING UPON THE LETTER OF CREDIT IN AN
AMOUNT EQUAL TO $ ."
IF PRESENTATION OF ANY DRAWING CERTIFICATE IS MADE ON A BUSINESS DAY AND SUCH
PRESENTATION IS MADE AT OUR COUNTERS ON OR BEFORE 10:00 A.M. TIME, WE SHALL
SATISFY SUCH DRAWING REQUEST ON THE SAME BUSINESS DAY. IF THE DRAWING
CERTIFICATE IS RECEIVED AT OUR COUNTERS AFTER 10:00 A.M. TIME, WE WILL SATISFY
SUCH DRAWING REQUEST ON THE NEXT BUSINESS DAY, FOR THE PURPOSES OF THIS SECTION,
A BUSINESS DAY MEANS A DAY, OTHER THAN A SATURDAY OR SUNDAY, ON WHICH COMMERCIAL
BANKS ARE NOT AUTHORIZED OR REQUIRED TO BE CLOSED IN NEW YORK, NEW YORK.
DISBURSEMENTS SHALL BE IN ACCORDANCE WITH THE INSTRUCTIONS OF NEPOOL.
THE FOLLOWING TERMS AND CONDITIONS APPLY:
THIS LETTER OF CREDIT SHALL EXPIRE AT THE CLOSE OF BUSINESS [DATE]. WE WILL
PROVIDE NOTICE TO NEPOOL AT LEAST 90 DAYS PRIOR TO SUCH DATE IF THIS LETTER
OF CREDIT WILL NOT BE RENEWED AS OF SUCH DATE [or: THIS LETTER OF CREDIT
SHALL EXPIRE ONLY UPON THE FOLLOWING CONDITIONS: (1) WHEN FULL PAYMENT HAS
BEEN RECEIVED BY NEPOOL FROM [PARTICIPANT] AND (2) NEPOOL HAS PROVIDED A
WRITTEN RELEASE TO THIS BANK .]
THE AMOUNT WHICH MAY BE DRAWN BY YOU UNDER THIS LETTER OF CREDIT SHALL BE
AUTOMATICALLY REDUCED BY THE AMOUNT OF ANY UNREIMBURSED DRAWINGS HEREUNDER AT
OUR COUNTERS. ANY NUMBER OF PARTIAL DRAWINGS ARE PERMITTED FROM TIME TO TIME
HEREUNDER.
ALL COMMISSIONS AND CHARGES WILL BE BORNE BY THE ACCOUNT PARTY.
THIS LETTER OF CREDIT IS NOT TRANSFERABLE OR ASSIGNABLE.
THIS LETTER OF CREDIT DOES NOT INCORPORATE AND SHALL NOT BE DEEMED MODIFIED,
AMENDED OR AMPLIFIED BY REFERENCE TO ANY DOCUMENT, INSTRUMENT OR AGREEMENT (A)
THAT IS REFERRED TO HEREIN (EXCEPT FOR THE UCP, AS DEFINED BELOW) OR (B) IN
WHICH THIS LETTER OF CREDIT IS REFERRED TO OR TO WHICH THIS LETTER OF CREDIT
RELATES.
THIS LETTER OF CREDIT SHALL BE GOVERNED BY THE UNIFORM CUSTOMS AND PRACTICE FOR
DOCUMENTARY CREDITS, 1993 REVISION, INTERNATIONAL CHAMBER OF COMMERCE
PUBLICATION NO. 500 (THE "UCP"), EXCEPT TO THE EXTENT THAT TERMS HEREOF ARE
INCONSISTENT WITH THE PROVISIONS OF THE UCP, INCLUDING BUT NOT LIMITED TO
ARTICLES 13(b) AND 17 OF THE UCP, IN WHICH CASE THE TERMS OF THE LETTER OF
CREDIT SHALL GOVERN.
THIS LETTER OF CREDIT MAY NOT BE AMENDED, CHANGED OR MODIFIED WITHOUT THE
EXPRESS WRITTEN CONSENT OF NEPOOL AND US.
WE HEREBY ENGAGE WITH YOU THAT DOCUMENTS DRAWN UNDER AND IN COMPLIANCE WITH THE
TERMS OF THIS LETTER OF CREDIT SHALL BE DULY HONORED UPON PRESENTATION AS
SPECIFIED.
PRESENTATION OF ANY DRAWING CERTIFICATE UNDER THIS STANDBY LETTER OF CREDIT MAY
BE SENT TO US BY COURIER, CERTIFIED MAIL, REGISTERED MAIL, TELEGRAM, TELEX TO
THE ADDRESS SET FORTH BELOW, OR SUCH OTHER ADDRESS AS MAY HEREAFTER BE FURNISHED
BY US. OTHER NOTICES CONCERNING THIS STANDBY LETTER OF CREDIT MAY BE SENT BY
FACSIMILE OR SIMILAR COMMUNICATIONS FACILITY TO THE RESPECTIVE ADDRESSES SET
FORTH BELOW. ALL SUCH NOTICES AND COMMUNICATIONS SHALL BE EFFECTIVE WHEN
ACTUALLY RECEIVED BY THE INTENDED RECIPIENT PARTY.
IF TO THE BENEFICIARY OF THIS LETTER OF CREDIT:
IF TO THE ACCOUNT PARTY:
IF TO US:
[signature]
[signature]
ATTACHMENT 2
SAMPLE PERFORMANCE BOND
[Insurance Company]
Bond No.
KNOW ALL MEN BY THESE PRESENTS, That the undersigned [participant], of
[participant's address] hereinafter referred to as the Principal, and [insurance
company], a corporation organized and existing under the laws of the State of
[insurance company's state of incorporation], as Surety, are held and firmly
bound unto the Participants in the New England Power Pool as obligees,
hereinafter referred to collectively as the Obligee, in the sum of
, lawful money of the United States of America (which sum shall
automatically be adjusted to reflect any adjustment in the Financial Assurance
Requirement applicable to the Principal under the New England Power Pool's
Financial Assurance Policy for NEPOOL Members, as in effect from time to time)
for the payment of which sum, well and truly to be made, we bind ourselves, our
executors, administrators, successors, and assigns, jointly and severally,
firmly by these presents.
WHEREAS, the Principal has entered into agreements for the purchase and sale of
electric services and the payment of amounts owed to ISO New England Inc. and
its share of the expenses of the New England Power Pool under the Restated
NEPOOL Agreement, the Restated NEPOOL Open Access Transmission Tariff and the
ISO New England Inc. Tariff for Transmission Dispatch and Power Administration
Services, each as amended from time to time (collectively referred to as the
"Agreements"), and in strict accordance with their respective terms.
NOW, THEREFORE, the condition of this obligation is such, that if the Principal
shall promptly and faithfully make the payments required by, and comply with
terms of, the Agreements which have been or may hereafter be in force and shall
save and keep harmless the Obligee from all loss or damage which it may sustain
or for which it may become liable on account of the issuance of said Agreements
to the Principal, then this obligation shall be void; otherwise, it shall remain
in full force and effect.
Upon notice from ISO New England Inc. of nonpayment by the Principal, Surety
will pay to ISO New England Inc., as agent for the Obligee, the amounts owed
by the Principal under the Agreements.
The Surety hereby waives notice of any alteration or extension of time made by
the Obligee.
Any suit on this bond must be instituted before the expiration of two (2) years
from the date on which the Principal's obligations under the Agreements expires.
SIGNED, SEALED AND DATED this day of ,
19 .
[Seal]
[Participant]
Principal
By:
[Seal]
[Insurance Company]
Surety
By:
ATTACHMENT 3
CORPORATE GUARANTY
For and in consideration of the credit advance or sale of products on open
account by the New England Power Pool Participants from time to time
("Participants") to [Participant] ("Company"), the undersigned guarantor,
("Guarantor"), the [subsidiary/affiliate] of Company, hereby unconditionally and
irrevocably guarantees the prompt and complete payment of all amounts that
Company now or hereafter owes to Participants under the Restated NEPOOL
Agreement and Restated NEPOOL Open Access Transmission Tariff, [and performance
by Company of any other agreements, whether now existing or hereafter arising,
between Company and Participants], as amended from time to time (collectively
referred to as the "Agreements"), in strict accordance with their respective
terms.
1. If Company does not perform its obligations in strict accordance with the
Agreements, Guarantor shall immediately pay all amounts now or hereafter due
thereunder (including, without limitation, all principal, interest, and fees)
and otherwise proceed to complete the same and satisfy all of Company's
obligations under the Agreements. This Guaranty may be satisfied by Guarantor
paying and/or performing (as appropriate) Company's obligations or by Guarantor
causing Company's obligations to be paid or performed; provided, however, that
Guarantor shall at all times remain fully responsible and liable for its
obligations hereunder notwithstanding any such payment or performance (or
failure thereof) by any third party. Participants will undertake commercially
reasonable efforts to notify Guarantor of a failure by Company to make a payment
or perform its obligations under the Agreements; provided, however, that failure
by Participants to so notify Guarantor shall not defeat, limit or otherwise
affect the rights and obligations of Participants, Company or Guarantor. Subject
to the terms and conditions set forth herein, Guarantor's obligations hereunder
shall not exceed the complete payment of all amounts that Company now or
hereafter owes to Participants under the Restated NEPOOL Agreement and NEPOOL
Open Access Transmission Tariff and performance by Company of the Agreements in
strict accordance with their respective terms.
2. This Guaranty is an absolute, unconditional and continuing guaranty of the
full and punctual payment and performance by Company of each of its obligations
under the Agreements, and not of collectibility only, and is in no way
conditioned upon any requirement that Participants first attempt to collect
payment from Company or any other guarantor or surety or resort to any security
or other means of obtaining payment of all or any part of Company's obligations
or upon any other contingency. This is a continuing guaranty and shall be
binding upon Guarantor until the full, final and irrevocable payment and
performance of all of Company's obligations under the Agreements, regardless of
(i) how long after the date hereof any part of the obligations under the
Agreements is incurred by Company and (ii) the amount of the obligations under
the Agreements at any time outstanding. This Guaranty may be enforced by
Participants from time to time and as often as occasion for such enforcement may
arise.
3. The obligations hereunder are independent of the obligations of Company, and
a separate action or actions may be brought and prosecuted against Guarantor
whether action is brought against Company or whether Company be joined in any
such action or actions. Guarantor's liability under this Guaranty is not
conditioned or contingent upon genuineness, validity, regularity or
enforceability of the Agreements.
4. Guarantor authorizes Participants, without notice or demand and without
affecting its liability hereunder, from time to time to (a) renew, extend, or
otherwise change the terms of the Agreements or any part thereof, (b) take and
hold security for the payment of the Agreements, and exchange, enforce, waive
and release any such security; and (c) apply such security and direct the order
or manner of sale thereof as Participants in their sole discretion may
determine. The obligations and liabilities of Guarantor hereunder shall be
absolute and unconditional, shall not be subject to any counterclaim, set- off,
deduction or defense based upon any claim Guarantor may have against Company,
any other guarantor, or any other person or entity, and shall remain in full
force and effect until all of the obligations hereunder and under the Agreements
have been fully satisfied, without regard to, or release or discharge by, any
event, circumstance or condition (whether or not Guarantor shall have knowledge
or notice thereof) which but for the provisions of this Section might constitute
a legal or equitable defense or discharge of a guarantor or surety or which
might in any way limit recourse against Guarantor, including without limitation:
(a) any amendment or modification of, or supplement to, the terms of the
Agreements; (b) any waiver, consent or indulgence by Participants, or any
exercise or non-exercise by Participants of any right, power or remedy, under or
in respect of this Guaranty or the Agreements (whether or not Guarantor or
Company has or have notice or knowledge of any such action or inaction); (c) the
invalidity or unenforceability, in whole or in part, of the Agreements, or the
termination (except pursuant to its terms or by written agreement between
Participants and Company), cancellation or frustration of any thereof, or any
limitation or cessation of Company's liability under any thereof (other than any
limitation or cessation expressly provided for therein), including without
limitation any invalidity, unenforceability or impaired liability resulting from
Company's lack of capacity, power and/or authority to enter into the Agreements
and/or to incur any or all of the obligations thereunder, or from the execution
and delivery of any Agreement by any person acting for Company without or in
excess of authority (except to the extent the same would limit or cease
Company's liability under the Agreements); (d) any actual, purported or
attempted sale, assignment or other transfer by Participants of any Agreement or
of any of its rights, interests or obligations thereunder; (e) the taking or
holding by Participants of a security interest, lien or other encumbrance in or
on any property as security for any or all of the obligations of Company under
the Agreements or any exchange, release, non- perfection, loss or alteration of,
or any other dealing with, any such security; (f) the addition of any party as a
guarantor or surety of all or any part of the obligations of Company under the
Agreements; (g) any merger, amalgamation or consolidation of Company into or
with any other entity, or any sale, lease, transfer or other disposition of any
or all of Company's assets or any sale, transfer or other disposition of any or
all of the shares of capital stock or other securities of Company to any other
person or entity; (h) any change in the financial condition of Company or (as
applicable) of any subsidiary, affiliate, partner or controlling shareholder
thereof, or Company's entry into an assignment for the benefit of creditors, an
arrangement or any other agreement or procedure for the restructuring of its
liabilities, or Company's insolvency, bankruptcy, reorganization, dissolution,
liquidation or any similar action by or occurrence with respect to Company.
5. Guarantor unconditionally waives, to the fullest extent permitted by law: (a)
notice of any of the matters referred to in Section 4 hereof; (b) any right to
the enforcement, assertion or exercise by Participants of any of their rights,
powers or remedies under, against or with respect to (i) any of the Agreements,
(ii) any other guarantor or surety, or (iii) any security for all or any part of
the obligations of Company under the Agreements or obligations of Guarantor
hereunder; (c) any requirement of diligence and any defense based on a claim of
laches; (d) all defenses which may now or hereafter exist by virtue of any
statute of limitations, or of any stay, valuation, exemption, moratorium or
similar law, except the sole defense of full and indefeasible payment; (e) any
requirement that Guarantor be joined as a party in any action or proceeding
against Company to enforce any of the provisions of the Agreements; (f) any
requirement that Participants mitigate or attempt to mitigate damages resulting
from a default by Guarantor hereunder or from a default by Company under any of
the Agreements; (g) acceptance of this Guaranty by Participants; and (h) all
presentments, protests, notices of dishonor, demands for performance and any and
all other demands upon and notices to Company, and any and all other formalities
of any kind, the omission of or delay in performance of which might but for the
provisions of this Section constitute legal or equitable grounds for relieving
or discharging Guarantor in whole or in part from its irrevocable, absolute and
continuing obligations hereunder, it being the intention of Guarantor that its
obligations hereunder shall not be discharged except by payment and performance
and then only to the extent thereof.
6. Guarantor waives any right to require Participants to (a) proceed against
Company; (b) proceed against or exhaust any security held from Company; or (c)
pursue any other remedy in Participants' power whatsoever. So long as any
obligations remain outstanding under this Guaranty or the Agreements, Guarantor
shall not exercise any rights against Company arising as a result of payment by
Guarantor hereunder, by way of subrogation or otherwise, and will not prove any
claim in competition with Participants or their affiliates in respect of any
payment under the Agreements in bankruptcy or insolvency proceedings of any
nature; Guarantor will not claim any set-off or counterclaim against Company in
respect of any liability of Guarantor to Company and Guarantor waives any
benefit of any right to participate in any collateral which may be held by
Participants or any of their affiliates. Guarantor shall have no right of
subrogation or reimbursement, contribution or other rights against Company.
7. If after receipt of any payment of, or the proceeds of any collateral for,
all or any part of the obligations of Company under the Agreements, Participants
are compelled to surrender or voluntarily surrender such payment or proceeds to
any person because such payment or application of proceeds is or may be avoided,
invalidated, recaptured, or set aside as a preference, fraudulent conveyance,
impermissible setoff or for any other reason, whether or not such surrender is
the result of (i) any judgment, decree or order of any court or administrative
body having jurisdiction over Participants, or (ii) any settlement or compromise
by Participants of any claim as to any of the foregoing with any person
(including Company), then the obligations of Company under the Agreements, or
part thereof affected, shall be reinstated and continue and this Guaranty shall
be reinstated and continue in full force as to such obligations or part thereof
as if such payment or proceeds had not been received, notwithstanding any
previous cancellation of any instrument evidencing any such obligation or any
previous instrument delivered to evidence the satisfaction thereof. The
provisions of this Section shall survive the termination of this Guaranty and
any satisfaction and discharge of Company by virtue of any payment, court order
or any federal or state law until the full, final and irrevocable satisfaction
of all of Company's obligations under the Agreements.
8. Any indebtedness of Company now or hereafter held by Guarantor is hereby
subordinated to any indebtedness of Company to Participants; and such
indebtedness of Company to Guarantor shall be collected, enforced and received
by Guarantor as trustee for Participants and be paid over to Participants on
account of the indebtedness of Company due and owing at any time to Participants
but without reducing or affecting in any manner the liability of Guarantor under
the other provisions of this Guaranty.
9. Guarantor represents and warrants to Participants, as an inducement to
Participants to make the credit advances or sales of products on open account to
Company, that:
a. the execution, delivery and performance by Guarantor of this Guaranty (i) are
within Guarantor's powers and have been duly authorized by all necessary action;
(ii) do not contravene Guarantor's charter documents or any law or any material
contractual restrictions binding on or affecting Guarantor or by which
Guarantor's property may be affected; and (iii) do not require any authorization
or approval or other action by, or any notice to or filing with, any public
authority or any other person except such as have been obtained or made;
b. this Guaranty constitutes the legal, valid and binding obligation of
Guarantor, enforceable in accordance with its terms, except as the
enforceability thereof may be subject to or limited by bankruptcy, insolvency,
reorganization, arrangement, moratorium or other similar laws relating to or
affecting the rights of creditors generally and by general principles of equity;
and
c. there is no action, suit or proceeding affecting Guarantor pending or
threatened before any court, arbitrator, or public authority that may materially
adversely affect Guarantor's ability to perform its obligations under this
Guaranty, except as set forth in writing to the Participants and ISO New England
Inc. prior to Participants' written authorization of this Guaranty.
10. Guarantor shall submit to Participants (i) a current credit rating agency
report regarding Guarantor promptly upon the request of Participants, (ii) a
copy of any Report on Form 8-K promptly after the filing by Guarantor of such
report with the Securities and Exchange Commission, and (iii) a balance sheet,
statement of income and such other financial statements of Guarantor as
Participants shall reasonably request within ten (10) days after such statements
are requested by Participants. Guarantor shall notify Participants in writing
within ten (10) days after a material change in the financial status of
Guarantor. For purposes of this section, a material change in financial status
includes, but is not limited to, the following: (a) a downgrade to a below
investment grade rating in the rating of Guarantor's senior long-term debt by a
major rating agency; (b) the placement of Guarantor on credit watch with
negative implication by a major credit rating agency if Guarantor's senior
long-term debt does not have an investment grade rating; (c) Guarantor's
bankruptcy or insolvency; (d) a report by Guarantor of a significant quarterly
loss or decline in earnings; (e) the resignation of a key officer of Guarantor;
and (e) the filing of a lawsuit that could materially adversely impact
Guarantor's current or future financial results. Guarantor acknowledges that
failure by it to provide the information required hereunder may result in
Participants bringing proceedings to terminate Company from the New England
Power Pool.
11. Guarantor agrees to pay on demand all reasonable attorneys' fees and all
other costs and expenses which may be incurred by Participants in the
enforcement of this Guaranty. No terms or provisions of this Guaranty may be
changed, waived, revoked or amended without Participants' prior written consent.
Should any provision of this Guaranty be determined by a court of competent
jurisdiction to be unenforceable, all of the other provisions shall remain
effective. This Guaranty embodies the entire agreement among the parties hereto
with respect to the matters set forth herein, and supersedes all prior
agreements among the parties with respect to the matters set forth herein. No
course of prior dealing among the parties, no usage of trade, and no parol or
extrinsic evidence of any nature shall be used to supplement, modify or vary any
of the terms hereof. There are no conditions to the full effectiveness of this
Guaranty. Participants may assign this Guaranty without in any way affecting
Guarantor's liability under it, except that Guarantor shall be provided
reasonable notice of any such assignment. This Guaranty shall inure to the
benefit of Participants and their successors and assigns. This Guaranty is in
addition to the guaranties of any other guarantors and any and all other
guaranties of Company's indebtedness or liabilities to Participants.
12. This Guaranty shall be governed by the laws of the State of Connecticut,
without regard to conflicts of laws principles. Guarantor hereby irrevocably
submits to the jurisdiction of any Connecticut State or United States Federal
court sitting in Connecticut over any action or proceeding arising out of or
relating to this Guaranty or any of the Agreements, and Guarantor hereby
irrevocably agrees that all claims in respect of such action or proceeding may
be heard and determined in such Connecticut State or Federal court. Guarantor
irrevocably consents to the service of any and all process in any such action or
proceeding by the mailing of copies of such process to Guarantor at its address
set forth below its signature. Guarantor agrees that a final judgment in any
such action or proceeding shall be conclusive and may be enforced in other
jurisdictions by suit on the judgment or in any other manner provided by law.
Guarantor further waives any objection to venue in such State and any objection
to an action or proceeding in such State on the basis of forum non conveniens.
Guarantor further agrees that any action or proceeding brought against
Participants shall be brought only in Connecticut State or United States Federal
courts sitting in Connecticut. Nothing herein shall affect the right of
Participants to bring any action or proceeding against the Guarantor or its
property in the courts of any other jurisdictions.
13. GUARANTOR ACKNOWLEDGES THAT IT HAS BEEN ADVISED BY COUNSEL OF ITS CHOICE
WITH RESPECT TO THIS GUARANTY AND THAT IT MAKES THE FOLLOWING WAIVERS KNOWINGLY
AND VOLUNTARILY:
a. IRREVOCABLY WAIVES TRIAL BY JURY IN ANY COURT AND IN ANY SUIT, ACTION OR
PROCEEDING OR ANY MATTER ARISING IN CONNECTION WITH OR IN ANY WAY RELATED TO THE
TRANSACTIONS CONTEMPLATED BY THIS GUARANTY, THE AGREEMENTS OR ANY DOCUMENTS
RELATED THERETO (INCLUDING CONTRACT CLAIMS, TORT CLAIMS, BREACH OF DUTY CLAIMS,
AND ALL OTHER COMMON LAW OR STATUTORY CLAIMS) AND THE ENFORCEMENT OF ANY OF
PARTICIPANTS' RIGHTS AND REMEDIES; AND
b. GUARANTOR EXPRESSLY ACKNOWLEDGES THAT THE OBLIGATIONS GUARANTEED HEREBY ARE
PART OF A COMMERCIAL TRANSACTION AS SUCH TERM IS USED AND DEFINED IN CHAPTER
903a OF THE CONNECTICUT GENERAL STATUTES AND VOLUNTARILY AND KNOWINGLY WAIVES
ANY AND ALL RIGHTS WHICH ARE OR MAY BE CONFERRED UPON IT UNDER CHAPTER 903a OF
SAID STATUTES (OR ANY OTHER STATUTE AFFECTING PREJUDGMENT REMEDIES) TO ANY
NOTICE OR HEARING OR PRIOR COURT ORDER OR THE POSTING OF ANY BOND PRIOR TO ANY
PREJUDGMENT REMEDY WHICH PARTICIPANTS MAY USE.
14. Any demand, notice, request, instruction or other communication to be given
hereunder by any party to another party shall be in writing and delivered
personally, by nationally recognized overnight courier, by certified mail,
postage prepaid and return receipt requested, by telegram, or by telecopier, as
follows:
If to Guarantor, at:
If to Participants, at:
Communications given by personal delivery or mail shall be effective upon actual
receipt. Communications given by telegram or telecopier shall be effective upon
actual receipt during the recipient's normal business hours, or at the beginning
of the next business day after receipt if not received during the recipient's
normal business hours. All communications by telegram or telecopier shall be
confirmed promptly in writing by certified mail or personal delivery. Any party
may change any address to which communications are to be given by giving notice
as provided above of such change of address.
IN WITNESS WHEREOF, the undersigned Guarantor has executed this Guaranty as of
this day of [month], 199_.
[GUARANTOR]
By:
Title:
Corporate Officer
Address:
ATTACHMENT M
Financial Assurance Policy for NEPOOL Non-Participant
Transmission Customers
This Financial Assurance Policy for Transmission Customers (FN1) that are
Non-Participants ("Policy") shall become effective on January 1, 1999 (the
"Policy Effective Date").
The purpose of this Policy is (i) to establish a financial assurance policy for
Non-Participant Transmission Customers pursuant to Section 11 of the Restated
NEPOOL Open Access Transmission Tariff (the "Tariff") that includes commercially
reasonable credit review procedures to assess the financial ability of each
Non-Participant applicant for service ("Applicant") under the Tariff to pay for
service transactions under the Tariff and under the ISO New England Inc. Tariff
for Transmission Dispatch and Power Administration Services (the "ISO Tariff"),
(ii) to set forth requirements for alternative forms of security that will be
deemed acceptable to NEPOOL and consistent with commercial practices established
by the Uniform Commercial Code that protects the Participants against the risk
of non-payment by Non-Participant Transmission Customers, (iii) to set forth the
conditions under which NEPOOL will conduct business so as to avoid the
possibility of failure of payment for services rendered to Non-Participant
Transmission Customers under the Tariff and the ISO Tariff, and (iv) to collect
amounts past due, make up shortfalls in payments, and terminate service to
defaulting Non-Participant Transmission Customers.
- -------
(FN1)
Capitalized terms used but not defined in this Policy are intended to have the
meanings given to such terms in Section 1 of the Restated NEPOOL Agreement or
Section 1 of the Restated NEPOOL Open Access Transmission Tariff (the "Tariff"),
as amended.
In accordance with Section 11 of the Tariff, NEPOOL requires the following
procedures and requirements to apply to all Applicants and Non-Participant
Transmission Customers. Generally, any Applicant or Non-Participant Transmission
Customer that does not have an investment grade rating by either Standard &
Poor's, Moody's, Duff & Phelps, or Fitch (or in the case of Applicants and
Non-Participant Transmission Customers that are not rated themselves, any
Applicant or Non-Participant Transmission Customer that does not have
outstanding debt with such a rating) will be required to provide financial
assurances, as described in detail below. (FN2)
- ------
(FN2)
The System Operator will act as NEPOOL's agent in managing and enforcing this
Policy with the exception of termination of membership issues, which are
specifically reserved to the NEPOOL Participants and will be addressed by the
NEPOOL Executive Committee Membership Subcommittee, subject to appeal to the
Management Committee. Accordingly, all financial information required pursuant
to this Policy is to be provided to the System Operator, which will keep all
such information confidential in accordance with the provisions of Section 2 of
NEPOOL Criteria, Rules and Standards No. 45.
GENERAL REQUIREMENTS
Each Applicant or Non-Participant Transmission Customer must comply with the
following general requirements.
Proof of Financial Viability
Each Applicant must with its application for service submit proof of financial
viability, as described below, satisfying NEPOOL requirements to demonstrate the
Applicant's ability to meet its obligations, or must provide, prior to NEPOOL's
filing of a Service Agreement for the Applicant and provision of service to the
Applicant under the Tariff, financial assurance in the form of a cash deposit,
letter of credit or performance bond as set forth below. An Applicant that
chooses to provide a cash deposit, letter of credit or performance bond will not
be required to provide financial information to NEPOOL.
Generally, each Applicant must submit a current rating agency report, which
report must indicate an investment grade rating by either Standard & Poor's,
Moody's, Duff & Phelps, or Fitch for the Applicant or, if the Applicant itself
is not rated, for the Applicant's outstanding rated debt, in order for NEPOOL to
file a Service Agreement for the Applicant and provide service to the Applicant
under the Tariff without the Applicant being required to furnish additional
financial assurances as described below.
Current Non-Participant Transmission Customers that have not already provided to
NEPOOL financial assurances consistent with the requirements of this Policy must
also provide a current rating agency report by the Policy Effective Date, as
well as any of the financial statements and information set forth below if and
as requested by NEPOOL within ten (10) days of such request. Those
Non-Participant Transmission Customers that do not satisfy the rating
requirement as set forth above must provide instead on the Policy Effective Date
one form of the financial assurances set forth below. A Non- Participant
Transmission Customer's failure to meet these requirements may result in
termination of service by NEPOOL in accordance with the procedure set forth for
payment defaults in Section 8.4 of the Tariff.
Financial Statements
Each Applicant must submit, if and as requested by NEPOOL and within ten (10)
days of such request, audited financial statements for at least the immediately
preceding three years, or the period of its existence, if shorter, including,
but not limited to, the following information:
Balance Sheets
Income Statements
Statements of Cash Flows
Notes to Financial Statements
Additionally, the following information for at least the immediately preceding
three years, if available, must be submitted if and as requested by NEPOOL and
within ten (10) days of such request:
Annual and Quarterly Reports
10-K, 10-Q and 8-K Reports
Where the above financial statements are available on the Internet, the
Applicant may provide instead a letter to NEPOOL stating where such statements
may be located and retrieved by NEPOOL.
Each Applicant may also be required to provide at least one bank reference and
three (3) utility credit references. In those cases where an Applicant does not
have three (3) utility credit references, three (3) trade payable vendor
references may be substituted.
Each Applicant may also be required to include information as to any known or
anticipated material lawsuits, as well as any prior bankruptcy declarations by
the Applicant, or by its predecessor(s), if any.
In the case of certain Applicants, some of the above financial submittals may
not be applicable, and alternate requirements may be specified by NEPOOL.
Ongoing Financial Review
Each Non-Participant Transmission Customer that has not provided a cash deposit,
letter of credit, performance bond, or corporate guaranty must submit its
current rating agency report promptly upon the request of NEPOOL, and 8-K
Reports promptly upon their issuance.
In addition, each Non-Participant Transmission Customer that has not provided a
cash deposit, letter of credit, performance bond or corporate guaranty is
responsible for informing NEPOOL in writing within ten (10) business days of any
material change in its financial status. A material change in financial status
includes, but is not limited to, the following: a downgrade to a below
investment grade rating of senior long term debt by a major rating agency, being
placed on credit watch with negative implication by a major rating agency if
senior long term debt does not have an investment grade rating, a bankruptcy
filing, insolvency, a report of a significant quarterly loss or decline of
earnings, the resignation of key officer(s), and/or the filing of a material
lawsuit that could materially adversely impact current or future financial
results. A Non-Participant Transmission Customer's failure to provide this
information as required may result in termination of service by NEPOOL in
accordance with the procedure set forth in Section 8.4 of the Tariff.
If there is a material adverse change in the financial condition of the Non-
Participant Transmission Customer that has not provided a cash deposit, letter
of credit, performance bond or corporate guaranty, NEPOOL may require such
Non-Participant Transmission Customer to provide one of the forms of other
financial assurances set forth below. If the Non-Participant Transmission
Customer fails to do so, NEPOOL may terminate service in accordance with the
procedure set forth for payment defaults in Section 8.4 of the Tariff.
OTHER FINANCIAL ASSURANCES
Applicants or Non-Participant Transmission Customers that do not satisfy the
rating requirement or NEPOOL's credit review process must submit instead one of
the following additional financial assurances, depending on the specific aspects
of the transactions they anticipate engaging in as Non-Participant Transmission
Customers.
In general, Non-Participant Transmission Customers must provide additional
financial assurance in the following amounts, based on their average or expected
monthly charges for service under the Tariff, including amounts owed to ISO New
England Inc. under the ISO Tariff (collectively the "NEPOOL Charges"):
Monthly NEPOOL Charges Financial Assurance Requirement
$0 - $15,000 0 months' NEPOOL Charges
$15,001 - $30,000 1 month's NEPOOL Charges
$30,001 - $50,000 2 months' NEPOOL Charges
$50,001 or more 31/2 months' NEPOOL Charges
The three and one-half months is based on the time required for a FERC filing
made by NEPOOL to suspend service to be effective.
Therefore, a Non-Participant Transmission Customer with $32,000 in monthly
NEPOOL Charges that does not satisfy the rating requirement or NEPOOL credit
review process must provide additional financial assurances in the amount of
$64,000 to NEPOOL.
In the case of new Non-Participant Transmission Customers, the Financial
Assurance Requirement will be based on estimated monthly NEPOOL Charges, which
estimate NEPOOL has the right to adjust in light of subsequent experience as to
actual monthly NEPOOL Charges. In no event will the Financial Assurance
Requirement exceed the anticipated charge for the service requested by the
Non-Participant Transmission Customer.
Cash Deposit
A cash deposit for the full value of the Financial Assurance Requirement based
on actual or anticipated NEPOOL Charges, as determined by NEPOOL, provides an
acceptable form of financial assurance to NEPOOL. A cash deposit greater than or
equal to one month's NEPOOL Charges of a Non-Participant Transmission Customer
shall also serve as that Non-Participant Transmission Customer's deposit under
Sections 31.3 and 41.2 of the Tariff.
If it is necessary to use all or a portion of the deposit to pay the Non-
Participant Transmission Customer's obligation, the deposit must be promptly
replenished to the required level; otherwise, termination of service proceedings
may be initiated. In the event that actual NEPOOL Charges exceed those
anticipated, the anticipated charges will be increased accordingly and the
Non-Participant Transmission Customer must augment its cash deposit to reach the
required level.
The cash deposit will be invested by NEPOOL in investments as may be designated
by the Non-Participant Transmission Customer in direct obligations of the United
States or its agencies and interest earned will be paid to the Non-Participant
Transmission Customer. NEPOOL may sell or otherwise liquidate such investments
at its discretion to meet the Non-Participant Transmission Customer's
obligations to NEPOOL.
The requirement to continue the deposit may be reviewed by NEPOOL after one
year. Consideration will be given to replacing the cash deposit with a corporate
guaranty if certain conditions are met, as discussed below in the Corporate
Guaranty section.
Letter of Credit
An irrevocable standby letter of credit for the full value of the Financial
Assurance Requirement based on actual or anticipated NEPOOL Charges, as
determined by NEPOOL, provides an acceptable form of financial assurance to
NEPOOL. The letter of credit will renew automatically unless the issuing bank
provides notice to NEPOOL at least ninety (90) days prior to the letter of
credit's expiration of the bank's decision not to renew the letter of credit.
If the letter of credit amount falls below the required level because of a
drawing, it must be replenished immediately; otherwise, termination of service
proceedings may be initiated by NEPOOL. If actual NEPOOL Charges exceed those
anticipated, the Non-Participant Transmission Customer must obtain a substitute
letter of credit that equals the actual NEPOOL Charges.
The form, substance, and provider of the letter of credit must all be acceptable
to NEPOOL. The letter of credit should clearly state the full names of the
"Issuer," "Account Party" and "Beneficiary" (NEPOOL), the dollar amount
available for drawings, and should include a statement required on the drawing
certificate and other terms and conditions that should apply. It should also
specify that funds will be disbursed, in accordance with the instructions,
within one (1) business day after due presentation of the drawing certificate.
The bank issuing the letter of credit must have a minimum corporate debt rating
of an "A-" by Standard & Poor's, or "A3" by Moody's, or "A-" by Duff & Phelps,
or "A-" by Fitch, or an equivalent short term debt rating by one of these
agencies.
Please refer to Attachment 1, which provides an example of a generally
acceptable sample "clean" letter of credit. All costs associated with obtaining
financial security and meeting the Policy provisions are the responsibility of
the Applicant or Non-Participant Transmission Customer.
The requirement to continue to provide a letter of credit may be reviewed by
NEPOOL after one year. Consideration will be given to replacing the letter of
credit with a corporate guaranty if certain conditions are met, as discussed
below in the Corporate Guaranty section.
Performance Bond
A performance bond complying with the requirements set forth herein provides an
acceptable form of financial assurance to NEPOOL. The penal sum of such
performance bond shall be in an amount equal to the full value of the Financial
Assurance Requirement based on actual or anticipated NEPOOL Charges, as
determined by NEPOOL, and shall automatically be adjusted to reflect any
adjustment in such Financial Assurance Requirement. The bond shall permit suit
thereunder until two years after the last date that service is provided to the
Non-Participant Transmission Customer under the Tariff.
If the amount of penal sum of the performance bond available to NEPOOL falls
below the required level because of a payment thereon, it must be increased to
the required level immediately; otherwise, termination of service proceedings
may be initiated by NEPOOL. If actual NEPOOL Charges exceed those anticipated,
the Non-Participant Transmission Customer must either cause the penal sum of
such performance bond to be increased accordingly or must obtain a substitute
performance bond in the appropriate amount.
The form, substance and provider of the performance bond must be acceptable to
NEPOOL. The performance bond should clearly state the full names of the
"Principal," the "Surety" and the "Obligee" (NEPOOL) and the penal sum and
should include a clear statement that the surety will promptly and faithfully
perform the Non-Participant Transmission Customer's obligations to NEPOOL if the
Non-Participant Transmission Customer fails to do so. The insurance company
issuing the performance bond must be rated "A" or better by A.M. Best & Co.
Please refer to Attachment 2, which provides an example of a generally
acceptable sample performance bond. All costs associated with obtaining
financial security and meeting the Policy provisions, including without
limitation the cost of the premiums for such performance bond, are the
responsibility of the Applicant or Non-Participant Transmission Customer.
The requirement to continue to provide a performance bond may be reviewed by
NEPOOL after one year. Consideration will given to replacing the performance
bond with a corporate guaranty if certain conditions are met, as discussed below
in the Corporate Guaranty section.
Weekly Payments
A Non-Participant Transmission Customer that does not satisfy the rating
requirement may request that, in lieu of providing one of the additional
financial assurances set forth above, a weekly billing schedule be implemented
for it. NEPOOL may, in its discretion, agree to such a request; provided,
however, that any weekly billing arrangement will terminate no more than six
months after the date on which such arrangement begins unless the
Non-Participant Transmission Customer requests an extension of such arrangement
and demonstrates to NEPOOL's satisfaction in its sole discretion that the
termination of such arrangement and compliance with the other provisions of this
Policy (including providing another form of financial assurance, if required)
will impose a substantial hardship on the Non- Participant Transmission
Customer. Such demonstration of a substantial hardship shall be made every six
months after the initial demonstration, and a Non-Participant Transmission
Customer's weekly billing arrangement will be terminated if it fails to
demonstrate to NEPOOL's satisfaction in its sole discretion at any such six
month interval that compliance with the other provisions of this Policy will
impose a substantial hardship on it.
If NEPOOL agrees to implement a weekly billing schedule for a Non-Participant
Transmission Customer, the Non-Participant Transmission Customer shall be billed
weekly in arrears on an estimated basis for all amounts owed to NEPOOL and the
System Operator for the week, with an adjustment for each month as part of the
regular NEPOOL monthly billing to reflect any under or over collection for the
month. The Non-Participant Transmission Customer shall be obligated to pay each
such weekly bill within five business days after it is received. The
Non-Participant Transmission Customer shall pay with respect to each weekly bill
an administrative fee, determined by the System Operator, to reimburse the
System Operator for the costs it incurs as a result of that Non-Participant
Transmission Customer's weekly billing arrangement.
If a weekly billing schedule is implemented for a Non-Participant Transmission
Customer in lieu of requiring the Non-Participant Transmission Customer to
provide an additional financial assurance, the Non-Participant Transmission
Customer may be required to provide an additional financial assurance at any
time if the Non-Participant Transmission Customer fails to pay when due any
weekly bill or, in its sole discretion, termination of service proceedings may
be initiated by NEPOOL. In addition, upon the termination of a Non-Participant
Transmission Customer's weekly billing arrangement, the Non-Participant
Transmission Customer shall either satisfy the rating requirement set forth
herein or provide one of the other forms of financial assurance set forth
herein.
Use of Transaction Setoffs
Under certain conditions, NEPOOL may be involved in other transactions with a
Non-Participant Transmission Customer in which NEPOOL is the buyer. In this
event, the amount of the prepayment, cash deposit, performance bond or letter of
credit required hereunder may be reduced ("setoff") by an amount equal to
NEPOOL's unpaid balance or expected billing under the other transaction. The
terms and the amount of the setoff must be approved by the System Operator. The
System Operator is responsible for monitoring the status of the setoff and
ensuring that an adequate financial assurance balance is maintained at all times
until the transaction is settled.
Corporate Guaranty
An irrevocable corporate guaranty obtained from a Non-Participant Transmission
Customer's affiliated company ("Guarantor") for the full value of the Financial
Assurance Requirement based on actual or anticipated NEPOOL Charges, as
determined by NEPOOL, may provide an acceptable form of financial assurance to
NEPOOL.
If actual NEPOOL Charges exceed those anticipated, the Non-Participant
Transmission Customer must provide a substitute corporate guaranty that equals
the actual NEPOOL Charges.
A Non-Participant Transmission Customer for which a letter of credit,
performance bond or cash deposit was initially required may have the opportunity
to substitute a corporate guaranty if the following conditions are met:
1. NEPOOL determines that the Non-Participant Transmission Customer has
satisfactorily met its payment obligations in NEPOOL for at least one year,
which one-year period may in whole or in part pre-date the Policy Effective
Date;
2. NEPOOL determines that the financial condition of the Guarantor meets the
requirements of this Policy; and
3. The form and substance of the corporate guaranty are acceptable to
NEPOOL.
Upon NEPOOL's written authorization, the Non-Participant Transmission Customer
may substitute a corporate guaranty that is issued by the Guarantor for a cash
deposit, bank letter of credit or performance bond when it has satisfied the
conditions stipulated above. The corporate guaranty is considered to be a lesser
form of financial assurance than a cash deposit, letter of credit or performance
bond, and therefore is allowed as an acceptable form of financial assurance only
to those Non-Participant Transmission Customers that have satisfied their
payment obligations to NEPOOL in a timely manner for at least one year.
The corporate guaranty may only be used if the Non-Participant Transmission
Customer is affiliated with a Guarantor that has greater financial assets, a
strong balance sheet and income statements, and at minimum an investment grade
rating by either Standard & Poor's, Moody's, Duff & Phelps, or Fitch.
The corporate guaranty should clearly state the identities of the "Guarantor,"
"Beneficiary" and "Obligor," and the relationship between the Guarantor and the
Non-Participant Transmission Customer Obligor. The corporate guaranty must be
duly authorized by the Guarantor, must be signed by an officer of the Guarantor,
and must be furnished with either an opinion satisfactory to NEPOOL of the
Guarantor's counsel with respect to the enforceability of the guaranty or
accompanied by a certificate of corporate guarantee that includes a seal of the
corporation with the signature of the corporate secretary. Additionally,
adequate documentation regarding the signature authority of the person signing
the corporate guaranty must be provided with the corporate guaranty.
A corporate guaranty must also obligate the Guarantor to submit a current rating
agency report promptly upon the request of NEPOOL, to submit 8-K Reports
promptly upon their issuance, to submit financial reports if and as requested by
NEPOOL within ten (10) days of such request, and to inform NEPOOL in writing
within ten (10) business days of any material change in its financial status. A
material change in financial status includes, but is not limited to, the
following: a downgrade to a below investment grade rating of senior long term
debt by a major rating agency, being placed on credit watch with negative
implication by a major rating agency if senior long term debt does not have an
investment grade rating, a bankruptcy filing, insolvency, a report of a
significant quarterly loss or decline of earnings, the resignation of key
officer(s), and/or the filing of a material lawsuit that could materially
adversely impact current or future financial results. A Guarantor's failure to
provide this information may result in proceedings by NEPOOL to terminate
service to the Non-Participant Transmission Customer Obligor. If there is a
material adverse change in the financial condition of the Guarantor, NEPOOL may
require the Non-Participant Transmission Customer Obligor to provide another
form of financial assurance, either a cash deposit or a letter of credit or a
performance bond.
Non-payment of Amounts Due
If a Non-Participant Transmission Customer does not pay amounts billed when due
and as a result a letter of credit or cash deposit is drawn down or a
performance bond is paid on, then the Non-Participant Transmission Customer must
immediately replenish the letter of credit or cash deposit to the required
amount or cause the penal sum of the performance bond to be increased to equal
the required amount plus all amounts paid thereunder. If a Non-Participant
Transmission Customer fails to do so, NEPOOL may initiate termination of service
proceedings against the
Non-Participant Transmission Customer in accordance with the procedure for
payment defaults set forth in Section 8.4 of the Tariff.
In order to encourage prompt payment of NEPOOL Charges by Non-Participant
Transmission Customers, if a Non-Participant Transmission Customer is delinquent
in paying on time its NEPOOL Charges, the Non-Participant Transmission Customer
shall pay interest on any unpaid amount as provided in Section 8.3 of the
Tariff.
ATTACHMENT 1
SAMPLE LETTER OF CREDIT
[DATE PROVIDED]
IRREVOCABLE STANDBY LETTER OF CREDIT NO.
[EXPIRATION DATE] AT OUR COUNTERS [unless an evergreen l/c is obtained]
WE DO HEREBY ISSUE AN IRREVOCABLE NON-TRANSFERABLE STANDBY LETTER OF CREDIT BY
ORDER OF AND FOR THE ACCOUNT OF ON BEHALF OF [NON- PARTICIPANT TRANSMISSION
CUSTOMER] ("ACCOUNT PARTY") IN FAVOR OF THE PARTICIPANTS IN THE NEW ENGLAND
POWER POOL ("NEPOOL") IN AN AMOUNT NOT EXCEEDING US$ .00 (UNITED STATES DOLLARS
AND 00/100) AGAINST PRESENTATION TO US OF A DRAWING CERTIFICATE SIGNED BY A
PURPORTED OFFICER OR AUTHORIZED AGENT OF NEPOOL AND DATED THE DATE OF
PRESENTATION CONTAINING THE FOLLOWING STATEMENT:
"THE UNDERSIGNED HEREBY CERTIFIES TO [BANK] ("BANK"), WITH REFERENCE TO
IRREVOCABLE NON-TRANSFERABLE STANDBY LETTER OF CREDIT NO. ISSUED BY [BANK] IN
FAVOR OF THE PARTICIPANTS IN THE NEW ENGLAND POWER POOL ("NEPOOL") THAT
[NON-PARTICIPANT TRANSMISSION CUSTOMER] HAS FAILED TO PAY AMOUNTS DUE UNDER THE
RESTATED NEPOOL OPEN ACCESS TRANSMISSION TARIFF OR THE ISO NEW ENGLAND INC.
TARIFF FOR TRANSMISSION DISPATCH AND POWER ADMINISTRATION SERVICES, AND THUS
NEPOOL IS DRAWING UPON THE LETTER OF CREDIT IN AN AMOUNT EQUAL TO $ ."
IF PRESENTATION OF ANY DRAWING CERTIFICATE IS MADE ON A BUSINESS DAY AND SUCH
PRESENTATION IS MADE AT OUR COUNTERS ON OR BEFORE 10:00 A.M. TIME, WE SHALL
SATISFY SUCH DRAWING REQUEST ON THE SAME BUSINESS DAY. IF THE DRAWING
CERTIFICATE IS RECEIVED AT OUR COUNTERS AFTER 10:00 A.M. TIME, WE WILL SATISFY
SUCH DRAWING REQUEST ON THE NEXT BUSINESS DAY, FOR THE PURPOSES OF THIS SECTION,
A BUSINESS DAY MEANS A DAY, OTHER THAN A SATURDAY OR SUNDAY, ON WHICH COMMERCIAL
BANKS ARE NOT AUTHORIZED OR REQUIRED TO BE CLOSED IN NEW YORK, NEW YORK.
DISBURSEMENTS SHALL BE IN ACCORDANCE WITH THE INSTRUCTIONS OF NEPOOL.
THE FOLLOWING TERMS AND CONDITIONS APPLY:
THIS LETTER OF CREDIT SHALL EXPIRE AT THE CLOSE OF BUSINESS [DATE]. WE WILL
PROVIDE NOTICE TO NEPOOL AT LEAST 90 DAYS PRIOR TO SUCH DATE IF THIS LETTER OF
CREDIT WILL NOT BE RENEWED AS OF SUCH DATE [or: THIS LETTER OF CREDIT SHALL
EXPIRE ONLY UPON THE FOLLOWING CONDITIONS: (1) WHEN FULL PAYMENT HAS BEEN
RECEIVED BY NEPOOL FROM [NON-PARTICIPANT TRANSMISSION CUSTOMER] AND (2) NEPOOL
HAS PROVIDED A WRITTEN RELEASE TO THIS BANK .]
THE AMOUNT WHICH MAY BE DRAWN BY YOU UNDER THIS LETTER OF CREDIT SHALL BE
AUTOMATICALLY REDUCED BY THE AMOUNT OF ANY UNREIMBURSED DRAWINGS HEREUNDER AT
OUR COUNTERS. ANY NUMBER OF PARTIAL DRAWINGS ARE PERMITTED FROM TIME TO TIME
HEREUNDER.
ALL COMMISSIONS AND CHARGES WILL BE BORNE BY THE ACCOUNT PARTY.
THIS LETTER OF CREDIT IS NOT TRANSFERABLE OR ASSIGNABLE.
THIS LETTER OF CREDIT DOES NOT INCORPORATE AND SHALL NOT BE DEEMED MODIFIED,
AMENDED OR AMPLIFIED BY REFERENCE TO ANY DOCUMENT, INSTRUMENT OR AGREEMENT (A)
THAT IS REFERRED TO HEREIN (EXCEPT FOR THE UCP, AS DEFINED BELOW) OR (B) IN
WHICH THIS LETTER OF CREDIT IS REFERRED TO OR TO WHICH THIS LETTER OF CREDIT
RELATES.
THIS LETTER OF CREDIT SHALL BE GOVERNED BY THE UNIFORM CUSTOMS AND PRACTICE FOR
DOCUMENTARY CREDITS, 1993 REVISION, INTERNATIONAL CHAMBER OF COMMERCE
PUBLICATION NO. 500 (THE "UCP"), EXCEPT TO THE EXTENT THAT TERMS HEREOF ARE
INCONSISTENT WITH THE PROVISIONS OF THE UCP, INCLUDING BUT NOT LIMITED TO
ARTICLES 13(b) AND 17 OF THE UCP, IN WHICH CASE THE TERMS OF THE LETTER OF
CREDIT SHALL GOVERN.
THIS LETTER OF CREDIT MAY NOT BE AMENDED, CHANGED OR MODIFIED WITHOUT THE
EXPRESS WRITTEN CONSENT OF NEPOOL AND US.
WE HEREBY ENGAGE WITH YOU THAT DOCUMENTS DRAWN UNDER AND IN COMPLIANCE WITH THE
TERMS OF THIS LETTER OF CREDIT SHALL BE DULY HONORED UPON PRESENTATION AS
SPECIFIED.
PRESENTATION OF ANY DRAWING CERTIFICATE UNDER THIS STANDBY LETTER OF CREDIT MAY
BE SENT TO US BY COURIER, CERTIFIED MAIL, REGISTERED MAIL, TELEGRAM, TELEX TO
THE ADDRESS SET FORTH BELOW, OR SUCH OTHER ADDRESS AS MAY HEREAFTER BE FURNISHED
BY US. OTHER NOTICES CONCERNING THIS STANDBY LETTER OF CREDIT MAY BE SENT BY
FACSIMILE OR SIMILAR COMMUNICATIONS FACILITY TO THE RESPECTIVE ADDRESSES SET
FORTH BELOW. ALL SUCH NOTICES AND COMMUNICATIONS SHALL BE EFFECTIVE WHEN
ACTUALLY RECEIVED BY THE INTENDED RECIPIENT PARTY.
IF TO THE BENEFICIARY OF THIS LETTER OF CREDIT:
IF TO THE ACCOUNT PARTY:
IF TO US:
[signature]
[signature]
ATTACHMENT 2
SAMPLE PERFORMANCE BOND
[Insurance Company]
Bond No.
KNOW ALL MEN BY THESE PRESENTS, That the undersigned [Non-Participant
Transmission Customer], of [Non-Participant Transmission Customer's address]
hereinafter referred to as the Principal, and [insurance company], a corporation
organized and existing under the laws of the State of [insurance company's state
of incorporation], as Surety, are held and firmly bound unto the Participants in
the New England Power Pool as obligees, hereinafter referred to collectively as
the Obligee, in the sum of , lawful money of the United States of America (which
sum shall automatically be adjusted to reflect any adjustment in the Financial
Assurance Requirement applicable to the Principal under the New England Power
Pool's Financial Assurance Policy for NEPOOL Non-Participant Transmission
Customers, as in effect from time to time) for the payment of which sum, well
and truly to be made, we bind ourselves, our executors, administrators,
successors, and assigns, jointly and severally, firmly by these presents.
WHEREAS, the Principal has entered into agreements for the purchase and sale of
electric services under the Restated NEPOOL Open Access Transmission Tariff and
the ISO New England Inc. Tariff for Transmission Dispatch and Power
Administration Services, each as amended from time to time (collectively
referred to as the "Agreements"), and in strict accordance with their respective
terms.
NOW, THEREFORE, the condition of this obligation is such, that if the Principal
shall promptly and faithfully make the payments required by, and comply with
terms of, the Agreements which have been or may hereafter be in force and shall
save and keep harmless the Obligee from all loss or damage which it may sustain
or for which it may become liable on account of the issuance of said Agreements
to the Principal, then this obligation shall be void; otherwise, it shall remain
in full force and effect.
Upon notice from ISO New England Inc. of nonpayment by the Principal, Surety
will pay to ISO New England Inc., as agent for the Obligee, the amounts owed
by the Principal under the Agreements.
The Surety hereby waives notice of any alteration or extension of time made by
the Obligee.
Any suit on this bond must be instituted before the expiration of two (2) years
from the date on which the Principal's obligations under the Agreements expires.
SIGNED, SEALED AND DATED this day of ,
19 .
[Seal]
[Non-Participant Transmission Customer]
Principal
By:
[Seal]
[Insurance Company]
Surety
By:
ATTACHMENT 3
CORPORATE GUARANTY
For and in consideration of the credit advance or sale of products on open
account by the New England Power Pool Participants from time to time
("Participants") to [Non-Participant Transmission Customer] ("Company"), the
undersigned guarantor, ("Guarantor"), the [subsidiary/affiliate] of Company,
hereby unconditionally and irrevocably guarantees the prompt and complete
payment of all amounts that Company now or hereafter owes to Participants under
the Restated NEPOOL Open Access Transmission Tariff (the "Tariff") and the ISO
New England Inc. Tariff for Transmission Dispatch and Power Administration
Services (the "ISO Tariff"), and performance by Company of any other agreements,
whether now existing or hereafter arising, between Company and Participants, as
amended from time to time (collectively referred to as the "Agreements"), in
strict accordance with their respective terms.
1. If Company does not perform its obligations in strict accordance with the
Agreements, Guarantor shall immediately pay all amounts now or hereafter due
thereunder (including, without limitation, all principal, interest, and fees)
and otherwise proceed to complete the same and satisfy all of Company's
obligations under the Agreements. This Guaranty may be satisfied by Guarantor
paying and/or performing (as appropriate) Company's obligations or by Guarantor
causing Company's obligations to be paid or performed; provided, however, that
Guarantor shall at all times remain fully responsible and liable for its
obligations hereunder notwithstanding any such payment or performance (or
failure thereof) by any third party. Participants will undertake commercially
reasonable efforts to notify Guarantor of a failure by Company to make a payment
or perform its obligations under the Agreements; provided, however, that failure
by Participants to so notify Guarantor shall not defeat, limit or otherwise
affect the rights and obligations of Participants, Company or Guarantor. Subject
to the terms and conditions set forth herein, Guarantor's obligations hereunder
shall not exceed the complete payment of all amounts that Company now or
hereafter owes to Participants under the Agreements and performance by Company
of the Agreements in strict accordance with their respective terms.
2. This Guaranty is an absolute, unconditional and continuing guaranty of the
full and punctual payment and performance by Company of each of its obligations
under the Agreements, and not of collectibility only, and is in no way
conditioned upon any requirement that Participants first attempt to collect
payment from Company or any other guarantor or surety or resort to any security
or other means of obtaining payment of all or any part of Company's obligations
or upon any other contingency. This is a continuing guaranty and shall be
binding upon Guarantor until the full, final and irrevocable payment and
performance of all of Company's obligations under the Agreements, regardless of
(i) how long after the date hereof any part of the obligations under the
Agreements is incurred by Company and (ii) the amount of the obligations under
the Agreements at any time outstanding. This Guaranty may be enforced by
Participants from time to time and as often as occasion for such enforcement may
arise.
3. The obligations hereunder are independent of the obligations of Company, and
a separate action or actions may be brought and prosecuted against Guarantor
whether action is brought against Company or whether Company be joined in any
such action or actions. Guarantor's liability under this Guaranty is not
conditioned or contingent upon genuineness, validity, regularity or
enforceability of the Agreements.
4. Guarantor authorizes Participants, without notice or demand and without
affecting its liability hereunder, from time to time to (a) renew, extend, or
otherwise change the terms of the Agreements or any part thereof, (b) take and
hold security for the payment of the Agreements, and exchange, enforce, waive
and release any such security; and (c) apply such security and direct the order
or manner of sale thereof as Participants in their sole discretion may
determine. The obligations and liabilities of Guarantor hereunder shall be
absolute and unconditional, shall not be subject to any counterclaim, set-off,
deduction or defense based upon any claim Guarantor may have against Company,
any other guarantor, or any other person or entity, and shall remain in full
force and effect until all of the obligations hereunder and under the Agreements
have been fully satisfied, without regard to, or release or discharge by, any
event, circumstance or condition (whether or not Guarantor shall have knowledge
or notice thereof) which but for the provisions of this Section might constitute
a legal or equitable defense or discharge of a guarantor or surety or which
might in any way limit recourse against Guarantor, including without limitation:
(a) any amendment or modification of, or supplement to, the terms of the
Agreements; (b) any waiver, consent or indulgence by Participants, or any
exercise or non-exercise by Participants of any right, power or remedy, under or
in respect of this Guaranty or the Agreements (whether or not Guarantor or
Company has or have notice or knowledge of any such action or inaction); (c) the
invalidity or unenforceability, in whole or in part, of the Agreements, or the
termination (except pursuant to its terms or by written agreement between
Participants and Company), cancellation or frustration of any thereof, or any
limitation or cessation of Company's liability under any thereof (other than any
limitation or cessation expressly provided for therein), including without
limitation any invalidity, unenforceability or impaired liability resulting from
Company's lack of capacity, power and/or authority to enter into the Agreements
and/or to incur any or all of the obligations thereunder, or from the execution
and delivery of any Agreement by any person acting for Company without or in
excess of authority (except to the extent the same would limit or cease
Company's liability under the Agreements); (d) any actual, purported or
attempted sale, assignment or other transfer by Participants of any Agreement or
of any of its rights, interests or obligations thereunder; (e) the taking or
holding by Participants of a security interest, lien or other encumbrance in or
on any property as security for any or all of the obligations of Company under
the Agreements or any exchange, release, non-perfection, loss or alteration of,
or any other dealing with, any such security; (f) the addition of any party as a
guarantor or surety of all or any part of the obligations of Company under the
Agreements; (g) any merger, amalgamation or consolidation of Company into or
with any other entity, or any sale, lease, transfer or other disposition of any
or all of Company's assets or any sale, transfer or other disposition of any or
all of the shares of capital stock or other securities of Company to any other
person or entity; (h) any change in the financial condition of Company or (as
applicable) of any subsidiary, affiliate, partner or controlling shareholder
thereof, or Company's entry into an assignment for the benefit of creditors, an
arrangement or any other agreement or procedure for the restructuring of its
liabilities, or Company's insolvency, bankruptcy, reorganization, dissolution,
liquidation or any similar action by or occurrence with respect to Company.
5. Guarantor unconditionally waives, to the fullest extent permitted by law: (a)
notice of any of the matters referred to in Section 4 hereof; (b) any right to
the enforcement, assertion or exercise by Participants of any of their rights,
powers or remedies under, against or with respect to (i) any of the Agreements,
(ii) any other guarantor or surety, or (iii) any security for all or any part of
the obligations of Company under the Agreements or obligations of Guarantor
hereunder; (c) any requirement of diligence and any defense based on a claim of
laches; (d) all defenses which may now or hereafter exist by virtue of any
statute of limitations, or of any stay, valuation, exemption, moratorium or
similar law, except the sole defense of full and indefeasible payment; (e) any
requirement that Guarantor be joined as a party in any action or proceeding
against Company to enforce any of the provisions of the Agreements; (f) any
requirement that Participants mitigate or attempt to mitigate damages resulting
from a default by Guarantor hereunder or from a default by Company under any of
the Agreements; (g) acceptance of this Guaranty by Participants; and (h) all
presentments, protests, notices of dishonor, demands for performance and any and
all other demands upon and notices to Company, and any and all other formalities
of any kind, the omission of or delay in performance of which might but for the
provisions of this Section constitute legal or equitable grounds for relieving
or discharging Guarantor in whole or in part from its irrevocable, absolute and
continuing obligations hereunder, it being the intention of Guarantor that its
obligations hereunder shall not be discharged except by payment and performance
and then only to the extent thereof.
6. Guarantor waives any right to require Participants to (a) proceed against
Company; (b) proceed against or exhaust any security held from Company; or (c)
pursue any other remedy in Participants' power whatsoever. So long as any
obligations remain outstanding under this Guaranty or the Agreements, Guarantor
shall not exercise any rights against Company arising as a result of payment by
Guarantor hereunder, by way of subrogation or otherwise, and will not prove any
claim in competition with Participants or their affiliates in respect of any
payment under the Agreements in bankruptcy or insolvency proceedings of any
nature; Guarantor will not claim any set-off or counterclaim against Company in
respect of any liability of Guarantor to Company and Guarantor waives any
benefit of any right to participate in any collateral which may be held by
Participants or any of their affiliates. Guarantor shall have no right of
subrogation or reimbursement, contribution or other rights against Company.
7. If after receipt of any payment of, or the proceeds of any collateral for,
all or any part of the obligations of Company under the Agreements, Participants
are compelled to surrender or voluntarily surrender such payment or proceeds to
any person because such payment or application of proceeds is or may be avoided,
invalidated, recaptured, or set aside as a preference, fraudulent conveyance,
impermissible setoff or for any other reason, whether or not such surrender is
the result of (i) any judgment, decree or order of any court or administrative
body having jurisdiction over Participants, or (ii) any settlement or compromise
by Participants of any claim as to any of the foregoing with any person
(including Company), then the obligations of Company under the Agreements, or
part thereof affected, shall be reinstated and continue and this Guaranty shall
be reinstated and continue in full force as to such obligations or part thereof
as if such payment or proceeds had not been received, notwithstanding any
previous cancellation of any instrument evidencing any such obligation or any
previous instrument delivered to evidence the satisfaction thereof. The
provisions of this Section shall survive the termination of this Guaranty and
any satisfaction and discharge of Company by virtue of any payment, court order
or any federal or state law until the full, final and irrevocable satisfaction
of all of Company's obligations under the Agreements.
8. Any indebtedness of Company now or hereafter held by Guarantor is hereby
subordinated to any indebtedness of Company to Participants; and such
indebtedness of Company to Guarantor shall be collected, enforced and received
by Guarantor as trustee for Participants and be paid over to Participants on
account of the indebtedness of Company due and owing at any time to Participants
but without reducing or affecting in any manner the liability of Guarantor under
the other provisions of this Guaranty.
9. Guarantor represents and warrants to Participants, as an inducement to
Participants to make the credit advances or sales of products on open account
to Company, that:
a. the execution, delivery and performance by Guarantor of this Guaranty (i) are
within Guarantor's powers and have been duly authorized by all necessary action;
(ii) do not contravene Guarantor's charter documents or any law or any material
contractual restrictions binding on or affecting Guarantor or by which
Guarantor's property may be affected; and (iii) do not require any authorization
or approval or other action by, or any notice to or filing with, any public
authority or any other person except such as have been obtained or made;
b. this Guaranty constitutes the legal, valid and binding obligation of
Guarantor, enforceable in accordance with its terms, except as the
enforceability thereof may be subject to or limited by bankruptcy, insolvency,
reorganization, arrangement, moratorium or other similar laws relating to or
affecting the rights of creditors generally and by general principles of equity;
and
c. there is no action, suit or proceeding affecting Guarantor pending or
threatened before any court, arbitrator, or public authority that may materially
adversely affect Guarantor's ability to perform its obligations under this
Guaranty, except as set forth in writing to the Participants and ISO New England
Inc. prior to Participants' written authorization of this Guaranty.
10. Guarantor shall submit to Participants (i) a current credit rating agency
report regarding Guarantor promptly upon the request of Participants, (ii) a
copy of any Report on Form 8-K promptly after the filing by Guarantor of such
report with the Securities and Exchange Commission, and (iii) a balance sheet,
statement of income and such other financial statements of Guarantor as
Participants shall reasonably request within ten (10) days after such statements
are requested by Participants. Guarantor shall notify Participants in writing
within ten (10) days after a material change in the financial status of
Guarantor. For purposes of this section, a material change in financial status
includes, but is not limited to, the following: (a) a downgrade to a below
investment grade rating in the rating of Guarantor's senior long-term debt by a
major rating agency; (b) the placement of Guarantor on credit watch with
negative implication by a major credit rating agency if Guarantor's senior
long-term debt does not have an investment grade rating; (c) Guarantor's
bankruptcy or insolvency; (d) a report by Guarantor of a significant quarterly
loss or decline in earnings; (e) the resignation of a key officer of Guarantor;
and (e) the filing of a lawsuit that could materially adversely impact
Guarantor's current or future financial results. Guarantor acknowledges that
failure by it to provide the information required hereunder may result in
Participants bringing proceedings to terminate service to Company in accordance
with the procedure set forth for payment defaults in Section 8.4 of the Tariff.
11. Guarantor agrees to pay on demand all reasonable attorneys' fees and all
other costs and expenses which may be incurred by Participants in the
enforcement of this Guaranty. No terms or provisions of this Guaranty may be
changed, waived, revoked or amended without Participants' prior written consent.
Should any provision of this Guaranty be determined by a court of competent
jurisdiction to be unenforceable, all of the other provisions shall remain
effective. This Guaranty embodies the entire agreement among the parties hereto
with respect to the matters set forth herein, and supersedes all prior
agreements among the parties with respect to the matters set forth herein. No
course of prior dealing among the parties, no usage of trade, and no parol or
extrinsic evidence of any nature shall be used to supplement, modify or vary any
of the terms hereof. There are no conditions to the full effectiveness of this
Guaranty. Participants may assign this Guaranty without in any way affecting
Guarantor's liability under it, except that Guarantor shall be provided
reasonable notice of any such assignment. This Guaranty shall inure to the
benefit of Participants and their successors and assigns. This Guaranty is in
addition to the guaranties of any other guarantors and any and all other
guaranties of Company's indebtedness or liabilities to Participants.
12. This Guaranty shall be governed by the laws of the State of Connecticut,
without regard to conflicts of laws principles. Guarantor hereby irrevocably
submits to the jurisdiction of any Connecticut State or United States Federal
court sitting in Connecticut over any action or proceeding arising out of or
relating to this Guaranty or any of the Agreements, and Guarantor hereby
irrevocably agrees that all claims in respect of such action or proceeding may
be heard and determined in such Connecticut State or Federal court. Guarantor
irrevocably consents to the service of any and all process in any such action or
proceeding by the mailing of copies of such process to Guarantor at its address
set forth below its signature. Guarantor agrees that a final judgment in any
such action or proceeding shall be conclusive and may be enforced in other
jurisdictions by suit on the judgment or in any other manner provided by law.
Guarantor further waives any objection to venue in such State and any objection
to an action or proceeding in such State on the basis of forum non conveniens.
Guarantor further agrees that any action or proceeding brought against
Participants shall be brought only in Connecticut State or United States Federal
courts sitting in Connecticut. Nothing herein shall affect the right of
Participants to bring any action or proceeding against the Guarantor or its
property in the courts of any other jurisdictions.
13. GUARANTOR ACKNOWLEDGES THAT IT HAS BEEN ADVISED BY COUNSEL OF ITS CHOICE
WITH RESPECT TO THIS GUARANTY AND THAT IT MAKES THE FOLLOWING WAIVERS KNOWINGLY
AND VOLUNTARILY:
a. GUARANTOR IRREVOCABLY WAIVES TRIAL BY JURY IN ANY COURT AND IN ANY SUIT,
ACTION OR PROCEEDING OR ANY MATTER ARISING IN CONNECTION WITH OR IN ANY WAY
RELATED TO THE TRANSACTIONS CONTEMPLATED BY THIS GUARANTY, THE AGREEMENTS OR ANY
DOCUMENTS RELATED THERETO (INCLUDING CONTRACT CLAIMS, TORT CLAIMS, BREACH OF
DUTY CLAIMS, AND ALL OTHER COMMON LAW OR STATUTORY CLAIMS) AND THE ENFORCEMENT
OF ANY OF PARTICIPANTS' RIGHTS AND REMEDIES; AND
b. GUARANTOR EXPRESSLY ACKNOWLEDGES THAT THE OBLIGATIONS GUARANTEED HEREBY ARE
PART OF A COMMERCIAL TRANSACTION AS SUCH TERM IS USED AND DEFINED IN CHAPTER
903a OF THE CONNECTICUT GENERAL STATUTES AND VOLUNTARILY AND KNOWINGLY WAIVES
ANY AND ALL RIGHTS WHICH ARE OR MAY BE CONFERRED UPON IT UNDER CHAPTER 903a OF
SAID STATUTES (OR ANY OTHER STATUTE AFFECTING PREJUDGMENT REMEDIES) TO ANY
NOTICE OR HEARING OR PRIOR COURT ORDER OR THE POSTING OF ANY BOND PRIOR TO ANY
PREJUDGMENT REMEDY WHICH PARTICIPANTS MAY USE.
14. Any demand, notice, request, instruction or other communication to be given
hereunder by any party to another party shall be in writing and delivered
personally, by nationally recognized overnight courier, by certified mail,
postage prepaid and return receipt requested, by telegram, or by telecopier, as
follows:
If to Guarantor, at:
If to Participants, at:
Communications given by personal delivery or mail shall be effective upon
actual receipt. Communications given by telegram or telecopier shall be
effective upon actual receipt during the recipient's normal business hours, or
at the beginning of the next business day after receipt if not received during
the recipient's normal business hours. All communications by telegram or
telecopier shall be confirmed promptly in writing by certified mail or personal
delivery. Any party may change any address to which communications are to be
given by giving notice as provided above of such change of address.
IN WITNESS WHEREOF, the undersigned Guarantor has executed this Guaranty as
of this day of [month], 199_.
[GUARANTOR]
By:
Title:
Corporate Officer
Address:
ATTACHMENT N
New England Power Pool Billing Policy
This New England Power Pool ("NEPOOL") Billing Policy (the "Policy") shall
become effective on the later of (i) the Second Effective Date or (ii) the
date that is sixty (60) days after the filing of this Policy with the Federal
Energy Regulatory Commission. (FN1)
SECTION 1 - OVERVIEW
Section 1.1 - Scope. The objective of this Policy is to define the billing and
payment procedures to be utilized in administering charges and payments due
under the NEPOOL Agreement, the NEPOOL Tariff, the Interim Independent System
Operator Agreement (the "Interim ISO Agreement") between NEPOOL and ISO New
England Inc. (the "ISO"), the Amended and Restated Independent System Operator
Agreement between NEPOOL and the ISO, when such agreement becomes effective (the
"Amended ISO Agreement" and together with the Interim ISO Agreement, the "ISO
Agreement"), and the ISO's Tariff for Transmission Dispatch and Power
Administration Services (the "ISO Tariff"), in each case as amended, modified,
supplemented and restated from time to time (collectively, the
"Documents").(FN2) This Policy applies to the ISO, the NEPOOL Participants and
Non-Participant Transmission Customers for billing and payments procedures for
amounts due under the Documents, including without limitation those procedures
related to the seven markets administered by the ISO.
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(FN1) Capitalized terms used but not defined in this Policy are intended to have
the meanings given to such terms in Section 1 of the Restated NEPOOL Agreement
(the "NEPOOL Agreement") or Section 1 of the Restated NEPOOL Open Access
Transmission Tariff (the "NEPOOL Tariff"), in each case as amended from time to
time.
(FN2) Unless otherwise stated herein, the ISO will act as NEPOOL's agent in
administering, managing and enforcing this Policy.
Section 1.2 - Financial Transaction Conventions. The following conventions have
been adopted in defining sums of money to be paid or received under this Policy:
a) The term "Charge" refers to a sum of money due from a Participant or a
Non-Participant Transmission Customer to the ISO, either in its individual
capacity or as billing agent for the Participants.
b) The term "Payment" refers to a sum of money due to a Participant or
Non-Participant Transmission Customer from the ISO, as remitting agent for the
Participants. Amounts due to and from the ISO include amounts collected and paid
by the ISO as billing agent for the Participants.
c) Where a Participant's or a Non-Participant Transmission Customer's total
Charges exceed its total Payments in a month, the ISO shall issue an "Invoice"
for the net Charge owed by such Participant or Non-Participant Transmission
Customer.
d) Where a Participant's or a Non-Participant Transmission Customer's total
Payments exceed its total Charges in a month, the ISO shall issue a "Remittance
Advice" for the net Payment owed to the Participant or Non- Participant
Transmission Customer. Invoices and Remittance Advices are collectively referred
to herein as "Statements."
Section 1.3 - General Process. The billing process is performed monthly, except
in the case of (i) Participants and Non-Participant Transmission Customers who
have requested and received a weekly billing schedule in accordance with the
Financial Assurance Policy for NEPOOL Members or the Financial Assurance Policy
for NEPOOL Non-Participant Transmission Customers (collectively, the "Financial
Assurance Policies") and (ii) special billings, as described below. There are
two major steps in the billing process:
a) Statement Issuance. The ISO will issue an Invoice or Remittance Advice
showing the net amounts due from or owed to a Participant or a Non- Participant
Transmission Customer for the preceding calendar month. This Statement is
determined from the preliminary statements of the seven markets, applicable
Charges due under the Documents (including amounts due under the Financial
Assurance Policies), as well as any monthly adjustments. This Statement is
normally issued not earlier than the fifth (5th) Business Day nor later than the
fifteenth (15th) day after the end of the calendar month to which such Statement
relates.
b) Electronic Funds Transfer ("EFT"). EFTs related to Invoices and Remittance
Advices are performed in a two-step process, as described below, in which all
Invoices are paid first and all Remittance Advices are paid within two Business
Days later.
Section 1.4 - Special Billings. In addition to the regular monthly billing, the
ISO will issue special, extraordinary Statements as and when required under the
Documents or in order to adjust for special circumstances. Such Statements shall
be payable in accordance with the instructions set forth therein.
Section 1.5 - Conflicts with Documents. To the extent any provision hereof
conflicts with any provision of any Document, the provision in the Document
shall govern.
SECTION 2 - TIMING AND CONTENT OF STATEMENTS.
Section 2.1 - Normal Billing Cycle. The ISO shall provide to each Participant
and Non-Participant Transmission Customer on a monthly basis one Statement for
the previous calendar month or the portion thereof capable of being settled. The
ISO shall issue the Statement typically not earlier than the fifth (5th)
Business Day nor later than the fifteenth (15th) day following the end of the
calendar month to which such Statement relates (although nothing set forth
herein shall prohibit the ISO from issuing Statements between the first and
fifth Business Days of a month). If the Statement is not issued by the 15th day
of a month, the ISO shall delay the relevant funds transfer dates as described
below.
Section 2.2 - Provisions for Weekly Billing. The ISO shall implement any weekly
billing arrangements effected under the Financial Assurance Policies in
accordance therewith and with the procedures set forth below.
Section 2.3 - Contents of Statements. Each Statement will include all of the
following line items that are applicable to the Participant or Non- Participant
Transmission Customer receiving such Statement for the month to which such
Statement relates:
a) Invoice or Remittance Advice Amount. The net amount of all Charges and
Payments owed by or due to a Participant or a Non-Participant Transmission
Customer for the relevant Statement. The ISO shall issue an Invoice where the
Participant or Non-Participant Transmission Customer owes monies. The ISO shall
issue a Remittance Advice where the Participant or Non-Participant Transmission
Customer is owed monies.
b) NEPOOL Tariff Charges and Payments. The Charges owed by and the Payments
owed to the Participant or Non-Participant Transmission Customer under the
NEPOOL Tariff.
c) ISO Tariff Charges. The Charges owed by the Participant or Non-Participant
Transmission Customer under the ISO Tariff, categorized by the section or
schedule under which such Charges arise.
d) Markets Charges and Payments. The Charges owed by and the Payments owed
to the Participant as a result of transactions in each of the seven markets
administered by the ISO.
e) NEPOOL Expenses. The Participant's pro-rata share of Pool fees and
expenses as set forth in Section 19 of the NEPOOL Agreement.
f) Sanctions Charges. Any Charges assessed on the Participant pursuant to
Market Rule 13, the so-called Sanctions Rule.
g) Other Amounts due under the NEPOOL Agreement and the ISO Agreement. The
Charges owed by or the Payments owed to the Participant under the NEPOOL
Agreement and the ISO Agreement to the extent that those amounts are not
included in items (b) - (f) above.
h) Other Charges, Payments or Adjustments. Any other Charges, Payments, or
adjustments owed by or to the Participant or Non-Participant Transmission
Customer that are not included in items (b) - (g) above. These items may be due
to retroactive billing adjustments, late payment fees, penalties or other items
collectible under the Documents.
i) Billing Periods. The billing period (from and to dates) covered for each
line item on the Statement. The billing periods for the various line items are
not necessarily the same because of differences in timing of settlements (e.g.
the ICAP market may be two months in arrears while hourly markets may be one
month in arrears) and because of retroactive adjustments.
j) Payment Due Date and Time. If the Statement is an Invoice, the date and
time on which the net amount due is to be received by the ISO.
k) Wire Transfer Instructions. Details including the account number, bank name,
routing number and electronic transfer instructions which, in the case of an
Invoice, will be for the ISO account to which Charges owed by the Participant or
Non-Participant Transmission Customer are to be paid or, in the case of a
Remittance Advice, will be for the Participant's or Non- Participant
Transmission Customer's account to which the ISO shall remit Payments owed to
that Participant or Non-Participant Transmission Customer (as previously
provided to the ISO by such Participant or Non-Participant Transmission
Customer).
A sample Invoice is attached hereto as Attachment 1. A sample Remittance Advice
is attached hereto as Attachment 2.
Section 2.4 - Subsequent Adjustments to Previously Issued Statements.
a) Adjustments Requested by Participants. Participants supplying Network Load
and other input data to the ISO for use by the ISO in developing Statements
shall use reasonable care to assure that the data supplied is complete and
accurate. Should a Participant supplying input data subsequently determine that
the data supplied was incorrect, that Participant shall notify the ISO promptly
of the error and submit corrected data as soon as practicable. If the error is
detected and corrected data is provided within the time frames set forth below,
the ISO will issue corrected Statements to reflect the newly supplied data.
Type of Adjustment Corrected Data Must be
Submitted Within
Adjustments to Monthly Three (3) months from the
Network Load Submissions date the subject Statement
for that calendar month is
issued
Adjustments to EHV Three (3) months from the
and LV PTF Percentages for effective date of the
PTF Billing of Excepted modification to an
Transactions Submissions entitlement receiving EHV and
LV PTF billing
Adjustments to Three (3) months after the
Annual Average annual average Network Load
Network Load for the current NEPOOL Tariff
(12CP) Submissions year has been developed
Adjustments to Annual Revenue Three (3) months after the
Requirement Submissions applicable RNS rate has been
established
Adjustments to Three (3) months after the
Annual NEPOOL Schedule 1 applicable annual Schedule 1
Submissions rate has been established
If the data correction is not submitted within the applicable time frame set
forth above, the obligation of the ISO to issue corrected Statements reflecting
that adjustment shall be as set forth in a written re-billing protocol approved
by the Transmission Settlement Sub-committee (or such other NEPOOL committee as
the NEPOOL Participants Committee may determine) and posted on the ISO web-site.
The re-billing protocol shall provide, for each category of adjustment listed
above, whether and to what extent the adjustment shall be prospective or
retroactive and the timing of the adjustment. If the corrected data is not
submitted within the applicable time frame, the ISO may assess each Participant
submitting corrected data on an untimely basis its costs in generating and
issuing the corrected Statement. The written re-billing protocol shall include a
fee schedule for this purpose.
b) Adjustments Triggered by ISO Audit. The ISO will review the results of
internal and outsourced audits with the Transmission Settlement Subcommittee, or
such other NEPOOL committee as the NEPOOL Participants Committee may determine.
That Subcommittee, or other designated committee, will determine whether any
errors found are sufficiently significant to require a re- billing. The
reasonable costs to the ISO of the re-billing shall be allocated to Schedule 1
of the ISO Tariff.
c) Adjustments Reflecting Compliance with an Order of the Commission or other
Regulatory or Judicial Authority With Jurisdiction. Adjustments required to
effect compliance with an order of the Commission (or any other regulatory or
judicial authority with jurisdiction to interpret and/or enforce the provisions
of the Documents) shall be completed by the ISO in compliance with such order.
The costs of any such re-billing to the ISO shall be allocated among the NEPOOL
Participants in accordance with the provisions of Section 19.2 of the Restated
NEPOOL Agreement.
SECTION 3 - PAYMENT PROCEDURES.
All Payments made by the ISO will in all instances be made by EFT or in
immediately available funds payable to the account designated to the ISO by the
Participant or Non-Participant Transmission Customer to which such Payment is
due. Payments made by Participants or Non-Participant Transmission Customers
shall be made by EFT to the account designated by the ISO.
Section 3.1 - Invoice Payments.
a) Payment Date. Except in the case of weekly billings and special billings, all
Charges due shall be paid to and received by the ISO not later than the first
(1st) Business Day after the nineteenth (19th) day of the calendar month in
which the subject invoice was issued; provided, however, that if the Invoice is
issued on or after the sixteenth (16th) day of the calendar month, the payment
on that Invoice shall be due on the fourth (4th) Business Day after the Invoice
is issued; and provided further that a Non- Participant Transmission Customer
will in no event be required to make a payment on an Invoice any sooner than
provided in Section 8.2 of the NEPOOL Tariff.
b) Right to Alter Payment Date. The ISO may alter the dates on which payments
are due in the case of special billings and Participants and Non-Participant
Transmission Customers that are on weekly billing schedules in accordance with
the Financial Assurance Policies; provided, however, that (i) payment on any
Invoice shall not be due prior to the fourth (4th) Business Day after the
Invoice is issued, and (ii) a Non-Participant Transmission Customer shall not be
required to make a payment on an Invoice any sooner than provided in Section 8.2
of the NEPOOL Tariff.
c) Payments Received by ISO. Each Participant or Non-Participant Transmission
Customer owing monies shall remit the amount shown on its Invoice no later than
the date such payment is due. Disputed amounts shall be paid in accordance with
clause (d) below.
d) Payments Pending Resolution of a Dispute. Any Participant or Non- Participant
Transmission Customer that disputes the amount due on any Invoice for service
other than transmission service under the NEPOOL Tariff shall pay to the ISO all
amounts due on such Invoice, including those in dispute. Such payment shall in
no way prejudice the right of such Participant or Non- Participant Transmission
Customer to seek reimbursement of such disputed amounts, including accrued
interest on such amounts at the Commission's standard rate, set forth in 18
C.F.R. Section 35.19, pursuant to the Billing Dispute Resolution Procedures
provided in Section 5 below.
Any Participant or Non-Participant Transmission Customer that disputes the
amount due on any Invoice for transmission service under the NEPOOL Tariff shall
pay to the ISO all amounts not in dispute and shall pay the amount in dispute
into an independent escrow account designated by the ISO, which account shall be
established at a banking institution acceptable to the ISO and the Participant
or Non-Participant Transmission Customer challenging the amount due and shall
accrue interest at a prevailing market rate. Such amount in dispute shall be
held in escrow pending the resolution of such dispute in accordance with the
applicable Document(s). To the extent that the amount in dispute would be
payable to one or more identifiable Participants (but not to the ISO), then the
amount due to each such Participant in the billing period to which such dispute
relates shall be reduced by the portion of the total amount in dispute that
would be payable to such Participant, subject to payment with interest accrued
thereon if and when the dispute is resolved in favor of such Participant(s). To
the extent that the amount in dispute would be payable to the ISO, or the
specific Participant(s) to which such amount would be payable cannot be
identified, then the shortfall of funds available to pay Remittance Advices
resulting from the amount in dispute being held in an escrow account shall be
allocated among the Participants according to the two-step allocation process
described in Section 3.3(e) below, subject to payment to all such Participants
being allocated a portion of the shortfall, with applicable interest (if any),
once the dispute is resolved with the funds in such escrow account or with other
amounts provided by the Participant or Non-Participant Transmission Customer
losing such dispute.
Section 3.2 - ISO Payment of Remittance Advice Amounts. The Payment Date for
Remittance Advices shall be the second (2nd) Business Day after the date on
which Invoices are due in such month.
Section 3.3 - Payment Default. If the ISO, in its reasonable opinion, believes
that all or any part of any amount due to be paid by any Participant or
Non-Participant Transmission Customer will not or has not been paid when due
(other than in the case of a payment dispute) (the "Default Amount"), then the
following procedures shall apply:
a) ISO Charges Paid First. The ISO shall use monies received by it from
Participants and Non-Participant Transmission Customers to pay all amounts due
to the ISO under the ISO Tariff and ISO Agreement before making any payments to
any Participants or Non-Participant Transmission Customers.
b) Use of Set-Offs. The ISO shall use any and all rights of set-off it has under
the Documents and this Policy against a defaulting Participant or a
Non-Participant Transmission Customer to the extent necessary to pay the Default
Amount, together with any interest accrued thereon and any late charges assessed
under the Documents and the Financial Assurance Policies, due from such
Participant or Non-Participant Transmission Customer.
c) Enforcing the Security of a Defaulting Party. If and to the extent that the
procedure described in clause (b) above is insufficient to effect payment of the
Default Amount and all interest accrued thereon and late charges assessed under
the Documents and the Financial Assurance Policies, the ISO shall use the
financial assurance(s) provided by the Participant or Non- Participant
Transmission Customer under the Financial Assurance Policies to the extent
necessary to pay the Default Amount and such interest and late charges. Any use
of financial assurance(s) shall be undertaken in compliance with the Financial
Assurance Policies.
d) Action Against a Defaulting Party. If and to the extent that the procedures
described in clauses (b) and (c) above are insufficient to effect payment of the
Default Amount and all interest accrued thereon and late charges assessed under
the Documents and the Financial Assurance Policies, the ISO shall take
appropriate actions to recover the Default Amount and such accrued interest and
late charges, which actions may include, without limitation, initiating
proceedings in accordance with the appropriate dispute resolution mechanisms or
actions with NEPOOL or before the Federal Energy Regulatory Commission or a
court of competent jurisdiction against the defaulting Participant or
Non-Participant Transmission Customer. Prior to the commencement of any such
action or proceeding with respect to amounts due to Participants, the ISO shall
obtain the approval of the NEPOOL Executive Committee or its designee and shall
offer to the NEPOOL Executive Committee or its designee an opportunity to be
involved in such action or proceeding. Any amounts incurred by the ISO or any
Participant in connection with any such action or proceeding shall be paid by
the defaulting Participant or Non- Participant Transmission Customer.
e) Reduction of Payments and Increases in Charges.
(i) If and to the extent that the procedures described in clauses (b), (c) and
(d) above do not yield sufficient funds to pay all Remittance Advice amounts in
full (after payment of amounts due to the ISO in accordance with clause (a)
above) on the date such Payments are due, the ISO shall reduce Payments to those
Participants owed monies for that billing period (the "Default Period"), pro
rata based on the amounts owed to such Participants, to the extent necessary to
clear its accounts by the close of banking business on the date such Payments
are due. As funds attributable to a Default Amount are received by the ISO
(including amounts received through financial assurances provided under the
Financial Assurance Policies or through actions or proceedings commenced against
the defaulting Participant or Non-Participant Transmission Customer) prior to
the next billing period's Statements being distributed, such funds, together
with any interest and late charges collected on the applicable Default Amount,
shall be distributed pro rata to the Participants that did not receive the full
amount of their Payments as a result of such Default Amount not being paid.
(ii) To the extent that any amount remains unpaid to Participants on the date
that Statements are distributed to Participants in the billing period
immediately following the Default Period, the Default Amount remaining unpaid
shall be reallocated among all of the Participants receiving Statements for the
Default Period (other than the Participant or Non-Participant Transmission
Customer defaulting on its payment obligations), pro rata based, for each
Participant being allocated a share of the Default Amount remaining unpaid, on
the sum of (i) all Charges due from such Participant that are reflected on its
Statement for the Default Period and (ii) all Payments due to such Participant
that are reflected on its Statement for the Default Period, without giving any
effect to the process of netting Charges against Payments on each Statement that
is the result of the ISO's single billing system. Thus, by way of example, a
Participant with $2,000 of Charges and no Payments on its Statement for the
Default Period and a Participant with $1,000 of Charges and $1,000 of Payments
on its Statement for the Default Period would be allocated an equal share of the
unpaid Default Amount under this clause (e)(ii). Each Participant that received
a Statement for the Default Period shall have the amount of its Invoice or
Remittance Advice in the billing period immediately following the Default Period
adjusted as necessary to reflect its obligation for the Default Amount remaining
unpaid under this clause (e)(ii). As funds attributable to a Default Amount are
received by the ISO (including amounts received through financial assurances
provided under the Financial Assurance Policies or through actions or
proceedings commenced against the defaulting Participant or Non-Participant
Transmission Customer) after such adjusted Statements are distributed, such
funds, together with any interest and late charges collected on the applicable
Default Amount, shall be distributed to the Participants pro rata based on their
allocation of the Default Amount under this clause (e)(ii).
f) Other Rights Against Defaulting Parties. Nothing set forth in this Policy
shall nullify, restrict or otherwise limit the rights and remedies of the ISO
and the Participants against a defaulting Participant or Non-Participant
Transmission Customer that are set forth in the Documents, the Financial
Assurance Policies or otherwise, including without limitation any late payment
charges or rights to terminate or limit trading rights of the defaulting
Participant, to the extent such rights and remedies otherwise exist.
g) Set-Off. The ISO shall apply any amount to which any defaulting Participant
or Non-Participant Transmission Customer is or will be entitled toward the
satisfaction of any of that defaulting Participant's or Non- Participant
Transmission Customer's debts to the ISO or the Participants which are incurred
under the Documents or the Financial Assurance Policies.
h) Order of Settlement. As amounts on Default Amounts are received by the ISO,
the oldest outstanding amount will be settled first in the order of the creation
of such debts.
i) Notification of Payment Default. Without limiting any of the other remedies
described above, in the event that the ISO, in its reasonable opinion, believes
that all or any part of any amount due to be paid by any Participant or any
Non-Participant Transmission Customer will not be or has not been paid within 10
days of when due (a "Payment Default"), the ISO (on its own behalf or on behalf
of NEPOOL) may (but shall not be required to) notify such Participant or
Non-Participant Transmission Customer in writing, electronically and by first
class mail sent in each case to such Participant's member or alternate on the
Participants Committee or billing contact (it being understood that the ISO will
use reasonable efforts to contact all three) or such Non-Participant
Transmission Customer's billing contact, of such Payment Default. Either
simultaneously with the giving of the notice described in the preceding sentence
or within ten days thereafter (unless the Payment Default giving rise to such
notice is cured during such period), the ISO shall notify each other member and
alternate on the NEPOOL Participants Committee and each Participant's billing
contact of the identity of the Participant or Non-Participant Transmission
Customer receiving such notice, whether such notice relates to a Payment Default
and the actions the ISO plans to take and/or has taken in response to such
Payment Default. Section 3.4 - Bankruptcy Filings. In the event any Participant
or Non- Participant Transmission Customer files a voluntary or involuntary
petition in bankruptcy or commences a proceeding under the United States
Bankruptcy Code or any other applicable law concerning insolvency,
reorganization or bankruptcy by or against such Participant or Non-Participant
Transmission Customer as debtor (the "Bankruptcy Event") and the ISO is required
to return any payments made by such Participant or Non-Participant Transmission
Customer to the bankruptcy court having jurisdiction over such Bankruptcy Event,
the ISO may avail itself of any emergency funding provisions in the ISO
Agreement to collect the amounts returned by the ISO.
SECTION 4 - WEEKLY BILLING PRINCIPLES.
The ISO shall administer weekly billing arrangements according to the following
principles:
Section 4.1 - Weekly Invoices. The ISO shall issue an Invoice each Friday to
each Participant and Non-Participant Transmission Customer for which a weekly
billing arrangement has been established to the extent such Participant's or
Non-Participant Transmission Customer's Charges exceed the Payments due to it
for the current calendar week. Remittance Advices for such Participants will
still be issued monthly, in accordance with the procedures set forth above.
Section 4.2 - Basis for Billing. The amounts for each market (except the
Installed Capability market), and all other amounts due from such Participant or
Non-Participant Transmission Customer shall be based on estimates derived by
pro-rating the most recent final monthly Statements issued for such Participant
or Non-Participant Transmission Customer. For the Installed Capability market,
the weekly amount billed for Capability Responsibility shall be based on
estimates derived by pro-rating the most recent preliminary report of the
Participant's position in the Installed Capability market.
Section 4.3 - Payment Date and Time. Each Participant or Non-Participant
Transmission Customer receiving such a weekly Invoice shall remit the amount
shown on its Invoice no later than five (5) Business Days after the date the
Invoice is issued.
Section 4.4 - Monthly Reconciliation. In connection with each monthly billing
cycle, the ISO shall reconcile the sum of the weekly Invoices issued with the
normal monthly billing quantities calculated for the Participant or
Non-Participant Transmission Customer. The ISO shall perform a true-up of any
amounts owed or due on the following weekly Statements.
SECTION 5 - BILLING DISPUTE PROCEDURES.
Section 5.1 - Requested Billing Adjustments Eligible for Resolution under
Billing Dispute Procedures. Any Participant or Non-Participant Transmission
Customer may dispute the amount due on any fully paid monthly Invoice and/or any
amount believed to be due or owed on a Remittance Advice (a "Disputed Amount").
Such party (a "Disputing Party") shall seek to recover such Disputed Amount,
including accrued interest, pursuant to this Section 5, by first submitting a
request for billing adjustment to the ISO (a "Requested Billing Adjustment" or
"RBA") in accordance with the procedures provided in this Section 5 and Market
Rule 18. A Disputing Party may seek resolution of a Requested Billing Adjustment
under this Section 5 concerning any Disputed Amount resulting from the
determination of a market clearing price, NEPOOL Tariff and/or ISO Tariff rate
by the ISO that allegedly either violates or is otherwise inconsistent with the
NEPOOL Tariff, ISO Tariff or the Market Rules, or results from error by the ISO.
Notwithstanding the foregoing, a Requested Billing Adjustment must involve a
requested change in an amount owed or believed to be owed in a Remittance Advice
that is not covered by another alternative dispute resolution procedure under
the NEPOOL Tariff, the ISO Tariff, the Interim ISO Agreement or the Market
Rules. Furthermore, a Requested Billing Adjustment must not involve Disputed
Amounts paid on a weekly Invoice pursuant to the Financial Assurance Policies,
provided, however, that this provision shall not preclude a Disputing Party from
submitting a Requested Billing Adjustment for a Disputed Amount on a fully paid
monthly Invoice which has been paid pursuant to a weekly Invoice in that month.
Section 5.2 - Effect of this Policy on Rights of Participant or Non- Participant
Transmission Customer with Respect to a Disputed Amount. Except as otherwise set
forth in this Section 5.2, nothing in this Section 5 shall in any way abridge
the right of any Participant or Non-Participant Transmission Customer to seek
legal or equitable relief under the Federal Power Act and/or any other
applicable laws with respect to any Disputed Amount. Prior to commencing a
proceeding before the Commission or other regulatory or judicial authority with
jurisdiction to resolve the dispute which is the subject of the Requested
Billing Adjustment, the Disputing Party must first submit the Requested Billing
Adjustment to the ISO for review pursuant to Section 5.3 of this Policy.
Section 5.3 - ISO Review of Requested Billing Adjustment.
Section 5.3.1 - Submission of Requested Billing Adjustment to ISO; Required
Contents of Requested Billing Adjustment. A Disputing Party shall submit a
Requested Billing Adjustment in writing to the chief financial officer of the
ISO. In its Requested Billing Adjustment, the Disputing Party must specify the
Disputed Amount at issue and specify the instance of alleged error at issue,
including a statement detailing the specific provisions of all applicable
governing documents that support the Requested Billing Adjustment. The Disputing
Party also must state the relief being requested and identify a specific person
or persons to whom all communications to the Disputing Party regarding the
Requested Billing Adjustment are to be addressed. A Disputing Party must submit
its Requested Billing Adjustment within 3 months of the date that the Invoice or
Remittance Advice containing the Disputed Amount was issued by the ISO unless
the Disputing Party could not have reasonably known of the existence of the
alleged error within such time.
Section 5.3.2 - Notice of ISO Review of Requested Billing Adjustment. Within
three (3) Business Days of the receipt by the ISO's Chief Financial Officer of a
Requested Billing Adjustment, the ISO shall prepare and submit to the Secretary
of the Participants Committee for distribution by the Secretary to all
Participants and Non-Participant Transmission Customers a notice of the
Requested Billing Adjustment ("Notice of RBA"), including, subject to the
protection of Confidential Information, the specifics of the Requested Billing
Adjustment. The Notice of RBA shall identify a specific representative of the
ISO to whom all communications regarding the Requested Billing Adjustment are to
be sent. The Secretary of the Participants Committee shall distribute the Notice
of RBA to all Participants and Non- Participant Transmission Customers by no
later than 5:00 p.m. on the next business day after receiving the Notice of RBA
from the ISO.
Section 5.3.3 - ISO Review of Requested Billing Adjustments. The ISO shall
complete its review of a Requested Billing Adjustment received pursuant to
Section 5.3 within twenty (20) business days of the date the Secretary of the
Participants Committee distributes the Notice of RBA. To the extent that either
party makes such a request and both parties agree to such request, the ISO and
Disputing Party may meet or otherwise confer during this period in an effort to
resolve the Requested Billing Adjustment.
Section 5.3.4 - Comment Period. Any Participant or Non-Participant Transmission
Customer, which desires to do so may submit to the ISO's designated
representative, on or before the tenth (10th) Business Day following the date
the Secretary of the Participants Committee distributes the Notice of RBA,
written comments to the ISO with respect to the Requested Billing Adjustment.
Any such comments are to be transmitted simultaneously to the Disputing Party.
The Disputing Party may respond to any such comments by submitting a written
response to the ISO's designated representative and to the commenting party on
or before the fifteenth (15th) Business Day following the date the Secretary of
the Participants Committee distributes the Notice of RBA. In determining the
action it will take with respect to the Requested Billing Adjustment, the ISO
shall consider the written response filed by the Disputing Party. The ISO may
but is not required to consider any written comments that are filed by any other
interested party.
Section 5.3.5 - ISO Action on Requested Billing Adjustment. The ISO shall
provide to the Disputing Party a written decision (the "RBA Decision") accepting
or denying a Requested Billing Adjustment received pursuant to Section 5.3
within twenty (20) Business Days of the date the Secretary of the Participants
Committee distributes the Notice of RBA, unless some later date is agreed upon
by the Disputing Party and the ISO. The ISO shall provide written notice and a
copy of each RBA Decision to each Participant or Non- Participant Transmission
Customer either eligible for reimbursement, denied reimbursement of a Disputed
Amount or required to provide reimbursement of a Disputed Amount because of an
RBA Decision (hereafter referred to as an "Affected Party" or the "Affected
Parties") within five (5) business days of the date the RBA Decision is
rendered. In providing such notice to any Affected Party required to provide
reimbursement of a Disputed Amount, the ISO shall specify the amount to be
reimbursed by such Affected Party and the calculations supporting the
determination of such reimbursement amount. Subsequent to the provision of the
written notice of the RBA Decision as set forth above, the ISO shall provide
each Affected Party with respect to that RBA Decision a monthly report of the
status of such RBA Decision within the dispute resolution process set forth in
this Section 5 of the Billing Policy, including a statement of the accounting
treatment of the disputed amount owed by or to that Affected Party with respect
to that RBA Decision in accordance with the most recent decision issued pursuant
to Sections 5.3.6 or 5.4 of this Billing Policy, whichever applies, with respect
to that RBA Decision. For purposes of Section 5 of this Policy, the term
"Affected Parties" shall also include the Disputing Party.
Section 5.3.6 - Finality of ISO Action on Requested Billing Adjustment. Except
as otherwise provided in this Section 5.3.6, the RBA Decision shall become final
and binding on the Affected Parties and shall not be appealable in any forum on
the twenty-first (21st) Business Day after the notice of the specific RBA
Decision at issue was provided to the Affected Parties as set forth in Section
5.3.5 above. The RBA Decision shall not become final or binding if, on or before
the twentieth (20th) Business Day after the notice of the specific RBA Decision
at issue was provided to the Affected Parties as set forth in Section 5.3.5
above, an Affected Party or Parties has appealed the RBA Decision by commencing
a proceeding before the Commission or other regulatory or judicial authority
with jurisdiction over the dispute, or has filed an appeal pursuant to Section
5.4 of this Policy. If a proceeding is commenced before the Commission or other
regulatory or judicial authority with jurisdiction over the dispute, the
Affected Party commencing that proceeding shall simultaneously transmit a copy
of their initial pleading in that proceeding to the ISO's designated
representative for that particular RBA Decision, and shall also submit to the
ISO's designated representative for that particular RBA a copy of the final
order or decision in that proceeding resolving the dispute. If any such appeal
is filed pursuant to Section 5.4 of this Policy, the RBA Decision shall have no
force or effect unless or until it is affirmed or upheld upon completion of the
appeal process selected by the Affected Party and as provided for in this
Policy.
Section 5.4 - Right of Affected Party to Review of ISO RBA Decision by AAA.
Section 5.4.1 - Right to Further Review. Any Affected Party may seek review of
an RBA Decision by an independent third party neutral by submitting, on or
before the twentieth (20th) Business Day after the notice of the specific RBA
Decision at issue was provided to the Affected Parties as set forth in Section
5.3.5 above, a request for arbitration of the Requested Billing Adjustment with
the American Arbitration Association ("AAA"). At the same time that it submits
its request to the AAA, the Affected Party commencing any such review of an RBA
Decision shall transmit its request for arbitration: (i) to the ISO's designated
representative for that particular RBA Decision; (ii) to each of the Affected
Parties; and, (iii) to the Secretary of the Participants Committee. The ISO and
any Affected Party shall be joined as parties to the arbitration. NEPOOL shall
be permitted to intervene in the arbitration if it desires to do so.
Section 5.4.2 - Finality of the AAA Neutral's Decision. Except as otherwise
provided in this Section 5.4.2, the written, final decision of the AAA neutral
(the "Neutral's Decision") shall become final and binding on the Affected
Parties, including the ISO, and shall not be appealable in any forum on the
twenty-first (21st) Business Day after the date on which the Neutral's Decision
was issued. The Neutral's Decision shall not become final or binding if on or
before the twentieth (20th) business day after the date on which the Neutral's
Decision was issued, an Affected Party or Parties or the ISO has appealed the
Neutral's Decision by commencing a proceeding before the Commission or other
regulatory or judicial authority with jurisdiction over the dispute. If any such
appeal is filed, the Neutral's Decision shall have no force or effect unless or
until it is affirmed or upheld upon completion of the appeal process.
Section 5.5 - Access to Confidential Information. Information that is deemed
confidential pursuant to the NEPOOL Information Policy in the possession,
custody or control of the ISO concerning the dollar amount in Invoices or
Remittance Advices issued by the ISO ("Confidential Information") shall be made
available under these Billing Dispute Procedures only to "Dispute
Representatives" as defined herein who have executed a confidentiality agreement
in accordance both with this Section 5.5 and the NEPOOL Information Policy
("Confidentiality Agreement"). A copy of the executed Confidentiality Agreement
for a Dispute Representative shall be provided to the ISO prior to the
disclosure of any Confidential Information to said Dispute Representative.
Confidential Information shall not be disclosed to anyone other than in
accordance with this Section 5.5, and shall be used only in connection with the
Billing Dispute Procedures provided under Section 5.
a) Potential Disputing Parties' Right of Access to Confidential Information. A
Participant or Non-Participant Transmission Customer that is a potential
Disputing Party is entitled to obtain access to Confidential Information for its
Dispute Representative, if and only if, it can demonstrate to the ISO that such
access is required to determine if it has a substantive basis for filing a
Requested Billing Adjustment with the ISO. Such demonstration by a potential
Disputing Party, at a minimum, shall include: the information submitted to the
chief financial officer of the ISO required in Section 5.3.1; and, why lack of
access to Confidential Information prevents the potential Disputing Party from
determining if it has a substantive basis for filing such a Requested Billing
Adjustment. A potential Disputing Party shall submit a request for access to
Confidential Information in writing to the ISO (an "Information Request"). The
ISO shall evaluate and respond to such an Information Request within ten (10)
days of the receipt of the Information Request, and where the need for access to
Confidential Information is demonstrated in accordance with the above, shall
provide access to such Confidential Information within fifteen (15) days of the
receipt of the Information Request.
b) Affected Parties Right of Access to Confidential Information. If the RBA
Decision is submitted to the AAA for resolution pursuant to Section 5.4, then
for purposes of that AAA proceeding a Participant or Non-Participant
Transmission Customer that is an Affected Party is entitled to obtain access to
Confidential Information for its Dispute Representative if, and only if, it can
demonstrate to the AAA Neutral that such access is required to protect its
financial interests with respect to review of an RBA Decision pending before the
Neutral. An Affected Party shall submit a request for access to Confidential
Information concerning an RBA Decision within the timeframes established by the
Neutral. The Neutral shall have the authority to enter such orders as may be
necessary to protect the Confidential Information, in accordance with applicable
NEPOOL policies including but not limited to the NEPOOL Information Policy.
c) Dispute Representatives. Dispute Representatives shall be limited to the AAA
Neutral(s), Participants, Non-Participant Transmission Customers, and third
parties retained by and/or in-house legal counsel of the AAA, Participants or
Non-Participant Transmission Customers, provided, however, that Confidential
Information may not be disclosed to a Dispute Representative to the extent the
disclosure is prohibited by Order 889. A Dispute Representative may disclose
Confidential Information to any other Dispute Representative as long as the
disclosing Dispute Representative and the receiving Dispute Representative each
have executed a Confidentiality Agreement. In the event that any Dispute
Representative to whom Confidential Information is disclosed ceases to be
engaged in a matter under these Billing Dispute Procedures, or is no longer
qualified to be a Dispute Representative under this Section, access to
Confidential Information by that person, or persons, shall be terminated and all
such Confidential Information received by that party shall be returned to the
ISO or destroyed to the satisfaction of the ISO. Even if no longer engaged as a
Dispute Representative under this Section, every person who has executed the
Confidentiality Agreement set forth below shall continue to be bound by the
provisions of this Section and such Confidentiality Agreement. All Dispute
Representatives are responsible for ensuring that persons under their
supervision or control comply with this Section and the Confidentiality
Agreement.
Re: Requested Billing Adjustment ______________
CONFIDENTIALITY AND NONDISCLOSURE AGREEMENT
The ISO ("Provider") agrees to make available, pursuant to Section 5 of the
NEPOOL Billing Policy, to ("Recipient") confidential and proprietary information
("Confidential Information") relevant to resolution of Requested Billing
Adjustment and any appeals thereof as provided for in said Section 5.
1. Any information provided to Recipient and labeled "Confidential
Information" by Provider shall be Confidential Information subject to this
Agreement.
2. The Confidential Information is received by Recipient in confidence.
3. The Confidential Information shall not be used or disclosed by the Recipient
except in accordance with the terms contained herein, with Section 5 of the
NEPOOL Billing Policy and with the NEPOOL Information Policy.
4. Only individuals who are Dispute Representatives as that term is defined in
Section 5 of the NEPOOL Billing Policy, and not entities, may be Recipients of
Confidential Information under this paragraph. By executing this Agreement, each
Recipient certifies that he/she meets the requirements of this Agreement.
5. The following conditions shall apply to each Recipient:
a. Each Recipient will receive one (1) numbered, controlled copy of the
Confidential Information. The Recipient shall not make any copies thereof or
provide the Confidential Information to any individual or entity except one who
has executed and delivered an Agreement identical to this Agreement to the
Provider.
b. The Recipient shall maintain a log of all persons granted access to the
Confidential Information.
c. The Recipient, by signing this Agreement acknowledges that he/she may not in
any manner disclose the Confidential Information to any person, and that he/she
may not use the Confidential Information for the benefit of any person except in
this proceeding and in accordance with the terms of this Agreement, Section 5 of
the NEPOOL Billing Policy and the NEPOOL Information Policy.
d. The Recipient acknowledges that any violation of this Agreement may
subject the Recipient to civil actions for violation hereof.
e. Within thirty (30) days of the final decision issued with respect to the
Requested Billing Adjustment terminating all appeals with respect to this
Requested Billing Adjustment, Recipient shall return the Confidential
Information to Provider.
PROVIDER: RECIPIENT:
By: By:
Dated: Dated:
d) Maintenance of Confidential Information. All copies of all documents and
materials containing Confidential Information shall be maintained by Dispute
Representatives at all times in a secure place in sealed envelopes or other
appropriate containers endorsed to the effect that they are sealed pursuant to
this Section. Such documents and material shall be marked PROTECTED CONFIDENTIAL
INFORMATION and shall be maintained under seal and provided only to Dispute
Representatives as are authorized to examine and inspect such Confidential
Informational. Dispute Representatives shall provide to the ISO a list of those
persons under the supervision and/or control of the Dispute Representative who
are entitled to receive Confidential Information. Dispute Representatives shall
take all reasonable precautions to ensure that Confidential Information is not
distributed to unauthorized persons.
e) ISO Right to Object to Access to Confidential Information. Nothing in this
Section shall be construed as precluding the ISO from objecting to providing any
party access to Confidential Information on any legal grounds other than those
provided under the NEPOOL Information Policy, the NEPOOL Agreement, and/or the
Interim ISO Agreement, as they may be amended time to time.
Section 5.6 - Transition Rules. Any Disputed Amount raised with the ISO between
the Second Effective Date and the effective date of these Billing Dispute
Procedures that is unresolved as of the effective date of these Billing Dispute
Procedures as determined by the Commission shall be submitted for resolution
under these Billing Dispute Procedures as specified below. Disputed Amounts so
referred shall be termed "Pre-Existing Disputes".
a) Review of Pre-Existing Disputes. On or before the thirtieth (30th) calendar
day after the date of the Commission's order accepting this Section 5 of the
Billing Policy, the Disputing Party in a Pre-Existing Dispute shall submit to
the ISO a Request for Billing Adjustment. All parties to Pre- Existing Disputes
shall be entitled to access to Confidential Information subject to the rights
and obligations provided with respect to Confidential Information in Section 5.5
above. If a Request for Billing Adjustment with respect to a Pre-Existing
Dispute is not submitted in accordance with this Section 5.6(a), the
Pre-Existing Dispute shall be deemed resolved for purposes of this Billing
Policy and Section 21.2 of the Restated NEPOOL Agreement .
b) Release of Amounts in Escrow for Pre-Existing Disputes Other than Disputes
Involving Transmission Service Under the Tariff. All amounts at issue in a
Pre-Existing Dispute held in escrow, except for amounts at issue in a
Pre-Existing Dispute concerning amounts due with respect to transmission service
under the NEPOOL Tariff, pursuant to the provisions of Section 3.1(d) of the
NEPOOL Billing Policy and Section 21.2(c) of the NEPOOL Agreement in effect
immediately prior to the effective date of this Section 5 of the NEPOOL Billing
Policy (together, the "Former Escrow Provisions") shall be released from escrow
to the payee upon satisfaction of the following two conditions: (1) thirty (30)
calendar days have elapsed since the date of the Commission's Order accepting
this Billing Policy; and, (2) the ISO has determined that the required Financial
Assurances under this Section 5 of the Billing Policy and the relevant
provisions of Attachment L to the NEPOOL Tariff have been satisfied with respect
to the amount at issue in the Dispute. If a Participant that has received from
one or more other Participants or Non-Participant Transmission Customers an
amount the payment of which is the subject of a dispute, an amount equal to 100%
of such amount in dispute shall be included in determining that Participant's
overall financial assurance requirement and the relevant provisions of
Attachment L to the NEPOOL Tariff shall apply.
c) Release of Amounts in Escrow With Respect to Disputes Concerning Transmission
Service Under the Tariff. If the Pre-Existing Dispute concerns amounts due on
any Invoice for transmission service under the NEPOOL Tariff, any amounts held
in escrow with respect to such Pre-Existing Dispute shall remain in escrow and
shall accrue interest at a prevailing market rate. Such amount in dispute shall
be held in escrow pending the resolution of such dispute in accordance with the
applicable Document(s). To the extent that the amount in dispute would be
payable to one or more identifiable Participants (but not to the ISO), then the
amount due to each such Participant in the billing period to which such dispute
relates shall be reduced by the portion of the total amount in dispute that
would be payable to such Participant, subject to payment with interest accrued
thereon if and when the dispute is resolved in favor of such Participant(s). To
the extent that the amount in dispute would be payable to the ISO, or the
specific Participant(s) to which such amount would be payable cannot be
identified, then the shortfall of funds available to pay Remittance Advices
resulting from the amount in dispute being held in an escrow account shall be
allocated among the Participants according to the two-step allocation process
described in Section 3.3(e) below, subject to payment to all such Participants
being allocated a portion of the shortfall, with applicable interest (if any),
once the dispute is resolved with the funds in such escrow account or with other
amounts provided by the Participant or Non-Participant Transmission Customer
losing such dispute.
Attachment 1
SAMPLE INVOICE
See attached pages
[Form of Sample Invoice]
Attachment 2
SAMPLE REMITTANCE ADVICE
See attached pages
[Form of Sample Remittance Advice]
Sheet Nos. 457-500 are reserved for future use.
ANCILLARY SERVICE SCHEDULE 1
SCHEDULING, SYSTEM CONTROL AND DISPATCH SERVICE
IMPLEMENTATION RULE
This rule provides detail with respect to the calculation of the rate surcharge
each year for Scheduling, System Control and Dispatch Service, which is defined
in the Tariff as the service required to schedule the movement of power through,
out of, within, or into the NEPOOL Control Area over Pool Transmission
Facilities ("PTF"). This service also includes the dispatch and security
analysis of the system. Scheduling, System Control and Dispatch Service for
transmission service over transmission facilities other than PTF is provided
under the Local Network Service Tariffs of the individual Transmission
Providers. For transmission service under the NEPOOL Tariff, this Ancillary
Service will be provided by the Independent System Operator (ISO), satellites,
and the Transmission Providers. All of the costs of the ISO will be recovered
directly by the ISO under its own tariff once that tariff becomes effective (a
January 1, 1999 effective date has been requested) and Schedule 1 of the NEPOOL
Tariff is for collection only of the revenue requirements for satellites and
Transmission Providers for System Control and Dispatch Service. Any Transmission
Customer taking Regional Network Service, Through or Out Service, or Internal
Point-to-Point Service shall be subject to the rate surcharge calculated under
Schedule 1 of the NEPOOL Tariff as described in more detail in this rule below.
NEPOOL shall make an annual informational filing on or before July 31 of each
year showing the Schedule 1 rate surcharge in effect for the period beginning
June 1 of that year through May 31 of the subsequent year. If there are any
corrections made to the information reflected in the informational filing after
it has been submitted, NEPOOL would file corrections to the informational
filing. At least thirty days before the informational filing is made with the
Commission, NEPOOL shall make available to Participants and any other interested
parties a draft of the proposed filing for review and comment prior to the
filing. The filing of the informational filing does not re-open the formula rate
set forth below for review, but rather is contestable only with respect to the
accuracy of the information contained in the informational filing. The System
Operator shall independently audit the charges in effect for the period June
1997 through May 2000 for charges under this Attachment, or direct that an
audit[s] be conducted under its supervision by an independent third party, and
shall have the discretion to conduct such audits of charges in effect beyond May
2000.
I. DEFINITIONS
Capitalized terms used in this rule that are not defined in the NEPOOL Tariff
have the following definitions:
Scheduling and Dispatch Surcharge Rate shall equal the rate surcharge that is
determined for the applicable period beginning on June 1, 1999, in accordance
with Section II of this rule below.
PTF Transmission-Related Satellite Scheduling and Dispatch Expense shall equal
the PTF transmission related expenses incurred by the Participant from
REMVEC II, CONVEX/ESCC, and the Maine Satellite as recorded in each
Participant's FERC Form 1, Account No. 561, excluding any charges recorded in
this account that were incurred under the NEPOOL Tariff or the Local Network
Service Tariffs of each Transmission Provider as a Transmission Customer. The
expenses shall be net of any revenues, as reflected in FERC Account No. 456,
received by the Participant for providing scheduling and dispatch services,
excluding any revenues recorded in this account that where received as a result
of charges under the NEPOOL Tariff or the LNS Tariffs of each Transmission
Provider.
REMVEC II is a satellite of the ISO-NE providing security analysis of PTF.
Local PTF Transmission-Related Scheduling and Dispatch Expense shall equal the
sum of (1) each Participant's expenses as recorded in FERC Account No. 561,
excluding any ISO and satellite related expenses and any expenses recorded in
this Account, that were incurred under this Tariff or the LNS Tariffs of each
Transmission Provider as a Transmission Customer, multiplied by the PTF
Transmission Plant Allocator, (2) SCADA-related expenses as calculated in
accordance with Appendix A to this Rule, and (3) the Maine Satellite revenue
requirements as calculated in accordance with Appendix A to this Rule.
PTF Transmission Plant Allocation Factor is the factor for allocating
transmission costs and expenses between PTF and non-PTF as determined for the
applicable period pursuant to Attachment F of the NEPOOL Tariff.
II. CALCULATION OF THE SCHEDULING AND DISPATCH SURCHARGE
A. Surcharge for Regional Network Service Customers
For Network Customers, the scheduling and dispatch surcharge shall equal the
Network Customer's Monthly Network Load, as defined in Section 46.1 of the
NEPOOL Tariff, multiplied by the Monthly Scheduling and Dispatch Surcharge Rate
as determined in accordance with Section II.C below.
B. Surcharge for Point-to-Point Customers
For Point to Point and Through or Out Service Customers, the Scheduling and
Dispatch Surcharge shall equal the Transmission Customer's Reserved Capacity for
each transaction scheduled for the month multiplied by the applicable Monthly,
Weekly, or Hourly Scheduling and Dispatch Surcharge Rate, as determined in
accordance with Section II.C below.
C. Scheduling and Dispatch Surcharge Rate
The Scheduling and Dispatch Surcharge Rate will be the surcharge rate in effect
from time to time for the applicable period, determined pursuant to the formula
described below based on the prior calendar year's data. The Scheduling and
Dispatch Surcharge Rate shall be redetermined each year, with the new Surcharge
Rate going into effect on June 1 of each year, and be effective for the
succeeding twelve months.
In the case of Transmission Providers which are subject to the Commission's
jurisdiction, the data used shall be as identified in the Participant's FERC
Form 1 report for that year, and shall be based on actual data in lieu of
allocated data if specifically identified in the FERC Form 1. When FERC Form 1
data is not the direct source of the data used in the formula, the worksheets
used to develop the inputs will be as reflected in Appendix A of this Rule.
The Scheduling and Dispatch Surcharge Rate shall be equal to the sum of (1) PTF
Transmission-Related Satellite Scheduling and Dispatch Expense, (2) Local PTF
Transmission Related Scheduling and Dispatch Expense, (3) less Schedule 1
revenues from the prior year surcharges for Short-Term Point-to-Point
Transactions, and divided by the annual average of the sum of all Network
Customers Monthly Peak Load, as defined in Section 46.1 of the NEPOOL Tariff,
from the prior calendar year plus the Long-Term Firm Point-to-Point Reserved
Capacity, from the prior calendar year.
The Monthly Scheduling and Dispatch Surcharge Rate shall equal one-twelfth of
the Scheduling and Dispatch Surcharge Rate.
The Weekly Scheduling and Dispatch Surcharge Rate shall equal one-fifty- second
of the Scheduling and Dispatch Surcharge Rate.
The Daily Firm Scheduling and Dispatch Surcharge Rate shall equal one-fifth of
the Weekly Scheduling and Dispatch Surcharge Rate.
The Daily Non-Firm Scheduling and Dispatch Surcharge Rate shall equal one-
seventh of the Weekly Scheduling and Dispatch Surcharge Rate.
The Hourly Non-Firm Scheduling and Dispatch Surcharge Rate shall equal one-
twenty-fourth of the Daily Non-Firm Scheduling and Dispatch Surcharge Rate.
APPENDIX A-1
NEPOOL Tariff Schedule 1 Implementation Rule
Scheduling, System Control and Dispatch Service
Boston Edison Company SCADA
This service is required to schedule the movement of power through, out of,
within, or into the NEPOOL Control Area over Pool Transmission Facilities (PTF).
Service under this schedule represents the contribution to that service provided
by The Transmission Provider's own Dispatch Center, commonly referred to as
SCADA. These costs are excluded from costs in Attachment F.
Definitions:
Dispatch Center Wages and Salaries Allocation Factor: Ratio of Dispatch Center
Related Direct Wages and Salaries to Boston Edison's total Direct Wages and
Salaries excluding Administrative and General Wages and Salaries.
Dispatch Center Plant Allocation Factor: Ratio of Total Investment in
Dispatch Center Plant plus Dispatch Center Related General Plant, to Total
Plant in service.
The PTF Revenue Requirement for the Scheduling System Control and Dispatch
Service shall equal the sum of The Transmission Provider's: (A) Return and
Associated Income Taxes, (B) Dispatch Center Depreciation Expense, (C) Dispatch
Center Related Amortization of Investment Tax Credits, (D) Dispatch Center
Related Municipal Tax Expense, (E) Dispatch Center Related Payroll Tax Expense
(F) Dispatch Center Operation and Maintenance Expense, and (G) Dispatch Center
Related Administrative and General Expense; multiplied by the PTF Transmission
Plant Allocation Factor.
A. Return and Associated Income Taxes shall equal the product of the
Dispatch Center Investment Base and the Cost of Capital Rate.
1. The Dispatch Center Investment Base will consist of (a) Dispatch Center Plant
in FERC accounts 350-359, plus (b) Dispatch Center Related General Plant, plus
(c) Dispatch Center Plant Held for Future Use, less (d) Dispatch Center Related
Depreciation Reserve, less (e) Dispatch Center Related Accumulated Deferred
Taxes, plus (f) Other Regulatory Assets, plus (g) Dispatch Center Prepayments,
plus (h) Dispatch Center Materials and Supplies, plus (i) Dispatch Center
Related Cash Working Capital.
a. Dispatch Center Plant will equal the year-end balance of the Transmission
Provider's Investment in Dispatch Center per FERC accounts 350 through
359.Dispatch Center Plant Investment is not included in PTF investment in the
Attachment F revenue requirement.
b. Dispatch Center Related General Plant shall equal the Transmission Provider's
year-end balance of Investment in General Plant multiplied by the Dispatch
Center Wages and Salaries Allocation Factor described above.
c. Dispatch Center Plant Held for Future Use shall equal the year-end balance of
Transmission related Dispatch Center Investment in FERC account 105.
d. Dispatch Center Related Depreciation Reserve shall equal the year-end balance
of Transmission Dispatch Center Depreciation Reserve, plus the year- end balance
of Dispatch Center Related General Depreciation Reserve. Dispatch Center Related
General Plant Depreciation Reserve shall equal the product of General Plant
Depreciation Reserve and the Dispatch Center Wages and Salaries Allocation
Factor described above.
e. Dispatch Center Related Accumulated Deferred Taxes shall equal the year- end
balance of Total Accumulated Deferred Income Taxes, multiplied by the Dispatch
Center Plant Allocation Factor described above.
f. Other Regulatory Assets shall equal the year-end balance of FAS 106
multiplied by the Dispatch Center Wages and Salaries Allocation Factor described
in Section (A) (2) (b) above and the year-end balance of FAS 109, net of FAS 109
liability, multiplied by the Dispatch Center Plant Allocation Factor described
in above.
g. Dispatch Center Prepayments shall equal the year-end balance of Prepayments
multiplied by the Dispatch Center Wages and Salaries Allocation Factor described
above.
h. Dispatch Center Materials and Supplies shall equal the year-end balance of
Transmission Plant Materials and Supplies multiplied times the Dispatch Center
Plant Allocation Factor described above.
i. Dispatch Center Related Cash Working Capital shall be a 12.5% allowance (45
days/360 days) of Dispatch Center Transmission Related Operation and Maintenance
Expense and Dispatch Center Transmission Related Administrative and General
Expense.
2. The Cost of Capital Rate shall equal (a) the Weighted Cost of Capital,
plus (b) Federal Income Taxes, plus (c) State Income Taxes.
a. the Weighted Cost of Capital will be calculated based upon the Transmission
Provider's capital structure at the end of each year and will equal the sum of
i. the Long Term Debt Component, which equals the product of the actual weighted
average embedded cost to maturity of Long Term Debt then outstanding and the
ratio that Long-Term Debt is to Total Capital.
ii. the Preferred Stock Component, which equals the product of the actual
weighted average embedded cost to maturity of Preferred Stock then outstanding
and the ratio that Preferred Stock is to Total Capital.
iii. the Return on Equity Component, which equals the product of The
Transmission Provider's Return on Equity as set in the Transmission Provider's
LNS open access tariff rate and the ratio that Common Equity is to Total
Capital.
b. Federal Income Taxes shall equal
A + [(C+B)/D]) x FT
1 - FT
Where FT is the Federal Income Tax Rate and A is the sum of the Preferred Stock
Component and the Return on Equity Component, as determined in Sections
A.2.(a)(ii) and (iii) above, B is Dispatch Center Related Amortization of
Investment Tax Credits, as determined in Section II.D. below, C is the Equity
AFUDC component of Dispatch Center Depreciation Expense, as defined in Section
B., and D is Dispatch Center Investment Base, as determined in A.1., above.
c. State Income Taxes shall equal
(A + [(C+B)/D] + Federal Income Tax) x ST
1 - ST
Where ST is the State Income Tax Rate and A is the sum of the Preferred Stock
Component and the Return on Equity Component, as determined in Section
A.2.(a)(ii), and Section A.2.(a)(iii) above, and Federal Income Tax is the rate
determined in Section A.2.(b) above.
B. Dispatch Center Depreciation Expense shall equal the sum of Transmission
Depreciation Expense for Dispatch Center Plant, plus an allocation of General
Plant Depreciation Expense calculated by multiplying General Plant Depreciation
Expense by the Dispatch Center Wages and Salaries Allocation Factor, described
in Section (A) (1) (b) above.
C. Dispatch Center Related Amortization of Investment Tax Credits shall equal
the Transmission Provider's Amortization of Investment Tax Credits multiplied
by the Dispatch Center Plant Allocation Factor described above.
D. Dispatch Center Related Municipal Tax Expense shall equal the Transmission
Provider's total Municipal Tax Expense multiplied by the Dispatch Center Plant
Allocation Factor described above.
E. Dispatch Center Related Payroll Tax Expense shall equal the Transmission
Provider's total electric payroll tax expense, multiplied by the Dispatch Center
Wages and Salaries Allocation Factor, described above.
F. Dispatch Center Operation and Maintenance Expense shall equal all expenses
related to SCADA operation charged to FERC Account Number 561, excluding any ISO
and satellite related expenses and any expenses recorded in this Account that
were incurred under this Tariff or the LNS tariff of any Transmission Provider
as a Transmission Customer.
G. Dispatch Center Related Administrative and General Expenses shall equal the
sum of (1) Transmission Provider's Administrative and General Expenses,
excluding Accounts 924, 928 and 930.1, multiplied by the Dispatch Center Wages
and Salaries Allocation Factor, (2) Property Insurance multiplied by the
Dispatch Center Plant Allocation Factor, and (3) Expenses included in Account
928 related to FERC
Assessments multiplied by Dispatch Center Plant Allocation Factor, plus any
other Federal and State Dispatch Center related expenses or assessments, plus
specific Dispatch Center related expenses included in Account 930.1.
APPENDIX A-2
NEPOOL Tariff Schedule 1 Implementation Rule
Scheduling, System Control and Dispatch Service
Central Maine Power Company Satellite
I. DEFINITIONS
Capitalized terms not otherwise defined in Section 1 of the NEPOOL Tariff and as
used in this rule have the following definitions:
A. ALLOCATION FACTORS
1. Wages and Salaries Allocation Factor shall equal the ratio of the Satellite
Direct Wages and Salaries to total direct wages and salaries excluding
administrative and general wages and salaries.
2. Satellite Wages and Salaries Allocation Factor shall equal the ratio of the
Transmission Satellite Direct Wages and Salaries to total Satellite Direct Wages
and Salaries.
3. Satellite PTF Allocation Factor shall equal the ratio of the Satellite PTF
Direct Wages and Salaries to the total Satellite Transmission Direct Wages and
Salaries.
4. Satellite Plant Allocation Factor shall equal the ratio of the Total
Investment in Satellite Plant to Total Plant in service.
B. TERMS
Administrative and General Expense shall equal the Transmission Provider's
expenses as recorded in FERC Account Nos. 920-935, excluding FERC Account
Nos. 924, 928, and 930.1.
Amortization of Investment Tax Credits shall equal the Transmission
Provider's credits as recorded in FERC Account No. 411.4
Amortization of Loss on Reacquired Debt shall equal the Transmission
Provider's expenses as recorded in FERC Account No. 428.1
Other Regulatory Assets/Liabilities - FAS 106 shall equal the net of the
Transmission Provider's FAS106 balance as recorded in FERC Account 182.3 and any
FAS 106 balance as recorded in the Transmission Provider's FERC Account No. 254.
Other Regulatory Assets/Liabilities - FAS 109 shall equal the net of the
Transmission Provider's FAS 109 balance in FERC Account No. 182.3 and any FAS
109 balance as recorded in the Transmission Provider's FERC Account No. 254.
Payroll Taxes shall equal those payroll expenses as recorded in the Transmission
Provider's FERC Account Nos. 408.1 and 409.1.
Plant Held for Future Use shall equal the Transmission Provider's balance in
FERC Account No. 105.
Prepayments shall equal the Transmission Provider's prepayment balance as
recorded in FERC Account No. 165.
Property Insurance shall equal the Transmission Provider's expenses as
recorded in FERC Account No. 924.
PTF Satellite Direct Wages and Salaries shall equal the Transmission Provider's
direct wages and salaries related to providing PTF satellite services as
recorded in FERC Account No. 561.
Satellite Direct Wages and Salaries shall equal the Transmission Provider's
direct wages and salaries related to providing satellite services as recorded in
FERC Account Nos. 556, 561, and 581.
Satellite Operation and Maintenance Expense shall equal the Transmission
Provider's expenses recorded in FERC Account Nos. 556, 561, & 581, less any
costs included in FERC Account No. 561 that are otherwise recoverable pursuant
to Subpart (1) of the Local PTF Transmission Related Scheduling and Dispatch
Expense of the rule implementing the Schedule 1 rate surcharge of the NEPOOL
Tariff.
Satellite Plant Depreciation Reserve shall equal the Transmission Provider's
depreciation reserve balance for Satellite Related Plant as recorded in FERC
Account No. 108.
Materials and Supplies shall equal the Transmission Provider's balance as
recorded in FERC Account No. 154.
Satellite Related Depreciation Expense shall equal the Transmission
Provider's depreciation expense for Satellite Related Plant as recorded in
FERC Account No. 403.
Satellite Related Plant shall equal the Transmission Provider's gross plant
balances used for system control and dispatch purposes as recorded in FERC
Account Nos. 303-399. To the extent that such plant includes any amounts
recorded as transmission investment in FERC Account Nos. 350-359, such amounts
will be excluded for purposes of determining annual transmission revenue
requirements pursuant to the billing rule which implements Attachment F of the
NEPOOL Tariff.
Satellite Support Revenues shall equal the revenues received from satellite
supporters as recorded in FERC Account Nos. 454 and 456, excluding any revenues
received under Schedule 1 of the NEPOOL Tariff or the Transmission Provider's
Local Tariff.
Total Accumulated Deferred Income Taxes shall equal the net of the deferred tax
balances as recorded in FERC Account Nos. 281-283 and 190..
Total Loss on Reacquired Debt shall equal the Transmission Provider's balance as
recorded in FERC Account No. 189.
Total Municipal Tax Expense shall equal the Transmission Provider's municipal
tax expenses as recorded in FERC Account Nos. 408.1 and 409.1.
Total Plant in Service shall equal the Transmission Provider's total gross plant
balance as recorded in FERC Account Nos. 301-399.
Transmission Satellite Direct Wages and Salaries shall equal the Transmission
Provider's direct wages and salaries related to providing satellite services as
recorded in FERC Account No. 561.
II. CALCULATION OF TOTAL SATELLITE REVENUE REQUIREMENTS
The Satellite Revenue Requirement shall equal the sum of the Satellite related
(A) Return and Associated Income Taxes, (B) Depreciation Expense, (C)
Amortization of Loss on Reacquired Debt, (D) Amortization of Investment Tax
Credits, (E) Municipal Tax Expense, (F) Payroll Tax Expense, (G) Operations and
Maintenance Expense, (H) Administrative and General, minus (I) Support Revenues.
A. Return and Associated Income Taxes shall equal the product of the Satellite
Investment Base and the Cost of Capital Rate reflected in the Transmission
Providers' Attachment F formula of the NEPOOL Tariff.
1. Satellite Investment Base
The Satellite Investment Base will be the year end balances of Satellite
related: (a) Plant, plus (b) Plant Held for Future Use, less (c) Depreciation
Reserve, less (d) Accumulated Deferred Taxes, plus (e) Loss on Reacquired Debt,
plus (f) Other Regulatory Assets/Liabilities, plus (g) prepayments, plus (h)
Materials and Supplies, plus (i) Cash Working Capital.
(a) Satellite Related Plant shall equal the balance of the Transmission
Provider's Investment in Satellite Plant
(b) Satellite Related Plant Held for Future Use shall equal the balance of
Plant Held for Future Use multiplied by the Satellite Plant Allocation Factor
(c) Satellite Related Depreciation Reserve shall equal the Depreciation Reserve
for the Transmission Provider's investment in Satellite plant.
(d) Satellite Related Accumulated Deferred Taxes shall equal the Transmission
Provider's electric balance of Accumulated Deferred Income Taxes multiplied by
the Satellite Plant Allocation Factor.
(e) Satellite Related Loss on Reacquired Debt shall equal the Transmission
Provider's electric balance of Total Loss on Reacquired Debt multiplied by the
Satellite Plant Allocation Factor.
(f) Satellite Related Other Regulatory Assets/Liabilities shall equal the
Transmission Provider's electric balance of any deferred recovery of FAS 106
expenses multiplied by the Satellite Wages and Salaries Allocation Factor, plus
the Transmission Provider's electric balance of FAS 109 multiplied by the
Satellite Plant Allocation Factor.
(g) Satellite Related Prepayments shall equal the Transmission Provider's
electric balance of prepayments multiplied by the Satellite Plant Allocation
Factor.
(h) Satellite Related Materials and Supplies shall equal the Transmission
Provider's electric balance of Plant Materials and Supplies, multiplied by
the Satellite Plant Allocation Factor.
(i) Satellite Related Cash Working Capital shall be a 12.5% allowance (45
days/360 days) of Satellite Operation and Maintenance Expense, Satellite Related
Administrative and General Expense.
2. Cost of Capital Rate
The Cost of Capital Rate will equal (a) The Transmission Provider's Weighted
Cost of Capital, plus (b) Federal Income Tax plus (c) State Income Tax.
(a) The Weighted Cost of Capital will be calculated based upon the capital
structure at the end of each year and will equal the sum of:
(i) the long-term debt component, which equals the product of the actual
weighted average embedded cost to maturity of the Transmission Provider's
long-term debt then outstanding and the ratio that long-term debt is to the
Transmission Provider's total capital.
(ii) the preferred stock component, which equals the product of the actual
weighted average embedded cost to maturity of the Transmission Provider's
preferred stock then outstanding and the ratio that preferred stock is to the
Transmission Provider's total capital.
(iii) the return on equity component, which equals the product of the
Transmission Provider's Return on Equity as set in the Provider's RNS open
access rate and the ratio that common equity is to the Transmission Provider's
total capital.
(b) Federal Income Tax shall equal
(A+[(C+B)/D]) x FT
1 - FT
Where FT is the Federal Income Tax Rate and A is the sum of the preferred stock
component and the return on equity component, as determined in Sections
II.A.2.(a)(ii) and (iii) above, B is the Amortization of Investment Tax Credits
as determined in Section II.D. below, C is the equity AFUDC component of
Satellite Depreciation Expense, as defined in II.B., and D is Satellite
Investment Base, as determined in II.A.1., above.
(c) State Income Tax shall equal
(A+[(C+B)/D] + Federal Income Tax) x ST
1 - ST
Where ST is the State Income Tax Rate, A is the sum of the preferred stock
component and return on equity component determined in Sections II.A.2.(a)(ii)
and (iii) above, B is the Amortization of Investment Tax Credits as determined
in Section II.D. below, C is the equity AFUDC component of Satellite
Depreciation Expense, as defined in II.B., D is the Satellite Investment Base,
as determined in II.A.1., above and Federal Income Tax is the rate determined in
Section II.A.1.(b) above.
B. Satellite Depreciation Expense shall equal the Satellite Plant Depreciation
Expense and Accumulated Amortization
C. Satellite Related Amortization of Loss on Reacquired Debt shall equal the
Transmission Provider's electric balance of Loss on Reacquired Debt
multiplied by the Satellite Plant Allocation Factor.
D. Satellite Related Amortization of Investment Tax Credits shall equal the
Transmission Provider's electric Amortization of Investment Tax Credits
multiplied by the Satellite Plant Allocation Factor.
E. Satellite Related Municipal Tax Expense shall equal the Transmission
Provider's total electric municipal tax expense multiplied by the Satellite
Plant Allocation Factor.
F. Satellite Related Payroll Tax Expense shall equal the Transmission Provider's
total electric payroll tax expense, multiplied by the Wages and Salaries
Allocation Factor.
G. Satellite Operation and Maintenance Expense shall equal the Transmission
Provider's Operation and Maintenance Expenses recorded in FERC Account Nos. 556,
561, and 581, less any costs included in FERC Account No. 561 that are otherwise
recoverable pursuant to Subpart (1) of Local PTF Transmission Related Scheduling
and Dispatch Expense of the rule implementing the Schedule 1 rate surcharge of
the NEPOOL Tariff.
H. Satellite Related Administrative and General Expenses shall equal the sum of
(1) Transmission Provider's Administrative and General Expenses multiplied by
the Wages and Salaries Allocation Factor, (2) Property Insurance multiplied by
the Satellite Plant Allocation Factor, and (3) Expenses included in Account 928
related to FERC Assessments multiplied by the Satellite Plant Allocation Factor,
plus any other Federal and State satellite related expenses or assessments, plus
specific satellite related expenses included in Account 930.1.
I. Transmission Support Revenues shall equal the Transmission Provider's
revenue received for providing system control and dispatch service
III. CALCULATION OF SATELLITE TRANSMISSION REVENUE REQUIREMENTS
The Total Satellite Revenue Requirements derived in Section II. above are
further multiplied by the Satellite Wages and Salaries Allocation Factor
defined in Section I. A. 2. above to determine the transmission related
revenue requirement, and further multiplied by the Satellite PTF Allocation
Factor defined in Section I. A. 3. above, to determine the PTF Transmission
related revenue requirements to be included in Schedule I of the NEPOOL Open
Access Transmission Tariff.
ANCILLARY SERVICE SCHEDULE 2
(Reactive Supply And Voltage Control From Generation Sources Service)
IMPLEMENTATION RULE
This rule is designed to implement the NEPOOL Open Access Transmission
Tariff Ancillary Service Schedule 2 (Reactive Supply and Voltage Control from
Generation Sources Service) ("Schedule 2"). As of the Second Effective Date,
service within the scope of Schedule 2 shall be paid by Participants and/or
Non-Participants in accordance with the formula set forth in Schedule
2. The rule defines how Participants providing Schedule 2 service shall be
compensated for providing such service.
1. Capacity Cost (CC)
1.1 The Capacity Cost will be set to zero ($0) until a methodology for cost
determination and compensation is developed and approved by the NEPOOL Markets
Committee (MC) and the NEPOOL Tariff Committee (TC) and filed and accepted by
the Commission.
2. Lost Opportunity Cost (LOC)
2.1 The Lost Opportunity Cost for hydro, pumped storage and thermal generating
units that are dispatched down by the ISO, a NEPOOL satellite or a NEPOOL
Participant dispatch center for the purpose of providing reactive supply and
voltage control will be calculated in a manner that is consistent with the rules
established in Market Rule and Procedure No. 6-A - Compensation For Resources
Postured For OP-4 Conditions (MRP 6-A).
2.2 LOC Data Submission
2.2.1 A NEPOOL satellite or a NEPOOL Participant dispatch center must notify the
ISO Control Room staff when a thermal, hydro, or pumped storage generating unit
has been dispatched down by the satellite or NEPOOL Participant dispatch center
for the purpose of providing reactive supply and voltage control.
2.2.2 The ISO Control Room staff will log all instances of a thermal, hydro or
pumped storage generating unit having been dispatched down by the ISO, a NEPOOL
satellite or a NEPOOL Participant dispatch center for the purpose of providing
reactive supply and voltage control.
2.2.3 The ISO Settlements staff will collect the data required for the
determination of LOCSched2 from the ISO Control Room logs, Energy Management
System, and Market System.
3. Cost of Energy Consumed (SCL)
3.1 Motoring Hydro or Pumped Storage Generating Units. The SCL associated with
hydro and pumped storage generating units that are motoring at the request of
the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch center for the
purpose of providing reactive supply and voltage control will equal the cost of
energy to motor and will be calculated in each hour as follows: SCL = (MWhUnit *
(ECP or Actual energy cost) + UpliftSched2), where the MwhUnit are calculated
pursuant to Section 3.2.4. Actual energy cost applies only if motoring energy is
purchased through a bilateral contract. Documentation of actual energy cost is
to be provided to the ISO. The UpliftSched2 component of the SCL is related to
the increase in the Participant's Electrical Load that was caused by the
motoring of a hydro or pumped storage generating unit that was motoring at the
request of the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch center
for the purpose of providing reactive supply and voltage control and any other
uplift allocations associated with providing this service and will be calculated
in each hour as follows: UpliftSched2 = MWhUnit * ((* AGC, OPCAP, TMNSR, TMOR
and TMSR Market Payments + Energy Market Uplift Payment) / * Participants'
Electrical Load + applicable ISO Tariff rates + any Emergency Purchase Cost
allocation associated with provision of this service). The UpliftSched2
component of the SCL applies only until the changes indicated in Sections 3.5
and 3.6 have been implemented.
3.2 Data submissions associated with Hydro and Pumped Storage Generating Units
that motored for the purpose of providing Reactive Supply and Voltage Control
3.2.1 A NEPOOL satellite or a NEPOOL Participant dispatch center must notify the
ISO Control Room staff of a generating unit having been instructed by the
satellite or NEPOOL Participant dispatch center to motor for the purpose of
providing reactive supply and voltage control.
3.2.2 The ISO Control Room staff will log all instances of hydro and pumped
storage generating units having been instructed by the ISO, a NEPOOL satellite
or a NEPOOL Participant dispatch center to motor for the purpose of providing
reactive supply and voltage control.
3.2.3 The ISO Settlements staff will collect the flags set by the ISO Control
Room and the ISO Control Room logs to determine which hydro or pumped storage
generating units had been instructed to motor for the purpose of providing
reactive supply and voltage control.
3.2.4 The Lead Participant will need to submit to the ISO Settlements staff the
following data for each hour that the hydro or pumped storage generating units
was motoring for the purpose of providing reactive supply and voltage control:
* The hourly incremental MWh reflecting the energy in each hour required to
support reactive supply and voltage control while motoring above that which is
required when not providing reactive supply and voltage control,
* If the energy to supply the motoring hydro or pumped storage generating unit
is being met by the hourly Energy Market, the hourly Energy Clearing Price, plus
UpliftSched2 related to the increase in the Participant's Electrical Load that
was caused by the motoring of a hydro or pumped storage generating unit that was
motoring at the request of the ISO, a NEPOOL satellite or a NEPOOL Participant
dispatch center for the purpose of providing reactive supply and voltage control
(in the hours that the unit was motored, if any) until the changes indicated in
Sections 3.5 and 3.6 below are in effect; or
If the energy to supply the motoring hydro or pumped storage generating unit is
being met by a retail power agreement, the actual cost of energy associated with
the wholesale/retail power agreement along with supporting contractual
documentation plus UpliftSched2 related to the increase in the Participant's
Electrical Load that was caused by the motoring of a hydro or pumped storage
generating unit that was motoring at the request of the ISO, a NEPOOL satellite
or a NEPOOL Participant dispatch center for the purpose of providing reactive
supply and voltage control (in the hours that the unit was motored, if any)
until the changes indicated in Sections 3.5 and 3.6 below are in effect, and
* An invoice for each motoring hydro or pumped storage generating unit that
includes a total net cost and an hourly cost detail that includes the hourly
data noted in Section 3.1.
3.3 Timing of Data Submissions by Participants for Hydro or Pumped Storage
Generating Units that motored for the purpose of providing Reactive Supply and
Voltage Control - Participants should submit their SCL data (noted in the above
three bullets, Section 3.2.4) related to the motoring of a hydro or pumped
storage generating unit for the purpose of providing reactive supply and voltage
control to ISO Settlements within fourteen (14) calendar days after the
completion of the month in which the unit was called to motor. Under no
circumstances will data submissions received three (3) calendar months or more
after the completion of the month in which the unit was called to motor be
compensated. Submittals received after the 14-day deadline will be reflected in
a single billing that will occur after the 3-month submission deadline has
passed.
3.4 Data submissions notifying the ISO of Hydro or Pumped Storage Generating
Units that have the ability to motor for the purpose of providing Reactive
Supply and Voltage Control - Direction as to whether the ECP or the actual
energy cost will be applied to the SCL calculation (the ECP is to be selected
only if the Participant does not have a wholesale/retail agreement to supply the
unit's station service requirements) must be submitted, with supporting
contractual documentation, to the ISO Settlements staff prior to the month in
which the hydro or pumped storage generating unit is called to motor for
reactive supply and voltage control. It is not intended that a Participant would
have the option to bounce back and forth between ECP and actual energy cost.
3.5 Power System Modeling of Hydro and Pumped Storage Generating Units that can
be motored for the purpose of providing Reactive Supply and Voltage Control -
The energy (MWh) required by a hydro or pumped storage generating unit that is
motoring for the purpose of providing reactive supply and voltage control should
be reported under a distinct and unique Load Asset.
The option of reporting the energy required by a hydro or pumped storage
generating unit that is motoring for the purpose of providing reactive supply
and voltage control under a distinct and unique Load Asset is currently not
available. This option will require incorporation within the appropriate Market
Rule and Procedures (e.g., MRP 20-H and MRP 20-I) and additional programming
within the Market System. Until such a time as that can be accommodated,
Participants will submit the appropriate data and be compensated through the
mechanism noted in Section 3.1 and 3.2.
3.6 Impact of Hydro or Pumped Storage Generating Units motoring for the purpose
of providing Reactive Supply and Voltage Control on the calculation of
Electrical Load and Load - The MWh reported under a distinct and unique Load
Asset (pursuant to Section 3.5) for the motoring of a hydro or pumped storage
generating unit will be excluded from the calculation of Electrical Load and
Load. The MWh that have not been reported under a distinct and unique Load Asset
(pursuant to Section 3.5) for the motoring of a hydro or pumped storage
generating unit will neither be excluded from the calculation of Electrical Load
and Load nor be compensated under Schedule 2.
3.7 Synchronous Condensers and Static Controlled VAR Regulators (SC/SCV). The
SCL will be set to zero ($0), and the cost of energy to supply reactive supply
and voltage control from the Chester SCV will be treated as losses on the NEPOOL
bulk transmission system. This treatment will be revisited by the MC and TC on
an as needed basis (e.g., upon the addition of a new SC or SCV within the NEPOOL
Control Area).
4. Cost of Energy Produced (PC)
4.1 Thermal Generating Units. The PC associated with thermal generating units
brought on-line by the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch
center for the purpose of providing reactive supply and voltage control shall
equal the product of (i) the difference between its Dispatch Price and the
Energy Clearing Price for the hour, times (ii) the number of megawatt hours of
out-of-merit generation produced by the resource for the hour. The "Dispatch
Price" of an out-of-merit resource for an hour is the price to provide energy
from the resources, as determined pursuant to Market Rules approved by the
NEPOOL Participants Committee, to incorporate the Bid Price for such energy and
any loss adjustments, if and as appropriate under such Market Rules. The "Energy
Clearing Price" for an hour is the price determined for the hour in accordance
with Section 14.8 of the Agreement.
4.2 Hydro and Pumped Storage Generating Units. The PC associated with hydro or
pumped storage generating units that are producing real power and that have also
been brought on-line by the ISO, a NEPOOL satellite or a NEPOOL Participant
dispatch center to provide reactive supply and voltage control shall equal the
product of (i) the difference between its Dispatch Price and the Energy Clearing
Price for the hour, times (ii) the number of megawatt hours of out-of-merit
generation produced by the resource for the hour. The "Dispatch Price" of an
out-of-merit resource for an hour is the price to provide energy from the
resources, as determined pursuant to Market Rules approved by the NEPOOL
Participants Committee, to incorporate the Bid Price for such energy and any
loss adjustments, if and as appropriate under such Market Rules. The "Energy
Clearing Price" for an hour is the price determined for the hour in accordance
with Section 14.8 of the Agreement.
4.3 Data submissions with respect to PC
4.3.1 A NEPOOL satellite or a NEPOOL Participant dispatch center must notify the
ISO Control Room staff of a generating unit having been brought on-line by the
satellite or NEPOOL Participant dispatch center for the purpose of providing
reactive supply and voltage control.
4.3.2 The ISO Control Room staff will log all instances of a generating unit
having been brought on-line by the ISO, a NEPOOL satellite or a NEPOOL
Participant dispatch center for the purpose of providing reactive supply and
voltage control.
4.3.3 The ISO Settlements Hourly Markets staff will collect the flags set by the
ISO Control Room and the ISO Control Room logs to determine which generating
units have been brought on-line for the purpose of providing reactive supply and
voltage control.
4.3.4 The ISO Settlement Staff will collect the appropriate data through the
Market System for each hour that the generating unit was brought on-line for the
purpose of providing reactive supply and voltage control.
Sheet Nos. 530-700 are reserved for future use.
NEPOOL TARIFF, ATTACHMENT F
IMPLEMENTATION RULE FOR CALCULATING
ANNUAL TRANSMISSION REVENUE REQUIREMENTS
This rule sets forth details with respect to the determination each year of the
Transmission Revenue Requirements for each Participant. Such Transmission
Revenue Requirements shall reflect the Participant's costs for Pool Transmission
Facilities ("PTF"). The Transmission Revenue Requirements will be an annual
formula rate calculation, effective June 1, based on the previous calendar
year's data, as shown below, and in the case of each Transmission Provider which
is subject to the Commission's jurisdiction, in the Participant's FERC Form 1
report for that year, and shall be based on actual data in lieu of allocated
data if specifically identified in the FERC Form 1, using end-of-year balances
for each rate base item, as set forth below.
NEPOOL shall make an annual informational filing on or before July 31 of each
year showing the Pool PTF Rate in effect for the period beginning June 1 of that
year through May 31 of the subsequent year. Further, the informational filing
with respect to the determination of the Pool PTF rate would include a breakdown
by Participant the amount of the change in PTF investment during the prior year
and the PTF retirements or additions causing such change to beginning and
end-of-year PTF balances (although beginning-of- year PTF balances are not used
in the formula itself), and any additions to PTF, retirements of PTF, and
reclassifications of PTF during the year for each Transmission Provider. If
there are any corrections made to the information reflected in the informational
filing after it has been submitted, NEPOOL would file corrections to the
informational filing. At least forty-five days before the informational filing
is made with the Commission, NEPOOL shall make available to Participants and any
other interested parties a draft of the proposed filing for review and comment
prior to the filing. The filing of the information filing does not re-open the
formula rate set forth below for review, but rather is contestable only with
respect to the accuracy of the information contained in the informational
filing.
The System Operator shall independently audit the charges in effect for the
period June 1997 through May 2000 for charges under this Attachment, or direct
that an audit[s] be conducted under its supervision by an independent third
party, and shall have the discretion to conduct such audits of charges in effect
beyond May 2000.
I. DEFINITIONS
Capitalized terms not otherwise defined in Section 1 of the NEPOOL Tariff and as
used in this rule have the following definitions:
A. ALLOCATION FACTORS
1. Transmission Wages and Salaries Allocation Factor shall equal the ratio of
Transmission-related direct wages and salaries including those of affiliated
Companies to the Transmission Provider's total direct wages and salaries
including those of the affiliates Companies and excluding administrative and
general wages and salaries.
2. PTF Transmission Plant Allocation Factor shall equal the ratio of PTF
Transmission Plant to Total Investment in Transmission Plant, excluding capital
leases in the Hydro-Quebec DC Facilities (HQ Leases).
3. Plant Allocation Factor shall equal the ratio of the sum of Total Investment
in Transmission Plant, excluding HQ leases, and Transmission Related General
Plant to Total Plant in service excluding HQ Leases.
B. TERMS
Administrative and General Expense shall equal the Transmission Provider's
expenses as recorded in FERC Account Nos. 920-935, excluding FERC Account
Nos. 924, 928 and 930.1.
Amortization of Loss on Reacquired Debt shall equal the Transmission Provider's
expenses as recorded in FERC Account No. 428.1.
Amortization of Investment Tax Credits shall equal the Transmission Provider's
credits as recorded in FERC Account No. 411.4.
Depreciation Expense for Transmission Plant shall equal the Transmission
Provider's transmission expenses as recorded in FERC Account No. 403.
General Plant shall equal the Transmission Provider's gross plant balance as
recorded in FERC Account Nos. 389-399.
General Plant Depreciation Expense shall equal the Transmission Provider's
general expenses as recorded in FERC Account No. 403.
General Plant Depreciation Reserve shall equal the Transmission Provider's
general reserve balance as recorded in FERC Account No. 108.
Hydro-Quebec DC Facilities (HQ Leases) shall equal the Transmission
Provider's balance in capital leases as recorded in FERC Account Nos. 350-359
and FERC Account Nos. 389-399.
Other Regulatory Assets/Liabilities - FAS 106 shall equal the net of the
Transmission Provider's FAS106 balance as recorded in FERC Account 182.3 and any
FAS 106 balance as recorded in the Transmission Provider's FERC Account No. 254.
Other Regulatory Assets/Liabilities - FAS 109 shall equal the net of the
Transmission Provider's FAS 109 balance in FERC Account No. 182.3 and any FAS
109 balance as recorded in the Transmission Provider's FERC Account No. 254.
Payroll Taxes shall equal those payroll expenses as recorded in the Transmission
Provider's FERC Account Nos. 408.1 and 409.1.
Plant Held for Future Use shall equal the Transmission Provider's balance in
FERC Account No.105.
Prepayments shall equal the Transmission Provider's prepayment balance as
recorded in FERC Account No. 165.
Property Insurance shall equal the Transmission Provider's expenses as
recorded in FERC Account No. 924.
PTF Transmission Plant Investment shall equal the Transmission Provider's
transmission plant as defined in the Section 15.1 of the Restated NEPOOL
Agreement and determined in accordance with Attachment 1.5 of this rule, which
is entitled "Rules for Determining Investment To be Included in PTF."
Total Accumulated Deferred Income Taxes shall equal the net of the deferred
tax balance as recorded in FERC Account Nos. 281-283 and the deferred tax
balance as recorded in FERC Account No. 190.
Total Loss on Reacquired Debt shall equal the Transmission Provider's expenses
as recorded in FERC Account 189.
Total Municipal Tax Expense shall equal the Transmission Provider's municipal
tax expenses as recorded in FERC Account Nos. 408.1, 409.1.
Total Plant in Service shall equal the Transmission Provider's total gross plant
balance as recorded in FERC Account Nos. 301-399.
Total Transmission Depreciation Reserve shall equal the Transmission Provider's
transmission reserve balance as recorded in FERC Account 108.
Transmission Operation and Maintenance Expense shall equal the Transmission
Provider's expenses as recorded in FERC Account Nos. 560, 562-564 and 566- 573,
and shall exclude all HQ HVDC expenses booked to accounts 560 through 573 and
expenses already included in Transmission Support Expense, as described in
Section K which are included in FERC Account Nos. 560-573.
Transmission Plant shall equal the Transmission Provider's Gross Plant balance
as recorded in FERC Account Nos. 350-359.
Transmission Plant Materials and Supplies shall equal the Transmission
Provider's balance as assigned to transmission, as recorded in FERC Account No.
154.
II. CALCULATION OF TRANSMISSION REVENUE REQUIREMENTS
The Transmission Revenue Requirement shall equal the sum of the Transmission
Provider's (A) Return and Associated Income Taxes, (B) Transmission Depreciation
Expense, (C) Transmission Related Amortization of Loss on Reacquired Debt, (D)
Transmission Related Amortization of Investment Tax Credits, (E) Transmission
Related Municipal Tax Expense, (F) Transmission Related Payroll Tax Expense, (G)
Transmission Operation and Maintenance Expense, (H) Transmission Related
Administrative and General Expenses, (I) Transmission Related Integrated
Facilities Charges, minus (J) Transmission Support Revenue, plus (K)
Transmission Support Expense, plus (L) Transmission-Related Expense from
Generators, plus (M) Transmission Related Taxes and Fees Charge, minus (N)
Revenue for Short-Term Transmission Service under the NEPOOL Tariff and (O)
Transmission Rents Received from Electric Property.
A. Return and Associated Income Taxes shall equal the product of the
Transmission Investment Base and the Cost of Capital Rate.
1. Transmission Investment Base
The Transmission Investment Base will be the year end balances of (a) PTF
Transmission Plant, plus (b) Transmission Related General Plant, plus (c)
Transmission Plant Held for Future Use, less (d) Transmission Related
Depreciation Reserve, less (e) Transmission Related Accumulated Deferred Taxes,
plus (f) Transmission Related Loss on Reacquired Debt, plus (g) Other Regulatory
Assets/Liabilities, plus (h) Transmission Prepayments, plus (i) Transmission
Materials and Supplies, plus (j) Transmission Related Cash Working Capital.
(a) PTF Transmission Plant will equal the balance of the Transmission Provider's
PTF Investment in Transmission Plant excluding (i) the Transmission Provider's
capital leases in the Hydro-Quebec DC Facilities (HQ Leases), (ii) the portion
of any facilities, the cost of which is directly assigned under Schedule 11 to
the Tariff, to the Transmission Customer or a Generator Owner or Interconnection
Requester, (iii) the Pre-1997 PTF gross plant investment associated with leased
facilities occupied by the Phase II HVDC facilities.
(b) Transmission Related General Plant shall equal the Transmission Provider's
balance of investment in General Plant multiplied by the Transmission Wages and
Salaries Allocation Factor and the PTF Transmission Plant Allocation Factor.
(c) Transmission Plant Held for Future Use shall equal the balance of
Transmission-related Plant Held for Future Use multiplied by the PTF
Transmission Plant Allocation Factor.
(d) Transmission Related Depreciation Reserve shall equal the balance of Total
Transmission Depreciation Reserve, plus the balance of Transmission Related
General Plant Depreciation Reserve. Transmission Related General Plant
Depreciation Reserve shall equal the product General Plant Depreciation Reserve
and the Transmission Wages and Salaries Allocation Factor. This sum shall be
multiplied by the PTF Transmission Plant Allocation Factor.
(e) Transmission Related Accumulated Deferred Taxes shall equal the Transmission
Provider's electric balance of Total Accumulated Deferred Income Taxes,
multiplied by the Plant Allocation Factor, further multiplied by the PTF
Transmission Plant Allocation Factor.
(f) Transmission Related Loss on Reacquired Debt shall equal the Transmission
Provider's electric balance of Total Loss on Reacquired Debt multiplied by the
Plant Allocation Factor, further multiplied by the PTF Transmission Plant
Allocation Factor.
(g) Other Regulatory Assets/Liabilities shall equal the Transmission Provider's
electric balance of any deferred rate recovery of FAS 106 expenses multiplied by
the Transmission Wages and Salaries Allocation Factor, plus the Transmission
Provider's electric balance of FAS 109 multiplied by the Plant Allocation
Factor. This sum shall be multiplied by the PTF Transmission Plant Allocation
Factor.
(h) Transmission Prepayments shall equal the Transmission Provider's electric
balance of prepayments multiplied by the Transmission Wages and Salaries
allocator and further multiplied by the PTF Transmission Plant Allocation
Factor.
(i) Transmission Materials and Supplies shall equal the Transmission Provider's
electric balance of Transmission Plant Materials and Supplies, multiplied by the
PTF Transmission Plant Allocation Factor.
(j) Transmission Related Cash Working Capital shall be a 12.5% allowance (45
days/360 days) of Transmission Operation and Maintenance Expense, Transmission
Related Administrative and General Expense and Transmission Support Expense, to
the extent that Transmission Support Expense exceeds Transmission Support
Revenue included in Paragraph J of the formula.
2. Cost of Capital Rate
The Cost of Capital Rate will equal (a) The Transmission Provider's Weighted
Cost of Capital, plus (b) Federal Income Tax plus (c) State Income Tax.
(a) The Weighted Cost of Capital will be calculated based upon the capital
structure at the end of each year and will equal the sum of:
(i) the long-term debt component, which equals the product of the actual
weighted average embedded cost to maturity of the Transmission Provider's
long-term debt then outstanding and the ratio that long-term debt is to the
Transmission Provider's total capital.
(ii) the preferred stock component, which equals the product of the actual
weighted average embedded cost to maturity of the Transmission Provider's
preferred stock then outstanding and the ratio that preferred stock is to the
Transmission Provider's total capital.
(iii) the return on equity component, which shall be determined as follows:
(1) For each year during the period March 1, 1997 through May 31, 2000, the
return on equity component for each of the Transmission Providers identified
below shall be the product of the Transmission Provider's Return on Equity
("ROE") as set forth below and the ratio that common equity is to the
Transmission Provider's total capital:
Bangor Hydro-Electric Company 11.5%
Boston Edison Company 10.65%
Central Maine Power Company 11.00%
Commonwealth Electric Company 10.75%
Eastern Utilities Associates 11.22%
(through May 31, 1999)
10.65%
(beginning June 1, 1999)
New England Electric System 10.65%
The United Illuminating Company 11.5%
(through May 31, 1999)
10.75%
(beginning June 1, 1999)
Vermont Electric Company 11.50%
Northeast Utilities 11.75%
(2) For each year during the period commencing June 1, 2000, the return on
equity component shall be determined in the same manner, and the allowed ROE for
each Transmission Provider identified above shall remain in effect for purposes
of such determination for the Provider until an amendment to its cost of service
under the Local Network Service Tariff for the Provider filed after December 31,
1999 results in a different allowed ROE for that Provider, in which case that
Provider's ROE shall be set for purposes of such determination at the ROE
ultimately determined to be just and reasonable in the proceeding involving the
applicable Local Network Service Tariff amendment.
(b) Federal Income Tax shall equal
(A+[(C+B)/D])(FT)
1 - FT
where FT is the Federal Income Tax Rate and A is the sum of the preferred stock
component and the return on equity component, as determined in Sections
II.A.2.(a)(ii) and (iii) above, B is Transmission Related Amortization of
Investment Tax Credits, as determined in Section II.D., below, C is the Equity
AFUDC component of Transmission Depreciation Expense , as defined in Section
II.B., and D is Transmission Investment Base, as determined in II.A.1., above.
(c) State Income Tax shall equal
(A+[(C+B)/D] + Federal Income Tax)(ST)
1 - ST
where ST is the State Income Tax Rate, A is the sum of the preferred stock
component and return on equity component determined in Sections II.A.2.(a)(ii)
and (iii) above, B is the Amortization of Investment Tax Credits as determined
in Section II.D. below, C is the equity AFUDC component of Transmission
Depreciation Expense, as defined in Section II.B., D is the Transmission
Investment Base, as determined in II.A.1., above and Federal Income Tax is the
rate determined in Section II.A.2.(b) above.
B. Transmission Depreciation Expense shall equal the PTF Transmission Plant
Allocation Factor, multiplied by the sum of Depreciation Expense for
Transmission Plant, plus an allocation of General Plant Depreciation Expense
calculated by multiplying General Plant Depreciation Expense by the Transmission
Wages and Salaries Allocation Factor.
C. Transmission Related Amortization of Loss on Reacquired Debt shall equal the
Transmission Provider's electric Amortization of Loss on Reacquired Debt
multiplied by the Plant Allocation Factor, and further multiplied by the PTF
Transmission Plant Allocation Factor.
D. Transmission Related Amortization of Investment Tax Credits shall equal the
Transmission Provider's electric Amortization of Investment Tax Credits
multiplied by the Plant Allocation Factor, and further multiplied by the PTF
Transmission Plant Allocation Factor.
E. Transmission Related Municipal Tax Expense shall equal the Transmission
Provider's total electric municipal tax expense multiplied by the Plant
Allocation Factor, and further multiplied by the PTF Transmission Plant
Allocation Factor.
F. Transmission Related Payroll Tax Expense shall equal the Transmission
Provider's total electric payroll tax expense, multiplied by the Transmission
Wages and Salaries Allocation Factor, further multiplied by the PTF Transmission
Plant Allocation Factor.
G. Transmission Operation and Maintenance Expense shall equal Transmission
Operation and Maintenance Expenses multiplied by the PTF Transmission Plant
Allocation Factor.
H. Transmission Related Administrative and General Expenses shall equal the sum
of (1) Transmission Provider's Administrative and General Expenses multiplied by
the Transmission Wages and Salaries Allocation Factor, (2) Property Insurance
multiplied by the Transmission Plant Allocation Factor, and (3) Expenses
included in Account 928 related to FERC Assessments multiplied by Plant
Allocation Factor, plus any other Federal and State transmission related
expenses or assessments, plus specific transmission related expenses included in
Account 930.1. This sum shall be multiplied by the PTF Transmission Plant
Allocation Factor.
I. Transmission Related Integrated Facilities Charges shall equal the
Transmission Provider's transmission payments to affiliates for use of the PTF
integrated transmission facilities of those affiliates.
J. Transmission Support Revenues shall equal the Transmission Provider's revenue
received for PTF transmission support but excluding the support payments to
Transmission Providers or their designee pursuant to Schedule 11 and excluding
the support payments to Transmission Providers or their designee pursuant to
Schedule 12 Part 1(a), Part 1(b), Part 2 and Part 3, and excluding support
payments, if any, made to Transmission Owners or their respective designee
pursuant to Part III of this Tariff.
K. Transmission Support Expense shall equal the expense paid by Transmission
Providers or Transmission Customers for PTF transmission support other than
expenses for payments made for congestion rights or for transmission facilities
or facility upgrades placed in service on or after January 1, 1997, where the
support obligation is required to be borne by particular Participants or other
entities in accordance with the NEPOOL Tariff. Transmission Support Expenses by
any entity other than an LNS Transmission Provider, included in this provision,
shall be capped at that entity's annual payment for Regional Network Service or
its Point to Point Service for each individual Point to Point transaction from
the resource with which the support payment is associated. For the purpose of
establishing this cap, for the first five years of the Transition Period the
annual payment for RNS and Internal Point-to-Point shall be recalculated at the
Pool PTF rate.
L. Transmission-Related Expense from Generators shall equal the expenses from
generators that both (1) the Management Committee determines should be included
as transmission expense as a result of the impact of such generators on reducing
transmission costs that would otherwise be required to be paid by Transmission
Customers and (2) are reflected in a filing made by NEPOOL with the Commission
under Section 205 of the Federal Power Act and accepted by the Commission for
recovery under the NEPOOL Tariff.
M. Transmission Related Taxes and Fees Charge shall include any fee or
assessment imposed by any governmental authority on service provided under this
Section which is not specifically identified under any other section of this
rule.
N. Revenues for Short-term Transmission Service under the NEPOOL Tariff shall be
revenues distributed to each Participant, from NEPOOL, for short term service
provided under the NEPOOL Tariff, received after March 1, 1999. These revenues
will be credited pro-rata between pre-1997 and post-1996 PTF revenue
requirements in proportion to pre-1997 and post-1996 PTF Transmission Plant.
O. Transmission Rents Received from Electric Property shall equal any Account
454 Rents from electric property, associated with PTF Transmission Plant as
defined in Section II.A.1.(a) above but not reflected as a credit in
Transmission Support Revenues in paragraph K of this Attachment.