September 03, 2013 | Westborough, MA

S E P T E M B E R 0 3 , 2 0 1 3 | W E S T B O R O U G H , M A

Reliability Committee & Markets Committee Meeting #3

Considerations in the Design of Capacity Zones

Al McBrideM A N A G E R , A R E A T R A N S M I S S I O N P L A N N I N G

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Presentation Objectives

• Introduce the ISO proposal at a high level

• Briefly review the Stakeholder discussions so far

• Discuss examples of the capacity zone models in place in PJM and NY

• Discuss the objective criteria (trigger) for the creation of zones (with examples)

• Discuss export constrained zones

• Discuss the proposed process for the analysis of transfer limits and interfaces in the Regional System Planning (RSP) process

• Describe what is proposed for FCA-9 and FCA-10 (and beyond)

• Discuss next steps

High Level Summary of the ISO Proposal

• For FCA-9 capacity zones would be created by implementing an objective criteria (automatic trigger) using the existing 8 energy zones as the starting point– The 8 energy load zones will serve as an approximation of the real

transmission operating boundaries– Energy load zones that do not exceed the automatic trigger will be merged

into the Rest-of-Pool Capacity zone– The objective criteria for the automatic creation of zones would be based on the

TSA-like analysis of the energy zone along with the security constrained import analysis

• For FCA-10 and beyond, incorporate the analysis of appropriate zonal boundaries into the annual process used to calculate transfer limits for RSP and NERC statutory requirements– The automatic trigger would continue to define whether a zone is modeled

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STAKEHOLDER DISCUSSIONS


Summary/Highlights

• At the July 7, 2013 RC meeting we discussed– The requirements of the FERC order– The constraints observed and expected on the New England system– The methodologies in place to calculate requirements– Considerations in the design of capacity zones– The timeline challenges associated with making changes for FCA-9

• At the July 22 and 23, 2013 Summer RC meeting we discussed– The possibility of making some changes in time for FCA-9

• On July 30, 2013, the ISO submitted the compliance timeline to FERChttp://www.iso-ne.com/regulatory/ferc/filings/2013/jul/er12-953-002_7-30-13_fcm_zone_compliance_filing.pdf

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http://www.iso-ne.com/regulatory/ferc/filings/2013/jul/er12-953-002_7-30-13_fcm_zone_compliance_filing.pdf

http://www.iso-ne.com/regulatory/ferc/filings/2013/jul/er12-953-002_7-30-13_fcm_zone_compliance_filing.pdf

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Summary/Highlights, continued

• At the August 19, 2013 RC meeting we discussed– The capacity zone creation methodologies in place in PJM and New

York– The Transmission Security Analysis (TSA) that has been performed in

New England for the 8 Energy Zones– The transmission transfer capability analysis processes in place in New

England– Possible ways forward

Stakeholder ProcessAs defined by FERC

• FERC has required the ISO to consider the following during the Stakeholder Process: “…(1) the appropriate level of zonal modeling going forward; (2) the

appropriate rules to govern intra- and inter-zonal transactions; and (3) whether objective criteria by which zones may automatically be created in response to rejected delist bids, generation retirements or other changes in system conditions would be appropriate in New England, or if not, why not.”

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Docket No. ER12-953-002: Order Issued May 31, 2013

Subsequent FilingAs defined by FERC

• FERC has required the ISO to make an additional filing at a later time to address:

“…how it has addressed these items in its stakeholder process, and it must: (i) develop and file with the Commission revisions to the ISO-NE tariff that articulate appropriate objective criteria to revise the number and boundaries of capacity zones automatically as the relevant conditions change, or (ii) file with the Commission an explanation as to why such criteria are unnecessary.”

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Docket No. ER12-953-002: Order Issued May 31, 2013

CAPACITY ZONE FORMATION METHODOLOGIES IN PLACE IN PJM AND NEW YORK


PJM Methodology Summary

• A starting list of Locational Deliverability Areas (LDAs) are defined in the PJM Reliability Assurance Agreement (RAA)– The RAA lists a number of zones, most of which align with the

footprints of the member Transmission Owning utilities or aggregations thereof

• Any changes to the list of LDAs are those areas that have a limited ability to import capacity due to physical limitations of the transmission system, voltage limitations or stability limitations – Identified by the load deliverability analyses conducted pursuant to

the Regional Transmission Expansion Planning (RTEP) Protocol

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PJM Methodology Summary, continued

• A new LDA is created if such new LDA is projected to have a capacity emergency transfer limit (CETL) less than 1.15 times* the capacity emergency transfer objective (CETO) of such area, or if warranted by other reliability concerns consistent with the Reliability Principles and Standards

• A FERC filing is made to amend the LDA list

*This trigger describes how capacity zones are automatically created in PJM

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Cleveland LDAAn Example of How a New Zone is Created in PJM

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Cleveland LDA, continuedAn Example of How a New Zone is Created in PJM

• As part of the 2012 RTEP process, PJM analyzed the need to model an LDA in the Cleveland area

• A number of recent generator deactivation notices and transmission reinforcements in the Cleveland area drove the need in 2012 to consider establishing a new LDA

• Transmission facilities in the Cleveland metropolitan area have been historically constrained by voltage and stability limitations as transfers into the area have risen over time

• These limitations have diminished the ability of Load Serving Entities (LSEs) to import power into the area

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Cleveland LDA, continuedAn Example of How a New Zone is Created in PJM

• The peak load inside the interface is approximately 5,000 MW

• Previously, Cleveland was part of the larger ATSI (formerly FirstEnergy) zone

• The CETL/CETO ratio was actually found to exceed 1.15

• However, given that the “Cleveland Reactive Operational Interface” is an electrical area which PJM dispatchers already monitor to ensure reliability under real-time conditions, PJM selected it to become a new “Cleveland LDA”

• The addition of the new zone was presented in the RTEP planning process and then filed at FERC

• Approved by the FERC, effective January 4, 2013, the new LDA has been used for the first time in RTEP process studies in 2013 and for RPM activities in May 2013

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NY Methodology Summary

• NYISO’s aligns the process for creating a new capacity zone with the triennial ICAP demand curve reset process

• NYISO begins the new capacity zone process with a New Capacity Zone Study (NCZ Study)

• If the NCZ Study identifies a Highway deliverability constraint (Highway constraint), NYISO will identify the boundary of a proposed new capacity zone

• A locational minimum ICAP requirement is determined, followed by an analysis of a demand curve for the new capacity zone and submission to the Commission of tariff revisions to establish the new capacity zone

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Lower Hudson Valley ZoneAn Example of How a New Zone is Created in NY

• In the recently completed NCZ study, NYISO identified the UPNY/SENY (Upstate New York/South East New York – located south of Albany) as a Highway deliverability constrained

• The NCZ study was discussed in the NY planning process

• NYISO filed with FERC the creation of a new downstate zone which merges Zones G, H, I & J– This leaves New York with three zones

• Rest of State (approximately 13,000 MW)• “Lower Hudson Valley” (approximately 16,700 MW)• Long Island (Zone K, approximately 6,000 MW)

• FERC approved the new zonal configuration in Docket No. ER13-1380-000

AUTOMATIC TRIGGERS FOR THE MODELING/CREATION OF ZONES


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The Attributes of a Zone

• The load in a zone is met by:– the addition of:– Resources in the Zone +

Import Capability

• Simplified Example Zone– In this case the load is exactly

met

Load = 9,000 MWResources = 8,000 MW

Import Capability = 1,000 MW

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Calculating Requirements

• There are two ways to think about calculating requirements:1. Resources: What amount of

Resources are required for a given Import Capability?

Or,2. Import Capability: What

amount of Import Capability is required for a given set of Resources?

• Simplified Example Zone

Load = 9,000 MWResources = ? MW

Import Capability = ? MW

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Which Import Capability?

• It is required under the planning criteria to consider N-1-1 events

• This discussion will focus on the N-1-1 Import Capability

• This will be equivalent to the line-line calculations described in Transmission Security Assessments (TSA)


Load = 9,000 MWResources = ? MW

N-1-1 Import Capability = ? MW

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Calculating a Transmission Security Requirement

• A TSA Requirement is calculated as follows (simplified):

• Assume resource unavailability of 5%

• TSA Requirement = 5,263 MW


Load = 9,000 MW

N-1-1 Import Capability = 4,000 MW

(Load – Import Limit)

1 - (resource unavailability factor)TSA Requirement

(9,000 – 4,000)

1 - (0.05)TSA Requirement

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Designing a Resource-Based Trigger


• Using a 15% automatic trigger for modeling zones:– If there is more than 1.15*5,263

MW = 6,052 MW of Existing Resources in the zone, then the zone would not be modeled

• Note: If there is more than 5,263 MW remaining in auction, the zone would not bind in the auction


Load = 9,000 MW

TSA = 5,263 MW


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A Resource-Based Trigger Considering Potential Retirements


• The largest resource in the zone is 1,000 MW

• Using a potential retirement automatic trigger for modeling zones:– If there is more than 5,263 +

1,000 = 6,263 MW of Existing Resources in the zone, then the zone would not be modeled


Load = 9,000 MW

TSA = 5,263 MW


The largest Resource is1,000 MW

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A “Higher Of” Resource-Based Trigger


• If the Existing Capacity of the Resources in the zone is greater than the higher of the [TSA*1.15] or the [TSA+the largest resource], then the zone would not be modeled


Load = 9,000 MW

TSA = 5,263 MW



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Designing an Import Limit-Based Trigger (This approximates the PJM method)• What is the required Import

Limit if the load is 7,000 MW and the Resources total 5,000 MW– The unavailability factor of the

Resources should be considered (assume 5%)

– Available Resources = 4,750 MW

• “Required” N-1-1 Import Capability = 2,250 MW

• If the import capability is greater than 1.15*2,250 = 2,587 MW, then the zone would not be modeled




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An Import-Based Trigger Considering Potential Retirements

• “Required” Import Capability = 2,250 MW

• The largest resource in the zone is 1,000 MW

• If the import capability is greater than 2,250 + 1,000 = 3,250 MW, then the zone would not be modeled





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A “Higher Of” Import Limit-Based Trigger

• “Required” Import Capability = 2,250 MW

• If the import capability is greater than [1.15*Required Import Capability] or [Required Import Capability + the largest resource], then the zone would not be modeled





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What if the Import Capability of a Zone has not been calculated?• A zone could be evaluated based

on its load and resources

• If there is enough Existing Capacity in the zone (considering no import capability) to meet the load, then the zone would not be modeled

• If some import capability is needed, N-1-1 power flow analysis can be used to confirm that the load can be served– This analysis would consider the

unavailability of one or more resources


LoadResources

TREATMENT OF EXPORT CONSTRAINED ZONES


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Modeling Export Constrained Zones

• What is the required Export Capability if the load is 2,000 MW and the Resources total 4,000 MW– The unavailability factor of the

Resources should be considered (assume 5%)

– Available Resources = 3,800 MW

• The Export Capability needs to be 3,800 – 2,000 = 1,800 MW to avoid locked-in capacity

• If the export capability is greater than 1.15*1,800 = 2,070 MW, then the zone would not be modeled



Export Capability = ? MW

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Export Constrained Zones

• Maine will continue to be evaluated for export constraint

• North of Orrington South will not be added as a capacity zone– There is no reliability benefit or need to do this– For FCA-9, the smallest building block is the Load Zone

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Modeling SEMA/RI

• SEMA/RI (Southeast Massachusetts/Rhode Island) has been identified as export constrained for many years

• The only interface currently available to System Planning that could be associated with modeling the SEMA/RI zones is the SEMA/RI Export Limit– 3,000 MW through 2017– 3,400 MW after 2017

• SEMA/RI

RI SEMA

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Modeling SEMA/RI, continued

• When Resource unavailability is considered, SEMA/RI does not appear to be export constrained at peak load

• The ISO does not propose to consider evaluating SEMA-RI as export constrained in FCA-9

• SEMA/RI – FCA-5 Values– 90/10 Load = 6,235 MW– Resources = 9,360 MW

RI SEMA

ANNUAL PLANNING PROCESS:PROPOSED ALIGNMENTS, AND ENHANCEMENTS


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FAC-013-2• NERC Standard FAC-013-2 ensures that Planning Coordinators have a

methodology for, and perform an annual assessment to identify potential future Transmission System weaknesses and limiting facilities that could impact the Bulk Electric System’s ability to reliably transfer energy in the Near-Term Transmission Planning Horizon

• In New England, when identifying potential future Transmission System weaknesses, consideration will be given to rejected delist bids, generation retirements or other changes in system conditions

Near-Term Transmission Planning Horizon = the transmission planning period that covers years one through five.

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Alignment of Planning Processes

• NERC FAC-013-2 activities have been brought in alignment with– FERC 715 reporting of various aspects the transmission system and the

transmission planning process– The calculation of future transmission limits needed for various

activities and documented in the Regional System Plan

• The following slide contains the most recent presentation of transfer capabilities that were provided to the Power Supply Planning Committee at their June 3, 2013 meeting

RSP13 Base Interface Limits

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Notes are discussed in Appendix 1 of this presentation

Single-Value, Summer Peak,1 Non-Firm, Transmission Interface Limits for Use in Subarea Transportation ModelsInterface 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022New Brunswick-New England 7002 7002 7002 7002 7002 7002 7002 7002 7002 7002

Orrington South Export 1200 1200 1325a 1325 1325 1325 1325 1325 1325 1325Surowiec South 1150 1150 1500a 1500 1500 1500 1500 1500 1500 1500Maine-New Hampshire 1600 1600 1900a 1900 1900 1900 1900 1900 1900 1900North-South 2700 2700 2700 2700 2700 2700 2700 2700 2700 2700East-West 2800 2800 2800 2800 2800 3500b 3500 3500 3500 3500West-East 1000 1000 1000 1000 1000 2200b 2200 2200 2200 2200 Boston Import (N-1) 4900 4850c 4850 4850d 4850 4850 4850 4850 4850 4850Boston Import (N-1-1) 3700 4175c 4175 4175d 4175 4175 4175 4175 4175 4175

SEMA ExportNo

LimitNo

LimitNo

LimitNo

LimitNo

LimitNo

LimitNo

LimitNo

LimitNo

LimitNo

LimitSEMA/RI Export 3000 3000 3000 3000 3000 3400b 3400 3400 3400 3400 Connecticut Import (N-1) 3050e 3050 3050 3050 2800f 2950b 2950 2950 2950 2950Connecticut Import (N-1-1) 1850e 1850 1850 1850 1600f 1750b 1750 1750 1750 1750SW Connecticut Import (N-1) 3200 3200 3200 3200 3200 3200 3200 3200 3200 3200Norwalk / Stamford 1650 1650 1650 1650 1650 1650 1650 1650 1650 1650 HQ-NE (Highgate) 200 200 200 200 200 200 200 200 200 200HQ-NE (Phase II)3 1400 1400 1400 1400 1400 1400 1400 1400 1400 1400Cross-Sound Cable (CSC) (In)4 0 0 0 0 0 0 0 0 0 0Cross-Sound Cable (CSC) (Out) 346 346 346 346 346 346 346 346 346 346NY-NE Summer5 1400 1400 1400 1400 1400 1400 1400 1400 1400 1400NY-NE Winter5 1875 1875 1875 1875 1875 1875 1875 1875 1875 1875NE-NY Summer5 1200 1200 1200 1200 1200 1200 1200 1200 1200 1200NE-NY Winter5 1400 1400 1400 1400 1400 1400 1400 1400 1400 1400

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Assessment of New Interfaces

• NERC FAC-013-2 activities will be further enhanced to incorporate the examination of future capacity zones and associated transfer capabilities– The transfer capability assessment will include the review of whether

additional interfaces would be required in the case of submitted or potential resource retirements

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Attachment K

• Attachment K of the ISO New England Open Access Transmission Tariff (OATT) describes the Regional System Planning (RSP) Process in New England

• According to Attachment K, the RSP shall, among other things:– describe, in a consolidated manner, the assessment of the PTF system needs, the

results of such assessments, and the projected improvements;– provide the projected annual and peak demands for electric energy for a five-to ten-

year horizon, the needs for resources over this period and how such resources are expected to be provided;

– specify the physical characteristics of the physical solutions that can meet the needs defined in the Needs Assessments and include information on market responses that can address them; and

– provide sufficient information to allow Market Participants to assess the quantity, general locations, operating characteristics and required availability criteria of the type of incremental supply or demand-side resources, or merchant transmission projects, that would satisfy the identified needs or that may serve to modify, offset or defer proposed regulated transmission upgrades.

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Attachment K, continued

• According to Attachment K, one of the triggers for a Needs Assessment is:– constraints or available transfer capability limitations that are

identified possibly as a result of generation additions or retirements, evaluation of load forecasts or proposals for the addition of transmission facilities in the New England Control Area

• In addition Needs Assessments are conducted for Rejected Non-Price Retirement Requests and De-List Bids– On-going Needs Assessments reflect Resources with Non-Price

Retirement Requests or Permanent De-List Bids as unavailable for reliability

– New Needs Assessments may be initiated

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Proposed addition to Attachment K

• The annual Transfer Capability Assessment, conducted pursuant to NERC Standard FAC-013-2, and the identification of any new interfaces will be a part of the annual RSP process

• The annual assessment will include the consideration of the addition of new interfaces that would result from submitted or potential retirements of resources

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Requirements Calculations

• A new interface and associated zone will be included in the preparation for a given FCA if the transfer capability analysis is complete in time for the requirement calculation process for the FCA

• Zones that do not trigger the automatic criteria are merged into the Rest-of-Pool zone

• The requirements calculations for the new capacity zone will follow the normal stakeholder review process used for FCA requirements calculations

• The LSR and MCL requirements calculations for import- and export-constrained zones will be unchanged– The higher of the Transmission Security Assessment and the Local Resource

Adequacy will be used to set LSR

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FERC Filing

• The zonal requirement of any new zone, along with the associated transfer capability will be included in the pre-FCA FERC filings

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Vermont ZoneExample of How a New Zone Could be Evaluated in the Planning Process

• In response to repeated requests to de-list generation in Vermont, the ISO had begun the process of defining an interface and calculating a transfer capability into Vermont

• The ISO will evaluate the modeling of a Vermont Zone in FCA-9– In response to a request to retire

generation

• Will be discussed in the RSP process in 2014

• Vermont Zone

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SEMA/RIExample of How a New Zone Could be Evaluated in the Planning Process

• SEMA/RI is a good example of why the load zone boundaries are not necessarily useful interfaces for modeling capacity zones– Some are perhaps counter-

productive

• For FCA-10 and beyond, the planning process can evaluate the addition of a more appropriate interface to manage the issues that could drive the need for a capacity zone

• SEMA/RI – FCA-5 Values– 90/10 Load = 6,235 MW– Resources = 9,360 MW

RI

SEMA

?

?

OTHER ISSUES

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Minimum Zone Size

• The zones modeled in PJM and New York are relatively large (many 1,000s MW)– Many zones are merged together in the absence of triggering the

objective criteria

• ISO New England proposes to remain focused on the more significant load serving constraints– Interregional Operating Limits (IROLs)

• Rule of thumb minimum IROL size is 1,200 MW of transfer capability or served load

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The Role of Market Resource Alternatives

• Market Resource Alternatives (MRAs – also known as Non-Transmission Alternatives or NTAs) are, by definition, a consideration in the long-term transmission planning space

• If NTAs become committed through the Forward Capacity Market or appropriate contract, they would be reflected in the zonal modeling process

LISTING OF THE ISO PROPOSAL

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ISO Proposal for The Management of Capacity Zones1. In Market Rule 1, Section 12 add automatic trigger(s) for the modeling and

creation of zones

2. For FCA-9 capacity zones would be created by implementing the objective criteria (automatic trigger) using the existing 8 energy zones as the starting point– The 8 energy zones will serve as an approximation of the real transmission operating

boundaries– Energy zones that do not exceed the automatic trigger will be collapsed into the Rest-

of-Pool Capacity zone– The objective criteria for the automatic creation of zones would be based on the TSA-

like analysis of the energy zone along with the security constrained import analysis

3. For FCA-10 and beyond, incorporate the analysis of appropriate zonal boundaries into the annual process used to calculate transfer limits for RSP and NERC statutory requirements– The automatic trigger would continue to define whether the zone would be created

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ISO Proposal for The Management of Capacity Zones, continued

4. In conducting compliance transfer capability analysis pursuant to FAC-013-2, include the review of whether new interfaces should be added based on submitted or potential retirements

5. Add to Attachment K the presentation of the annual transfer capability assessments as part of the annual RSP process

6. Once a zone is modeled in the FCA, it will persist in the subsequent reconfiguration auctions and bilateral transaction windows for that Capacity Commitment Period– No change to bilateral trading rules

STEPS TO IMPLEMENTATION

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Steps to Completion

• Changes to Market Rule 1 Section 12– Reliability Committee

• Changes to Planning Procedure 10– Reliability Committee

• Changes to Attachment K?– Transmission Committee

• Changes to Market Rule 1 Section 13?– Markets Committee

• FERC Filing

Schedule for Implementation

Implementation for FCA #9:

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Dates Discussion Topics

Jul - Sep 2013 Discuss current methodologies and explore new methodologies for determining zones and requirements while minimally changing other aspects of the FCM

Sep - Nov 2013 Finalize principles for zone creation

Nov 2013 - Jan 2014 Define zones and finalize zonal requirements; begin Tariff language changes

RC (with MC invitation) Action Jan - Feb 2014

NPC Action Early March 2014

FERC Filing of Tariff Changes Late March 2014

FERC Order* Late May 2014

* FERC Order to be received after opening of the Show of Interest Window but before New Capacity Qualification Deadline and De-list Bid Deadline

APPENDIX 1:NOTES TO THE RSP13 BASE INTERFACE LIMITS


RSP13 Base Interface Limits

1. Limits are for the Summer period, except where noted to be winter– The limits do not include possible simultaneous impacts, and should not be considered

as “firm” (the bases for these limits are subject to more detailed review in the future)

– For the years within the Forward Capacity Market (FCM) horizon (2017 [Forward Capacity Auction 8] and sooner), only certified transmission upgrades are included when identifying transfer limits

– For the years beyond the FCM horizon (2018 and later), proposed plan approved transmission upgrades are included according to their expected in-service dates

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RSP13 Base Interface Limits, continued

– Relevant in-service datesa) Maine Power Reliability Program – 2015

b) NEEWS Interstate Reliability Program – 12/2015 (However, not all portions of this project have been certified to be in service by 2017)

c) The Boston import capabilities change in 2014 as a result of the combination of the retirement of Salem Harbor and the inclusion of the advanced NEMA/Boston upgrades

d) The effect of the addition of the Footprint generation project on the Boston import capability will be evaluated at a future date

e) NEEWS Greater Springfield Reliability Program – 2013

f) With the certification of the new 345 kV Lake Road-Card line, the Lake Road generating facility will be modeled in the Connecticut zone for Capacity Commitment Period 8 (2017)

– The 345 kV Lake Road-Card line was certified to be in-service by 2016. It is under review whether Lake Road will be modeled in the Connecticut zone for Capacity Commitment Period 7 (2016) .

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2. The electrical limit of the New Brunswick-New England (NB-NE) Tie is 1,000 MW

– When adjusted for the ability to deliver capacity to the greater New England Control area, the NB-NE transfer capability is 700 MW

• This is because of downstream constraints; in particular Orrington South

3. The Hydro-Quebec Phase II interconnection is a DC tie with equipment ratings of 2,000 MW. Due to the need to protect for the loss of this line at full import level in the PJM and NY Control Areas’ systems, ISO-NE has assumed its transfer capability for capacity and reliability calculation purposes to be 1,400 MW

– This assumption is based on the results of loss-of-source analyses conducted by PJM and NY

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4. Import capability on the Cross Sound Cable (CSC) is dependent on the level of local generation

5. New York interface limits– These are without CSC and with the Northport Norwalk Cable at 0 MW flow

– Simultaneously importing into NE and SWCT or CT can lower the NY-NE capability (very rough decrease = 200 MW)

– Simultaneously exporting to NY and importing to SWCT or CT can lower the NE-NY capability (very rough decrease = 700 MW)

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APPENDIX 2:TSA CALCULATIONS FOR FCA-5


FCA-5 TSA Requirements

• Review the assumptions, methodology and Transmission Security Analysis (TSA) requirements for the 2014-2015 Capacity Commitment Period (FCA-5)in New England

• The methodology and assumptions used to determine the 2014/15 TSA requirements were developed in accordance with section III.12.2.1.2. of Market Rule 1, and section 6 of ISO Planning Procedure 10 – Planning Procedure to Support the Forward Capacity Market

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FCA-5 TSA Requirements - Model

• The calculation of the FCA-5 local capacity requirements, including the TSA requirements, relied on the latest available data– Load forecast, resource data and resource availability were presented

to the Power Supply Planning Committee on 12/06/2010; details are available at:

http://www.iso-ne.com/committees/comm_wkgrps/relblty_comm/pwrsuppln_comm/mtrls/2010/dec62010/index.html

– The transmission topology that was certified for FCA-5 was introduced at the 09/20/10 Reliability Committee; details are available at:

http://www.iso-ne.com/markets/othrmkts_data/fcm/qual/models/index.html

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http://www.iso-ne.com/committees/comm_wkgrps/relblty_comm/relblty/mtrls/2009/oct202009/a4_fca4_basecase_development.pdf




Methodology• The TSA determines the requirement of an area (in the case of FCA-5 the

energy load zone) to meet its load through internal generation and import capability

• It stems from ISO Planning Procedure 3 - Reliability Standards for the New England Area Bulk Power Supply System key transmission security requirements– Identify all resources and serve area load under N-1 and N-1-1 conditions– Perform review under reasonably stressed conditions (“With due allowance for

generator maintenance and forced outages”)

• It is performed via a series of transmission load flow studies– In performing the analysis, static transmission interface transfer limits may be

established as a reasonable representation of the transmission system’s capability to serve sub-area load with available existing resources

• Results may be presented in the form of a deterministic operable capacity analysis

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Methodology, continued• When presented in the form of a deterministic operable capacity analysis, the TSA

compares need with available resources– Needs include

• Load + Loss of Generator (“Line-Gen” scenario), or• Load + Loss of import capability (going from an N-1 import capability to an N-1-1 import

capability; “Line-Line” scenario)– Resources include

• N-1 Import capability• Regular generation• Operating actions (fast start units, demand response…)

– Resource unavailability is applied by de-rating capacity

• Example

Subarea 90/10 Load 8 300Reserves (Largest unit or loss of import capability) 1 200

Subarea Transmission Security Need 9 500Existing Resources 10 000Assumed Unavailable Capacity 500Subarea N-1 Import Capability 2 500

Subarea Available Resources 12 000

Subarea Transmission Security Margin 2 500

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Methodology, continued• For each of the potential import constrained Capacity Zones, the TSA

requirement (resource requirement that will be compared to the Local Resource Adequacy Requirement) is the amount of internal resources (generators and Demand Resources) needed in the zone, so that the Line-Line or Line-Gen requirements can be met after proper accounting for resource unavailability

• The TSA requirement can be approximated by using the following formula

(Need – Import Limit)

1 - ( Assumed Unavailable Capacity / Existing Resources)TSA Requirement

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Methodology, continued• Example: Subarea 90/10 Load 8 300

Reserves (Largest unit or loss of import capability) 1 200Subarea Transmission Security Need 9 500

Existing Resources 10 000Assumed Unavailable Capacity 500Subarea N-1 Import Capability 2 500

Subarea Available Resources 12 000

Subarea Transmission Security Margin 2 500

(9,500 – 2,500)

1 - (500/ 10,000)TSA Requirement 7,368 MW

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Methodology, continued

• The application of the TSA requirement calculation using energy load zones is an approximation, due to:– The use of static transmission interface transfer limits– The reliance on specific scenarios (“Line-Gen”) and (“Line-Line”)– The nature of the calculation

• The term [Assumed Unavailable Capacity / Existing Resource] in the above equation depends on the actual proportion of regular generation, peaking generation, intermittent resources, Real-Time Emergency Generation (RT-EG), active non-RTEG Demand Resources (DR) and passive DR

– The fact that the energy load zones boundaries do not exactly correspond to the real transmission operating boundaries

• Real transmission operating boundaries are based on the limiting constraints that define a geographic areas (within which resources have a very high probability of substitutability) import capability and the ability of the resources within the zone to alleviate those constraints

• The TSA requirement should be calculated based on an area’s real transmission operating boundaries. However, the TSA calculation using energy load zones could serve as an approximation for what the requirement would be for the geographic area that contains an individual or combined energy load zone.

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FCA-5 TSA Requirements and Related Analysis, cont.• TSA requirements were calculated for both a “Line-Gen” and “Line-Line”

scenario• As a worst-case sensitivity analysis, TSA requirements were also calculated

for the New Hampshire, Rhode Island, SEMASS, WCMASS and Vermont Load Zones; a worst-case assumption of 0 MW of N-1 and N-1-1 import transfer capability was initially assumed for these Load Zones– As further sensitivity, a Capacity Zone determination was performed

» It was assumed that in every Load Zone, the Local Sourcing Requirement would be set by the TSA requirement

» The determination was based on the methodology described in section III.12.4 of Market Rule 1

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1 Connecticut

NEMA/Boston(Salem Harbor

assumed "in" in the TSA analysis)


assumed "out" in the TSA analysis)New Hampshire Rhode Island SEMASS WCMASS Vermont

2 Zone 2014 90/10 Load 8240 6325 6325 2815 2170 4065 4215 1160

3 Reserves (Largest unit or loss of import capability) 1225 1360 1360 1247 529 682 326 6044 Sub-area Transmission Security Need 9465 7685 7685 4062 2699 4747 4541 17645 Existing Resources** 9502 4017 3269 4427 2889 6471 4409 13276 Assumed Unvailable Capacity -779 -345 -176 -152 -229 -423 -268 -527 Sub-area N-1 Import Capability* 2600 4900 4775 0 0 0 0 08 Sub-area Available Resources 11323 8572 7868 4275 2660 6048 4141 12749 TSA Margin 1858 887 183 213 -38 1301 -400 -490

10

11 LSR (=TSA requirement, assuming TSA>LRA) 7478 3046 3075 4206 2931 5079 4835 1837

12 +Export Bid or Admin. Export De-List Bid with a path going through the zone 100 0 0 0 0 0 0 0

13 = Export-Adjusted LSR 7578 3046 3075 4206 2931 5079 4835 183714

15 Existing Capacity Resource in the Load Zone** 9502 4017 4017 4427 2889 6471 4409 132716 - Admin. Export De-List Bids in the Load Zone 0 0 0 0 0 0 100 017 - Non-Price Retirements in the Load Zone 0 0 0 0 0 0 0 0

18 =First Amount of capacity to be compared to the Export-Adjusted LSR 9502 4017 4017 4427 2889 6471 4309 1327

19

20

First Amount of capacity to be compared to the Export-Adjusted LSR 9502 4017 4017 4427 2889 6471 4309 1327

21 - Permanent De-List Bids 0 749 749 0 0 0 0 022 - Export Bids from non-FCM Pivotal Suppliers 0 0 0 0 0 0 0 0

23 - Static De-List Bids from non-FCM Pivotal Suppliers 0 0 0 0 0 127 16 40

24 =Revised Amount of capacity to be compared to the Export-Adjusted LSR 9502 3269 3269 4427 2889 6344 4293 1287

25

26 Revised Amount Minus Export-Adjusted LSR 1924 222 193 221 -42 1265 -542 -550

* Import Capability on the AC Ties** Includes 39 MW of Existing Import Resources over Phase I/II in WCMASS and 194 MW of Existing Import Resources over Highgate in Vermont

FCA-5 TSA Requirements – Line-Gen

69

All values in MW

1 Connecticut


assumed "in" in the TSA analysis)


assumed "out" in the TSA analysis)New Hampshire Rhode Island SEMASS WCMASS Vermont

2 Zone 2014 90/10 Load 8240 6325 6325 2815 2170 4065 4215 1160

3 Reserves (Largest unit or loss of import capability) 1200 1200 1400 0 0 0 0 04 Sub-area Transmission Security Need 9440 7525 7725 2815 2170 4065 4215 11605 Existing Resources** 9502 4017 3269 4427 2889 6471 4409 13276 Assumed Unvailable Capacity -800 -371 -202 -174 -231 -467 -280 -637 Sub-area N-1 Import Capability* 2600 4900 4775 0 0 0 0 08 Sub-area Available Resources 11302 8546 7841 4253 2658 6004 4130 12649 TSA Margin 1862 1021 116 1438 488 1939 -85 104

10

11 LSR (=TSA requirement, assuming TSA>LRA) 7469 2892 3145 2930 2359 4381 4500 1218

12 +Export Bid or Admin. Export De-List Bid with a path going through the zone 100 0 0 0 0 0 0 0

13 = Export-Adjusted LSR 7569 2892 3145 2930 2359 4381 4500 121814

15 Existing Capacity Resource in the Load Zone** 9502 4017 4017 4427 2889 6471 4409 132716 - Admin. Export De-List Bids in the Load Zone 0 0 0 0 0 0 100 017 - Non-Price Retirements in the Load Zone 0 0 0 0 0 0 0 0

18 =First Amount of capacity to be compared to the Export-Adjusted LSR 9502 4017 4017 4427 2889 6471 4309 1327

19

20

First Amount of capacity to be compared to the Export-Adjusted LSR 9502 4017 4017 4427 2889 6471 4309 1327

21 - Permanent De-List Bids 0 749 749 0 0 0 0 022 - Export Bids from non-FCM Pivotal Suppliers 0 0 0 0 0 0 0 0

23 - Static De-List Bids from non-FCM Pivotal Suppliers 0 0 0 0 0 127 16 40

24 =Revised Amount of capacity to be compared to the Export-Adjusted LSR 9502 3269 3269 4427 2889 6344 4293 1287

25

26 Revised Amount Minus Export-Adjusted LSR 1933 376 124 1497 530 1962 -207 69

* Import Capability on the AC Ties

** Includes 39 MW of Existing Import Resources over Phase I/II in WCMASS and 194 MW of Existing Import Resources over Highgate in Vermont

FCA-5 TSA Requirements – Line-Line

70

All values in MW

FCA-5 TSA Requirements - Results• The Load Zone sensitivity analysis showed that

– Regardless of their N-1 or N-1-1 import capability, there was no need to form separate capacity zones for New Hampshire or SEMASS, because the revised amount of capacity to be compared to the export-adjusted LSR could not be lower than the export-adjusted LSR

– Under the worst-case assumption where the N-1 or N-1-1 import capability into Rhode Island, WCMASS and Vermont is below the required import capability shown below, the revised amount of capacity to be compared to the export –adjusted LSR can be less than the export-adjusted LSR; however, these Load Zones’ interfaces are such that they include many 345kV, 230kV or 115kV ties; therefore, there is still no need to form separate capacity zones for Rhode Island, WCMASS and Vermont

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Load Zone Required Import Capability (MW) Load Zone Interface Characteristics

Rhode Island N-1: 38 MW 3 345kV and 8 115kV paths into the load pocket

WCMASS N-1: 509 MWN-1-1: 194 MW

8 345kV, 2 230kV and 15 115kV paths into the load pocket

Vermont N-1: 528 MW 2 345kV, 1 230kV and 7 115kV paths into the load pocket

Compare with PJM’s capacity emergency transfer objective

September 03, 2013 | Westborough, MA

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