Manasa Kotha 4135404753mkothaisonecom 20202021 Third Annual Reconfiguration Auction 20202021 ARA 3 20212022 Second Annual Reconfiguration Auction 20212022 ARA 2 20222023 First Annual Reconfiguration Auction 20222023 ARA 1 ID: 783704
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Slide1
AUGUST 9, 2019, Holyoke Massachusetts
Manasa Kotha(413)-540-4753|mkotha@iso-ne.com
• 2020-2021 Third Annual Reconfiguration Auction (2020-2021 ARA 3) • 2021-2022 Second Annual Reconfiguration Auction (2021-2022 ARA 2) • 2022-2023 First Annual Reconfiguration Auction (2022-2023 ARA 1)
Assumptions for the Installed Capacity Requirement (ICR) Values
Calculations
Slide2Objective of this Presentation
Review the ICR-Related Values* development, NEPOOL committee review and FERC filing schedules
for Annual Reconfiguration Auctions (ARAs) to be conducted in 2020Review the assumptions for calculating:
Installed Capacity Requirement (ICR)Transmission Security Analysis (TSA)Local Resource Adequacy Requirement (LRA)Local Sourcing Requirement (LSR)
Maximum Capacity Limit (MCL)
Marginal Reliability Impact (MRI) System Wide and Zonal Demand Curves, as applicable
*The ICR, TSA, LRA, LSR, MCL, Demand Curve values and
the Hydro-Quebec Interconnection Capability Credits (HQICCs) are collectively referred to as the ICR-Related Values
2
Slide3ARAs ICR-Related Values Development ScheduleICR-Related Values for the ARAs to be conducted in 2020 will be calculated, reviewed and filed concurrently2020-2021 ARA 3 ICR-Related Values
2021-2022 ARA 2 ICR-Related Values2022-2023 ARA 1 ICR-Related Values3
Date
TopicAugust 9
PSPC review of assumptions for ICR-Related Values for ARAs and assumptions for ARA 3 tie benefits study
August 29
PSPC review of ARA 3 tie benefits study
September 9
PSPC review of proposed ICR for ARAs
October 8
PSPC review of
proposed
ICR-Related Values
October 23
RC review/vote of proposed ICR-Related Values
November 1
PC review/vote of proposed ICR-Related Values
By November 30
File with FERC
Slide4Calculation of ICR-Related Values
4
LSR,
MCL, and
MRI Demand Curves will
be calculated for the
same Capacity
Zones determined for the respective Forward Capacity Auction (FCA)
ICR
-Related Values
CCP
2020-2021
CCP
2021-2022
CCP
2022-2023
Import
Capacity
Zone
(TSA, LRA, LSR)
Southeast New England (SEMA, RI, NEMA-Boston)
Southeast
New England (SEMA, RI, NEMA-Boston)
Southeast
New England (SEMA, RI, NEMA-Boston)
Export
Capacity
Zone
(MCL)
Northern New England
(ME,
NH, VT)
Northern New England
(ME,
NH, VT)
Northern New England (ME, NH
, VT
)
Demand
Curves
MRI Demand
Curves
System
&
Zonal
MRI Demand
Curves
System
&
Zonal
MRI Demand
Curves
System
&
Zonal
Slide5Assumptions for the CCP 2020-2021 ARA 3, CCP 2021-2022 ARA 2 and CCP 2022-2023 ARA 1
ICR-Related Values Calculations
5
Slide6Modeling the New England Control Area for ARAs to be Conducted in 2020The General Electric Multi-Area Reliability Simulation model (GE MARS) is used to calculate several of the ICR-Related ValuesInternal transmission constraints are not modeled in the ICR calculation. All loads and resources are assumed to be connected to a single electric bus
Internal transmission constraints are addressed through the LSR and MCLsA LSR will be calculated for the import-constrained Southeast New England (SENE) Capacity Zone, consisting of the NEMA/Boston, SEMA and RI Load ZonesAn MCL will be calculated for the export-constrained Northern New England (NNE) Capacity Zone, consisting of the combined Load Zones of Maine, New Hampshire and Vermont The MRI based method for calculating demand curves will be used to develop System and Capacity Zone Demand Curves
6
Slide77
Assumptions for the ICR-Related Values Calculations
Load Forecast
Net of behind-the-meter (BTM)
p
hotovoltaic
(PV) resource
forecastLoad forecast distributionQualified Capacity (QC) of resources*Generating Capacity Resources Intermittent
Power
Resources (IPR)
Import Capacity Resources
Demand Resources (DR
)
Resource availability
Generating Resources’ availability
Intermittent Power Resources’ availability
Demand Resources’ availability
*
Known resource retirements are removed; new cleared capacity resources are added as applicable; capacity imports are de-rated according to assumed external transmission transfer capability
.
Slide8OP-4 Actions used to Develop Assumptions for the ICR-Related Values Calculations
8
Load or capacity relief assumed obtainable from implementing the following actions of the Operating Procedure No. 4, Action during a Capacity Deficiency (OP-4)
Request emergency assistance from neighboring Control Areas (Tie reliability benefits)
Quebec (includes Hydro-Quebec Interconnection Capability Credits (HQICCs))
Maritimes
New York
Initiate 5% voltage reduction
Slide99
Load Forecast (MW)For Applicable Capacity Zones and Total New England
50/50 & 90/10 reference (net of BTM PV) load forecasts values are from the 2019 CELT load forecast (
labeled “2A Summer (MW): ISONE Control Area, New England States, RSP Sub-areas, and SMD Load Zones
”
) for the corresponding RSP sub-areas used in the ARA ICR Values calculations (see:
https://www.iso-ne.com/static-assets/documents/2019/04/forecast_data_2019.xlsx
)The reference 50/50 load forecast shown is for informational purposes; in the ICR Values calculations, the GE MARS model sees an hourly distribution of loads with the BTM PV modeled with an
hourly
profile and a 7-day window uncertainty methodology
The 90/10 load forecast values are used directly in the calculation of TSA for import-constrained Capacity Zones; all other values shown are for informational purposes
SENE
NNE
Total New England
CCP
50/50
90/10
50/50
90/10
50/50
90/10
2020-2021
12,244
13,213
5,300
5,533
28,353
30,273
2021-2022
12,337
13,325
5,339
5,595
28,499
30,449
2022-2023
12,439
13,449
5,386
5,645
28,670
30,652
Slide10Load Forecast, cont.Modeling of BTM PV
ICR calculations will use an hourly profile of BTM PV corresponding to the load shape for the year 2002, used by the Northeast Power Coordinating Council (NPCC) for reliability studies. For more information on the development of the hourly profile see: https://www.iso-ne.com/static-assets/documents/2017/06/pspc_6_22_2017_2002_PV_profile.pdfUsed for all probabilistic ICR-Related Values calculations
Modeled in GE MARS by Regional System Plan (RSP) 13-subarea representationIncludes an 8% transmission and distribution gross-upPeak load reduction uncertainty is modeled (randomly selected by MARS from
a seven day window distribution)The values of BTM PV published in the 2019 CELT Report are the values of BTM PV subtracted from the gross load forecast to determine the net load forecastThe published 90/10 net load forecast for the SENE sub-areas is used in the TSA
Notes:
For more info on the PV forecast, see
https
://www.iso-ne.com/static-assets/documents/2019/04/final-2019-pv-forecast.pdf 10
Slide11Resources’ Qualified Capacity (QC) Resource Data : Used the latest available data for each CCP
11Note:
*Qualified New Capacity Resources on critical path schedule monitoring with deliverability prior to June
1, 2022
2020-2021 ARA 3
2021-2022
ARA 2
2022-2023 ARA 1
2020-2021 ARA 2 bilateral
period QC
data
2021-2022 ARA
1 QC
data
2022-2023 FCA Existing QC
data + 2022-2023 FCA New Capacity Resources
amount
*
Import
Capacity Resources
The
QC
values are
de-rated
if the sum of the import
QC
is higher than the remaining
transmission
t
ransfer
c
apability
(TTC) of the external interface after accounting for tie benefits
This is the same procedure used for the ARA ICR calculations in previous years
Slide1212
Resources’ QC (MW)
By Capacity Zone & Total New England
2020-2021 ARA 3
2021-2022 ARA 2
2022-2023 ARA 1
Note:
Generating resources exclude a
30 MW derating to reflect the value of the
firm Vermont Joint Owners (VJO)
contract
for CCP 2020-2021 and CCP 2021-2022
Known retirement requests are removed from the applicable CCP
Resource Type
SENE
NNE
New England
Non-intermittent Generating Capacity Resources
9,651
7,368
30,482
Intermittent
Power Resources
223
557
1,061
Import
Capacity Resources
-
255
1,750
On-Peak Demand Resources
1,588
473
2,739
Seasonal Peak Demand Resources
-
-
596
Active Demand Capacity Resources
254
274
962
Grand Total
11,716
8,927
37,590
Resource Type
SENE
NNE
New England
Non-intermittent Generating Capacity Resources
9,652
7,360
30,227
Intermittent
Power Resources
222
7191,236Import Capacity Resources- 2511,680On-Peak Demand Resources1,6215302,874Seasonal Peak Demand Resources--656Active Demand Capacity Resources249253945Grand Total11,7449,11337,618
Resource Type
SENE
NNE
New England
Non-intermittent Generating Capacity Resources
9,640
7,314
31,008
Intermittent
Power Resources
478
650
1,395
Import
Capacity
Resources
-
235
1,698
On-Peak Demand Resources
1,742
537
3,013
Seasonal Peak Demand Resources
-
-
651
Active Demand Capacity Resources
326
259
1,086
Grand Total
12,186
8,996
38,851
Slide13Internal TTC Assumptions (MW)
- For LSR and MCL Modeling13
Based on transmission transfer capability limits presented at the March 20, 2019 Reliability Committee meeting. The presentation is available at
: https://www.iso-ne.com/static-assets/documents/2019/03/a7_fca_14_transmission_transfer_capabilities_and_capacity_zone_development.pdf
Southeast
New
England Import (MW)
(for SENE LSR)
North-South Interface (MW)
(for NNE MCL)
CCP
N-1
N-1-1
N-1
2020-2021
5,400
4,500
2,725
2021-2022
5,700
4,600
2,725
2022-2023
5,700
4,600
2,725
Slide14Resource Availability Assumptions
Generating
Capacity ResourcesForced outages assumption
Each generating unit’s Equivalent Forced Outage Rate on demand (non-weighted EFORd) modeledBased on a 5-year average (Jan 2014 – Dec 2018) of generating unit data submitted to Generation Availability Data System (GADS)
NERC GADS Class average data is used for immature & non-commercial units
Scheduled outage
a
ssumptionEach generating unit’s weeks of maintenance modeledBased on a 5-year average (Jan 2014 – Dec 2018) of each generating unit’s actual historical average of planned and maintenance outages scheduled at least 14 days in advance
NERC GADS
c
lass average data is used for immature & non-commercial units
Each CCP will have the appropriate
generating units
modeled along with their individual availability
statistics
Intermittent Power Resources are modeled as 100% available since their outages have been incorporated in their 5-year historical output used in their ratings
determination
14
Slide15Resource Availability Assumptions, cont
.
Demand Resources (DR)Use historical DR performance from summer & winter
2014 – 2018 (same values developed for FCA 14)For more information see the May 2019 PSPC presentation:
https://www.iso-ne.com/static-assets/documents/2019/05/a3_dr_season_perfrmnce_0530219.pdf
Modeled by Load Zones and type of DR with outage factor calculated as 1- performance/100
The
same performance values will be applied for CCP 2020-2021 through CCP 2022-202315
Slide16Resource Availability Assumptions, cont.16
Import Capacity
Resources
Modeled
in the ICR calculations
as:
Pool
backed are 100% availableResource backed are modeled with availability assumptions shown below
NERC Class Avg
EFORd
Maintenance (Weeks)
HYDRO 30 Plus
3.76
7.00
Slide17Resource Availability Assumptions, cont.
17
Note:
Non-intermittent Generating Capacity Resources uses the same per unit EFORd and maintenance weeks values developed for FCA 14. In the LOLE simulations, individual unit values are modeled
Assumed
summer MW weighted
EFORd/Forced Outage Rate (FOR)
and maintenance weeks are shown by resource types for informational purposesNon-intermittent Generating Capacity Resources category excludes a 30 MW
derating
to reflect the value of the firm VJO contract
CCP 2020-2021 ARA 3
Resource Type
Summer MW
Assumed Average EFORd (%) Weighted by Summer Ratings
Assumed Average Maintenance Weeks Weighted by Summer Ratings
Non-intermittent Generating Capacity Resources
30,482
6.3
4.9
Intermittent Generating Resources
1,061
0.0
0.0
Import Capacity Resources
1,750
2.7
8.2
On Peak Demand Resources
2,739
0.0
0.0
Seasonal Peak Demand Resources
596
0.0
0.0
Active Demand Capacity Resource
962
5.8
0.0
Total New England
37,590
5.4
4.3
Slide18Resource Availability
Assumptions, cont.18
CCP 2021-2022 ARA 2
Notes:Non-intermittent Generating Capacity Resources
uses the same per unit EFORd and
maintenance
weeks values developed for
FCA 14. In the LOLE simulations, individual unit values are modeledAssumed summer MW weighted EFORd/FOR and maintenance weeks are shown by resource type
for informational purposes
Non-intermittent Generating Capacity Resources
excludes
a 30 MW derating to reflect the value of the firm VJO contract
Resource Type
Summer MW
Assumed Average EFORd (%) Weighted by Summer Ratings
Assumed Average Maintenance Weeks Weighted by Summer Ratings
Non-intermittent Generating Capacity Resources
30,227
6.2
4.8
Intermittent Generating Resources
1,236
0.0
0.0
Import Capacity Resources
1,680
2.5
7.9
On Peak Demand Resources
2,874
0.0
0.0
Seasonal Peak Demand Resources
656
0.0
0.0
Active Demand Capacity Resource
945
5.6
0.0
Total New England
37,618
5.2
4.2
Slide19Resource Availability
Assumptions, cont.19
CCP 2022-2023 ARA 1
Note:Non-Intermittent Generating Resources uses the same per unit EFORd and Maintenance weeks values developed for
FCA 14.
In the LOLE simulations, individual unit values are modeled
Assumed summer MW weighted EFORd/FOR and maintenance weeks are shown by resource
types for informational purposes
Resource Type
Summer MW
Assumed Average EFORd (%) Weighted by Summer Ratings
Assumed Average Maintenance Weeks Weighted by Summer Ratings
Non-intermittent Generating Capacity Resources
31,008
6.1
4.8
Intermittent
Power
Resources
1,395
0.0
0.0
Import Capacity Resources
1,698
2.6
8.1
On Peak Demand Resources
3,013
0.0
0.0
Seasonal Peak Demand Resources
651
0.0
0.0
Active Demand Capacity Resource
1,086
5.9
0.0
Total New England
38,851
5.2
4.2
Slide2020
TSA Assumptions for Import Capacity Zones2020-2021 ARA 3, 2021-2022 ARA 2 and 2022-2023 ARA 1
2020-2021 ARA 3
2021-2022 ARA 2
2022-2023 ARA 1
DR Qualified Capacity are
same values used
as shown in Slide 12DR derating factors used in TSA are the same factors that are being used in FCA 14 ICR calculations
RI: 15%; SEMA:3%; NEMA:11%
Peaking Generating
Capacity Resources
uses the individual unit’s availability (EFORd)
Resource Type
SENE
QC(MW)
EFORD
Non-intermittent Generating Capacity Resources
9,651
6%
Intermittent
Power
Resources
223
0%
Resource Type
SENE
QC(MW)
EFORD
Non-intermittent Generating Capacity Resources
9,652
6%
Intermittent
Power
Resources
222
0%
Resource Type
SENE
QC(MW)
EFORD
Non-intermittent Generating Capacity Resources
9,640
6%
Intermittent Power
Resources
478
0%
Slide21Operating Procedure No. 4 (OP-4) Assumptions
- Actions 6 & 8—5% Voltage Reduction (MW)
Uses the 90-10 Peak load forecast net of BTM PV minus all DR multiplied by the 1% value assumed in estimating relief obtained from OP-4 voltage reduction
21
90-10 Peak Load
Passive DR
ACDR
Actions
6 & 8
5% Voltage Reduction
June
2020-Sept 2020
30,273
3,335
962
260
October
2020-May 2021
23,983
3,143
950
199
June
2021-Sept 2021
30,449
3,530
945
260
October
2021-May 2022
24,138
3,407
902
198
June
2022-Sept 2022
30,652
3,664
1,086
259
October
2022-May 2023
24,283
3,558
1,041
197
Slide22OP4 Assumptions,
cont. - Tie Benefits
Values for 2020-2021 ARA 3 tie benefits will be the results of the 2020 ARA 3 tie benefits studyValues for 2021-2022 ARA 2 and 2022-2023 ARA 1 are those calculated for the corresponding
FCAs (FCA 12 and FCA 13, respectively)22
Control Area
2020-2021
ARA 3
2021-2022
ARA 2 (MW)
2022-2023
ARA 1 (MW)
Quebec via Phase II
TBD
958
969
Quebec via Highgate
TBD
143
149
Maritimes
TBD
506
516
New
York AC ties
TBD
413
366
Total
2,020
2,000
The tie benefits availability assumptions will be based on the availability assumptions associated with the external transmission line
updated
using the newly proposed
methodology*
These are the same values used to model the performance of the Import Capacity Resources that are
p
ool-
b
acked
*
Based on recently updated values using the newly proposed methodology presented at the March 30, 2019 Power Supply Planning Committee meeting.
The
presentation is available at:
https://www.iso-ne.com/static-assets/documents/2019/05/a5_tie_line_availability_05302019.pdf
Slide23OP4 Assumptions, cont. - Minimum System Reserve Assumption (MW)
23
Minimum
system r
eserve
is the
minimum reserves held for transmission system security
Modeled at 700 MW
Slide24Summary of all MW Modeled in the ICR Values Calculations
Notes:
Generating Capacity Resources excludes a 30 MW de-rate to reflect the value of the firm VJO contract for CCP 2020-2021 and CCP 2021-2022 Intermittent Power Resources have both the summer and winter capacity values modeled
Import Capacity Resources reflect a derating to account for TTC and each CCP’s tie benefitsOP-4 voltage reduction includes both Action 6 and Action 8 MW assumptionsMinimum system reserve is the minimum reserves held for transmission system securityTie benefits for 2020-2021 are the results of the 2020 ARA 3 tie benefits study; Tie benefits for 2021-2022 and 2022-2023 are those calculated for the corresponding FCA
24
Total
Capacity/OP4
Breakdown
2020-2021
ARA3
2021-2022
ARA2
2022-2023
ARA1
Non-intermittent Generating Capacity Resources
30,482
30,227
31,008
Intermittent
Power Resources
1,061
1,236
1,395
Import
Capacity Resources
1,750
1,680
1,698
Demand Resources
4,297
4,475
4,750
Voltage
Reduction
260
260
259
Minimum
system reserve
-700
-700
-700
Tie
benefits
TBD
2,020
2,000
Total Capacity
TBD
39,198
40,410
Slide25Appendix IAcronyms
25
Slide26AcronymsARA – Annual Reconfiguration AuctionBTM PV – Behind-the-meter Photovoltaic
FCA – Forward Capacity AuctionCCP – Capacity Commitment PeriodCSO – Capacity Supply ObligationCELT – Capacity, Energy, Loads and TransmissionCT – ConnecticutDR – Demand ResourceEE – Energy EfficiencyFCA – Forward Capacity Auction
FERC – Federal Energy Regulatory Commission26
Slide27Acronyms, cont.HQICCs – Hydro-Quebec Interconnection Capability CreditsICR – Installed Capacity RequirementISO – ISO New England
LRA – Local Resource AdequacyLSR – Local Sourcing RequirementMCL – Maximum Capacity LimitMRI – Marginal Reliability ImpactNet ICR – ICR minus HQICCs OP-4 – Operating Procedure No. 4, Action During a Capacity DeficiencyPC – Participants Committee
PSPC – Power Supply Planning CommitteeRC – Reliability CommitteeTSA – Transmission Security Analysis
27
Slide2828