NYISO Demand Side Programs and
Issues
Rana Mukerji
Senior Vice President - Market Structures
Markets for Demand Response Products
 Capacity Market
 Assure enough resources, including demand that can
be responsive, to assure resource adequacy
 Reserves & Regulation Market
 Keep sufficient resources, including responsive
demand, available in ten or thirty minutes to maintain
reliable operation.

Provide regulation services comparable to generators
 Energy Markets
 Schedule and dispatch resources, including pricesensitive demand, economically to meet customers’
demand 24 hours per day, 365 days per year.
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NYISO Demand Response
 Reliability-based programs


NYISO controls activation
Provide load reductions to supplement generation when operating
reserves are forecast to be short or actual Operating Reserve
Deficiency
• Emergency Demand Response Program (EDRP)
• ICAP-Special Case Resources (ICAP/SCR)
 Economic-based programs


Resource determines when to participate through bidding
Load reduction acting as - and competing with - generation
• Day-Ahead Demand Response Program (DADRP)
• Demand-Side Ancillary Service Program (DSASP)
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NYISO Special Case Resources & Emergency Demand
Response Program Have Added Almost 2000 MW Since
2000.
Peak Load Reductions from Demand Response - MW
2001, 2006, and 2009
2500
2147
2000
1500
1172
1000
500
1320
712
435
0
2001
2006
Actual Impact
2009
MW Capability
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19:15
19:25
19:35
19:45
19:55
20:05
20:15
17:55
18:05
18:15
18:25
18:35
18:45
18:55
19:05
17:35
17:45
16:13
16:25
16:35
16:45
16:55
17:05
17:15
17:25
8/2 NYCA
16:00
16:10
14:40
14:50
15:00
15:10
15:20
15:30
15:40
15:50
14:26
14:29
13:20
13:22
13:35
13:45
13:55
14:05
14:15
14:20
12:00
12:10
12:20
12:25
12:36
12:50
13:00
13:10
MW
MWs
NYISO – DR Impacts on 8/2/06
8/2 NYCA no DR
36000
35000
34000
33000
32000
31000
30000
29000
28000
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Capacity - Special Case Resources
 Available to curtailable load & emergency backup
generation of at least 100 kW per zone
 Activated for operating reserve deficiency
 Day-ahead advisory and a 2-hour in-day notification
 Mandatory – Penalties and derated for non-compliance
 Payment for capacity (kW) reduction plus payment for
energy (kWh) reduction at the greater of real-time price or
strike price (up to $500/MWh) for at least 4 hours.
 May set real time market price under scarcity pricing rules
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Emergency Demand Response
 Available to curtailable load & emergency backup
generation of at least 100 kW per zone
 Activated for operating reserve deficiency after SCR
resources
 Providers notified of activation 2 hours ahead, if possible
 Voluntary – no penalties for non-performance
 Payment for energy (kWh) reduction at the greater of real-
time price or $500/MWh for at least 4 hours.
 May set real-time energy price at $500/MWh
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Day-Ahead Demand Response
 Available to interruptible load only of at least 1 MW / zone
 Loads bid curtailment in Day-Ahead Market with
$75/MWh minimum bid
 Providers notified by 11 AM for following day schedule
 Mandatory – Penalties assessed for non-compliance
(penalized for buy-through at greater of DAM or RT price)
 Payment for energy (kWh) reduction at the greater of
DAM price or bid for actual interruption (also allowed lower
credit requirements by curtailment amount)
 May set DAM energy marginal price
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Demand-Side Ancillary Service
 Demand resources capable of at least 1 MW of curtailable
load may provide Regulation or Operating Reserves

Demand resources with local generation may only provide nonsynchronous reserves
 Demand resources selected based on economics of day-
ahead and/or real-time offers

Modeled as suppliers in the ancillary services markets
 Real-time telemetry required
 Performance measured relative to load at start of dispatch
 Payments based on interval-level performance index
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Real-Time Demand Response Pricing

FERC NOPR on DR Pricing
 Proposal would require full Locational Marginal Price (LMP)
payment for demand reduction in response to price signals
 Are DR and Generation comparable?
 “…the challenge of setting appropriate demand response
compensation inherently includes a consideration of retail rates.”
- Professor William Hogan, Harvard Electricity Policy Group
 A more economically efficient approach is “LMP-G”
 G = “an imputed amount reflecting some (or all) components of
the retail rate”
 Provides the correct economic price signal to curtail
 Avoids the need for complicated and contentious net benefits
test and cost allocation rules
 Full LBMP “subsidy” endangers development of dynamic retail
pricing
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Current Demand Response
Issues
 Evaluation of alternative demand response




baseline approaches
Direct telemetry to demand response resources
(including aggregated resources) providing
ancillary services
Rules for demand response participation in realtime energy markets (major issue is settlements)
Implementing Demand Response Information
System
Dynamic Pricing vs Demand Response
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NYISO Dynamic
Pricing Study

Purpose
 Estimate the wholesale market impacts of expanded dynamic
pricing
 No recommendation for particular rate design
 Approach
 Wholesale market simulation using proxy demand elasticity
for New York under multiple scenarios
• Conservation case
• High capacity price
• High demand elasticity
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Demand Reductions
Impact of Dynamic Pricing on Hourly Loads

Dynamic rates encourage shift
to off-peak usage

Reduced capacity requirement
drives savings: potential 1014% reduction in system peak

Additional benefits with
significant Plug-In Electric
Vehicle (PEV) deployment

Supports renewable resource
integration
Effects of Dynamic Pricing on Peak and Average Demand
Change in
Change in
Change in
New York City Long Island
Change in
Peak
Peak
Average Load
Dynamic Pricing Scenario System Peak
All Hours
All Hours
All Hours
All Hours
150 Hours
w/Max ∆ Load
Base Case
(MW)
(3,418)
(%)
(10%)
(MW)
(1,514)
(%)
(13%)
(MW)
(590)
(%)
(11%)
(MW)
84
(%)
0.4%
(MW)
(1,897)
(%)
(6%)
Conservation
(3,751)
(11%)
(1,514)
(13%)
(604)
(11%)
(288)
(1.5%)
(2,158)
(7%)
High Capacity Price
(4,282)
(13%)
(1,671)
(14%)
(776)
(14%)
176
1.0%
(3,147)
(11%)
High Elasticity
(4,603)
(14%)
(1,961)
(16%)
(779)
(14%)
130
0.7%
(3,606)
(12%)
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Cost Savings
Change in Annual Resource Costs
Dynamic Pricing Scenario
Change in
Capacity Cost
Total Change in
Resource Cost
(Million $)
(%)
(Million $)
(%)
(Million $)
(%)
10.6
0.3%
(153.6)
(11%)
(143.0)
(2.6%)
(188.2)
(4.5%)
(163.3)
(12%)
(351.5)
(6.3%)
60.3
1.4%
(569.0)
(13%)
(508.8)
(6.0%)
Change22.5
in Annual0.5%
Market-Based
Customer
Costs
(204.1)
(15%)
(181.6)
(3.3%)
Base Case
Conservation
High Capacity Price
High Elasticity
Change in Energy
Production Cost
Change in Annual Market-Based Consumer Costs
Dynamic Pricing Scenario
•
•
Change in
Market Based
Energy Costs
Change in
Capacity Costs
Total Change in
Market Based
Customer Costs
All Hours
All Hours
All Hours
(Million $)
(%)
(Million $)
(%)
(Million $)
(%)
Base Case
(17.8)
(0.2%)
(153.6)
(11%)
(171.3)
(1.6%)
Conservation
(415.6)
(4.3%)
(163.3)
(12%)
(578.9)
(5.2%)
High Capacity Price
62.1
0.6%
(569.0)
(13%)
(507.0)
(3.6%)
High Elasticity
(4.5)
(0.0%)
(204.1)
(15%)
(208.6)
(1.9%)
Total resource cost reduction of 3 to 6 percent ($143 to $509 mm) for the year
Market-based customer cost reduction of 2 to 5 percent ($171 to $579 mm) per year,
excluding AMI deployment costs
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How do we achieve these savings ?
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ISO/RTO Role: Wholesale Level
 Control & Operation of bulk system (transmission
system)
 Administration of wholesale electric markets
 Transparency of wholesale price signals
 Communications systems and smart grid devices
for:
 ISO/RTO control centers SCADA and economic
dispatch systems
 Generators connected to bulk system
 Transmission Owners’ control centers
 Aggregators of retail customer demand
response resources
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State Role: Retail Level
 Deployment of smart grid devices at the
distribution level
 Distribution stations and facilities
 Customer owned facilities
 Retail rate design
 Real time pricing
 Smart meters
 Providing cost recovery for TOs
 Allowing aggregation of retail loads
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Dynamic Retail Pricing

Currently only a fraction of large C&I load faces dynamic prices
 Currently, ~6000 MW large C&I in NY has hourly pricing as the
default, but only 20% of those stayed with the default. 80% went
to competitive LSEs, and about half of those chose fixed rates

Large untapped potential: if most/all customers faced dynamic
prices, peak hour consumption could be reduced by more than
10%
 NYISO/Brattle study

But greater participation is largely outside of NYISO’s control.
Depends primarily on actions by others:
 The state: approve AMI deployment (for mass market dynamic
pricing) & make dynamic pricing the default rate for more classes
of customers
 EDCs: install AMI
 LSEs: offer dynamic rates
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Dynamic Pricing Driving Smart
Grid / Renewables
Aggregator
Evolutionary
Market Design
Demand
Response
(Real Time)
NYISO
Control
Center
Dispatch
Instructions
&
Prices
Wind Generators
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Paradigm Shift – Load
follows generation
PHEV Charging Profile and Wind Power
12%
1.9
1.8
10%
1.7
8%
1.6
1.5
6%
1.4
4%
1.3
1.2
2%
1.1
0%
1
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Charging Profile
Wind PowerCharging Profile: EPRI/NRDC
Wind Power: 2007 average normalized load
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Smart Grid Future
 Dynamic price signals
 Intelligent load responding to price
Plug-in hybrid vehicles
 Advanced consumer components
 Seamless integration of intermittent resources
 Wind, solar, hydropower
 Enhanced control of power grid

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
People &
&
People
Process
Process

Regulatory & Market Incentives

Environment

Sustainability

Reliability
Organizational Capabilities

Business Processes

Roles & Responsibilities - Skills
Technology

Supply Side
• Distributed & Demand-Side
Resources
• Interconnections and MicroGrids

Power Delivery
• Network Design
• Protection and Control
Strategies
• Asset Management & Utilization

Information Technologies
• Data Communications
• Data Management
• Enterprise Level Integration and
Inter-operability
• Intelligent Applications
Regulatory Incentives
Organizational Capabilities
Business Processes
Systems and Data Integration / Interoperability
Technology
Technology

Policy
Policy
Smart Grid Building Blocks
Data Processing,
Analysis & Intelligent Applications
Data Communications
Grid Design &
Configuration
Intelligent Devices;
Metering. Protection, Control & Monitoring Equipment
Demand-Side
Automation
Distributed Generation
Technologies
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Smart Grid - What needs to
happen?

Industry standards – Uniform standards
for communication and interoperability

Removal of barriers – Elimination of
legal and regulatory policy barriers

Informed customers – Better education
and timely information for consumers
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Appendix
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Program Feature Summary
EDRP
ICAP/SCR
Curtailment Service Provider (CSP)
Responsible Interface Party (RIP)
100 kW
Aggregations Supported
100 kW
Aggregations Supported
none
Monthly
Based on ICAP auction
Greater of real-time LBMP or $500/MWh
and guaranteed 4-hour minimum
Greater of real-time LBMP or Strike Price
(maximum $500/MWh) and guaranteed 4-hour
minimum
Event Notification
2-hour in-day notice
Day-ahead advisory and 2-hour in-day notice
Types of reduction
Curtailable Load and Local Generation
Curtailable Load and Local Generation
Penalty for Noncompliance
none
Penalties and derated for non-compliance
Credit Requirements
none
none
After ICAP/SCR resources
Prior to EDRP resources
NYISO Interface
Minimum Size
Capacity Payment
Energy Payment
Activation Priority
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Program Feature Summary
DADRP
DSASP
Demand Reduction Provider (DRP)
Demand Reduction Provider (DRP)
Minimum Size
1 MW
1 MW
Aggregations Supported
Capacity Payment
None
None
Greater of energy marginal price or offer price
Reserve market clearing price
Event Notification
Notified by 11:00 a.m. of scheduled commitment
for the next day (midnight to midnight)
Notified by 11:00 a.m. of scheduled commitment
for the next day. Real-Time telemetered energy
schedule
Types of reduction
Curtailable Load
Curtailable Load and Local Generation
Buy-through at greater of Day-Ahead or RealTime price
Buy-through at Real-Time Reserve Market
Clearing Price
Reduced from Generator levels
Reserve/Regulation levels
Scheduled day-ahead if economic, no real-time
schedule
Scheduled Day-ahead and Real-Time if
economic
NYISO Interface
Payment
Penalty for Noncompliance
Credit Requirements
Activation Priority
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ISO Demand Response Programs
AESO CAISO ERCOT IESO ISONE MISO NYISO PJM SPP
Day-Ahead Economic DR

Day-Ahead Price Sensitive Load

Load as a Capacity Resource










Emergency / Imbalance DR








Operating Reserves DR




Pilot



Regulation DR




Real-Time Dispatchable Load

Voltage / Load Reduction













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Dynamic Pricing -Simulation Design




Define fixed and dynamic rates
 Dynamic rates based on LBMPs w/ capacity cost during critical
hours
 Dynamic rate structured so that average customer’s cost would be
unchanged from fixed rate if demand remained unchanged
 Analysis uses representative customers in four regions: Western
NY (Load Zones A-E), Eastern NY (Load Zones F-I), NYC (Load
Zone J) and Long Island (Load Zone K)
Estimate the effects of dynamic pricing on consumer demand
 Elasticity of demand derived from dynamic pricing pilot programs
with small customers and full scale deployments for large
customers
 Used Brattle’s PRISM software to apply elasticities of demand to
calculate hourly differences between fixed and dynamic rates
Quantify changes in demand on LBMPs using dispatch simulation
 Conservative assumption that suppliers’ offers to supply energy
remain the same despite price-responsive demand
Did not evaluate long-term savings or long-term equilibrium prices
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The New York Independent System Operator (NYISO) is a not-for-profit
corporation that began operations in 1999. The NYISO operates New
York’s bulk electricity grid, administers the state’s wholesale electricity
markets, and conducts system and resource planning for the state’s
bulk electricity system.
__________________________________________________________
www.nyiso.com
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