1. NYISO Demand Side Programs and Issues
Rana Mukerji Senior Vice President - Market Structures

2. 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 price-sensitive demand, economically to meet customers’ demand 24 hours per day, 365 days per year.

4. 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)
From DR-Expo presentation

5. NYISO Special Case Resources & Emergency Demand Response Program Have Added Almost 2000 MW Since 2000.

6. NYISO – DR Impacts on 8/2/06
MWs

7. 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

8. 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

9. 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

10. 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 non-synchronous 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

11. 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 11

12. 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 real-time energy markets (major issue is settlements)
Implementing Demand Response Information System
Dynamic Pricing vs Demand Response

13. 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 13

14. Demand Reductions Dynamic rates encourage shift to off-peak usage
Impact of Dynamic Pricing on Hourly Loads
Dynamic rates encourage shift to off-peak usage
Reduced capacity requirement drives savings: potential 10-14% 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
Dynamic Pricing Scenario
Change in System Peak
Change in New York City Peak
Change in Long Island Peak
Change in Average Load
All Hours
150 Hours
w/Max ∆ Load
(MW)
(%)
Base Case
(3,418)
(10%)
(1,514)
(13%)
(590)
(11%) 84
0.4%
(1,897)
(6%)
Conservation
(3,751)
(604)
(288)
(1.5%)
(2,158)
(7%)
High Capacity Price
(4,282)
(1,671)
(14%)
(776)
176
1.0%
(3,147)
High Elasticity
(4,603)
(1,961)
(16%)
(779)
130
0.7%
(3,606)
(12%) 14

15. Cost Savings Change in Annual Market-Based Customer Costs
Change in Annual Resource Costs
Dynamic Pricing Scenario
Change in Energy Production Cost
Change in Capacity Cost
Total Change in Resource Cost
(Million $)
(%)
Base Case
10.6
0.3%
(153.6)
(11%)
(143.0)
(2.6%)
Conservation
(188.2)
(4.5%)
(163.3)
(12%)
(351.5)
(6.3%)
High Capacity Price
60.3
1.4%
(569.0)
(13%)
(508.8)
(6.0%)
High Elasticity
22.5
0.5%
(204.1)
(15%)
(181.6)
(3.3%)
Change in Annual Market-Based Customer Costs
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
(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 15

16. How do we achieve these savings ?

17. 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

18. 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

19. 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

20. Dynamic Pricing Driving Smart Grid / Renewables
Aggregator
Evolutionary Market Design
NYISO
Control Center
Demand
Response
(Real Time)
Dispatch
Instructions
&
Prices
Wind Generators 20

21. Paradigm Shift – Load follows generation
Charging Profile: EPRI/NRDC
Wind Power: 2007 average normalized load

22. 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 22

23. Smart Grid Building Blocks
Regulatory & Market Incentives
Environment
Sustainability
Reliability
Organizational Capabilities
Business Processes
Roles & Responsibilities - Skills
Technology
Supply Side
Distributed & Demand-Side Resources
Interconnections and Micro-Grids
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

24. 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

25. Appendix

26. Program Feature Summary
EDRP
ICAP/SCR
NYISO Interface
Curtailment Service Provider (CSP)
Responsible Interface Party (RIP)
Minimum Size
100 kW
Aggregations Supported
Capacity Payment
none
Monthly
Based on ICAP auction
Energy Payment
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
Penalty for Non-compliance
Penalties and derated for non-compliance
Credit Requirements
Activation Priority
After ICAP/SCR resources
Prior to EDRP resources

27. Program Feature Summary
DADRP
DSASP
NYISO Interface
Demand Reduction Provider (DRP)
Minimum Size
1 MW
Aggregations Supported
Capacity Payment
None
Payment
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
Penalty for Non-compliance
Buy-through at greater of Day-Ahead or Real-Time price
Buy-through at Real-Time Reserve Market Clearing Price
Credit Requirements
Reduced from Generator levels
Reserve/Regulation levels
Activation Priority
Scheduled day-ahead if economic, no real-time schedule
Scheduled Day-ahead and Real-Time if economic

28. ISO Demand Response Programs

29. 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 29

30. __________________________________________________________
The New York Independent System Operator (NYISO) is a not-for-profit corporation that began operations in 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.
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