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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 - PowerPoint PPT Presentation
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NYISO Demand Side Programs and Issues
Rana MukerjiSenior Vice President - Market Structures
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Markets for Demand Response ProductsMarkets 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.
3
4
NYISO Demand ResponseNYISO 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 NYISO Special Case Resources & Emergency Demand Response Program Have Added Almost 2000 MW Since Response Program Have Added Almost 2000 MW Since 2000.2000.
Peak Load Reductions from Demand Response - MW2001, 2006, and 2009
435
1172
712
1320
2147
0
500
1000
1500
2000
2500
2001 2006 2009
Actual Impact MW Capability
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NYISO – DR Impacts on 8/2/06NYISO – DR Impacts on 8/2/06
28000
29000
30000
31000
32000
33000
34000
35000
36000
12:0
012
:10
12:2
012
:25
12:3
612
:50
13:0
013
:10
13:2
013
:22
13:3
513
:45
13:5
514
:05
14:1
514
:20
14:2
614
:29
14:4
014
:50
15:0
015
:10
15:2
015
:30
15:4
015
:50
16:0
016
:10
16:1
316
:25
16:3
516
:45
16:5
517
:05
17:1
517
:25
17:3
517
:45
17:5
518
:05
18:1
518
:25
18:3
518
:45
18:5
519
:05
19:1
519
:25
19:3
519
:45
19:5
520
:05
20:1
5
MW
8/2 NYCA 8/2 NYCA no DR
MW
s
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Capacity - Special Case ResourcesCapacity - 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 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 ResponseDay-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-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
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Real-Time Demand Response PricingReal-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 IssuesCurrent 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
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NYISO Dynamic NYISO Dynamic Pricing StudyPricing 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 ReductionsDemand Reductions 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
Impact of Dynamic Pricing on Hourly Loads
Dynamic Pricing Scenario
Change in System Peak
Change in New York City
Peak
Change in Long Island
PeakChange in
Average Load
All Hours All Hours All Hours All Hours150 Hours
w/Max ∆ Load(MW) (%) (MW) (%) (MW) (%) (MW) (%) (MW) (%)
Base Case (3,418) (10%) (1,514) (13%) (590) (11%) 84 0.4% (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%)
Effects of Dynamic Pricing on Peak and Average Demand
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Cost SavingsCost Savings
Dynamic Pricing Scenario
Change in Market Based Energy Costs
Change in Capacity Costs
Total Change inMarket 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%)
Change in Annual Market-Based Customer Costs
• 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
Change in Annual Resource Costs
Dynamic Pricing Scenario
Change in EnergyProduction Cost
Change in Capacity Cost
Total Change inResource Cost
(Million $) (%) (Million $) (%) (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 Consumer Costs
15
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How do we achieve these savings ?How do we achieve these savings ?
17
ISO/RTO Role: Wholesale LevelISO/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 LevelState 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 PricingDynamic 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 Dynamic Pricing Driving Smart Grid / RenewablesGrid / Renewables
Aggregator
Evolutionary Market Design NYISO
Control Center
Dispatch Instructions
&Prices
DemandResponse
(Real Time)
20Wind Generators
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Paradigm Paradigm Shift – Load follows Shift – Load follows generation generation
PHEV Charging Profile and Wind Power
0%
2%
4%
6%
8%
10%
12%
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
1
1.1
1.2
1.3
1.4
1.5
1.6
1.7
1.8
1.9
Charging Profile Wind PowerCharging Profile: EPRI/NRDCWind Power: 2007 average normalized load
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Smart Grid FutureSmart 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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Smart Grid Building BlocksSmart Grid Building Blocks
Grid Design &ConfigurationData Communications
Data Processing, Analysis & Intelligent Applications
Systems and Data Integration / Interoperability
Business Processes
Organizational Capabilities
Distributed GenerationTechnologies
Demand-SideAutomation
Intelligent Devices; Metering. Protection, Control & Monitoring Equipment
Regulatory Incentives
Tech
nolo
gyTe
chno
logy
Peo
ple
&
Pro
cess
Peo
ple
&
Pro
cess
Pol
icy
Pol
icy
Grid Design &ConfigurationData Communications
Data Processing, Analysis & Intelligent Applications
Systems and Data Integration / Interoperability
Business Processes
Organizational Capabilities
Distributed GenerationTechnologies
Demand-SideAutomation
Intelligent Devices; Metering. Protection, Control & Monitoring Equipment
Regulatory Incentives
Tech
nolo
gyTe
chno
logy
Peo
ple
&
Pro
cess
Peo
ple
&
Pro
cess
Pol
icy
Pol
icy
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?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 SummaryEDRP ICAP/SCR
NYISO Interface Curtailment Service Provider (CSP) Responsible Interface Party (RIP)
Minimum Size100 kW
Aggregations Supported
100 kW
Aggregations Supported
Capacity Payment noneMonthly
Based on ICAP auction
Energy PaymentGreater 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 Non-compliance
none Penalties and derated for non-compliance
Credit Requirements none none
Activation Priority After ICAP/SCR resources Prior to EDRP resources
27
Program Feature SummaryDADRP DSASP
NYISO Interface Demand Reduction Provider (DRP) Demand Reduction Provider (DRP)
Minimum Size 1 MW1 MW
Aggregations Supported
Capacity Payment None None
Payment Greater of energy marginal price or offer price Reserve market clearing price
Event NotificationNotified 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 PriorityScheduled day-ahead if economic, no real-time
scheduleScheduled Day-ahead and Real-Time if economic
28
ISO Demand Response ProgramsISO 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
29
Dynamic Pricing -Simulation DesignDynamic 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
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The New York Independent System Operator (NYISO) is a not-for-profit The New York Independent System Operator (NYISO) is a not-for-profit corporation that began operations in 1999. The NYISO operates New corporation that began operations in 1999. The NYISO operates New York’s bulk electricity grid, administers the state’s wholesale electricity York’s bulk electricity grid, administers the state’s wholesale electricity markets, and conducts system and resource planning for the state’s markets, and conducts system and resource planning for the state’s
bulk electricity system.bulk electricity system.
____________________________________________________________________________________________________________________
www.nyiso.comwww.nyiso.com
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