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.

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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

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How do we achieve these savings ?How do we achieve these savings ?

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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

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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

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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

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Appendix

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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

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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

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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

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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

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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.

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www.nyiso.comwww.nyiso.com