new england developments in demand response and smart grid 2010 national town meeting on demand...

New England Developments in Demand Response and Smart Grid

2010 National Town Meeting on Demand Response and Smart Grid

Henry Yoshimura, Director, Demand Resource Strategy ISO New England

June 24, 2010

New Opportunities in New England

• On June 1, 2010, ISO New England implemented the Forward Capacity Market

• Over 2,500 MW of demand resources participating – 2009 system peak was 25,100 MW; 2010 projected system peak is

27,190 MW

– New communication infrastructure implemented – demand response dispatched where and when needed to improve efficiency and mitigate potential fatigue

• Some New England states are requiring more aggressive energy efficiency and demand response programs– “Smart-grid” pilot programs are being proposed by major New England

utilities

– Some New England utilities are planning to deploy advanced metering infrastructure

© 2010 ISO New England Inc. 2

New Challenges for New England

• Achieving greater levels of demand response in New England requires more dynamic retail pricing– Barriers need to be addressed:

• Smart meters, smart prices, smart technology

• A better understanding of the economics of demand response

• Addressing the FERC Notice of Proposed Rulemaking on Demand Response Compensation in Organized Wholesale Energy Markets (“NOPR”)– What’s the purpose behind demand response participation in the

energy market? Price reductions? Economic efficiency?

– The proposed rule would introduce economic inefficiency, increased total resource costs and lower value for consumers


Background Information

New Opportunities and Challenges for New England Regarding Demand Response and Smart Grid

4© 2009 ISO New England Inc.

New Opportunities for New England Consumers to Benefit from DR and Smart Grid

• New Demand Response and Smart Grid Opportunities– On June 1, 2010, ISO New England implemented the Forward

Capacity Market

• Over 2,500 MW of demand resources participating

– 2009 system peak was 25,100 MW; 2010 projected system peak is 27,190 MW

• New infrastructure developed to securely communicate dispatch instructions, and receive near real-time telemetry and revenue-quality meter data from active demand response capacity resources

– Demand response dispatched where and when needed to improve efficiency and mitigate potential fatigue


Demand Resources in New EnglandForward Capacity Market Promotes Growth

6

FCM

2010-2012: Total DR Cleared in FCM (New and Existing)Through 2009: Total DR Enrollment in ISO Programs

© 2010 ISO New England Inc.

Smart Grid Presents Greater Opportunities

• Smarter retail consumers through smart metering, smart rates, smart technologies– Some New England utilities

are experimenting with “smart-grid” programs that allow customers to benefit more from conserving during peak times and/or shifting energy usage from on-peak to off-peak periods


8

Future DR Potential is in Dynamic Retail Pricing

© 2010 ISO New England Inc.

BAU = Business As Usual

* From FERC National DR Potential Assessment

Smarter Grid Allows Customers to Use Energy More Wisely While Saving Money


G3 Basic Service: $38,133.81 Real-Time Price: $24,367.70

One-Month Savings: 36%

Future of DR is Customer Response to Prices

• Customer response to time-varying wholesale prices is needed – Creates the lowest average prices and total bills over time– Improves economic efficiency– Eliminates customer baseline estimation problems– Resolves cost allocation issues– Promotes customer choice– Stimulates investment in load shifting technologies (e.g., energy storage, plug-

in electric vehicles)

• Barriers must be overcome– Advanced metering infrastructure– Smart pricing

• Wholesale and retail– Enabling technology


Background Information

Notice of Proposed Rulemaking on Demand Response Compensation


Notice of Proposed Rulemaking on Demand Response Compensation

• The FERC is proposing that demand response reducing electricity consumption from expected levels in response to price signals should be paid, in all hours, the market price for energy – i.e., the full LMP – for such reductions

• This raises a host of issues:– Economic Efficiency

– Price Formation

– Entitlement

– Cost Allocation

– Customer Baseline Estimation

• Does not fully reward economic load shifting (e.g., energy storage) or off-peak usage (e.g., plug-in electric vehicles)


Implications of Economic Analysis

• Programs implemented by the ISO should seek to replicate the incentives provided by dynamic retail rates

• Allowing consumers to realize retail bill savings and receive full-LMP payments for reduced demand is less efficient than uniform retail rates– Inducing under-consumption in every period more than offsets the

benefits of avoiding excessive consumption during peak periods

– Undermines implementation of dynamic retail rates in retail markets

– Results in higher prices and costs in the long-run


Economic Efficiency

• Efficiency requires that programs address on- and off-peak consumption

– Providing incentives for reduced consumption alone does not guarantee that load would be shifted to low-LMP periods

• Customers may reduce load in a high-LMP hour in response to an incentive payment. However, customers on fixed retail rates do not have the incentive to shift that load to a low-LMP hour – i.e., they may shift that load to a different high-LMP hour

– This deficiency in program design will become increasingly apparent as technologies that shift energy usage (e.g., plug-in electric vehicles and energy storage) are developed


The Price-Formation Problem

• Payment of full LMP for reduced energy consumption can cause a “price-formation” problem in the energy market by giving consumers an incentive to defer consumption whose value exceeds the LMP, or to use sources of energy that cost more than the LMP. For example:– The retail rate is $80/MWh and the LMP is $90/MWh

– The consumer can reduce net energy costs by $20/MWh using an $150/MWh on-site generator to reduce its net metered load

• ($80 bill savings + $90 payment - $150 generator cost = $20 net gain)

• The incentive payment induces consumers to waste society’s resources by encouraging the use of a more expensive $150/MWh resource when a less expensive $90/MWh resource was available


Impact of Full-LMP Payment and Meter Placement – Resource In-Front of the Meter


Customer

Load = 10 MWh

Meter Reading 10 MWh

Distributed Resource

Cost = $150/MWh

Production 0 MWh

Revenue = $0

Cost = $0 Rest of Grid

LMP = $90/MWh

Production 10 MWh

Revenue = $900

Retail Bill (@ $80/MWh) = ($ 800)DR Revenue = $ 0DR Cost = $ 0Customer Net Bill = ($ 800)

Impact of Full-LMP Payment and Meter Placement – Resource Behind the Meter


Customer

Load = 10 MWh

Meter Reading 0 MWh

Distributed Resource

Cost = $150/MWh

Production 10 MWh

Revenue = $900

Cost = $1,500 Rest of Grid

LMP = $90/MWh

Production 0 MWh

Revenue = $0

Retail Bill (@ $80/MWh) = $ 0DR Revenue = $ 900DR Cost = ($ 1,500)Customer Net Bill = ($ 600)

• Full LMP payment results in higher total resource costs as customers use distributed resources to reduce their net electricity bill

• Behind-the-meter resources are given a competitive advantage over lower-cost, in-front of meter resources

Entitlement Issues

• Assume that the price of gasoline is $3.00/gallon• If I do not drive today and save two gallons of gasoline, I

save $6.00• If I previously purchased two gallons, I can sell the two

gallons that I did not use at today’s price of $3.00/gallon and receive a $6.00 payment

• If I did not previously purchase two gallons, should I receive a $6.00 payment for saving two gallons of gasoline by not driving today?– If I receive a $6.00 payment, it appears that am able to sell two

gallons for which I do not have entitlement


Cost Allocation Problem

• Demand Resources reduce load and do not produce energy

• Treating Demand Resources like a supply resource creates a “missing money” problem. For example:– 20,000 MW of supply clear in the energy market in a particular hour

– 2,000 MW of the supply that cleared are load reductions from Demand Resources

– If the 2,000 MW load reduction is delivered, the energy market clears with 18,000 MW of demand and 20,000 MW of supply (18,000 MW of generation plus 2,000 MW of Demand Resources)

– While 20,000 MW of supply must be paid the LMP, the LMP would only be collected from 18,000 MW of demand resulting in an under-collection

• If the LMP were $100/MWh, suppliers must be paid $2 million, but only $1.8 million is collected from demand

– The $200,000 payment associated with the 2,000 MW of Demand Resources that cleared must be allocated in some fashion


Customer Baseline Observations

• Many demand response approaches rely on the use of an estimated Customer Baseline – an estimate of what would have been consumed but for a consumer’s response to wholesale market prices– Adverse selection and moral hazard lead to inflated Customer

Baselines

– Since Customer Baselines are not directly observable, the legitimacy of such estimates is difficult to verify

– Customer Baseline estimates become increasingly unreliable as the frequency of load reduction events increase

• If a customer interrupts usage everyday, what is that customer’s baseline?


Customer Baseline Observations

• To encourage price-responsiveness over many (or all) hours of the year, approaches that use an estimated Customer Baseline ought to be avoided

• Many Customer Baseline methodologies have acceptable accuracy for relatively infrequent events, such as those projected under the Forward Capacity Market


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