Energy Efficiency and Demand Response Programs in the United States

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1 Energy Efficiency and Demand Response Programs in the United States Structure, Operations, Accomplishments, Lessons Learned Claude Godin Director Energy Data Analytics

2 Overview Introduction - Definitions of Demand Response (DR) Energy Efficiency (EE) - Size and importance of EE and DR programs in the U. S. electrical industry - Structure of the U. S. electrical industry: ownership and regulation Demand Response Programs - Types of DR Programs - Organization of DR Programs - Performance of DR Programs - Peak demand reduction - Effects on Customer Bills - Next steps in Developing DR Programs 2

3 Definitions Demand Response Programs: organized activities to induce endusers to modify temporarily the time pattern of energy use in response to signals from electric system operators - Direct control of selected end-use loads - Signals based on generation or transmission system imbalances or shortages, fluctuations in wholesale prices - Signals built into retail electric rates Energy Efficiency Programs: organized activities to induce end-users to reduce total energy consumption, without regard to time of use - Promote research and development to increase the efficiency of end-use technologies - Accelerate the adoption of efficient end-use technologies - Accelerate the adoption of practices and behaviors that reduce energy use Both EE and DR contribute to efficient use of electric system assets 3

4 Importance of EE and DR in the U. S. Electric Market Energy Efficiency Programs: 2011 Energy Savings from new projects: 36.5 TWh/Year or 0.5% of 2010 total electric sales - California: 1.8% of 2010 sales - Massachusetts: 1.1% of 2010 sales Energy savings from all projects in place: TWh/Year or 3.1% of 2010 total electric sales Program costs: $5.9 billion or 1.6% of total sales revenues Cost Effectiveness: - Costs of conserved energy: $ $0.06/kWh - Levelized cost of energy supply: $ cts/kwh, depending on jurisdiction Demand Response Programs Load under Demand Response Contract, 2012: 66.3 GW or 8.5% of summer peak load Actual Load Reduction, 2012: 20.2 GW or 2.6% of summer peak load - Utilization of contracts ranged from 15% to 90%, depending on region Program costs: ~$2 billion/year, Revenues of related businesses: $2 - $3 billion Cost Effectiveness - $50 - $75 per year for kw of DR v. minimum of $110 per kw, levelized cost of least expensive generation resource 4

5 Effect of EE and DR on U. S. aggregate electric demand Key Points Combined demand reduction attributable to DR and EE equal to 4.2% of non-coincident summer peak in 2009 Since then, both types of programs have grown significantly 5

6 Structure of the U. S. Electric Market System Function/Type of Organization Generation Investor-owned utilities Public/Municipal Federal Government Non-Utility (Merchant) Transmission Investor-owned utilities Public/Municipal/Coops Federal Government Independent TransCos and other Distribution Investor-Owned Utilities Public/Municipal Cooperatives Retail Supply (In 17 States) Residential Sector Commercial & Industrial Sectors Regulation Market Metric Share Owned Investment Reliability Installed Cap. 38% 14% 7% 41% Miles HV Line 66% 13% 14% 7% Customers 73% 15% 12% Annual Sales/US 4% 18% S L,S F S,Mkt,L,L,L,L F Rates/ Revenue S,Mkt,F L,Mkt,F F,Mkt,F Mkt,F F= Federal, S = State, L = Local, Mkt prices or investment influenced primarily by markets S L L F,L F,L S S S L L Mkt Mkt 6

7 Independent System Operators/Regional Transmission Org. Functions Schedule and dispatch generation Schedule and dispatch transmission Operate wholesale electric markets: capacity, energy, balancing (regulation) Integrate DR into electricity market operations Scale Serve ~ 2/3 of US electric customers; ½ of Canadian customers 7

8 Demand Response Programs

9 Objectives Served by Demand Response Demand Response can affect load in several ways 1. Energy Efficiency programs reduce overall electricity consumption, generally also at times of peak demand. 2. Price Response programs move consumption from times of high prices to times of lower prices (real time pricing or time of use) expanded to address transmission distribution congestion management. 3. Peak Shaving programs require more response during peak hours and focus on reducing peaks on high-system load days expanded to address transmission distribution congestion management. 4. Reliability Response (contingency response) requires the fastest, shortest duration response. Response is only required during power system events. 5. Regulation Response continuously follows minute-tominute commands from the grid in order to balance the aggregate system load and generation This is also very new and appears to be very promising for certain loads. 9

10 Dispatchable v. non-dispatchable demand response Demand Response Dispatchable Non-dispatchable Capacity services Grid/system reliability Ancilliary services Economy Energy market Time-sensitive pricing (TOU, CPP, RTP) & time dependent capacity tariffs. 10

11 Distribution of Enrolled Load by Program Type: 2012 Incentive Programs Pricing Programs 11

12 Development of DR shaped by Federal Laws & Regulations Legislation/Regulation 1992: Federal Energy Policy Act Major Effects on Demand Response Allows independent power producers to participate in wholesale power markets 1993: FERC Order 888 Mandates open access for high voltage transmission 2005: Federal Energy Policy Act With 1992 Energy Policy Act, enabled restructuring, which led to development of RTOs and ISOs to coordinate deregulated generation markets Declares official federal policy to promote DR, facilitate deployment of enabling technology, eliminate barriers to DR participation in energy, capacity, and ancillary service markets Takes value of DR to non-participating customers into account 2008: FERC Order 719 Directs RTOs and ISOs to ensure that market prices reflect value of DR Enables aggregators to bid directly into electricity markets Directs RTOs and ISOs to accept DR bids for ancillary services 2011: FERC Order 745 Requires that DR be compensated at the full market price for the comparable products All RTOs and ISOs must develop filings detailing how they will comply 12

13 Growth in DR parallels development of capacity markets Relationship of capacity markets to growth of DR - Provides steady stream of revenue to aggregators and other providers - Providers no longer dependent on relatively rare events in local energy markets - Pool of potential participating customers increased 13

14 Growth in DR parallels development of capacity markets PJM Example 14

15 Reliability of DR is comparable to conventional generation Performance of New England Demand Response and Emergency Generation Resources: Demand resources delivered 86% of capacity commitments versus 90% for conventional emergency generators - Generation fleet availability after accounting for forced outages: 94.5% 15

16 DR Programs Reduce Average Prices to Consumers PJM Modeled Real Time Energy Price Decreases Per 1% Load Curtailed Brattle Group, Load curtailments generally occur during highest cost hours - Benefits of spot price reductions received by all customers on the system 16

17 DR Programs have Delivered 10-minute Reserves Deployment of Demand Response Reserves Texas, August 4,

18 Range of Energy Savings from Pricing Programs - Highest savings achieved by Critical Peak Pricing approach - Combination of messaging technology or automatic controls with pricing appears to generate the most savings 18

19 Impacts of Pricing Programs on Annual Utility Costs Bill Impacts of California Pilot Pricing Programs - Pricing programs are designed to save money for customers who shift consumption patterns - Share of participants who reduced bill ranged from 66% to 94%, depending on program design and market segment 19

20 Savings & Elasticities: Commercial Pricing Programs 20

21 Customer Baseline: Settlement and Evaluation Verification of compliance with contract requirements and measurement of reduction require estimate of baseline: what demand would have been during the event in the absence of curtailment efforts Most common methods use regression of hourly demand versus temperature and hour of the day for individual sites during non-event days, adjusted for event day characteristics Best Practice: methods should reflect variability and weather sensitivity of loads Interval meter data generally required 21

22 Current Challenges to Continued Growth of DR in the US Limited number of customers on time-based rates - Particularly important for residential customers Lack of standards for communicating DR signals and measuring demand reductions - Increases costs and uncertainty for providers and customers - National standard setting organizations are addressing this issue Lack of customer engagement - Consumers must be educated to the benefits of DR, otherwise consumer dissatisfaction and distrust of smart meters may occur Lack of DR modeling and forecasting tools - Complicates the development of convincing business cases for program funding 22

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