1. Measurement, Verification, and Forecasting Protocols for Demand Response Resources: Chuck Goldman CAGoldman@lbl.gov Lawrence Berkeley National Laboratory NARUC-FERC Demand Response Collaborative Washington DC February 18, 2007

2. Why is DR M&V and forecasting important? EntityPerspective Customer/Load Aggregator Payments for customer-specific impacts Settlements: timely, transparent Regulator (PUCs)Program-wide load impacts are key input to B/C analysis & Resource Plan System Operator (e.g., ISO,RTO, Utility) Capacity: Resource adequacy? Reserves & Emergency: Keep lights on? Energy Markets: Can DR resource mitigate price volatility? Real-time operational needs? Transmission planning/expansion: Can DR resource projects defer/meet needs in congested areas? Utility/LSEResource planning: Defer peaking generation

3. Role of DR in Electric Power Systems DR options include price-based DR (time-varying electricity tariffs) and incentive-based DR (programs that pay for load reductions) Incentive-based DR: “dispatchable”; event-based Linkage between retail rate design/DR programs and wholesale market design/structure

4. Measuring DR Impacts: Establishing Customer Baseline is Key

5. DR M&V Protocols: Standardization vs. Flexibility M&V ApproachRecommendations Incentive- based DR programs Representative day baselines for population Event day adjustments For Residential and small C/I, need sample of customers with interval meters Use Default Baseline Method (Average of last 10 non-event days) with Alternatives Additive scalar adjustment to align with known conditions on curtailment day (e.g. 2 hrs prior) Alternative Methods can account for load characteristics (e.g. weather- sensitive) and operating practices Price-based DR (e.g. RTP, TOU) No events; No CBL Regression-based models

6. DR Measurement/Verification and Forecasting: Challenges & Issues Significant diversity among DR Resources –M&V methods may vary: Default with Alternatives –DR Load impacts for Customer settlement vs. B/C tests and resource planning M&V Protocols: Standardization vs. Flexibility? –ISOs have made progress (across product markets; “mass market”) “Firming up the DR resource”? –Price-based DR (RTP, CPP, TOU) rarely treated as a “resource” –Events are rare: Role of periodic “testing” of resource capability? Linking DR program evaluation results to Market Potential and forecasting assessments?

7. DR M&V Resources & References KEMA-XENERGY, 2003. Protocol Development for Demand Response Calculation – Findings and Recommendations, Prepared for California Energy Commission, CEC-400-02-017F, February. Summit Blue Consulting LLC. and Quantum Consulting Inc., 2006. Protocols for Estimating the Load Impacts from DR Program, Prepared for CPUC/ CEC Working Group 2: Evaluation Committee, April 3. LBNL Electricity Markets and Policy Publications http://eetd.lbl.gov/ea/EMS/drlm-pubs.html http://eetd.lbl.gov/ea/EMS/drlm-pubs.html –Goldman, C. et al., 2007. Estimating Demand Response Market Potential among Large Commercial and Industrial Customers: A Scoping Study, LBNL-61498, January. –Hopper, N. et al., 2006. Customer Response to Day-Ahead Market Hourly Pricing: Choices and Performance, LBNL- 58114. June.

8. Background slides

9. Definition of Demand Response “Changes in electric usage by end-use customers from their normal consumption patterns in response to changes in the price of electricity over time, or to incentive payments designed to induce lower electricity use at times of high wholesale market prices or when system reliability is jeopardized.” - Benefits of Demand Response in Electricity Markets, U.S. Department of Energy

10. Demand Response Resources Classification Incentive-based Programs –Direct Load Control (DLC) –Interruptible/curtailable rated (I/C) –Demand bidding/Buy-back programs (DB) –Emergency Demand Response Programs (EDRP) –Capacity Programs (CAP) –Ancillary Services markets program (A/S) Time-based rates –Time-of-use (TOU) –Critical peak pricing (CPP) –Real-time pricing (RTP)

11. Electric System Planning & Operations