Christensen Associates RTP as a Demand Response Program – How Much Load Response Can You Expect? Peak Load Management Alliance Fall Conference November 2001 Steven Braithwait Christensen Associates

Christensen Associates Economic and engineering consulting for energy industry 25 years of experience in designing and evaluating retail pricing strategies – TOU (traditional and competitive) Real-time pricing (NiMo, Georgia Power, KCP&L) Market-based interruptible load programs

Sound Bites from Yesterday “Square peg in round hole” Customers aren’t generators Trends in DR programs? Look at competitive markets “Dollars on the table” Focus on NEW $$$ from efficient pricing “Keep it simple” Here are tomorrow’s prices, you decide…

Topics Real-time pricing as a DR program Capturing the benefits of DR and RTP Evidence of RTP load response Technology facilitates residential “RTP”

What is Real-time Pricing (RTP)? A market-based pricing strategy Customers face hourly spot market prices Advance notice – day-ahead; hour-ahead Price protection through hedging/price caps Works in regulated and competitive markets A demand response program RTP customers provide load reductions at times of high wholesale prices

RTP at Georgia Power Company 1,700 C & I customers 5,000 MW (80% of C & I sales) Day-ahead (75%) & hour-ahead (25%) Load response: 500 – 1,000 MW (at prices of $500 – $2,000/MWh)

Benefits of Demand Response Connects wholesale and retail markets Demand response at high prices can reduce wholesale price spikes

Connected Markets: Demand Response Yields Lower Wholesale Prices $/MWh WP Lnormal Lhot Dhot A Pspike B Qhot Phot E´ Dnormal E Retail Price Pnormal GWh Qnormal Qspike

Capturing the Benefits of DR To capture benefits, the amount of demand response must be measured and anticipated (e.g., in unit dispatch and power purchases)

Measuring Non-RTP DR DR programs pay for “performance” However, cannot “measure” performance (i.e., load reductions) by metering Load response (LR) must be estimated: LR = Baseline load - Actual load Problems in estimating CBL; $$ at risk

Measuring and Forecasting RTP Load Response For billing: No “verification” problem – RTP customers pay for what they consume For forecasting: Develop load response model based on analysis of historical experience Advantage of aggregating over customers

RTP Load Response Curve for Georgia Power (Load Response as a Percent of Total RTP Load)

Evidence of RTP Load Response Georgia Power Real-Time Pricing (RTP) 1,700 large C & I customers; 5,000 MW of load Duke Power Hourly Pricing 100 large industrial customers; 1,000 MW GPU Energy “Critical price” TOU 1997 residential pilot program

Summary of RTP Price Responsiveness Significant, consistent load response Small to modest price elasticities Wide range across customer types Most price responsive customers: Electricity intensive (e.g., most intensive industrials; residential customers with most major appliances) Enabling technology (e.g., own generation; storable production process; automatic controls)

Load on highest-price day GP RTP Load Response (DA): Very High-Price (Load response = 500 MW; 20% of reference load) Highest DA prices Load on highest-price day

Diversity of Customer Price Responsiveness Price Elasticity by Customer Type and Price Level 0.000 0.050 0.100 0.150 0.200 0.250 0.300 0.350 0.400 HA OSG - I Non-Int - I OSG - C Non-Int - C Moderately high price Very high price

Duke Power RTP Load Response (per Tom Taylor, Rates and Regulation) 100 industrial customers; 1,000 MW Total load response when Price > $.25/kWh 200 MW, or 20% of expected load 20 customers reduced load by > 5% Significant price elasticities for 25% of customers

GPU “Critical-price” TOU Rate Effect of Technology on Load Response TOU rate, plus critical price ($.50/kWh) Interactive communication system customers pre-select thermostat settings and circuit priority at different price triggers utility can send critical price signal Similar programs at AEP, Gulf Power

“Critical-price” TOU Rate Design 0.5 Critical price 0.4 0.3 Rate 6173 Standard Rate 0.2 Rate 9122 0.1 1 8 14 18 20 24

Residential TOU Load Response – Critical Price Day 0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Average Hourly Usage: kWh/hr. Control Treatment OP S Peak

Conclusions RTP offers demand response in a natural retail market setting Methods are available for anticipating RTP load response at different price levels Evidence is available on amount of RTP load response to expect

For Additional Information: Customer Response to Market Prices – How Much Can You Expect When You Need it Most?, Steven Braithwait and Michael O’Sheasy, EPRI Pricing Conference, July 2000. Residential TOU Response in the Presence of Interactive Communication Equipment, Steven Braithwait, in Pricing in Competitive Electricity Markets, Ahmad Faruqui, Ed. The Choice Not to Buy: Energy Savings and Policy Alternatives for Demand Response, Steven Braithwait and Ahmad Faruqui, in Public Utilities Fortnightly, March 15, 2001. Contact: Steve Braithwait (sdbraithwait@lrca.com) Christensen Associates 608-231-2266

Types of Demand Response Programs Demand-side bidding – customers bid load reductions into the wholesale market “Buy-back,” or pay-for-performance interruptible Suppliers buy load reductions, relative to baseline, at price tied to market price Real-time (hourly) pricing Full-time Part-time; whenever cost exceeds specified level

How to Estimate Reference Load? Historical load on same day-type (e.g., summer Tuesday, with “hot” weather) Rolling average of loads on “non-event” days (e.g., previous 10 weekdays) Average load in previous hours (e.g., previous 3 hours) Key objective – avoid “gaming” possibilities

“Disconnected” Electricity Markets: Fixed retail price  no demand response $/MWh WP Qnormal Lnormal Qspike Lhot Pspike Retail Price Pnormal GWh