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RTP as a Demand Response Program – How Much Load Response Can You Expect?

This presentation discusses the potential load response that can be expected from a Real-time Pricing (RTP) program. It explores the benefits of demand response and provides evidence of load response from RTP programs. The use of technology to facilitate residential RTP is also highlighted.

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RTP as a Demand Response Program – How Much Load Response Can You Expect?

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  1. 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

  2. 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

  3. 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…

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

  5. What is Real-time Pricing (RTP)? • A market-basedpricing 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 • Ademand response program • RTP customers provide load reductions at times of high wholesale prices

  6. 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)

  7. Benefits of Demand Response • Connects wholesale and retailmarkets • Demand response at high prices can reduce wholesale price spikes

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

  9. 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)

  10. 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

  11. 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

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

  13. 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 industrialcustomers; 1,000 MW • GPU Energy “Critical price” TOU • 1997 residentialpilot program

  14. 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)

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

  16. 0.400 0.350 0.300 Veryhigh price 0.250 Moderatelyhigh price 0.200 0.150 0.100 0.050 0.000 HA OSG - I Non-Int - I OSG - C Non-Int - C Diversity of Customer Price ResponsivenessPrice Elasticity by Customer Type and Price Level

  17. 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

  18. GPU “Critical-price” TOU RateEffect 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

  19. “Critical-price” TOU Rate Design 0.5 Critical price 0.4 0.3 Rate 6173 Standard Rate 0.2 Rate 9122 0.1 0 1 8 14 18 20 24

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

  21. 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

  22. 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 Associates608-231-2266

  23. 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

  24. 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

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

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