1. 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

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-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

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 retail markets
Demand response at high prices can reduce wholesale price spikes

8. 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

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 industrial customers; 1,000 MW
GPU Energy “Critical price” TOU
1997 residential pilot 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 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

16. 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

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 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

19. “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

20. 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

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 Christensen Associates

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