Retail Pricing & Demand Response in New England

1. Metering and Retail Pricing New England Demand Response Initiative Rick Weston 2 May 2002

2. Purpose and Challenge • To better align behavior in the retail and wholesale markets, what policies need to be implemented and what metering and communications technologies deployed to encourage customer demand-response? • What can be done to reveal to customers and LSEs the value (cost) of energy savings (consumption) during times of high loads or system constraints?

3. Background: The Pricing Continuum • Energy-only rates • 100 years of consumption metering: • Fundamental purpose: collect revenues • Multi-part and time-of-use • 2nd half 20th century: Boiteaux, Bonbright and Kahn and the goal of economic efficiency • Real-time pricing • Wholesale competition and the uncertainty of supply

4. Pricing and Metering:Energy Only • Per kWh, by billing period (e.g., monthly) • Flat, energy-only rates • Seasonal differentiation • Block rates: inclining or declining • No time-differentiated pricing with billing period • After the fact data collection • No information about customer usage patterns

5. Pricing and Metering:TOU and Multi-Part • Additional metering capabilities • Special TOU, capacity, or interval metering • Per kWh and per kW • Time-of-use, typically time-of-day • Multi-part: energy and demand • Measures customer non-coincident demand • Useful for distribution planning, though not system • After the fact data collection • Some information about customer usage patterns

6. Pricing and Metering:Real-Time Pricing • Different retail prices for different hours of the day and for different days, usually based on some measure of short-term power costs • Hourly differentiation of prices • Advanced metering and communications • The other side of the RTP coin: Interruptible programs

7. Pricing and Metering

8. Advanced Metering and Communications • Technologies that record, process, and transmit time-specific information about a customer’s electricity usage • Interval metering • Advanced meter reading • Frequent polling for time-specific usage data • Two-way communications for real-time pricing

9. Capabilities ofAdvanced Metering • Pricing and billing • Customer service • Billing inquiries, mass marketing, outages, emergencies, service calls, customer habits, diagnostics • Energy services • Discos, LSEs • Meter maintenance

10. Capabilities ofAdvanced Metering 2 • System operations • Dispatch, demand response, identifying losses, settlements, load research and forecasting • Planning • Distributed utility, transmission, or IRP • Information for developing improved building and appliance standards

11. Meters and Networks • What kinds of systems can support demand response and dynamic pricing? • Considerations: • Usage measured: demand or energy • Interval length • Data storage capacity • Remote communications • Meter architecture

12. Meters and Networks 2 • Where should the intelligence reside in the network? • “Smart meter, dumb network” • Sophisticated meter, public network, infrequent polling • “Dumb meter, smart network” • Less meter functionality, dedicated network elements, frequent polling • Two-way communications

13. Determining Loads andSettling LSE Obligations • Load profiling • Average load profile by customer type • Total class usage in period fitted to load profile • Class loads and profiles summed to establish aggregate load and profile for each LSE • Aggregate profiles used to establish each LSE’s responsibility for system dispatch • Interval metered load • On basis of actual, hourly metered data

14. Drawbacks of Load Profiling • Individual customer’s actual demand is not directly relevant to the settlement process • But it is highly relevant to the actual costs that were incurred to balance the system) • To the extent that a customer’s actual load profile differs from the class average, the LSE sees neither the savings nor the costs • No incentive for load management, end-use efficiency, or dynamic pricing

15. Pricing Experience • Vermont, Maine • Seasonally differentiated TOD rates • Puget Sound Power • TOD, four periods: morning, mid-day, afternoon, and night • Remote meter reading, frequent polling • California inclining block rates

16. Pricing Experience 2 • RTP and Load Management • Georgia Power: Two-Part RTP • Baseline usage based on historic demand, priced at embedded rates • Incremental usage and decremental savings priced at RTP, calculated as sum of marginal energy costs, line losses, a “risk recovery factor” (a fixed adder), and, at peaks, marginal transmission costs and outage cost estimates • Two options: day ahead and hour ahead • 1,600 customers, 5,000 MW of load

17. Pricing Experience 3 • RTP and Load Management • Georgia Power, continued • Interruptible for some customers, penalties for failure to interrupt • Price protection products: variable customer baselines (up or down), caps, collars, indexing • Duke Power: Two-Part RTP • Similar to Georgia Power • TVA: One-Part RTP • Surplus energy at off-peak times, interruptible

18. Pricing Experience 4 • RTP and Load Management • Gulf Power, TOD and RTP • Residential TOD, four periods • Low, Medium, High, and Critical • Times for Low, Medium, and High are set • Critical periods occur when wholesale market conditions dictate • Customer programmable “Superstat” controls heating, cooling, pool pumps, water heating • Customer’s willingness to pay determines usage

19. Lessons Learned • Seasonal, TOD, multi-part, block • Long-term improvements in efficiency: higher load factors, smaller needle peaks, increased end-use efficiency, greater price stability, and lower total system costs • No short-term dispatchability (interruptibility) and only generalized signals of the actual costs of production

20. Lessons Learned 2 • RTP and Load Management • Significant load shifting benefits, mostly from a relatively small number of customers • Those with on-site generation and discrete production processes most likely to respond • Customers motivated by saving $ • Customers dislike price volatility • Customer education critical to program success

21. Barriers to Innovative Pricing • Costs • Metering, education, admin, telemetry • Cost-effectiveness: perceptions and testing • Customer • Risk aversion, price volatility • Elasticity, identifying responsive customers

22. Barriers to Innovative Pricing 2 • Utility/LSE • Revenue loss, load profiling, billing and collection, gaming of customer baselines • Regulatory and Legislative • Perceptions of customer elasticities, concerns about fairness, other pricing policies (e.g., price caps), lack of coordination with DSM programs, default service

23. Barriers to Innovative Pricing 3 • Technological • Lack of requisite metering and communications equipment, integration with existing systems, lack of customer energy management capabilities

24. Policy Issues: Pricing • Purpose: What are we trying to achieve? • Dynamic pricing: mandatory or optional? • Free-ridership, impacts on inelastic users • Low-volume v. high volume consumers • Threshold for mandatory dynamic pricing? • Utility net lost revenues • Disincentives to efficient solutions? Policy responses?

25. Policy Issues: Pricing 2 • Potential benefits • What are the costs and benefits of more dynamic pricing? How are they measured? • Retail competition and default service • How does the existence of default service promote or inhibit demand responsiveness? • Load profiling and settlement • Alternatives to interval-metered data?

26. Policy Issues: Metering • Purpose: What are we trying to achieve? • Cost-effectiveness • What are the costs and benefits of alternative approaches to metering? • Current state of interval metering and AMR in region? • How will this affect policy choices?

27. Policy Issues: Metering 2 • Should advanced metering be provided competitively? Who should own the meter? • Who should should pay? • Large scale or targeted deployment? • Threshold? Affected by pricing objectives. • Smart meter, dumb network? Or opposite? • Information control, access, and format