Securing Alternative Supply: Advanced Renewable Tariffs and Demand Response

1. Securing Alternative Supply:Advanced Renewable Tariffs and Demand Response Bruce Chapman Christensen Associates Energy Consulting October 3, 2012 Wisconsin Public Utility InstituteFundamental Course: Energy Utility Basics

2. Agenda • Advanced Renewable Tariffs • Demand Response

3.  Advanced Renewable Tariffs

4. Precursors to ARTs • PURPA required utilities to buy others’ generation at avoided cost • On-site generators of large customers served under standby tariffs • Net metering: many jurisdictions mandate some means to permit small providers to net out own supply and sell back surpluses to the utility • Limits on size of generation units and overall peak capacity served • Selling back sometimes credited at utility’s retail rate, more often at avoided cost

5. ART/“Feed-in” Tariff Components • Guaranteed interconnection • Premium rate, declining over 20-year contract life • Rate based on renewable generation source’s cost of service, including reasonable return • Cost recovery via a system benefits charge • Can include a MW maximum for jurisdictions, to limit risk to utilities and consumers of price rise

6. Status in U.S. of ARTs/FITs Source: NREL, A Policymaker’s Guide to Feed-In Tariff Policy Design, July 2010p. 20 http://www.nrel.gov/docs/fy10osti/44849.pdf

7. Recent Trends in ARTs/FITs • 2010-12 have featured pauses, backward steps in some jurisdictions: • Spain, the U.K., other nations in Europe and elsewhere and have cut payments, including retroactively • German rates are also being reduced to reflect declining technology costs • North American jurisdictions mixed: • U.S. not advancing, perhaps due to government budgets, rise of shale gas potential • Canada expanding, especially Ontario and Nova Scotia; Ontario now among the most generous North American jurisdictions, but prices are declining as renewable technology costs decline

8. Illustrative FIT Prices ($US) • Prices vary widely across technologies. • Prices vary widely with scale of technology. • Prices are relatively similar across jurisdictions. • Some prices “degress” over time at an annual degression rate.

9. The German Experience • German intention: • Reduce environmental impact of energy • Stimulate development of clean energy industry • Outcome: • Share in electricity consumption rose from 6.4% in 2000 to 17% in 2010; targeting 35% for 2020 • Germany is now a significant producer in renewable energy generation • Government claimed 280,000 jobs in 2009

10. Current Issues • Renewable targets are being reviewed as part of discussion of fate of nuclear generation • Electricity cost increases are being questioned: • Small apparent price increases, but future uncertain • Subsidy for renewables vs. claimed negative effect of renewables on spot prices • Out-of-merit dispatch vs. absence of environmental cost in standard generation costs • Cap and Trade results in (partial) offset of German conservation by increased fossil production elsewhere

11. ART vs. RPS • ARTs may compete with Renewable Portfolio Standards in stimulating demand for renewable generation • An RPS attempts to regulate the quantity of renewable generation while an ART/FIT attempts to regulate its price • Arguably, one must choose • Europe has chosen ARTs • US favors RPSs but is still looking at ARTs • ART advocates maintain that having both is feasible • 29 states, DC and two territories have a mandatory RPS; 8 states and two territories have voluntary RPS targets (DSIRE 2012)

12. ARTs & RPSs World-Wide Use of ARTs continues to spread, but the rate of growth is slow.

13.  Demand Response

14. Demand Response – (DR)or, Price-Responsive Demand (PRD) • What is it? • Changes in consumers’ electricity usage pattern (particularly in peak periods) in response to • Price signals(e.g., occasional high prices), • Incentive payments (for load reductions), or • Requests to curtail usage

15. Why Important? Inefficient Markets Disconnect Between Wholesale and Retail Markets • Wholesale costs – vary substantially by season, day, and hour (and location) • Highly skewed – many low-cost hours; few very high-cost hours (e.g., 1 – 2%) • Retail price – typically fixed at an average for season or year (or possibly time of day) • Consumers don’t see or respond to variations in wholesale costs

16. Cost far exceeds price Price exceeds market cost Retail price Market Inefficiency / Lost Opportunities (Persistent differences between cost and price) Hourly wholesale costs

17. DR Has a Role in Various Wholesale Electricity Markets • Energy markets (kWh) • Day-ahead • Hour-ahead • Real-time • Capacity markets (maximum kW) • PJM, ISONE • Utility resource plans • Ancillary services markets • Supplemental/non-spinning reserves • Synchronized/spinning reserves

18. How to Achieve Price-Responsive Demand (PRD) • Price-based mechanisms: • Dynamic retail pricing: Prices vary to reflect costs • DR programs:Retail prices remain fixed, but consumers receive credits for load reductions • Quantity-based mechanisms • Utilities: Direct load control (e.g., AC); interruptible service (large customers) • DR programs: Emergency or capacity-based DR through ISO/RTOs

19. Do Customers Respond to Dynamic Pricing? Overview • YES. Numerous studies show significant price response on average • Considerable variability across customers • Most responsive – large; energy intensive; have facilitating technology • Small % of customers provide large % of total response

20. CPP for C&I Customers (> 200 kW)Recent California Experience • Voluntary CPP rates offered since 2005 • Transition to default CPP • SDG&E in 2008; • SCE in fall 2009 • PG&E in spring 2010 • CA Energy Consulting conducted statewide load impact evaluations for 2006 through 2009, as well analysis of other demand response programs

21. Default CPP Load Impacts, SDG&EAverage Event Day

22. Distribution of C&I CPP Load Impacts across Customers • Share of load impacts accounted for by the top-responding 5% of customers: • PG&E: 64% (16% of load) • SCE: 55% (15% of load) • SDG&E: 74% (13% of load)

23. Conclusions • Price-responsive demand is vital to well-functioning wholesale power markets • Dynamic pricing provides natural market-based approach • DR programs can provide price signal in absence of efficient retail pricing • Key issues: • Costs of advanced metering • DR program design without subsidies • Measuring DR load impacts (baseline)

24. Appendix: Types of Price-Responsive Demand • Dynamic, time-varying pricing • Utility programs • Direct load control • Interruptible programs • ISO/RTO programs • Economic response • Reliability response

25. A. Dynamic, Time-Varying Pricing • Real-time pricing (RTP) • Hourly pricing with day-ahead or hour-ahead notice • Critical-peak pricing (CPP) • Flat or TOU rate, plus a critical peak-periodprice when high-load/high-cost market conditions occur • Peak-time rebate (PTR) • Credit for critical, or peak-time load reductions relative to baseline load

26. B. DR Programs – Utilities • Direct load control (e.g., AC, water heat) • Monthly credit for utility right to invoke cycling strategy • Interruptible service • Capacity credit for utility right to call for interruption • No payment for performance or over-compliance • Strong penalty for non-compliance

27. C. DR Programs – ISO/RTOs • Retail load “participates in the wholesale market” by bidding demand reductions • Needed due to absence of dynamic retail pricing • Customers generally participate through energy providers or curtailment aggregators • Economic – Customers receive DR payment ($ per kWh-reduced), as substitute for a dynamic price • Reliability – Customers receive capacity credit for committing to curtail when called; and often an energy payment for load reductions during events