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

October 3, Agenda Advanced Renewable Tariffs Demand Response

Advanced Renewable Tariffs Advanced Renewable Tariffs

October 3, 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 utilitys retail rate, more often at avoided cost

October 3, ART/Feed-in Tariff Components Guaranteed interconnection Premium rate, declining over 20-year contract life Rate based on renewable generation sources 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

October 3, Status in U.S. of ARTs/FITs Source: NREL, A Policymakers Guide to Feed-In Tariff Policy Design, July 2010p. 20

October 3, Recent Trends in ARTs/FITs 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

October 3, 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.

October 3, 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

October 3, 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

October 3, 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)

October 3, ARTs & RPSs World-Wide Use of ARTs continues to spread, but the rate of growth is slow.

Demand Response Demand Response

October 3, 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

October 3, 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 dont see or respond to variations in wholesale costs

October 3, Market Inefficiency / Lost Opportunities (Persistent differences between cost and price) Hourly wholesale costs Retail price Cost far exceeds pricePrice exceeds market cost

October 3, 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

October 3, 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

October 3, 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

October 3, 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

October 3, Default CPP Load Impacts, SDG&E Average Event Day

October 3, 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)

October 3, 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)

October 3, Appendix: Types of Price-Responsive Demand Dynamic, time-varying pricing Utility programs Direct load control Interruptible programs ISO/RTO programs Economic response Reliability response

October 3, 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-period price when high-load/high-cost market conditions occur Peak-time rebate (PTR) Credit for critical, or peak-time load reductions relative to baseline load

October 3, 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

October 3, 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