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Lessons from California The Role of Demand Response

Lessons from California The Role of Demand Response. Energy Markets in Turmoil Institute for Regulatory Policy Studies May 17, 2001 Steven Braithwait Christensen Associates. Christensen Associates. Economic and engineering consulting for electric power industry

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Lessons from California The Role of Demand Response

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  1. Lessons from CaliforniaThe Role of Demand Response Energy Markets in Turmoil Institute for Regulatory Policy Studies May 17, 2001 Steven Braithwait Christensen Associates

  2. Christensen Associates • Economic and engineering consulting for electric power industry • 20 years of experience in designing and evaluating pricing strategies – • TOU • Real-time pricing (NiMo, Georgia Power, KCP&L) • Market-based interruptible load programs • Unbundling; pricing transmission and ancillary services

  3. The California Energy Crisis • High wholesale prices • Rolling blackouts • Financial/debt crisis – bankruptcy • State take-over of power purchases • Charges of market manipulation

  4. California Background -- Supply • No new capacity in ’90s • Utilities sold ½ of generation (fossil) to Duke, Dynegy, AES, Mirant, Reliant, etc. • No long-term power contracts • California imports 20 – 25% of power requirements (NW hydro; SW fossil) • Tight capacity margin

  5. California Background -- Demand • Modest growth in early 90s • Rapid growth since 1995 in Calif. and in the Southwest & Northwest • Rate freeze, with 10% discount until 2002 (or when “stranded costs” recovered) • SDG&E rate freeze lifted in 1999

  6. Background – Wholesale Markets • All power bought and sold in spot market • PX day-ahead energy; ISO real-time energy, reserves & ancillary services • ISO price cap ($750/MWh  500  250) • 30% + of energy left unscheduled for ISO real-time market on high-price days

  7. PX Prices and ISO Load(May – September 1999)

  8. 800 700 600 500 $/MWh 400 300 200 100 0 20000 25000 30000 35000 40000 45000 MW PX Prices and Total ISO Load(May 15 - August 31, 2000)

  9. Utilities “Buy High” and “Sell Low”(May – August, 2000) 140 $126 120 100 80 $65 $/MWh $50 60 40 20 0 Average Revenue Wholesale Costs (expected) Wholesale Costs (actual)

  10. Financial Impacts of California CrisisSummer 2000 • Wholesale costs – $13.5 billion (May – Sept.) • Expected costs under rate freeze -- $5 billion • Utility debt -- $8 billion (now $13 billion+) • Customer cost of outages(e.g., $400 million for 4 days of rolling blackouts in early 2001)

  11. What Went Wrong in Summer 2000? • “Perfect storm” hit an already tight market • Unexpected outages • Low imports (low hydro, high demand outside) • High natural gas prices • Market design problems • No hedging (financial effect) • Price caps (affected multiple markets) • Strategic bidding/withholding? • No demand response (except San Diego)

  12. What Continues to go Wrong? • Financial/debt crisis continues • Utility debt from 2000 still exists • Generators not paid; some independents shutting down • Continuing high natural gas prices • Political/regulatory gridlock -- retail energy prices still below wholesale costs • Insufficient capacity for summer • No demand response (new buy-back and RTP programs planned for the summer)

  13. WP Lhot Lnormal Pspike Pnormal Qnormal Qspike Disconnected Markets – Fixed price  no demand response $/MWh Retail Price GWh

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

  15. Benefits of Demand Response Programs • Prices signal customers the cost of power • Customer demand response helps balance supply and demand • Reduces wholesale prices, by factor of 10+(e.g.,  load by 2.5%  WP  by 25%) • Reduces market power of suppliers

  16. Types of Demand Response Programs • Demand-side bidding • “Buy-back,” or pay-for-performance interruptible • Suppliers buy load relative to baseline at price tied to market price • Real-time (hourly) pricing • Full-time • Whenever prices exceed specified level

  17. Load on highest price day Highest HA prices Example of Demand Response – Georgia Power RTP(Demand response = 250 MW; 60% of reference load)

  18. Estimated Effect of Demand Response(Braithwait-Faruqui; March 15 PUF) If RTP offered to California large C&I customers: • Load reduction in high-price hour – 2.4% • Reduction in wholesale price – 24% • Drop in summer wholesale costs -- $700 M

  19. 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. • Demand Response – The Ignored Solution to California’s Energy Crisis, Steven Braithwait and Ahmad Faruqui, in Public Utilities Fortnightly, March 15, 2001. • Contact:Steve Braithwait (steve@lrca.com)Christensen Associates608-231-2266

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