Does Real-time Pricing Deliver Demand Response?

1. Does Real-time Pricing Deliver Demand Response? Charles Goldman Lawrence Berkeley National Laboratory CAGoldman@lbl.gov New England Restructuring Roundtable October 28, 2005

2. Policy Questions • What evidence is there that RTP delivers demand response (DR)? • What factors determine how much DR you get? • Customer enrollment (amount of load exposed to hourly varying prices) • Price response of enrolled customers • Relative roles of RTP and Emergency DR programs • How does default service RTP impact retail market development?

3. Recent Projects Examining Large Customer RTP Experience • Optional RTP Tariffs: Utility Experience • Summarized 43 RTP programs offered by vertically integrated utilities in 2003 • Analyzed trends in program participation & participant price response • RTP as Default Service: • Case studies of eight states where RTP is considered for large C/I customers in context of competition for retail load • Comparative analysis of market and regulatory context, RTP tariff design, and customer choices and response • Case Study of Niagara Mohawk RTP • In-depth study of customer choices and response to day-ahead hourly RTP tariff as default-service in a competitive retail environment • Interviewed and surveyed customers and estimated price response

4. Optional RTP Tariffs: Overview • RTP offered by: • Most investor-owned utilities (IOU) in Southeast and TVA • All IOU in Illinois and NY (statutory/ regulatory requirement) • Many mid-west utilities (First Energy, Cinergy, Xcel, KCPL) • All CA IOUs in 2003, but two programs since cancelled • RTP not offered by many utilities in: • The West • New England Number of Utilities in Each State withRTP as Optional Tariff (2003)

5. RTP as Default Service: Regulatory & Market Context • Default RTP driven primarily by retail market restructuring goals – not DR • In New York, PSC first decided against and then recently in favor of statewide default service RTP for large C&I

6. Case Study of Niagara Mohawk RTP: Choices Available to SC-3A Customers

7. RTP Enrollment: A Snapshot • Enrollment in Default RTP: • 3-15% in PJM states • 25-34% in New York • Why the differences? • Alternative, fixed-price utility supply option (e.g., Duquesne) • Tariff design: day-ahead vs. after-the-fact price notice • Retail market development? • Enrollment in Optional RTP: • Anemic in all cases except Ga. Power • Offer inadequate savings opportunities or “too risky” • Lack of aggressive marketing by utility

8. Niagara Mohawk RTP: Customer Migration Patterns • “You can build it, but they may not (or may) stick around” • 17% of customers left NMPC for ESCO and never returned • 18% went back and forth • 37% switched later to ESCO and never returned • 28% of customers stayed on NMPC RTP • Load served by ESCO: 30% (2000) increased to 63% by 2004 • Surprise: Load facing hourly prices (45-60% in 2004)

9. Load Response Strategies Niagara Mohawk RTP: What Customers Told Us • ~30% of customers say they are unable to curtail load • ~70% can either forego or shift load or utilize onsite generation • Most customers report multiple barriers to price response;~15% respond without obstacles

10. Niagara Mohawk RTP: What customers actually did? • Relative price responsiveness varies substantially across and within business sectors • Key Findings: • 18% of customers account for 75-80% of aggregate DR • 119 customers reduced their peak demand (500 MW) by ~10% (50 MW)

11. Optional RTP Tariffs: Maximum Load Reductions Public Service of Oklahoma 40 MW • Aggregate load reductions are modest for nearly all RTP programs (<1% of utility peak) • Only two utilities (Duke & Georgia Power) reported load reductions greater than 100 MW Duke Power 200 MW Com Ed (Rate RHEP) Jersey Central Power & Light 60 MW Florida Power & Light Kansas CityPower & Light Otter Tail Power(Option 1) Pacific Gas & Electric Georgia Power 750 MW 23 MW Gulf Power 0% 1% 2% 3% 4% 5% 6% Maximum Load Reduction (% of Utility's Peak)

12. RTP as Default Service: Customers Exposed to Spot Market Prices • Potential market impact: • Niagara Mohawk – curtailments equivalent to about 0.6% of system peak load • New Jersey and Maryland – unknown

13. ISO/Utility DR Program Performance DR Program Maximum Load Reductions Percent of Total System (State or Utility) Peak • Actual performance tends to vary with program type • Emergency DR programs yield large reductions when high payments offered (e.g., $0.50/kWh) • Call option programs yield close to participants’ nominated amount • “Emergency DR” programs have thus far demonstrated larger load reductions than RTP (except for GA) • but not a direct substitute for RTP

14. Conclusions: RTP as a Demand Response Strategy • “You can build it but they may not come” • Low enrollment in most optional RTP programs • “Participation doesn’t guarantee price response” • Only 10 of 42 Optional RTP programs report load reductions • 18% of NMPC customers account for 75-80% of DR • “Even if they come, they may not stick around” • Expect that most customers will switch from Default RTP • But Default RTP can yield significant indirect market benefits • More retail choice customers willing to face hourly prices; but will they respond? • Program design, supporting infrastructure and utility incentives are keys to success • Default Service RTP: Day-ahead, hourly pricing balances retail market development and DR • Optional RTP: Georgia Power’s secrets to success (corporate commitment, aggressive marketing; customers can hedge; and CBL rules allow customers to generate bill savings) • Policymakers must make long-term commitment to build DR infrastructure (e.g.,customer info, tech. assistance, codes/standards, mkt. assessment)

15. Implications: RTP as a Demand Response Strategy • Retail choice states • Will state PUCs have the political will to establish RTP as default service and for which groups of customers? • Many customers willing to face hourly prices for some load under current market conditions (moderate price volatility, reasonably competitive retail market) • NMPC experience suggests moderate levels of demand response at high prices (10%; 50 MW) • Policymakers need more information on retailer contract types and response • Wholesale market design • Customers will enroll and respond to emergency DR programs (1-3% of system peak) • These DR programs are complementary with RTP • Linking Price Response to ISO Spot Markets

16. LBNL Reports on RTP Experience “A Survey of Utility Experience with Real Time Pricing” G. Barbose, C. Goldman and B. Neenan. LBNL-54238, December 2004. “Real Time Pricing as Default or Optional Service for C&I Customers: A Comparative Analysis of Eight Case Studies” G. Barbose, C. Goldman, R. Bharvirkar, N. Hopper, M. Ting and B. Neenan. LBNL-57661, August 2005. “Customer Strategies for Responding to Day-Ahead Market Hourly Electricity Pricing” C. Goldman, N. Hopper R. Bharvirkar, B. Neenan, R. Boisvert, P. Cappers, D. Pratt, and K. Butkins. LBNL-57128. August 2005. Reports available at: http://eetd.lbl.gov/ea/EMS/drlm-pubs.html

17. Background slides

18. Two-part Real-Time Pricing Tariff: How It Works • Customer sees hourly prices for their marginal usage • Customer baseline (historic) usage (CBL) partially hedges customer against hourly price volatility

19. Block and Index Pricing

20. RTP as Default Service: Customer Enrollment

21. Niagara Mohawk RTP Case Study: Most Customers Don’t Check Hourly Prices • 70% of NMPC customers report never or rarely checking day-ahead hourly prices • 13% check when other signals – NYISO events or hot weather – suggest they are high • 17% consult prices routinely

22. $815/$169 Average Peak to Off-Peak Price Ratio $439/$140 Avg. Pk and Off-Pk Price ($/MWh) $181/$80 $77/$51 Response to Day-Ahead Prices: NMPC Aggregate Price Response Curve 119 SC-3A customers would reduce their load by about 50 MW, or 11% of their peak demand (~500 MW), at high prices

23. Price Response of Customers on Utility RTP Tariffs • Georgia Power Company (Summer 1999 estimates) • 750 MW load reduction on an exceptionally high priced day • Load reduction = ~15% of participants’ combined billing demand • Niagara Mohawk Power Company (2004) • 50 MW reduction when peak prices = 5x off-peak prices • Load reduction = ~10% of participants’ combined billing demand

24. Trends in Day-Ahead Market Prices: Summer, Eastern New York *On-Peak defined as 2pm-5pm on weekdays • Less price volatility since 2002 compared to summers of 2000 and 2001 • Average hourly prices for summer period are relatively stable over 5 years

25. Georgia Power’s Secrets of Success • Unique Georgia retail market underlies Georgia Power’s success with RTP • “New” C&I customers have a one-time choice of supplier and GPC is allowed to compete • High-level corporate commitment to RTP as a tool to compete for new load • Key tariff design and implementation details • Aggressive marketing for >10 yrs • High degree of ongoing customer support and (re-)training • Attractive hedging options • Two-part tariff design with CBL • Supplemental financial hedging products (caps, collars, contracts for differences, adjustable CBLs) • CBLrules have enabled many participants to obtain substantial bill savings, regardless of load response

26. Georgia Power RTP: CBL Rules Enable Bill Savings • Key fact: On average, each customer on Georgia Power’s RTP rate has a CBL equal to 60% of its actual load • Across a sample of 85 accounts, the CBLs ranged from 0%-80% of the customer’s total load • How can this be? • Customers previously on Georgia Power’s Supplemental Energy rate (a curtailable rate) could receive an initial CBL equal to their Firm Load Level • New customers can receive a CBL below their projected load • All customers can expand their facilities or add load without adjusting their CBL upward • Hourly RTP prices for load above the CBL have historically averaged less than standard tariff rates • Marginal vs. Embedded Costs

27. Utility and ISO/RTO DR Program Enrollment (2004) • Most case study states have call option (or interruptible) and voluntary load reduction programs for large C&I