1 / 158

TEAC21

TEAC21. Thursday, May 6, 2004 Sheraton Hotel Springfield, Massachusetts. TEAC21 Agenda. Welcoming Remarks Load Response Program 2004 Load Response Penetration Study SWCT RFP Results Resource Adequacy Results Interregional Planning Update

rhonda
Download Presentation

TEAC21

An Image/Link below is provided (as is) to download presentation Download Policy: Content on the Website is provided to you AS IS for your information and personal use and may not be sold / licensed / shared on other websites without getting consent from its author. Content is provided to you AS IS for your information and personal use only. Download presentation by click this link. While downloading, if for some reason you are not able to download a presentation, the publisher may have deleted the file from their server. During download, if you can't get a presentation, the file might be deleted by the publisher.

E N D

Presentation Transcript


  1. TEAC21 Thursday, May 6, 2004 Sheraton Hotel Springfield, Massachusetts

  2. TEAC21 Agenda • Welcoming Remarks • Load Response Program 2004 • Load Response Penetration Study • SWCT RFP Results • Resource Adequacy Results • Interregional Planning Update • Economic Assessment Review methodology Results

  3. TEAC22 - June 2nd • TEAC23 - June 25th • FDWG's Elec. & Gas Wholesale Initiative Project May 14th • Cold Snap Issues

  4. Making the Business Case for Demand Response Henry YoshimuraISO New England

  5. Agenda • What is Demand Response? • How do the Demand Response programs work? • What’s New for 2004? • Making the Business Case or What’s in it for me?

  6. What is Demand Response? • Customers reducing their electricity consumption in response to either: • High Wholesale Electricity Prices or • SystemReliabilityEvents • Customers being paid for performance based on wholesale market prices.

  7. Program Types • Reliability (Demand) Programs: • Customers respond to System Reliability Conditions as determined by the ISO New England Control Room • Price Programs: • Customers respond to Wholesale Spot Prices as determined by the Market.

  8. Real-Time Demand Response

  9. Example 1: Scrap Metal Processor • Demand Program • August 15, 2003 • Suspended Operation within 30-Minutes Notice • Promised: • 2.5 MW per Hour • Delivered (Avg): • 1.94 MW per Hour • Energy Payment: • $9,700

  10. Example 2: Industrial Gas Producer • Demand Program • August 15, 2003 • Suspended Operation within 30-Minutes Notice • Promised: • 19 MW per Hour • Delivered (Avg): • 15.4 MW per Hour • Energy Payment: • $127,000

  11. Real-Time Price Response

  12. Example 3: Pharmaceutical Company • Price Response Program • Participated in thirty (30) event days from March through December 2003 • Total of 239 hours of Demand Reduction • Average Demand Reduction: 1.3 MW • Average Payment Rate: $0.104/kWh • Total Energy Payment: $34,000

  13. Metering Options • Internet Based Communication System (IBCS) • 5-Minute Usage Data, Event Notification, Internet Access to Usage and Performance data • Financial subsidies available from ISO-NE • Low Tech and Super Low Tech Option: • Hourly data sent to ISO NE either every day or within 3 months of an event. • Customized Metering Plans: • Data from EMS or sub-metering systems • Statistical sampling allowed • Flexibility: Monitor kW, operating times, on/off status, etc.

  14. Estimating Demand Reduction Adjusted Baseline Actual Usage Baseline (Average of 5 prior non-event business days)

  15. New for 2004 Annual Audit • All programs will be activated at least once per year as a test. • Customers will be paid for the Audit Event • Only ISO New England will know the difference between an Audit Event and a Real Event.

  16. New for 2004 Metering Subsidies for Smaller Facilities • $/kW Basis • Minimum 25kW per Site • Maximums Apply • Smaller Sites must be Aggregated to achieve 100 kW

  17. New for 2004 5-Day Initial Baseline • Initial Baseline reduced from 10 business days to 5 business days. • Customers eligible to participate within 5 business days of the start of ISO New England receiving their hourly data. • Customers must have an hourly meter installed before they are eligible to participate.

  18. New for 2004 Locational Installed Capacity (ICAP) • Currently one capacity market (ICAP) for all of New England • Same ICAP price from Northeast Maine to Southwest Connecticut. • Summer 2004 - Different ICAP values by Load Zone. • Resources located in congested Load Zones may receive higher ICAP payments.

  19. Building the Business Case

  20. Program Benefits: Paid to Get in Shape! • Short-Term • Paid for Performance • Minimum Payment $0.10 to $0.50/kWh • Paid for Availability* • $/kW per Month based on ICAP Market, Utility Program or Resource RFP • Long-Term • Better Load Shape = Better Retail Price * Demand Programs Only

  21. Program Costs • Fixed Costs • Advanced Metering (Required) • Subsidies are available to cover 50% to 100% of the cost. • Controls and Equipment Upgrades (Optional) • Variable Costs • Internal and External Labor • Fuel and O&M • Lost Opportunity • What would I have earned had I not shut down manufacturing for 4 hours? • Did sales go down because I dimmed the overhead lights?

  22. Integrated Energy Management Energy Efficiency Demand Response Supply Management

  23. Integrated Energy Management • Energy Efficiency – Managing energy consumption. • Supply Management – Managing the supplier relationship and risk. • Demand Response – Managing load shape.

  24. Supply Management and Demand Response • Yesterday: Prices set by the Regulator. Customers had little interest in the wholesale markets. • Today: Prices set by the Supplier and Customer. Customers have the option of being connected with the wholesale markets

  25. Supply Management and Demand Response – Customer’s Perspective • It’s all about risk management! The price a customer pays for electricity is based on: • The customer’s credit • The customer’s timing (when they decide to shop for a supplier) • The customer’s load shape (how much electricity they use each hour of the day)

  26. Customer’s Perspective (Continued) • Customers who can not control when they use electricity transfer risk to their supplier. • The supplier must assume the risk that at any point in time the customer can increase their consumption without any consideration for the supplier’s wholesale costs. • Higher risk translates into a higher retail price.

  27. Customer’s Perspective (Continued) • Customers who participate in a Demand Response Program can: • Manage their hourly usage, • Respond to wholesale prices or reliability events, and • Help lower their supplier’s risk. • Lower risk translates into a lower retail price.

  28. Time-of-Use Rate vs. Demand Response “I’ve already shifted all the load I can!” • Time of Use (TOU) Rate Management • Routinely shifting energy use from on-peak to off-peak without impacting day-to-day business operations. Actions justified by rate tariff. • Demand Response • Temporary changes from routine day-to-day business operation during critical time periods. Actions justified by the program benefits.

  29. Real-Time Pricing vs. Demand Response • Real Time Pricing • Exposed to wholesale price volatility and risk all the time. • Real-Time Price Response Program • Opportunity to respond to price volatility on a limited basis without any risk.

  30. Summary of Customer Benefits • Paid for managing consumption in response to reliability or price events. • Hourly usage information that can be used to manage demand and energy charges year round. • Customers who can manage their demand may be able to negotiate lower retail electricity prices from their competitive supplier. • Help ensure the reliability of the region’s electrical grid. • Help mitigate supplier power in setting wholesale prices.

  31. 2003 Customer Survey Results

  32. Questions: • Who participates in Demand Response Programs? • What do they do? • Why do they participate?

  33. Who participates in Demand Response Programs?

  34. Demand Response Growth 400 MW (2003) 200 MW (2002)

  35. ME 17.2% NEMA/ Boston 17.9% NH 52.1% 0.1% RI 0.4% SEMA CT 2.1% VT 3.8% West/Central Mass (WCMA) 6.4% Where are Demand Response Resources? • Where it’s needed most: • Southwest Connecticut and the Greater Boston Area • Where it’s most available: • Maine’s Large Industrial Consumers

  36. Customers by Industry Type Service Industry (Real Estate, Recreation, Health Care, Education, Government) Retail Transportation, Communication, Utilities Manufacturing 0 5 10 15 20 25 30 35 40 45 50 Percent (%) Demand Response Price Response

  37. Customer Characteristics • Price Program: 30% of the MWs, 70% of the customers • Demand Programs: 70% of the MWs, 30% of the customers • Air Conditioning and Refrigeration • 80% of Price Response Customers • 40% of Demand Response Customers • Emergency Generator • 70% of Demand Response Customers • 45% of Price Response Customers

  38. Customer Characteristics (Continued) • Company Size: • Majority have less than 1,000 employees • 1/3 have less than 100 employees • Electricity represents greater than 5% of the their Total Operating Costs • Most customers spend less than 10% of their time Buying and Managing Energy

  39. Customer Characteristics (Continued) • Over 90% have made investments in Energy Efficiency in the past 5 years; 50% have installed Energy Management Systems • 2/3 of Demand Response Customers have participated in either a Time-of-Use, Interruptible or Real-Time Price rate program • 2/3 of all participating customers conducted a Cost/Benefit Analysis prior to enrolling in a Demand Response Program

  40. What changes do customers make to reduce electricity use?

  41. Demand Reduction Methods • Lighting • Over 85% control their Interior Lighting with Wall Switches and Circuit Breakers • HVAC • 50% use their Energy Management Systems • Over 50% say they can increase Temperatures by 1 to 2 °F without effecting Processes or Occupant Comfort • Manufacturing Processes • 45% use Computer or Fully Integrated Manufacturing Controls • Emergency Generation • 40% in the Demand Programs start their Emergency Generators • 70% say they have Emergency Generators • Environmental permitting issues limit the use of most generators to “emergency conditions”

  42. Why do customers participate in Demand Response Programs?

  43. Payments to customers in 2003 totaled approximately $1 million

  44. Load Response PotentialDave EhrlichISO New England

  45. Real Time Price Demand Response Program Market Assessment Prepared for: ISO – New England Prepared by: RLW Analytics and Neenan Associates

  46. The objective of this market assessment is to utilize available customer specific Demand Response data in conjunction with ISO-NE supply models and Utility customer load data to develop a Price Response Market Model (PRMM). • The PRMM will estimate the magnitude of price responsive load response, by zone, as the real time LMP changes.

  47. SWCT New Resource RFP 2004-2008 Presentation to TEAC 21 Jim Platts – ISO New England May 6, 2004

  48. Background • On 12/01/03 ISO New England issued an RFP for up to 300 MW of new emergency resources for SWCT 2004 – 2008 • These resources were sought to meet reliability criteria for SWCT, i.e. provide reserve to reduce the risk of load shedding • Critical area is 16 “Preferred Towns” and 38 “Other Towns”

More Related