Demand Response Price Responsive Demand Energy Efficiency Planning for Public Policy. June 25, 2013

Transcription

1 Demand Response Price Responsive Demand Energy Efficiency Planning for Public Policy June 25, 2013

2 DR and PRD Demand Response Capacity resource Emergency DR paid for capacity and receives full LMP for reducing energy consumption Economic DR is dispatched Zonal modeling Interval metering but two-way communication not required Price Responsive Demand Reduces capacity obligation Reduces payment for capacity and has a dynamic retail rate for energy PRD responds to price Nodal modeling Advanced metering infrastructure with two-way communication 2

3 Economic resource Emergency resource Wholesale Service Demand Side Response PJM Opportunity by Wholesale Service Energy Efficiency Capacity Yes Yes yes Price Responsive Demand* Energy Day Ahead Scheduling Reserves (30 min) Synchronized Reserves (10 min) Regulation Yes Yes Yes Yes Customer may participate as Emergency and Economic DR and as EE 3

4 Market Structure who does what? Energy Efficiency Provider (EERP): Energy efficiency activity by the customer. Curtailment Service Provider (CSP): Demand side response activity by the customer. End Use Customer Load Serving Entity (LSE): Electricity supply to the customer. Electric Distribution Company (EDC): Distribution assets used to distribute the electricity to the customer. 4

5 Emergency DR Revenue and Penalities Revenue Capacity volume bid in market can not exceed capacity responsibility for the customer Peak Load Contribution ( PLC ) RPM clearing price * Capacity volume Energy paid at higher of LMP or offer price Penalties Resource Capability Deficiency Annual Revenue + Higher of (20% * Revenue OR $20/MWday) Event Compliance On Peak: Lesser of (1/number of events or 50%) * Annual Revenue Off Peak: 1/52 * Annual Revenue 5

6 Emergency Product Type Requirements Requirement Limited DR Extended Summer DR Annual DR Availability Maximum Number of Interruptions Hours of Day Required to Respond (Hours in EPT) Maximum Duration of Interruption Notification Event Compliance Test Compliance Any weekday, other than NERC holidays, during June Sept. period of DY Any day during June- October period and following May of DY 10 interruptions Unlimited Unlimited Any day during DY (unless on an approved maintenance outage during Oct. - April) 12:00 PM 8:00 PM 10:00 AM 10:00 PM Jun Oct. and following May: 10 AM 10 PM Nov. April: 6 AM- 9 PM 6 Hours 10 Hours 10 Hours Must be able to reduce load within 2 hours of notification Data due 45 day after end of event month Mandatory test required if no emergency event called 6

7 Economic DR in Energy market Post Order 745 (4/1/12) Participation Day Ahead market or dispatched by PJM Accurate load estimation methodology Revenue If bid => Net Benefits Test Higher of Load reduction * LMP or bid value If bid < Net Benefits Test Load reduction * LMP minus retail rate for generation and transmission DR Cost $30 $40 Mwh (2010) DR Benefit 7

8 Demand Response in Ancillary Service Markets Day ahead scheduling reserves (30 minute supplemental reserves) Must reduce net load within 30 minutes if dispatched by PJM Hourly market price (DAMCP) Synchronized Reserves (10 minute spinning reserves) Reduce load during reserve shortage, must reduce net load within 10 minutes. Hourly market price (SRMCP) Regulation real time load change (increase and decrease) based on real time system conditions Hourly market price (RMCP) 0.1 MW required to participate 8

9 Offers of Demand Response as Capacity in PJM by Delivery Year 9

10 Demand Response Offered by State 10

11 Energy Efficiency (EE) Definition Installation of more efficient devices or equipment or implementation of more efficient processes/systems exceeding building codes, appliance standards, or other relevant standards at the time of installation as known at the time of the commitment to the capacity market. Designed to achieve a continuous reduction in electric demand at the End-Use Customer s retail site that is not reflected in the peak load forecast prepared for the Delivery Year. Value of EE installation is measured during defined EE Performance Hours Fully implemented at all times during the Delivery Year, without any requirement of notice, dispatch, operator intervention. If dispatchable, it would be considered a Demand Resource. 11

12 Eligibility Criteria for EE Installation EE installation must be scheduled for completion prior to DY EE installation is not reflected in peak load forecast posted for the BRA for the DY initially offered EE installation exceeds relevant standards at time of installation as known at time of commitment EE installation achieves load reduction during defined EE Performance Hours EE installation is not dispatchable 12

13 EE Resource EE Resource shall be EE project(s) or portion of EE project(s) in a zone that represents the installations of EE during a defined period of time from June 1 to May 31. EE Resources are eligible to be offered into RPM Auctions (effective 2011/2012 DY) EE Resource may be eligible to receive Capacity Market (RPM) revenue for up to four consecutive Delivery Years. Installation Period Fully Installed for Summer Eligible Delivery Years June 2007-May /2012 June 2008-May /2012, 2012/2013 June 2009-May /2012, 2012/2013, 2013/2014 June 2010-May /2012, 2012/2013, 2013/2014, 2014/2015 June 2011-May /2013, 2013/2014, 2014/2015, 2015/2016 June prior to DY May prior to DY DY DY, DY+1, DY+2, DY+3 13

14 Energy Efficiency Offered in the Mid Atlantic States 14

15 Order 1000 Issues Public Policy Requirements Planning process must consider public policy requirements and evaluate transmission solutions required to satisfy them. No requirement to order transmission to satisfy public policy requirements 15

16 State Agreement Approach PJM will work with states to evaluate public policy requirements and any necessary transmission. States will decide whether to proceed with transmission to meet their needs. Transmission costs will be borne by states sponsoring projects to meet their needs. 16

17 Independent State Advisory Committee (ISAC) State Engagement Comprised of state agencies as deemed appropriate by states PJM would perform analysis and discuss the results with ISAC PJM would inform the Transmission Expansion Advisory Committee of the state input into study assumptions and the results of study analysis for information flow / transparency purposes PJM State RTEP Advisory Committee TEAC ISAC is a communication vehicle for organized input into RTEP studies. It does not decide which projects to include in the RTEP. 17

18 Renewable Portfolio Standard Scenario #1 18

19 Renewable Portfolio Standard Scenario #2 19

20 Renewable Portfolio Standard Scenario #3 20