OPSI Annual Meeting October 13, 2015

2 Session 6 Reliability Pricing Model: Are Further Changes Necessary? Reluctantly…yes But States should also be thinking beyond RPM

3 Problem CP rules virtually eliminate ability of summer demand response (DR) to continue as capacity resources Why? 1.Elimination of Base Capacity in 20/21 2.Performance Criteria – New Measurement & Verification (M&V)

4 Issue #1 – Elimination of Base Capacity RPM - Limited & Summer Extended DR Summer peaking system and summer available demand resources Least cost procurement Capped total amount CP through 19/20 - Base Capacity (similar to Limited & Extended Products) Summer peaking system and summer available resources Least cost procurement Capped total amount CP 20/21 and beyond – NO Base Capacity PJM procuring year round for summer peak

5 ISSUE #2 – M&V TODAY Peak Load Contribution (PLC) Customers billed for capacity based on PLC DR performance measured relative to PLC DR customers commit to a Firm Service Level (FSL) Customer’s level of uninterruptible service Must drop to that level when dispatched Customers receive credit for difference between FSL and PLC

6 ISSUE #2 – M&V FUTURE UNDER CP Customers still billed for capacity based on PLC DR as CP measured against estimate of what customer would have consumed ( i.e. “winter demand” not PLC) DR as CP participation limited to lesser of summer or winter capability Why? – customers must commit to both an FSL (i.e. level of uninterruptible service) AND to reducing load from their winter demand. Winter peak often well below summer peak, so most load’s ability to provide DR will be reduced This will cause many customers to “leave MWs on the table” in summer, or exit market & peak shave

7 ISSUE #2 M&V Example -Customer has 1 MW PLC which sets capacity costs -Customer can reduce to zero in summer, shut down in winter, so already at zero consumption -Today: Customer can commit to DR, register 1 MW to get to FSL of zero -Hedged capacity costs through interruptible portion of load -Under CP: Customer can no longer serve as a capacity resource because limited to “lesser of” - Customer not consuming in winter, but still paying for 1 MW of capacity year round -PJM will have to procure 1 MW of other resources to replace lost customer, even though that 1 MW not needed in winter

8 IMPACT Range of potential DR that could exit market: 3,300 – 7,600MW. 27% of DR from HVAC which can’t perform in the winter Roughly 3,300 MWs 18/19 BRA, only 38% of DR offered as capacity performance If other 62% doesn’t convert to CP roughly 7,645 MWs of DR lost In 18/19 BRA, 6,252 MWs of DR offered as Base Capacity ONLY, no commitment to CP at any price Existing “Annual DR,” at its peak represented 68% of DR offers If 68% switches to CP, remaining 32% (3,547MW) could be lost. HOWEVER Annual DR subject to different penalties and under current M&V, so should not expect full 68% to transition to CP

9 IMPACT Capacity Cost Impact of Losing 3,330 – 7,600 MWs of DR Previous PJM RPM scenario analysis Loss of 3,000 MWs of capacity = $946 million to $1.8 billion increase in annual capacity costs Loss of 6,000 MWs of capacity = $1.9 - $3.3 billion increase in annual capacity costs

10 IMPACT Market Efficiency RPM no longer least cost alternative to meeting reliability Procuring year round for a summer peak Reliability 1000s of MWs of customers converting to peak shaving a unique challenge to PJM operators Economic Capacity: $1 - $3 Billion above increases already seen in 18/19 BRA Energy: Potential increase in uplift because of lost control & transparency of DR that converts to peak shaving

11 SOLUTIONS 1.Reinstate Base Capacity 2.Keep a summer only product, but with CP penalty structure 3.Fix M&V rules so full value of summer reduction capabilities captured 4.Seasonal procurement 5.Others? **Stakeholder Process Before** ** 20/21 BRA in May 2017**

12 Order 745 is the….. BUT… Regardless of SCOTUS decision Regardless of whether DR is wholesale or retail Regardless of M&V rules Reality is…. Demand response in some form is needed for reliability and efficient market outcomes For demand response in any form… Need customer engagement

13 Changes Outside RPM To future proof your utilities from… Whatever happens with Order 745 Unfavorable DR participation rules Demand or emission reduction targets Increasing choices (solar, distributed generation, EE, etc) Key is… Customer engagement at all levels

14 Changes Outside RPM Successful customer engagement… Allows customers and utilities to deal with market changes, whether GOOD or BAD Keys to successful customer engagement… Provide incentives for utilities to invest in new technology E.g. cost recovery for investments in energy intelligence software and cloud computing technology