OPSI Annual Meeting
October 13, 2015
Session 6
Reliability Pricing Model:
Are Further Changes Necessary?
Reluctantly…yes
But States should also be thinking
beyond RPM
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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)
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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
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CP 20/21 and beyond – NO Base Capacity
• PJM procuring year round for summer peak
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
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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
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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
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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
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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
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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
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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**
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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
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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
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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
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