Transcript Slide 1

Demand Side Products in PJM
Cornell University
January 17, 2011
Joseph Bowring
Demand Side Products in PJM
• Overview of demand side programs in PJM
• Rationale for demand side programs
• Definition of economic demand side product
• Energy market interruptibility
• LMP customers
• Retail rate customers
• Definition of DR product
•
•
•
•
•
©2011
Capacity market interruptibility
Called only for an emergency (economic product)
Limits on number and duration of calls; season
2.5 percent demand reduction in capacity market
DR sets own energy price when called
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Demand Side Products in PJM
• Inclusion of LMP customers in energy market
program
• M&V issues
• CBL definition
• Double counting/over compliance
• Impact on RPM clearing prices
• Relationship to quality of product
• No DR market power mitigation
©2011
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New Demand Side Products in PJM
• New demand side products: capacity market
• Limited product (10 x 6)
• Unlimited product (some limits remain)
• Summer unlimited
• New demand side products: energy and capacity
markets
• PRD
o
o
o
o
o
©2011
Metering
Central control
Economic resource
Nodal pricing
Link to wholesale price
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Table 2-100 Overview of Demand Side Programs (See 2009
SOM, Table 2-93)
Emergency Load Response Program
Load Management (LM)
Capacity Only
Capacity and Energy
Registered ILR only
DR cleared in RPM; Registered
ILR
Mandatory Curtailment
Mandatory Curtailment
RPM event or test compliance
RPM event or test compliance
penalties
penalties
Capacity payments based on RPM Capacity payments based on RPM
clearing price
price
No energy payment
Energy payment based on
submitted higher of "minimum
dispatch price" and LMP. Energy
payment only for mandatory
curtailments.
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Economic Load Response Program
Energy Only
Not included in RPM
Energy Only
Not included in RPM
Voluntary Curtailment
NA
Voluntary Curtailment
NA
NA
NA
Energy payment based on
submitted higher of "minimum
dispatch price" and LMP. Energy
payment only for mandatory
curtailments.
Energy payment based on LMP less
generation component of retail rate.
Energy payment for hours of voluntary
curtailment.
5
Figure 2-23 Demand Response revenue by market: Calendar
years 2002 through 2009
350
Synchronized Reserve
Energy Emergency
Capacity
300
Energy Economic Incentive
Energy Economic
250
Millions ($)
200
150
100
50
0
2002
2003
2004
2005
2006
Month
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2007
2008
2009
Table 2-101 Economic Program registration on peak load days:
Calendar years 2002 to 2009 and January through September
2010 (See 2009 SOM, Table 2-94)
14-Aug-02
22-Aug-03
03-Aug-04
26-Jul-05
02-Aug-06
08-Aug-07
09-Jun-08
10-Aug-09
06-Jul-10
©2010
Registrations
96
240
782
2,548
253
2,897
956
1,321
899
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Peak-Day,
Registered MW
335.4
650.6
875.6
2,210.2
1,100.7
2,498.0
2,294.7
2,486.6
1,725.7
Table 2-106 Distinct customers and CSPs submitting
settlements in the Economic Program by month: January 2007
through September 2010 (See 2009 SOM, Table 2-101)
2007
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Total Distinct Active
©2010
Active CSPs
11
10
9
11
12
12
15
19
15
11
10
11
21
2008
Active
Customers Active CSPs
72
13
89
13
87
11
98
12
109
12
195
17
259
16
321
17
279
17
245
13
204
14
243
13
405
24
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2009
Active
Customers Active CSPs
261
17
243
12
216
11
208
9
233
9
317
20
295
21
306
15
312
11
226
11
208
9
193
10
522
25
8
2010
Active
Customers Active CSPs
257
11
129
9
149
7
76
5
201
6
231
11
183
18
400
14
181
11
93
143
160
747
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Active
Customers
162
92
124
77
140
152
243
302
97
433
Figure 2-25 Economic Program payments: Calendar years
2007 through 2009 and January through September 2010 (See
2009 SOM, Figure 2-24)
$6,000,000
2007
2008
2009
$5,000,000
2010
$4,000,000
$3,000,000
$2,000,000
$1,000,000
$0
Jan
©2010
Feb
Mar
Apr
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May
Jun
9
Jul
Aug
Sep
Oct
Nov
Dec
Table 2-110 Registered MW in the Load Management Program
by program type: Delivery years 2007/2008 through 2010/2011
(See 2009 SOM, Table 2-105)
Delivery Year
2007/2008
2008/2009
2009/2010
2010/2011
©2010
Total DR MW
560.7
1,017.7
1,020.5
893.4
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Total ILR MW
1,584.6
3,480.5
6,273.8
7,982.4
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Total LM MW
2,145.3
4,498.2
7,294.3
8,875.9
Table 2-112 Demand Response (DR) offered and cleared in
RPM Base Residual Auction: Delivery years 2007/2008 through
2013/2014 (See 2009 SOM, Table 2-107)
Delivery Year
2007/2008
2008/2009
2009/2010
2010/2011
2011/2012
2012/2013
2013/2014
©2010
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DR Offered in BRA
123.5
691.9
906.9
935.6
1,597.3
9,535.4
12,528.7
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DR Cleared in BRA
123.5
518.5
865.2
908.1
1,319.5
6,824.1
8,977.4
Table 15 Impact of not reducing demand by Short-Term
Resource Procurement Target: 2013/2014 RPM Base Residual
Auction
LDA
Pepco
EMAAC
MAAC
RTO
©2010
Actual Auction Results
Clearing Prices
Cleared UCAP
($ per MW-day)
(MW)
$247.14
4,791.7
$245.00
32,835.4
$226.15
67,639.9
$27.73
152,743.3
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Without Short-Term Resource
Procurement Target Reduction
Clearing Prices
Cleared UCAP
($ per MW-day)
(MW)
$272.34
5,288.9
$324.01
32,977.5
$272.34
68,308.1
$42.00
156,493.0
Table 22 DR and EE Offers by Price Range: 2013/2014 Base
Residual Auction
Price Range
$0 per MW-day to $20 per MW-day
$20 per MW-day to $40 per MW-day
$40 per MW-day to $60 per MW-day
$60 per MW-day to $80 per MW-day
$80 per MW-day to $100 per MW-day
> $100 per MW-day
©2010
Existing
Percent of
UCAP (MW) Existing Offers
5,115.9
68.5%
879.8
11.8%
874.6
11.7%
141.0
1.9%
240.0
3.2%
222.1
3.0%
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Planned
UCAP (MW)
1,863.9
465.8
1,687.7
777.9
756.3
684.5
Percent of
Planned Offers
29.9%
7.5%
27.1%
12.5%
12.1%
11.0%
Total Cumulative
UCAP (MW) Total Percent
6,979.8
50.9%
1,345.6
60.7%
2,562.3
79.4%
918.9
86.1%
996.3
93.4%
906.6
100.0%
Table 23 DR and EE Offer Impact
Actual Auction Results
Two Thirds of Actual DR or EE
One Third of Actual DR or EE
No DR or EE Offers
Clearing Prices Cleared UCAP Clearing Prices Cleared UCAP Clearing Prices Cleared UCAP Clearing Prices Cleared UCAP
($ per MW-day)
(MW) ($ per MW-day)
(MW) ($ per MW-day)
(MW) ($ per MW-day)
(MW)
$247.14
4,791.7
$289.69
5,094.3
$340.80
4,900.4
$340.80
4,705.8
$245.00
32,835.4
$321.47
32,079.1
$391.59
31,320.8
$391.59
30,492.3
$226.15
67,639.9
$289.69
66,229.4
$340.80
64,293.8
$340.80
62,285.0
$27.73
152,743.3
$43.66
152,743.3
$133.12
151,320.9
$330.05
147,144.0
LDA
Pepco
EMAAC
MAAC
RTO
©2010
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New Demand Side Products: Capacity
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Unlimited Capacity Product
• MMU supports the development of an unlimited
capacity only product to replace the current
summer only 10X6 product:
• Unlimited capacity is the standard unit of measure
in the RPM Auctions.
o
This is the definition of the capacity product.
• The 10X6 product and the summer unlimited
product are not equivalent capacity
• Paying the full capacity price for a limited product
distorts market outcomes
• Defining the product clearly and consistently
means that there is no reason for multiple capacity
prices
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Unlimited Capacity Product
• Current limited DR can be converted to an
unlimited product:
• Portfolio aggregation of limited DR customers to
create an unlimited equivalent portfolio
• Compliance evaluated at portfolio basis
• EFORd approach can value all DR products
• Unlimited DR is a capacity only product
• DR is selling interruptibility. Load is not on system
when those who pay for capacity need it.
• No Day Ahead or Real Time energy offers
• Not eligible to set price in the energy market when
called in the capacity market
• No retail rate related restrictions
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Summer Only Capacity Product
• Unlimited Product definition is consistent with
value of Summer Unlimited product
• Customers qualifying as Summer Unlimited
should wholly or partially qualify as Unlimited:
• Using Firm Service Level (FSL) approach, if
naturally occurring load levels are below the FSL
outside the summer period, customer is compliant
• Example:
o
o
©2010
If load reduction to FSL comes from air conditioning
load cycling in summer peaks, non summer period
load will already reflect absence of air conditioning
load.
Customer would be compliant in non summer period
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Capacity Product: Questions
• What are the locational requirements for DR
compliance/response calculations?
• PJM needs to define minimum likely needed
geographic area for DR response
• Defines ability of CSP to aggregate limited
customers into unlimited portfolio
• To what extent are there offsetting increases in
fixed load outside of the summer period which
may cause load to be greater than the FSL?
• Is there weather sensitive winter load that creates
load above summer FSL?
©2010
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New Demand Side Products: PRD
©2010
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Introduction
• Issues in defining PRD:
• Price setting in emergency conditions
• Initiation of mandatory curtailment
• Ratio of peak load/forecast adjustments to
Maximum Emergency Service Level for M&V
• Retail rate contract eligibility
• Nodal pricing
• Balancing Operating Reserve deviation exemptions
©2010
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PRD Issues
1. PRD should be modeled as a price taker and
required to reduce in any instance when if not for
PRD, an emergency event would be called. (This
means that PRD load would be required to
interrupt prior to max emergency generation)
2. PRD business rules should place specific,
minimum requirements on the relationship
between retail rates and wholesale nodal prices:
o
o
©2010
When nodal LMP is > $120, the retail rate must be at
least 80 percent of nodal LMP
Nodal pricing of load is a significant change
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PRD Issues
3. Proposed actual/forecast load adjustment to
Maximum Emergency Service Level (MESL) in
compliance calculations inconsistent with
traditional Firm Service Level (FSL) approach.
4. Balancing Operating Reserve (BOR) deviation
charge exemptions should be limited to estimated
PRD values using submitted PRD curves and
nodal deviation calculations
©2010
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Emergency Event
• PJM proposal requires all PRD to be curtailed
when an emergency event is declared regardless
of price level and submitted PRD curves
• Real-Time LMP will be set by PRD curves even
though customer is required to be off the system
• Creates a disconnect between actual system
conditions and the wholesale price signal
• Results in a higher LMP than would occur if PRD
reduced load to avoid capacity obligation
independent of program (e.g. if DR participant)
• Does not consider scenarios in which customer or
LSE has incentive to drive up price
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MMU Position
• Capacity is procured with a reserve margin to
prevent reserve shortages and emergency events
for a given future delivery year
• PRD customers’ reductions are subtracted from
the load forecast such that neither capacity nor
reserves are procured for PRD load
• The subtraction of PRD load from load forecast
reduces the demand for capacity, reduces RPM
clearing price and displaces generating capacity
• PRD should be called to avoid and relieve
emergency events
• Price levels should reflect the absence of PRD
consumption when called to avoid emergencies
and throughout emergency events
©2010
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MMU Position
• Under normal system conditions, PRD is not
obligated to reduce but to make real time
consumption decisions based on LMP. No
penalties should be assessed unless PRD is
required to interrupt to avoid emergency
conditions.
• PRD represents a forward agreement by customers
to forgo consumption during system stress,
regardless of their economic real time demand
schedule.
• Energy Only price responsive customers can and
do affect price in emergency situations, which is
appropriate since capacity is procured for these
customers
©2010
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Rate Contract Eligibility
• PJM proposes that Price Responsive Demand
(PRD) be bid into the energy market daily, and
asserts that it will respond economically and
provide value to the system outside of an
emergency event
• No penalties are assessed by PJM outside of an
emergency event as PRD should by definition face
higher prices for consumption when LMP rises.
• The extent to which this is true depends on the
nature of the link between eligible retail rates and
wholesale price signals
©2010
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Current Business Rules
• PJM proposed criteria:
• “served under a dynamic retail rate structure that
can change on an hourly basis, that is linked to or
based upon a PJM real-time LMP trigger at an
electrical substation location… that results in
predictable response to varying wholesale
electricity prices”
• PJM proposed criteria are not adequate to
establish the required link between retail and
wholesale prices
• Under PJM proposed criteria, the following is
eligible:
• $20/MWh when nodal LMP is <=$999/MWh
• $21/MWh when nodal LMP is >=$1,000/MWh
©2010
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Retail and Wholesale Price Link
• Level of response is dependent upon the strength
of linkage between wholesale price and retail
price.
• Failure to adequately specify the link between
wholesale and retail prices will result in “capacity
only” type product, e.g. DR.
• For PRD, price signal should be directly
proportional to and within a percentage threshold
of nodal wholesale price signal
• Ideal retail price equals nodal wholesale price
• Any modifications should closely approximate this
ideal
©2010
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MMU Proposal
• Specify minimum conditions for qualifying
linkage between wholesale and retail prices:
• Nodal LMP ($/MWh) threshold above which there
must be dynamic and proportional changes in
retail price
• Floor percentage (%) of LMP that retail price must
reflect when LMP is above first threshold
• For example: when nodal LMP is > $ “X”/MWh,
retail rate must be “Y” percent of nodal LMP
• MMU suggest target of 5 percent of hours:
• When nodal LMP is greater than $120/MWh, the
retail rate must be at least 80 percent of nodal LMP.
• This allows for, but does not require, fixed rates at
lower price levels
©2010
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Adjustment to MESL
• PJM proposes adjustment to Maximum
Emergency Service Level (MESL) by the ratio of
actual load to forecast, to account for higher load
levels than forecasted
• Inconsistent with traditional FSL approach to
Measurement and Verification in which
commitment is to reduce to a certain value
regardless of actual to forecast ratio
• Product definitions have different implications:
• Adjusted MESL approach will ensure proportional
capacity charges to consumption ratio
• Unadjusted MESL approach provides greater
assurance of action taken and defined load in
capacity event
©2010
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Adjustment to MESL: Example
• Two identical LSEs in same zone, one with
registered PRD
LSE 1
Obligation (MW)
Registered PRD (MW)
Net Obligation
Final Capacity Price for DY ($/MW-Day)
Charges ($/MW-Year)
Credits ($/MW-Year)
Net Payments ($/MW-Year)
LSE 2
10
2
8
$20
$200
$40
$160
10
0
10
$20
$200
0
$200
• Actual peak load 25 percent higher than forecast:
©2010
Scenario 1: Adjusted MESL
Unrestricted Consumption (MW)
Adjusted MESL
PRD reduction (MW)
Capacity Consumption (MW)
Net Payments ($/MW-Year)
Effective Capacity Rate ($/MW-Day)
LSE 1
Scenario 2: Unadjusted MESL
Unrestricted Consumption (MW)
MESL
PRD reduction (MW)
Capacity Consumption (MW)
Net Payments ($/MW-Year)
Effective Capacity Rate ($/MW-Day)
LSE 1
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LSE 2
12.5
10 NA
2.5 NA
10
$160
$16.00
LSE 2
12.5
8 NA
4.5 NA
8
$160
$20.00
12.5
12.5
$200
$16.00
12.5
12.5
$200
$16.00
Underlying
Assumption
Adjustment to MESL: RPM Implications
• PJM proposal maintains a proportional
relationship between obligation and usage
between LSEs, under some assumptions.
• Unadjusted MESL provides a direct relationship
between capacity obligation and usage.
• In example, LSE 1 pays for 8 MW and reduces
usage to exactly 8 MW
©2010
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Adjustment to MESL: M&V Implications
• Assumption of PJM approach is that fixed portion
of PRD customer load will be higher than
obligation by the same proportion that actual load
is higher than forecast.
• Is this a valid assumption?
• Is it reasonable to assume that all load above
MESL is curtailable?
• To the extent that is not true, PRD customers
may be found compliant while taking little or
no actions in real time.
o
©2010
In example, if LSE 1 were already operating at 10
MW, consistent with PLC obligation, it would be
found compliant without reducing usage
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Adjustment to MESL: Example 2
Scenario 1: Adjusted MESL
Net Obligation
Actual / Forecast Adjustment
Unrestricted Consumption (MW)
Adjusted MESL
PRD reduction (MW)
Capacity Consumption (MW)
Net Payments ($/MW-Year)
Effective Capacity Rate ($/MW-Day)
LSE 1
Scenario 2: Unadjusted MESL
Net Obligation
Actual / Forecast Adjustment
Unrestricted Consumption (MW)
MESL
PRD reduction (MW)
Capacity Consumption (MW)
Net Payments ($/MW-Year)
Effective Capacity Rate ($/MW-Day)
LSE 1
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LSE 2
8
1.25
10
10 NA
0 NA
10
$160
$16.00
10
12.5
12.5
$200
$16.00
LSE 2
8
1.25
10
8 NA
2 NA
8
$160
$20.00
35
10
12.5
12.5
$200
$16.00
Unrestricted Load not
proportionally higher
than PLC
Balancing Operating Reserve Deviations
• Issue: PRD is to be bid into Day-Ahead Market,
but the retail rate of the end use customer must
be tied to Real-Time LMP
• If PRD clears unreduced quantity in Day-Ahead,
but Real-Time LMP is high enough to justify
response, that response is subject to a Balancing
Operating Reserve (BOR) Deviation charge
• PJM proposal exempts Load Serving Entities
(LSEs) with PRD for deviations from Day-Ahead
when Real-Time LMP is greater than Day-Ahead
LMP
• Intent of rule is to eliminate the disincentive to
respond in real time when committed Day-Ahead
©2010
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Balancing Operating Reserve Deviations
• PJM proposal does not estimate MW of PRD
included in BOR MW deviations, but exempts all
BOR deviation charges in any situation where
PRD may have caused the deviation
• Without a limit on exemption, LSEs with PRD will
see arbitrary exemptions and have an incentive to
overbid Price Sensitive Demand (PSD) in DayAhead
• Exemption should be limited to the amount of
PRD related MW deviation based on the
differential between Day Ahead and Real-Time
LMP at the pnode and the submitted PRD
schedule
©2010
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BOR Deviations: Example
• Nodal Day-Ahead LMP is $25/MWh but Real-Time LMP
is $30/MWh
• PRD is modeled at this node, and committed in Day
Ahead for full bid at $25/MWh. Based on submitted
PRD curve, price responsiveness starts at $50/MWh
• Under PJM proposed business rules, if load in real
time less cleared fixed Day-Ahead Load is less than
cleared Price Sensitive Demand (PSD), LSE will be
exempt from BOR deviation charges
• Actual lower load in real-time is due to factors other
than PRD
©2010
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2621 Van Buren Avenue
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Eagleville, PA
19403
(610) 271-8050
[email protected]
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