Transcript Slide 1

Demand Resources: Challenges and
New Initiatives for ISO New England
Henry Yoshimura, ISO New England
NEW DEMAND RESPONSE PRODUCTS IN ELECTRICITY
MARKETS
Cornell University
January 17, 2011
Demand Resources in New England
• Overall Goal:
– Integrate Demand Resources into capacity, energy, and ancillary
services markets in an efficient manner
• Today:
– Demand Resources can sell load reduction capability in the
Forward Capacity Market and receive payments comparable to
generation resources
• About 2,300 MW of Demand Resources in FCM today
• Almost 3,300 MW of Demand Resources expected by 2013
– ISO-NE has invested in metering and communication infrastructure
to integrate demand response resource information into the systems
that monitor the electricity grid and dispatches resources
– Opportunities for customers to purchase electricity at wholesale
energy prices and participate in Ancillary Services Markets
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Demand Resources Growing in New England
Enrollment in ISO programs prior to start of FCM
FCM 
2010/11–2013/14: Total DR cleared in FCAs 1–4 (New and Existing); Real-Time Emergency Generation capped at 600 MW.
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Challenges to the Integration of Demand
Resources into Wholesale Markets
• Competing business models
– A supply of generation
– A consumer of generation
• Economic issues
– Compensation and price formation
– Baseline
– Cost allocation
• Structural issues
–
–
–
–
Legal issues – conflicts in policy and jurisdiction
Lack of linkage between retail rates and wholesale prices
Lack of advanced metering infrastructure in the retail space
Lack of enabling technology
DRAFT
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Achieving Price Responsive Demand Through
Dynamic Retail Pricing
• Price-Responsive Demand (PRD) means customers
change their electricity use in response to time-varying
wholesale prices
• Over time, PRD:
– Improves economic efficiency of wholesale market
– Lowers average prices and total customer bills
– Promotes customer choice
– Stimulates investment in smart grid technologies such as
advanced metering, load control, load shifting, and energy
storage technologies
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AMI Penetration by Region as of 2008
New England States
included in NPCC
*From Graph II-3, “FERC 2008 Assessment of
Demand Response and Advanced Metering.”
Includes US data only.
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Efforts to Integrate Demand Resources into the
Energy and Ancillary Services Markets
• October 2008, ISO started a region-wide stakeholder process
to determine the best way to encourage more PriceResponsive Demand (PRD) in the Energy Market
– Over the past 2 years there have been many stakeholder meetings on
this topic
– Strong disagreement expressed on the issue of compensation
• Demand response: is it supply or demand?
• March 2010, FERC issued Notice of Proposed Rule Making
– FERC’s goal is to establish a national policy on the appropriate payment
rate for demand response participating in energy markets
– Final order pending
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FERC NOPR on Demand Response
Compensation, March 2010
• The FERC proposed that demand response reducing
electricity consumption from expected levels in response to
price signals should be paid, in all hours, the market price for
energy – i.e., the full LMP – for such reductions
• This raises a host of issues:
– Economic efficiency
– Competitive/comparability issues
– Legal (entitlement)
– Baseline estimation
– Cost allocation
• Does not fully reward economic load shifting (e.g., energy
storage) or off-peak usage (e.g., plug-in electric vehicles)
© 2010 ISO New England Inc.
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New Initiatives: Revising the Capacity
Cost Allocation Method
Present Capacity Cost Allocation Method
• Market Participants pay the cost associated with the
Installed Capacity Requirement (“ICR”) based on their
share of total consumption in the single hour of the
annual system coincident peak from the previous year
– System peak only known after the fact
– Difficult to make the case for retail products that promote PRD
• Analysis by the ISO shows that reducing loads in just the
peak hour has little effect on ICR
– Poor linkage between consumption and cost
• ICR is a function of LOLPs across many hours, which is
a function of the peak load forecast distribution and
expected supply availability
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Findings From Analyses Conducted by the ISO
• Reducing daily peaks in the eight-week period during the months of
July and August has the greatest impact on ICR
– More recent analysis by the ISO in response to feedback showed that the impact of
reducing peak loads on the 15 highest load days in July and August was largely the
same as reducing peak loads on all business days in July and August
• Reduced consumption during a six-hour period between 12:00 and
18:00 on summer non-holiday weekday afternoons has the greatest
impact on loss of load probabilities and ICR
– Accommodates significant load reduction without creating new peaks at the border of
the period
• Periodic review is needed, especially if customer response becomes
strong over time
• Research suggests that retail customers are willing and able to actively
reduce load for up to 20 days without causing “customer fatigue”
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ICR is a Function of Observed Peak Loads from
Week-to-Week and Year-to-Year
Change in ICR vs. Number of Weeks of Daily Peak Load
Reduction
0
0.0000%
1
2
3
4
5
6
7
8
9
10
-500
-20.0000%
-1000
-40.0000%
-1500
-60.0000%
-2000
-80.0000%
-2500
-100.0000%
-3000
Number of Weeks that Peak Reductions Occur
Summed LOLPs over weeks of reduction
MW ICR Change
0
2%Delta, 5yrs
5%Delta, 3yrs
5%Delta, 5yrs
Summed LOLPs
-120.0000%
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Effect on ICR From Reductions Only During Peak
Days, July 1st through Aug 31st, for 5 years
Reducing consumption during the top 15 peak days in July/August had a
similar impact as reducing consumption on all 40 business days in July/August
Effect of Reducing Daily Peaks Upon 2013 ICR
0
0
5
10
15
20
25
-500
MW ICR Change
-1000
5% Delta, 5 years
-1500
2% Delta, 5 years
-2000
-2500
-3000
Number of Peak Days Affected
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Redefining the Daily Peak Period
A six-hour window captures the full impact of a 5% load reduction
Average Load Profile of Top 15 Peak Days, Summer 2006
Hourly Window HE 13-18 (6 hrs)
25500
25000
24500
MW of Daily Load
24000
23500
Top 15 avg
23000
2% reduction top 15
3% reduction top 15
22500
5% reduction top 15
22000
21500
21000
0
5
10
15
20
25
30
Hour Ending
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Elements of a Revised Approach
1. Allocate costs based on a load’s share of total system
consumption during multiple hours that affect the ICR
most directly
2. Specify the hours to be used in determining Peak
Contribution values before the start of each Capability
Year
–
Periodic analysis conducted to determine if the hours or the period
need to change in future years
3. Bill capacity costs using new capacity allocators as soon
as the numbers are available rather than waiting until
the following year
–
Load-serving entities have indicated that this change will present
challenges given the current retail contracting cycle
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New Initiatives: Real-Time Energy and
Reserves Pilot Program
Background: Demand Response
Reserves Pilot Program (“DRRP”)
• DRRP ran from October 2006 to May 2010
• DRRP objectives:
– Test the ability of smaller demand response resources to
respond to ISO dispatch instructions in a manner similar to
resources providing Operating Reserve
– Performance was assessed by measuring how quickly and
consistently participating assets were able to reduce load relative
to the quantity of interruptible capacity enrolled in the DRRP
• Results of the DRRP evaluation study by KEMA
Consulting was presented to the Markets Committee on
December 8, 2010
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10/06/2006
10/30/2006
12/06/2006
01/16/2007
02/15/2007
03/06/2007
03/22/2007
04/13/2007
04/26/2007
05/30/2007
06/08/2007
06/22/2007
07/05/2007
07/25/2007
08/07/2007
08/13/2007
08/15/2007
09/05/2007
09/26/2007
11/06/2007
11/29/2007
12/28/2007
01/22/2008
02/29/2008
03/26/2008
04/17/2008
05/01/2008
06/12/2008
06/23/2008
07/02/2008
07/16/2008
07/28/2008
08/12/2008
09/02/2008
09/17/2008
06/03/2009
06/08/2009
06/25/2009
07/08/2009
07/17/2009
08/07/2009
08/17/2009
08/28/2009
09/10/2009
10/07/2009
11/02/2009
12/07/2009
01/15/2010
02/16/2010
03/05/2010
03/22/2010
04/13/2010
04/27/2010
05/17/2010
Total DR Performance (From KEMA Study)
180%
160%
140%
120%
100%
80%
60%
40%
20%
0%
Total Load Relief as Percent of DRR Contract Amount (Mean MW)
Session Average
Linear Trend
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Observations and Conclusions From the
Demand Response Reserves Pilot
• Participation was limited – pilot never reached 50 MW
(average participation was 26.4 MW per session)
• Response to dispatch instructions was statistically
significant, but highly variable
• On average, certain demand response asset groupings
substantially under-performed while others substantially
over-performed
• The drivers of under- or over-performance are not
completely clear at this time
• These results indicate that further research and
development is needed for demand response to become
a dispatchable energy and reserve resource
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Design and Implement a Real-Time
Energy and Reserves Pilot Program
• Overall Goal:
Improve the reliability and efficiency of the bulk
power system by presenting an opportunity for
alternative resources to provide energy and
reserve products to the wholesale market
– Alternative resources include installed measures (i.e.,
equipment, systems, services, practices and/or
strategies) that are otherwise not able to participate in
energy or reserve markets as a supply-side resource
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How Could the New Pilot Improve Upon
the Old Pilot?
Old DRR Pilot
New RTER Pilot
Reserves only
Could include energy and reserves
Participating assets consisted of
individual facilities
Participating assets could consist of
aggregations of facilities
Random dispatch
Dispatch could be priced-based
No offer curve – Market Participants
provided a single load reduction
quantity per asset
Market Participant could submit an
offer curve consisting of multiple load
reduction increments per asset
ISO calculated baseline forecast
Market Participant could submit the
baseline forecast
Dispatch instruction was “reduce load
at this time”
Dispatch instruction could be
“consume this amount at this time”
Payment based on the difference
between actual load and the baseline
Payment could be based on ability to
follow dispatch instructions