Designing Capacity Markets
for D3 Resources
D3 Expert Stakeholder Workshop
3 March 2011
Chris Neme, Energy Futures Group
Paul Peterson, Synapse Energy Economics
3 March 2011
The Regulatory Assistance Project
48 Rue de Stassart
Building C, BE-1050
Brussels, Belgium
Phone: +32 2-894-9300
web: www.raponline.org
Presentation Overview
2
1.
2.
3.
4.
5.
6.
Emerging Resources
Capacity Market Design
Capacity Market Mechanics of Participation
Benefits & Challenges for D3
Capacity Market Results
Lessons learned
2
3
Introduction
Emerging Resources
3
D3 Resources as a Continuum
4
Energy
Efficiency
Load
Management
Demand
Response
Distributed
Generation
Renewables
4
D3 Resource Attributes
5
Passive or active
Aggregation or single site
Appropriate services/markets
– Capacity
– Ancillary
– Energy
5
6
Introduction
Capacity Market Designs
6
Goals (US experience):
7
• Reduce boom-bust cycle for historical capacity
prices
– Hobbes study of PJM and RPM
• Provide price signal for new investment to meet
system peak loads (not to balance increasing
renewables)
• Revenue substitute for “capped” energy market
• Capital contribution for marginal units (gas)
• Allow demand resources to compete
7
“Forward” Capacity Markets (FCM)
Examples: New England ISO and PJM
8
• Run by the system operator of the mandatory power
pools in each region (different market than UK)
– Peak demand forecasted in region for a future delivery
year (several years in advance)
– Resources bid on a “forward” basis—commit to being
available during peak demand periods (as forecasted) for
the delivery year
• Administrative auction; single price paid to all
– Existing and new resources submit bids and get paid the
single clearing price in the market (similar to energy-only)
8
New England ISO and PJM Territories
FCMs cover regions with installed
WA
generation capacity
on the order of:
MT
VT
ND
 About 1/4ORof the EU-27 member
ID
states combined installed
WY
capacity
MN
NH
WI
SD
NV
 The combined installed
UT
CO
generation
capacity
of Poland,
CA
Germany and Belgium
OH
IL
MO
VA
KY
MD
DC
NC
TN
AR
LEGEND
PJM territory - covers all or most of the state
NJ
DE
IN
WV
NM
ISO New England territory
CT
PA
IA
KS
MA
RI
NY
MI
NE
AZ
ME
SC
MS
TX
AL
GA
LA
FL
PJM territory - covers part of the state
9
Capacity Markets and D3 Resources
10
• Performance hours:
– Limited number of peak hours
– All peak hours in a season
– Year-round
• Measure and verify
– Prior to auction
– Prior to delivery period
– Post delivery period
• Comparable payment for comparable service
10
Other Types of Markets
11
ISO-NE Emergency Generation :
• Component of Forward Capacity Market
• Quantity is capped at 600 MW
• Originally 850 MW cleared
• Price pro-rated among the 850 MW
• Today, just over 600 MW
• May have application for UK target capacity payment
approach
11
Other Markets
12
ISO-NE Forward Reserves Market :
• Auction for “fast-start” resources (including demand
response)
– Ten-minute non-spinning reserves (TMNSR)
– Thirty-minute operating reserve (TMOR)
• Locational pricing as appropriate
• Initially under-subscribed in some zones
• Currently over-subscribed in all zones
• May have application for UK target capacity payment
12
13
Introduction
Capacity Market Participation
13
Requirements For Participating
14
• Qualifications package
– Peak capacity to be delivered
– Documentation of funding
– Added requirements for demand resources:
• Plans for “customer acquisition”
• Measurement and verification plans
• Length of commitment: 1 to 5 years
• Cost analysis
• Financial assurance
14
0
Month/Year
Jun-11
Apr-11
Feb-11
Dec-10
Construction
Period
Oct-10
Aug-10
Jun-10
Apr-10
Feb-10
Dec-09
Oct-09
Aug-09
Jun-09
Apr-09
Feb-09
Qualification
Period
Dec-08
Oct-08
Aug-08
Jun-08
Apr-08
Feb-08
Dec-07
40
Oct-07
Aug-07
10
Jun-07
20
Apr-07
Feb-07
MW
Time Line – New Generation
80
70
60
50
Auction #1
supply
30
MW
for
FCA#1
Delivery
Period
Time Line – Energy Efficiency
100
Construction
Period #3
90
Construction
Period #2
80
70
fca3
fca2
fca1
Auction #2
50
40
Auction #1
30
20
Construction
Period #1
Delivery
Period #1
Delivery
Period #2
10
0
Feb-07
Apr-07
Jun-07
Aug-07
Oct-07
Dec-07
Feb-08
Apr-08
Jun-08
Aug-08
Oct-08
Dec-08
Feb-09
Apr-09
Jun-09
Aug-09
Oct-09
Dec-09
Feb-10
Apr-10
Jun-10
Aug-10
Oct-10
Dec-10
Feb-11
Apr-11
Jun-11
Aug-11
Oct-11
Dec-11
Feb-12
Apr-12
Jun-12
MW
60
Auction #3
Month/Year
Challenges for D3
17
• Forecasting uncertainty
–
–
–
–
3 to 8 year lead time
Market changes could affect savings potential
Significant potential financial penalties
Revenues depend on volatile market
• Significant transaction costs
– Planning (qualifying)
– Measurement & verification
– Tracking & reporting
• Establishing ownership of resources
• Revenues not enough to support most measures
– Addresses only one benefit of D3
17
18
Introduction
Capacity Market Results
18
Good News about
Forward Capacity Markets:
 Addressed looming capacity shortages
(reason for FCMs in the first place)
 Recognise D3 as a reliability resource
 Impressive participation of D3
• D3 resources can perform reliably
• D3 participation reduces system costs
19
Demand-Side Results (ISO-NE)
Demand Resources Cleared
20
DR
FCA
MW
FCA 1
FCA 2
FCA 3
FCA 4
Net ICR*, MW
FCA Clearing Price, $/kW-Month
FCA Prorated Price, $/kW-Month
Net ICR*, MW
FCA Clearing Price, $/kW-Month
FCA Prorated Price, $/kW-Month
Net ICR*, MW
FCA Clearing Price, $/kW-Month
FCA Prorated Price, $/kW-Month
Net ICR*, MW
FCA Clearing Price, $/kW-Month
FCA Prorated Price, $/kW-Month
$
$
$
$
$
$
$
$
32,305
4.50
4.25
32,528
3.60
3.12
31,965
2.95
2.54
32,127
2.95
2.52
EE
% ICR MW
DG
% ICR MW % ICR
Total Demand
Resources
MW
% ICR
1,853 5.7%
655 2.0%
46
0.1%
2,554
7.9%
1,953 6.0%
890 2.7%
93
0.3%
2,937
9.0%
1,836 5.7%
975 3.0%
87
0.3%
2,898
9.1%
2,055 6.4%
1,167 3.6%
128
0.4%
3,349 10.4%
20
Capacity Markets Results
21
21
System Load vs. Forecast
Thunderstorms move
through South
Western CT
22
Real-Time DR Obligation and Performance by Load Zone
Load Zone
Total Net CSO
Average Aggregate
Performance*
Percent Net
CSO
(across 100% dispatch)
Connecticut
226.83
170
33.9
West Central Massachusetts
79.59
79
11.9
Northeast Massachusetts
70.74
46
10.6
Southeast Massachusetts
45.23
30
6.8
Rhode Island
27.76
27
4.1
Vermont
23.71
29
3.5
New Hampshire
29.11
33
4.4
Maine
166.22
239
24.8
669
653
100.0
New England
* Additional meter data corrections to address data quality issues will adjust the net
performance. The values noted above adjust for known problems and anomalies.
23
D3 Reduces Cost of Reliability
ISO-NE Calculation for a single year:*
– D3 reduced costs by ~$290 million
– Savings >15% of total cost
Note: substantial savings in PJM capacity auctions, too.
* FCA-1 Installed Capacity Requirement = 32,305 MW
– 2,554 MW of demand resources cleared
– Surplus of 2,047 MW at floor price of $4.50/kW-month
– Without D3, auction clears between $5.63 to $5.25
•
24
But There’s Bad News:
• Volatility (boom-bust) continues
• High transaction costs
– Qualification, financial assurance, M&V
• Over-supply leads to low prices that hurt
new resources and reward old resources
• Little evidence of new investments
– Some upgrades
– Resources with other revenue streams
• New investment voids price signal
• Following the money=carbon & windfalls
25
Capacity Markets Results
26
26
Cumulative PJM Capacity Revenues
($42 billion)
Other Renewables (Existing)
0.68%
Coal--Existing
Gas--Existing
Hydro-Existing
Other Renewables (Planned)
0.05%
Demand Resources
2.43%
Oil (Planned)
0.00%
Nuclear (Planned)
0.00%
Nuclear-Existing
Energy Efficiency Resources
0.07%
Oil (Existing)
8.14%
Oil-Existing
Demand Response
Coal (Existing)
30.01%
Nuclear (Existing)
21.06%
Hydro (Planned)
0.00%
Hydro (Existing)
4.91%
Coal (Planned)
0.16%
Gas (Planned)
0.66%
Gas (Existing)
31.83%
27
Source: Market Monitoring Analytics (PJM) Communications
27
28
Introduction
Lessons Learned
28
Broad Lessons
 D3 resources, including efficiency, can provide
capacity services--at reduced costs to the system
 US grid operators are experimenting with different
capacity markets
 Single-price capacity auctions
• have proven to be flawed in practice
• questionable value for a decarbonisation agenda
 More promise: targeted capacity payments for
specific system reliability resources you need
• can be competitive tenders, long-term
• “missing money” can be addressed, as needed
29
When Designing Capacity Payments…
30
• Target specific resource services
–
–
–
–
Balancing role*
Limited peak hours
Seasonal hours
24/7
• Include opportunities for D3 resources to compete
• Pay for entire life of D3 measures
• One-size payment does not fit all
– Need to reflect long-term needs
*‘Balancing’ refers to additional capacity requirements to ensure overall system security/reliability
—and not as this term is often used in the UK to refer to short-term, gate-closure balancing
30
…and Optimize Transaction Costs
31
• Clarity on rules at outset
– avoid making it up as you go
• Limited paperwork on planning/qualifying
• Balance system benefits with cost allocations
• Balanced measurement & verification
requirements
– must show resource performance
– value versus cost of increased precision
31
Capacity Markets Not Enough
32
• Address only one of several D3 benefits
• Need equivalent markets for T&D and energy
– Efficiency lowers system balancing/reliability costs
• Need markets for other fuel savings too
– Many D3 measures cost-effective only w/multi-fuel view
• Need to value carbon benefits in all markets, or
else…
– Only small fraction of cost-effective D3 will participate
– No foundation for deeper savings needed later
– Market skews demand in favor of “on-peak” D3
32
About RAP
The Regulatory Assistance Project (RAP) is a global, non-profit team of experts that
focuses on the long-term economic and environmental sustainability of the power
and natural gas sectors. RAP has deep expertise in regulatory and market policies
that:
 Promote economic efficiency
 Protect the environment
 Ensure system reliability
 Allocate system benefits fairly among all consumers
Learn more about RAP at www.raponline.org
Meg Gottstein, Principal
[email protected]; +1 209 304 5931 (mobile)
34
Introduction
Appendix:
additional slides
34
35
Introduction
Introductions
35
Energy Futures Group
36
Efficiency Expertise
Range of Clients
•
•
•
•
•
•
•
•
•
Policy Development
Program Design
Building Codes
Evaluation
Cost-Effectiveness
Government Agencies
NGOs
Regulators
Utilities
Clients in 15 states/provinces plus regional, national and
international organizations.
36
Synapse Energy Economics
37
Areas of Expertise
•
•
•
•
•
•
Range of Clients
Energy and Environment •
Electricity Markets
•
System Planning
Renewable Resources •
Greenhouse Gas Policy •
Utility Rates and Regulation
Federal, State and
Local Government
Advocates
NGOs
Foundations
Clients across the US and Canada and few utility clients.
37
Energy Efficiency Myths
38
•
•
•
•
Acquisition rate for EE decreases over time
Over time a saturation level is reached
There is a finite quantity of cost-effective EE
As penetration increases, cost-effectiveness
decreases (reverse is often true)
38
System Reliability Myths
39
•
•
•
•
Served load increases year to year
Served load is fixed and predictable
Electricity cannot be stored cost-effectively
GDP growth requires electricity growth
39
D3 Investment In U.S.
40
• Increasing rapidly
• Not just New England and California any more
• Impacts are measurable
– Policies and Trends (see extra slides)
But lots more to be done…
40
EE Results
Annual
Savings (%)
Year(s)
Source
Interstate Power & Light (MN)
Efficiency Vermont (VT)
Massachusetts Electric Co.
(MA)
2.6
2.5
2006
2008
Garvey, E. 2007. “Minnesota’s Demand Efficiency
Program”
Efficiency Vermont 2009. 2008 Highlights
2.0
2006
Pacific Gas & Electric (CA)
1.9
2008
Minnesota Power (MN)
Puget Sound Energy (WA)
1.9
1.4
2005
2007
Connecticut IOUs (CT)
Pacific Corp (ID & WA)
Energy Trust of Oregon (OR)
Southern California Edison
(CA)
Avista Corp (ID, WA, MT)
Idaho Power Co (ID)
San Diego Gas & Electric (CA)
PUD No 1 of Snohomish (WA)
1.3
1.3
1.3
2006
2007
2005
1.2
1.1
1.1
1.1
1.0
2008
2005
2007
2008
2007
Otter Trail (MN)
Seattle City Light (WA)
MidAmerican (IA)
0.9
0.9
0.9
2005
2007
2008
Entity
41
EIA 861
CPUC 2009. Energy Efficiency Verification Reports
issued on February 5, 2009 and October 15, 2009
Garvey, E. 2007. “Minnesota’s Demand Efficiency
Program”
Northwest Power and Conservation Council
CT Energy Conservation Management Board
(ECMB). 2007
Northwest Power and Conservation Council
Northwest Power and Conservation Council
CPUC 2009
Northwest Power and Conservation Council
Northwest Power and Conservation Council
CPUC 2009
Northwest Power and Conservation Council
Garvey, E. 2007. “Minnesota’s Demand Efficiency
Program”
Northwest Power and Conservation Council
Iowa Utilities Board 2006
41
States w/EEPS
42
Source: ACEEE, State Energy Efficiency Resource Standard Fact Sheet, Updated December 2010
42
U.S. Ratepayer Spending on EE
43
Source: ACEEE, 2010 State Energy Efficiency Scorecard
43
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
Net Energy for Load, GWh
Changes in Energy Growth
New England Weather Normal Net Energy for Load, 1981-2010
44
140000
130000
120000
110000
100000
90000
80000
NEL
44
Review of 22 EE studies
45
45
Long-Term Impacts
46
46
System Planning
47
Accounting for D3 resources
– Load forecasts
– Capacity forecasts
– Resource forecasts
– Others
47
48
Forward Capacity Markets:
Treatment of Energy Efficiency
ISO-NE
PJM
• Payment for
measure life
• No reconstitution of
D3 loads
• M&V Manual
• Pre-auction screen
• Delivery year verify
• Payment for max of
four years
• No reconstitution of
D3 loads
• M&V Manual
• Pre-auction screen
• Delivery year verify
48
Descending Clock Auction
Supply available (MW) at end of
round
Final Results of ISO-NE FCM Auction #1
40,000
Start at
$15.00
Yellow boxes
show end-ofround price
39,000
38,000
37,000
$9.00
$8.00
$7.00
$6.00
$5.625
$5.25
$4.875
$4.50
6
7
Close
36,000
35,000
34,000
33,000
32,000
Final Capacity Needed (ICR)
31,000
30,000
Start
1
2
3
Round
4
5
Lifetime Revenues by Measure
140%
Rebate: $40
FCM Revenue: $47
120%
100%
80%
60%
Rebate: $2
FCM Revenue: $1
40%
Rebate: $40
FCM Revenue: $8
Rebate: $20
FCM Revenue: $3
20%
0%
Residential
CFL
Commercial
Lighting
Efficient Room
A/C
Efficient
Refrigerator
51
Introduction
Benefits & Challenges for D3
51
Notes for PJM Forward Capacity
Market Revenues:
• All PJM revenues for all auctions for the
2007/2008 Delivery Year through the 2013/2014
Delivery Year
– Total revenue = $42.1 billion
• Planned resources are new units that did not
previously exist
• Existing resources are existing units and any
modifications to existing resources
• DR resources are demand side capacity resources.
• EE resources are energy efficiency resources.
52
Benefits for D3
53
• Recognition as viable & equivalent alternative
– Could lead to other needed policy reforms
• Substantial new source of revenue
53
LSEs all install same percentage
Illustrative Values for Power Year 2011-2012
Installed Capacity Requirement (MW)
36,750 (summer 2010 peak load x 1.5% growth x 15% reserve margin)
Capacity Clearing Price ($/kWh)
$
6.05
Total Cost of Capacity ($m)
$
2,668
Reconsituted Load
LSE
NU
UI
NGrid
NStar
VELCO
PSNH
CMP/BH
MA Munis
CT Munis
Totals
Summer
2010 Peak
Load (MW)
7,000
1,500
9,000
4,500
1,300
1,800
4,000
1,200
1,200
31,500
% EE
0.5%
0.5%
0.5%
0.5%
0.5%
0.5%
0.5%
0.5%
0.5%
EE
(MW)
35
8
45
22
7
9
20
6
6
158
Delta
Metered Load
Peak Load
Peak Load
Peak Load
Ratio Capacity
Ratio Capacity
Ratio Capacity
Share Cost ($m)
Share Cost ($m)
Share Cost ($m)
22.22%
4.76%
28.57%
14.28%
4.13%
5.71%
12.70%
3.81%
3.81%
592.89
127.09
762.29
381.10
110.15
152.46
338.79
101.64
101.64
22.22%
4.76%
28.57%
14.29%
4.13%
5.71%
12.70%
3.81%
3.81%
592.90
127.05
762.30
381.15
110.11
152.46
338.80
101.64
101.64
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.01
(0.04)
0.01
0.05
(0.04)
0.00
0.01
0.00
0.00
100%
2,668
100%
2,668
0%
0.00
Capacity
Cost (%)
0.00%
-0.03%
0.00%
0.01%
-0.04%
0.00%
0.00%
0.00%
0.00%
54
LSEs install varying percentages
Illustrative Values for Power Year 2011-2012
Installed Capacity Requirement (MW)
36,750 (summer 2010 peak load x 1.5% growth x 15% reserve margin)
Capacity Clearing Price ($/kWh)
$
6.05 without EE
$
6.00 with EE
Total Cost of Capacity ($m)
$ 2,668 without EE
$ 2,646 with EE
Reconsituted Load
LSE
NU
UI
NGrid
NStar
VELCO
PSNH
CMP/BH
MA Munis
CT Munis
Totals
Summer
2010 Peak
Load (MW)
7,000
1,500
9,000
4,500
1,300
1,800
4,000
1,200
1,200
31,500
% EE
0.6%
0.5%
0.5%
0.5%
0.8%
0.3%
0.4%
0.1%
0.2%
Metered Load
Delta
Peak Load
Peak Load
Capacity
EE
Ratio
Ratio Capacity Capacity
(MW)
Share Cost ($m)
Share Cost ($m) Cost ($m)
42
8
45
22
10
5
16
1
2
151
22.25%
4.76%
28.58%
14.29%
4.14%
5.70%
12.69%
3.79%
3.80%
593.61
127.12
762.46
381.19
110.43
152.15
338.53
101.24
101.32
22.22%
4.76%
28.57%
14.29%
4.13%
5.71%
12.70%
3.81%
3.81%
592.90
127.05
762.30
381.15
110.11
152.46
338.80
101.64
101.64
(0.71)
(0.07)
(0.16)
(0.04)
(0.32)
0.31
0.27
0.40
0.32
100%
2,668
100%
2,668
(0.00)
5 Cent Impact
Capacity Capacity
Cost (%) Cost ($m)
-0.12%
-0.05%
-0.02%
-0.01%
-0.29%
0.20%
0.08%
0.40%
0.31%
(4.90)
(1.05)
(6.30)
(3.15)
(0.91)
(1.26)
(2.80)
(0.84)
(0.84)
Capacity
Cost (%)
-0.83%
-0.83%
-0.83%
-0.83%
-0.83%
-0.83%
-0.83%
-0.83%
-0.83%
(22.05)
55
System Load vs. Forecast
Thunderstorms move
through South
Western CT
56
Operating Reserves 1300 to
1800
57
Observations
• System Operators performed well under multiple events
• New Control Room Software, Hardware and Business Processes for
FCM and DRI worked well including data and voice
communications
• Virtually all facets of dispatch and auditing demand has been
exercised in the first month of operations
• Training materials at the following locations are helpful for the DDE
System Operators to understand system conditions and operational
expectations
http://www.isone.com/support/training/courses/oper_train/drot_101_may_2010.pdf
http://www.iso-ne.com/support/training/courses/dalrp/arat-dr_april_2010.pdf
58