Post on 18-Jan-2016
The State of Demand Response in California
Ahmad Faruqui, Ph.D.
Principal
June 13, 2007
2Privileged and ConfidentialPrepared at the Request of Counsel
The top 1 percent of the hours account for more than 10 percent of the peak load in the state
2004 Load Duration Curve for California IOUs
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
0
500
1,00
0
1,50
0
2,00
0
2,50
0
3,00
0
3,50
0
4,00
0
4,50
0
5,00
0
5,50
0
6,00
0
6,50
0
7,00
0
7,50
0
8,00
0
8,50
0
Hours (Sorted from Highest to Lowest)
Co
inci
den
t H
ou
rly
Dem
and
of
CA
IO
Us
(MW
)
Coincident peak demand = 41,811 MW
1% of hours greater than 37,296 MW
5% of hours greater than 33,026 MW
3Privileged and ConfidentialPrepared at the Request of Counsel
California Faces a Deficit in its Demand Response
Policy
4Privileged and ConfidentialPrepared at the Request of Counsel
Utility price-responsive programs are expected to fall short of this year’s goal of 5 percent
2007 Expected Peak Demand
(MW)
Peak Reduction (MW)
Reduction as % of Peak
PG&E 19,440 588 3.0%
SCE 23,124 373 1.6%
SDG&E 4,450 96 2.2%
Total 47,014 1,057 2.2%
Total Anticipated DR from Price Responsive Programs (2007)
Sources: IOU Reports on Interruptible Load Programs and Demand Response Programs for January 2007; CEC, “Staff Forecast of 2007 Peak Demand,” June 2006
5Privileged and ConfidentialPrepared at the Request of Counsel
However, interruptible programs are expected to provide an additional 3.4 percent of peak demand reduction
2007 Expected Peak Demand
(MW)
Peak Reduction (MW)
Reduction as % of Peak
PG&E 19,440 314 1.6%
SCE 23,124 1,204 5.2%
SDG&E 4,450 95 2.1%
Total 47,014 1,613 3.4%
Total Anticipated DR from Interruptible Programs (2007)
Sources: IOU Reports on Interruptible Load Programs and Demand Response Programs for January 2007; CEC, “Staff Forecast of 2007 Peak Demand,” June 2006
6Privileged and ConfidentialPrepared at the Request of Counsel
Price-based programs empower customers to choose the level of risk that best suits them
Flat Rate
TOU
RTP
CPP-F
Consumer Risk
Supplier Risk
Seasonal Rate
CPP-V
VPP
7Privileged and ConfidentialPrepared at the Request of Counsel
How much additional DR can California achieve from price-responsive programs?
• Technical potential► Measures the outcome if all customers used the best
available DR technology
• Economic potential► Measures the outcome if all customers used a cost-
effective combination of technologies
• Market potential► Measures the outcome if a cost-effective combination
of technologies is accepted by a reasonable number of customers in the market place
8Privileged and ConfidentialPrepared at the Request of Counsel
The technical potential for DR in California is around 25 percent of peak demand
Assumptions• Full statewide deployment of AMI• 100% participation• Peak demand allocation by sector
► 41% residential, 41% commercial, 18% industrial
• All residential customers use gateway system ► 43% peak demand reduction per customer
• All commercial and industrial customers use Automated DR► 13% peak demand reduction per customer
Technical potential = 25% peak demand reduction
9Privileged and ConfidentialPrepared at the Request of Counsel
The economic potential for DR is around 12 percent of peak demand
Customers use a cost-effective mix of enabling technologies
Residential• 10% have gateway system• 20% have smart thermostat• 70% have no enabling technology• 19% weighted average peak demand reduction
Commercial• 10% have Automated DR• 30% have smart thermostat• 60% have no enabling technology• 7% weighted average peak demand reduction
Industrial• 40% have Automated DR• 60% have no enabling technology• 9% weighted average peak demand reduction
Economic potential = 12 percent peak demand reduction
10Privileged and ConfidentialPrepared at the Request of Counsel
The market potential for DR is around 5 percent of peak demand
• Customers use same cost-effective mix of enabling technologies
• 40% participation rate in all sectors► Falls between 20% estimate for opt-in rate and 80%
estimate for opt-out rate
Market potential = 5 percent peak demand reduction
11Privileged and ConfidentialPrepared at the Request of Counsel
A 5 percent peak demand reduction would provide three types of benefit
• Avoided generation capacity cost► Over 3,000 MW of avoided peak demand, or 50 combustion turbines► Cost of new capacity = $52/kW-year► $200 million in avoided costs per year
• Avoided electricity generation cost► Reduced electricity generation during peak► $20 million in avoided costs per year*
• Avoided transmission & distribution capacity cost► 10% of avoided generation capacity and energy costs► $20 million in avoided costs per year
*Using relationship observed in a recent PJM analysis of demand response
12Privileged and ConfidentialPrepared at the Request of Counsel
Even a 5 percent peak demand reduction would save $240 million per year or $3 billion over 20 years
T&D Capacity:$22 Million, 9%
Energy:$24 Million, 10%
Generation Capacity:
$197 Million, 81%
Annual Financial Benefits of 5% Peak Demand Reduction
13Privileged and ConfidentialPrepared at the Request of Counsel
Stakeholder interviews identified 14 barriers to the achievement of the state’s DR potential
1. Assembly Bill 1X (rate freeze on first two tiers)2. Lack of AMI penetration for customers < 200 kW (being remedied)3. Lack of cost-effective enabling technology4. Lack of consumer interest5. Ineffective program design6. Utility fear of not recovering costs7. Fear of customer backlash8. Confusion with energy efficiency programs9. Concerns about adverse environmental impacts10. Lack of retail competition11. Low capacity and energy prices12. No recent blackouts13. Complicated state-federal coordination issues14. Lack of a wholesale power market
14Privileged and ConfidentialPrepared at the Request of Counsel
The barriers can be grouped into two areas
• Dynamic pricing ► Develop better and more innovative rate designs► Resolve AB 1X complications► Develop realistic goals for DR► Modify existing cost-benefit methodologies for demand-side
programs► Educate customers about the benefits of time-varying and
dynamic rates
• Technology ► Install AMI► Equip customers with enabling technologies► Design rates with understanding of response that customers
are able to provide
15Privileged and ConfidentialPrepared at the Request of Counsel
The best way to overcome these barriers may be through instituting new load management standards
• The Energy Commission pioneered load management standards in the late 1970s
• These were intended to reduce peak demand by 7 percent and enjoyed a certain amount of success
• The Energy Commission’s Title 20 and 24 standards have contributed half of the efficiency gain that has been observed over the past three decades
16Privileged and ConfidentialPrepared at the Request of Counsel
Back to the Future!
17Privileged and ConfidentialPrepared at the Request of Counsel
In 1978, the Energy Commission proposed four load management standards
• Load control standard• Swimming pool filter pump standard• Non-residential (commercial) standard• Load management tariff standard
18Privileged and ConfidentialPrepared at the Request of Counsel
The impact of the load management standards
• Slow initial response to the standards• Two workshops were held to facilitate program
development in 1979► Load management technology► Improving customer participation
• Report from Governor’s Energy Conservation Task Force reinforced need for immediate response in January 1980
19Privileged and ConfidentialPrepared at the Request of Counsel
The impact (concluded)
• Utilities responded and California survived low capacity margins of the early 1980s
• Two programs produced lasting impacts► TOU rates exist for customers above 500 kW of demand
(lowered to 200 kW after the Western Energy Crisis)► Residential load control programs at some utilities
20Privileged and ConfidentialPrepared at the Request of Counsel
Reasons for limited success
• Advisory nature► The Energy Commission does not have independent
authority to enforce the standards, as it does with the appliance and building standards (Titles 20 and 24)
• Administrative constraints► Programs must be approved by both commissions and
today may additionally require involvement of CAISO
• Technological issues► Technical challenges with the pool pump timers;
required significant manual efforts by user
21Privileged and ConfidentialPrepared at the Request of Counsel
Reasons (concluded)
• Voluntary participation► With exception of mandatory TOU rates, the standards
did not require default participation
• Private market for DR did not exist► Programs remained under control of utilities; little
private sector involvement and innovation
• Cyclical nature of capacity shortages► Eventual capacity surplus in the state shifted the focus
away from load management
22Privileged and ConfidentialPrepared at the Request of Counsel
Load Management II
23Privileged and ConfidentialPrepared at the Request of Counsel
The state is now reconsidering the imposition of load management standards
• They are likely to be centered around three pillars• Dynamic pricing standard
► Default dynamic pricing tariff for all customers
• Programmable Communicating Thermostat (PCT) standard
► PCTs for all residential customers
• Automated Demand Response standard► Automated DR for all C&I customers
24Privileged and ConfidentialPrepared at the Request of Counsel
Without the standards, a 2.5% peak reduction might be achieved, representing over $1 billion in the next 20 years
Assumptions• Same methodology described in morning presentation• Statewide deployment of AMI• Voluntary (opt-in) dynamic pricing is offered by the three IOUs
► 20 percent participation rate
• Most customers are not equipped with enabling technologies such as PCTs
Result• 2.5% peak reduction• Financial benefits of over $1 billion in the next 20 years
25Privileged and ConfidentialPrepared at the Request of Counsel
With the adoption of a dynamic pricing standard, the peak reduction could increase by 7 percentage points and benefits could rise by $4 billion
Assumptions• Default pricing is made the default tariff for all
customer classes• 80 percent of customers stay on the default tariff, 20
percent opt back to their old tariff• No enabling technologies are offered to customers
Result• Additional 7 percent peak demand reduction• Incremental financial benefits of $4 billion
26Privileged and ConfidentialPrepared at the Request of Counsel
The adoption of a PCT standard could increase the peak reduction by 8 percentage points and raise financial benefits by some $5 billion
Assumptions• The dynamic pricing standard is in place• All residential customers are equipped with a PCT• The average peak reduction for residential
customers with a PCT is 27%
Result• Additional 8 percent demand reduction overall• Incremental financial benefits of $5 billion
27Privileged and ConfidentialPrepared at the Request of Counsel
The further adoption of an Automated DR standard could increase the peak reduction by 2 percentage points and raise financial benefits by $1 billion
Assumptions• Dynamic pricing standard and PCT standard are in
place• All C&I customers are equipped with system-wide
automation for managing multiple end uses• The average peak demand reduction for a customer
equipped with this technology is 13 percent
Results• Additional 2 percent peak demand reduction• $1 billion in incremental financial benefits
28Privileged and ConfidentialPrepared at the Request of Counsel
The incremental benefit of all three is nearly an 18 percent peak demand reduction, representing an additional $10 billion in financial benefits
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
VoluntaryDynamic Pricing
Dynamic PricingStandard
PCT+ Standard
Automated DRStandard
TotalBenefit
Pre
sen
t V
alu
e o
f In
crem
enta
l B
enef
it (
$ B
illi
on
s)
$1.4 Billion,2.5% Reduction
$4.2 Billion,7.4% Reduction
$4.5 Billion,7.9% Reduction
$1.3 Billion,2.4% Reduction
$11.4 Billion,20.2% Reduction
Wit
h S
tan
dar
ds
29Privileged and ConfidentialPrepared at the Request of Counsel
After adjusting the calculation of the benefits of the PCT standard, the incremental peak reduction is still over 12%, representing an additional $7 billion
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
10.0
VoluntaryDynamic Pricing
Dynamic PricingStandard
PCT Standard
Automated DRStandard
TotalBenefit
Pre
sen
t V
alu
e o
f In
crem
enta
l B
enef
it (
$ B
illi
on
s)
$1.4 Billion,2.5% Reduction
$4.2 Billion,7.4% Reduction
$1.5 Billion,2.7% Reduction
$1.3 Billion,2.4% Reduction
$8.5 Billion,15% Reduction
Wit
h S
tan
dar
ds
30Privileged and ConfidentialPrepared at the Request of Counsel
Conclusions
• California’s earlier experience with load management standards was successful
► Stimulated discussion about ways to reduce peak load► Produced programs that are still effective today
• The state has had much success with building and appliance standards
• Load management standards are being revisited• The three strawman proposals present a compelling picture of
the benefits that might be derived by pursuing the CEC’s load management standard-setting authority
► Focus on dynamic pricing and enabling technologies► Day-ahead and day-of deployment► Enhance the role of pricing mechanisms for managing demand
and supply► Decrease the role of cash incentives
31Privileged and ConfidentialPrepared at the Request of Counsel
Contact information
Ahmad Faruqui, Ph. D.Principal
The Brattle Group353 Sacramento Street, Suite 1140San Francisco, CA 94111Voice: 415.217.1026Fax: 415.217.1099Cell: 925.408.0149
Email: Ahmad.Faruqui@Brattle.Com