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

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500

1,00

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1,50

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2,00

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2,50

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3,50

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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