1. Retail Rate Options for
Small Customers
The California Statewide Pricing Pilot
Why? … What? … The Future?
The utility industry is renowned for its tendency to conduct pilots.
In almost 30 years of utility projects I’ve witnessed and participated in pilots to examine rates, metering, load control technologies, communications, marketing campaigns, customer education, information services - and their respective variations.
The California Statewide Pricing Pilot covered all of this and more.
Like many consultants and some of the wiser utility representatives I’ve worked with over the years – Pilots are frustrating.
As the principal consultant to the CEC I helped structure this pilot. I also suggested it was unnecessary.
They did it anyway.
Spent lots of money (over $20 million), wasted lots of time (over two years and climbing), collected lots of data and printed thousands of pages of nice reports.
One thing was different – Action items and decisions.
Levy Associates

2. Two Objectives 1
Summarize the most significant results from the California Statewide Pricing Pilot. 2
Identify how California is interpreting these results and what they mean for regulatory policy and demand response.
I have two objectives today.
Summary the most significant results. I won’t be reviewing the experimental design, sampling process, price elasticity's, technology evaluations, or each of the many different rate forms.
What I can tell you is that this was very likely the most sophisticated, complex and most expensive demand response / rate pilot ever conducted – anywhere.
I can also tell you that the results have been vetted and the results are considered representative and statistically significant.
Most significantly, I will describe how and why California is now using the results from this pilot to significantly reshape its energy policies and system operating procedures.
One qualifier:
While the intent is genuine, we are talking about (1) a regulatory environment and (2) California. Use the results accordingly.

3. Why ?
“ Why was there virtually no reduction in electricity peak demand from the customer side of the market when wholesale prices increased by a factor of five in less than a week in the summer of 2000? “ *
How do we solve outage management practices that exempt 50% of the utility customers?
How do you provide customers with the capability to better manage their electric bills and tailor reliability to their individual needs?
What can we do to turn demand response into a viable resource?
What motivated California to do a pricing pilot.
While I’ve listed four primary reasons on this slide, it really comes down to one key issue:
i)        At best DR programs can be best characterized as patches to compensate for poor and/or ineffective rate design.
If you examine the four items on this slide, they all have one they all have one common denominator – Pricing.
* CEC Action Plan, October 11, 2002

4. The Problems
DR programs can be best characterized as patches to compensate for poor or ineffective rate design.
Without basic price information customers do not have the capability to make rational investment or operating decisions.
Price
Rates
Customers don’t understand their electric rates.
PRICE – We present customers with rate forms they don’t understand with metrics that don’t reflect price or value.
PROGRAMS –
Energy efficiency requires technology or structural changes to facilities and appliances, but is ultimately dependent upon customer behavior to make it work or not work.
Demand response is dependent upon customer behavior yet we don’t provide the customer with technologies to support and automate their response.
Instead, Efficiency measures actually create barriers to Demand Response and program designs further inhibit customer participation.
What is needed is a new view of Demand Response, one that takes a customer perspective.
Electrical system problems require that technologies and procedures be in place and instantly available – they weren’t.
Programs

5. Statewide Pricing Pilot
Results

6. Critical Design Features
Approximately 2,500 participating customers.
CPUC, CEC and CPA cooperative regulatory proceeding.
Complex experimental design – statistically representative.
SCE, PG&E and SDG&E cooperative joint-venture pilot.
Revenue neutral rate designs.
Rate treatments: (1) TOU, (2) CPP-F, (3) CPP-V.
Technology and information treatments.

7. Conservation and Peak Load Impacts
SPP Conclusions
System Impacts
Residential CPP rates can, within five years of deployment reduce California’s peak load by 1,500 to over 3,000 mW.
Conservation and Peak Load Impacts
Dynamic rates encourage greater conservation and peak demand impacts than conventional inverted tier or time-of-use rates.
Customer Acceptance
Residential and small to medium commercial and industrial customers understand and overwhelmingly prefer dynamic rates to existing inverted tier rates.
Source: CEC staff conclusions based on review of collective SPP reports.

8. Percent Change In Peak Period Energy Use (CPP-F)
Residential Load Impacts (Weather)
Percent Change In Peak Period Energy Use (CPP-F)
-13.4
-12.5
-11.0
-16.0
-12.0
-17.1
-9.6
-8.4
1.0
-20
-15
-10 -5 5
Zone 1
Coastal
Zone 2
Inland
Zone 3
Inland Hot
Zone 4
Desert Hottest
Statewide
Average
% Change In kWh
Climate
Zone
CRA Econometric Model
CEC Engineering Method
Source: Statewide Pricing Pilot, Summer 2003 Impact Analysis, Charles Rivers Associates, August 9, 2004, Table 5-4

9. Percent Reduction in Peak Period Usage (CPP-F)
Residential Load Impacts (Demographics)
Percent Reduction in Peak Period Usage (CPP-F) 2 4 6 8 10 14 16 18 20
Percent Reduction 12
High vs. Low User
200% Average Use
50% Average Use
17.2%
9.79%
Central AC Ownership
YES NO
12.8%
12.3%
Pool Ownership
19.2%
12.1%
Income
> $100,000
< $40,000
15.1%
Single vs. Multi-Family
Single Family
Multi-family
13.5%
9.8%
State-wide Average
12.5%
Source: Statewide Pricing Pilot, Summer 2003 Impact Analysis, CRA, August 9, 2004, Table 5-9, p.90

10. Residential Load Impacts (Technology)
Critical Peak Impacts By Rate Treatment
Hottest Critical Peak Day *
Average Critical Peak Day
50%
47.4%
Critical Peak Variable With Automated Controls
40%
34.5%
Critical Peak Variable With
Automated Controls
30%
Peak Load Reduction
20%
12.5%
Critical Peak Fixed
10%
4.1%
TOU 0%
Time of Use TOU
CPP-F
CPP-V
CPP-V
Source: Statewide Pricing Pilot Summer 2003 Impact Analysis, Charles Rivers Associates, Table 1-3, 1-4, August 9, 2004.

11. Residential Load Impacts (Incentives)
Residential Response with Automation:
Participation Incentive vs. Critical Peak Rate
5.0
CPP Event
Critical Peak Rate
Participation Incentive
Control Group
4.5
4.0
3.5
3.0 kW
2.5
2.0
1.5
1.0
0.5
0.0
Noon
2:30
7:30
Midnight
Hot Day, August 15, 2003, Average Peak Temperature 88.50

12. Residential Load Impacts (Historical Results)
Two Tier TOU with
Dispatched
CPP
47.4%
Hottest Critical
Peak Day *
California Pilot 1
2003
Average Critical Peak Day 0%
10%
20%
30%
40%
50%
Peak Load Reduction
41.0%
Three Tier TOU with Dispatched CPP
35.0%
34.8%
34.5%
Three Tier TOU with Dispatched CPP
Three Tier TOU with Dispatched CPP
Two Tier TOU with
Dispatched
CPP
AEP Pilot 4
1991
Gulf Power Pilot 3
Midwest Pilot 2
2004
California Pilot 1
2003
Source:
Statewide Pricing Pilot Summer 2003 Impact Analysis, Charles River Associates, Table 1-3, 1-4, August 9, Hottest day impacts on page 105.
Private communication, residential TOU pilot study, May 2005.
Results of the Pilot Residential Advanced Energy Management System, Gulf Power, November 1994.
Levy Associates case study report, July 1994.

13. Small-Medium Commercial
Customer Bill Impacts (Actual)
Small-Medium Commercial
Residential
CPPV
CPPF
TOU
Participants (%)
71.1%
73.7%
70.0%
Average Monthly Savings (%)
5.1%
5.5%
4.5%
Average Monthly Savings ($)
$6.81
$3.89
$3.25
CPPV
TOU
80.3%
58.2%
12.2%
9.6%
$155.17
$90.65
Customers
With Bill
Savings
Participants (%)
28.9%
26.3%
30.0%
Average Monthly Increase (%)
4.0%
6.2%
3.0%
Average Monthly Increase ($)
$5.03
$4.93
$3.32
19.7%
41.8%
5.0%
10.0%
$22.89
$62.52
Customers
With Bill
Increases
summer / winter 2003
Source: Statewide Pricing Pilot, Shadow Bill Results, WG3 report, June 9, 2004.

14. Change in Average Monthly Customer Bill, July 2003 thru May 2004
Customer Bill Impacts (Actual by Utility)
Change in Average Monthly Customer Bill, July 2003 thru May 2004
TOU
CPP-F
CPP-V
SCE
PG&E
SDG&E 2 -2 -4 -6 -8
$0.18
-$4.15
-$5.86
-$2.60
-$2.10
-$1.76
$1.22
-$3.31
Average Monthly Bill Impact
<300
> 750
Average Monthly Usage (kWh)
Source: Response of Residential Customers to Critical Peak Pricing and Time-of-Use Rates during the Summer of 2003, September 13, 2004, CEC Analysis.

15. Rates Should be Offered to All Residential Customers
Residential Rate Preferences
Rates Should be Offered to All Residential Customers
Rate Group
CPP-V
CPP-F
TOU
88%
27% 20 10 40 50 60 70
61%
62%
57%
Percent Responding 30 80
25%
87%
30%
Definitely
Probably

16. Original Inverted Tier Rate
Customer Rate Preferences (Old vs. New)
Original Inverted Tier Rate
Pilot Rates
Residential
CPP-V
CPP-F
TOU
80%
81%
20%
23%
19%
Commercial
77%
71%
70% 20 40 60 80
30%
29%
Percent that Prefer
Source: SPP End-of-Summer Survey Report, Momentum Market Intelligence, WG3 Report, January 21, 2004, p23-24.

17. Translating the Results
Regulatory Policy and Improved Operating Practices

18. Demand Response – A Customer Perspective
The Customer Perspective
Customer Impact
Purpose of DR
Valuing DR
Advance Notice
Time Perspective
Full Outage
Full Outage Cost
Total Loss of Service
System Protection
0-6 hrs/yr 5
Entire facility outage.
None
End-Use Curtailment
Grid or System Protection 4
Loss of End-Use
Seconds or Less
Targeted end-use automatic curtailment brief period
2-10 hrs/yr
Reliability Responsive DR
Expected Value Partial Outage Cost
Voluntary Partial End-Use Curtailment
Reduced usage, increase temp settings or curtailments
Reliability and Economics 3
Some Comfort Impacts
Seconds to Hours
20-40 hrs/yr kW
Price Responsive DR
Shifting or Rescheduling 2
Load Shifting or Rescheduling
No Noticeable Impacts
Hours to Days
hrs/yr
Economics
kWh
Basic Service 1
None
None
Annual
years
Efficiency and Conservation
Customer Facility Envelope / Equipment
Control Systems
Interface
Customer facility, end-uses and operating practices define the infrastructure that form the foundation for all DR and efficiency options.
Efficiency and Demand Response are both part of the same continuum, differing only in time perspectives and valuation factors.

19. 1 2 3 Regulatory Proceedings – Policy Initiatives
Statewide implementation of advanced metering. 2
Critical Peak Pricing as the default tariff. 3
Programmable controllable thermostats in the Building and Appliance Standards.

20. Regulatory Proceedings – Policy Initiatives
Measure
Purpose
Statewide implementation of advanced metering.
Facilitate better pricing.
Support customer education. 1
Integrates efficiency and demand response on a common financial basis.
Demand response becomes a condition of service for all customers.
Critical Peak Pricing as the default tariff. 2
There are three elements that define a new customer perspective of DEMAND RESPONSE:
Advanced metering – a technology that facilitates data gathering and the ability to provide accountability
Pricing – rates that reflect cost in a way that is relatively simple yet responsive to the market and/or system conditions
Automation technology – to support customer choice, automate behavior and provide system management with reliability measures less onerous than full rotating outages.
When you have pricing that reflects cost, you provide the customer with the capability to establish value. The automation technology allows the customer to translate that value into behavior.
The automation technology also provides the system operator with the assurance that when the button is pushed, there will be a response. DEMAND RESPONSE then becomes a resource.
Enable / automate customer choice.
Economic response (CPP day ahead)
Reliability response (CPP day of)
Enable system protection and redefine outage management.
Programmable controllable thermostats in the Building and Appliance Standards. 3