prepared by: roger levy; levy associates 1 uscl corporation california spp results initiative on...

Prepared by:

Roger Levy; Levy Associates

1

USCLCorporation

California SPP ResultsInitiative on Demand Pricing and Critical Peak Pricing

July 2004

USCLCorporation

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USCLCorporation

•Residential and Commercial / Industrial customers don't understand their current rates.

•Both groups overwhelmingly prefer the Critical Peak rates to their existing rates.

•Both groups respond to these rates with substantial peak load reductions

•Both groups respond to these rates with reduced overall energy use.

•A majority (roughly 80%) of all customers will see reduced monthly energy bills on the Critical Peak rates. Those that don’t are being charged for their peak load.

Results From the California State Pricing Pilot (SPP) Generally Show:

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California Vision

Rule Making CPUC, CEC, CPA joint proceeding June 2002[CPUC R.02-06-001, CEC 02-Demand Response-01]

CPUC, CEC, CPA joint proceeding June 2002[CPUC R.02-06-001, CEC 02-Demand Response-01]

How

1. Install advanced [interval capable] meters with communication links on all customers.

2. Establish Critical Peak Pricing as the default tariff for all customers.

3. Provide customers with options to ‘opt-out’ to real-time pricing or risk adjusted time-of-use, non-time varying tiered or other rate forms.

1. Install advanced [interval capable] meters with communication links on all customers.

2. Establish Critical Peak Pricing as the default tariff for all customers.

3. Provide customers with options to ‘opt-out’ to real-time pricing or risk adjusted time-of-use, non-time varying tiered or other rate forms.

1

Objectives1. Improve system reliability and reduce energy

costs by encouraging demand response.

2. Provide customers with options to manage costs.

1. Improve system reliability and reduce energy costs by encouraging demand response.

2. Provide customers with options to manage costs.

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Problems

1. California utilities concerned that prior 25 years of pricing and demand response research not applicable.

2. California utilities need up-to-date demand elasticities to estimate system resource and procurement impacts.

3. The cost to implement advanced metering system wide requires a complete and thorough business case evaluation.

Solution

Statewide Pricing Pilot (SPP)Statewide Pricing Pilot (SPP)

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SPP Conclusions

1. Rates that reflect market price (Critical Peak Pricing), produce greater conservation and demand response impacts than TOU or inverted tier rate forms.

2. Residential and commercial/industrial customers with demands less than 200kW demonstrate substantial, statistically significant response to critical peak pricing.

3. Critical Peak rates will produce short-run residential peak demand reductions of 2,000 MW or more, energy conservation of up to 7% and even greater impacts in the long-term. At $85 per kW-year, these savings equal $3-$4 per customer per month.

4. Customers understand and respond favorably to Critical Peak rates.

5. At least 50% of residential customers will receive a lower energy bill under Critical Peak Pricing without any change in usage. Another 20% to 30% of residential customers will receive a lower energy bill under Critical Peak Pricing with only minor changes in usage.

6. The net investment to implement the advanced metering infrastructure to support Critical Peak Pricing should result in incremental residential charges substantially less than $1.00 per meter per month.

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California Vision – The Results

Costs & BenefitsUtility Business Case for Advanced Metering

Major Issues

System Impacts

System Wide - Procurement impacts

Conservation / Peak Load Impacts

Demand Elasticities

Customer Response

Customer Understanding

Customer Preferences

Bill Impacts

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System Impacts SPP Conclusions

CPP rates can, within five years of deployment reduce the California’s

residential peak load by 2,000 to 2,400 MW.

System Wide Procurement

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CPP-V rates encourage greater conservation and peak demand impacts than conventional inverted tier, TOU or CPP-F rates.

Conservation and Peak Load

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1. SPP short-run own-price demand elasticities are consistent with 25 years of historical findings in California and elsewhere.

2. Historical long-run own-price demand elasticities are typically about double short-run elasticities.

Demand ElasticitiesS

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Confidence in Conclusion

Need for Further Tests

High Moderate Low

None Useful

Essential

High Moderate Low

None Useful

Essential

High Moderate Low

None Useful

Essential

High Moderate Low

None Useful

Essential

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RESIDENTIAL CUSTOMERSRESIDENTIAL CUSTOMERS

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1. Customers show significant response to both the CPP-F and CPP-V rates

2. Impacts are higher in the hotter zones for both CPP and non CPP days

3. Responses are substantially higher on CPP days than on non-CPP days

4. For all zones, the CPP day impact is -12% and the non-CPP day impact is –2.3%

5. CPP day impacts differ slightly between the two experimental rates within the CPP-F rate

6. Results are generally similar across the two functional forms tested in this study

7. Customers do not respond to TOU rates

Source: SPP Summer 2003 Update Analysis, Charles Rivers Associates, June 9, 2004.

SPP Conclusions


ImpactsSP

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Historical Findings SPP Findings

Residential customer elasticities were higher than those for commercial customers. Confirmed.

Residential customer elasticities were typically higher for customers with higher usage, more appliances, and air conditioning load.

Confirmed.

Price response was typically significantly higher – approximately double – when automated control capability was available.

Confirmed.

Customers typically reduced total consumption by around three percent, with the range from zero percent to as high as 23 percent.

Confirmed.

Customers reduced peak demands by a four percent (low end of time-of-use range) to 59 percent (high end of critical peak pricing range).

Confirmed.

Commercial customer elasticities varied widely by business type. Confirmed.

Customer Response to Price

What Have We Learned ?

Source: Proposed Pilot Projects and Market Research to Assess the Potential for Deployment of Dynamic Tariffs for Residential and Small Commercial Customers, Report of Working Group 3 to Working Group 1, R.02-06-001, Final Version 5, December 10, 2002, p25.


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71.5

23.7

7.5

51.7

21.3

11.0

61.0

22.5

9.4

0

10

20

30

40

50

60

70

80

Ce

nts

/ k

Wh

CPP-F High Ratio CPP-F Low Ratio Average

Residential Price For Consumers At Midpoint of Tier 3

(Weighted Average, Climate Zone 2)

CPP Period Peak Period Off-Peak Period

Control Group Average Price 13.3 cents/kWh

RESIDENTIALRESIDENTIALConservation and Peak Load

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Rates

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SPP Residential Rate Forms( Example TOU & CPP High Options )


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CPP Tariff- (high)TOU Tariff- (high)

$0.7336

$0.2336

$0.0886

0

10

20

30

40

50

60

70

80

Ce

nts

pe

r k

Wh

Existing RatesAvg. Summer Price

13.36 ¢/kWh

$0.2596

$0.1026

2:00-7:00pmWeekdays

Other Weekday & Weekend hours

2:00-7:00pmWeekdays

Other Weekday & Weekend hours

Dispatched2:00-7:00pm

1,500 hrs/yr 7,260 hrs/yr Maximum 75 hrs/yr 1,425 hrs/yr 7,260 hrs/yr

Critical Peak

Summer Peak

Summer Off-Peak

RESIDENTIALRESIDENTIAL

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0

500

1000

1500

2000

2500

3000

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Avo

ided

MW Pure CPP 75 Universal

CPPF 75 Universal

TOU 1.5:1 Ratio Mandatory

TOU 2.5:1 Ratio Voluntary

SPP Residential Rate Options System Wide Potential Peak Demand Impacts

Source: Charles Rivers Working Group 3 presentation, March 30, 2004.


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Probabilistic System Wide CPP Residential Potential Peak Demand Impacts


Assumptions:

Illustrative CPP and TOU rates are constructed, building upon the rates used in the SPP; the rates are revenue neutral for the typical California investor-owned utility residence

Marginal capacity cost of $85/kW-year are used in the analysis, along with energy costs of 15¢ /kWh in the CPP period, 4.7¢ /kWh in the peak period, and 4.0 ¢ /kWh in the off peak period.

The pure CPP rate will reduce the state’s residential peak load by 2,400 MW in the year 2007 with a probability of 50% and almost certainly meet that target by the year 2012

Avoided MW – All Weather Zones

0.000.90

0.800.700.600.50

0.400.300.200.10

1.00

1,758 2,058 2,358 2,658 2,958 MW

Pro

bab

ilit

y o

f D

R I

mp

act

2007

2012

The pure CPP rate will reduce residential peak load by 2,000 MW in the year 2007 with a probability of 95% and almost certainly meet that target by the year 2012


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TRC NPV Benefits – All Zones

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

1.10

$1,009 $1,359 $1,709 $2,059 $2,409

Millions of Dollars

Pro

bab

ility The pure CPP rate will almost certainly

produce more than a billion dollars worth of Total Resource Cost benefits.Note: TRC benefit estimates exclude utility operating savings.

System Wide Pricing ImpactsDemand Response Dollar Value of Impacts



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Residential Coincident Critical Peak Demand Impacts

By SPP Rate Treatment

Source: Statewide Pricing Pilot Summer 2003 Impact Analysis, Charles Rivers Associates, March 9, 2004.

0%

10%

20%

30%

40%

50%P

eak

Lo

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edu

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n49.4%

19.5%

CPPF

(Critical Peak Fixed)

23.5%

TOU

(Time-of Use)

CPPV

(Critical Peak Variable w/Automated Controls)


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Percent Change In Energy Use By Rate Period

For Average Experimental Prices On Non-CPP Days

-9.3

-2.3

3.82.2

3.8

-6.2

1.2

4.3

7.3

4.2

-12-10-8-6-4-202468

10

Zone 1 Zone 2 Zone 3 Zone 4 All

%

Ch

an

ge

In

kW

h

Peak Period Off-Peak Period



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Percent Change In Energy Use During

The Peak Period On CPP Days By Price Ratio

-23.5

-11.5-8.1

-17.8

-11.7

-24.5

-5.1

3.4

-1.9

-22.8

-30

-25

-20

-15

-10

-5

0

5


%

Ch

an

ge

In

kW

h

High Ratio Low Ratio



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Conservation vs. Peak Period Impacts

By SPP Rate Form

Source: Statewide Pricing Pilot Summer 2003 Impact Analysis, Charles Rivers Associates, March 9, 2004.

Peak Period kWh Impacts

( Example: Weather Zone 3 )

0

- 4

- 6

- 8

- 10

- 2

Conservation

Non-Critical Days

Peak Period Impact

Demand Response

Critical Days

Peak Period Impact

-0.5

-1.4

-3.6 -3.3

-1.9 -2.0

-5.4

-9.9

kW

h P

eri

od

Im

pa

ct

CPPF

TOU

CPPV, Smart Thermostat

CPPV, > 600 kWh/mo


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-38.8-28.0CPP - Variable

-22.0-9.4CPP – Fixed

-16.0-16.0Time-of-Use

CPP DaysNon-CPP

DaysRate Form

-49.4-1.4

-19.5-0.2

-23.5-0.3

PercentkWh

`Change in Coincident

Peak DemandPercent Change in Peak Consumption

SPP Impacts on Peak Consumption and Coincident Peak Demand

Source: Statewide Pricing Pilot, Summer 2003 Impact Analysis, Charles Rivers Associates, January 16, 2004, Tables 1-1 and 1-2.


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Weather Related Impacts Load Impacts

CPP Days (Percentage Change in Usage)

4.85.1

-13.4

3.1

-16

-9.7

-20

-15

-10

-5

0

5

10


%

Ch

an

ge

In

kW

h

Average Top Quintile Bottom Quintile

Interpreting This graph:

As seen, the percent reduction in peak-period energy use on CPP days based on average weather for the treatment period is 13.4 percent. Based on weather conditions representing the top 20 percent of CPP days (as measured by system load conditions), the percent reduction is –16 percent, whereas the reduction falls to 9.7 percent on the cooler, lowest system-load days.

Source: Charles Rivers Associates Analysis memo, June 24, 2004.

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Non-CPP Days (Percentage Change in Usage)


4.74.8

-2.4

4.2

-4.8

-2

-6

-4

-2

0

2

4

6


%

Ch

an

ge

In

kW

h

Average Top Quintile Bottom Quintile


On non-CPP days, the percent reduction in peak-period energy use is 4.8 percent based on weather conditions representing high-load days and 2 percent on low-load days.

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-20.2

-16

-2.6

-14.6

-9.7

-25.3

-7.2

0.02

-1.4

-21.2

-30

-25

-20

-15

-10

-5

0

5


%

Ch

an

ge

In

kW

h

Top Quintile Bottom Quintile


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By Weather Zone on CPP Days(Percentage Change in Usage)



This graph shows the variation in percentage impacts across climate zones for peak-period energy use on CPP days. The percent impact is clearly much larger in the hotter climate zones than in the cooler zones. However, the change in the percentage impact between the top and bottom quintile load days is greater in zone 2 than it is in zones 3 and 4.

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-2.04

-1.09

-0.09

-0.78-0.41

-3.11

-0.35

0

-0.04

-1.25

-3.5

-3

-2.5

-2

-1.5

-1

-0.5

0


C

ha

ng

e In

kW

h

Top Quintile Bottom Quintile


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By Weather Zone on CPP Days(Change in Actual kWh)



This graph shows the absolute impact, in kilowatt-hours, resulting from the SPP prices by climate zone and for the state as a whole. Clearly, the difference in the absolute impact on high-load and low-load days is much larger than the difference in percentage impacts, as customers in the hotter zones are both more responsive high-load days and larger energy users. When these two factors are combined, the impact on high load days in zone 2 is nearly four times higher than on low-load days. In zones 3 and 4, the impact is roughly 2½ times higher on high-load days than on low-load days. Statewide, the impact is roughly 2.7 times higher on high-load days than on low-load days. It is also worth noting that the absolute impact on high-load days in the hottest zone 4 is almost nine times greater than the impact in the moderate zone 2.

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COMMERCIAL / INDUSTRIAL CUSTOMERS

COMMERCIAL / INDUSTRIAL CUSTOMERS

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SPP Commercial / Industrial Rate Forms( TOU & CPP High Options )


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Average Prices For C&I Customers During Treatment Period ($/kWh)

Customer Segment

Rate Treatment

Price Ratio

Non-CPP Day CPP-Day

Peak Period

Off-Peak Period

Peak Period

Off-Peak Period

LT20 Control n/a 0.186 0.186

TOU High 0.272 0.094 0.272 0.094

Low 0.325 0.159 0.325 0.159

CPP-V High 0.200 0.095 1.07 0.091

Low 0.256 0.169 0.813 0.166

GT20 Control n/a 0.154 0.154

TOU High 0.224 0.100 0.224 0.100

Low 0.254 0.144 0.254 0.144

CPP-V High 0.187 0.086 0.820 0.084

Low 0.212 0.137 0.629 0.136


Commercial / IndustrialCommercial / Industrial

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Price For Typical C&I Customer On CPP-V Rate(Weighted Average For Treatment Customers)

106.0

20.0

9.5

80.4

25.6

16.9

81.6

18.7

8.6

62.5

21.113.7

0

20

40

60

80

100

120

ce

nts

/kW

h

LT20-High Ratio LT20-Low Ratio GT20-High Ratio GT20-Low Ratio

CPP Period Peak Period Off-Peak Period





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Percent Change In Energy During Peak Period

(Average Experimental Prices On CPP Days)

-26

-14.7

-27.8

-9.1

-13.3

-33.1

-25.2

-11.3

-35

-30

-25

-20

-15

-10

-5

0

LT20 kW Separate Dispatch

GT20 kW Separate Dispatch

LT20 kW Common Dispatch

GT20 kWCommon Dispatch

%

Ch

an

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In

kW

h

Log-Log SpecificationCES Specification

* Estimates for the CPP-V tariff may not represent the impacts of the general population of customers



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Percent Change In Energy Use By Rate Period For Average Experimental Prices On CPP Days

(Based on Log-Log Model)

-26

7 5.7

-9.1-13.3

-33.1

2.1 3.8

-40-35-30-25-20-15-10-505

10

LT20 kW

Separate Dispatch

GT20 kW

Separate Dispatch

LT20 kW

Common Dispatch

GT20 kW

Common Dispatch

%

Ch

an

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In

kW

h

Peak Period

Off-Peak Period




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Percent Change In Energy Use During Peak Periods On CPP Days By Price Ratio

(Based on Log-Log Model)

-26.8

-18.9

-24.4

-1-5.5

-35.7

-30

-15.1

-40

-35

-30

-25

-20

-15

-10

-5

0

LT20 kW

Separate Dispatch

GT20 kW

Separate Dispatch

LT20 kW

Common Dispatch

GT20 kW

Common Dispatch

%

Ch

an

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In

kW

h

High Ratio

Low Ratio



ImpactsSP

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INDUSTRY WIDE EXPERIENCEINDUSTRY WIDE EXPERIENCE

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0%

10%

20%

30%

40%

50%P

eak

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edu

ctio

n

22%

Dynamic Pricing (CPP)

32%

AC Load Control

45%

Dynamic Pricing (CPP) with AC Control

Source: ISSUES IN DEMAND RESPONSE, Combining Residential Dynamic Pricing and Load Control: The Literature Chris King, December 2003

Comparison of Pricing Only, Load Control Only and Combined Programs


Impacts

Industry ExperienceIndustry Experience

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Cost EffectivenessCPP Rates Dominate TOU Rates

Total Resource Cost - Net Present Value

32.9 30.3

2.6

111.8

30.3

81.5

0

20

40

60

80

100

120

Benefits Costs Net Benefits

$ M

illi

on

s

TOU CPP

Source: [ Northern State Power Case Study ]

Creating Value Through Dynamic Pricing in Mass Markets, Peak Load Management Alliance Fall Conference, Annapolis, Maryland, Ahmad Faruqui and Steve George, Charles River Associates, October 8, 2002

Industry ExperienceIndustry ExperienceConservation and Peak Load

Impacts

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Own-Price Elasticities

California SPP vs. Nationwide Historical Results

1980 1985 1990 1995 2000 2005

-0.5

0.0

-0.1

-0.2

-0.3

-0.4

-0.6

-0.7

-0.8

-0.9

California 2003 SPP CPP-F Critical Peak Days

Nationwide Historical Results

Average = -0.30

Source: Predicting California Demand Response, Chris King and Sanjoy Chatterjee, Public Utilities Fortnightly, July 1, 2003, p.27-32.


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Climate Zone

CPP-FCPP Days*

CPP-FNon-CPP

Days

TOUAll

Weekdays

Zone 1 -0.14 -0.21 +0.03

Zone 2 -0.24 -0.26 -0.13

Zone 3 -0.34 -0.50 -0.59

Zone 4 -0.25 -0.25 -0.27

Statewide Pricing Pilot (SPP)Own-Price Elasticity Results

Source: Charles Rivers Associates, SPP Summer 2003 Impact Analysis, January 27, 2004.

Climate Zone

Short-Run Elasticity1

Long-Run Elasticity

Low -0.12 -0.60

Medium -0.20 -0.90

High -0.35 -1.20

Historical StudiesOwn-Price Elasticity Results

1. Short-run – customers make no change in appliance holdings.

Source: Predicting California Demand Response, Chris King and Sanjoy Chatterjee, Public Utilities Fortnightly, July 1, 2003, p.27-32.

Own-Price Elasticity of Demand

SPP Compared to Historical Industry Results


PP

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• A variety of experiments, quasi-experiments and demonstration programs have been conducted during the past quarter century to assess customer response to innovative pricing options.

• On average, if the on-peak price is doubled, on-peak usage drops by 20%. The drop in usage varies based on factors such as appliance ownership and climate.

• Puget Sound Energy has shown that if the on-peak price is raised about 15%, on-peak usage drops by 5%.

• Salt River Project has shown that coincident peak demand drops by 28% if the on-peak energy price is doubled.

• GPU has shown that enabling technologies can double the magnitude of customer response.

There Is Ample Evidence That US Customers Respond To Dynamic Pricing Rates

Source:

Creating Value Through Dynamic Pricing in Mass Markets, Peak Load Management Alliance Fall Conference, Annapolis, Maryland, Ahmad Faruqui and Steve George, Charles River Associates, October 8, 2002

Demand Elasticities


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Customer Demand Response Estimates

Program Type Range of ElasticitiesRange of Peak

Demand ReductionRange of Total

Usage Reduction

Residential time-of-use

-0.05 to -1.3(SCE; North Carolina)

4% to 35% (Ontario; Duke)

0% to 23%(PG&E; Connecticut)

Residential critical peak

pricing

-0.35 to -0.82(GPU; EdF France)

42% to 59%(Gulf Power; AEP)

0% to 6.5%(AEP; Gulf Power)

Small commercial time-

of-use-0.03 to -0.04

(SCE; PG&E)

SPP Results in Process

2.1% to 5% (McKinsey multi-utility

data; Finland)

Small commercial dynamic pricing No studies



Source:

Proposed Pilot Projects and Market Research to Assess the Potential for Deployment of Dynamic Tariffs for Residential and Small Commercial Customers, Report of Working Group 3 to Working Group 1, R.02-06-001, Final Version 5, December 10, 2002, Table 2-2.

Demand Elasticities


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CUSTOMER KNOWLEDGE,

PREFERENCES and BILL IMPACTS

CUSTOMER KNOWLEDGE,

PREFERENCES and BILL IMPACTS

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Customer Response

SPP Conclusions

1. Customers do not understand the relationship between how they use energy and what they pay.

2. Customers understand and accept the concept of time-differentiated pricing.

Customer KnowledgeS

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1. Customers resist change due to uncertainty regarding their present usage and billing situation.

2. Residential and business customers support rates that match price with electricity demand.

Customer PreferencesS

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1. Low and moderate use residential customers will receive reduced energy bills under a CPP rate without any change to their usage pattern because they already use less on-peak energy.

2. CPP rates will provide all customers with a clear option for managing their energy cost.

Bill Impacts

SP

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Confidence in Conclusion

Need for Further Tests

High Moderate Low

None Useful

Essential

High Moderate Low

None Useful

Essential

High Moderate Low

None Useful

Essential

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“..most respondents could easily understand the logic of time-differentiated electricity prices,..”

1

“..customers understood time-differentiated pricing (at least the on-peak / off-peak variety) more easily than they understood the notion of inclining block [tiered] or declining block pricing.”

2

Source: 1- Residential Customer Understanding of Electricity Usage and Billing, Momentum Market Intelligence, WG3 Report, January 29, 2004.p16.

Conventional vs. Time-Differentiated Pricing

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Customer Knowledge Findings

What it means.

• Customers don’t understand how electricity use is measured.

• Customers don’t understand how electricity is priced.

• There is an uncertain and inaccurate link between how customers use energy, what they pay and what they get in service value.

• Bill accuracy – customer’s must trust their supplier. No other choice.

Lack of meaningful feedback on usage and usage pattern.

Complicated rates mask the time and/or volume vs. cost relationship.

The inability to clearly link cost with value contributes to improper / inefficient usage and impedes better investment decisions.

Creates a fragile, tenuous relationship.

Results from the SPP 1 What it means2

Source: 1- Residential Customer Understanding of Electricity Usage and Billing, Momentum Market Intelligence, WG3 Report, January 29, 2004.pviii-ix.

2 – CEC interpretation.

Customer KnowledgeS

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USCLCorporation

SPP Customer Rate Preference

Source: SPP End-of-Summer Survey Report, Momentum Market Intelligence, WG3 Report, January 21, 2004, p23-24.


PP

R

es

ult

s

Original Inverted Tier Rate Time-Differentiated Rate

Res

iden

tialCPP-V

CPP-F

TOU

80%

81%

20%

23%

19%

Co

mm

erci

al

CPP-V

TOU

77%

71%

70%

20406080 20 40 60 80

30%

29%

Percent that Prefer 0

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USCLCorporation

Customer Resistance to Change

Justification for a Revised Default Tariff

“Having to change plans, however, is not viewed as a good thing but rather as a necessary step when a given plan turns out to not work as well as had been anticipated.”

1

“The implication for electricity pricing plans is to recognize that customers do not tend to adopt such plans with the notion that they are willing to ‘trial’ options and ‘see how they work out’.”

2

..several participants claimed to be on a TOU rate, derived from the “Flex Your Power” advertising campaign. They were delaying some electric usage until evenings and weekends – they believed they were paying less for electricity during those times.

3


PP

R

es

ult

s

Source: SPP End-of-Summer Survey Report, Momentum Market Intelligence, WG3 Report, January 21, 2004, p 15.

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USCLCorporation

Average Bill Impacts

Residential and Commercial / Industrial Savings (summer / winter 2003)

Bill ImpactsS

PP

R

es

ult

s

CPPV CPPF TOUInfo Only

Participants (%) 71.1% 73.7% 70.0% 79.0%

Average Monthly Savings (%)

5.1% 5.5% 4.5% 5.4%

Average Monthly Savings ($)

$53 $35 $29 $19

CPPV TOU

80.3% 58.2%

12.2% 9.6%

$1,521 $869

Participants (%) 28.9% 26.3% 30.0% 21.0%

Average Monthly Increase (%)

4.0% 6.2% 3.0% 10.0%

Average Monthly Increase ($)

$39 $44 $30 $9

19.7% 41.8%

5.0% 10.0%

$224 $600

ResidentialCommercial /

Industrial

Bill Savings

Bill Increases

Source: Statewide Pricing Pilot, Shadow Bill Results, WG3 report, June 9, 2004.

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USCLCorporation

Potential Impacts from Systemwide Implementation

Existing Inverted Tier vs. SPP CPP Rate (Summer)( Assumes no customer response )

Bill ImpactsS

PP

R

es

ult

s

$20

$120

$100

$80

$60

$40

MO

NT

HL

Y S

UM

ME

R B

ILL

($

)

Typical Utility Residential Population2 TURN Target Group1

321 kWh/MoLow User

286 kWh/MoLow User

562 kWh/MoModerate User

923 kWh/MoHigh User

$39.58$37.59 $35.26

$33.08

$69.29 $70.67

$113.81

$119.71

Inverted Tier

CPP Rate

Baseline = 373 kWh

Savings$1.99

Savings$2.18

Increase$1.38

Increase$5.90

1. Target Population identified: Financial Externalities and “Peak Hogs”: New Consideration for Energy Efficiency and Rate Design Policy, by William B. Marcus, Principle Economist, JBS Energy, Inc., March 2001.

2. Target Population identified from PG&E SPP rate design exercise.

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USCLCorporation

Typical Utility Residential Population by Average Monthly Electric Usage

Low Use Moderate Use High Use

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

Per

cen

t

<399 400-599 600-799 800-1,199 1,200-1,599 >1,600

Single Family

Multi-Family

44% 69% 82% 94% 97% 100%Cumulative

Percent

~ 500 kWh/moReduced Bill

With no ChangeIncreased Bill

With no Change

Customer Bill ImpactsBill ImpactsS

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R

es

ult

s

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USCLCorporation


Cost Benefit IssuesCost Benefit Issues

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48

USCLCorporation

Costs & Benefits Advanced Metering

Infrastructure System CostS

PP

Is

su

e

Cost Allocation

SP

P

Iss

ue

Outsourcing

SP

P

Iss

ue

Full system wide deployment is too expensive. Implementation should be targeted to select customers or programs.

Concern:Concern:

Response:Response:U.S. utilities have deployed over 15 million units based on utility operating savings alone.

Small customers will be adversely and disproportionately impacted by monthly fixed meter charges.

Concern:Concern:

Response:Response:Allocating meter costs using kWh usage reduces monthly impacts to under $0.50.

Outsourcing offers no benefits to utilities.Concern:Concern:

Response:Response:Two-thirds of U.S. deployments are outsourced at lower cost and risk to the utility.

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USCLCorporation


PP

Is

su

e

Advanced Metering

Improved Data Access Impacts all Utility Functions

Data Preparation

[VEE]

System Operations

Meter Maintenance

Customer Service

Accounting and Billing

Energy Information

Services

Demand Response

Management

Demand Response

Management

Work OrderProcessingWork OrderProcessing

ESCOServicesESCO

Services

ServiceCalls

ServiceCalls

Meter ReadingMeter

Reading

System DispatchSystem Dispatch

Load Forecasts

Load Forecasts

EnergyReconciliation

EnergyReconciliation

SettlementsSettlements

EMSServices

EMSServices

PerformanceMonitoring

PerformanceMonitoringOutage

ManagementOutage

Management

MarketingSupport

MarketingSupport

Cash Management

Cash Management

Theft Management

Theft Management

Electronic Billing and

Presentment

Electronic Billing and

Presentment

RateDesignRate

Design

DataWarehouse

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USCLCorporation


PP

Is

su

eAdvanced Metering

Establishing the Business Case

UTILITYUTILITY

CUSTOMER

SOCIETY

Business Case Perspective Emphasis

•Operational Costs

•Operational Savings

•System Integration

•Value of Services

•Value of Information

•Bill Management

•Value of Information

•Responsiveness

•Risk Management

Traditional Scope

Expanded Scope

Protect Revenue

Requirement

Improve Value of Service

Reduce Total System Cost

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51

USCLCorporation

Meter System Costs (Example)

ResidentialCommercial

Industrial

Solid State Meter and communication module $45-$75 $50-$800

Installation Cost $5-$150 $10-$300

Information and Communication Systems *

$10-$40 $10-$40

Total $ Cost per Meter $85-$265 $90-$1,000


PP

Is

su

e

Per Customer / Month Incremental Cost

$1.00 to $1.50 per meter

Today’s Metering Cost$2.50 - $3.50 / meter / month

Source: WG3, industry presentation, 2003.

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USCLCorporation


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Is

su

e

Advanced Metering - Utility Benefits

Cumulative Utility Benefits

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00M

on

thly

Ben

efit

s P

er M

eter

Field Service

Administrative Customer Service

System Operations+ + +

$5.69

$7.34

$7.76

Low Benefit

High Benefit

$1.65

$0.72$0.95 $1.15 $1.22

Source: “Capturing the Value: The Future of Advanced Metering and Energy Information”, Cambridge Energy Research Associates (CERA), Final Report, Spring 1999, Chapter VI, Figure VI-6 (Levy Associates Working papers).


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USCLCorporation

Electric System Benefits

Puget Sound Energy

Electric System Benefits

Puget Sound Energy

47%

8%6%

4%

4%

27%

4%

Meter Reading

DiversionProcess

Improvement

Call Center

Outage Management

Revenue Enhancement

Other

Source: California Experiential Workshop, Presentation by Puget Sound Energy, Brian Pollom and Todd Starnes, September 10, 2002.


PP

Is

su

e Industry ExperienceIndustry Experience

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USCLCorporation


PP

Is

su

e Industry ExperienceIndustry Experience

Advanced Metering - System Benefits

Standards and Construction

Collections

Field Work Management

Safety

Load Forecasting

Meter Management

Demand Response

Vegetation Management

Outage and Restoration

Tariff and Regulatory

Asset Management

Billing and Customer Care

System Control

Settlement

0

Reported Percentage Reduction in System Costs

5 10 15 20 25

Source: “Distribution Technology Roadmap”, Report for the Canadian Electrical Association & Consortium, by Cap Gemini Ernst & Young, U.S. LLC, 2003.

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USCLCorporation

Reduce System Meter Reading Costs NO YES

Improve Billing Information, Reduce Estimated Bills LIMITED YES

Improve Financial Management NO YES

Reduce / Improve Call Center Operation NO YES

Reduce Diversion and Theft LIMITED YES

Improve System Outage Response NO YES

Better Information for Planning, Forecasting &

EvaluationLIMITED YES

Better Information for T&D Planning / Management LIMITED YES

Expanded Demand Response Planning and Evaluation LIMITED YES

System-Wide ImplementationSystem-Wide

ImplementationImproved Utility

OperationsImproved Utility

OperationsTargeted

ImplementationTargeted

Implementation

1

2

3

4

5

6

7

8

9

B


PP

Is

su

eAdvanced Metering

Full vs. Targeted Deployment – Impact on Benefits(Example)

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USCLCorporation

Cost AllocationS

PP

Is

su

e

Advanced Metering - Cost Allocation

PROBLEMPROBLEMFixed meter charges disproportionately impact low use customer bills.

SOLUTIONSOLUTION kWh based volumetric cost allocation method.

Total Cost Per Residential Meter

Option #1.

Fixed Charge

$ / Meter / Month

Option #2.

Volumetric Charge

$ / Meter / Month

$85 - $265 $1.05 - $2.25

Monthly Usage Monthly Charge

0 - 300 kWh $0.33

301 - 500 kWh $0.56

501 – 1,000 kWh $1.12

> 1,000 kWh $1.67

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USCLCorporation

Meter System Economics

Financing Impacts on NPV and Payback

Source: Private communication between Levy Associates and Invensys, background data for a utility highlighted at the Distributech 2001 Utility Conference.

Outsourcing

SP

P

Iss

ue

$20

$15

$10

$5

$0

$5

$10

$15

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

OutsourceOutsource

Pay-for-ReadSynthetic Lease

Year

NP

V

($m

illi

on

s)

PurchasePurchase

1.0 3.5 11.0

Payback year

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USCLCorporation

Next Steps Options

1. Regulatory Process

2. Legislation

3. Settlement

4. Policy Decision

prepared by: roger levy; levy associates 1 uscl corporation california spp results initiative on...

Documents

demand pricing

critical peak rates

roger levy levy associates

residential customers

commercialindustrial

demand response impacts

years of pricing

demand response research