Dynamic Pricing - Potential and Issues

Joe Wharton and Ahmad Faruqui

Kansas Corporation Commission Workshop on

Energy Efficiency March 25, 2008

2

Policy of Dynamic Pricing raises important questions

1. What is the potential impact of dynamic pricing on peak demand?

2. What is the value of this demand response (DR)?

3. How much does customer price responsiveness vary by customer and region?

4. How can rate design make dynamic pricing more attractive to customers?

3

Dynamic pricing can lower system peak demand by 5 percent, considerably below the economic and technical potential

Estimates of Total Potential Peak Demand Reduction

5%

15%

52%

0%

10%

20%

30%

40%

50%

60%

Market Projection Economic Potential Technical Potential

Red

uct

ion

in

Pea

k D

eman

d

4

A 5 percent reduction in US peak demand could be worth $31 billion over a 20-year period, just on avoided costs

Assumptions

• 5% demand reduction in 757 GW

• $52/kW-year capacity price

• 20 year horizon

• 15% discount rate

• 2% peak growth rate

• Avoided cost of energy is 36% of avoided cost of capacity*

• Value of wholesale price reduction is 278% of avoided cost of capacity*

*Derived from a study on the value of DR in PJM:

The Brattle Group, 2007, Quantifying Demand Response Benefits in PJM, Prepared for PJM and MADRI NPV of Avoided Costs = $31 billion

Annual Value of a 5% Reduction in Peak Demand

5.50.7

2.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

Avoided Costs Wholesale Price Reduction

An

nu

al F

inan

cial

Val

ue

(Bil

lio

ns

of

$)

Avoided EnergyCost

Avoided Capacity

Cost

5

There is a range of pricing options – from static (fully hedged) to dynamic

Risk (Variance in

Price)

Reward (Discount from Flat

Rate)

10%

5%

10.5

RTP

CPP-F

VPP

Flat Rate

TOD

Seasonal Rate

CPP-V

0%0

PTR?

Inverted Tier Rate

Risk Averse Customers

Risk Seeking Customers

6

What peak demand reductions come from dynamic pricing - results from pricing pilots

7

Across the TOU pilots, there is solid evidence of demand response

Percentage Reduction Estimates from Reviewed TOU Pilot Programs

0%

5%

10%

15%

20%

25%

30%

35%

Ontario- 1 Ontario- 2 SPP PSEG PSEG ADRS- 04 ADRS- 05 Gulf Power-1

Pilot Program

% R

edu

ctio

n i

n L

oa

d

TOU TOU w/ Tech

8

Dynamic pricing gives rise to greater peak reductions

Percentage Reduction Estimates from Reviewed CPP/PTR Pilot Programs

0%

10%

20%

30%

40%

50%

60%

Pilot Program

% R

edu

ctio

n i

n L

oa

d

CPP PTR CPP w/ Tech

9

The Peak Time Rebate (PTR) rate has achieved demand response in two pilots

Comparison of Peak Time Rebate (PTR) Program Tariffs and Resulting Impacts

-0.30

-0.20

-0.10

0.00

0.10

0.20

0.30

0.40

0.50

Ontario Anaheim

Pilot Program

Ra

te (

$/k

Wh

) o

r

Lo

ad

Im

pa

ct (

as

a f

ract

ion

of

tota

l lo

ad

)

Existing Off-Peak Mid-Peak

Peak PTR Load Impact

10

Different Critical Peak Pricing (CPP) tariffs induce different load impacts during “event days”

Comparison of Critical Peak Pricing (CPP) Program Tariffs and Resulting Impacts

-0.50

-0.40

-0.30

-0.20

-0.10

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

PSE&G Ontario AmerenUE SPP Idaho

Pilot Program

Ra

te (

$/k

Wh

) o

r

Lo

ad

Im

pa

ct (

as

a f

ract

ion

of

tota

l lo

ad

)

Existing Off-Peak Mid-Peak

Peak CPP Load Impact

Note: PSE&G load impact on CPP days is not provided in the reviewed study. The load impact is calculated using the reported kWh reductions and an estimate of consumption during peak on CPP days.

11

Enabling technologies magnify demand response

Role of Technology on Pilot Program Impacts

0%

5%

10%

15%

20%

25%

30%

35%

40%

PSE&G (TOU) PSE&G (CPP) SPP (CPP) AmerenUE-2004 (CPP)

AmerenUE-2005 (CPP)

Pilot Program

% R

edu

ctio

n i

n L

oa

d

No Technology Technology

Note: PSE&G load impacts on CPP days are not provided in the reviewed study. The load impacts are calculated using the reported kWh reductions and an estimate of consumption during peak on CPP days.

12

Mass Market customers’ response varies by enabling technologies and the customers’ end uses

Peak Demand Reduction by Customer Type

-35%

-30%

-25%

-20%

-15%

-10%

-5%

0%

0.00 0.20 0.40 0.60 0.80 1.00

Critical Peak Rate ($/kWh)

De

cre

as

e i

n C

riti

ca

l P

ea

k D

em

and

Non-CAC

Average

CAC

CAC w/ Technology

13

Applying these relationships, one expects to find customer responses will vary by region

Demand Response Comparison Across Regions

-25%

-20%

-15%

-10%

-5%

0%

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40

Critical Peak Rate ($/kWh)

Pea

k D

eman

d R

edu

ctio

n

HawaiiPacific NorthwestBaltimoreCalifornia - Zone 4

14

But there is equity issue: could Bills rise for 50% of the customers choosing dynamic pricing

Distribution of Bill Impacts

-15%

-10%

-5%

0%

5%

10%

15%

20%

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Percentile of Customer Base

Ele

ctri

city

Bil

l In

crea

se (

Dec

reas

e)

Customers with Peakier ConsumptionCustomers with Flatter Consumption

15

A discount could be build-in for the “insurance or risk premium” incorporated in flat or hedged rates

• Empirically, this “insurance premium” is estimated to range from 3 to 13 percent for different types of time-varying rates

• Illinois used a value of 10 percent in its RTP pilot for residential customers

• Monte Carlo simulations with a standard financial equation suggest a mean value of 11 percent

• A conservative estimate is 3 percent

16

By adjusting for conservative risk premium, dynamic pricing rates become attractive for 70% of customers

Distribution of Bill Impacts

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%

20%

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Percentile of Customer Base

Ele

ctri

city

Bil

l In

crea

se (

Dec

reas

e)

Revenue neutral

Credit for hedging cost premium

Customers with Peakier ConsumptionCustomers with Flatter Consumption

17

Also factoring in the demand response expands the appeal to 90%

Distribution of Bill Impacts

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%

20%

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Percentile of Customer Base

Ele

ctri

city

Bill

Incr

ease

(D

ecre

ase)

Revenue Neutral

Credit for Hedging Cost Premium

Demand Response Plus Credit for Hedging Cost Premium

Customers with Peakier ConsumptionCustomers with Flatter Consumption

18

Conclusion: the way forward should involve a careful look at the range of dynamic pricing options

Risk (Variance in

Price)

Reward (Discount from Flat

Rate)

10%

5%

10.5

RTP

CPP-F

VPP

Flat Rate

TOD

Seasonal Rate

CPP-V

0%0

PTR?

Inverted Tier Rate

Risk Averse Customers

Risk Seeking Customers

19

Footnotes

See A. Faruqui and L. Wood, Quantifying the Benefits of Dynamic Pricing in the Mass Market, for EEI, Jan 2008.

Note: Percentage reduction in load is defined relative to the different bases in different pilots. Following notes are intended to clarify these different definitions. TOU impacts are defined relative to the usage during peak hours unless otherwise noted. CPP impacts are defined relative to the usage during peak hours on CPP days unless otherwise noted.

• Ontario- 1 refers to the percentage impacts during the critical hours that represent only 3-4 hours of the entire peak period on a CPP day. Ontario- 2 refers to the percentage impacts of the programs during the entire peak period on a CPP day

• TOU impact from the SPP study uses the CPP-F treatment effect for normal weekdays• PSEG program impacts represented in the TOU section are the % impacts during peak period on non-CPP days.• PSEG program impacts represented in the CPP section are derived using the reported kWh reductions and the

estimated consumption during the peak period on CPP days• ADRS- 04 and ADRS- 05 refer to the 2004 and 2005 impacts. ADRS impacts on non-event days are represented

in the TOU with Tech section• CPP impact for Idaho is derived from the information provided in the study. Average of kW consumption per hour

during the CPP hours (for all 10 event days) is approximately 2.5 kW for a control group customer. This value is 1.3 kW for a treatment group customer. Percentage impact from the CPP treatment is calculated as 48%.

• Gulf Power-1 refers to the impact during peak hours on non-CPP days while Gulf Power-2 refers to the impact during CPP hours on CPP days.

• Ameren-04 and Ameren-05 refer to the impacts respectively from the summers of 2004 and 2005.• SPP- A refers to the impacts from the CPP-V program on Track A customers. Two-thirds of Track A customers

had some form of enabling technologies.• SPP-C refers to the impacts from the CPP-V program on Track C customers. All Track C customers had smart

thermostats.