Assessing Ontario’s
Regulated Price Plan
Ahmad Faruqui
Ryan Hledik
Ontario Energy Board Consultation Meeting
Toronto, Ontario
December 21, 2010
Copyright © 2010 The Brattle Group, Inc.
www.brattle.com
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The logic of Time-of-Use (TOU) pricing
Generation costs vary by pricing period but this variation is masked by non-TOU rates,
thereby creating an unintended inequity
Under non-TOU rates, customers who don’t consume much during peak periods pay
more than their fair share of costs and those who consume much during peak periods
pay less than their fair share
By reflecting this time-variation in costs, TOU rates eliminate an important unfairness
in rate design
Additionally, by lowering rates during the off-peak period and raising them during the
peak period, TOU rates provide customers an opportunity to reduce their monthly bills
by curtailing consumption during peak periods and/or shifting it to off-peak periods
These benefits have been demonstrated consistently across a broad range of studies
carried out in North America, Europe and Australia which have found that about 75
percent of customers are better off with TOU rates
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We explored the merits of alternative TOU design
options in Ontario
Overview of Project Approach
Step 1:
Review Existing
TOU Rate
Step 2:
Identify Areas for
Improvement
Step 3:
Establish
Alternatives
Step 4:
Evaluate the
Alternatives
Define rate
evaluation criteria
Benchmark rate
against industry best
practices
Peak-to-off-peak
price ratio is too
small
Identify aspects of
TOU that can be
modified
Review TOU impact
evaluation studies
Expected range of
bill impacts not fully
understood
Modify aspects of
TOU design to
create attractive
alternative rate
options
Simulate expected
rate impacts under
full deployment
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Further research on
rate impacts (pilots)
needed
Simulate expected
impacts of rate
options
3
Assess pros and
cons of each rate
option
Summarize rate
evaluation and
present
recommendations
Ontario’s transition to TOU pricing is in progress
… to a TOU rate
TOU Rate Illustration - Electricity Price
0.14
0.14
0.12
0.12
Generation Rate (C$/kWh)
Generation Rate (C$/kWh)
Transitioning
from -the
tiered
Tiered Rate Illustration
Electricity
Price rate…
0.10
$0.075
0.08
$0.065
0.06
0.04
Summer Tiered
0.02
$0.099
$0.099
0.10
0.08
$0.080
$0.053
0.06
$0.053
0.04
Summer TOU
0.02
Winter Tiered
Winter TOU
0.00
0.00
0
200
400
600
800
1000
1200
1400
1600
0
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Monthly Usage (kWh)
Hour Starting
Currently ~2.8 million enrolled
Currently ~1.2 million enrolled
Compared to the tiered rate, the TOU provides a discount during the
off-peak period (59% of hours) and a higher price in the remaining hours
Note:
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Prices represent only the generation component of the rate.
4
The majority of hours are in the low-priced off-peak
period, an attractive feature for customers
Summer TOU Hour Allocation
Winter TOU Hour Types
On-peak
774
18%
Mid-peak
1032
23%
On-peak
1016
23%
Off-peak
2610
59%
Mid-peak
762
18%
There is a larger share of peak hours in the winter than in the summer
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Off-peak
2566
59%
Each defining characteristic of the TOU rate was
benchmarked against industry best practices
Results of Benchmarking
TOU Characteristic
Alignment with
Best Practices?
Reason
Number of periods
Strong
Many TOU rates have three periods
Timing/duration of
peak
Strong
Aligns well with historical system load and hourly
energy market prices
Seasonality
Strong
Dual peak in winter justifies seasonal change in
pricing structure
Time-varying charges
Strong
Typically only generation-related charges are
made to be time-varying
Moderate
Calculation is reasonable given available data;
focus on province-wide supply cost recovery can
have differential impacts on customers
Weak
Price ratio is low relative to TOU programs in
other jurisdictions; likely to produce modest
customer response or bill savings
Average customer
cost neutrality
Price ratio
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System load and hourly energy prices align well in
shape with the TOU rate
$0.12
30,000
$0.12
25,000
$0.10
25,000
$0.10
20,000
$0.08
20,000
$0.08
15,000
$0.06
15,000
$0.06
10,000
$0.04
10,000
$0.04
Load
Avg Energy Price (2004-2010)
TOU
5,000
-
System Load (MW)
30,000
$0.02
$-
-
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour Starting
Load
Avg Energy Price (2004-2010)
TOU
5,000
$0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
System Load Data from 2009
LMP Data from 2009
Hour Starting
There is a fairly broad summer peak and a dual peak in the winter
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$0.02
7
System Load Data from 2009
LMP Data from 2009
Rate (C$/kWh)
System Load, LMP, and TOU Rate
Average Winter Day
Rate (C$/kWh)
System Load (MW)
System Load, LMP, and TOU Rate
Average Summer Day
The peak-to-off-peak price ratio is low relative to
TOU rates elsewhere
Distribution of Price Ratios in Existing TOU Rates (Generation Only)
Distribution of Price Ratios (Peak / Off Peak) in Existing TOU Programs
16
RPP TOU Price Ratios
All-in:
1.4 to 1.2 to 1
Number of TOU Programs
Generation Only:
1.9 to 1.5 to 1
14
RPP TOU
ratio = 1.9
12
Mean ratio = 3.8
10
8
6
4
2
0
0
1
2
3
4
5
6
7
8
Price Ratio (Peak / Off Peak)
Note: Excludes
II" which
ratio of 29
1.
Note:ConEdison
Details Residential
on each"Rate
TOU
rate has
area price
provided
in tothe
appendix
This ratio could be adjusted to better reflect system conditions
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9
10
11
There are many ways to increase the price ratio
Rate Design
Option
In Existing
TOU…
Alternative
option…
Likely Impact on Price Ratio
Renewables Cost
Reallocation
Existing GA costs only,
allocated uniformly
across periods
Allocate wind & solar to
peak period, account for
expected FIT costs
Increases peak costs, decreases off-peak
costs, and increases price ratio
Peak Duration
6 hour peak, 8 hour
mid-peak (opposite in
non-summer months)
Shorten peak and midpeak period to 4 hours in
both seasons
Shorter peak period spreads capacity costs
over fewer peak hours, increasing the peak
price
Seasonality
Year-round
Summer-only TOU with
off-peak rate applying
during the winter months
Summer-only means fewer peak hours and
therefore higher peak price
Price setting
methodology
Set off-peak and midpeak price, solve for
peak price
Set peak and mid-peak
price, solve for off-peak
price
Changes in the supply cost structure could
increase or decrease the price ratio under
this approach
Number of
periods
Three periods
(peak, mid-peak, and
off-peak)
Remove mid-peak period
to create 2 period rate
Depends on how prices are set; combined
with other rate design approaches, smaller
number of periods could be beneficial
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Collectively, these changes could produce a price ratio of
4.9:1, while an alternate approach could lead to a 4.1:1 ratio
Price Ratios with Incremental Changes to Rate Design
Generation-only Peak to Off-Peak Price Ratio
6
4.9
5
4.1
4
3.2
3
2.7
1.9
2
1
0
Existing TOU
Reallocation
of Wind/Solar
GA Cost
4 Hour Peak
Period
Summer Only
Alternative
Peak Price,
2 Periods
Note: Impact on price ratio is cumulative as shown in figure; incremental impacts of
each change to the design would be different if implemented individually
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The results of TOU pilots in Ontario can be used to
predict customer response to the new rate designs
TOU pricing was tested in five Ontario pilots
♦ Newmarket Hydro
♦ Hydro One
♦ Hydro Ottawa
♦ Oakville Hydro
♦ Veridian Connections
TOU enrollment in the pilots ranged from 40 to 180 participants (although one
pilot was just 3 commercial buildings)
Treatment periods were in the 2006 to 2007 timeframe, with pilot durations
lasting from 5 months to slightly over 1 year
See Appendix A for details on the pilots
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The pilots are moderately applicable for
extrapolation of TOU impacts at the province level
Applicability of Pilot Results for Province-Wide Assessment
Applicability of
Results
Reason
High
TOU results are relevant and impacts cover
full summer season
Newmarket Hydro
Medium
TOU results are relevant, but sample size is small
(39 participants)
Hydro Ottawa (OSPP)
Medium
Relevant TOU results, but not statistically significant and
impacts only reported for critical days
Oakville Hydro
Low
Short period of pre-treatment data collection, very limited
and unrepresentative sample of only 3 buildings
Veridian Connections
Low
Only includes bulk-metered customers >200 kW
Utility
Hydro One
Based on this screening, we have selected the Hydro One,
Newmarket Hydro, and Hydro Ottawa pilots for more detailed analysis
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The results from the 3 most relevant pilots were
benchmarked against informed expectations
Comparison of Peak Impacts Across Pilots
Calibrated Impacts from Other Pilots
Connecticut
California
Maryland
Impacts from Ontario Pilots
Newmarket
Hydro
Hydro Ottawa
Hydro One
Change in Demand During Peak Period
0.0%
-0.4%
-1.0%
-1.2%
-2.0%
-1.8%
-2.3%
-2.4%
-3.0%
-4.0%
-5.0%
-3.7%
♦ Peak impacts from the
Ontario pilots align fairly
well with expectations from
other pilots around North
America
♦ The other North American
pilot impacts were calibrated
to the price ratio of the RPP
TOU rate and Ontario’s
system conditions
Notes:
(1) The impact evaluations conducted by Oakville Hydro and Veridian Connections were excluded due to lack of applicability of results or statistically
insignificant impacts. (2) “Other pilot” impacts are calibrated roughly to the rates tested in the Ontario
13 pilots; results would vary slightly depending on which
Ontario pilot rates they are being calibrated to, although this variation is not enough to produce any significant difference in the impacts (roughly +/- 0.1%)
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There is significant variation in overall energy
consumption impacts across the pilots
♦ This variation is partly
Comparison of Energy Consumption Impacts Across Pilots
Calibrated Impacts from Other Pilots
Connecticut
California
Maryland
0.3%
0.4%
Change in Usage During Study Period
2.0%
1.0%
Impacts from Ontario Pilots
Newmarket
Hydro
Hydro One
Hydro Ottawa
1.1%
0.4%
0.0%
-1.0%
-2.0%
-3.0%
-4.0%
-3.3%
-5.0%
-6.0%
-6.0%
-7.0%
explained by Ontario pilot
limitations (short pilot
durations spanning different
time periods, often with a
small number of participants)
♦ Also explained by lack of
average customer cost
neutrality at the utility level
(customers experience change
in rate level when moving
from existing tiered rate to
TOU)
♦ This highlights the need for
better understanding of the
impact of the TOU rate in
Ontario
Notes:
(1) The impact evaluations conducted by Oakville Hydro and Veridian Connections were excluded due to lack of applicability of results or statistically
insignificant impacts. (2) “Other pilot” impacts are calibrated roughly to the rates tested in the Ontario
14 pilots; results would vary slightly depending on which
Ontario pilot rates they are being calibrated to, although this variation is not enough to produce any significant difference in the impacts (roughly +/- 0.1%)
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Implied elasticities from the Ontario pilots were integrated
into Brattle’s Price Impact Simulation Model (PRISM)
The PRISM Modeling Framework
Model Inputs
Customer’s peak
period usage
Customer’s off-peak
period usage
All-in peak price of
new rate
All-in off-peak price of
new rate
Central air-conditioning
saturation
Weather
Basic Drivers
of Impacts
Load Shape Effects
Peak-to-off-peak
usage ratio
Peak-to-off-peak price
ratio
Substitution effect
(i.e. load shifting)
Overall change in
load shape
(peak and off-peak
by day)
Elasticity of
substitution
Geographic location
Customer class
(e.g. residential, C&I)
Load-wtd avg daily allin price of new rate
Existing flat rate
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Aggregate Load
Shape and Energy
Consumption
Impact
Daily price elasticity
Daily effect
(i.e. conservation or
load building)
Difference between
new rate (daily
average) and existing
flat rate
15
Our PRISM analysis relied on three elasticity
scenarios
Lower-bound elasticity assumption:
♦ Roughly tied to results of the Newmarket Hydro pilot
♦ 0.5% peak reduction at 3-to-1 price ratio, with little conservation effect
Upper-bound elasticity assumption:
♦ Roughly tied to results of Hydro One pilot
♦ 3% peak reduction at 3-to-1 price ratio, but with smaller conservation effect
“Base Case” elasticity assumption:
♦ Average of “low” and “high” elasticities
♦ Aligns with range of simulated impacts from other North American studies
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Four alternative TOU rate designs were developed
based on our findings
Alternative TOU
Description
Price ratio
Rate #1:
Wind/solar reallocation
The existing TOU with the addition and reallocation of
expected wind and solar GA costs to the peak period
2.7-to-1
Rate #2:
Wind/solar reallocation
+ 4-hour peak
Rate #1 but also with peak and mid-peak windows
reduced to four hours
3.2-to-1
Rate #3:
Wind/solar reallocation
+ 4-hour peak
+ summer only
Rate #2 but also with TOU rate limited to summer
months (May through October); flat rate applies other
months
4.9-to-1
Rate #4:
Alternative peak price
+ 2 period
Peak price set equal to average peak energy price plus
levelized cost of capacity ($100/kW-yr); off-peak solved
for cost neutrality; summer only with 4 hour peak period
4.1-to-1
See Appendix B for details of these four alternative rate designs
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The average peak impacts of the four rate alternatives range
from 1% to 4% and could be as high as 7%
Range of Average RPP Customer Response by Rate Alternative
Range of Average RPP Customer Response Projections
8%
7%
Peak Reduction
6%
Range represents
impacts from "high"
and "low" response
estimates
5%
4%
4.0%
3.3%
3%
2%
2.0%
1.4%
1%
0.9%
0%
Existing TOU
Rate #1:
Wind/Solar
Reallocation
Rate #2:
Reallocation
+ 4-hr Peak
Rate #3:
Reallocation
+ 4-hr Peak
+ Summer-only
Rate #4:
Alternative Price
+ 2-period
Elasticity assumptions based on the range of reasonable elasticities derived from a review of the existing Ontario impact
studies and supplemented by the results of other time-based pricing studies; For the midpoint, elasticity of substitution = -0.03
and daily elasticity = -0.11
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The rates will impact each customer differently
depending on their consumption profile
Three Illustrative Customer Consumption Profiles
3.5
"Peaky" customer
Hourly Electricity Usage (kW)
3.0
2.5
"Average" customer
2.0
"Flat" customer
1.5
1.0
0.5
0.0
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour of Day
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♦ “Flat” usage customers will
experience bill savings due
to low consumption in the
higher-priced periods
♦ The opposite is true for
“peaky” usage customers
♦ Bill impacts have been
estimated for a
representative sample of
roughly 500 utility
customers that fall at various
points along the spectrum of
“flat” and “peaky” usage
Across samples from 5 utilities, changes in
customer bills will range from -12% to +18%
Distribution of Bill Impacts for Rate #3 (Before Response)
20%
Toronto Hydro
Generation-Only Bill Change (%)
15%
10%
Avg
bill
increase
5%
0%
-5%
Avg
bill
decrease
-10%
-15%
-20%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Percentile
Note: Results shown for Rate #3 before any customer response and are relative to today’s TOU
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Across samples from 5 utilities, changes in
customer bills will range from -12% to +18%
Distribution of Bill Impacts for Rate #3 (Before Response)
20%
Thunder Bay
15%
Generation-Only Bill Change (%)
Toronto Hydro
10%
Avg
bill
increase
5%
0%
-5%
Avg
bill
decrease
-10%
-15%
-20%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Percentile
Note: Results shown for Rate #3 before any customer response and are relative to today’s TOU
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Across samples from 5 utilities, changes in
customer bills will range from -12% to +18%
Distribution of Bill Impacts for Rate #3 (Before Response)
20%
Newmarket
Thunder Bay
15%
Generation-Only Bill Change (%)
Toronto Hydro
10%
Avg
bill
increase
5%
0%
-5%
Avg
bill
decrease
-10%
-15%
-20%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Percentile
Note: Results shown for Rate #3 before any customer response and are relative to today’s TOU
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Across samples from 5 utilities, changes in
customer bills will range from -12% to +18%
Distribution of Bill Impacts for Rate #3 (Before Response)
20%
PowerStream
Newmarket
Thunder Bay
Toronto Hydro
Generation-Only Bill Change (%)
15%
10%
Avg
bill
increase
5%
0%
-5%
Avg
bill
decrease
-10%
-15%
-20%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Percentile
Note: Results shown for Rate #3 before any customer response and are relative to today’s TOU
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Across samples from 5 utilities, changes in
customer bills will range from -12% to +18%
Spread Renewables
TOU with
Today's
Relative to for
Impacts
Estimated
Distribution
ofBillBill
Impacts
Rate
#3Evenly
(Before
Response)
Today's TOU w/ Renewables and 4 Hour Peak - Summer Only
20%
PowerStream
Newmarket
Thunder Bay
Toronto Hydro
Milton Hydro
Generation-Only Bill Change (%)
15%
10%
Avg
bill
increase
5%
0%
-5%
Avg
bill
decrease
-10%
-15%
-20%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Percentile
Note: Results shown for Rate #3 before any customer response and are relative to today’s TOU
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After customers shift consumption, a higher
percentage will experience bill savings
Estimated Bill Impacts Relative to Today's TOU with Evenly Spread Renewables
Today's TOU w/ Renewables and 4 Hour Peak - Summer Only
Bill Impacts Before and After Customer Response
10%
Bill impact before customer response
8%
Bill impact after customer response ("high" case)
Generation-Only Bill Change (%)
6%
4%
2%
0%
-2%
Customer response
results in greater bill
savings and a larger
share of customers
with an incremental
bill decrease
-4%
-6%
-8%
-10%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Percentile
Note: Results shown for Rate #3 for Toronto Hydro sample; see Appendix C for full results
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The aggregate response of 4 million customers on the TOU
rate will lower peak demand and ultimately contribute to a
reduction in generation costs, helping all Ontarians
IESO Load Duration Curve with Rate #3 Impact
25,000
24,500
Reduction in system peak due to largest
simulated TOU impact = 4% (1,064 MW)
System Load (MW)
24,000
23,500
23,000
22,500
22,000
21,500
21,000
System Load without TOU
20,500
System Load with Largest Projected TOU Impact
20,000
0
50
100
Top 200 Hours
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150
200
In other rate scenarios, peak demand declines from
a low of 0.2% to a high of 4.4%
IESO System Peak Demand Impacts by Rate Scenario
Low Response
Moderate Response
High Response
%
MW
%
MW
%
MW
Rate #1:
Wind/solar reallocation
0.2%
61
1.0%
234
1.7%
405
Rate #2:
Renewables reallocation
+ 4-hour peak
0.4%
101
1.4%
335
2.3%
566
Rate #3:
Renewables reallocation
+ 4-hour peak
+ summer-only
0.7%
160
2.8%
676
4.4%
1,064
Rate #4:
Alternative peak price
+ 2 period
0.7%
159
2.1%
510
2.8%
674
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The Path Forward
If the top priority is to…
Then the OEB could…
But be aware…
Minimize the implementation
burden
Continue with the current design and
simply reallocate renewables costs to
the peak period
This only marginally improves the price
ratio
Improve the price ratio
Consider significant rate design
changes that decrease the number of
peak hours (such as seasonality and a
shorter peak period)
Significant design changes will require
re-education of utilities, policymakers,
and customers regarding the new rate
structure
Simplify the rate-setting
process
Pursue an alternative approach where
the peak period price is pegged to
marginal capacity and energy costs,
and the off-peak is solved for revenue
neutrality
This would require a major overhaul of
the current methodology and would
require significant research to determine
the appropriate marginal cost
assumptions
Better understand customer
responsiveness
Conduct an impact assessment of
customer consumption behavior after
the full transition to the TOU rate
While this option carries little risk, alone
it does not lead to greater customer
response rates
Improve customer response
and perception
Work with utilities to initiate an
education campaign around the rate
and its benefits, possibly including the
provision of enabling technologies
Customer education improves response
but cannot lead to greater bill savings if
the rate design does not offer the
opportunity to significantly reduce bills
Combinations of these approaches could achieve balance across priorities, but would be more complex
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Ahmad Faruqui
Ahmad Faruqui provides expert advice on time-of-use and dynamic pricing to
utilities and government agencies. He has testified on rate design issues before a
dozen state and provincial commissions and legislative bodies and spoken at a wide
variety of energy conferences in Brazil, Canada, France, Ireland, Saudi Arabia, the
United Kingdom and the United States.
During the past two years, he has assisted FERC in the development of the
“National Action Plan on Demand Response” and in writing “A National
Assessment of Demand Response Potential.” He co-authored EPRI’s national
assessment of the potential for energy efficiency and EEI’s report on quantifying the
benefits of dynamic pricing. He has assessed the benefits of dynamic pricing for the
New York Independent System Operator, worked on fostering economic Demand
Response for the Midwest ISO and ISO New England, reviewed demand forecasts
for the PJM Interconnection and assisted the California Energy Commission in
developing load management standards. His most recent report, “The Impact of
Dynamic Pricing on Low Income Customers,” has just been published by the
Institute for Electric Efficiency.
The author, co-author or editor of four books and more than 150 articles, papers and
reports, he holds a doctoral degree in economics from the University of California at
Davis.
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Ryan Hledik
Ryan Hledik is a senior associate of The Brattle Group with specialized expertise in
assessing the impacts of smart grid programs, technologies, and policies. He has
assisted electric utilities, regulators, research organizations, wholesale market
operators, and technology firms in the development of innovative demand response
and energy efficiency portfolios and strategies.
Recently, Mr. Hledik contributed to the development of the Federal Energy
Regulatory Commission’s (FERC) National Assessment of Demand Response
Potential, which was submitted to U.S. Congress in June 2009. Mr. Hledik has been
the lead developer of several energy market simulation tools for the purposes of
wholesale price forecasting, asset valuation, and emissions analysis.
Mr. Hledik received his M.S. in Management Science and Engineering from
Stanford University in 2006, where his concentration was in Energy Economics and
Policy. He received his B.S. in Applied Science (with honors) from the University of
Pennsylvania in 2002 with minors in Economics and Mathematics. Prior to joining
The Brattle Group, Mr. Hledik was a research assistant with Stanford University’s
Energy Modeling Forum and a research analyst at Charles River Associates.
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About The Brattle Group
The Brattle Group provides consulting and expert testimony in economics, finance, and
regulation to corporations, law firms, and governments around the world.
We combine in-depth industry experience, rigorous analyses, and principled techniques to help
clients answer complex economic and financial questions in litigation and regulation, develop
strategies for changing markets, and make critical business decisions.
Climate Change Policy and Planning
Cost of Capital
Demand Forecasting and Weather Normalization
Demand Response and Energy Efficiency
Electricity Market Modeling
Energy Asset Valuation
Energy Contract Litigation
Environmental Compliance
Fuel and Power Procurement
Incentive Regulation
Rate Design, Cost Allocation, and Rate Structure
Regulatory Strategy and Litigation Support
Renewables
Resource Planning
Retail Access and Restructuring
Risk Management
Market-Based Rates
Market Design and Competitive Analysis
Mergers and Acquisitions
Transmission
ahmad.faruqui@brattle.com
353 Sacramento Street, Suite 1140
San Francisco, CA 94111
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Appendix A:
Current TOU
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Today’s TOU has a 10-hour off-peak period and a
price ratio of 1.9
Illustration of Today's TOU
Peak Summer Day
32
Today's TOU
Generation Rate (cents/kWh)
28
Average Supply Cost (No New Renewables)
24
20
16
Peak to off-peak
price ratio = 1.9
12
8
4
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23
Hour Starting
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The seasonal definition lines up with historical
IESO load data
2009 IESO System Load
♦ Ontario is mostly a
30,000
System Load (MW)
25,000
20,000
15,000
10,000
5,000
Summer (May – Oct)
Jan-09
Feb-09
Mar-09
Apr-09
OEB Consultation Meeting
May-09
Jun-09
Jul-09
Aug-09
Sep-09
Oct-09
Nov-09
34
Dec-09
summer peaking
region (2004 was last
year with winter peak)
♦ However, on average
energy use is higher in
the winter (by 3% to
9% since 2004),
presumably due to
electric space and
water heating
There is a less pronounced seasonal pattern in the
historical energy price data
2008 Hourly Ontario Energy Price (HOEP)
♦ Prices are more
600
Summer (May – Oct)
System Load (MW)
500
400
300
200
100
Jan-08
Feb-08
Mar-08
Apr-08
May-08
Jun-08
Jul-08
Aug-08
Sep-08
Oct-08
Nov-08
Dec-08
volatile in the summer
season
♦ In 2008, the price
exceeded $200/MWh
in 15 hours, most of
which were in the
summer
(100)
Note: 2008 Hourly Ontario Energy Price (HOEP) was used, because it appears to be more representative of the
average historical prices than the 2009 HOEP, which was quite low.
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TOU pricing pilots in Ontario
Overview of Ontario TOU Pilots
Classes of
Participants
Number of TOU
Participants
Total Number of
Pilot Participants
Treatment Period
TOU Rate
(cents/kWh)
Notes
Residential
39
220
Aug 06 - Oct 07
P: 9.2
M: 7.2
O: 3.2
Pilot also tested CPR and controllable
thermostats
Residential, farm,
small C&I (<50 kW)
177
500
May 07 - Sep 07
P: 9.7
M: 7.1
O: 3.4
Pilot also tested in-home displays
Hydro Ottawa
Residential
124
375
Aug 06 - Feb 07
P: 9.7 - 10.5
M: 7.1 - 7.5
O: 3.4 - 3.5
Pilot also tested CPP, CPR, and
enabling technolgy
Oakville Hydro
Multi-res buildings
286 residents in
3 buildings
286 residents in
3 buildings
Jan 06 - Oct 07
P: 9.2 - 10.5
M: 7.1 - 7.5
O: 3.2 - 3.5
Pilot primarily tested impact of
transition from bulk-metered building to
individually metering residents
Multi-res and MUSH,
all bulk-metered and
>200 kW
38
38
Feb 07 - Sep 07
P: 9.2 - 9.7
M: 7.1 - 7.2
O: 3.2 - 3.4
Pilot only focused on TOU rate
Utility
Newmarket Hydro
Hydro One
Veridian Connections
Notes:
“MUSH” is municipals, universities, schools, and hospitals
In some pilots the TOU rate changed over time. In this table, the range is provided.
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Appendix B:
Alternate TOU Designs
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Rate #1: Today’s TOU with re-allocation (and
addition) of renewable GA costs
Illustration of Today's TOU w/ Renewables
Peak Summer Day
32
Today's TOU w/ Renewables
Generation Rate (cents/kWh)
28
Average Supply Cost (With New Renewables)
24
20
Peak to off-peak
price ratio = 2.7
16
12
8
4
-
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23
Hour Starting
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♦ Existing and expected wind &
solar GA costs are allocated
entirely to the peak period
♦ The peak period price
increases, with minor changes
to prices in other periods
♦ Alternative allocations could
be explored, such as
allocating a larger share of
hydro costs to the peak period
as well
♦ Note that the GA cost
associated with new
renewables leads to an overall
rate increase of 7.5%
Rate #2: Today’s TOU with renewable cost reallocation and a four-hour peak period
Illustration of Today's TOU w/ Renewables & 4 Hour Peak
Peak Summer Day
32
Today's TOU w/ Renewables and 4 Hour Peak
Generation Rate (cents/kWh)
28
Average Supply Cost (With New Renewables)
24
Peak to off-peak
price ratio = 3.2
20
16
12
8
4
-
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23
Hour Starting
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♦ The peak and mid-peak
duration are decreased to 4
hours each
♦ 25% of peak period GA cost
is assumed to be a capacity
cost; as such, the absolute
cost is spread over the peak
hours
♦ As the number of peak and
mid-peak hours decreases, the
average $/MWh capacity
price increases
♦ Note that the 25% estimate
for the capacity portion of GA
costs is subject to revision
Rate #3: Summer-only TOU with renewable cost reallocation and a four-hour peak period
Illustration of Today's TOU w/ Renewables & 4 Hour Peak - Summer Only
Peak Summer Day
Generation Rate (cents/kWh)
32
28
Today's TOU w/ Renewables and
4 Hour Peak - Summer Only
24
Average Supply Cost (With New
Renewables)
Peak to off-peak
price ratio = 4.9
20
16
12
8
4
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23
Hour Starting
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♦ The TOU rate structure
only applies during
summer months
♦ The rate is flat during the
remaining months of the
year (equal to the off-peak
price of the summer TOU
rate)
♦ The capacity portion of
peak GA costs is spread
over fewer hours as a
result, and the peak price
rises
Rate #4: The peak price is set based on historical
marginal energy and capacity costs
Illustration of Marginal Cost-Based Rate (Summer Only)
Peak Summer Day
32
Generation Rate (cents/kWh)
28
Marginal Cost-Based Rate
Average Supply Cost (No New Renewables)
Peak to off-peak
price ratio = 4.1
24
20
16
12
8
4
-
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23
Hour Starting
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♦ The peak price is equal to
an average peak energy
price of $0.068/kWh plus a
capacity price of $100/kWyear, spread across the
peak hours
♦ The rate is summer-only
♦ This is a common marginal
cost-based approach to
TOU rate design that has
been adopted by utilities in
other parts of North
America
Appendix C:
Summary of Bill Impacts
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Expected Bill Impacts: Commodity Portion Only
(Percent)
Expected Bill Change for Alternative Rate Options Relative to Existing TOU (Annual Average, Commodity Portion Only)
For 10th, 50th, and 90th Percentiles of Customer Bill Impact Distributions
Rate
Elasticity Case
10th %
Rate #1:
Reallocation of
wind/solar GA costs
Rate #2:
Reallocation
+ 4-hour peak
Rate #3:
Reallocation
+ 4-hour peak
+ summer-only
Rate #4:
Alternative peak price
+ 2 periods
+ 4-hour peak
+ summer only
Toronto Hydro
50th %
90th %
10th %
Power Stream
50th %
90th %
10th %
Thunder Bay
50th %
90th %
10th %
Newmarket
50th %
90th %
10th %
Milton Hydro
50th %
90th %
No Respose
-1%
0%
2%
-1%
0%
1%
-1%
0%
2%
-1%
0%
2%
-2%
0%
2%
Low Respose
-1%
0%
1%
-1%
0%
1%
-1%
0%
2%
-1%
0%
2%
-2%
0%
2%
Moderate Response
-2%
-1%
1%
-2%
-1%
1%
-2%
0%
1%
-2%
-1%
1%
-2%
-1%
1%
High Response
-2%
-1%
0%
-3%
-1%
0%
-3%
-1%
1%
-2%
-1%
0%
-3%
-1%
1%
No Respose
-4%
0%
3%
-2%
0%
3%
-2%
1%
5%
-2%
1%
3%
-3%
0%
4%
Low Respose
-4%
0%
2%
-3%
0%
3%
-2%
1%
4%
-2%
1%
3%
-3%
0%
3%
Moderate Response
-4%
-1%
2%
-3%
0%
2%
-3%
1%
4%
-3%
0%
2%
-4%
0%
3%
High Response
-5%
-2%
1%
-4%
-1%
1%
-4%
0%
3%
-4%
-1%
2%
-5%
-1%
2%
No Respose
-6%
-1%
4%
-5%
2%
10%
-6%
0%
10%
-6%
2%
8%
-4%
3%
10%
Low Respose
-6%
-1%
4%
-5%
2%
9%
-6%
0%
9%
-6%
2%
8%
-4%
3%
9%
Moderate Response
-6%
-2%
3%
-6%
1%
8%
-6%
-1%
8%
-7%
1%
7%
-5%
2%
8%
High Response
-7%
-3%
2%
-6%
0%
7%
-7%
-2%
7%
-7%
0%
5%
-5%
1%
7%
No Respose
-4%
-1%
3%
-4%
2%
6%
-5%
0%
7%
-4%
1%
6%
-3%
2%
7%
Low Respose
-4%
-1%
3%
-4%
2%
6%
-5%
0%
7%
-5%
1%
6%
-3%
2%
7%
Moderate Response
-4%
-2%
2%
-4%
1%
5%
-6%
-1%
6%
-5%
0%
5%
-4%
2%
6%
High Response
-5%
-2%
2%
-4%
1%
5%
-6%
-1%
6%
-5%
0%
4%
-4%
1%
5%
Notes:
Impacts are relative to the current TOU with expected future renewable GA costs included and allocated evenly across the rate periods.
Power Stream sample appears to include residential and non-residential customers; the other samples are limited to residential customers.
OEB Consultation Meeting
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Expected Bill Impacts: Commodity Portion Only
(Dollar Amount)
Expected Bill Change for Alternative Rate Options Relative to Existing TOU (Annual Average, Commodity Portion Only)
For 10th, 50th, and 90th Percentiles of Customer Bill Impact Distributions
Rate
Elasticity Case
10th %
Rate #1:
Reallocation of
wind/solar GA costs
Rate #2:
Reallocation
+ 4-hour peak
Rate #3:
Reallocation
+ 4-hour peak
+ summer-only
Rate #4:
Alternative peak price
+ 2 periods
+ 4-hour peak
+ summer only
Toronto Hydro
50th %
90th %
10th %
Power Stream
50th %
90th %
10th %
Thunder Bay
50th %
90th %
10th %
Newmarket
50th %
90th %
10th %
Milton Hydro
50th %
90th %
No Respose
-$5.71
$0.58
$9.02
-$13.09
$0.37
$14.24
-$5.36
$1.58
$9.01
-$5.85
$0.65
$10.72
-$8.91
$0.39
$14.36
Low Respose
-$6.13
$0.19
$7.96
-$14.84
$0.02
$12.22
-$5.74
$1.00
$8.51
-$6.12
$0.31
$9.72
-$9.54
-$0.21
$13.09
Moderate Response
-$9.35
-$2.35
$4.99
-$24.36
-$4.71
$5.34
-$8.53
-$2.18
$5.59
-$10.09
-$2.85
$5.09
-$14.47
-$4.26
$8.25
High Response
-$12.56
-$5.63
$1.25
-$32.55
-$9.27
-$0.11
-$11.51
-$5.38
$2.59
-$14.22
-$5.84
$1.32
-$19.71
-$8.33
$4.81
No Respose
-$18.28
-$1.57
$16.62
-$15.39
$1.85
$37.08
-$13.73
$4.50
$27.83
-$13.93
$2.75
$17.81
-$18.17
$1.48
$27.72
Low Respose
-$18.63
-$2.08
$15.95
-$15.74
$1.06
$34.64
-$14.30
$3.81
$26.60
-$14.47
$2.39
$16.96
-$18.62
$1.02
$26.08
Moderate Response
-$21.34
-$5.60
$12.50
-$20.56
-$3.77
$22.75
-$20.66
$1.51
$21.14
-$20.06
-$1.13
$12.93
-$23.06
-$2.02
$19.27
High Response
-$24.91
-$8.84
$5.34
-$29.36
-$7.89
$12.58
-$26.56
-$0.14
$16.52
-$22.60
-$4.73
$8.49
-$28.02
-$6.33
$11.30
No Respose
-$30.44
-$6.27
$22.05
-$19.85
$17.93
$120.32
-$27.79
$1.39
$48.47
-$21.16
$8.55
$71.15
-$23.96
$17.47
$74.74
Low Respose
-$31.32
-$6.79
$20.54
-$20.94
$16.68
$115.24
-$28.50
$0.43
$46.86
-$21.23
$7.93
$68.33
-$24.59
$15.66
$72.31
Moderate Response
-$40.27
-$9.72
$14.17
-$26.75
$10.17
$82.29
-$33.60
-$5.20
$39.54
-$25.37
$3.82
$53.92
-$27.91
$9.14
$60.82
High Response
-$41.28
-$11.73
$8.76
-$53.84
$3.57
$62.84
-$39.54
-$8.87
$32.50
-$29.22
-$0.14
$40.95
-$31.42
$4.51
$49.15
No Respose
-$23.90
-$4.21
$16.75
-$17.93
$15.05
$80.13
-$26.65
-$0.84
$29.63
-$17.15
$5.67
$52.35
-$16.54
$12.26
$54.89
Low Respose
-$24.43
-$4.66
$15.48
-$19.58
$13.62
$75.66
-$27.92
-$1.70
$28.29
-$17.60
$4.86
$49.86
-$17.96
$11.45
$52.33
Moderate Response
-$24.98
-$5.74
$12.19
-$23.39
$9.57
$60.52
-$28.80
-$3.30
$24.58
-$18.64
$1.32
$40.95
-$21.60
$9.02
$46.09
High Response
-$28.10
-$7.72
$9.67
-$25.80
$5.91
$53.54
-$29.24
-$4.80
$20.99
-$20.71
-$0.49
$32.24
-$22.59
$5.62
$41.00
Notes:
Impacts are relative to the current TOU with expected future renewable GA costs included and allocated evenly across the rate periods.
Power Stream sample appears to include residential and non-residential customers; the other samples are limited to residential customers.
OEB Consultation Meeting
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Expected Bill Impacts: All-In Bill (Percent)
Expected Bill Change for Alternative Rate Options Relative to Existing TOU (Annual Average, All-In Rate)
For 10th, 50th, and 90th Percentiles of Customer Bill Impact Distributions
Rate
Elasticity Case
10th %
Rate #1:
Reallocation of
wind/solar GA costs
Rate #2:
Reallocation
+ 4-hour peak
Rate #3:
Reallocation
+ 4-hour peak
+ summer-only
Rate #4:
Alternative peak price
+ 2 periods
+ 4-hour peak
+ summer only
Toronto Hydro
50th %
90th %
10th %
Power Stream
50th %
90th %
10th %
Thunder Bay
50th %
90th %
10th %
Newmarket
50th %
90th %
10th %
Milton Hydro
50th %
90th %
No Respose
-1%
0%
1%
-1%
0%
1%
-1%
0%
1%
-1%
0%
1%
-1%
0%
1%
Low Respose
-1%
0%
1%
-1%
0%
1%
-1%
0%
1%
-1%
0%
1%
-1%
0%
1%
Moderate Response
-1%
-1%
0%
-1%
-1%
0%
-1%
0%
0%
-1%
-1%
0%
-1%
-1%
0%
High Response
-2%
-1%
0%
-2%
-1%
0%
-2%
-1%
0%
-2%
-1%
0%
-2%
-1%
0%
No Respose
-2%
0%
1%
-1%
0%
2%
-1%
1%
2%
-1%
0%
2%
-2%
0%
2%
Low Respose
-2%
0%
1%
-1%
0%
1%
-1%
1%
2%
-1%
0%
2%
-2%
0%
2%
Moderate Response
-2%
-1%
1%
-2%
0%
1%
-2%
0%
2%
-2%
0%
1%
-2%
0%
1%
High Response
-3%
-1%
0%
-2%
-1%
0%
-2%
0%
1%
-2%
-1%
0%
-3%
-1%
0%
No Respose
-3%
-1%
2%
-3%
1%
5%
-3%
0%
5%
-3%
1%
4%
-2%
2%
5%
Low Respose
-3%
-1%
2%
-3%
1%
5%
-3%
0%
5%
-3%
1%
4%
-2%
1%
5%
Moderate Response
-3%
-1%
1%
-3%
0%
4%
-3%
-1%
4%
-3%
0%
3%
-2%
1%
4%
High Response
-3%
-2%
1%
-3%
0%
3%
-4%
-1%
3%
-3%
0%
2%
-3%
0%
3%
No Respose
-2%
-1%
2%
-2%
1%
3%
-3%
0%
4%
-2%
1%
3%
-2%
1%
4%
Low Respose
-2%
-1%
1%
-2%
1%
3%
-3%
0%
4%
-2%
0%
3%
-2%
1%
4%
Moderate Response
-2%
-1%
1%
-2%
1%
3%
-3%
0%
3%
-2%
0%
2%
-2%
1%
3%
High Response
-2%
-1%
1%
-2%
0%
2%
-3%
-1%
3%
-2%
0%
2%
-2%
0%
2%
Notes:
Impacts are relative to the current TOU with expected future renewable GA costs included and allocated evenly across the rate periods.
Power Stream sample appears to include residential and non-residential customers; the other samples are limited to residential customers.
OEB Consultation Meeting
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Appendix C:
Sources
OEB Consultation Meeting
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Other TOU Rates (1)
On Peak
Price ¢/kWh
Off Peak
Price ¢/kWh
Peak/ Off
Peak Ratio
2 period, 2 season TOU
2 period, 2 season TOU
3 period summer, 2 period winter TOU
18.26
15.00
16.72
0.63
1.40
1.83
29.0
10.7
9.1
R-4
2-period, year-round TOU
9.20
1.30
7.1
D1.2
Rate TD
2 period, 2 season TOU
2 period, 2 season TOU
2 period, 2 season TOU, with two-tier inverted block
price off-peak
20.53
14.95
2.93
2.25
7.0
6.6
20.91
3.52
5.9
TOU-REO2
2 period, 2 season TOU with block pricing in winter
16.07
2.77
5.8
RG2
2 period, year-round TOU
15.04
2.74
5.5
RTE
2 period, 2 season TOU
3 period summer and winter, 1 period spring and fall
TOU
2 period, 2 season TOU
2 period, 2 season TOU; customers can choose from
3 time options to define their TOU periods
2-period, 1-season TOU plus load management
technology
20.84
3.85
5.4
17.06
3.66
4.7
15.16
3.51
4.3
17.70
4.17
4.2
7.92
1.87
4.2
Utility
Tariff Name
Description
ConEd
Dominion Virginia
Alabama Power Co
Massachusetts Electric Co
(National Grid)
Detroit Edison
Cinergy
Rate II
R1T
FDT
Commonwealth Edison (Exelon) Rate 1DR
Georgia Power
Wisconsin Electric Power Co
(WE Energies)
Duke Energy Corporation
Niagara Mohawk
SC-1C
Carolina Power & Light Co
Wisconsin Public Service
(WPS)
R-TOUE
AEP (Indiana Michigan Power)
RS-LMTOD
Time-of-Use
OEB Consultation Meeting
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Other TOU Rates (2)
Utility
Tariff Name
London Energy
Economy 7
Consumers Energy Company
A-3
Electricidade de Portugal
tarifa trihoraria
Los Angeles (LADWP)
Time-of-Use
Long Island Power Authority
Rate 184
Ameren Union Electric
PG&E
PECO Energy
Pennsylvania Power and Light
(PP&L)
Jacksonville Electric
Arizona Public Service Co
Pacific Power (PacifiCorp)
Baltimore Gas and Electricity
(BGE)
El Paso Electric
Description
2-period, year-round TOU; low period is composed of
2 declining blocks
2 period, year round TOU
Demand subscription (3.45 to 20.7 kW) + 3 period,
year-round TOU energy rate.
3 period, year-round TOU
2 period, 2 season TOU, with two-tier inverted block
price by usage level
Optional Time of Day
2 period, 2 season TOU
Rate
E-7
2 period, 2 season TOU, with customer baseline
RT
2 period, 2 season TOU
On Peak
Price ¢/kWh
Off Peak
Price ¢/kWh
Peak/ Off
Peak Ratio
13.17
3.17
4.2
14.60
3.60
4.1
27.33
6.75
4.0
14.30
3.80
3.8
27.60
7.70
3.6
11.11
3.24
3.4
29.37
22.71
8.66
6.83
3.4
3.3
Time-of-Day
2 period, year-round TOU
15.84
4.80
3.3
Time-of-Day
ET-1
RS4
4 period summer, 2 period winter TOU
2 period, 2 season TOU
4 period, 2 season TOU
8.46
13.30
6.12
2.59
4.30
2.19
3.3
3.1
2.8
RL-2
3-period, 2-season TOU
8.04
2.99
2.7
Alternate Time-ofUse
2 period, year-round TOU
12.52
4.75
2.6
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Other TOU Rates (3)
Utility
Tariff Name
Description
Electricidade de Portugal
tarifa bihoraria
Demand subscription (3.45 to 20.7 kW in 10
increments) + 2 period, year-round TOU energy rate.
SMUD
PG&E
NUON
Jersey Central Power & Light
(First Energy)
Kansas City Power and Light
(KCPL)
Bangor Hydro
Optional Time of Use
2 period, 2 season TOU
Rate
E-2
2 period, 2 season TOU
Strom zakelijk
2-period, year-round TOU
On Peak
Price ¢/kWh
Off Peak
Price ¢/kWh
Peak/ Off
Peak Ratio
17.13
6.75
2.5
20.39
8.09
2.5
23.97
8.09
9.84
3.43
2.4
2.4
RT
2 period, 2 season TOU
16.80
7.20
2.3
RTOD
3 period, 2 season TOU
11.34
4.88
2.3
Time-of-Use
2 period, 2 season TOU
9.36
4.14
2.3
Public Service Elec & Gas Co
Residential Load Mgt 2 period, 2 season TOU
17.19
7.74
2.2
Boston Edison (NSTAR)
Dominion Virginia
United Illuminating (UI)
Arizona Public Service Co
R-5
R1S
RT
ECT-1R
Time-of-Day + PEM
(personal energy
mgt)
Zeitzonen
2 period, 2 season TOU
2 period, 2 season TOU for energy and demand
2 period, 2 season TOU
2 period, 2 season TOU for energy and demand
19.09
3.72
17.90
4.80
9.12
1.80
8.70
2.60
2.1
2.1
2.1
1.8
4-period, 2-season TOU
6.80
3.80
1.8
2 period, year-round TOU
23.35
13.41
1.7
Puget Sound Energy (PSE)
Bewag
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Other TOU Rates (4)
On Peak
Price ¢/kWh
Off Peak
Price ¢/kWh
Peak/ Off
Peak Ratio
2 period, year-round TOU
2 period, year round TOU
2 period, 2 season TOU for energy and demand
3 period summer, 1 period winter TOU
2 period, 2 season TOU for energy and demand
2 period, 2 season TOU, experimental
Demand subscription (3-15 kVA) + 2 period, yearTariffa bioraria “Due”
round TOU, with 3 options
Tidstariff
2 period winter, 1 period summer TOU
23.80
11.47
4.88
7.08
4.84
13.38
13.81
7.97
3.51
5.58
3.85
10.88
1.7
1.4
1.4
1.3
1.3
1.2
15.28
12.78
1.2
11.54
10.13
1.1
R-TM
11.42
10.41
1.1
Utility
Tariff Name
EnviaM
Connecticut Light & Power Co
Carolina Power & Light Co
Idaho Power
Duke Energy Corporation
SDG&E
EnviaM base night
Rate 7
R-TOUD
Time-of-Day
RT
DR-TOU
ENEL SPA
Vattenfall
Potomac Electric Power
(PEPCO)
Description
3 period, 2 season TOU
Ohio Edison (First Energy)
Optional Time of Day flat energy charge + demand charge; TOU periods
Rate
are described but no time-dependent rates are given
2.91
2.91
1.0
Public Service Co of Colorado
(Xcel)
RT
2 period, year round demand only TOU, energy is flat
rate
1.65
1.65
1.0
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RPP TOU Pilot Impact Studies
Hydro One Networks Inc. Time-of-Use Pricing Pilot Project
Results, May 2008.
Navigant Consulting, Inc., Evaluation of Individual Metering and
Time-of-Use Pricing Pilot: Presented to Newmarket Hydro
Ltd., March 4, 2008.
Navigant Consulting, Inc., Evaluation of Time-of-Use Pricing
Pilot: Presented to Veridian Connections, March 18, 2008.
Navigant Consulting, Inc., Evaluation of Individual Metering and
Time-of-Use Pricing Pilot: Presented to Oakville Hydro
Electricity Distribution, Inc., March 18, 2008.
Ontario Energy Board, prepared by IBM Global Business
Services and eMeter Strategic Consulting, Ontario Energy
Board Smart Price Pilot Final Report, July 2007.
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Other references on TOU and dynamic pricing rates
♦ Chao, Hung-po. “Connecting the Wholesale and Retail Markets,” GridWeek
♦
♦
♦
♦
♦
♦
2010, Washington, D.C.
Centolella, Paul. “Smart Pricing: The Key to Smart Grid Benefits,” GridWeek
2010, Washington, D.C.
Faruqui, Ahmad. “The Ethics of Dynamic Pricing,” The Electricity Journal,
July 2010.
Faruqui, Ahmad. “Residential dynamic pricing and ‘energy stamps’,”
Regulation, December 2010, forthcoming.
Faruqui, Ahmad and Sanem Sergici. “Household response to dynamic pricing
of electricity–a survey of 15 experiments,” Journal of Regulatory Economics
(2010), 38:193-225
Institute for Electric Efficiency. The Impact of Dynamic Pricing on Low
Income Customers. An IEE Whitepaper. September 2010.
http://www.edisonfoundation.net/IEE/reports/IEE_LowIncomeDynamicPricing
_0910.pdf.
Morgan, Rick. “Rethinking ‘dumb’ rates,” Public Utilities Fortnightly, March
1, 2009.
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