presentation: assessing ontario's regulated price plan
TRANSCRIPT
Antitrust/Competition Commercial Damages Environmental Litigation and Regulation Forensic Economics Intellectual Property International Arbitration International Trade Product Liability Regulatory Finance and Accounting Risk Management Securities Tax Utility Regulatory Policy and Ratemaking Valuation Electric Power Financial Institutions Natural Gas Petroleum Pharmaceuticals, Medical Devices, and Biotechnology Telecommunications and Media Transportation
Copyright © 2010 The Brattle Group, Inc. www.brattle.com
Assessing Ontario’sRegulated Price Plan
Ahmad FaruquiRyan Hledik
Ontario Energy Board Consultation MeetingToronto, Ontario
December 21, 2010
2OEB Consultation Meeting
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
3OEB Consultation Meeting
We explored the merits of alternative TOU design options in Ontario
Step 1:Review Existing
TOU Rate
Step 2:Identify Areas for
Improvement
Step 3:Establish
Alternatives
Step 4:Evaluate the Alternatives
Benchmark rate against industry best practices
Review TOU impact evaluation studies
Simulate expected rate impacts under full deployment
Peak-to-off-peak price ratio is too small
Expected range of bill impacts not fully understood
Further research on rate impacts (pilots) needed
Identify aspects of TOU that can be modified
Modify aspects of TOU design to create attractive alternative rate options
Simulate expected impacts of rate options
Define rate evaluation criteria
Assess pros and cons of each rate option
Summarize rate evaluation and present recommendations
Overview of Project Approach
4OEB Consultation Meeting
Ontario’s transition to TOU pricing is in progress
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
Currently ~2.8 million enrolled Currently ~1.2 million enrolled
Note:
Prices represent only the generation component of the rate.
Transitioning from the tiered rate… … to a TOU rate
$0.053
$0.053
$0.099
$0.080
$0.099
0.00
0.02
0.04
0.06
0.08
0.10
0.12
0.14
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour StartingG
ener
atio
n R
ate
(C$/
kWh)
Summer TOU
Winter TOU
$0.065$0.075
0.00
0.02
0.04
0.06
0.08
0.10
0.12
0.14
0 200 400 600 800 1000 1200 1400 1600
Monthly Usage (kWh)
Gen
erat
ion
Rat
e (C
$/kW
h)
Summer Tiered
Winter Tiered
5OEB Consultation Meeting
The majority of hours are in the low-priced off-peak period, an attractive feature for customers
Summer TOU Hour Allocation
Off-peak261059%
On-peak774
18%
Mid-peak103223%
Winter TOU Hour Types
Mid-peak76218%
On-peak101623%
Off-peak256659%
There is a larger share of peak hours in the winter than in the summer
6OEB Consultation Meeting
Each defining characteristic of the TOU rate was benchmarked against industry best practices
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
Average customer cost neutrality
Moderate Calculation is reasonable given available data; focus on province-wide supply cost recovery can
have differential impacts on customers
Price ratio Weak Price ratio is low relative to TOU programs in other jurisdictions; likely to produce modest
customer response or bill savings
Results of Benchmarking
7OEB Consultation Meeting
System load and hourly energy prices align well in shape with the TOU rate
System Load, LMP, and TOU RateAverage Summer Day
-
5,000
10,000
15,000
20,000
25,000
30,000
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
Hour Starting
Syst
em L
oad
(MW
)
$-
$0.02
$0.04
$0.06
$0.08
$0.10
$0.12
Rat
e (C
$/kW
h)
LoadAvg Energy Price (2004-2010)TOU
System Load Data from 2009LMP Data from 2009
System Load, LMP, and TOU RateAverage Winter Day
-
5,000
10,000
15,000
20,000
25,000
30,000
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
Hour StartingSy
stem
Loa
d (M
W)
$-
$0.02
$0.04
$0.06
$0.08
$0.10
$0.12
Rat
e (C
$/kW
h)
LoadAvg Energy Price (2004-2010)TOU
System Load Data from 2009LMP Data from 2009
There is a fairly broad summer peak and a dual peak in the winter
8OEB Consultation Meeting
The peak-to-off-peak price ratio is low relative to TOU rates elsewhere
RPP TOU Price Ratios
Generation Only: 1.9 to 1.5 to 1
All-in: 1.4 to 1.2 to 1
0
2
4
6
8
10
12
14
16
0 1 2 3 4 5 6 7 8 9 10 11
Price Ratio (Peak / Off Peak)
Num
ber
of T
OU
Pro
gram
s
Note: Excludes ConEdison Residential "Rate II" which has a price ratio of 29 to 1.
Distribution of Price Ratios in Existing TOU Rates (Generation Only)
RPP TOU ratio = 1.9
Mean ratio = 3.8
Note: Details on each TOU rate are provided in the appendix
This ratio could be adjusted to better reflect system conditions
9OEB Consultation Meeting
There are many ways to increase the price ratio
Depends on how prices are set; combined with other rate design approaches, smaller number of periods could be beneficial
Remove mid-peak period to create 2 period rate
Three periods (peak, mid-peak, and off-peak)
Number of periods
Changes in the supply cost structure could increase or decrease the price ratio under this approach
Set peak and mid-peak price, solve for off-peak price
Set off-peak and mid-peak price, solve for peak price
Price setting methodology
Summer-only means fewer peak hours and therefore higher peak price
Summer-only TOU with off-peak rate applying during the winter months
Year-roundSeasonality
Shorter peak period spreads capacity costs over fewer peak hours, increasing the peak price
Shorten peak and mid-peak period to 4 hours in both seasons
6 hour peak, 8 hour mid-peak (opposite in non-summer months)
Peak Duration
Increases peak costs, decreases off-peak costs, and increases price ratio
Allocate wind & solar to peak period, account for expected FIT costs
Existing GA costs only, allocated uniformly across periods
Renewables Cost Reallocation
Likely Impact on Price RatioAlternative option…
In Existing TOU…
Rate Design Option
10OEB Consultation Meeting
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
0
1
2
3
4
5
6
Existing TOU Reallocation of Wind/Solar
GA Cost
4 Hour PeakPeriod
Summer Only AlternativePeak Price,
2 Periods
Gen
erat
ion-
only
Pea
k to
Off
-Pea
k Pr
ice
Rat
io
4.9
3.2
2.7
1.9
4.1
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
11OEB Consultation Meeting
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
12OEB Consultation Meeting
The pilots are moderately applicable for extrapolation of TOU impacts at the province level
Based on this screening, we have selected the Hydro One, Newmarket Hydro, and Hydro Ottawa pilots for more detailed analysis
Applicability of Pilot Results for Province-Wide Assessment
Utility Applicability of Results Reason
Hydro One 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
13OEB Consultation Meeting
The results from the 3 most relevant pilots were benchmarked against informed expectations
♦ 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
Comparison of Peak Impacts Across Pilots
-1.2%
-1.8%-2.3%
-0.4%
-2.4%
-3.7%
-5.0%
-4.0%
-3.0%
-2.0%
-1.0%
0.0%Connecticut California Maryland
NewmarketHydro Hydro Ottawa Hydro One
Cha
nge
in D
eman
d D
urin
g Pe
ak P
erio
d
Calibrated Impacts from Other Pilots Impacts from Ontario Pilots
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 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%)
14OEB Consultation Meeting
There is significant variation in overall energy consumption impacts across the pilots
♦ This variation is partly 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 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%)
Comparison of Energy Consumption Impacts Across Pilots
0.4% 0.3% 0.4%1.1%
-3.3%
-6.0%-7.0%
-6.0%
-5.0%
-4.0%
-3.0%
-2.0%
-1.0%
0.0%
1.0%
2.0%Connecticut California Maryland
NewmarketHydro Hydro One Hydro Ottawa
Cha
nge
in U
sage
Dur
ing
Stud
y Pe
riod
Calibrated Impacts from Other Pilots Impacts from Ontario Pilots
15OEB Consultation Meeting
Implied elasticities from the Ontario pilots were integrated into Brattle’s Price Impact Simulation Model (PRISM)
Customer’s peak period usage
Customer’s off-peak period usage
Central air-conditioning saturation
Weather
Geographic location
Customer class(e.g. residential, C&I)
All-in peak price of new rate
All-in off-peak price of new rate
Load-wtd avg daily all-in price of new rate
Existing flat rate
Peak-to-off-peak usage ratio
Model Inputs
Peak-to-off-peak price ratio
Elasticity of substitution
Daily price elasticity
Difference between new rate (daily
average) and existing flat rate
Basic Driversof Impacts
Substitution effect (i.e. load shifting)
Daily effect (i.e. conservation or
load building)
Overall change in load shape
(peak and off-peak by day)
Load Shape Effects Aggregate Load Shape and Energy
Consumption Impact
The PRISM Modeling Framework
16OEB Consultation Meeting
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
17OEB Consultation Meeting
Four alternative TOU rate designs were developed based on our findings
4.1-to-1Peak 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
Rate #4:Alternative peak price+ 2 period
4.9-to-1Rate #2 but also with TOU rate limited to summer months (May through October); flat rate applies other months
Rate #3:Wind/solar reallocation+ 4-hour peak+ summer only
3.2-to-1Rate #1 but also with peak and mid-peak windows reduced to four hours
Rate #2:Wind/solar reallocation+ 4-hour peak
2.7-to-1The existing TOU with the addition and reallocation of expected wind and solar GA costs to the peak period
Rate #1:Wind/solar reallocation
Price ratioDescriptionAlternative TOU
See Appendix B for details of these four alternative rate designs
18OEB Consultation Meeting
The average peak impacts of the four rate alternatives range from 1% to 4% and could be as high as 7%
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
0.9%1.4%
2.0%
4.0%3.3%
0%
1%
2%
3%
4%
5%
6%
7%
8%
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
Peak
Red
uctio
n
Range represents impacts from "high" and "low" response estimates
Range of Average RPP Customer Response Projections
19OEB Consultation Meeting
The rates will impact each customer differently depending on their consumption profile
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
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
Hou
rly E
lect
ricity
Usa
ge (k
W)
"Peaky" customer
"Flat" customer
"Average" customer
Three Illustrative Customer Consumption Profiles ♦ “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
20OEB Consultation Meeting
Across samples from 5 utilities, changes in customer bills will range from -12% to +18%
Note: Results shown for Rate #3 before any customer response and are relative to today’s TOU
Distribution of Bill Impacts for Rate #3 (Before Response)
-20%
-15%
-10%
-5%
0%
5%
10%
15%
20%
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%Percentile
Gen
erat
ion-
Onl
y B
ill C
hang
e (%
)
Toronto Hydro
Avgbillincrease
Avgbilldecrease
21OEB Consultation Meeting
Across samples from 5 utilities, changes in customer bills will range from -12% to +18%
Note: Results shown for Rate #3 before any customer response and are relative to today’s TOU
Distribution of Bill Impacts for Rate #3 (Before Response)
-20%
-15%
-10%
-5%
0%
5%
10%
15%
20%
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%Percentile
Gen
erat
ion-
Onl
y B
ill C
hang
e (%
)
Thunder Bay
Toronto Hydro
Avgbillincrease
Avgbilldecrease
22OEB Consultation Meeting
Across samples from 5 utilities, changes in customer bills will range from -12% to +18%
Note: Results shown for Rate #3 before any customer response and are relative to today’s TOU
Distribution of Bill Impacts for Rate #3 (Before Response)
-20%
-15%
-10%
-5%
0%
5%
10%
15%
20%
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%Percentile
Gen
erat
ion-
Onl
y B
ill C
hang
e (%
)
Newmarket
Thunder Bay
Toronto Hydro
Avgbillincrease
Avgbilldecrease
23OEB Consultation Meeting
Across samples from 5 utilities, changes in customer bills will range from -12% to +18%
Note: Results shown for Rate #3 before any customer response and are relative to today’s TOU
Distribution of Bill Impacts for Rate #3 (Before Response)
-20%
-15%
-10%
-5%
0%
5%
10%
15%
20%
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%Percentile
Gen
erat
ion-
Onl
y B
ill C
hang
e (%
)
PowerStreamNewmarketThunder BayToronto Hydro
Avgbillincrease
Avgbilldecrease
24OEB Consultation Meeting
Across samples from 5 utilities, changes in customer bills will range from -12% to +18%
-20%
-15%
-10%
-5%
0%
5%
10%
15%
20%
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%Percentile
Gen
erat
ion-
Onl
y B
ill C
hang
e (%
)
PowerStreamNewmarketThunder BayToronto HydroMilton Hydro
Avgbillincrease
Avgbilldecrease
Note: Results shown for Rate #3 before any customer response and are relative to today’s TOU
Distribution of Bill Impacts for Rate #3 (Before Response)
25OEB Consultation Meeting
After customers shift consumption, a higher percentage will experience bill savings
-10%
-8%
-6%
-4%
-2%
0%
2%
4%
6%
8%
10%
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%Percentile
Gen
erat
ion-
Onl
y B
ill C
hang
e (%
)
Bill impact before customer response
Bill impact after customer response ("high" case)
Customer response results in greater bill savings and a larger share of customers with an incremental bill decrease
Note: Results shown for Rate #3 for Toronto Hydro sample; see Appendix C for full results
Bill Impacts Before and After Customer Response
26OEB Consultation Meeting
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
20,000
20,500
21,000
21,500
22,000
22,500
23,000
23,500
24,000
24,500
25,000
0 50 100 150 200Top 200 Hours
Syst
em L
oad
(MW
)
System Load without TOUSystem Load with Largest Projected TOU Impact
Reduction in system peak due to largest simulated TOU impact = 4% (1,064 MW)
27OEB Consultation Meeting
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
28OEB Consultation Meeting
The Path Forward
While this option carries little risk, alone it does not lead to greater customer response rates
Conduct an impact assessment of customer consumption behavior after the full transition to the TOU rate
Better understand customer responsiveness
This would require a major overhaul of the current methodology and would require significant research to determine the appropriate marginal cost assumptions
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
Simplify the rate-setting process
Customer education improves response but cannot lead to greater bill savings if the rate design does not offer the opportunity to significantly reduce bills
Work with utilities to initiate an education campaign around the rate and its benefits, possibly including the provision of enabling technologies
Improve customer response and perception
Significant design changes will require re-education of utilities, policymakers, and customers regarding the new rate structure
Consider significant rate design changes that decrease the number of peak hours (such as seasonality and a shorter peak period)
Improve the price ratio
This only marginally improves the price ratio
Continue with the current design and simply reallocate renewables costs to the peak period
Minimize the implementation burden
But be aware…Then the OEB could…If the top priority is to…
Combinations of these approaches could achieve balance across priorities, but would be more complex
29OEB Consultation Meeting
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.
30OEB Consultation Meeting
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.
31OEB Consultation Meeting
About The Brattle Group
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
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.
[email protected] Sacramento Street, Suite 1140
San Francisco, CA 94111
32OEB Consultation Meeting
Appendix A: Current TOU
33OEB Consultation Meeting
Today’s TOU has a 10-hour off-peak period and a price ratio of 1.9
Illustration of Today's TOUPeak Summer Day
-
4
8
12
16
20
24
28
32
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
Gen
erat
ion
Rat
e (c
ents
/kW
h)
Today's TOU
Average Supply Cost (No New Renewables)
Peak to off-peak price ratio = 1.9
34OEB Consultation Meeting
2009 IESO System Load
-
5,000
10,000
15,000
20,000
25,000
30,000
Jan-09 Feb-09 Mar-09 Apr-09 May-09 Jun-09 Jul-09 Aug-09 Sep-09 Oct-09 Nov-09 Dec-09
Syst
em L
oad
(MW
)The seasonal definition lines up with historical IESO load data
Summer (May – Oct)
♦ Ontario is mostly a 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
35OEB Consultation Meeting
2008 Hourly Ontario Energy Price (HOEP)
(100)
-
100
200
300
400
500
600
Jan-08 Feb-08 Mar-08 Apr-08 May-08 Jun-08 Jul-08 Aug-08 Sep-08 Oct-08 Nov-08 Dec-08
Syst
em L
oad
(MW
)There is a less pronounced seasonal pattern in the historical energy price data
Summer (May – Oct) ♦ Prices are more volatile in the summer season
♦ In 2008, the price exceeded $200/MWh in 15 hours, most of which were in the summer
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.
36OEB Consultation Meeting
TOU pricing pilots in Ontario
Notes:“MUSH” is municipals, universities, schools, and hospitalsIn some pilots the TOU rate changed over time. In this table, the range is provided.
Overview of Ontario TOU Pilots
Utility Classes of Participants
Number of TOU Participants
Total Number of Pilot Participants Treatment Period TOU Rate
(cents/kWh) Notes
Newmarket Hydro Residential 39 220 Aug 06 - Oct 07P: 9.2M: 7.2O: 3.2
Pilot also tested CPR and controllable thermostats
Hydro One Residential, farm, small C&I (<50 kW) 177 500 May 07 - Sep 07
P: 9.7M: 7.1O: 3.4
Pilot also tested in-home displays
Hydro Ottawa Residential 124 375 Aug 06 - Feb 07P: 9.7 - 10.5M: 7.1 - 7.5O: 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 - 10.5M: 7.1 - 7.5O: 3.2 - 3.5
Pilot primarily tested impact of transition from bulk-metered building to
individually metering residents
Veridian ConnectionsMulti-res and MUSH, all bulk-metered and
>200 kW38 38 Feb 07 - Sep 07
P: 9.2 - 9.7M: 7.1 - 7.2O: 3.2 - 3.4
Pilot only focused on TOU rate
37OEB Consultation Meeting
Appendix B: Alternate TOU Designs
38OEB Consultation Meeting
Rate #1: Today’s TOU with re-allocation (and addition) of renewable GA costs
♦ 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%
Illustration of Today's TOU w/ RenewablesPeak Summer Day
-
4
8
12
16
20
24
28
32
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
Gen
erat
ion
Rat
e (c
ents
/kW
h)
Today's TOU w/ Renewables
Average Supply Cost (With New Renewables)
Peak to off-peak price ratio = 2.7
39OEB Consultation Meeting
Rate #2: Today’s TOU with renewable cost re-allocation and a four-hour peak period
♦ 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
Illustration of Today's TOU w/ Renewables & 4 Hour PeakPeak Summer Day
-
4
8
12
16
20
24
28
32
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
Gen
erat
ion
Rat
e (c
ents
/kW
h)
Today's TOU w/ Renewables and 4 Hour Peak
Average Supply Cost (With New Renewables)
Peak to off-peak price ratio = 3.2
40OEB Consultation Meeting
Rate #3: Summer-only TOU with renewable cost re-allocation and a four-hour peak period
♦ 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
Illustration of Today's TOU w/ Renewables & 4 Hour Peak - Summer Only Peak Summer Day
-
4
8
12
16
20
24
28
32
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
Gen
erat
ion
Rat
e (c
ents
/kW
h)
Today's TOU w/ Renewables and4 Hour Peak - Summer OnlyAverage Supply Cost (With NewRenewables)
Peak to off-peak price ratio = 4.9
41OEB Consultation Meeting
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
-
4
8
12
16
20
24
28
32
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
Gen
erat
ion
Rat
e (c
ents
/kW
h)
Marginal Cost-Based RateAverage Supply Cost (No New Renewables)
Peak to off-peak price ratio = 4.1
♦ The peak price is equal to an average peak energy price of $0.068/kWh plus a capacity price of $100/kW-year, 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
42OEB Consultation Meeting
Appendix C: Summary of Bill Impacts
43OEB Consultation Meeting
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 Toronto Hydro Power Stream Thunder Bay Newmarket Milton Hydro10th % 50th % 90th % 10th % 50th % 90th % 10th % 50th % 90th % 10th % 50th % 90th % 10th % 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.
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
44OEB Consultation Meeting
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 Toronto Hydro Power Stream Thunder Bay Newmarket Milton Hydro10th % 50th % 90th % 10th % 50th % 90th % 10th % 50th % 90th % 10th % 50th % 90th % 10th % 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.
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
45OEB Consultation Meeting
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 Toronto Hydro Power Stream Thunder Bay Newmarket Milton Hydro10th % 50th % 90th % 10th % 50th % 90th % 10th % 50th % 90th % 10th % 50th % 90th % 10th % 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.
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
46OEB Consultation Meeting
Appendix C: Sources
47OEB Consultation Meeting
Other TOU Rates (1)
Utility Tariff Name Description On Peak Price ¢/kWh
Off Peak Price ¢/kWh
Peak/ Off Peak Ratio
ConEd Rate II 2 period, 2 season TOU 18.26 0.63 29.0Dominion Virginia R1T 2 period, 2 season TOU 15.00 1.40 10.7Alabama Power Co FDT 3 period summer, 2 period winter TOU 16.72 1.83 9.1Massachusetts Electric Co (National Grid) R-4 2-period, year-round TOU 9.20 1.30 7.1
Detroit Edison D1.2 2 period, 2 season TOU 20.53 2.93 7.0Cinergy Rate TD 2 period, 2 season TOU 14.95 2.25 6.6
Commonwealth Edison (Exelon) Rate 1DR 2 period, 2 season TOU, with two-tier inverted block price off-peak 20.91 3.52 5.9
Georgia Power TOU-REO2 2 period, 2 season TOU with block pricing in winter 16.07 2.77 5.8
Wisconsin Electric Power Co (WE Energies) RG2 2 period, year-round TOU 15.04 2.74 5.5
Duke Energy Corporation RTE 2 period, 2 season TOU 20.84 3.85 5.4
Niagara Mohawk SC-1C 3 period summer and winter, 1 period spring and fall TOU 17.06 3.66 4.7
Carolina Power & Light Co R-TOUE 2 period, 2 season TOU 15.16 3.51 4.3Wisconsin Public Service (WPS) Time-of-Use 2 period, 2 season TOU; customers can choose from
3 time options to define their TOU periods 17.70 4.17 4.2
AEP (Indiana Michigan Power) RS-LMTOD 2-period, 1-season TOU plus load management technology 7.92 1.87 4.2
48OEB Consultation Meeting
Other TOU Rates (2)
Utility Tariff Name Description On Peak Price ¢/kWh
Off Peak Price ¢/kWh
Peak/ Off Peak Ratio
London Energy Economy 7 2-period, year-round TOU; low period is composed of 2 declining blocks 13.17 3.17 4.2
Consumers Energy Company A-3 2 period, year round TOU 14.60 3.60 4.1
Electricidade de Portugal tarifa trihoraria Demand subscription (3.45 to 20.7 kW) + 3 period, year-round TOU energy rate. 27.33 6.75 4.0
Los Angeles (LADWP) Time-of-Use 3 period, year-round TOU 14.30 3.80 3.8
Long Island Power Authority Rate 184 2 period, 2 season TOU, with two-tier inverted block price by usage level 27.60 7.70 3.6
Ameren Union Electric Optional Time of Day Rate 2 period, 2 season TOU 11.11 3.24 3.4
PG&E E-7 2 period, 2 season TOU, with customer baseline 29.37 8.66 3.4PECO Energy RT 2 period, 2 season TOU 22.71 6.83 3.3Pennsylvania Power and Light (PP&L) Time-of-Day 2 period, year-round TOU 15.84 4.80 3.3
Jacksonville Electric Time-of-Day 4 period summer, 2 period winter TOU 8.46 2.59 3.3Arizona Public Service Co ET-1 2 period, 2 season TOU 13.30 4.30 3.1Pacific Power (PacifiCorp) RS4 4 period, 2 season TOU 6.12 2.19 2.8Baltimore Gas and Electricity (BGE) RL-2 3-period, 2-season TOU 8.04 2.99 2.7
El Paso Electric Alternate Time-of-Use 2 period, year-round TOU 12.52 4.75 2.6
49OEB Consultation Meeting
Other TOU Rates (3)
Utility Tariff Name Description On Peak Price ¢/kWh
Off Peak Price ¢/kWh
Peak/ Off Peak Ratio
Electricidade de Portugal tarifa bihoraria Demand subscription (3.45 to 20.7 kW in 10 increments) + 2 period, year-round TOU energy rate. 17.13 6.75 2.5
SMUD Optional Time of Use Rate 2 period, 2 season TOU 20.39 8.09 2.5
PG&E E-2 2 period, 2 season TOU 23.97 9.84 2.4NUON Strom zakelijk 2-period, year-round TOU 8.09 3.43 2.4Jersey Central Power & Light (First Energy) RT 2 period, 2 season TOU 16.80 7.20 2.3
Kansas City Power and Light (KCPL) RTOD 3 period, 2 season TOU 11.34 4.88 2.3
Bangor Hydro 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) R-5 2 period, 2 season TOU 19.09 9.12 2.1Dominion Virginia R1S 2 period, 2 season TOU for energy and demand 3.72 1.80 2.1United Illuminating (UI) RT 2 period, 2 season TOU 17.90 8.70 2.1Arizona Public Service Co ECT-1R 2 period, 2 season TOU for energy and demand 4.80 2.60 1.8
Puget Sound Energy (PSE)Time-of-Day + PEM (personal energy mgt)
4-period, 2-season TOU 6.80 3.80 1.8
Bewag Zeitzonen 2 period, year-round TOU 23.35 13.41 1.7
50OEB Consultation Meeting
Other TOU Rates (4)
Utility Tariff Name Description On Peak Price ¢/kWh
Off Peak Price ¢/kWh
Peak/ Off Peak Ratio
EnviaM EnviaM base night 2 period, year-round TOU 23.80 13.81 1.7Connecticut Light & Power Co Rate 7 2 period, year round TOU 11.47 7.97 1.4Carolina Power & Light Co R-TOUD 2 period, 2 season TOU for energy and demand 4.88 3.51 1.4Idaho Power Time-of-Day 3 period summer, 1 period winter TOU 7.08 5.58 1.3Duke Energy Corporation RT 2 period, 2 season TOU for energy and demand 4.84 3.85 1.3SDG&E DR-TOU 2 period, 2 season TOU, experimental 13.38 10.88 1.2
ENEL SPA Tariffa bioraria “Due” Demand subscription (3-15 kVA) + 2 period, year-round TOU, with 3 options 15.28 12.78 1.2
Vattenfall Tidstariff 2 period winter, 1 period summer TOU 11.54 10.13 1.1Potomac Electric Power (PEPCO) R-TM 3 period, 2 season TOU 11.42 10.41 1.1
Ohio Edison (First Energy) Optional Time of Day Rate
flat energy charge + demand charge; TOU periods 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
51OEB Consultation Meeting
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.
52OEB Consultation Meeting
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.