presentation: assessing ontario's regulated price plan

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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


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


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


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


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


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


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


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


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


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


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


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%)


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


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


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


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


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


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


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





-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





-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





-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



-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




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


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)


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


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


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.


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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Appendix A: Current TOU


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


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


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.


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


Appendix B: Alternate TOU Designs


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)



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)



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

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Today's TOU w/ Renewables and4 Hour Peak - Summer OnlyAverage Supply Cost (With NewRenewables)



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

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Marginal Cost-Based RateAverage Supply Cost (No New Renewables)


♦ 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


Appendix C: Summary of Bill Impacts


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%


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


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


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







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


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%


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%


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%


High Response -2% -1% 1% -2% 0% 2% -3% -1% 3% -2% 0% 2% -2% 0% 2%







Appendix C: Sources


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


Other TOU Rates (2)




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


Other TOU Rates (3)




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


Other TOU Rates (4)




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


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.


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.

http://www.edisonfoundation.net/IEE/reports/IEE_LowIncomeDynamicPricing_0910.pdf

http://www.edisonfoundation.net/IEE/reports/IEE_LowIncomeDynamicPricing_0910.pdf

presentation: assessing ontario's regulated price plan

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