January 2014

January 2014

Cost of Electricity Service2013 LTEP: Module 4

Overview

Cost for Electricity

Service

Sources of Revenue for Suppliers of

Electricity Services

Customer Bill & Rates

• Generation• Conservation• Transmission• Distribution•Wholesale

• Debt Retirement

Components of Cost

• Hourly Markets• Global

Adjustment

• Residential• Large Industrial

Customers

- Methodology- Categories

Note: Tabulation of data for figures shown in this module is contained in the Appendix

2

This module will walk you through the steps used to develop the cost for electricity service associated with the 2013 LTEP. It also provides the details to building the typical residential bill forecast and industrial prices.

The basis for cost projections

• The cost projections made in this analysis are based on many assumptions. As will become evident throughout this analysis, there are many considerations affecting costs/bills that will change over time

• We present annual averages in this analysis. More detailed, more current estimates for each of the components are developed for settlement/rate setting purposes

• The journey from cost to customer bills is complex because of the number of service providers, the different ways they get paid, the factors that affect costs, and the process of allocation of costs to customers

3

Electricity Service is comprised of the following categories

i. Electricity Generation: All payments to generators for the production of the electricity commodity. This includes payments pursuant to contracts, regulated rates or market clearing prices as established/negotiated by the generating facility.

ii. Electricity Conservation: This includes energy efficiency and demand response costs that are recovered by electricity ratepayers (i.e. excludes the equipment investments made by the customer implementing the conservation initiative).

iii. Transmission Delivery System: The regulated revenue requirements for the high-voltage transmission required to transport electricity from the generators to the low-voltage distribution delivery system

iv. Distribution Delivery System: The regulated revenue requirements for the low-voltage distribution delivery system required to transport electricity to retail customers embedded in an LDC

v. Wholesale Market Services: These costs include: payments for constraints and losses, provisions for reserves, black starts, IESO administration fee, OPA administration fee, rural and remote electricity rate protection. These costs reflect the operation and administration cost for the electricity system.

vi. Debt Retirement Charge: The Electricity Act, 1998, O. Reg. 493/01 imposes a charge which is payable on electricity consumed in Ontario. This is applied to the $20.9 billion debt of the former Ontario Hydro and is collected on behalf of the Ontario Electricity Financial Corporation.

4

Generation62%

Conservation2%

Transmission8%

Distribution 19%

Wholesale4%

DRC5%

2014 = $18.7 B ($2012)

Electricity Service Cost in 2014

Generation62%

Conservation2%

Transmission8%

Distribution 19%

Wholesale4%

DRC5%

2014 = $18.7 B ($2012)

Market Services

5

Electricity Service Cost Projection

17.618.7

19.4 19.8 19.620.2 19.7 20.0 20.4 20.7

19.8 19.7 19.8 19.9 19.9 19.8 19.8 19.7 19.6 19.5

0.0

5.0

10.0

15.0

20.0

25.0

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

$201

2 Bi

llion

s

Generation Conservation* Transmission Distribution Wholesale DRC

* includes the Aboriginal, Municipal and Community Funds

• The above graph provides information consistent with Figure 6: Total Cost of Electricity Services, in the 2013 LTEP. 6

Electricity Service Cost - Generation





Adjustment


Customers


Service


• Debt Retirement

Components of Cost


7

Electricity Generation Cost Methodology

• The cost of electricity generation is the payment to generators for electricity. The majority of generation is under contract or regulated rates

• The capacity and production levels from each generator are estimated.

• The cost is then calculated based on the general contract terms or regulated rates.

• Costs are in real $2012 dollars. For analysis provided in nominal dollars, an inflation rate of 2% is assumed.

• No cost for carbon emission is assumed.

• For costing modeling purposed, planned flexibility is priced as generic SCGT.

• The natural gas price forecast for this analysis is March 2013 - Sproule Forecast: http://www.sproule.com/forecasts/archives

Generation62%

8

http://www.sproule.com/forecasts/archives

Generation Cost Projection by Resource

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

Tota

l Cos

t of G

ener

ation

(Rea

l $20

12 M

illio

ns)

Coal Nuclear Natural Gas Hydro Bio Wind Solar Planned Flexibility

9

0

100

200

300

400

500

600

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

$/M

Wh

(in $

2012

Raa

l)

Coal Nuclear Natural Gas and Planned Flexibility Hydro Bio Wind Solar

Generation Unit Cost by Resource

10

2018 Contribution to Summer

Peak Capacity MW

2018 Installed Capacity

MW

2018 Energy TWh

2018 Cost of

Generation $

Nuclear Hydro Non-Hydro Renewables Natural Gas Demand Response

Costs are added to the summary developed in module 3

11

29,400 MW

500 MW

Summer Capacity Contribution (%)

100 %

40,500 MW

9,000 MW

2,200 MW

6,400 MW

11,300 MW

71 %

23 %

84 %

89 %

600 MW

10,100 MW

9,400 MW

9,100 MW

11,300 MW

20 TWh

41 TWh

80 TWh

151 TWh

11 TWh

51 %

13 %

24 %

81 %

CapacityFactor (%) $ 13.1 B

$ 5.8 B

$ 2.0 B

$ 3.5 B

$ 1.8 B

$ 87/MWh

$73/MWh

$50/MWh

$177/MWh

$163/MWh


Peak Capacity MW

2018 Installed

Capacity MW



Peak Capacity MW

2018 Installed

Capacity MW



Peak Capacity MW

2018 Installed

Capacity MW


Electricity Service Cost - Conservation





Adjustment


Customers


Service


• Debt Retirement

Components of Cost


12

• This conservation cost includes energy efficiency and demand response costs that are recovered from electricity ratepayers (i.e. excludes the equipment investments made by the customer implementing the conservation initiative).

• Conservation assumptions for cost analysis

• Cumulative program savings assumptions

• As this component will develop further (eg: conservation details post framework definition), the budget and estimates will need to be flexible to accommodate the evolution of refining the program.

Conservation Delivery Cost AssumptionsConservation

2%

Conservation category Program Cost Assumptions

Energy Efficiency 2015-2020: approx 3.5 - 4¢/kWh2021-2025: approx 4 - 4.5¢/kWh 2026-2032: 4.5¢/kWh

Demand Response Cost of existing DR resources is based on current program costs. For modeling purposes, cost of new dispatchable DR resources is assumed to be same as SCGT ($130/kW-yr)

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032Program energy saving (TWh) 7 8 9 9 9 10 11 12 13 13 14 15 16 17 17 18 18 19 19 20DR program peak savings (MW) 539 539 528 528 528 528 528 628 778 928 1128 1328 1518 1538 1558 1568 1588 1608 1608 1618

13

Conservation Cost Projection

$-

$0.1

$0.2

$0.3

$0.4

$0.5

$0.6

$0.7

$0.8

$0.9

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

EE delivery cost DR delivery cost

$201

2 M

illio

ns

• Conservation delivery costs includes program and funds administration plus incentives. They exclude participants’ costs

• While participants of a conservation program may incur additional capital/equipment costs, these costs are not included in the total cost of electricity service estimate as they are not passed on to all Ontario electricity consumers. 14

Electricity Service Cost - Transmission





Adjustment


Customers


Service


• Debt Retirement

Components of Cost


15

Transmission Delivery Cost Methodology

• Transmission cost is estimated with a base cost of transmission for the planning period plus an incremental revenue requirement for the additional capital investments that occur during the planning period.

• Base transmission revenue requirement is based on the November 2, 2012, EB-2012-0031, Settlement Proposal filed by Hydro One Networks Inc. for 2013 and 2014 Transmission Rates.

• Incremental Revenue Requirement is based on the assumption of about $3 billion ($2012) in new capital investments occur during the 20 year planning period, for regional and system planning purposes.

Transmission8%

16

Transmission Delivery Cost Projection

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

$1.80

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

$201

2 Bi

llion

Base Transmission Incremental Transmission

17

Electricity Service Cost - Distribution

Sources of Revenue for Supplier of




Adjustment


Customers


Service


• Debt Retirement

Components of Cost


18

Distribution Delivery Cost Methodology

• There are over 70 local distribution utilities (LDCs) in Ontario.

• Revenue requirements for a distributor is primarily related to the distribution system infrastructure, meters and meter reading services, and customer care services (such as billing and customer information services).

• The distribution cost for this analysis is comprised of four components 1. Base distribution cost – OEB 2012 Yearbook Data2. Incremental distribution cost related to growth in households3. Smart meter and grid costs4. Incremental Low-Income Energy Assistance Program costs

• Given the large number of LDCs in the province, a proxy (not detailed assessments) is used to estimate the projection of costs. The proxy is the increase in number of households .

Distribution 19%

19

Distribution Delivery Cost Projection

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

$201

2 Bi

llion

s

Base Distribution Incremental Distibution Cost due to Household Growth

Smart Meter and Smart Grid Incremental Low Income Energy Assistance Program

20

Electricity Service Cost – Wholesale Market Services

Sources of Revenue for Supplier of




Adjustment


Customers


Service


• Debt Retirement

Components of Cost


21

Wholesale Market Services Methodology

The Wholesale Market Services were grouped into the following categories. Further description is provided on the next slide.1.Congestion Management Settlement Uplift Costs2.Energy Reliability (or ancillary ) Services3.Intertie Offer Guarantee4.IESO and OPA Administration Fee5.Rural and Remote Electricity Rate ProtectionThe cost methodology for this analysis is as follows: •The first three items listed above are assumed to grow in proportion to the generation cost. This of course is an approximation of a complex set of services.•IESO and OPA administration fees are held constant in real terms over time.•The rural and remote rate is held constant in nominal dollars over the planning period.

Wholesale4%

22

Wholesale Market Services

A comprehensive list of wholesale market services is outlined in the following IESO document: http://www.ieso.ca/imoweb/pubs/settlements/IMO_Charge_Types_and_Equations.pdf

For cost modeling purposes these services are grouped under five categories:

1.Congestion Management Settlement Uplift: represents the cost of dispatching the power system out of economic merit order in light of transmission or other physical constraints

2.Energy Reliability: services related to maintaining a balance between generation and demand during unanticipated events, such as equipment failure or a surge in consumption. The IESO purchases spare capability that is available on short notice. The cost of these types of services can vary by the hour. (i.e., black starts and provisions for reserves)

3.Intertie Offer Guarantee: a payment to reduce the risk for imports. Imports are settled on real-time prices but are scheduled on pre-dispatch prices, which may be different. The Intertie Offer Guarantee ensures that, over the course of an hour, an importer would receive at least the average price of their offer.

4.IESO and OPA Administration Fee: an OEB-approved administration fee to allow the IESO and OPA to recover their net revenue requirement needed to operate.

5. Rural and Remote Electricity Rate Protection: A rate used to partially offset the higher costs of providing electricity in rural/remote areas. This rate is embellished by regulation.

23

http://www.ieso.ca/imoweb/pubs/settlements/IMO_Charge_Types_and_Equations.pdf

Projection of the Cost of Wholesale Market Services

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

$0.60

$0.70

$0.80

$0.90

$1.00

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

$201

2 Bi

llion

s

IESO and OPA Admin. Fee Congestion Management Settlement Uplift Energy Reliability

Intertie Offer Guarantee Rural/Remote Electricity Rate Protection

24

Cost for Electricity Service – Debt Retirement





Adjustment


Customers


Service


• Debt Retirement

Components of Cost


25

Debt Retirement Charge Methodology

• The Electricity Act, 1998, O. Reg. 493/01 provides for thedebt retirement charge to be paid by electricity consumers until the residual stranded debt is retired.

• The rate is established at $0.007 per kWh (or 0.7 ¢/KWh) for electricity consumed for most Ontario communities.

• For modeling purposes, the DRC is assumed to be the legislated rate of 0.7 cents per kWh, in nominal dollars as this rate has not changed since its inception into the Ontario electricity market.

• For 2013 LTEP cost analysis, the DRC is assumed to be retired after 2018, which is consistent with OEFC Annual Report 2011, which notes the debt repayment plan estimates will likely be defeased between 2015 and 2018 (pg. 5).

DRC5%

26

Debt Retirement Charge Projection and Data

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

$201

2 Bi

llion

s

Debt Retirement Charge (DRC)

$2012 Billions 2013 2014 2015 2016 2017 2018Debt Retirement Charge 0.91 0.88 0.86 0.85 0.82 0.81

27

Sources of Revenue for Suppliers of Electricity Services



Customers


Service


• Debt Retirement

Components of Cost




• Hourly Markets• Global Adjustment

28

Generation and conservation costs are paid to service providers from two sources

• The two sources of revenue are: 1. Hourly market revenues and2. Global adjustment

• All generators participate in the IESO administered markets. Therefore all generators will obtain revenues based primarily on the hourly prices

• The majority of generators are either:1) Rate regulated by the OEB or2) Contracted with OPA or OEFC.

The global adjustment is the payment mechanism that provides the settlement difference between market revenues and the regulated rates or contract prices. As a result, generators make up the difference between their collected market revenues and their regulated or contract rate by obtaining debits or credits from the global adjustment.

• Conservation delivery costs and funds such as the Aboriginal, Municipal and Community Fund are paid for from the global adjustment.

29

HOEP Annual Average Projection

$23 $25

$24 $26

$31 $33

$36 $36

$43 $44 $45

$44 $45 $42

$44 $44 $46 $46 $47

$45

$-

$5

$10

$15

$20

$25

$30

$35

$40

$45

$50

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

Real

201

2$ -

$/M

Wh

HOEP - Marginal Cost as Proxy

• Marginal cost of generation is used as a proxy for HOEP,

30

Global Adjustment and Hourly Market Revenues: Illustrative Projection

0

2

4

6

8

10

12

14

16

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

$201

2 Bi

llion

s

Market Revenues (via, HOEP) Global Adjustment Generation Global Adjustment Conservation (including Funds)

31


Peak Capacity MW

2018 Installed Capacity

MW

2018 Energy TWh

2018 Cost of

Generation $

GAM & Market

Revenue Component


Costs developed in module 3 extended to illustrate the share of GA and Market Revenues

32

29,400 MW

500 MW

Summer Capacity Contribution (%)

100 %

40,500 MW

9,000 MW

2,200 MW

6,400 MW

11,300 MW

71 %

23 %

84 %

89 %

600 MW

10,100 MW

9,400 MW

9,100 MW

11,300 MW

20 TWh

41 TWh

80 TWh

151 TWh

11 TWh

51 %

13 %

24 %

81 %

CapacityFactor (%) $ 13.1 B

$ 5.8 B

$ 2.0 B

$ 3.5 B

$ 1.8 B

$ 87/MWh

$73/MWh

$50/MWh

$177/MWh

$163/MWh


Peak Capacity MW

2018 Installed

Capacity MW

Nuclear Hydro Non-Hydro Renewables Natural Gas Demand ResponseGlobal Adjustment Market Revenue

Share of GA & Market Revenue

71%

29%

82%

18%

54%

46%

32%

68%


Peak Capacity MW

2018 Installed

Capacity MW



Peak Capacity MW

2018 Installed

Capacity MW

Nuclear Hydro Non-Hydro Renewables Natural Gas Demand ResponseGlobal Adjustment Market Revenue

Global Adjustment

Market Revenue

2018GA & Market

RevenueComponents (%)

Residential Bills and Industrial Rates


Service


• Debt Retirement

Components of Cost




• Hourly Markets• Global Adjustment

Customer Bills & Rates


Customers

33

The allocation of the global adjustment is a factor in calculating bills/large industrial rates.

• To make a projection of residential bills and industrial rates, assumptions (detailed later in this presentation) are made about the share of the global adjustment allocated between the two broad categories called:

1. Class A (>5MW) and2. Class B

• Effective January 1, 2011 – GAM costs are divided between Class A and Class B customers as follows:

– Class A (demand greater than 5 MW) pay the global adjustment based on their use during five highest peak demand hours in the prior year known as a “base period”

– Class B (=< 5MW) pay the remaining global adjustment cost on a volumetric rate basis

• For purposes of this analysis, the cost share of global adjustment between Class A and Class B is 10% and 90%, and the volume share is assumed to be 17% and 83%, respectively. These ratios are held constant for the planning period. These cost and volumes shares are based on the current actual shares, and are held constant as a simplifying assumption.

34

The Basis for Calculating a Typical Residential Electricity Bill Forecast

• The proxy of a current residential bill is a Toronto Hydro’s residential customer that consumes 800 KWh on average during a month. Factors that make every customer bill unique are listed on the next slide

• The residential bill is comprised of the following components:1. Electricity (generation + conservation costs)2. Transmission Delivery3. Distribution Delivery4. Regulatory (wholesale market services)5. DRC (debt retirement charge)6. HST (13% for harmonized sales tax)

• To get an indication of the bill over time, the 2012 actual proxy bill is increased by the year over year percentage changes in each of the 6 components of the bill.

• Actual residential bills based on OEB approved rates are available on OEB website: http://www.ontarioenergyboard.ca/OEB/Consumers/Electricity/Your+Electricity+Utility/All+Electricity+Utility+Bills

35

http://www.ontarioenergyboard.ca/OEB/Consumers/Electricity/Your+Electricity+Utility/All+Electricity+Utility+Bills

http://www.ontarioenergyboard.ca/OEB/Consumers/Electricity/Your+Electricity+Utility/All+Electricity+Utility+Bills

Bills vary from customer to customer depending on use, and on tax credit eligibility

• The assumption of 800 kwh/month use on average is maintained for consistency with historical comparisons

• As consumers reduce or increase their demand, the bills will be lower or higher. Residential customer bills are also impacted by their usage patterns (on-peak, off-peak and mid-peak)

• Northern Ontario Energy Credit available to low to middle income families and individuals in the north based on an individual’s/family’s net income

• Ontario Energy and Property Tax Credit is available to low to moderate income individuals and families, including seniors based on individual’s/family’s net income

36

Bills also vary depending on location and the distribution service provider

• There are over 70 separate LDCs in Ontario. Each LDC has its own rate and cost structures.

• Transmission rates are developed on a postage stamp basis; thus the transmission rates are the same for each LDC. However, the LDC’s unique system usage profile and service requirements impact the overall cost charged to it for transmission and connection costs.

• Rural/Remote Protection Plan credit is given to customers in some LDCs with low customer density.

37

Typical Residential Electricity Bill Forecast – Before OCEB* (Nominal $/Month – assuming 800KWh/Month)

• The above graph provides information consistent with Figure 7: Typical Residential Electricity Bill Forecast, in the 2013 LTEP.• OCEB – Ontario Clean Energy Benefit• Based on Toronto Hydro’s 2012 annual average residential bill, assuming 800kWh/month• Inflation rate of 2% assumed to convert real $2012 dollars to nominal dollars

$138

$152 $162

$167 $170 $178 $177 $181

$187 $193 $188 $191 $194 $198 $200 $202 $204 $205 $207 $210

$-

$50

$100

$150

$200

$250

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

Mon

thly

Res

iden

tial

Cus

tom

er B

ill

Ass

ume

800

KWh

Nom

inal

$

Electricity Distribution Transmission Regulated Charges (Wholesale Market Service Charge) Debt Retirement Charge (DRC) HST

38

Typical Residential Electricity Bill Forecast – After OCEB (Nominal $/Month – assuming 800KWh/Month)

• The above graph provides information consistent with Figure 7: Typical Residential Electricity Bill Forecast, in the 2013 LTEP. • Ontario Clean Energy Benefit (OCEB) is a 10% credit to residential customer bills, which is in effect from 2011 to 2015. A 3,000 kWh per month cap was implemented in September 2012.• Beyond 2015, the OECB program’s future would require legislative changes and would need to be take into account a number of factors including the province’s fiscal position.• Based on Toronto Hydro’s 2012 annual average residential bill, assuming 800kWh/month• Inflation rate of 2% assumed to convert real $2012 dollars to nominal dollars

125137 145

167 170 178 177 181 187 193 188 191 194 198 200 202 204 205 207 210

$14

$15 $16

0

20

40

60

80

100

120

140

160

180

200

220

240

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

Mon

thly

Res

iden

tial C

usto

mer

Bill

incl

udin

g tax

es in

Nom

inal

$, a

ssum

ing

800k

Wh

Ontario Clean Energy Benefit Credit (OCEB)

Residential Bill Projection After OCEBC

39

An illustrative example of how improvements in efficiency will lower average customer bills

• Average residential household energy use is decreasing as customers adopt energy efficient measures and behaviour supported by conservation programs. • The above graph provides information consistent with Figure 7: Typical Residential Electricity Bill Forecast, in the 2013 LTEP. 40

138152

162 167 170178 177 181 187 193 188 191 194 198 200 202 204 205 207 210

138151

159 163 164 170 167 170 173 177 171 171 172 174 174 173 173 172 172 172

0

50

100

150

200

250

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

Mon

thly

Res

iden

tial B

ill,

incl

udes

taxe

s in

nom

inal

$

Residential Bill Forecast

LTEP Figure 7: 2013 LTEP Residential Bill Forecast (800 kWh/hh month) Before OCEB

Residential Bill Forecast Assuming a 20% reduction in energy use by 2032

Methodology for Large Industrial Electricity Price Forecast

• The large industrial rate is applicable to a customer (>5MW) that is directly connected to the transmission system

• The industrial rate does not include HST, as this would be an allowed corporate tax credit.

• The large industrial rate is composed of four components:– electricity (HOEP + Class A GA rate), transmission, wholesale market charge, and DRC

• This price forecast is an illustrative aggregate. Each large user Class A customer will pay a global adjustment rate based on their unique usage during the 5 highest hours of the prior year (during base period).

41

Large Industrial Electricity Price Forecast (Nominal $/MWh)

79

87 92

96 100

105 102 104

111 115 113 113 115 116 118 118 121 121 123 123

0

20

40

60

80

100

120

140

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

No

min

al $

/MW

h

Electricity(via Market Clearing Price - HOEP)

Electricity(via GA Class A Rate)

Transmission Regulatory DRC

• The above graph provides information consistent with Figure 8: Industrial Electricity Price Forecast, in the 2013 LTEP. • Inflation rate of 2% assumed to convert real $2012 dollars to nominal dollars

42

More detailed projections of global adjustment allocation used for rate setting purposes

• For purposes of this forecast, the cost share of global adjustment (GA) between Class A and Class B is 10% and 90%, and the volume share is assumed to be 17% and 83%, respectively. These ratios are held constant for the planning period

• As actual Class A and B share values change, the rate and bill outlooks will change correspondingly. An estimate of the monthly GA is prepared by the IESO, for LDC billing purposes: http://www.ieso.ca/imoweb/b100/b100_ga.asp

• Historical monthly data on GA is available at the following links: http://www.ieso.ca/imoweb/b100/b100_ga.asphttp://www.ieso.ca/imoweb/b100/ga_archive.asp

• The Ontario Energy Board establishes the electricity commodity rates for households and small businesses via the regulated price plan, using higher resolution data that reflect current assumptions and circumstances.

http://www.ontarioenergyboard.ca/OEB/Industry/Regulatory%20Proceedings/Policy%20Initiatives%20and%20Consultations/Regulated%20Price%20Plan

43

http://www.ieso.ca/imoweb/b100/b100_ga.asp

http://www.ieso.ca/imoweb/b100/b100_ga.asp

http://www.ieso.ca/imoweb/b100/ga_archive.asp



Class A and Class B GA Unit Rates: Illustrative Projection

$-

$10

$20

$30

$40

$50

$60

$70

$80

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

$2

01

2/M

Wh

Class A - GA Rate Class B - GA Rate HOEP - Marginal Cost as Proxy

• The Class A GA Rate is illustrative of the average rate for Class A, individual Class A customer will pay a GA rate based on their specific usage of the 5 highest hours in the prior year (base period)

44

All-in Electricity Rates: Class A and Class B(GA Rates + HOEP)

$55 $61 $63 $65 $67 $70 $71 $71

$76 $77 $73 $72 $72 $71 $71 $70 $70 $69 $68 $67

$82

$91 $97 $98 $97

$100 $101 $101 $103 $105

$97 $96 $95 $95 $93 $92 $90 $88 $86 $85

$-

$20

$40

$60

$80

$100

$120

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

$201

2/M

Wh

Class A - All-In Commodity Rate Class B - All-In Commodity Rate

The Class A all-in rate is illustrative of the average rate for Class A, individual Class A customer will pay a GA rate based on their specific usage of the 5 highest hours in the prior year (base period)

45

APPENDIX

This section contains tabulation of data for figures shown in this module.

46

Appendix: Data for Slide 6 – Cost of Electricity Service

47

Total Cost for Electricity Service$Billions ($2012) 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032Generation 12.7 12.5 12.5 12.5 12.4 12.3 12.2 12.1 11.9 11.8Conservation 0.6 0.7 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8Transmission 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6Distribution 4.0 4.0 4.1 4.1 4.2 4.3 4.3 4.3 4.4 4.4Wholesale 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8DRC 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Total Costs 19.8 19.7 19.8 19.9 19.9 19.8 19.8 19.7 19.6 19.5

Total Cost for Electricity Service$Billions ($2012) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022Generation 10.7 11.6 12.3 12.6 12.4 12.8 13.0 13.1 13.5 13.8Conservation 0.4 0.5 0.4 0.3 0.4 0.4 0.5 0.5 0.6 0.6Transmission 1.4 1.5 1.5 1.5 1.5 1.5 1.6 1.6 1.6 1.6Distribution 3.5 3.5 3.6 3.7 3.7 3.7 3.8 3.8 3.9 3.9Wholesale 0.8 0.8 0.8 0.8 0.8 0.9 0.9 0.9 0.9 0.9DRC 0.9 0.9 0.9 0.8 0.8 0.8 0.0 0.0 0.0 0.0Total Costs 17.6 18.7 19.4 19.8 19.6 20.2 19.7 20.0 20.4 20.7

Appendix: Data for Slide 9 – Generation Cost by Resource

Note: Planned Flexibility include generic SCGT facilities and a Notional Import Tie. Both Planned Flexibility options are priced as a SCGT facility for cost modeling purposes.

48

Generation Cost By ResourceReal $2012 Millions 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022Coal 137 0 - - - - - - - - Nuclear 5,617 5,843 5,670 6,074 5,611 5,831 5,763 5,704 4,787 5,041 Natural Gas 2,249 1,967 1,756 1,678 1,676 1,842 1,782 1,766 2,004 1,937 Hydro 1,583 2,102 2,074 2,053 2,055 2,043 2,051 2,026 2,026 2,123 Bio 177 249 353 334 333 405 475 497 726 719 Wind 614 846 1,380 1,389 1,518 1,503 1,560 1,714 1,882 1,873 Solar 559 838 1,281 1,305 1,470 1,548 1,606 1,621 1,587 1,556 Planned Flexibility - - - - - - 54 95 391 511 Imports 80$ 84$ 93$ 116$ 162$ 198$ 242$ 255$ 584$ 590$ Total Market Demand 11,016$ 11,928$ 12,607$ 12,949$ 12,825$ 13,370$ 13,534$ 13,677$ 13,987$ 14,349$ Less Exports 341$ 346$ 327$ 362$ 444$ 550$ 563$ 558$ 465$ 588$ Ontario Demand 10,674$ 11,582$ 12,280$ 12,587$ 12,380$ 12,820$ 12,971$ 13,119$ 13,522$ 13,761$

Generation Cost By ResourceReal $2012 Millions 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032Coal - - - - - - - - - - Nuclear 4,360 4,356 4,517 4,866 4,709 4,720 4,699 4,894 5,012 5,276 Natural Gas 1,899 1,825 1,788 1,701 1,749 1,741 1,733 1,703 1,699 1,678 Hydro 1,974 1,987 1,977 1,962 1,945 1,930 1,907 1,890 1,866 1,825 Bio 710 676 631 622 613 605 598 588 574 556 Wind 1,845 1,826 1,785 1,745 1,696 1,669 1,613 1,574 1,506 1,376 Solar 1,525 1,497 1,466 1,438 1,410 1,384 1,355 1,326 1,270 1,206 Planned Flexibility 389 376 379 279 316 341 375 301 313 220 Imports 602$ 573$ 559$ 518$ 599$ 520$ 558$ 508$ 484$ 463$ Total Market Demand 13,306$ 13,116$ 13,102$ 13,130$ 13,037$ 12,911$ 12,840$ 12,783$ 12,722$ 12,600$ Less Exports 593$ 596$ 646$ 625$ 602$ 626$ 629$ 723$ 807$ 824$ Ontario Demand 12,713$ 12,520$ 12,456$ 12,505$ 12,435$ 12,285$ 12,211$ 12,061$ 11,915$ 11,776$

Appendix: Data for Slide 10 – Generation Unit Cost by Resource

49

Unit Cost for Generation by ResourceReal $2012/MWh 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022Coal 125$ 25$ Nuclear 59$ 66$ 68$ 72$ 70$ 73$ 76$ 77$ 87$ 90$ Natural Gas and Planned Flexibility 156$ 146$ 166$ 161$ 174$ 163$ 155$ 158$ 131$ 132$ Hydro 43$ 55$ 53$ 51$ 51$ 50$ 50$ 50$ 50$ 51$ Bio 98$ 119$ 156$ 158$ 158$ 164$ 167$ 159$ 173$ 171$ Wind 108$ 114$ 120$ 118$ 116$ 114$ 112$ 111$ 112$ 111$ Solar 504$ 476$ 463$ 450$ 417$ 393$ 373$ 359$ 352$ 345$

Unit Cost for Generation by ResourceReal $2012/MWh 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032CoalNuclear 78$ 74$ 74$ 75$ 76$ 72$ 73$ 71$ 70$ 71$ Natural Gas and Planned Flexibility 120$ 121$ 123$ 127$ 121$ 120$ 111$ 102$ 102$ 98$ Hydro 47$ 47$ 47$ 46$ 46$ 46$ 45$ 45$ 44$ 43$ Bio 169$ 160$ 150$ 148$ 146$ 143$ 142$ 140$ 139$ 136$ Wind 109$ 107$ 105$ 103$ 100$ 98$ 95$ 93$ 90$ 82$ Solar 338$ 331$ 325$ 319$ 312$ 306$ 300$ 294$ 285$ 275$

Appendix: Data for Slide 14 – Conservation Costs

50

Conservation Costs$2012 Billions 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022EE delivery cost 0.3$ 0.4$ 0.3$ 0.3$ 0.3$ 0.4$ 0.4$ 0.5$ 0.5$ 0.5$ DR delivery cost 0.1$ 0.1$ 0.1$ 0.1$ 0.1$ 0.1$ 0.1$ 0.1$ 0.1$ 0.1$ Funds 0.0$ 0.0$ 0.0$ -$ -$ -$ -$ -$ -$ -$ Total Conservation and Fund Costs 0.4$ 0.5$ 0.4$ 0.3$ 0.4$ 0.4$ 0.5$ 0.5$ 0.6$ 0.6$

Conservation Costs$2012 Billions 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032EE delivery cost 0.5$ 0.6$ 0.6$ 0.6$ 0.6$ 0.6$ 0.6$ 0.6$ 0.6$ 0.6$ DR delivery cost 0.1$ 0.2$ 0.2$ 0.2$ 0.2$ 0.2$ 0.2$ 0.2$ 0.2$ 0.2$ Funds -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ Total Conservation and Fund Costs 0.6$ 0.7$ 0.8$ 0.8$ 0.8$ 0.8$ 0.8$ 0.8$ 0.8$ 0.8$

Appendix: Data for Slide 17 – Transmission Delivery Costs

51

Transmission Delivery Costs$2012 B 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022Base Transmission $1.4 $1.4 $1.4 $1.4 $1.4 $1.4 $1.4 $1.4 $1.4 $1.4Incremental Transmission $0.0 $0.0 $0.0 $0.0 $0.0 $0.1 $0.2 $0.2 $0.2 $0.2Total Transmission Costs $1.4 $1.5 $1.5 $1.5 $1.5 $1.5 $1.6 $1.6 $1.6 $1.6

Transmission Delivery Costs$2012 B 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032Base Transmission $1.4 $1.4 $1.4 $1.4 $1.4 $1.4 $1.4 $1.4 $1.4 $1.4Incremental Transmission $0.2 $0.2 $0.2 $0.2 $0.2 $0.2 $0.2 $0.2 $0.2 $0.2Total Transmission Costs $1.6 $1.6 $1.6 $1.6 $1.6 $1.6 $1.6 $1.6 $1.6 $1.6

Appendix: Data for Slide 20 – Distribution Delivery Costs

52

Distribution Delivery Costs$2012 Billions 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022Base Distribution 3.31 3.31 3.31 3.31 3.31 3.31 3.31 3.31 3.31 3.31Incremental Distibution Cost due to Household Growth 0.05 0.10 0.14 0.19 0.24 0.29 0.34 0.39 0.44 0.49Smart Meter and Smart Grid 0.10 0.12 0.13 0.15 0.15 0.14 0.14 0.13 0.13 0.13Incremental Low Income Energy Assistance Program 0.0002 0.0003 0.0003 0.0004 0.0005 0.0005 0.0006 0.0006 0.0007 0.0007 Total Distribution Costs 3.46 3.52 3.59 3.66 3.70 3.75 3.79 3.84 3.88 3.92

Distribution Delivery Costs$2012 Billions 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032Base Distribution 3.31 3.31 3.31 3.31 3.31 3.31 3.31 3.31 3.31 3.31Incremental Distibution Cost due to Household Growth 0.54 0.59 0.64 0.69 0.74 0.79 0.84 0.88 0.93 0.98Smart Meter and Smart Grid 0.12 0.13 0.14 0.14 0.15 0.16 0.15 0.14 0.14 0.13Incremental Low Income Energy Assistance Program 0.0008 0.0009 0.0009 0.0010 0.0011 0.0011 0.0012 0.0012 0.0013 0.0013 Total Distribution Costs 3.97 4.03 4.08 4.14 4.20 4.25 4.30 4.34 4.38 4.42

Appendix: Data for Slide 24 – Wholesale Market Service Costs

53

Wholesale Market Service Costs$2012 Billions 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022Congestion Management Settlement Uplift $0.09 $0.09 $0.10 $0.10 $0.10 $0.10 $0.10 $0.11 $0.11 $0.11Energy Reliability $0.36 $0.34 $0.36 $0.37 $0.36 $0.38 $0.38 $0.39 $0.39 $0.40Intertie Offer Guarantee $0.02 $0.02 $0.03 $0.03 $0.03 $0.03 $0.03 $0.03 $0.03 $0.03IESO and OPA Admin. Fee $0.20 $0.20 $0.20 $0.20 $0.20 $0.20 $0.20 $0.20 $0.20 $0.20Rural/Remote Electricity Rate Protection $0.16 $0.15 $0.15 $0.14 $0.14 $0.14 $0.14 $0.14 $0.13 $0.13 Wholesale Market Charge Cost $0.82 $0.81 $0.84 $0.85 $0.83 $0.86 $0.86 $0.86 $0.86 $0.87

Wholesale Market Service Costs$2012 Billions 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032Congestion Management Settlement Uplift $0.10 $0.10 $0.10 $0.10 $0.10 $0.10 $0.10 $0.10 $0.10 $0.10Energy Reliability $0.37 $0.37 $0.36 $0.37 $0.36 $0.36 $0.35 $0.35 $0.35 $0.35Intertie Offer Guarantee $0.03 $0.03 $0.03 $0.03 $0.03 $0.03 $0.03 $0.03 $0.03 $0.03IESO and OPA Admin. Fee $0.20 $0.20 $0.20 $0.20 $0.20 $0.20 $0.20 $0.20 $0.20 $0.20Rural/Remote Electricity Rate Protection $0.13 $0.13 $0.13 $0.12 $0.12 $0.12 $0.12 $0.12 $0.12 $0.12 Wholesale Market Charge Cost $0.83 $0.82 $0.82 $0.82 $0.81 $0.81 $0.80 $0.80 $0.79 $0.79

Appendix: Data for Slide 27– Debt Retirement Charge

54

Debt Retirement Charge$2012 Billions 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022Debt Retirement Charge 0.91 0.88 0.86 0.85 0.82 0.81

Debt Retirement Charge$2012 Billions 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032Debt Retirement Charge

Appendix: Data for Slide 31 – Global Adjustment: Data

55

Global Adjustment Costs$2012 Billion 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Global Adjustment Generation 7.42$ 8.07$ 8.95$ 8.97$ 7.98$ 8.11$ 7.95$ 8.07$ 7.33$ 7.46$ Global Adjustment Conservation (including funds*) 0.36$ 0.46$ 0.42$ 0.34$ 0.37$ 0.42$ 0.48$ 0.54$ 0.55$ 0.57$ Market Revenues (via, HOEP) 3.26$ 3.51$ 3.32$ 3.62$ 4.40$ 4.71$ 5.02$ 5.05$ 6.19$ 6.30$

Total Generation and Conservation (including funds*) Costs 11.04$ 12.04$ 12.69$ 12.93$ 12.75$ 13.24$ 13.46$ 13.65$ 14.08$ 14.33$

Global Adjustment Costs$2012 Billion 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

Global Adjustment Generation 6.20$ 6.14$ 5.90$ 6.28$ 5.85$ 5.76$ 5.31$ 4.98$ 4.73$ 4.88$ Global Adjustment Conservation (including funds*) 0.64$ 0.72$ 0.79$ 0.83$ 0.84$ 0.84$ 0.84$ 0.84$ 0.84$ 0.84$ Market Revenues (via, HOEP) 6.51$ 6.38$ 6.56$ 6.23$ 6.58$ 6.53$ 6.90$ 7.08$ 7.19$ 6.90$

Total Generation and Conservation (including funds*) Costs 13.36$ 13.24$ 13.24$ 13.34$ 13.27$ 13.12$ 13.05$ 12.90$ 12.76$ 12.62$

Note: *Fund costs for Aboriginal, Community, and Municipal Funds

Appendix: Data for Slide 38 and 39 – Typical Residential Electricity Bill Forecast

56

Residential Customer Bill - Assumes 800KWh/Mth$ Nominal 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022Distribution 32$ 34$ 36$ 37$ 39$ 40$ 41$ 43$ 43$ 45$ Transmission 11$ 12$ 12$ 12$ 13$ 13$ 14$ 14$ 15$ 15$ Regulated Charges (Wholesale Market Service Charge) 5$ 5$ 5$ 5$ 6$ 6$ 6$ 6$ 6$ 6$ Debt Retirement Charge (DRC) 6$ 6$ 6$ 6$ 6$ 6$ -$ -$ -$ -$ Electricity 69$ 78$ 84$ 87$ 88$ 93$ 95$ 98$ 101$ 105$ Total Bill before Taxes 122$ 134$ 143$ 148$ 151$ 158$ 157$ 161$ 165$ 171$ HST 16$ 17$ 19$ 19$ 20$ 21$ 20$ 21$ 21$ 22$ Total Residential Bill with Taxes (Before OCEB) 138$ 152$ 162$ 167$ 170$ 178$ 177$ 181$ 187$ 193$ Ontario Clean Energy Benefit Credit (OCEB) 14$ 15$ 16$ Total Residential Bill with Taxes: After OCEB 125$ 137$ 145$ 167$ 170$ 178$ 177$ 181$ 187$ 193$ Residential Customer Bill - Assumes 800KWh/Mth$ Nominal 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032Distribution 46$ 47$ 49$ 50$ 51$ 52$ 53$ 54$ 56$ 57$ Transmission 15$ 15$ 16$ 16$ 16$ 16$ 16$ 16$ 17$ 17$ Regulated Charges (Wholesale Market Service Charge) 6$ 6$ 7$ 7$ 7$ 7$ 7$ 7$ 7$ 7$ Debt Retirement Charge (DRC) -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ Electricity 99$ 100$ 101$ 103$ 103$ 103$ 104$ 103$ 103$ 104$ Total Bill before Taxes 167$ 169$ 172$ 176$ 177$ 179$ 180$ 181$ 183$ 185$ HST 22$ 22$ 22$ 23$ 23$ 23$ 23$ 24$ 24$ 24$ Total Residential Bill with Taxes (Before OCEB) 188$ 191$ 194$ 198$ 200$ 202$ 204$ 205$ 207$ 210$ Ontario Clean Energy Benefit Credit (OCEB)Total Residential Bill with Taxes: After OCEB 188$ 191$ 194$ 198$ 200$ 202$ 204$ 205$ 207$ 210$

Appendix: Data for Slide 42 – Large Industrial Electricity Price Forecast

Note: This is an illustrative rate for large user >5 MW and is directly connected to the transmission system

57

Large User > 5 MW proxy for Industrial RateNominal $/MWh 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022Electricity(via Market Clearing Price - HOEP) 23$ 26$ 25$ 28$ 35$ 38$ 41$ 42$ 52$ 54$ Electricity (via GA Class A Rate) 33$ 37$ 42$ 43$ 39$ 41$ 41$ 42$ 39$ 40$ Transmission 10$ 11$ 11$ 12$ 12$ 13$ 13$ 14$ 14$ 14$ Regulatory 6$ 6$ 6$ 7$ 7$ 7$ 7$ 7$ 7$ 8$ DRC 7$ 7$ 7$ 7$ 7$ 7$ -$ -$ -$ -$ Total 79$ 87$ 92$ 96$ 100$ 105$ 102$ 104$ 111$ 115$

Large User > 5 MW proxy for Industrial RateNominal $/MWh 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032Electricity(via Market Clearing Price - HOEP) 56$ 56$ 58$ 56$ 60$ 60$ 64$ 66$ 68$ 67$ Electricity (via GA Class A Rate) 35$ 35$ 35$ 38$ 36$ 36$ 34$ 32$ 31$ 32$ Transmission 14$ 14$ 15$ 15$ 15$ 15$ 15$ 16$ 16$ 16$ Regulatory 7$ 7$ 7$ 8$ 7$ 8$ 8$ 8$ 8$ 8$ DRC -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ Total 113$ 113$ 115$ 116$ 118$ 118$ 121$ 121$ 123$ 123$

Appendix: Data for Slide 44, 45 – Class A and Class B: GA Rates and All-In Electricity Rates

58

GA Class A and Class B Unit Rates

$/MWh (in Real 2012$) 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022Class A - GA Rate 32$ 36$ 40$ 39$ 36$ 36$ 36$ 36$ 32$ 33$ Class B - GA Rate 59$ 66$ 73$ 73$ 66$ 67$ 65$ 66$ 60$ 61$ HOEP (Marginal Cost - Proxy for HOEP) 23$ 25$ 24$ 26$ 31$ 33$ 36$ 36$ 43$ 44$

All-In Electricity Rate (GA + HOEP) - $/MWh (in Real $2012)2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Class A - All-In Electricity Rate 55$ 61$ 63$ 65$ 67$ 70$ 71$ 71$ 76$ 77$ Class B - All-In Electricity Rate 82$ 91$ 97$ 98$ 97$ 100$ 101$ 101$ 103$ 105$

GA Class A and Class B Unit Rates

$/MWh (in Real 2012$) 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032Class A - GA Rate 28$ 28$ 27$ 29$ 27$ 26$ 24$ 22$ 21$ 22$ Class B - GA Rate 52$ 52$ 50$ 53$ 49$ 48$ 44$ 41$ 39$ 40$ HOEP (Marginal Cost - Proxy for HOEP) 45$ 44$ 45$ 42$ 44$ 44$ 46$ 46$ 47$ 45$

All-In Electricity Rate (GA + HOEP) - $/MWh (in Real $2012)2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

Class A - All-In Electricity Rate 73$ 72$ 72$ 71$ 71$ 70$ 70$ 69$ 68$ 67$ Class B - All-In Electricity Rate 97$ 96$ 95$ 95$ 93$ 92$ 90$ 88$ 86$ 85$

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