1. Electricity System Cost Outlook
MODULE 7:
Electricity System Cost Outlook
August 2016

2. Overview
The following module provides an illustration of the cost of the electricity system across the demand outlooks presented in the Ontario Planning Outlook
Further information with respect to the demand outlooks can be found in Module 2 “Demand Outlook”
The total cost of electricity service and average unit cost for electricity service are illustrated for each of the demand outlooks
The cost outlooks illustrated here are not forecasts. They illustrate a range of potential outcomes based on the assumptions made. There are many assumptions with varying levels of uncertainty. These assumptions could change over time.
The purpose of this module is to illustrate a range of potential outcomes. They are best interpreted in relation to each other and serve to inform discussions on how to meet electricity system needs across the demand outlooks.
This is facilitated by illustrating a number of resource portfolios for meeting the four demand outlooks. The resource portfolios are illustrative. It is recognized that many options exist beyond those considered here.

3. Electricity System Cost Outlook
The electricity system cost outlook varies with the outlook for supply resources which in turn varies with the outlook for demand. The cost of delivering, operating, and maintaining electricity resources (conservation, generation, and transmission/distribution) and the extent to which investments are made in new resources vary with the level of electricity demand.
As described in Module 4 “Supply Outlook”, Ontario:
Could meet flat demand outlooks provided that existing resources continue to operate, planned resource come into service, and arrangements can be made for the continued operations of resources past their current contract expiry. Ontario could also take advantage of improvements in technology performance and costs that may emerge to replace existing resources as contracts expire.
Could find itself in a position of excess supply over the planning outlook under low demand outlooks
Would require more electricity resources than it has today to serve higher demand outlooks
There are a number of ways in which electricity demand can be met across each of the demand outlooks. Some of these are illustrated in the following slides for each of the four demand outlooks.
Each demand outlook has a resource requirement. Developing cost outlooks for the four demand outlooks entailed making assumptions about the cost and performance of resource options for the purpose of illustrating relative cost performance to inform discussions with policymakers and stakeholders.

4. Electricity System Cost Outlook:
Outlook B “Flat” Demand Outlook

5. Overview of Electricity System Cost Outlook: Outlook B
In demand Outlook B, Ontario could meet flat demand outlooks with existing and planned resources provided they continue to operate following contract expiry
Ontario could also take advantage of improvements in technology performance and costs that may emerge to replace existing resources as contracts expire.
Opportunities in this regard include ongoing evolution in renewable technologies, storage technologies, distributed energy resources, clean energy imports and others
Ontario could adapt by not recontracting with generation facilities when contracts expire
Ontario also has the option of exercising nuclear refurbishment off-ramps where there are more economic electricity supply alternatives
To illustrate the outlook for electricity costs in demand Outlook B, it is assumed that existing resources continue to operate, planned resources come into service, and arrangements can be made for the continued operations of resources past their current contract expiry.
No new transmission investments is assumed to be required beyond those currently in various stages of development (see Module 5)
It is assumed that resources with expired contracts continue to operate at costs below existing contract rates, reflecting the reduced cost of capital for continuing to operate these facilities (relative to building new resources)

6. Change in Resource Requirements: Outlook B
Existing, Committed, and Directed resources would be sufficient to meet the flat demand outlook assuming resources with expiring contracts continue to operate
Further information on conservation and demand response resources can be found in Module 3. Further information on supply resources can be found in Module 4.

7. Change in Resource Requirements: Outlook B, Summer
  Capacity at Time of Summer Peak Demand, MW
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Nuclear
12,939
12,061
11,242
10,364
8,581
10,277
7,446
Natural Gas
8,774
8,784
9,153
9,943
10,019
Waterpower
6,206
6,232
6,295
6,299
6,300
6,325
6,378
Bioenergy
537
540
543
591
621
Wind
553
579
594
624
685
Solar PV
711
806
927
1,044
1,134
1,236
1,336
Storage & Demand Response
616
633
802
971
1,140
Firm Import (if needed)
500
TOTAL
30,337
30,118
30,705
31,666
30,879
30,195
30,280
28,768
30,687
28,125
Capacity at Time of Summer Peak Demand, MW
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
8,259
8,208
9,026
9,845
6,441
6,578
684
28,501
28,587
29,404
30,223

8. Change in Resource Requirements: Outlook B, Winter
Capacity at Time of Winter Peak Demand, MW
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Nuclear
11,651
10,773
9,076
9,954
6,929
7,807
6,673
Natural Gas
9,267
9,325
9,623
9,694
10,613
10,704
Waterpower
6,562
6,577
6,627
6,657
6,662
6,663
6,689
6,745
Bioenergy
537
539
542
543
591
621
Wind
1,240
1,338
1,445
1,520
1,670
Solar PV
100
106
116
130
146
158
172
Storage & Demand Response
442
458
524
678
832
TOTAL
29,799
29,099
29,567
29,700
29,057
30,102
29,265
27,295
28,340
27,417
Reserved for Quebec
(500)
Total Available for Ontario
29,299
28,599
29,067
29,200
28,557
29,602
28,765
26,795
27,840
26,917
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
7,486
7,435
8,254
8,253
9,072
6,811
6,956
1,669
185
987
27,584
28,463
29,375
30,193

9. Electricity production in 2035 relative to 2015: Outlook B

10. Electricity production in 2035 relative to 2015: Outlook B
Energy Production, TWh
2015, Actual
2035, Outlook B
Nuclear 92 73
Natural Gas 16 14
Waterpower 37 41
Non-Waterpower Renewables 24
Total
159
152

11. Electricity production, 2016-2035: Outlook B

12. Electricity production, 2016-2035: Outlook B
Energy Production, TWh
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Nuclear 92 86 83 81 75 73 65 56
Natural Gas 12 10 9 8 11
Waterpower 36 37 38 39 40
Non-Waterpower Renewables 17 18 19 20 21 22 23 24
Total
157
151
149
152
150
145
144
138
147
132
 Energy Production, TWh
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035 62 67 68 70 66 72 14 41
136
141
142
143

13. Cost Assumptions
Existing and committed generation costs for generators of all fuel types are based on the contract prices negotiated.
OPG regulated rates for nuclear and waterpower are as provided by OPG.
Cost assumption for resources assumed to be recontracted following end of their contract term is outlined in the next slide
Conservation program cost reflects IESO experience with conservation programs.
Transmission costs are based on the 2016 Hydro One Transmission Revenue Requirement EB Decision and Order, plus the cost for incremental capital projects required to meet resource requirements.
Distribution costs are based on 2015 OEB Yearbook distribution cost indexed to the growth of housing stocks.
Wholesale Market Service Charge components that are market based such as auxiliary services, IOG are indexed the change in the cost of generation. IESO fees and legislated rates (i.e., Rural/Remote Settlement Rate) are assumed to remain constant.
Debt Retirement Charge is based on the legislated rate of $7/MWh in nominal dollars for 2016 to 2018, and applicable to non-residential customers

14. Repowering Cost Assumptions
Assumption of cost of continuing to operate resources following the end of their contract term
Resource Type
Repowering Cost Assumptions
Non-Utility Generators (NUGs) - for all expired NUG Contracts (Bio, MSW (Municipal Solid Waste), and Gas)
Variable cost component plus 50% of the fixed costs
Natural Gas 
Lennox
As per original contract
CCGT
All original contract price components, with 20% of the capital portion
SCGT
CHP
MSW (Municipal Solid Waste)
All original contract price components, with 35% of the capital portion
Waterpower
Assumes the regulated non-prescribed waterpower rates
Bioenergy 
Thunder Bay Bio Conversion
Atikokan Bio Conversion (ABESA)
CHP3
RES BIO, RESOP, Advance RESOP Fit Amendment (ARFA), MicroFIT/FIT
Base Contract Price, variable component plus 35% of the capital component
Wind
Consistent with the procurement rates for LRP I wind
Solar PV
Consistent with the procurement rates for LRP I solar
Source: IESO.

15. Total Cost of Electricity Service: Outlook B

16. Total Cost of Electricity Service: Outlook B
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Total Cost of Electricity Services (2016$)
20.7
21.3
21.2
20.5
21.5
20.8
20.9
21.0
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
20.4
20.2
20.1
19.9
19.4

17. Average Unit Cost of Electricity Service: Outlook B

18. Average Unit Cost of Electricity Service: Outlook B
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Demand: Outlook B (TWh)
143
142
B (2016$/MWh)
$144
$149
$151
$146
$147
$148
$152
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
141
144
145
146
148
$145
$150
$143
$141
$140
$137
$136
$131

19. Electricity System Cost Outlook:
Outlook A “Low” Demand Outlook

20. Overview of Electricity System Cost Outlook: Outlook A
In demand Outlook A, by 2035 the electricity peak demand is 2 GW less than in Outlook B and energy consumption is 15 TWh less. The reduction in peak demand translates to a reduction in total resource requirement of 2.5 GW after accounting for the reduction in reserve requirements.
Ontario could find itself with resources in excess of demand. There are a number of ways in which lower electricity demand can be met:
Ontario could adapt to low demand outlooks by not recontracting with generation facilities when contracts expire
Ontario also has the option of exercising nuclear refurbishment off-ramps in response to sustained, very low demand expectations
To illustrate the outlook for electricity costs in demand Outlook A, two illustrative resource outlooks were developed to reflect potential ways to address the low demand outlook:
A1 “Gas, Solar PV & Wind”: As resource contracts expire, they are assumed to be not recontracted. This includes a reduction in gas-fired resources for capacity and solar PV and wind resources for energy in quantities that are in excess of resource requirements.
A2- “Gas & Nuclear”: As gas-fired resource contracts expire they are assumed to be not recontracted due to reduced capacity requirements. Two nuclear units are not refurbished due to reduced energy requirements.
The reduction in resources is equivalent to the reduction in capacity requirements and energy consumption relative to Outlook B. No changes in transmission and distribution costs, relative to Outlook B, was assumed.

21. Change in Resource Requirements: Outlook A
The overall reduction in available capacity at time of system peak is the same for the two options (~2.5 GW)
In A1 “Gas, Solar PV & Wind”, the reduction in peak capacity is greater for natural gas than for wind and solar PV. The lower capacity contributions of wind and solar PV at the time of peak demand translates to a larger reduction in their installed capacity.

22. Change in Resource Capacity: Outlook A
Capacity Reduction, MW
A1, At Peak
A2, At Peak
A1, Installed
A2, Installed
Nuclear
1,644
Natural Gas
1,700
981
1,090
Wind
460
4,600
Solar PV
600
2,000

23. Electricity production in 2035 relative to 2015: Outlook A

24. Electricity production in 2035 relative to 2015: Outlook A
Energy Production, TWh
2015, Actual
2035, A1
2035, A2
Nuclear 92 73 60
Natural Gas 16 15
Waterpower 37 41
Solar PV, Wind & Bioenergy 14 9 24

25. Total Cost of Electricity Service: Outlook A

26. Total Cost of Electricity Service: Outlook A
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
A - High Range (2016$)
$20.7
$21.3
$21.1
$20.4
$20.5
$20.6
$20.9
A - Low Range (2016$)
$21.0
 Total Cost of Electricity Service
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
$19.9
$20.3
$19.8
$19.6
$19.4
$19.3
$19.0
$18.8
$18.2
$20.2
$19.7
$19.2
$18.6
$18.4
$17.8

27. Average Unit Cost of Electricity Service: Outlook A

28. Average Unit Cost of Electricity Service: Outlook A
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Demand: Outlook A (TWh)
143
142
141
139
138
136
135
134
133
A - High Range (2016$/MWh)
$144
$150
$146
$154
$152
$153
$158
A - Low Range (2016$/MWh)
 Average Unit Cost of Electricity Service
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
132
131
$151
$157
$155
$149
$147
$142
$136
$145
$139
$134

29. Electricity System Cost Outlook:
Outlook C & D “Higher” Demand Outlook

30. Overview of Electricity System Cost Outlook: Outlooks C & D
Ontario would require more electricity resources than it has today to serve higher levels of electricity demand growth. In addition, Ontario would transition back to a winter peaking jurisdiction due to the increase in electric heating loads.
While higher demand could create a need for additional resources in the longer-term, these needs are not projected to occur until the mid-2020s
Resources considered for inclusion in the outlooks include conservation, wind, solar PV, waterpower, bioenergy, demand response, nuclear, firm imports, and natural gas.
In light of Ontario transitioning to a winter peaking system, it was found that solar PV would have a limited role in meeting capacity requirements in the winter (when solar insolation is low). Solar PV has the potential to reduce demand requirements other times of the year. As additional solar PV is incorporated though the net-metering program, it would be reflected in the net demand that is to be served.
Gas-fired resources provide considerable flexibility and can facilitate the integration of variable resources. Opportunities could exist for other technologies such as storage to provide similar services. Currently these technologies are higher cost than the resources considered. Opportunities exist to incorporate lessons learned from the various storage pilot projects underway.

31. Overview of Electricity System Cost Outlook: Outlooks C & D (continued)
As described in Module 4, Ontario faces sizeable and increasing opportunities for further deployment of cleaner technologies including distributed energy resources to meet higher demand outlooks. These opportunities are being driven by technological advancements, evolutions in policy and market design and increasing customer engagement.
No single technology is expected to fully meet potential increases in electricity demand. Some resources are baseload in nature, others are peaking. Some have higher costs, other lower. Some produce GHG emissions, while others do not.
To illustrate a range of potential electricity cost outlooks under higher demand outlooks, a number of resource outlooks are presented. The resource outlooks were constructed in the following manner:
The increase in capacity and energy requirements in Outlook C and Outlook D are met, taking into consideration reserve requirements
GHG emissions are kept at or below those illustrated in Outlook B
Sufficient resources are included to meet system operability requirements as they relate to ramping requirements (see Module 5) to facilitate the integration of renewable resources
Additional transmission is included to accommodate new resources
The electricity cost outlook in Outlook C and Outlook D reflect the capital investment in new resources, operations and maintenance cost, fuel cost, and incremental transmission investments
Due to the limited information available to the IESO, it was assumed that distribution system costs remain unchanged relative to Outlook B. However, it is recognized that these costs would also increase in order to accommodate the additional investments distribution companies would require to serve additional load.

32. Conservation opportunities in Outlooks C and D
All demand outlooks reflect the achievement of the 2013 LTEP conservation targets for existing loads.
A considerable amount of conservation is assumed in the demand outlooks. New loads that drive the increases in demand are assumed to occur efficiently (i.e. fuel switching leads to an uptake in heat pumps as opposed to baseboard heating) and there is limited potential for additional future conservation savings on fuel switching actions that are being undertaken (described further in Module 3).
Higher demand outlooks provide greater potential for electricity conservation from existing loads:
The value of conservation is greater in the higher demand outlooks because in these outlooks incremental conservation will avoid the construction of new electricity infrastructure and increase the avoided costs
These increased avoided costs of conservation will unlock conservation potential from existing end uses which are uneconomic under outlook B, supporting higher investment in more efficient technologies
The cost outlooks set out in the following slides provide an illustration of the cost of electricity service. Additional investments in cost effective conservation would help meet the demand and reduce the cost of electricity service as less infrastructure investment would be required
Further work is needed to understand the amount of available additional conservation potential under the higher demand outlooks. The cost analysis assists in the development of avoided costs for conservation potential assessments.

33. Capacity Contribution at Summer/Winter Peak
Input assumptions for cost, performance, maximum available capacity, and lead time for new resources
The input assumptions for each resource are based on the information provided in Module 4
Incremental Resource
LUEC
(2016$/MWh)
Capacity Cost
($/kW-year)
Capacity Factor
Construction
Lead Time
Capacity Contribution at Summer/Winter Peak
Notes
Simple Cycle Natural Gas-Fired Turbine
N/A
$135
0-1%*
3 years
89%/95%
Peak capacity
Large Nuclear
$120
85%
10 years
99%/90%
Waterpower
$140
50%
63%/67%
Maximum new, incremental waterpower capacity of 6,000 MW
Wind
$86
30%
10%/20%
Solar PV
$90 (2030)
15%
20%/3%
Bioenergy
$164
80%
90%/90%
Demand Response
$100
N/A*
85%/60%
Max capacity of 2,000 MW
Firm Imports
(<1,250 MW)
Up to 85%
5 years
95%/95%
Not available for winter capacity prior to 2028
(Up to 3,300 MW)
$160
*Simple Cycle Natural Gas-Fired Turbine and Demand Response are capacity based resources. The cost of these resources is not expressed as a LUEC (levelized unit energy cost) due to the limited amount of energy these resources are expected to provide (due to their low utilization).

34. Outlook C

35. Overview of Outlook C Electricity System Cost Outlook
In demand Outlook C, by 2035 the electricity peak demand is 2.5 GW (Summer) and 6.7 GW (Winter) more than in Outlook B and energy consumption is 30 TWh more. The increase in peak demand translates to an increase in total resource requirement of 5.6 GW after accounting for reserve requirements.
To illustrate the outlook for electricity costs in demand Outlook C, three illustrative resource outlooks were developed to reflect potential ways to address this particular higher demand future:
C1 “Wind, Waterpower, Demand Response, Firm Imports”: A mix of renewable resources are added supplemented by additional demand response for capacity and firm imports.
C2 “Wind, Demand Response, Gas, Firm Imports”: Assumes new waterpower is out of scope. Gas-fired resources are added to provide capacity.
C3 “Wind, Demand Response, Nuclear, Firm Imports”: Assumes new waterpower is out of scope but new nuclear is in scope to meet energy requirements.
The amount of new resources added is equivalent to the increase in capacity requirements and energy consumption relative to Outlook B. The bulk electricity system would require additional investments in transmission to incorporate these resource additions as outlined in the next slide.

36. Change in Resource Requirements: Outlook C
Three resource outlooks were developed to illustrate a range of possible approaches to meeting the increased demand in Outlook C

37. Change in Resource Requirements: Outlook C
Capacity Additions, MW
C1, Installed
C2, Installed
C3, Installed
Nuclear
1,700
Waterpower
2,500
Wind
2,550
5,950
1,550
Gas
1,900
Demand Response
600
900
800
Firm Imports
1,800
 Capacity Additions, MW
C1, At Peak
C2, At Peak
C3, At Peak
1,750
410
1,190
310
480
720
640

38. Electricity production in 2035 relative to 2015: Outlook C

39. Electricity production in 2035 relative to 2015: Outlook C
Energy Production, TWh
2015, Actual
2035, C1
2035, C2
2035, C3
Nuclear 92 73 86
Natural Gas 16 14 15
Waterpower 37 52 41
Solar PV, Wind & Bioenergy 29 40 28
Firm Imports 10 11

40. Bulk transmission requirements for Outlook C outlooks
The Outlook C outlooks require bulk transmission upgrades in order to be incorporated into the transmission system.
Estimated total capital costs of conceptual transmission options explored for Outlook C range between $4.0 billion and $9.5 billion (2016$), depending on the resource outlooks
Additional information on the nature of these transmission options can be found in Module 5
Resource Outlook
Transmission Projects to Enable New Resources
Total Capital Cost (2016$) C1
North-South Reinforcements, Sudbury West Reinforcements, Sudbury North Reinforcements, Enabling Facilities, New HVDC Line from Quebec to Lennox
$7.2 Billion C2
North-South Reinforcements, Sudbury West Reinforcements, Sudbury North Reinforcements, Enabling Facilities, New HVDC Line from Quebec to Lennox, West of London Reinforcements
$9.5 Billion C3
North-South Reinforcements, Sudbury West Reinforcements, Enabling Facilities, New HVDC Intertie from Quebec to Lennox, Reinforcements from Bowmanville to GTA, New HVDC Line from Quebec to Lennox
$4.0 Billion

41. Total Cost of Electricity Service: Outlook C

42. Total Cost of Electricity Service: Outlook C
Total Cost of Electricity Service (2016$ Billions)
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
C1 - Wind, Waterpower, Demand Response, Firm Imports
$20.7
$21.4
$21.3
$20.6
$21.6
$20.9
$21.5
$21.8
$21.7
$23.0
C2 - Wind, Demand Response, Firm Imports, Gas
$23.2
C3 - Wind, Demand Response, Nuclear, Firm Imports
$21.9
$22.8
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
$22.0
$22.6
$22.3
$22.2
$22.9
$23.3
$22.5
$22.4
$23.1
$22.1
$22.7

43. Average Unit Cost of Electricity Service: Outlook C

44. Average Unit Cost of Electricity Service: Outlook C
Average Unit Cost of Electricity Service (2016$/MWh)
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Demand: Outlook C (TWh)
144
143
145
146
147
148
149
151
C1 - Wind, Waterpower, Demand Response, Firm Imports
$144
$149
$148
$143
$147
$145
$153
C2 - Wind, Demand Response, Firm Imports, Gas
$154
C3 - Wind, Demand Response, Nuclear, Firm Imports
$151
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
152
154
156
158
161
163
166
170
173
177
$141
$138
$140
$135
$134
$132
$146
$150
$142
$139
$136
$130
$137
$131

45. Outlook D

46. Overview of Electricity System Cost Outlook: Outlook D
In demand Outlook D, by 2035 the electricity peak demand is 3.7 GW (Summer) and 13 GW (Winter) more than in Outlook B and energy consumption is 50 TWh more. The increase in peak demand translates to an increase in total resource requirement of 11.4 GW after accounting for reserve requirements.
To illustrate the outlook for electricity costs in demand Outlook D, four illustrative resource outlooks were developed to reflect potential ways to address this particular higher demand future:
D1 “Wind, Waterpower, Demand Response, Firm Imports”: A mix of renewable resources are added supplemented by additional demand response for capacity and firm imports.
D2 “Wind, Demand Response, Waterpower, Gas, Firm Imports”: Assumes gas-fired resources are added to supplement renewable additions. The gas-fired resource provides capacity and makes up for the lower capacity contribution of renewables.
D3 “Wind, Waterpower, Demand Response, Nuclear, Firm Imports”: Assumes new nuclear is in scope to meet energy requirements.
D4 “Wind, Demand Response, Nuclear, Gas, Firm Imports”: Assumes new nuclear is in scope to meet energy requirements. The gas-fired resource provides capacity and makes up for the lower capacity contribution of renewables.
The amount of new resources added is equivalent to the increase in capacity requirements and energy consumption relative to Outlook B. This is more than in Outlook C. The bulk electricity system would also require additional investments in transmission to incorporate new resources as outlined in the next slide.

47. Change in Resource Requirements: Outlook D
Four resource outlooks were developed to illustrate a range of possible approaches to meeting the increased demand in Outlook D
The four outlooks represent a diverse approach to meeting the higher demand outlook. The scale of new resource build demonstrates the challenges associated with significant electrification.

48. Change in Resource Requirements: Outlook D
Capacity Additions, MW
D1, Installed
D2, Installed
D3, Installed
D4, Installed
Nuclear
3,400
2,500
Waterpower
6,000
3,700
1,850
Wind
9,600
4,500
4,250
Gas
2,450
2,050
Demand Response
2,000
1,900
1,750
Firm Imports
3,300
D1, At Peak
D2, At Peak
D3, At Peak
D4, At Peak
4,200
2,950
1,295
1,920
1,200
900
850
1,600
1,520
1,400

49. Bulk Transmission Requirements for Outlook D outlooks
Outlook D outlooks require bulk transmission upgrades in order to be incorporated into the transmission system.
Estimated total capital costs of conceptual transmission options explored for Outlook C range between $7.4 billion and $24 billion (2016$), depending on the resource outlooks
Additional information on the nature of these transmission options can be found in Module 5
Resource Outlook
Transmission Projects to Enable New Resources
Total Capital Cost (2016$) D1
North-South Reinforcements, Sudbury West Reinforcements, Sudbury North Reinforcements, Enabling Facilities, New HVDC Line from Quebec to Lennox and a New HVDC Line from Quebec to GTA
$24 Billion D2
North-South Reinforcements, Sudbury West Reinforcements, Sudbury North Reinforcements, Enabling Facilities, New HVDC Line from Quebec to Lennox and a New HVDC Line from Quebec to GTA, West of London Reinforcements
$17.1 Billion D3
North-South Reinforcements, Sudbury West Reinforcements, Sudbury North Reinforcements, Enabling Facilities, New HVDC Line from Quebec to Lennox and a New HVDC Line from Quebec to GTA, Reinforcements from Bowmanville to GTA
$7.4 Billion D4
North-South Reinforcements, Sudbury West Reinforcements, Sudbury North Reinforcements, Enabling Facilities, New HVDC Line from Quebec to Lennox and a New HVDC Line from Quebec to GTA, Reinforcements from Bowmanville to GTA, West of London Reinforcements
$12.5 Billion

50. Electricity production in 2035 relative to 2015: Outlook D

51. Electricity production in 2035 relative to 2015: Outlook D
Energy Production, TWh
2015, Actual
2035, D1
2035, D2
2035, D3
2035, D4
Nuclear 92 73
101 87
Natural Gas 16 12 17 11
Waterpower 37 67 57 52 49
Solar PV, Wind & Bioenergy 14 48 40 36 35
Firm Imports  0 20

52. Total Cost of Electricity Service: Outlook D

53. Total Cost of Electricity Service: Outlook D
Total Cost of Electricity Service (2016$ Billions)
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
D1 - Wind, Waterpower, Demand Response, Firm Imports
$20.7
$21.3
$20.6
$21.7
$21.0
$23.1
$23.3
$23.2
$25.1
D2 - Wind, Waterpower, Demand Response, Firm Imports, Gas
$22.5
$22.8
$22.7
$24.7
D3 - Wind, Waterpower, Demand Response, Nuclear, Firm Imports
$21.6
$21.9
$22.2
$22.1
$24.0
D4 - Wind, Waterpower, Demand Response, Nuclear, Firm Imports, Gas
$22.4
$24.3
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
$25.2
$25.0
$26.5
$26.9
$27.7
$27.9
$23.8
$24.5
$24.2
$24.6
$25.5
$26.8
$27.1
$23.9
$23.6
$25.4
$25.8
$26.6
$27.5
$23.5
$24.4
$26.7
$27.0

54. Average Unit Cost of Electricity Service: Outlook D

55. Average Unit Cost of Electricity Service: Outlook D
Average Unit Cost of Electricity Service (2016$/MWh)
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Demand: Outlook D (TWh)
144
143
145
147
148
150
152
155
157
D1 - Wind, Waterpower, Demand Response, Firm Imports
$144
$149
$147
$142
$154
$153
$150
$160
D2 - Wind, Waterpower, Demand Response, Firm Imports, Gas
$157
D3 - Wind, Waterpower, Demand Response, Nuclear, Firm Imports
$146
$143
D4 - Wind, Waterpower, Demand Response, Nuclear, Firm Imports, Gas
$148
$145
$155
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
159
162
165
169
173
176
181
186
191
197
$151
$141
$138
$140
$139
$137

56. Summary

57. Range of 2035 Total Cost of Electricity Service: Outlooks A-D (2016$)
The total cost of electricity service in 2035 ranges from $18-28 billion (2016$) across the demand outlooks

58. Range of 2035 Total Cost of Electricity Service: Outlooks A-D (2016$)
Total Cost of Electricity Service, 2016$ Billions
Low Range
High Range
Outlook A
$17.8
$18.2
Outlook B
$19.4
Outlook C
$23.1
$23.3
Outlook D
$27.1
$27.9

59. Range of 2035 Average Unit Cost of Electricity Service: Outlooks A-D (2016$)
The 2035 average unit cost of electricity service ranges from $ /MWh (2016$) across the demand outlooks

60. Range of 2035 Average Unit Cost of Electricity Service: Outlooks A-D (2016$)
Average Unit Cost of Electricity Service, 2016$/MWh
Low Range
High Range
Outlook A
$134
$136
Outlook B
$131
Outlook C
$130
$132
Outlook D
$137
$142