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Appendices and Notes

Appendices, Notes, and Tables

An ongoing collection of calculations, data tables, and notes used for the book "No Illusions".
Ben Scott
Ben Scott
76 minute read
Appendices and Notes
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Appendix - Table of Contents

Appendix for Chapter 1

Appendix 1A - Wildfire Trends in Canada: Annual Area Burned by Decade (1991–2024)

Date Range Area Burned (ha) Avg Burned per Year (ha) Percent Change
1981 - 1990 19,586,010 (est.) 1,958,601 -
1991 - 2000 27,471,497 2,747,150 +40.3%
2001 - 2010 19,941,053 1,994,105 -27.4%
2011 - 2020 26,173,971 2,617,397 +31.3%
2021 - 2024 28,239,255 7,059,813.75 +169.7%

* Sources: National Forestry Database, Canadian Interagency Forest Fire Centre, Canadian National Fire Database

* Years 1981 and 1982 are estimates due to the data only being available in graph form.

Key Takeaways from Wildfire Trends in Canada (1991–2024)

Wildfires in Canada have increased significantly over the past three decades, with an unprecedented surge in the 2020s.

  1. Dramatic Increase: The average area burned per year in the 2020s is more than 2.7 times higher than the previous decade.
  2. Steady Trends Until 2020: Between 1991 and 2020, burned areas fluctuated, but the recent surge marks a sharp departure from past trends.
  3. Over 250% Growth: The annual burned area jumped from 2.6 million ha (2011–2020) to over 7 million ha (2021–2024).
  4. Climate Change Factor: The trend aligns with climate models predicting hotter, drier conditions and worsening fire seasons.
  5. Potential Record-Breaking Decade: With only four years of data, the 2020s have already surpassed past decades in total burned area.

Appendix for Chapter 3

Appendix 3A - Energy Calculations for Solar in Alberta:

Estimating Alberta's Electricity Demand

Key Assumptions: Calculation:
  • Total demand: 4.371 million × 17.9 MWh = 78,240,900 MWh/year (~78,000 GWh/year)
  • Required generating capacity: 78,240,900 MWh ÷ 8,760 hours/year = 8,932 megawatts (~9 gigawatts)

Solar Capacity Needed to Meet Demand

Key Assumptions:
  • Average capacity factor for solar in Alberta: 20%
    • For every 1 MW of installed capacity, only 0.2 MW is produced due to night hours and weather.
  • Existing renewable contribution: 15% of Alberta’s grid is already powered by renewables
Calculation:
  • Remaining demand: 78,240,900 MWh - 15% from renewables = 66,504,765 MWh from fossil fuels
  • Generating capacity needed: 66,504,765 MWh ÷ 8,760 hours/year = 7,592 MW
  • Solar capacity required: 7,592 MW ÷ 0.2 (capacity factor) = 37,960 MW
    • To put this in perspective, Alberta's total installed capacity in 2023 was 19,004 MW

Land Needed for Solar

With Alberta's solar capacity factor at 20%, we would need to install about five times the solar capacity to generate and store enough energy for non-sunny periods.

Key Assumptions:
  • Utility-scale solar farms require about 30-40 acres per 5 MW installation
  • 40 acres = 16 hectares, so ~3 hectares are needed per MW
  • With 5x capacity needed to ensure storage, we’d need 15 hectares per MW
Calculation:
  • 15 hectares/MW × 7,592 MW = 113,880 hectares

Key Takeaway

  • Calgary's land area: 82,500 hectares (825 km²)
  • Alberta's land area: 63.5 million hectares (~0.18% of Alberta's land would be needed for solar)

To replace fossil fuels with solar and meet Alberta’s electricity needs, we’d need to dedicate a land area 27.5% larger than the entire city of Calgary—around 0.18% of Alberta's total land area—exclusively for solar power production. While Alberta’s vast land area makes this achievable, smaller countries with less space may struggle to meet their energy needs through solar alone, highlighting the importance of a diversified energy mix that includes nuclear and other low-carbon options.

Appendix for Chapter 4

Appendix 4A - Comparing fossil fuel emissions to geothermal:

Energy Source CO2 Emissions (kg per Million Btu)
Coal (All types) 95.99
Natural gas 52.91
Geothermal (steam) 11.81
Geothermal (binary cycle) 0

* Source: U.S. Energy Information Administration

Appendix 4B - Power Plant Cost Estimates Per Kilowatt (2021 Data):

Power Plant Type Cost (USD per kW) Notes
Ultra Supercritical Coal (USC) $4,074  
USC with 90% CCS $6,495  
Natural Gas Combined Cycle (Single Shaft) $1,201  
Natural Gas Combined Cycle with 90% CCS $2,736  
Nuclear—Light Water Reactor $6,695  
Nuclear—Small Modular Reactor $6,861  
Onshore Wind $1,718 Price dropped by 27% from 2013 to 2021
Solar Photovoltaic with Tracking $1,327 Price dropped by 70% from 2013 to 2021
Solar PV with Storage $1,748  
Geothermal $3,076  
Conventional Hydroelectric $3,083  

* Source: EIA Assumptions 2021

Appendix 4C - Fuel Cost Comparison for Power Generation (2023):

This table compares the costs of power generation for fossil steam and nuclear energy, highlighting the impact of operating at full vs. partial capacity. Nuclear typically runs at around 92% capacity year round. Natural Gas (Fossil Steam) typically operates at around 54% capacity.

Fuel Type Cost per MWh Annual Cost per MW (100% Capacity) Annual Cost for 1000 MW (54% Capacity)
Fossil Steam $30.58 $267,880 $145 million
Nuclear $6.12 $53,611 $29 million

* Source: EIA Annual Electric Power Data (Mills per Kilowatt-hour)

Conversion Information:

  • 1 mill = 1/1,000 of a U.S. dollar = 1/10 of a cent
  • Mills per killowatt-hour is equivalent to dollars per megawatt-hour
  • Hours in a year = 365 days x 24 hours = 8,760 hours
  • To calculate annual cost per MW, multiple 8,760 hours times the cost per megawatt

Key Takeaways:

  • 1000 MW Fossil Steam Facility (54% capacity): $145 million/year
  • Natural Gas fuel cost over 30 year facility lifespan (at 54% capacity): $4.34 billion
  • Nuclear fuel cost over 30 year facility lifespan (at 54% capacity): $868.5 million (20% of the cost of natural gas)

Appendix 4D - Cost Estimations of Power Plants (2021):

Plant Type Capacity Factor (%) Capital Cost ($/MWh) LCOE ($/MWh) Value-Cost Ratio
Coal 85 $52.11 $82.61 0.47
Natural Gas (Combined Cycle) no CCS 87 $9.36 $39.94 0.99
Advanced Nuclear 90 $60.71 $88.24 0.47
Geothermal 90 $22.04 $39.82 1.20
Wind (Onshore) 41 $29.90 $40.23 0.88
Solar (Standalone) 29 $26.60 $36.49 0.98
Hydroelectric 54 $46.58 $64.27 0.60

* Source: U.S. Energy Information Administration

Understanding The Data

The data assumes a standard operational lifetime of 30 years for most plant types. In reality, the actual lifespan depends on various factors, including the technology used. For example, nuclear power plants tend to operate for 60 years or more, which significantly improves their value-cost ratio.

  1. Capacity Factor: The percentage of maximum potential output that a plant typically achieves over a year.
  2. Capital Cost: The cost of building the plant, amortized over its operational life.
  3. LCOE (Levelized Cost of Electricity): The average cost to produce electricity, including capital, operating, and fuel costs.
  4. Value-Cost Ratio: The average economic value of the energy relative to its cost. A ratio above 1.0 indicates cost-effectiveness.

Appendix 4E: Calculating the Costs and Revenue Potential for Generating Enough Geothermal Energy to Power All 1.7 Million Albertan Homes

This figure outlines the estimated construction, operating, and revenue potential for a geothermal energy facility sufficient to power Alberta’s 1.7 million homes.

Category Details Values
Energy Requirements Energy requirement per home 7,200 kWh
  Energy requirement to power 1.7m homes 12,240,000,000 kWh
Construction Costs Required Capacity 1,553 MW (at 90% capacity)
  Capital Cost per MW $5,250,000 CAD (2023 $)
  Total Capital Cost $8.15 billion CAD
Operating & Maintenance Costs Annual O&M Cost per MWh $24 CAD (17.78 USD)
  Total Annual O&M Cost $293.76 million CAD
  O&M Cost over 30 years $8.81 billion CAD
Loan Repayment Total Interest (4% rate, 30 years) $5.86 billion CAD
  Total Loan Repayment $14.01 billion CAD
  Annual Loan Repayment (over 30 years) $466.91 million CAD
Revenue & Profit Annual Revenue (at $0.166/kWh) $2.03 billion CAD
  Gross Annual Profit (Revenue - O&M) $1.736 billion CAD
  Taxes (27%) $468.78 million CAD
  Net Annual Profit (After Taxes) $1.267 billion CAD
  Net Annual Profit after Loan Repayment $800.1 million CAD

* Sources: Clean Energy BC, EIA Electricity Generation

Appendix for Chapter 5

Appendix 5A – Comparing CO₂ Emissions from Oil vs. Lithium Production

  • Hard-rock lithium extraction releases about 15 tonnes of CO₂ for every tonne of lithium produced. (Source: BBC Future)
  • A barrel of crude oil weighs roughly 300 pounds, or about 136 kilograms. (Source: Energy Education)
  • Carbon intensity varies by operation. The least carbon-intensive sources produce 39 kg of CO₂ per barrel, while the most intensive produce 127 kg per barrel. (Source: Maclean’s)
  • Conversion calculation
    • 1 tonne of oil = 1,000 kg
    • 1,000 kg ÷ 136 kg per barrel ≈ 7.35 barrels
    • 7.35 barrels × 127 kg CO₂ per barrel ≈ 934 kg of CO₂ per tonne of oil
  • Relative carbon intensity
    • 15,000 kg CO₂ (per tonne of lithium mined) ÷ 934 kg CO₂ (per tonne of oil) = 16.06 times more emissions than oil production.

Pound for pound, hard-rock lithium mining is about sixteen times more carbon-intensive than even the dirtiest crude oil extraction.

Appendix 5B – Calculating the Cost of TransCanada EV Charging Network

  • Number of Charging Stations: 15,000 (along the Trans-Canada Highway)
  • Average Cost Per Fast-Charging Station: $125,000 (hardware + installation)
  • Total Cost for EV Charging Network (All Stations): 15,000 × $125,000 = $1,875,000,000

Appendix 5C – Calculating the Refueling Potential for Electrolysis Network

  • Number of Electrolysis Stations: 780 (along the Trans-Canada Highway)
  • Electrolysis Energy Requirement: 50 kWh per kg of hydrogen
  • Solar Capacity Factor: 1 MW × 14% capacity = 140 kW average output
  • Daily Hydrogen Output per Station: 140 kW × 24 hrs = 3,360 kWh/day ÷ 50 kWh = 67.2 kg of H₂ per day
  • Vehicle Tank Size: 5.6 kg tank (Toyota Mirai)
  • Annual Refueling Capacity (All Stations): 365 days × 67.2 kg/day × 780 stations ÷ 5.6 kg/tank = 3,416,400 tanks refilled per year

Appendix for Chapter 7

Appendix 7A – Calculating the Annual Energy Used in the Oil Sands

  • Source: Investopedia – Barrel of Oil Equivalent
    • The energy contained in a barrel of oil is approximately 5.8 million British thermal units (MBtus) or 1,700 kilowatt-hours (kWh).
  • Source: Oil Sands Magazine – Alberta Oil & Bitumen Production Records (2022)
    • Both conventional oil and oil sands output reached a new annualized record high. Total in-situ production edged out mining in 2022, averaging 1.72 million barrels per day for the year.
  • Annual production:
    • 1.72 million barrels per day × 365 days = 627.8 million barrels per year
  • Source: Scientific American – The Dirt on Oil Sands
    • With an EROI of 5, 1 barrel is used to extract every 5 barrels.
    • 627.8 million barrels ÷ 5 = 125.6 million barrels used for extraction.
  • Energy consumption for extraction:
    • 125.6 million barrels × 1,700 kWh = 213.52 billion kWh
  • Average continuous power demand:
    • 213.52 billion kWh ÷ 365 days ÷ 24 hours = 24.37 million kilowatts (or 24.37 gigawatts)

Appendix 7B – Calculating the oil sands carbon emissions equivalent in cars

  • Source: United States Environmental Protection Agency
    • A typical passenger vehicle emits about 4.6 metric tons of carbon dioxide per year.
  • Source: Government of Alberta
    • Oil sands operations currently emit roughly 70 Megatonnes (Mt) per year.
  • Oil Sands CO2 emissions equivalent in cars:
    • 70 million tonnes (70 Mt) of CO2 ÷ 4.6 tonnes per car = 15.2 million cars

Appendix 7C – Calculating the Bioplastic Capacity of Hemp Compared to Oil

Oil Sands Production and Plastic Usage

  • An estimated 10% of oil and gas is used to produce plastics.
    • 87% is burned for transport, electricity, and heating.
  • Oil sands output in 2021: 3.46 million barrels per day
  • Annual production: 3.46 million × 365 = 1.26 billion barrels per year
  • Each barrel contains 136 kg of oil → 1.26 billion × 136 kg = 171 billion kg, or 171 million tonnes of oil annually
  • Portion of Albert’s oil sands production used for plastic (10%):
    • 10% of 171 million = 17.1 million tonnes

Hemp Yield and Cellulose Content

  • Canadian hemp can produce between 2 to 10 tonnes of biomass per hectare, depending on cultivar. For this calculation, we’ll use an average of 5 tonnes per hectare.
  • Cellulose makes up approximately 60% of the stalk, concentrated in the bast fibers.
  • 5 tonnes × 60% = 3 tonnes of usable cellulose per hectare

Hemp Required to Offset Oil-Derived Plastic To replace 17.1 million tonnes of oil used for plastic with hemp-based bioplastic:

  • 17.1 million tonnes ÷ 3 tonnes/hectare = 5.7 million hectares needed

How Much Farmland Would That Require?

  • Canada has 62.2 million hectares of farmland
  • Alberta has 19.9 million hectares of farmland
  • 3.43 million hectares = 9.2% of Canada’s farmland

Replacing all plastic derived from the oil sands with hemp-based bioplastic would require:

  • 9.2% of total farmland in Canada, or
  • 28.6% of Alberta’s farmland alone

* Sources: Government of Alberta, British Plastics Federation, Canada Energy Regulator, Agriculture and Agri-Food Canada, Statistics Canada

Appendix for Chapter 8

Appendix 8A – Estimating Hydrogen Production from Plasma Arc Gasification

Context Plasma arc gasification not only eliminates waste but produces synthesis gas (syngas) rich in hydrogen. With proper recovery systems, that hydrogen can be separated and used as a clean fuel. The following calculation estimates how much hydrogen a single large-scale facility could generate annually.

References

Calculation

  1. Feedstock capacity: A large PAG facility processes 3,000 U.S. tons (2,720 metric tonnes) of waste per day.
  2. Syngas yield: Assuming 25% of total energy is lost to the process (80% recovered – 5% for torches = 75%), output = 2,040 tonnes of syngas per day.
  3. Hydrogen content: At 25% H₂, with 90% recovery = 22.5% hydrogen by mass.
  4. Daily hydrogen production:
    • 2,040,000 kg syngas × 22.5% = 459,000 kg of hydrogen per day.
  5. Annual production:
    • 459,000 × 260 working days = 119,340,000 kg (119,340 tonnes) per year.
  6. End-use example (Toyota Mirai fuel cell vehicle):
    • Each tank requires 5.65 kg hydrogen.
    • 119,340,000 ÷ 5.65 = ≈21.1 million full tanks per year.

Result One plasma arc gasification facility could produce enough hydrogen annually to fuel over 20 million hydrogen cars, underscoring its potential as both a waste solution and a major contributor to the clean energy transition.

Appendix for Chapter 10

Appendix 10A – Estimated Carbon Pricing Revenues (2022–2030)

This is a conservative, ballpark estimate of carbon pricing revenue across Canada. It does not include all provincial revenues and excludes Quebec’s cap-and-trade system due to structural differences in how revenue is generated and reported. The “federal” pool includes revenues collected in provinces and territories without their own carbon pricing systems (e.g. Alberta, Saskatchewan, Manitoba, Ontario, Yukon, Nunavut).

Total estimated carbon pricing revenue (2022): ~$11.0 billion (excluding Quebec)

Year Revenue ($CAD) Tax Rate ($/tonne) Annual $ Increase Annual % Increase
2022 $11,000,000,000 $50 – –
2023 $14,300,000,000 $65 $15 30.00%
2024 $17,600,000,000 $80 $15 23.08%
2025 $20,900,000,000 $95 $15 18.75%
2026 $24,200,000,000 $110 $15 15.79%
2027 $27,500,000,000 $125 $15 13.64%
2028 $30,800,000,000 $140 $15 12.00%
2029 $34,100,000,000 $155 $15 10.71%
2030 $37,400,000,000 $170 $15 9.68%
Total $218,800,000,000 – – –

Appendix for Chapter 11

Appendix 11A – Estimated Number of Wind Turbines Required to Replace Fossil Fuels in Canada

  • Average National Capacity Factor for Wind Turbines: 30% Source: International Energy Agency: Report 2022 Canada https://iea-wind.org/wp-content/uploads/2023/10/Canada_2022.pdf
  • Effective capacity of a 2 MW wind turbine: 600 KW or about 5,256 MWh
  • Canada’s total electricity generation in 2024: 622.2 million megawatt-hours (MWh) Source: Statistics Canada https://www150.statcan.gc.ca/n1/daily-quotidien/251022/dq251022c-eng.htm
  • Percent of electricity generated by fossil fuels: 19.2%
  • Approximate total electricity generated from fossil fuels: 622.2 million MWh * 19.2% = 119.5 million MWh
  • Number of 2MW Wind Turbines Required to Replace Fossil Fuels: 119.5 million MWh ÷ 5,256 MWh = 22,736 wind turbines

Appendix 11B – Calculating Levelized Costs for Power Plant Technologies

Technology Capex ($B) Fixed O&M 30y ($B) Variable O&M 30y ($B) Fuel 30y ($B) Capacity Factor Generation 30y (TWh) Total 30y ($B) All-in ($/MWh)
Natural Gas CC (multi-shaft) 0.824 0.370 0.546 4.479 60% 157.680 6.219 39.44
Geothermal 3.097 4.888 0.000 0.000 90% 236.520 7.986 33.76
SMR (Nuclear) 9.314 3.717 0.763 1.656 90% 236.520 15.449 65.32
Solar PV (tracking) 1.379 0.687 0.000 0.000 20% 52.560 2.066 39.31
Wind (onshore) 1.626 1.007 0.000 0.000 30% 78.840 2.633 33.39

This table compares the 30-year lifetime cost of a 1 GW power plant across five technologies: natural gas combined cycle (multi-shaft), geothermal, small modular nuclear (SMR), solar PV (with sun tracking), and onshore wind. Cost inputs (capital costs, fixed and variable operations and maintenance costs, and gas plant heat rate) are taken from the U.S. Energy Information Administration (EIA), Annual Energy Outlook 2025 — Electricity Market Module assumptions (Table 3), based on 2024 USD. Source: EIA, AEO2025 Electricity Market Module Assumptions — Table 3.

To estimate total lifetime cost, the following components were calculated and summed for each technology:

  • Capex ($B): Overnight construction cost = Capex ($/kW) × 1,000,000 kW
  • Fixed O&M (30y) ($B): Fixed O&M ($/kW-year) × 1,000,000 kW × 30 years
  • Variable O&M (30y) ($B): Variable O&M ($/MWh) × total lifetime generation (MWh)
  • Fuel cost (30y) ($B):
    • Natural gas: Heat rate (Btu/kWh) → MMBtu/MWh × gas price ($/MMBtu) × generation (MWh)
    • Nuclear: fuel cost assumed at $7/MWh × generation
    • Wind/solar/geothermal: $0 fuel cost assumed

Total lifetime generation is calculated as:

  • Total generation (30y): 1,000 MW × 8,760 hours/year × 30 years × capacity factor

Finally:

  • All-in cost ($/MWh): Total lifetime cost ÷ total lifetime generation (MWh)

Assumptions:

To reflect typical utilization, the following average capacity factors were assumed:

  • Natural gas CC: 60 percent
  • Geothermal: 90 percent
  • SMR (nuclear): 90 percent
  • Wind: 30 percent
  • Solar PV: 20 percent

Fuel cost assumptions:

  • Natural gas price modeled as $3.50/MMBtu in year 1 and $4.60/MMBtu in years 2–30 (average ≈ $4.56/MMBtu over 30 years).
  • Nuclear fuel modeled as a flat $7/MWh (used as a simple proxy).

Note: This is a simplified levelized-cost comparison. It does not include financing costs (discount rates, interest during construction), transmission buildout, curtailment, or the additional backup/storage required to make intermittent generation fully equivalent to firm generation.

Appendix 11C – Calculating Clean Energy Capacity Required to Replace Fossil Fuels in Canada (2024)

In 2024, Canada generated 142.4 TWh of electricity from fossil fuels. To estimate how much firm clean energy would be required to replace this generation (e.g., geothermal or nuclear), we can convert annual electricity output (TWh) into an equivalent average power requirement (MW), then adjust for capacity factor.

  • Total electricity generated by fossil fuels (2024): 142.4 TWh/year (Natural gas — 110 TWh, Coal — 25.1 TWh, Other fossil — 7.3 TWh) Source: Ember Energy — Electricity Data Explorer (Canada, 2024) https://ember-energy.org/data/electricity-data-explorer/?entity=Canada&chart=single_year&tab=main

  • Equivalent average power requirement (100% capacity factor): 142.4 TWh = 142,400,000 MWh 142,400,000 MWh ÷ (24 × 365) = 16,255.71 MW

  • Installed capacity required at 92% capacity factor (geothermal / nuclear): 16,255.71 MW ÷ 0.92 = 17,669.25 MW

  • Planning allowance (future demand + reliability margin): Rounded estimate = 18,000 MW (18 GW)

Appendix 11D – Capital and Operating Cost Assumptions for Clean Baseload Power

This appendix documents how capital cost assumptions for geothermal power and Small Modular Reactors (SMRs) were derived for Chapter 10, including source data, scope, and currency conversion. All costs are expressed in Canadian dollars per gigawatt of nameplate capacity (after conversion from USD), consistent with the plan’s total build target of 18 GW nameplate.

Scope and capacity basis

  • Firm power required: ~16.3 GW
  • Average capacity factor assumed: ~92 percent
  • Total nameplate capacity built: ~18 GW

Because nameplate capacity has already been sized to account for capacity factor, no additional capacity-factor adjustment is applied to capital costs.

Geothermal capital cost (~$8.83 billion per GW)

The U.S. Energy Information Administration (EIA) reports overnight geothermal plant costs of approximately:

  • $3,097 USD per kW (overnight geothermal plant costs)

However, overnight costs exclude exploration, confirmation drilling, dry-hole risk, and system-level development. Studies that account for fully developed geothermal systems typically place costs in the range of US$5,000–6,500 per kW. To remain conservative and to reflect early-stage development and drilling risk, this analysis adopts the upper end of that range.

For planning purposes, this analysis adopts a conservative system-level cost of:

  • US$6,500 per kW

Converted at a representative exchange rate of 1 USD ≈ 1.36 CAD:

  • ~$8.83 billion CAD per GW nameplate

SMR capital cost (~$14.63 billion per GW)

The U.S. Energy Information Administration (EIA) reports overnight capital costs for advanced nuclear reactors, including Small Modular Reactor designs, of approximately:

  • $9,314 USD per kW (overnight SMR nuclear plant costs)

Published cost estimates for early-fleet SMRs generally fall in the range of $9,000–13,500 USD per kW, reflecting first-of-a-kind construction, regulatory risk, and limited standardization.

This analysis uses a conservative early-fleet average of: $10,500 USD per kW

Converted to Canadian dollars: ~$14.63 billion CAD per GW nameplate

Capital Cost Assumptions

The plan assumes a 50/50 split between geothermal and SMR capacity.

  • Geothermal capital cost: ~$8.83 billion per GW
  • SMR capital cost: ~$14.63 billion per GW

The average capital cost per gigawatt is calculated as the midpoint of these two technologies:

  • Average capital cost: (8.83 + 14.63) ÷ 2 ≈ $11.73 billion per GW

Applied to 18 gigawatts of total capacity:

  • Total capital investment: 18 GW × $11.73 billion per GW ≯ $211.14 billion

These figures reflect system-level capital costs and do not assume cost reductions from learning curves, fleet deployment, or financing reforms discussed elsewhere in this chapter.

Operating and Maintenance Cost Assumptions

Operating and maintenance (O&M) costs are based on published fixed and variable O&M reference values for geothermal and nuclear facilities, drawn primarily from U.S. Energy Information Administration (EIA) and International Energy Agency (IEA) sources. A blended average is used, weighted evenly across geothermal and SMR capacity to reflect the plan’s 50/50 technology split.

For planning purposes, O&M costs are treated as Canadian-dollar costs and are not converted from USD, since the majority of operating expenses—labour, maintenance, services, and local operations—would be incurred domestically. Fuel cost estimates, where applicable, are converted from USD to CAD, reflecting exposure to international commodity pricing.

Geothermal

  • Fixed O&M: $150.60/kW-year
  • Variable O&M: $0.00/MWh

SMR Nuclear

  • Fixed O&M: $121.99/kW-year
  • Variable O&M: $3.19/MWh

Convert fixed O&M to $/MWh

  • At 92 percent capacity factor, 1 GW produces:
    • 1,000 MW × 8,760 hours × 0.92 = 8,059,200 MWh/year

Geothermal fixed O&M per MWh

  • $150.60 million per GW-year ÷ 8,059,200 MWh ≈ $18.69/MWh (plus $0 variable)

SMR non-fuel O&M per MWh

  • fixed: $121.99 million ÷ 8,059,200 ≈ $15.14/MWh
  • plus variable: $3.19/MWh
  • total ≈ $18.33/MWh

Average O&M per MWh for combined SMR and Geothermal (assuming 50/50 split):

  • Average O&M cost: (18.69 + 18.33) ÷ 2 ≈ $18.51/MWh (non-fuel O&M, USD basis)

Annual electricity generation is calculated as:

  • 18,000 MW × 8,760 hours × 0.92 ≈ 145,065,600 MWh per year

Annual O&M costs (before fuel):

  • 145,065,600 MWh × $18.51 = 2,244,164,832 per year ≈ $2.69 billion per year

Annual O&M costs (including nuclear fuel):

  • Assumed Fuel Price = $7.00 USD per MWh
  • SMR output ≈ 8,760 hours × 9,000 MW × 0.92 ≈ 72,532,800 MWh/year (9,000 MW of installed capacity is half of the total required)
  • Fuel ≈ 72,532,800 × 7 ≈ $0.51B USD/year ≈ $0.69B CAD/year (assumes a 1.36% exchange rate)

Total Projected Operating Costs: ~$2.69B CAD/year (non-fuel O&M) + ~$0.69B CAD/year (SMR fuel) ≈ $3.4 billion CAD/year

Summary

  • Average capital cost: ~$11.73 billion per GW
  • Total capital investment: ~$211.14 billion
  • Annual O&M costs: ~$3.4 billion

Appendix 11E – Revenue and Carbon Offset for Clean Baseload Power

Annual net revenue

This section estimates annual net revenue from 18 GW of firm clean baseload capacity (50 percent geothermal / 50 percent SMR), using a single electricity price assumption grounded in provinces where fossil generation is more prevalent.

Inputs

  • Nameplate capacity: 18 GW = 18,000 MW
  • Capacity factor: 0.92
  • Hours/year: 8,760
  • Annual generation: 18,000 × 8,760 × 0.92 = 145,065,600 MWh/year
  • Annual operating costs (incl. SMR fuel): $3.4B CAD/year (from Appendix 10E)
  • Total capital investment: $211.14B CAD (from Appendix 10E)
  • Effective borrowing interest rate: 2.5 percent
  • Effective tax rate: 25 percent

Electricity price assumption (single price)

To avoid cherry-picking low-cost hydro provinces, we use a simple average of published/regulated energy rates (¢/kWh) from provinces that rely more heavily on fossil generation:

  • Alberta (Rate of Last Resort): 12.02 ¢/kWh (as of January 1, 2025)
  • Saskatchewan (Saskatoon Light & Power energy charge): 16.38 ¢/kWh (as of January 1, 2025)
  • Nova Scotia Power (Domestic Service energy charge): 18.187 ¢/kWh (as of January 1, 2026)
  • New Brunswick Power (Residential Service – urban): 15.17 ¢/kWh (as of April 1, 2025)

Assumed electricity price (simple average):

  • (12.02 + 16.38 + 18.187 + 15.17) ÷ 4
  • = 15.439 ¢/kWh ≈ $0.15439/kWh
  • = $154.39 per MWh

Note: these are customer-facing energy charges/rates (not wholesale). Using retail-ish prices is deliberate here because the plan’s “return” is ultimately captured through what the electricity system can charge and recover over time.

Revenue Calculations

Step 1 — Annual gross revenue:

  • 145,065,600 MWh × $154.39/MWh = $22.40B CAD per year

Step 2 — Operating margin (after O&M):

  • $22.40B − $3.40B = $19.00B CAD per year

Step 3 — Annual financing cost (effective interest):

  • $211.14B × 2.5 percent = $5.28B CAD per year

Step 4 — Pre-tax profit:

  • $19.00B − $5.28B = $13.72B CAD per year

Step 5 — Taxes (25 percent):

  • $13.72B × 0.25 = $3.43B CAD per year

Step 6 — Annual net revenue (after O&M, interest, and tax):

  • $13.72B − $3.43B = $10.29B CAD per year

NOTE: This analysis applies a conservative flat tax rate for simplicity. In practice, large clean energy projects in Canada qualify for accelerated capital cost allowance, substantially reducing taxable income in early years. As a result, actual taxes paid would be materially lower than modeled here, particularly during the amortization period. Net revenues presented in this appendix should therefore be understood as conservative estimates.

Annual net revenue summary

  • Gross revenue: ~$22.4B per year
  • Net operating revenue (after O&M): ~$19.0B per year
  • Net revenue after interest: ~$13.7B per year
  • After-tax net revenue: ~$10.3B per year

Capital payback period

This section estimates how long it takes for the project to recover its initial capital investment using the annual net revenue calculated above.

Inputs

  • Total capital investment: $211.14B CAD (Appendix 10E)
  • Annual net revenue (after O&M, interest, and tax): ~$10.29B CAD/year (Appendix 10F)

Payback calculation

  • Payback period = Total capital investment ÷ Annual net revenue
  • $211.14B ÷ $10.29B/year
  • ≈ 20.5 years

Result

At the assumed electricity price and financing/tax assumptions used in this appendix, the clean baseload build reaches capital payback in roughly 20–21 years.

Note: This is a simplified payback estimate using a steady annual net-revenue figure. It does not model ramp-up timing, principal repayment schedules, depreciation/tax shielding, or changes in electricity prices over time.

Net profit over a 30-year lifespan

This section estimates cumulative net profit over a 30-year horizon using a mortgage-style financing model, and then accounts for the post-amortization surplus once the capital investment has been fully repaid.

Financing recap

  • Total capital investment: $211.14B CAD
  • Amortization period: 30 years
  • Effective interest rate: 2.5 percent
  • Annual debt service (principal + interest): ~$10.0B CAD/year
  • Annual net operating revenue (after O&M and tax, before debt service): ~$10.29B CAD/year

Phase 1: During amortization (Years 1–30)

For the first 30 years, annual net operating revenue is primarily used to service capital.

  • Annual net operating revenue: ~$10.29B
  • Annual debt service: ~$10.0B

Annual retained surplus during amortization:

  • $10.29B − $10.0B = ~$0.29B CAD/year

Cumulative retained surplus (Years 1–30):

  • $0.29B × 30 ≈ $8.7B CAD

By the end of year 30:

  • The entire $211.14B capital investment has been repaid
  • The system owns 18 GW of fully paid-off, firm clean baseload capacity
  • No further revenue is required to service debt

Phase 2: Post-amortization surplus (Year 31 onward)

Once the capital is fully repaid, annual revenues are no longer consumed by debt service.

At current prices and assumptions:

  • Annual net operating revenue (no debt service): ≈ $10.29B CAD/year

This represents true surplus—available for rate reductions, reinvestment, public revenue, or accelerated decarbonization elsewhere in the economy.

Even without assuming price growth or efficiency gains:

  • Post-amortization surplus over 10 years (Years 31–40): ≈ $103B CAD

Total net value over the modeled horizon

Over the first 30 years alone, the system:

  • Fully repays $211.14B in capital
  • Generates ~$8.7B in retained surplus
  • Delivers zero-emissions baseload power throughout

From year 31 onward, the system transitions from a debt-servicing asset to a high-margin public energy asset, generating on the order of $10B per year in net surplus at 2025 electricity prices.

Depreciation and Capital Cost Allowance (CCA) Adjustment

The net revenue figures above are deliberately conservative. They assume a steady effective tax rate throughout the amortization period and therefore understate retained value in the early and middle years of operation. In reality, capital-intensive infrastructure such as geothermal and nuclear power benefits from accelerated capital cost allowance (CCA) and interest deductibility, which significantly reduce taxable income while capital is being repaid. Rather than modeling a detailed year-by-year depreciation schedule, this adjustment treats taxes avoided through CCA as retained value over the 30-year financing horizon.

Planning-level impact:

  • Conservative retained surplus (no CCA): ~$8.7B over 30 years
  • Estimated taxes avoided through CCA: ~$30–60B over 30 years
  • CCA-adjusted retained value: ~$29–59B over the first 30 years
  • Capital fully repaid: $211.14B
  • Post-amortization surplus (year 31+): ~$10B per year at 2025 electricity prices
  • Total surplus from year 31-50: ~$200B per year

This does not change the underlying economics of the system. The conservative case demonstrates viability even under simplified assumptions. The CCA-adjusted case reflects how large-scale energy infrastructure is actually financed and taxed in practice, and why public ownership or public-backed financing materially improves long-term outcomes.

Annual emissions avoided (coal + natural gas displacement)

This estimate calculates direct (stack) CO₂ emissions avoided by replacing fossil baseload generation with 18 GW of firm clean power (50 percent geothermal / 50 percent SMR).

Emissions factors (direct stack CO₂):

Converted to metric:

  • Natural gas: 0.443 t CO₂ per MWh
  • Coal: 1.024 t CO₂ per MWh

Annual clean electricity generation:

  • 18,000 MW × 8,760 hours × 0.92 = 145,065,600 MWh per year

Displacement assumption (conservative and realistic):

  • Coal is displaced first (as baseload)
  • Remaining clean generation displaces natural gas

Coal displacement:

  • Canada coal power emissions (2024): ~22.5 Mt CO₂e Source: Ember Energy
  • Implied coal generation displaced: 22.5 Mt ÷ 1.024 t/MWh ≈ 22.0 TWh per year

Natural gas displacement:

  • Remaining clean generation: 145.1 TWh − 22.0 TWh ≈ 123.1 TWh per year
  • Avoided gas emissions: 123.1 TWh × 0.443 t/MWh ≈ 54.5 Mt CO₂ per year

Total annual emissions avoided:

  • Coal: ~22.5 Mt CO₂
  • Natural gas: ~54.5 Mt CO₂
  • Total: ~77 Mt CO₂ per year

Planning note:

  • This estimate includes direct stack CO₂ only
  • It excludes upstream methane leakage
  • It does not assume displacement of oil-fired generation
  • Ember’s reported totals use CO₂e, so minor differences are expected

Appendix 11F – Carbon Capture Retrofit Cost Model (Natural Gas Power Plants)

1. Baseline Emissions

According to Canada’s National Inventory Report, natural gas–fired electricity generation emitted approximately:

  • 24.1 megatonnes (Mt) CO₂e in 2023

This figure is used as the baseline for modeling carbon capture retrofits.

Not all natural gas facilities are suitable candidates for retrofit. Low-utilization peaker plants operate only during short periods of peak demand and are unlikely to justify capital-intensive upgrades. This model assumes retrofits target high- and mid-merit facilities responsible for the majority of emissions.

For modeling purposes, we assume:

  • Eligible emissions base: ~24.1 Mt CO₂e annually
  • Capture rate: 90 percent

Estimated annual emissions avoided:

  • 24.1 Mt × 90 percent = 21.7 Mt CO₂e avoided per year

This is the maximum technical capture potential if the majority of baseload and mid-merit gas units are retrofitted.

2. Installed Capacity Assumptions

Installed natural gas generation capacity in Canada (2023): 23.66 GW

Not all of this capacity operates at high utilization. For modeling purposes, we assume:

  • ~70 percent of capacity is suitable for retrofit
  • Retrofit target: ~16–17 GW

For calculation simplicity, this appendix uses: 17 GW retrofit target

3. Capital Cost of Retrofit

Estimated retrofit cost for NGCC plants with carbon capture: ~$1,700 CAD per kW

This estimate reflects inflation-adjusted values from historical CCS retrofit studies and current industry cost ranges.

Total retrofit capacity: 17 GW = 17,000,000 kW

Capital cost calculation:

  • 17,000,000 kW × $1,700/kW = $28.9 billion CAD total capital investment
  • Rounded: ~$29 billion

4. Operating Cost of Carbon Capture

Estimated cost to capture and manage CO₂: ~$70 per tonne CO₂

Annual captured emissions: 21.7 Mt × $70 = $1.52 billion per year operating cost

(If capture rates or cost per tonne vary, this number scales proportionally.)

5. Annualized Capital Cost

Assuming 25-year amortization: $29 billion ÷ 25 years = $1.16 billion per year

Total annual cost (capital + operating): $1.16B + $1.52B = $2.68 billion per year

6. Electricity Output Estimate

To convert costs into per-kWh impact, we estimate total annual gas generation.

Using installed capacity:

  • 17 GW × 55 percent average capacity factor = 9.35 GW effective output
  • 9.35 GW × 8,760 hours = 81.9 TWh annually

81.9 TWh = 81.9 billion kWh

7. Cost Impact per kWh

Total annual cost ÷ annual generation: $2.68B ÷ 81.9B kWh = $0.0327 per kWh (~3.3 cents per kWh)

8. Estimated Household Impact

  • Capital base: $29B
  • Annual O&M (capture operations): $1.518B/year
  • Annual gas electricity (implied by 24.1 Mt at 0.185 kg/kWh): 130.27B kWh/year
  • Household usage: 7,200 kWh/year (average Alberta household electricity consumption)
  • Amortization formula: annual payment = (P \times \frac{r(1+r)^n}{(1+r)^n-1})

Scenario A — Full Market Pass-Through (Baseline Stress Case)

Assumptions:

  • Retrofit financed privately
  • 7–8 percent borrowing cost
    • At 8 percent over 25 years → ~$2.72 billion per year
  • Full cost recovered through rates
  • 25-year amortization

Total cost:

  • ~3.25 cents per kWh
    • (Borrowing cost + O&M costs) ÷ total kWh = $/kWh
    • ($2.72B + $1.518B) ÷ 130.27B kWh = $0.0325/kWh
  • ~$234 per year household impact
    • 7,200 × $0.0325 = $234

Scenario B — Federal Low-Cost Financing

Assumptions:

  • Capital financed at 2–3 percent via federal green bonds
    • 30-year amortization
    • At 3 percent over 30 years → ~$1.48 billion per year
  • No capital grant
  • O&M still recovered through rates

Total cost:

  • ~2.30 cents per kWh
    • (Borrowing cost + O&M costs) ÷ total kWh = $/kWh
    • (1.48B + 1.518B) ÷ 130.27B kWh = $0.0230/kWh
  • ~$166 per year household impact
    • 7,200 × $0.0230 = $166

Lower interest + longer amortization materially reduces annual capital burden.

Scenario C — Blended Federal Support Model

Assumptions:

  • 30 percent capital offset via federal grants or tax credits
  • Remaining financed at 3 percent
    • $29 billion × 70 percent = ~$20.3B financed
    • 30-year amortization
    • At 3 percent over 30 years → ~$1.04 billion per year
  • Carbon revenue recycled into retrofit fund

Total cost:

  • ~1.96 cents per kWh
    • (Borrowing cost + O&M costs) ÷ total kWh = $/kWh
    • (1.04B + 1.518B) ÷ 130.27B kWh = $0.0196/kWh
  • ~$141 per year household impact
    • 7,200 × $0.0196 = $141

Cost Impact Under Alternative Financing Structures

Financing Model Estimated Cost per kWh Household Impact (7,200 kWh)
Full Pass-Through ~3.25¢ ~$234/year
Federal Low-Interest Financing ~2.30¢ ~$166/year
Blended Federal Support (30% capital offset) ~1.96¢ ~$141/year

9. Avoided Carbon Liability

At a federal carbon price of $170 per tonne: 21.7 Mt × $170 = $3.69 billion per year avoided carbon exposure

This avoided liability exceeds estimated operating costs and partially offsets capital investment when carbon pricing remains in place.

Key Observations

  1. Carbon capture is capital intensive but technically feasible at national scale.
  2. The annual emissions reduction potential (~22 Mt) represents roughly 3 percent of Canada’s total national emissions.
  3. Carbon capture does not eliminate fossil infrastructure; it stabilizes emissions while firm clean baseload capacity is built.
  4. Financing structure significantly determines ratepayer impact.

Appendix 11G – Carbon Capture Retrofit: Lifetime Impact and Cost

  • Installed natural gas capacity (2023): 23.66 GW

  • Annual emissions (natural gas electricity, 2023): 24.1 Mt CO₂e
    • Source: Environment and Climate Change Canada, Electricity sector greenhouse gas emissions, Canada, 1990–2023
    • https://www.canada.ca/en/environment-climate-change/services/environmental-indicators/greenhouse-gas-emissions.html

  • Assumed capture rate: 90% → 24.1 Mt × 0.90 = 21.7 Mt captured per year

  • 30-year cumulative emissions avoided: → 21.7 Mt × 30 = 651 Mt CO₂e

  • Capital cost: ~$29B → $29B ÷ 651 Mt = ~$45 per tonne (capital only)

  • Operating cost: ~$1.52B per year → $1.52B × 30 = $45.6B over 30 years

  • Total 30-year cost: → $29B + $45.6B = $74.6B total

  • All-in cost per tonne (30-year horizon): → $74.6B ÷ 651 Mt = ~$115 per tonne

  • Avoided carbon liability at $170/tonne: → 21.7 Mt × $170 = ~$3.69B per year

Appendix 11H – Estimating Canada’s Commercial Rooftop Solar Capacity

The following estimate focuses primarily on industrial warehouses, distribution centres, and large-format commercial buildings, which are typically single-storey structures. For these building types, reported industrial inventory closely approximates roof area.

1. Estimated Commercial & Industrial Floor Space

According to Cushman & Wakefield’s Canada Industrial MarketBeat (Q4 2025), total national industrial inventory is:

  • 2,072,307,521 square feet
  • ~2.07B square feet

Industrial inventory consists predominantly of warehouse, logistics, and distribution facilities, which are overwhelmingly single-storey buildings with large flat roofs. As such, total inventory square footage serves as a reasonable proxy for available rooftop area.

Source: Cushman & Wakefield - Q4 2025 Canada Industrial Marketbeat Report https://www.cushmanwakefield.com/en/canada/insights/canada-marketbeats/industrial-marketbeats

2. Solar Density Assumption

Utility-scale and commercial rooftop systems typically install:

  • ~1 kilowatt (kW) per 50 square feet
  • Equivalent to ~0.02 kW per square foot
  • Equivalent to ~20 megawatts (MW) per 1 million square feet

3. Theoretical Installed Capacity

2.07 billion sq ft × 0.02 kW per sq ft = 41,400,000 kW = 41.4 gigawatts (GW) of theoretical installed capacity

4. Structural and Usability Adjustments

Not all rooftops are usable due to:

  • Structural load limitations
  • Roof orientation
  • Mechanical equipment obstructions
  • Shading
  • Age of building

To remain conservative:

  • Assume 60 percent structural suitability
  • Assume 70 percent effective panel coverage

41.4 GW × 0.6 × 0.7 = 17.4 GW realistically installable capacity

5. Capacity Factor and Annual Output

Average Canadian commercial solar capacity factor: ~18 percent

17.4 GW × 8,760 hours/year × 0.18 = 27,417 GWh per year

Canada’s annual electricity consumption: ~625,700+ GWh (2021)

  • Source: https://www.cer-rec.gc.ca/en/data-analysis/energy-markets/provincial-territorial-energy-profiles/provincial-territorial-energy-profiles-canada.html

27,417 GWh ÷ 625,700 GWh = ~4.4 percent of national electricity demand

6. Interpretation

Even under conservative assumptions, commercial rooftop solar in major cities alone could supply roughly five to six percent of Canada’s total electricity demand.

This would:

  • Reduce peak daytime grid demand
  • Lower reliance on natural gas peaker plants
  • Reduce transmission expansion pressure
  • Utilize already-developed infrastructure
  • Require no additional land use

Tier 2 – Expanded Commercial & Institutional Potential

The above estimate includes only national industrial inventory. It excludes:

  • Institutional buildings (schools, hospitals, universities)
  • Large-format retail and shopping centres
  • Government buildings
  • Parking canopy solar installations

Including these additional categories would materially increase national rooftop solar potential. A conservative expansion suggests total rooftop capacity could reasonably approach five to six percent of national electricity demand when broader commercial and institutional structures are included.

Appendix 11I – Canada’s Solar Resource Potential

Solar energy potential is often underestimated in northern climates. In reality, several Canadian cities receive as much—or more—annual sunshine as locations much farther south.

Photovoltaic panels also operate more efficiently in cooler temperatures, meaning cold climates can partially offset shorter winter days through improved panel efficiency.

Appendix 11J – Estimating Canada’s Commercial Rooftop Solar Returns

This appendix outlines the assumptions used to estimate electricity generation, economic value, and emissions reductions associated with installing approximately 17 gigawatts of commercial rooftop solar capacity across Canada.

Installed Capacity

  • Total installed rooftop solar capacity: 17 GW
  • Capacity factor assumption: 18 percent

This capacity factor reflects typical solar performance across Canadian provinces when seasonal variation in sunlight is considered.

Annual Electricity Generation

Annual electricity generation is calculated using the standard production formula:

  • Capacity × Capacity Factor × Hours per Year
  • 17 GW × 0.18 × 8760 hours = 26.8 TWh

Rounded value used in the chapter: ~27 TWh per year

Equivalent Households Powered

Average Canadian household electricity consumption is roughly 10,500–11,000 kWh per year.

  • 27 TWh = 27,000,000,000 kWh
  • 27,000,000,000 ÷ 10,800 ≈ 2.5 million homes

Result used in the chapter: Equivalent to powering approximately 2.5 million Canadian households.

Estimated Electricity Value

Commercial electricity prices in Canada vary widely by province. Typical blended commercial rates fall between $0.10 and $0.12 per kWh.

  • 27 TWh × $0.10 = $2.7 billion
  • 27 TWh × $0.12 = $3.2 billion

Estimated annual electricity value: ~$2.7–3.2 billion per year

This represents avoided electricity purchases by building owners rather than wholesale electricity sales.

Estimating Avoided Emissions

Canada’s electricity system is already dominated by low-carbon sources such as hydropower, nuclear, and wind. Fossil fuels supply roughly 21 percent of total generation.

Average emissions intensity of fossil generation in North America is approximately 430–450 kg CO₂ per MWh, largely reflecting natural gas generation.

For comparison, U.S. natural gas power plants averaged 437 kg CO₂ per MWh in 2024.

To estimate the portion of rooftop solar generation likely to displace fossil generation, the fossil share of the grid is applied.

  • 27 TWh × 21 percent = 5.67 TWh of fossil generation displaced

Emissions avoided:

  • 5.67 TWh = 5,670,000 MWh
  • 5,670,000 × 0.45 tonnes CO₂/MWh ≈ 2.6 million tonnes CO₂

Result

Estimated annual emissions avoided: ~2.5–3 Mt CO₂e per year

Installing 17 GW of commercial rooftop solar across Canada would generate roughly 27 TWh of electricity annually, equivalent to the power consumption of about 2.5 million homes.

Appendix 11K – Estimating The Returns for Pillar I

This appendix outlines the assumptions and calculations used to estimate the electricity generation and emissions reductions associated with Pillar I.

1. Increase to Canada’s electricity supply

Recent Canadian electricity generation is approximately 630–650 terawatt-hours (TWh) per year.

Pillar I adds two major sources of new generation:

Firm clean baseload generation

  • 18 gigawatts (GW) of nuclear and geothermal capacity
  • Assumed capacity factor: ~90 percent
  • Estimated annual generation: ~142 TWh

This estimate is derived by multiplying installed capacity by annual operating hours:

18 GW × 8,760 hours per year × 90 percent capacity factor ≈ 142 TWh per year

Commercial rooftop solar

  • 17 GW of distributed solar capacity
  • Assumed capacity factor: ~18 percent
  • Estimated annual generation: ~27 TWh

Total new clean generation

Combining these sources produces approximately:

  • 142 TWh + 27 TWh = ~169 TWh per year

Relative to Canada’s current electricity generation of roughly 640 TWh annually, this represents an increase of approximately:

  • 169 TWh ÷ 640 TWh ≈ 26 percent

In other words, Pillar I increases Canada’s clean electricity supply by roughly 25–27 percent.

2. Emissions reductions from new clean generation

Only the portion of electricity that displaces fossil generation reduces emissions.

Approximately 21 percent of Canada’s electricity currently comes from fossil fuels, primarily natural gas.

Assuming that the new clean generation displaces fossil generation in proportion to its share of the grid:

  • 169 TWh × 21 percent ≈ 35.5 TWh of fossil generation displaced

Natural gas power plants emit roughly 437 kilograms of CO₂ per megawatt-hour (MWh) on average.

Source:

Converting displaced generation to emissions reductions:

  • 35.5 million MWh × 0.437 tonnes CO₂ per MWh ≈ 15.5 million tonnes of CO₂ per year

This means the clean generation portion of Pillar I reduces emissions by approximately:

  • ~15–16 million tonnes of CO₂ annually

3. Emissions reductions from carbon capture retrofits

Carbon capture systems installed on natural gas plants are assumed to capture approximately 90 percent of plant emissions.

Natural gas plants typically emit 0.4–0.45 tonnes of CO₂ per MWh of electricity produced.

If the retrofitted plants collectively generate approximately 75 TWh of electricity per year, total emissions without capture would be:

  • 75 million MWh × 0.437 tonnes CO₂ per MWh ≈ 32.8 million tonnes of CO₂

Capturing 90 percent of those emissions results in avoided emissions of approximately:

  • 32.8 Mt × 90 percent ≈ 29–30 million tonnes of CO₂ annually

4. Total emissions reductions from Pillar I

Combining both sources of reductions produces the following estimate:

Source Annual reduction
Clean generation displacing fossil electricity ~15–16 Mt CO₂
Carbon capture retrofits ~29–30 Mt CO₂

Total estimated emissions reduction: ~44–46 million tonnes of CO₂ per year

For context, Canada’s total annual greenhouse gas emissions are roughly 670 million tonnes. Pillar I therefore reduces national emissions by approximately 6–7 percent.

5. Contribution to future electricity demand

Canada currently generates a little over 600 TWh of electricity per year.

Federal projections indicate electricity demand could rise to roughly 750 TWh by 2035, while long-term net-zero scenarios suggest demand may exceed 1,200 TWh by 2050 in a high-electrification future.

Sources:

With ~169 TWh of new clean generation, Pillar I would provide:

  • roughly 26 percent of Canada’s current electricity supply, and
  • roughly 29 percent of the additional electricity Canada may require by 2050 under a high-electrification scenario.

In practical terms, this means Pillar I alone could meet roughly one-quarter to one-third of Canada’s projected electricity demand growth over the coming decades.

Appendix for Chapter 12

Appendix 12A – Converting Canada’s Natural Gas Consumption to Hydrogen Equivalent

Conclusion

To replace Canada’s current natural gas consumption with hydrogen on an energy-equivalent basis would require approximately: ~37 billion kilograms of hydrogen annually.

Appendix 12B – Calculating Electricity Required for Electrolytic Hydrogen Production

  • Hydrogen Requirement: 37 billion kg per year
    • Source: Appendix 12A – Converting Canada’s Natural Gas Consumption to Hydrogen Equivalent
  • Electricity required per Kilogram of Hydrogen Produced
    • Electrolysis energy requirement: ~52.5 kWh per kg of hydrogen
    • Sources typically range from 50 to 55 kWh per kg of hydrogen using conventional electrolysis.
  • Total Annual Electricity Requirement
    • 37 billion kg × 52.5 kWh = 1,942,500,000,000 kWh = 1,943 TWh per year
  • Continuous Power Requirement
    • 365 days × 24 hours per day = 8,760 hours
    • 1,942,500,000,000 kWh ÷ 8,760 hours = 221,746,575 kW
    • ≈ 222 GW

Conclusion

Producing hydrogen via electrolysis at the scale required to replace Canada’s natural gas consumption would require:

~220 GW of continuous electricity demand

This exceeds Canada’s current total installed electricity generation capacity.

Appendix 12C – Calculating the Number of Facilities and Investment Required to Achieve 132 Mt CO₂e Reduction

Key Assumptions

  • Emissions reduction target: 132 megatonnes CO₂e per year at full buildout
  • Facility model: Air Products Edmonton Hydrogen Hub — 1,500 tonnes of hydrogen per day, with carbon capture
  • Annual hydrogen output per facility: 1,500 tonnes/day × 365 days = 547,500 tonnes/year (~500,000 tonnes rounded)
  • Carbon capture rate assumed: 85% (conservative, based on real-world CCS performance ranges of 85–95%)
  • Emissions intensity of unabated natural gas combustion: ~11.99 kg CO₂e per kg H₂ (steam methane reforming without capture)
  • Emissions intensity of blue hydrogen at 85% capture: ~2.5 kg CO₂e per kg H₂
  • Net CO₂e reduction per kg of hydrogen substituted: 11.99 − 2.5 = ~9.5 kg CO₂e per kg H₂
  • Conservative net reduction used in calculation: 7.5 kg CO₂e per kg H₂ (accounts for upstream methane leakage and real-world variability)
  • Per-facility cost: ~$1.6 billion CAD, based on the Air Products Net-Zero Hydrogen Energy Complex in Edmonton

Calculation

Step 1 — Emissions reduction per facility per year

  • Annual hydrogen output: 500,000 tonnes = 500,000,000 kg
  • CO₂e reduction per kg: 7.5 kg
  • Emissions reduction per facility: 500,000,000 × 7.5 = 3,750,000,000 kg CO₂e = 3.75 Mt CO₂e per year

Step 2 — Number of facilities required

  • Target: 132 Mt CO₂e per year
  • Facilities required: 132 ÷ 3.75 = ~35 facilities

Step 3 — Total capital investment

  • 35 facilities × $1.6 billion = $56 billion, rounded to ~$60 billion (conservative)
  • Spread over 25 years: ~$2.4 billion per year

Step 4 — Annual hydrogen production at full buildout

  • 35 facilities × 500,000 tonnes/year = 17.5 million tonnes of hydrogen annually

Step 5 — Annual revenue at full buildout

  • At projected IEA hydrogen prices of $2–4 per kilogram:
    • Low end: 17.5 million tonnes × $2/kg = $35 billion/year
    • High end: 17.5 million tonnes × $4/kg = $70 billion/year

Conclusion

Approximately 35 facilities at the scale of the Edmonton Hydrogen Hub, representing a total capital investment of ~$60 billion over 25 years, would be sufficient to reduce Canada’s industrial emissions by 132 megatonnes of CO₂e annually — approximately 19 percent of Canada’s total national emissions. At full buildout, the system would produce approximately 17.5 million tonnes of hydrogen per year, generating estimated annual revenues of $35–70 billion.

Sources:

Appendix 12D – Assessing Canada's Natural Gas Supply Adequacy for Blue Hydrogen Production

Key Assumptions

  • Facilities at full buildout: 35 (see Appendix 12C)
  • Hydrogen output per facility: ~500,000 tonnes/year
  • Natural gas feedstock ratio: ~4.5 kg of natural gas per kg of hydrogen produced via steam methane reforming (SMR)
  • Canada's current natural gas production: 18.3 billion cubic feet per day (Bcf/d) in 2024 = ~6.7 trillion cubic feet per year (Tcf/year)
  • Canada's current natural gas exports: 8.8 Bcf/d in 2024 = ~3.2 Tcf/year
  • Canada's proven natural gas reserves: 1,368 Tcf as of 2024
  • Conversion factor: 1 tonne of hydrogen ≈ 190,000 cubic feet of natural gas (based on SMR feedstock ratio)

Calculation

Step 1 — Total natural gas feedstock required at full buildout

  • Annual hydrogen production: 17.5 million tonnes
  • Natural gas per tonne of hydrogen: 190,000 cubic feet
  • Total feedstock required: 17.5 million × 190,000 = 3,325,000,000,000 cubic feet
  • = ~3.3 Tcf/year (rounded to ~4 Tcf/year including compression, processing, and facility energy use)

Step 2 — Compare against current production

Metric Volume (Tcf/year)
Current Canadian production (2024) ~6.7
Current domestic consumption ~3.5
Current exports ~3.2
Hydrogen feedstock requirement (full buildout) ~4.0
Gap above current available surplus ~1–2

Step 3 — Reserve adequacy

  • Proven reserves: 1,368 Tcf
  • Annual feedstock consumption at full buildout: ~4 Tcf
  • Reserve consumption rate: 4 ÷ 1,368 = ~0.3% of reserves per year
  • Reserves at this consumption rate: sufficient for ~340 years

Step 4 — Production scaling required

  • Current production of 6.7 Tcf/year exceeds domestic consumption (~3.5 Tcf) by ~3.2 Tcf
  • Hydrogen feedstock demand of ~4 Tcf/year would require either export reallocation or production growth of approximately 1–2 Tcf/year above current levels by full buildout in 2050
  • Canadian production is already growing: 18.3 Bcf/d in 2024, up from 17.9 Bcf/d in 2023, with 2025 averaging 19.2 Bcf/d through May
  • The required growth of ~1–2 Tcf/year spread over 25 years represents a modest and achievable increase on the current trajectory

Step 5 — Green hydrogen transition reduces long-term dependence

As Pillar I’s clean electricity buildout expands generating capacity, blue hydrogen facilities can be progressively converted to green hydrogen production via electrolysis. This reduces natural gas feedstock demand over time, meaning the peak natural gas requirement is a transitional constraint, not a permanent one.

Conclusion

Canada’s natural gas reserves are more than adequate to support 35 blue hydrogen production facilities — the feedstock requirement of ~4 Tcf/year represents less than 0.3% of proven reserves annually. However, at current production and export levels, full buildout will require modest production growth of approximately 1–2 Tcf/year above current levels — achievable within the growth trajectory already underway and spread across a 25-year buildout period. This feedstock dependence decreases progressively as the system transitions toward green hydrogen production.

Sources:

Appendix 12E – Hydrogen Production: Revenue, Margin, Export Potential, and Payback Analysis

Key Assumptions

Calculation

Step 1 — Annual revenue at full buildout

  • Production: 17.5 million tonnes = 17,500,000,000 kg
  • At $2/kg: 17,500,000,000 × $2 = $35 billion/year
  • At $4/kg: 17,500,000,000 × $4 = $70 billion/year
  • Revenue range: $35–70 billion per year

Step 2 — Gross margin per kilogram

  • Production cost (SMR + CCS): $1.50–2.50/kg
  • Market price: $2.00–4.00/kg
  • Gross margin: $2.00 − $2.50 = −$0.50/kg (break-even or slight loss at low price, high cost)
  • to $4.00 − $1.50 = $2.50/kg (strong margin at high price, low cost)
  • Conservative midpoint margin: ~$1.00/kg
Scenario Price Production Cost Gross Margin/kg Annual Gross Margin
Low (conservative) $2.00/kg $2.50/kg −$0.50/kg Break-even
Mid $3.00/kg $2.00/kg $1.00/kg ~$17.5B/year
High (optimistic) $4.00/kg $1.50/kg $2.50/kg ~$43.75B/year

Note: The low scenario (break-even) reflects the early transition period before production costs fall with scale. IEA projects blue hydrogen production costs declining toward $1.50/kg by the mid-2030s as SMR+CCS technology matures, which shifts all scenarios toward the mid and high cases over the life of the programme.

Step 3 — Payback period

  • Total capital investment: $60 billion
  • At $35B annual revenue (low): $60B ÷ $35B = ~1.7 years to revenue recovery
  • At $70B annual revenue (high): $60B ÷ $70B = ~0.9 years to revenue recovery

Note: Revenue recovery is not the same as full return on investment. After subtracting annual operating costs (~$4–6B/year across 35 facilities) and debt service on capital, net payback periods are longer:

Scenario Annual Revenue Annual Operating Cost Net Annual Cash Flow Net Payback on $60B
Low $35B $6B $29B ~2 years
Mid $52.5B $5B $47.5B ~1.3 years
High $70B $4B $66B ~0.9 years

These payback periods are unusually short for infrastructure of this scale, reflecting the high value of hydrogen as a commodity relative to capital cost. For comparison, the Trans Mountain Pipeline expansion cost $34 billion and generates approximately $1–2 billion in annual toll revenue—a payback period measured in decades, not years.

Step 4 — Export revenue

  • Total production: 17.5 million tonnes/year
  • Export share (one-third): 17.5 ÷ 3 = ~5.8 million tonnes/year
  • At $2/kg: 5,800,000,000 kg × $2 = $11.6 billion/year
  • At $4/kg: 5,800,000,000 kg × $4 = $23.2 billion/year
  • Export revenue range: $11.6–23.2 billion per year

For context: Canada’s total goods exports in 2023 were approximately $700 billion. Hydrogen exports at the mid-case ($17B/year) would represent roughly 2.4 percent of total export value—comparable in scale to Canada’s current softwood lumber export sector.

Conclusion

At full buildout, Canada’s 35-facility blue hydrogen system generates $35–70 billion in annual revenue, with a net payback period of under two years at the low revenue scenario and under one year at the high scenario—making this among the fastest-returning infrastructure investments in Canadian history on a capital-to-revenue basis. Gross margins of $1.00–2.50/kg at mid-to-high price scenarios generate $17.5–43.75 billion in annual operating profit before debt service. Export revenue of $11.6–23.2 billion per year would establish hydrogen as one of Canada’s top five export commodities by value within the programme’s operational lifetime.

Sources:

Appendix 12F – Pipeline Conversion Cost and Revenue Model

Key Assumptions

  • Natural gas transmission pipelines: ~48,000 km (CER-regulated natural gas transmission network; excludes oil pipelines)
  • Natural gas distribution pipelines: ~450,000 km (local distribution mains operated by gas utilities)
  • Phase 1–2 scope (Objective 2.2 priority): The 48,000 km transmission backbone — the high-utilisation long-haul network connecting production regions to major industrial and urban centres
  • Upgrade cost basis: U.S. DOE — transmission pipeline upgrade ~$1.05M/km; distribution pipeline upgrade ~$266,000/km
  • Compressor stations: one per 80 km on average; hydrogen requires higher-capacity compressors at ~$2.8M each
  • Revenue basis: FortisBC regulated natural gas delivery rate of $5.93/GJ, applied to national natural gas consumption of ~4.1 billion GJ/year
  • O&M basis: FortisBC operating cost of ~$5,500/km/year, scaled to network length

Hydrogen Compatibility by Pipeline Type

Not all pipeline segments require the same level of modification. Compatibility varies by material, operating pressure, and age:

Pipeline Type Hydrogen Compatibility Modification Required
Modern low-strength steel (X42–X52) High — up to 100% H₂ Minimal; seal and fitting upgrades
Higher-strength steel (X65–X80) Moderate — up to ~30% blend Embrittlement monitoring; possible segment replacement
Plastic distribution lines High — compatible with H₂ blends Minimal; fitting inspection
Older cast iron/uncoated steel Low Retirement or full replacement recommended

Most of Canada’s transmission backbone consists of X52–X65 grade steel, making it compatible with hydrogen blending at the 5–20% range without significant modification, and with engineering upgrades for higher concentrations.

Calculation

Step 1 — Phase 1–2 priority: transmission backbone upgrade cost

  • Scope: ~48,000 km of natural gas transmission pipelines
  • Upgrade cost at $1.05M/km: 48,000 × $1.05M = ~$50 billion
  • Infrastructure projects of this scale routinely experience 1.5–2× cost overruns; upper bound: ~$100 billion
  • Priority conversion cost range: $50–100 billion over 20 years

Step 2 — Full network upgrade cost (Phase 3 long-term)

  • Transmission: 48,000 km × $1.05M/km = ~$50 billion
  • Distribution: 450,000 km × $266,000/km = ~$120 billion
  • Compressor replacements: (498,000 km ÷ 80 km) × $2.8M = 6,225 units × $2.8M = ~$17 billion
  • Base full-network cost: ~$187 billion
  • With 2× cost overrun: ~$375 billion
  • Full network range: $187–375 billion

Step 3 — Annual revenue at scale

  • National natural gas consumption: ~4.1 billion GJ/year
  • Variable delivery rate basis: FortisBC Rate Schedule 1 (Mainland and Vancouver Island, 2023): $5.93/GJ — applied as a national average delivery rate proxy; actual national rate will vary by province and utility
  • Gross delivery revenue: 4.1B GJ × $5.93/GJ = ~$24.3 billion/year
  • O&M costs: 498,000 km × $5,500/km = ~$2.7 billion/year (FortisBC operating cost basis)
  • Net annual revenue: ~$21.6 billion/year (rounds to ~$21 billion)

Step 4 — Payback period

  • On full network conversion ($187B base / $375B with overruns) at $21.6B/year net: 8.7–17.4 years
  • Planning range: 12–25 years accounting for hydrogen adoption ramp-up (early-phase delivery volumes are lower; full $21B/year is not realised from day one)

Step 5 — Blending phase emissions reduction

Baseline: Canadian natural gas combustion emits ~232 Mt CO₂/year (122 billion m³ × ~1.9 kg CO₂/m³).

Hydrogen’s energy content per unit volume is approximately 30% that of natural gas (H₂ LHV: ~10.79 MJ/m³; CH₄ LHV: ~35.9 MJ/m³), so percentage reductions by volume overstate energy-equivalent displacement. Emissions reduction is calculated from the H₂ energy fraction of the blended mixture.

Blend level H₂ by volume H₂ energy fraction CO₂ reduction % of Canada total
Phase 1 target 10% 3.2% ~7 Mt CO₂/year ~1%
Phase 2 target 20% 7.0% ~16 Mt CO₂/year ~2%
Singapore low 41% 17.3% ~40 Mt CO₂/year ~6%
Singapore high 65% 35.8% ~83 Mt CO₂/year ~12%

Singapore’s City Energy (formerly City Gas) has operated its distribution network at 41–65% hydrogen by volume for decades — the longest-running large-scale hydrogen blending programme in the world. Reaching the Singapore blend range across Canada’s natural gas network would eliminate 40–83 Mt CO₂/year from combustion emissions alone, making pipeline conversion one of the highest-impact single measures in this plan.

Step 6 — Industrial carbon pricing and the case for hydrogen

Two overlapping regulatory frameworks create the economic conditions for industrial hydrogen adoption in Canada. Neither is speculative — both are in force.

Canada’s Output-Based Pricing System (OBPS) applies to large industrial emitters (facilities producing ≥50,000 tCO₂e/year). Unlike the consumer fuel charge (eliminated April 1, 2025), the OBPS remains fully in effect. It charges facilities on emissions above a benchmark intensity standard — not on all emissions — at $95/tonne CO₂e in 2025, rising to $115/tonne by 2030 under the updated federal trajectory published May 2026, and $140/tonne by 2040. Because the OBPS targets only above-benchmark emissions, the effective carbon cost on a facility’s total emissions is lower than the headline rate — typically $10–20/tonne of total emissions depending on how far above benchmark the facility operates. The marginal incentive to reduce emissions below the benchmark, however, is the full headline rate: a facility that can eliminate one tonne of emissions through fuel switching avoids the full $115/tonne charge on that tonne. Switching to hydrogen eliminates the carbon charge on every tonne of combustion emissions reduced.

The EU Carbon Border Adjustment Mechanism (CBAM) became fully operational January 1, 2026, and applies to imports of steel, aluminum, cement, fertilizers, electricity, and hydrogen entering the European Union. Importers pay a carbon certificate for each tonne of CO₂ embedded in the goods they bring in, priced at the EU Emissions Trading System rate — €75.36/tonne CO₂e as of the first quarterly price (April 2026), with projections of €120–200/tonne by the mid-2030s. For Canadian manufacturers exporting to Europe, the cost difference between conventional and hydrogen-based production is immediate and material:

Product Conventional production (CO₂/tonne) CBAM cost at €75/tonne Hydrogen-based (CO₂/tonne) CBAM cost at €75/tonne
Steel (blast furnace, default values) 3.5 t CO₂ ~€264 (~CAD 388) 0.4 t CO₂ ~€30 (~CAD 44)
Ammonia / fertilizer 1.8 t CO₂ ~€136 (~CAD 199) 0.1 t CO₂ ~€8 (~CAD 11)

CBAM certificate price from Q1 2026; CAD/EUR conversion at 1.47; steel emissions based on CBAM default values — actual verified figures will vary by facility.

For a Canadian steel mill exporting to Europe, the CBAM cost differential between conventional and hydrogen-based production runs to approximately CAD $344/tonne of steel at current carbon prices — against a total steel price of $800–1,100/tonne. As EU ETS prices rise toward €120–200/tonne over the coming decade, that gap widens further. This creates a direct export-competitiveness incentive for Canada’s steel, fertilizer, and cement industries to adopt hydrogen that operates entirely independently of domestic carbon policy.

The combined effect of the OBPS (domestic carbon cost on above-benchmark emissions) and the CBAM (export carbon cost on all embedded emissions in EU-bound goods) means that, for Canada’s largest industrial emitters, the question of whether to convert to hydrogen is increasingly a question of when, not whether.

Step 7 — Investment structure and government revenue

Under the regulated private operator model, the federal government lends directly to private pipeline operators—TC Energy, Enbridge, FortisBC, and others already operating the network—through a crown lending facility at a subsidized rate of 3%. Operators fund, own, and manage the conversion; the government recovers its capital with interest over the payback period. This keeps the $50–100B off the public expenditure balance sheet while giving the government two distinct revenue streams: loan interest during repayment, and corporate tax on operator profits throughout the asset’s life.

Government interest income (3% direct lending, repaid over payback period):

Scenario Principal Repayment term Total interest to government
Fast payback, low capital $50B 12 years ~$10B
Slow payback, low capital $50B 25 years ~$22B
Fast payback, high capital $100B 12 years ~$21B
Slow payback, high capital $100B 25 years ~$44B
Planning range     ~$10–44B

Annual average government interest income during repayment: ~$0.9–1.7B/year.

Government corporate tax revenue on operator profits:

Component Low ($50B capital) High ($100B capital)
Annual net delivery revenue $21.0B $21.0B
Less: depreciation (30-year asset life) –$1.7B –$3.3B
Less: interest repayment to government at 3% –$0.9B –$1.7B
Estimated taxable income ~$18.4B ~$16.0B
Corporate tax at 26.5% (federal + provincial avg.) ~$4.9B/year ~$4.2B/year
Cumulative government tax revenue over 25 years ~$122B ~$105B

Combined corporate tax rate: federal 15% + average provincial 11.5%. Figures are estimates; actual taxable income varies with operator financing structure and provincial rates.

Total 25-year government revenue (interest + taxes): ~$119–162 billion

The government lends $50–100B at a subsidized rate, recovers it with interest, then continues collecting corporate taxes on $21B/year in operator profits for the remaining decades of the asset’s life. Operators recover their capital within 12–25 years and earn approximately $525–800 billion in cumulative profit over the 50-year post-conversion lifespan.

Conclusion

Upgrading Canada’s 48,000 km natural gas transmission backbone costs an estimated $50–100 billion over 25 years, financed through government direct lending to regulated private pipeline operators at 3%. At scale, the network generates approximately $21 billion per year in net delivery revenue. The government recovers its loan with $10–44 billion in interest and collects a further $105–122 billion in corporate taxes over 25 years—total public revenue of approximately $119–162 billion from capital that stays off the expenditure balance sheet. For the industrial users who will drive Phase 2 conversion, Canada’s Output-Based Pricing System and the EU’s Carbon Border Adjustment Mechanism together make hydrogen adoption an economic necessity: conventional steel exported to Europe already carries a CBAM cost of approximately CAD $388/tonne at current carbon prices, against ~$44/tonne for hydrogen-based steel.

Sources:

Appendix 12G – Trans-Canada Clean Energy Corridor: Site Count, Capital Cost, and Generation Capacity

Key Assumptions

  • Corridor length: ~7,800 km (Trans-Canada Highway, St. John's to Victoria)
  • Site spacing: approximately every 50 km, providing continuous coverage for both battery electric vehicles (typical long-range EV range: 400–500 km) and hydrogen fuel cell vehicles (typical range: 500–650 km)
  • Site count: 7,800 km ÷ 50 km = 156 sites, rounded to ~150 sites
  • Site configuration: each site includes EV fast-charging capacity (minimum 4 × 350 kW DC fast chargers) and a hydrogen refuelling unit with on-site electrolysis or compressed delivery
  • Average capital cost per site: $5–8 million, based on comparable deployments in the U.S. DOE Alternative Fuels Station database and European hydrogen refuelling network cost data
  • Solar/wind generation: phased installation of 2–4 GW along the corridor; cost basis of $1.5M/MW (wind, installed) consistent with Canadian Wind Energy Association benchmarks

Calculation

Step 1 — Site count and spacing

  • Highway length: 7,800 km
  • Target spacing: 1 site per 50 km
  • Sites required: 7,800 ÷ 50 = 156 sites (rounded to ~150 in chapter text)
  • Coverage gap for EVs: zero — 50 km spacing is well within range of any current long-range battery electric vehicle even in cold-weather conditions where range is reduced by 20–30%
  • Coverage gap for hydrogen fuel cell vehicles: zero — 50 km between hydrogen refuelling points is within the operational range of all current commercial hydrogen trucks

Step 2 — Capital cost of corridor stations

  • 150 sites × $5M (low) = $750 million
  • 150 sites × $8M (high) = $1.2 billion
  • Total station capital: ~$750M to $1.2B

Step 3 — On-site power generation

  • Target generating capacity: 2–4 GW (combined solar and wind along corridor, developed in phases)
  • Cost at $1.5M/MW:
    • Low end (2 GW): 2,000 MW × $1.5M = $3 billion
    • High end (4 GW): 4,000 MW × $1.5M = $6 billion
  • Total generation capital: ~$3–6 billion

Step 4 — Total corridor capital

Component Capital Cost
Station construction (150 sites) $750M–$1.2B
On-site solar and wind generation $3–6B
Total ~$3.75–7.2B

Step 5 — Fuel import substitution

  • Canada’s annual petroleum product imports: ~$15–20 billion
  • Long-haul trucking share of transportation emissions: approximately 10% of Canada’s total (~22% of emissions × ~45% freight share)
  • Each percentage point of long-haul fleet converted to clean fuel: ~$150–200M in annual import substitution

Step 6 — Revenue from fuel sales

  • 150 stations operating at moderate utilisation (50 hydrogen vehicles/day per station):
    • 150 × 50 vehicles × 35 kg/fill = 262,500 kg/day
    • Annual throughput: ~96 million kg/year
    • At $8–12/kg retail hydrogen: $768M–$1.15B per year in fuel revenue across the network at moderate utilisation
  • EV charging revenue (150 stations × 100 charges/day × $25/charge): ~$136M per year

Conclusion

A 150-station Trans-Canada clean energy corridor requires approximately $750M to $1.2B in station capital and $3–6B in phased on-site generation capacity, for a total corridor investment of roughly $3.75–7.2 billion. At moderate utilisation, hydrogen fuel sales alone generate approximately $770M–$1.15B per year across the network. The corridor provides continuous coast-to-coast coverage with zero range-anxiety gaps for both battery electric and hydrogen fuel cell vehicles, and represents less than five percent of the cost of the Trans Mountain Pipeline expansion.

Sources:

Appendix for Chapter 13

Appendix for Chapter 14

Appendix for Chapter 15

Step 8 - Build a Green Energy Highway Across the Whole Country

Appendix ??-3A – Calculating the Cost of Green Hydrogen

  • Electrolysis energy input: 50 kWh per kg of hydrogen
  • Solar capacity factor: 1 MW × 14% capacity = 140 kW average output
  • Daily output: 140 kW × 24 hrs = 3,360 kWh/day → 67.2 kg H₂/day
  • Capital cost: $5 million CAD (electrolyzer, solar, compression, storage, dispensing)
  • Levelized cost: $5M ÷ 25 years ÷ 365 days ÷ 67.2 kg = $8.15/kg
  • Vehicle usage: Toyota Mirai = 5.6 kg tank → $45.64
  • Markup (23%): +$10.50 = $56.14 (5% loan interest, 5% operating & maintenance, 13% profit margin)
  • Taxes (12%): +$6.73 = $62.87 final price per tank

Appendix ??-3B – Calculating the Total Cost of Electrolysis Stations

  • Capital cost per station: $5 million CAD (electrolyzer, solar, compression, storage, dispensing)
  • Number of stations: 780 installed along TransCanada Highway
  • Total capital cost: 780 × $5 million CAD = 3.9 billion CAD

Figure XX - O&M Cost Comparison for Geothermal and SMR Nuclear Plants (2021):

This table compares the operating and maintenance (O&M) costs for a 1,000 MW geothermal plant and a 1,000 MW small modular reactor (SMR) nuclear plant. The calculations include variable and fixed costs and highlight the impact of operating at 90% capacity, which is typical for both plant types.

Plant Type Variable O&M Costs ($) Fixed O&M Costs ($) Total O&M Costs (100% Capacity) Total O&M Costs (90% Capacity) O&M Cost per MWh
Geothermal (1,000 MW) $10,161,600 $143,220,000 $153,381,600 $152,365,440 $17.39
SMR Nuclear (1,000 MW) $26,280,000 $95,000,000 $121,280,000 $118,652,000 $13.54

* Source: U.S. Energy Information Administration (AEO2020)

Calculation Details:

  • Geothermal Variable O&M Costs: $1.16/MWh x 8,760,000 MWh/year (100% capacity) = $10,161,600/year
  • SMR Variable O&M Costs: $3.00/MWh x 8,760,000 MWh/year (100% capacity) = $26,280,000/year
  • Fixed O&M Costs: Per kW-year costs multiplied by plant capacity
    • Geothermal: $128.54/kW-year x 1,000,000 kW = $143,220,000
    • SMR: $95.00/kW-year x 1,000,000 kW = $95,000,000
  • Adjusted for 90% Capacity: Multiply totals by 0.90 to reflect realistic operation rates.
  • Annual Energy Output: 1,000 MW x 8,760 hours/year = 8,760,000 MWh/year

Key Takeaways:

  • At 90% capacity, geothermal O&M costs are approximately $152.37 million/year, while SMR nuclear is $118.65 million/year.
  • SMR nuclear has a lower O&M cost per megawatt-hour ($13.54) than geothermal ($17.39), but geothermal plants do not require fuel and produce no waste.

Appendix for Chapter 16

Ben Scott
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Ben Scott

I’m a father and a tech industry professional who is deeply concerned with the state of our world.

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Sources & References

An ongoing collection of sources and references used for the book "No Illusions".

Ben Scott
Ben Scott