Appendices and Notes

Appendix - Table of Contents

• Appendix - Table of Contents
• Appendix for Chapter 1
• Appendix for Chapter 3
• Appendix for Chapter 4
• Appendix for Chapter 5
• Appendix for Chapter 6
• Appendix for Chapter 7
• Appendix for Chapter 8
• Appendix for Chapter 9
• Appendix for Chapter 10
• Appendix for Chapter 11
• Appendix for Chapter 12
• Appendix for Chapter 13
• Appendix for Chapter 14
• Appendix for Chapter 15

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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.

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Appendix for Chapter 3

Appendix 3A - Energy Calculations for Solar in Alberta:

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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

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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

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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)

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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

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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

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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.

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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

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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

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Appendix for Chapter 6

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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)

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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

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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

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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

• NETL – Westinghouse Plasma Gasification: Plasma torches consume ~2–5% of total energy input; ~80% of feed energy can be recovered in syngas.
• NETL – Syngas Composition: Typical syngas = 30–60% CO, 25–30% H₂.
• Membrane Technology & Research Inc.: Membrane systems recover 90–98% of feed hydrogen, with product purity of 85–95%.

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.

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Appendix for Chapter 9

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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).

• British Columbia: Budgeted carbon tax revenue for 2021–2022: $1.985 billion Source: B.C. Budget 2021, Table A5, p.153 https://www.bcbudget.gov.bc.ca/2021/pdf/2021_Budget%20and%20Fiscal%20Plan.pdf

• Federal Government: Estimated carbon tax revenue for 2022–2023 at $50/tonne: $8.27 billion Source: Reuters (Jan 2020) https://www.reuters.com/article/us-canada-economy-climatechange-idUSKBN1ZY215

• Maritime Provinces (industrial portion): Emissions: 38.1 Mt × $50/tonne = $1.9 billion Estimated provincially managed industrial share: ~$750 million Source: Canada Energy Regulator https://www.cer-rec.gc.ca/en/data-analysis/energy-markets/provincial-territorial-energy-profiles/provincial-territorial-energy-profiles-explore.html

• Quebec (excluded): Quebec operates a cap-and-trade system rather than a direct carbon tax. In 2022, auction proceeds generated approximately $1.4 billion, but these are not included in the total due to differences in design and revenue flow. Source: ICAP Carbon Action https://icapcarbonaction.com/en/ets/canada-quebec-cap-and-trade-system

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	–	–	–

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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

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Appendix 11B – Calculating Levelized Costs for Power Plant Technologies

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.

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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)

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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.

• Representative sources:
  • U.S. Energy Information Administration – Annual Energy Outlook 2025
  • Clean Energy BC – Geothermal Energy
  • International Renewable Energy Agency (IRENA) – Geothermal Power: Technology Brief

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.

• Representative sources:
  • Natural Resources Canada – Canada’s SMR Action Plan
  • U.S. Department of Energy – Advanced Nuclear Cost Estimates
  • OECD Nuclear Energy Agency – The Economics of SMRs

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
  • Representative source: Projected Costs of Generating Electricity, pg. 39 IEA (2020)
• 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

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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)
  • Source: Alberta Utilities Consumer Advocate
• Saskatchewan (Saskatoon Light & Power energy charge): 16.38 ¢/kWh (as of January 1, 2025)
  • Source: Saskatoon.ca, Electricity Rates
• Nova Scotia Power (Domestic Service energy charge): 18.187 ¢/kWh (as of January 1, 2026)
  • Source: Nova Scotia Power
• New Brunswick Power (Residential Service – urban): 15.17 ¢/kWh (as of April 1, 2025)
  • Source: NB Power

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):

• Natural gas: 976 lb CO₂ per MWh
  • Source: U.S. Energy Information Administration
• Coal: 2,257 lb CO₂ per MWh
  • Source: U.S. Energy Information Administration

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

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Appendix for Chapter 12

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Appendix for Chapter 13

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Appendix for Chapter 14

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Appendix for Chapter 15

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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

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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

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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.

Chapter 11