Regulations Amending the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations: SOR/2018-263

Canada Gazette, Part II, Volume 152, Number 25

Registration

SOR/2018-263 November 30, 2018

CANADIAN ENVIRONMENTAL PROTECTION ACT, 1999

P.C. 2018-1484 November 29, 2018

Whereas, pursuant to subsection 332(1) ^{footnote a} of the Canadian Environmental Protection Act, 1999 ^{footnote b}, the Minister of the Environment published in the Canada Gazette, Part I, on February 17, 2018, a copy of the proposed Regulations Amending the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, substantially in the annexed form, and persons were given an opportunity to file comments with respect to the proposed Regulations or to file a notice of objection requesting that a board of review be established and stating the reasons for the objection;

Whereas, pursuant to subsection 93(3) of that Act, the National Advisory Committee has been given an opportunity to provide its advice under section 6 ^{footnote c} of that Act;

And whereas, in accordance with subsection 93(4) of that Act, the Governor in Council is of the opinion that the proposed Regulations do not regulate an aspect of a substance that is regulated by or under any other Act of Parliament in a manner that provides, in the opinion of the Governor in Council, sufficient protection to the environment and human health;

Therefore, Her Excellency the Governor General in Council, on the recommendation of the Minister of the Environment and the Minister of Health, pursuant to subsections 93(1) and 330(3.2) ^{footnote d} of the Canadian Environmental Protection Act, 1999 ^{footnote b}, makes the annexed Regulations Amending the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations.

Regulations Amending the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations

Amendments

1 (1) The definition calendar year in subsection 2(1) of the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations ^{footnote 1} is repealed.

(2) Paragraphs (a) and (b) of the definition useful life in subsection 2(1) of the Regulations are replaced by the following:

• (a) for a unit other than a unit referred to in paragraph (a) of the definition commissioning date,
  • (i) in the case of a unit whose commissioning date is before 1975, the earlier of
    • (A) December 31 of the calendar year that is 50 years after the commissioning date, and
    • (B) December 31, 2019, and
  • (ii) in the case of a unit whose commissioning date is after 1974, the earlier of
    • (A) December 31 of the calendar year that is 50 years after the commissioning date, and
    • (B) December 31, 2029; and
• (b) for a unit referred to in paragraph (a) of the definition commissioning date, 18 months after the applicable date described in paragraph (a). (vie utile)

2 Subsection 3(5) of the Regulations is replaced by the following:

CCS excluded

(5) The CO₂ emissions from a unit referred to in subsection (1) do not include emissions that

• (a) are captured in accordance with the laws of Canada or a province that regulate that capture;
• (b) are transported and stored in accordance with the laws of Canada or a province, or of the United States or one of its states, that regulate that transportation or storage, as the case may be; and
• (c) are not subsequently released into the atmosphere.

3 (1) Subsection 4(1) of the Regulations is replaced by the following:

Registration

4 (1) A responsible person for a new unit must register the new unit by sending to the Minister, on or before 30 days after its commissioning date, a registration report that contains the information set out in Schedule 1.

(2) Subsection 4(3) of the Regulations is replaced by the following:

Change of information

(3) If the information provided in the registration report changes or if the unit is decommissioned, the responsible person must, not later than 30 days after the change or decommissioning, send to the Minister a notice that provides the updated information or that indicates the unit has been decommissioned, as the case may be, along with the date of the decommissioning.

4 Subsection 5(2) of the Regulations is replaced by the following:

Period of application

(2) The application must be made in the period that begins on January 1 and that ends on May 31 of the calendar year during which the unit reaches its end of life.

5 Paragraphs 9(1)(a) and (b) of the Regulations are replaced by the following:

• (a) in the case of a new unit, the unit is designed to permit its integration with a carbon capture and storage system that is to be constructed; and
• (b) in the case of an old unit, the unit may be retrofitted to permit its integration with a carbon capture and storage system that is to be constructed.

6 Paragraphs 10(a) to (d) of the English version of the Regulations are replaced by the following:

• (a) carry out a front end engineering design study by January 1, 2020;
• (b) purchase any major equipment that is necessary for the capture element by January 1, 2021;
• (c) enter into any contract required for the transportation and storage of CO₂ emissions from the unit by January 1, 2022;
• (d) take all necessary steps to obtain all permits or approvals required in relation to the construction of the capture element by January 1, 2022; and

7 (1) Paragraph 14(1)(d) of the Regulations is replaced by the following:

• (d) the quantity of CO₂ emissions from the combustion of fossil fuels in the existing unit is determined in accordance with a system or method referred to in subsection 20(1);

(2) Paragraph 14(3)(b) of the Regulations is replaced by the following:

• (b) at least 30 consecutive months of the period referred to in paragraph (1)(g) have occurred before the day on which the application is made.

8 The description of G_aux in subsection 19(1) of the Regulations is replaced by the following:

• G_aux is the quantity of electricity that is produced by the unit and used by the power plant in which the unit is located during the calendar year to operate infrastructure and equipment that is attributed to the unit for electricity generation and for separation, but not for pressurization, of CO₂, expressed in GWh, determined in accordance with an appropriate method of attribution, based on data collected using meters that comply with the requirements of the Electricity and Gas Inspection Act and the Electricity and Gas Inspection Regulations.

9 The formula set out in section 22 of the English version of the Regulations is replaced by the following:

10 The portion of the description of CC_i in subsection 23(2) of the French version of the Regulations before paragraph (a) is replaced by the following:

• CC_i représente le contenu en carbone de chaque échantillon ou échantillon composite, selon le cas, de combustible pour la i^e période d’échantillonnage, exprimé pour un combustible solide, liquide et gazeux, respectivement, selon la même unité de mesure applicable que celle mentionnée pour la variable CC_M, et fourni à la personne responsable par le fournisseur du combustible ou, s’il ne l’est pas, celui établi par la personne responsable — ce contenu étant déterminé :

11 (1) Paragraph 24(2)(c) of the Regulations is replaced by the following:

• (c) a fuel listed in Table 4 to Schedule 5; and

(2) Subparagraphs 24(6)(a)(i) and (ii) of the Regulations are replaced by the following:

• (i) coal or biomass, in accordance with ASTM D5865 - 13, entitled Standard Test Method for Gross Calorific Value of Coal and Coke,
• (ii) a fuel from waste, in accordance with ASTM D5865 - 13, and

12 Paragraph 2(d) of Schedule 1 to the Regulations is replaced by the following:

• (d) for an existing or old unit, the calendar year in which it reaches, or has reached, the end of its useful life;

Coming into Force

13 These Regulations come into force on the day on which they are registered.

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the Regulations.)

Executive summary

Background

The Regulations were published in the Canada Gazette, Part II, in September 2012. The Regulations impose a performance standard (an emissions limit) of 420 t of CO₂/GWh of electricity produced by electricity generating units fuelled by coal, coal derivatives and petroleum coke. The standard is designed to allow electricity generating units to permanently shift to lower- or non-emitting types of generation, renewable energy, or fossil fuel-fired power with carbon capture and storage (CCS) all of which can operate at the level of 420 t/GWh, considered to be a “clean-as-gas” level of performance. New units coming online after July 1, 2015, are subject to the performance standard from the start of operation. Units operational prior to 2015 must comply with the performance standard once they have reached the end of their useful life, which is defined as follows in the Regulations:

• Units commissioned before January 1, 1975, are subject to the performance standard after 50 years of operation, or no later than December 31, 2019, whichever date comes first;
• Units commissioned after December 31, 1974, and before January 1, 1986, are subject to the performance standard after 50 years of operation, or no later than December 31, 2029, whichever date comes first; and
• Units commissioned after December 31, 1985, are subject to the performance standard after 50 years of operation.

The Regulations also include compliance flexibility options to ensure a reliable supply of electricity while achieving the objectives of the Regulations.

In 2015, utilities in Canada generated approximately 580 terawatt hours (TWh) of electricity.^{footnote 3} By 2030, utility generation is expected to rise to 608 TWh. The GHG emissions from the electricity sector^{footnote 4}are expected to decrease as a whole, from about 79 Mt CO₂e in 2015^{footnote 5} to 43 Mt CO₂e estimated in 2030, about a 46% decrease, mainly due to the declining use of coal as a fuel for electricity generation. This decrease is due in large part to the Regulations.

In 2015, coal-fired units, responsible for 11% of the total electricity generated in Canada, accounted for 78% (61.5 Mt CO₂e) of GHG emissions from the sector. By 2030, coal-fired units are expected to generate only 5% of the total electricity generated in Canada, but would account for nearly 63% (27 Mt CO₂e) of GHG emissions from the sector.

At the 21st session of the Conference of the Parties to the United Nations Framework Convention on Climate Change (UNFCCC) held in Paris in December 2015, Canada and 194 other countries reached an agreement to fight climate change (the Paris Agreement). The Paris Agreement strengthened the efforts of Parties to the UNFCCC to limit the global average temperature rise to well below 2 °C and pursue efforts to limit the increase to 1.5 °C. The Paris Agreement was officially ratified by Parliament in October 2016, committing Canada to reducing GHG emissions by 30%, from 2005 levels, by 2030. The goal was agreed to by most provincial premiers at a meeting of First Ministers in March 2016.^{footnote 6}

In December 2016, the Government of Canada released the Pan-Canadian Framework. ^{footnote 7} The Government of Canada developed this Framework with provinces and territories, and in consultation with Indigenous peoples. The Pan-Canadian Framework outlines initiatives to achieve emission reductions across all sectors of the economy. New actions for reducing GHG emissions from the electricity sector include a commitment from federal, provincial, and territorial governments to work together to accelerate the phase-out of conventional coal-fired units in Canada by 2030 as part of the plan to achieve the Canada’s Paris Agreement commitment.

The Government of Canada is working with the provinces to accelerate the transition to clean electricity. The Regional Electricity Cooperation and Strategic Infrastructure (RECSI) Program will identify promising electricity infrastructure projects, including interprovincial transmission interties, with the potential of cost effectively achieving significant GHG reductions and bringing clean electricity to places that need it. Potential electric intertie projects could increase grid flexibility and allow greater interaction and more efficient use of variable renewable energy sources. RECSI will help inform future clean electricity infrastructure investment decisions and encourage clean economic growth. The federal government has also made significant investments in clean growth, such as federal funding for projects under the $21.9 billion green infrastructure portion of the Government’s Investing in Canada Plan laid out in Budget 2017, as well as the $5 billion that will be available for green infrastructure investment through the Canada Infrastructure Bank.^{footnote 8}

The Government of Canada recognizes the importance of supporting a just and fair transition for workers and communities that may be affected by the transition to a low-carbon economy, including the phase-out of traditional coal-fired electricity. In an effort to better understand and minimize the impacts of this phase-out, the Government of Canada launched a Task Force on Just Transition for Canadian Coal Power Workers and Communities. The Task Force includes representatives from labour, business, and municipal government, as well as sustainable development and workforce development experts. In spring 2018, the Task Force travelled to the affected regions across Canada. Its members met directly with coal workers and communities and consulted stakeholders and governments. The Task Force will provide recommendations by the end of 2018 on what could be included in a just transition plan for coal power workers and communities.

In November 2017, the Government of Canada partnered with the Government of the United Kingdom to launch the Powering Past Coal Alliance, a global alliance to phase out coal-fired electricity.

In order to support the Government of Canada’s commitment under the Paris Agreement, on December 17, 2016, the Department of the Environment (the Department) published a notice of intent (NOI) in the Canada Gazette, Part I, ^{footnote 9} that communicated its intent to amend the Regulations to require that all coal-fired units meet the performance standard of 420 t of CO₂/GWh by no later than 2030.

Affected units and provincial reduction measures

In 2017, there were 36 coal-fired electricity generating units operating at 16 facilities in 5 provinces, with a combined generating capacity of approximately 10 000 megawatts (MW).

Of the 36 units operating in 2017, 20 are expected to shut down before 2030, ^{footnote 10} as they will reach their end of useful life under the Regulations before that year. One unit in Saskatchewan has been equipped with carbon capture and storage technology and will be able to meet the 420 t of CO₂/GWh performance standard and operate past its prescribed end of useful life. As a result, the total number of coal-fired units expected to operate past 2030 in the absence of the Amendments is 15, plus one unit that has been equipped with carbon capture and storage.

Figures 1 and 2 show the location of coal-fired electricity generating facilities and high-voltage transmission lines in Alberta and Saskatchewan, and New Brunswick and Nova Scotia, respectively.

Figure 1: Coal-fired electricity generating facilities in Alberta and Saskatchewan

Figure 2: Coal-fired electricity generating facilities in New Brunswick and Nova Scotia

The bar graph in Figure 3 shows the number of units expected to operate between 2019 and 2055, in the absence of the Amendments but including provincial policy announcements, such as Alberta’s announced closure of all coal units by the end of 2030. The area graph behind the bars shows the combined capacity of the units in operation. The right, vertical axis shows the combined capacity of coal-fired units operating in megawatts.

Figure 3: Forecast of counts and capacity of coal-fired generating units in Canada

Alberta

The electricity sector in Alberta is a government-organized energy market with privately owned participants. In 2016, the Government of Alberta endorsed a plan by the Alberta Electric System Operator to transition to a new market framework that includes an energy market and a capacity market. In an energy-only market, generators are paid only for the electricity supplied to the grid. With a capacity market framework, generators would be compensated to have capacity ready to dispatch electricity, whether it is supplied or not. The new framework is expected to be in place by 2021.^{footnote 11} In 2017, there were 18 coal-fired generation units operating in Alberta, with a total capacity of 6 286 MW.

In 2015, coal-fired generating plants in Alberta accounted for 53.0% (41.9 Mt CO₂e)^{footnote 12} of all GHG emissions from electric utility generation in Canada. Six units, with a combined capacity of 2 500 MW, are expected to shut down at the end of 2030. Six further units are expected to shut down before 2030 due to the Regulation, while the remaining six units will convert the fuel usage from coal to natural gas.

Under its Climate Leadership Plan (2015),^{footnote 13}Alberta has committed to eliminating GHG emissions from coal-fired electricity generating sources by the end of 2030. This plan also imposes a carbon price of $30 per tonne of CO₂ emissions on large industrial emitters (including electricity generators) starting in 2018, while also requiring that 30% of electric utility generation in the province come from renewable sources by 2030.

To reach this objective,^{footnote 14} Alberta will add 5 000 MW of wind and solar capacity by 2030, which would replace the equivalent of approximately 80% of the electricity currently generated by coal. New natural gas-fired units are expected to replace the remaining capacity.

Coal to natural gas conversion

One firm in Alberta has announced intentions to convert six coal-fired units to run on natural gas between 2020 and 2022 (coal-to-gas conversions). These units have a combined maximum capacity of approximately 2 400 MW. Once converted, they would no longer be subject to the Regulations, but will instead be subject to the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity. ^{footnote 15} The regulations on natural gas-fired electricity units were developed in parallel with the Amendments, and will set a performance standard for all new natural gas-fired generating units as well as coal-fired generating units that have been converted to run on natural gas.

Saskatchewan

The electric utility sector in Saskatchewan is a regulated monopoly with most of the generating and transmission assets owned and operated by SaskPower, a provincial Crown corporation. In 2017, there were seven coal-fired electricity generation units operating in Saskatchewan, with a total capacity of 1 535 MW.

In 2015, coal-fired electricity generating facilities in Saskatchewan accounted for 15.6% (12.3 Mt CO₂e)^{footnote 16} of all GHG emissions from electric utility generation in Canada. One unit, with a capacity of 120 MW, began operating with carbon capture and storage technology in 2014. The CO₂ emission rate for this unit is below the performance standard limit set by the Regulations and it would not be affected by the Amendments.

Two coal-fired generating units are expected to retire in 2020, another in 2028, and two more in 2030. The remaining unit, with a capacity of 276 MW is expected to retire in 2043. Most of the electricity generated by the coal units retiring before 2030 is expected to be replaced by a new natural gas-fired generating unit that would begin operating in 2020. New natural gas capacity is expected to be commissioned in 2029 and 2042 to replace coal-fired units as they retire.

In November 2015, SaskPower committed to having 50% of electric generating capacity from renewable sources by 2030, with about 30% generated by wind power.^{footnote 17}

Manitoba

There is one coal-fired generating unit in operation in Manitoba, used only for emergency operations. It is expected to shut down by the end of 2019.

New Brunswick

The electric utility generation sector in New Brunswick is a regulated monopoly with NB Power, a provincial Crown corporation, responsible for generation, transmission and distribution of most electricity in the province. In 2015, coal or petroleum coke-fired electricity generating units in New Brunswick accounted for 2.9% (2.3 Mt CO₂e)^{footnote 18} of all GHG emissions from electric utility generation in Canada.

In 2017, New Brunswick had two coal-fired electricity generating units in operation with a total capacity of 837 MW. One of the two units, with a capacity of 357 MW is fuelled by petroleum coke with heavy fuel oil and is expected to shut down in 2029, whereas the remaining unit, with a capacity of 480 MW, is expected to shut down in 2044.

In 2015, New Brunswick passed regulations under its Electricity Act that require that 40% of in-province electricity sales come from renewable sources by 2020. Until then, in-province electricity sales from renewable sources must meet or exceed the 2012–2013 proportion, about 28%.^{footnote 19}

Nova Scotia

The electricity sector is a regulated monopoly in Nova Scotia, with most electricity generation and transmission assets owned by Nova Scotia Power Inc., a privately owned utility.

In 2017, Nova Scotia had eight coal-fired electricity generation units, with a total capacity of 1 247 MW. Under the existing regulation, six of these eight units have useful life dates before 2030, but Nova Scotia entered into an equivalency agreement with the federal government, which suspended the application of the Regulations in the province.^{footnote 20} As a result, seven of the eight units (1 094 MW) are expected to operate beyond 2030 in the baseline scenario.

In 2015, coal-fired units in Nova Scotia accounted for 6.2% (4.9 Mt CO₂e)^{footnote 21} of all GHG emissions from electric utility generation in Canada.

As part of the equivalency agreement, Nova Scotia amended its Environment Act in 2013 to include GHG emission caps for electricity utility generation. Total GHG emissions from electricity utility generation are capped at 4.5 Mt CO₂e for the year 2030. Under its 2009 Climate Change Action Plan, 2009 Energy Strategy, and 2010 Renewable Electricity Plan, Nova Scotia committed to transitioning from coal to more renewable energy sources. These policies required Nova Scotia Power Inc. to obtain 25% of electricity from renewable energy sources by 2015, and to increase this minimum to 40% by 2020.

Issues

GHG emissions pose a risk to the health, environment, and overall welfare of Canadians by contributing to climate change. According to Environment and Climate Change Canada’s Greenhouse Gas Inventory and Air Pollutant Emissions Inventory, coal-fired electricity generating units are the highest emitting stationary sources of harmful GHGs and air pollutants in Canada, accounting for nearly 9% of total national GHG emissions in 2015, 22% of total national emissions of sulphur oxides, 6% of nitrogen oxides, and 16% of mercury. Although Canada has taken action to reduce GHG and air pollutant emissions from coal-fired electricity generating units, making a meaningful contribution to achieving its Paris Agreement commitment and further protecting the health and environment of Canadians will require these reductions to occur earlier than expected under the existing Regulations.

Objectives

The objective of the Amendments is to ensure that the permanent transition from high-emitting electricity sources (e.g. coal-fired electricity generation) to low- or non-emitting sources is achieved by 2030, which will further contribute to the protection of the environment and the health of Canadians, as well as help Canada fulfill its Paris Agreement commitment of reducing GHG emissions by 30% below 2005 levels by 2030.

Description

Under the Regulations, the performance standard of 420 t of CO₂/GWh of electricity produced applies to new coal-fired electricity generating units commissioned on or after July 1, 2015, and existing units that have reached the end of their useful life as defined by the Regulations. The Amendments will require all existing units to comply with the performance standard after they reach the end of their useful life (between 45 and 50 years of operation), or by 2030, whichever comes first. This performance standard is designed to phase out conventional coal by 2030.

Regulatory and non-regulatory options considered

In order to achieve the objective of ensuring a permanent transition from high-emitting to low- or non-emitting sources of electricity generation by 2030, the Department considered the following options:

Status quo approach

Emissions of CO₂ from coal-fired generating units are regulated under the Regulations, whereby high-emitting coal-fired units could continue operating beyond 2040 (with the last unit scheduled to close in 2053). Allowing high-emitting coal-fired units to operate would require other sectors to reduce GHG emissions even more in order to meet Canada’s 2030 emission target. This would result in an unnecessary loss of social welfare.

Voluntary measures

Voluntary (or alternative) measures are less prescriptive than a regulatory approach. For example, under the Canadian Environmental Protection Act, 1999 (CEPA), a Pollution Prevention Plan (P2 Plan) is a voluntary agreement for the use of processes, practices, materials, products, substances or energy that avoids or minimizes the creation of pollutants and waste and reduces the overall risk to the environment or to human health.

The Risk Management Objective (RMO) identified in a P2 planning notice is not enforceable under CEPA. Persons subject to a P2 planning notice must consider the RMO in the preparation and implementation of their plans, but they would not be held accountable under the law if it is not met. P2 planning notices are therefore not as prescriptive nor as stringent as regulations. A regulatory approach would ensure that the requirements of the Amendments are met and that such reductions help contribute to Canada’s commitment under the Paris Agreement.

A P2 Plan could not provide assurance of significant emission reductions in the desired time frame, nor the level of certainty needed to support industry investment in lower- or non-emitting sources of electricity generation.

Pricing of GHG emissions

A key pillar of the Pan-Canadian Framework is pricing carbon pollution across Canada, and a crucial element of nationwide carbon pricing is the Greenhouse Gas Pollution Pricing Act, 2018. Coal-fired electricity generating units would be subject to provincial or federal carbon pricing in all provinces starting no later than January 2019. Even though provincial and federal carbon pricing systems are either in place or being developed, the Amendments have been included in the Pan-Canadian Framework as a complementary climate action that would achieve greater, faster emission reductions than carbon pricing alone.

Existing and planned carbon pricing systems implemented by provincial and federal governments would reduce emissions from coal-fired electricity generation units, but the complete phase-out of conventional coal-fired electricity would be no sooner than as estimated in the Regulation.

Regulated approach under CEPA

Reducing GHG emissions to the level required to meet the 2030 target will require reductions from all sectors of Canada’s economy. The Amendments are one of many measures taken to meet this target. The regulated approach leverages the existing regulatory framework to ensure that the permanent transition from conventional high-emitting coal-fired electricity generating sources to lower- or non-emitting sources is accomplished within the desired time frame. It is designed to provide regulatory certainty to allow electric utility generators to adjust capital investment plans.

Benefits and costs

Between 2019 and 2055, the expected reduction in GHG emissions^{footnote 22} from electric utility generation as a result of the Amendments is approximately 94 Mt CO₂e, which will result in avoided climate change damages valued at $3.4 billion.^{footnote 23} Another benefit of the Amendments will be a reduction in air pollutant emissions, which will result in air quality improvements to human health and the environment valued at $1.3 billion, bringing the total benefit to nearly $4.7 billion. The total cost for complying with the Amendments is $2.0 billion, resulting in a net benefit of $2.7 billion.

As shown in Figure 4, the most significant costs will be carried around 2029 and 2030 for commissioning new capacity to replace coal-fired generating units and for decommissioning units that have reached the end of their amended useful life. Those costs will be partly offset later, by the avoided costs of replacement capacity, had those units operated until the end of their useful life. Early replacement will also result in incrementally higher annual generating costs in subsequent years, as utilities will be required to supply electricity from a more expensive source.

Figure 4: Baseline scenario and policy scenario CO₂ emissions and compliance costs by year

Analytical framework

The benefits and costs associated with the Amendments were assessed in accordance with the Treasury Board Secretariat (TBS) Canadian Cost-Benefit Analysis Guide, which includes identifying, quantifying and, where possible, monetizing the impacts associated with the policy. The incremental impacts of the Amendments are determined by comparing the electricity sector without the Amendments (the baseline scenario), and with the Amendments (the policy scenario). The baseline scenario includes provincial regulations and programs that influence electricity generation in the provinces.

The key impacts of the Amendments are demonstrated in the logic model below (Figure 5). The central analysis considers the benefits and costs of replacing generating capacity earlier in the policy scenario than in the baseline scenario. The difference between the two is reported as the net benefits of the Amendments.

Based on the information provided in consultation with utility stakeholders, it is assumed that coal-fired electricity units which will not meet the standards set in the Amendments (420 t of CO₂/GWh of electricity produced), will shut down in 2030 as opposed to a later date set in the Regulation or in the provincial regulations (accelerated phase-out). Accelerating the closure of coal-fired generating units will reduce GHG and air pollutant emissions from the electricity sector, which will result in avoided climate change damage in the future and improved air quality. Compliance with the Amendments will result in higher costs to supply customers with electricity in the policy scenario relative to the baseline scenario. Consumers will respond to higher prices by using less electricity in the policy scenario than in the baseline scenario, which will reduce consumer welfare. The compliance costs to electricity providers and welfare loss of consumers will be the social cost of the Amendments.

Figure 5: Logic model for the analysis of the Amendments

A coal unit reaches its regulated end of life and must comply with the 420 t of CO2/GWh performance standard.	→	Reduced GHG and air pollutant emissions	→	Avoided climate change damage / Improved air quality					→	Social benefit
↓
Shut down and replace with generation from non-coal-fired source. Three compliance strategies to respond to lost generation.	→	Build replacement capacity		→	Compliance costs			→		Social cost
	→	Increase generation from existing non-coal units		→		→		Higher retail prices
								↓
	→	Increase imports / Reduce exports		→		→		Reduced electricity use	→

The baseline and policy scenarios were based on Canada’s 2017 greenhouse gas emissions reference case and updated through consultation with stakeholders, as well as with counterparts in federal departments and provincial ministries.

Modelled scenarios were based on the most recent information and the provincial and federal regulations currently in place, whereas regulations under development, such as the federal carbon pricing in all provinces (the federal backstop) are not included in the department’s modelling. Given the evidence from utilities, the analysis also assumed that six coal-fired electricity units in Alberta will convert to natural gas-fired units (coal-to-gas conversions) between 2020 and 2022.

The underlying assumption of the policy scenario is that electric utilities will respond to the Amendments in a manner consistent with cost minimization behaviour of the firm, while accounting for system operation requirements and observing all other existing regulations.

The time frame considered for this analysis is 2019–2055. The end year for the analysis is meant to capture the full impact of replacing all coal-fired units early, since the last coal-fired generating unit is not expected to retire until 2053 in the baseline scenario. As shown in Figure 4, few costs are expected prior to 2029.

Any regulation that affects how utilities supply electricity will indirectly affect many parts of the economy. Higher electricity prices will alter the behaviour of electricity-dependent individuals and firms. Nonetheless, the scope of the central analysis is limited to the impact on costs for, and emissions from, the electricity sector, with consideration for how consumer welfare will be affected by the resulting higher retail prices for electricity.^{footnote 24}

Compliance strategies

The Amendments will accelerate the regulated useful life for conventional coal-fired electricity generating units to the end of 2029. Electricity generating firms are expected to respond with one or a combination of the following three options to replace the lost generation from coal-fired electricity generating units:

• (a) build emission-compliant replacement capacity;
• (b) increase imports and/or decrease exports; or
• (c) increase generation from existing non-coal-fired units.

This analysis assumes that utilities will respond to lost generation from coal-fired electricity units with the same strategy in both the baseline and the policy scenario. For example, where the generation from a coal-fired generation unit is expected to be replaced with generation from a newly constructed natural gas-fired unit in the baseline scenario, then it will be expected to be replaced by a newly built natural gas unit in the policy scenario as well.

Alberta

In the baseline scenario, coal-fired units in Alberta will be shut down by December 31, 2030, in response to Alberta’s Climate Leadership Plan. In the policy scenario, all coal units in Alberta will shut down at the end of 2029. This will create a 12-month gap between the baseline and policy scenarios. Any costs, benefits and emission reductions attributable to the Amendments will occur because of the difference between the baseline and policy scenarios, i.e. the 12-month earlier shutdown in the policy scenario versus the baseline scenario. The foregone generation from coal-fired units will be replaced through increased generation from existing utility generating units (including the coal-to-gas converted units).

Saskatchewan

Saskatchewan is expected to build additional natural gas-fired capacity in 2042 to replace the coal unit that will close in 2043 in the baseline scenario. In the policy scenario, the coal unit in Saskatchewan will shut down at the end of 2029 with the lost coal-fired generation replaced by a new natural gas unit built around the same year. Natural gas-fired generating capacity is already expected to be built in that year to replace coal units closing in 2029 in the baseline scenario. The new units would have a greater capacity in the policy scenario than in the baseline scenario. This would result in incrementally higher generating costs between 2030 and 2043. The capital costs would be higher in 2029 to replace the coal unit early, but avoided in 2043 since it would have been decommissioned 13 years earlier.

New Brunswick

New Brunswick is a regional electricity hub, with a transmission grid strongly interconnected to the Maritimes, Quebec and New England. The province is expected to take advantage of its existing transmission capacity and replace lost generation from coal-fired units with hydroelectricity purchased from Quebec.

Historically, New Brunswick has been a net exporter of electricity. However, this is expected to change dramatically over the next two decades as generating capacity is expected to shut down without being fully replaced.

In the baseline scenario, approximately 480 MW of generating capacity in New Brunswick is expected to shut down around 2044, when the only coal-fired unit retires.

In the policy scenario, the early closure of the coal-fired unit would lead to approximately 480 MW of generating capacity shutting down in 2030. Electricity generated by the coal-fired unit would be replaced by reduced electricity exports and purchases from outside the province. This is expected to create a net inflow of electricity to nearly 2 600 GWh in 2030 (compared to a net outflow of about 620 GWh in the baseline scenario).

In both the baseline and policy scenarios, the province would build some new natural gas capacity to maintain a reserve margin;^{footnote 25} however, the high price of natural gas would make it more cost effective to import hydroelectricity from Quebec, so the utilization rate for these units would be low. Importing electricity from Quebec would less expensive than generating it with a natural gas-fired unit, but more expensive than generating it with a coal-fired power plant. As a result, increasing imports of hydroelectricity from Quebec when coal plants retire (as opposed to building new natural gas units) would result in lower electricity prices.

Nova Scotia

In the baseline scenario, the Nova Scotia equivalency agreement is assumed to meet the conditions required in CEPA and extend indefinitely beyond 2030, whereas it will end in 2030 in the policy scenario.

In the modelled scenarios, Nova Scotia will replace almost all its coal-fired electricity with electricity generated by new natural gas-fired units. There will also be some adjustment of the electricity trade flows in and out of the province. Trade with Newfoundland and Labrador, through the Maritime Link, is expected to reach maximum capacity in the baseline and policy scenarios prior to 2030. However, Nova Scotia will generate and send more electricity to New Brunswick in the policy scenario than in the baseline scenario, due to the demand created in New Brunswick when coal-fired electricity plants shut down.

Updates to the analysis following publication in the Canada Gazette, Part I (CG-I)

Following the publication in the Canada Gazette, Part I, the Department engaged with provincial partners, industry stakeholders and non-governmental organizations to review modelling assumptions used in the analysis of the Amendments. Below is the summary of substantive changes made to the analysis:

Baseline assumption updates

• In Alberta, 6 out of the 12 coal-fired units that were to retire before 2029 as per the Regulations, convert to coal-to-gas plants between 2020 and 2022. They are assumed to operate for 10 years after the conversion to natural gas and produce an equivalent level of output to the previous coal units while emitting about 40% less GHG emissions.^{footnote 26} The coal-to-gas conversions are expected to reduce construction of new natural gas plants in the short-term, and increase fuel usage and GHG emissions in the policy scenario between 2029 and 2031 (year in which the last coal-to-gas plant is expected to retire). This would result in lower incremental net construction costs, higher incremental fuel costs, and lower GHG emission reductions in CG-II compared to CG-I.
• In New Brunswick, the main change is that a coal-fired plant, with a capacity of 480 MW, which had its forecast generation fixed at the last historical year level in CG-I, was allowed to freely dispatch in CG-II, resulting in higher projected generation in the baseline. This increased generation from the coal-fired plant in the baseline is expected to result in higher cost of replacing lost generation and higher GHG emission reductions in the policy scenario, when the plant closes early due to the Amendment.
• Due to updated information from Nova Scotia, two natural gas steam boilers are no longer assumed to retire in the baseline in 2025 and 2032, respectively, and will keep operating. When the coal-fired plants close early due to the Amendment (in the policy scenario), the lost generation from the coal plants is compensated by increasing generation from these old and inefficient plants kept in operation as opposed to generation from new natural gas plants, as projected in CG-I. Keeping these natural gas steam boilers in operation is therefore expected to reduce construction of new natural gas plants, and increase fuel usage and GHG emissions in the policy scenario (resulting in lower incremental net construction costs, higher fuel costs, and lower GHG emission reductions in CG-II analysis compared to CG-I).
• The Department also updated natural gas fuel price projections for New Brunswick and Nova Scotia, based on average citygate price growth rates for the Algonquin Hub from Wood Mackenzie. New Brunswick’s natural gas forecast prices for electric utilities are now aligned with Nova Scotia’s. Natural gas usage is expected to increase due to the Amendments. The significantly higher price of natural gas in the Maritimes relative to the cost of coal increases fuel costs in the policy scenario relative to the baseline.

Other modelling updates

• The CG-II analysis was based on the 2017 reference case compared to the CG-I analysis that was based on the 2016 reference case. The 2017 reference case updated some key input data such as Gross Domestic Product and population, sector-specific industrial growth assumptions, and some cost assumptions.
• The Department quantified and valued GHG impacts (avoided climate change damage) in CG-II to account for changes in electricity mix in different provinces as reported during the consultation period, and incorporate more robust and realistic projections for some electricity units.
• The Department did not remodel air quality benefits (health and environmental benefits), as the changes in air pollutant emission reductions were considered to be negligible at the national level over the analytical time frame. However, the results may differ at a regional level, due to changes in the baseline between CG-I and CG-II. For example, the estimated air quality benefits may be slightly smaller in Alberta in 2030, due to the incorporation of coal to gas conversions in the baseline scenario.

Incremental impacts of compliance

Most of the incremental costs of the Amendments will occur in the four provinces directly affected by the Regulations, shown in Table 11 in the “Distributional impact analysis” section below. There will be a cost saving in other provinces due to increased electricity export revenues and reduced electricity import costs.

Benefits of compliance

The cumulative benefit in Canada of the emission reductions from the Amendments is valued at about $4.7 billion (2019–2055).

Benefits of the Amendments are from avoided global climate change damage and improved air quality due to reduced air pollutant emissions. Benefits from reduced air pollutants (calculated at the provincial level) include health benefits and environmental benefits. The Amendments will reduce GHG emissions from electricity generation by 94 Mt CO₂e^{footnote 27} between 2019 and 2055 versus the baseline scenario. The avoided climate change damage from these reductions is valued at $3.4 billion using the Department’s Social Cost of Greenhouse Gas Estimates. The Amendments will also result in the reduction of emissions of many criteria air pollutants. The most significant reduction in emissions will be 555 kilotons (kt) of sulphur oxides (SO_x) and 206 kt of nitrogen oxides (NO_x) between 2019 and 2055. These criteria air pollutants have been shown to adversely affect the health of Canadians, through direct exposure and through the creation of smog (including particulate matter and ground-level ozone). The health benefits from reduced air pollutant emissions and avoided human exposure to mercury are valued at $1.3 billion. Environmental benefits, such as increased crop yields, reduced surface soiling, and improvement in visibility, is valued at $40 million.

GHG emission reductions

Almost all (>99%) of GHG emission reductions from the Amendments will be from reductions in CO₂ emissions. There will also be reductions in nitrous oxide (N₂O) emissions, but a small increase in methane (CH₄) emissions. These emissions are valued separately using the Social Cost of GHG Estimates. However, for reporting purposes, emissions of N₂O and CH₄ are converted to CO₂e using 100-year Global Warming Potentials from the Intergovernmental Panel on Climate Change Fourth Assessment Report. Table 1 shows the expected reduction in GHG emissions attributable to the Amendments.

Table 1: GHG emission reductions (Mt CO₂e)

	2019—2025	2026—2030	2031—2035	2036—2040	2041—2045	2046—2050	2051—2055	Total
Alberta	0	7.1	0.5	0.3	0	0	0	8.0
Saskatchewan	0	0.8	6.6	6.6	2.7	0	0	16.7
New Brunswick	0	2.8	13.8	13.6	8	0	0	38.3
Nova Scotia	0	2.1	10.1	9.2	6.6	3.3	0.7	32
Rest of Canada	0	–0.1	–0.5	–0.5	0	0	0	–1,1
Total	0	12.8	30.6	29.2	17.3	3.3	0.7	93.8

Social cost values are used to estimate the monetary value, in a given year, of the worldwide damage that will occur over the coming decades from each additional tonne of GHGs emitted into the atmosphere. This analysis uses the central values for social cost of CO₂, CH₄, and N₂O. A valuation using the 95th percentile (P₉₅) value, which represents a low-probability, high-cost climate change future, is presented in the sensitivity analysis. Table 2 shows the central and 95th percentile social cost values for CO₂, CH₄, and N₂O at the start of each decade.

Table 2: Social cost of GHGs at the start of each decade, central and 95th percentile values (2016, $ per tonne)

GHG	2020		2030		2040		2050
	Central	P95	Central	P95	Central	P95	Central	P95
CO2	46	191	56	244	67	292	77	331
CH4	1,319	3,955	1,785	5,730	2,291	7,676	2,802	9,357
N2O	16,461	55,120	20,807	71,566	25,300	88,465	30,137	106,241

Benefits from reduced air pollutant emissions

To assess the potential health and environmental benefits resulting from air pollutant emission reductions, Environment and Climate Change Canada’s Meteorological Service of Canada used the A Unified Regional Air-quality Modelling System (AURAMS) atmospheric model to determine how the emission decrease will affect ambient air quality (i.e. the air that Canadians breathe). Health Canada then used the Air Quality Benefits Assessment Tool (AQBAT) to determine how improvements in ambient air quality will affect the health of Canadians.

Based on changes in local ambient air quality, AQBAT estimates the likely reductions in average per capita risks for a range of health impacts known to be associated with air pollution exposure. These changes in per capita health risks are then multiplied by the affected populations in order to estimate the reduction in the number of adverse health outcomes across the Canadian population. AQBAT also applies economic values drawn from the available literature to estimate the average per capita socio-economic benefits of lowered health risks.

Environmental benefits were estimated using the Air Quality Valuation Model (AQVM2). This model estimates how changes in ambient air quality will impact three different endpoints being exposed to atmospheric pollution: crop productivity, surface soiling, and visibility. More precisely, AQVM2 relies on biological dose-response functions to measure increases in sales revenue from enhanced crop productivity associated with reduced ground-level ozone, as well as willingness-to-pay estimates to measure Canadian households’ welfare improvement from reduced surface soiling and increased visibility (i.e. windows), both associated with lower levels of particulate matter.

Benefit estimates reflect not only the emission reductions, but also the atmospheric conditions and endpoint (population or croplands) exposure to these pollutants. Population density, wind direction, and atmospheric conditions play a critical role in smog formation. For instance, emission reductions at facilities that are located upwind of large population centres or extensive croplands can have a greater impact than similar emission reductions at facilities in remote or downwind locations. Consequently, benefit estimates in a province may not necessarily be proportional to emission reductions in that same province. In addition, environmental benefits in some provinces may be partly attributable to reductions of emission releases from adjacent provinces, because pollutants can travel over longer distances. The AURAMS, AQBAT, and AQMV2 models were run for the years 2030 and 2035. To estimate the benefits for the remaining years, pro-rating techniques were used. Significantly more emissions will be reduced in 2030, relative to any other year in the analytical time frame. Since the variability in annual emission reductions was estimated to be lower between 2031 and 2055, the annual environmental benefits in this period were proxied by pro-rating the 2035 values by the proportion of pollutant emission reductions (mainly composed of SO_x and NO_x) for each year between 2031 and 2034, and between 2036 and 2055.^{footnote 28}

Improved health outcomes

Total health benefits are estimated be around $1.2 billion for the 2019 to 2055 period.

The human health impacts and resulting socio-economic benefits are highly dependent on population proximity to the source of emissions from coal-fired electricity generation. As mentioned above, it is the population exposure to changes in air quality, and not simply the absolute changes in particulate matter (PM) and ozone levels, which determines the health benefits of the Amendments. For this reason, the areas that experience the largest health benefits, and the areas that experience the largest air quality improvements, are not necessarily the same.

The health benefits covered in the analysis include a wide range of health outcomes linked with air pollution, such as asthma episodes and minor breathing difficulties to more serious impacts such as visits to the emergency room and hospitalization for respiratory or cardiovascular problems. Air pollution also increases the average per capita risk of death. While the changes in individual risk levels are small, they apply to large populations; these individual risk reductions translate into large social benefits. Table 3 shows some of the estimated changes in cumulative health outcomes as a result of the Amendments.

Health benefits resulting from improved air quality under the Amendments will have a present value of roughly $440 million in 2030. This includes a large benefit in Alberta ($310 million). The benefits estimated in Alberta attributable to the Amendments do not extend past 2030, as coal-fired units will shut down by 2031 in the baseline scenario. In 2035, the estimated health benefits across Canada are expected to be lower, approximately $56 million. The largest benefit is estimated in Nova Scotia ($26 million).

Table 3 shows the estimated total present value of the improvement in social welfare, expressed in economic (dollar) terms, for all health outcomes over 2019 to 2055. The present value of the health benefits is estimated at $1.2 billion, with the largest benefits in Nova Scotia, followed by Alberta, New Brunswick and Saskatchewan.^{footnote 29}

The reductions in ambient PM_2.5 account for approximately 60% of the health benefits from the Amendments. This is primarily from secondary formation of PM_2.5 from reductions in other primary pollutants, such as NO_x and SO_x. Ozone improvements account for about 40% of the health benefits. Benefits are driven by a reduction in premature death risk, largely because of reductions in ambient PM levels.
The values shown in Table 3 are socio-economic values associated with changes in health status, or changes in health risks. These values are derived using a social welfare approach. The values in the table should not be interpreted as health care cost savings or changes in productivity. Rather, the values in the table are estimated measures of improvement in quality of life, resulting from better health. By far the most significant impact of the air quality improvements, in terms of quality of life, is a reduction in the risk of premature mortality. Reductions in mortality risk account for approximately 95% of the estimated social welfare.^{footnote 30}

Table 3: Estimated changes in cumulative health outcomes as a result of the Regulations^{footnote 31} and total present value of the improvement in social welfare for all health outcomes, 2019–2055

Region	Estimated reductions in cumulative health outcomes as a result of the Regulations			Present value in 2017 of total avoided health outcomes (millions of dollars, discounted to 2017 using a 3% discount rate)
	Premature mortalities	Asthma episodes	Days of breathing difficulty and reduced activity	Ozone related	PM2.5 related	Total (Includes additional pollutants including mercury)
Alberta	56	14 000	66 000	90	210	306
Saskatchewan	10	1 400	9 400	4	40	48
New Brunswick	36	4 100	23 000	70	80	158
Nova Scotia	89	8 000	58 000	70	300	396
Rest of Canada	73	12 000	38 000	230	100	315
Total	260	40 000	190 000	470	730	1,223

The estimated changes in cumulative health outcomes are concurrent for aggregate number of persons affected.

Mercury reductions from the electricity sector

In addition to reductions in NO_x, SO_x and PM emissions, the Amendments are expected to reduce mercury emissions from the electric utility sector by 1.4 tonnes between 2019 and 2055. Mercury that enters the ecosystem can enter the food chain and can have toxic impacts on humans and wildlife. Reducing mercury emissions from power plants is, therefore, expected to result in human health benefits. These health benefits have been estimated at approximately $5 million.^{footnote 32}

Environmental benefits

PM may accumulate on surfaces and alter their optical characteristics, making them appear soiled or dirty, while PM in suspension in the air can block and scatter the direct passage of sunlight to reduce visibility. In addition, high concentrations of ozone can affect crops by reducing their biomass and increasing their vulnerability to stressors such as diseases. Therefore, better air quality may result in reduced surface soiling, improvement in visibility, which may positively impact the general welfare of Canadians, as well as tourism, and increased crop yields. The quantified environmental benefits resulting from the Amendments are estimated to be about $40 million. The welfare of residential households associated with improvement in visibility is valued at $29.6 million. Higher crop yields and avoided household cleaning costs account for $8.2 million and $2.5 million, respectively. Nova Scotia will receive the largest portion of these benefits, which is consistent with its large reduction in emissions.

Table 4 below presents the estimated environmental benefits, for each modelled impact and province experiencing significant reductions in emissions under the Amendments, with the other provinces/territories aggregated as the “Rest of Canada.”

Table 4: Cumulative environmental benefits by impact and province (2019–2055), millions of dollars, discounted to 2017 using a 3% discount rate

Environmental impact	Agriculture	Soiling	Visibility	Total
Economic indicator	Change in sales revenues for crop producers	Avoided costs for households	Change in welfare for households
Alberta	3	1	5	9
Saskatchewan	1	0	1	3
New Brunswick	0	0	3	4
Nova Scotia	0	1	11	12
Rest of Canada	3	0	9	12
Total	8	2	29	40

Totals may not add up due to rounding.

The estimate above for total environmental benefits should be considered to be conservative, because several benefits could not be quantified. The reduction in concentrations of ozone and PM may benefit the health of forest ecosystems and may reduce the risk of illness or premature death within sensitive wildlife or livestock populations. This will potentially result in reduced treatment costs and economic losses for the agri-food industry. However, due to limitations in data and methodology, these benefits could not be quantified in the AQVM2 model.

Compliance costs

The incremental cost of the Amendments is estimated to be $2.0 billion between 2019 and 2055.

Total spending on electric utility generation was calculated for each year and each province in Canada for the baseline and the policy scenarios. The values for costs presented in this analysis are the difference between the two scenarios.

Incremental costs associated with the Amendments are divided into three categories: capital costs, supply costs, and reduced electricity use. Almost all of the incremental cost is attributable to additional fuel costs or purchased power from another region.

Capital costs

Capital costs represent a one-time expenditure for building replacement capacity, refurbishing existing units, and decommissioning units that have reached their end of useful life. Costs for replacement capacity and decommissioning occur in both the baseline and policy scenarios, though at different times. Refurbishment costs are investments intended to restore the operational integrity of the unit. When a coal-fired unit is shut down early, refurbishment costs will be avoided.

There are significant upfront capital costs for compliance between 2026 and 2030 as replacement units are built and coal units are decommissioned. This is offset by avoided construction in later years and avoided refurbishment costs to keep coal-fired generating units running beyond 2030.

Overall, the Amendments will result in net capital cost savings of $305 million, as seen in Table 5. Most of the savings will be in New Brunswick, Nova Scotia and Alberta, with a positive incremental net capital cost in Saskatchewan. The values in Table 5.A (net construction costs), Table 5.B (refurbishment costs) and Table 5.C (decommissioning costs) sum to the totals presented in Table 5.

Table 5: Incremental capital cost (millions of dollars, discounted to 2017 using a 3% discount rate)

	2019–2025	2026–2030	2031–2035	2036–2040	2041–2045	2046–2050	2051–2055	Total
Alberta	0	195	−263	−1	0	0	0	−69
Saskatchewan	0	224	−28	−27	−159	0	0	10
New Brunswick	0	100	−86	37	−222	0	0	−171
Nova Scotia	−40	585	−65	−163	−175	−141	−79	−79
Rest of Canada	0	6	22	−27	3	0	0	4
Total	−40	1,110	−419	−181	−553	−142	−79	−305

Cost to build replacement capacity

The total incremental cost for commissioning replacement generating capacity is approximately $142 million

The price per kilowatt (kW) of commissioning new generating capacity is taken from the National Renewable Energy Laboratory 2015 Standard Scenarios Annual Report and then adjusted for each province through consultation with stakeholders. For example, the undiscounted expected 2030 price of natural gas combined cycle generating capacity is $1,748/kW in Alberta and Saskatchewan, $1,624/kW in Nova Scotia, and $1,020/kW in New Brunswick.

Table 5.A shows the expected incremental construction costs for new generating capacity. Positive values mean that utilities are expected to spend more in the policy scenario than in the baseline scenario. Negative values mean that new construction costs are avoided in the policy scenario. In the case of Nova Scotia, $708 million will be spent in the policy scenario to replace coal-fired generating units with natural gas-fired generating units by 2030. Since these units will be gradually replaced in the baseline scenario, these replacement costs are avoided in subsequent years, resulting in an overall net cost of $256 million.

New Brunswick builds approximately $100 million worth of new natural gas capacity in the policy scenario in comparison with the baseline scenario between 2026 and 2040. This is, however, outweighed by the avoided costs amounting to $197 million between 2041 and 2045 for constructing new natural gas capacity in the baseline scenario. As a result, there is an overall cost saving of $98 million. Overall, the incremental net construction costs are low in New Brunswick, as the province imports electricity from Quebec, which is less expensive than building new natural gas-fired electricity plants.

Table 5.A: Incremental net construction costs (millions of dollars, discounted to 2017 using a 3% discount rate)

	2019–2025	2026–2030	2031–2035	2036–2040	2041–2045	2046–2050	2051–2055	Total
Alberta	0	0	−74	−1	0	0	0	−75
Saskatchewan	0	203	23	−27	−145	0	0	55
New Brunswick	0	63	0	37	−197	0	0	−98
Nova Scotia	0	708	2	−95	−159	−134	−66	256
Rest of Canada	0	6	22	−27	3	0	0	4
Total	0	980	−26	−113	−498	−134	−66	142

Refurbishments

The Amendments will result in $502 million in net avoided refurbishment costs. Coal-fired electricity generating units can operate for up to 50 years through refurbishments. Refurbishment costs vary according to the scope and intensity of the repairs, the life extension being sought and the type of parts that have to be replaced.

The first refurbishment usually occurs after about 20 years of operation to prevent unplanned outages. An initial refurbishment to extend a unit’s life by another 20 years is assumed to cost $1,008/kW, whereas one that will grant an extension of 15 years will cost only $504/kW.^{footnote 33} Subsequent refurbishments are expected to achieve shorter life extensions but cost less because even though older units have higher levels of thermal stress, they have a smaller subset of parts that must be replaced to address this issue. Refurbishment costs for units that have already had at least one refurbishment are therefore assumed to be 60% of the above values.

Since the Amendments will reduce the operational life of affected units, major refurbishments will be avoided. In some cases, utilities will choose to undertake less extensive refurbishments prior to 2030, since the unit will only operate for another 6 or 7 years, as opposed to another 20 years. For example, one unit in Nova Scotia is expected to require refurbishments in 2022. In the baseline scenario, an extensive refurbishment will enable the unit to operate for another 20 years before it will need to be refurbished again. In the policy scenario, the refurbishment will be less extensive, since the unit will be shut down after eight years. This will result in approximately $40 million in avoided refurbishment costs.

Natural gas-fired units will be refurbished after about 20 years in operation. The estimated average refurbishment cost of a natural gas combined cycle unit will be about $126/kW. Table 5.B shows these costs from the units that will otherwise be invested in refurbishment.

Table 5.B: Incremental net refurbishment costs (millions of dollars, discounted to 2017 using a 3% discount rate)

	2019–2025	2026–2030	2031–2035	2036–2040	2041–2045	2046–2050	2051–2055	Total
Alberta	0	0	0	0	0	0	0	0
Saskatchewan	0	0	−51	0	0	0	0	−51
New Brunswick	0	0	−86	0	0	0	0	−86
Nova Scotia	−40	−209	−57	−59	0	0	0	−365
Rest of Canada	0	0	0	0	0	0	0	0
Total	−40	−209	−194	−59	0	0	0	−502

Decommissioning costs

The cost of decommissioning units is expected to be $55 million. Units are expected to be decommissioned the year they cease operating. In the policy scenario all decommissioning costs for coal-fired units will be carried in 2030. These costs will then be avoided in the future. Decommissioning costs are assumed to be $117/kW when scrap material credit is taken into account. This cost accounts for activities such as dismantling boilers, demolishing structures and asbestos remediation. It also includes project expenses such as securing permits and insurance, renting heavy equipment and hiring operating engineers. Since the real cost does not change over time, the incremental impact is the time value of money spent at different periods.

Table 5.C: Incremental net decommissioning costs (millions of dollars, discounted to 2017 using a 3% discount rate)

	2019–2025	2026–2030	2031–2035	2036–2040	2041–2045	2046–2050	2051–2055	Total
Alberta	0	195	−189	0	0	0	0	6
Saskatchewan	0	22	0	0	−15	0	0	7
New Brunswick	0	37	0	0	−25	0	0	13
Nova Scotia	0	85	−10	−9	−16	−7	−13	29
Rest of Canada	0	0	0	0	0	0	0	0
Total	0	339	−199	−9	−56	−7	−13	55

Electricity supply costs

The additional cost of supplying customers with electricity in Canada will be $1.9 billion between 2019 and 2055. Electricity supply costs are ongoing costs associated with delivering electricity to customers. Supply costs consist of operations and maintenance (O&M) [the non-fuel cost for generating electricity], fuel, out of province purchases (the price paid to import electricity), and lost revenue from foregone exports. These are discussed below. The values in tables 6.A (changes to electricity trade with other regions), 6.B (operating and maintenance costs), and 6.C (fuel costs), sum to the values presented in Table 6.

Table 6: Incremental impact on the cost to supply electricity (millions of dollars, discounted to 2017 using a 3% discount rate)

	2019–2025	2026–2030	2031–2035	2036–2040	2041–2045	2046–2050	2051–2055	Total
Alberta	0	338	−7	8	−1	−1	−1	334
Saskatchewan	0	35	123	111	43	0	0	312
New Brunswick	0	77	363	315	−94	−3	−2	656
Nova Scotia	0	103	451	312	147	−28	−73	913
Rest of Canada	0	−147	−106	−83	1	0	0	−336
Total	0	406	824	661	96	−32	−76	1,879

Electricity trade

The North American electricity grid is strongly interconnected, particularly in eastern regions. Canada is a net exporter of electricity to the United States, mainly due the availability of low-cost hydroelectric generating resources. According to the National Energy Board’s Electricity Trade Summary, the net electricity exports from Canada to the United States was 62.2 TWh in 2017, with net revenue of $2.7 billion.

The Amendments will slightly increase electricity imports and reduce exports since a greater portion of domestic capacity will be used to supply the domestic market. Net exports to the United States will be an average of 2.3 TWh lower per year between 2030 and 2044 in the policy scenario relative to the baseline scenario. Cumulatively, exports to the United States are 33.8 TWh lower while imports will be 1.4 TWh higher in the policy scenario than in the baseline scenario. The reduction in net export revenue will be approximately $1.1 billion. It should be noted that Canada remains a net exporter of electricity in both the baseline and policy scenarios, and the change in trade represents a small share of overall electricity demand in Canada.

Most of the reduction in electricity exports is due to the expected change in flows from Quebec. A portion of the electricity that is currently exported to New York State or New England in the baseline scenario will be sent to New Brunswick in the policy scenario. On the other hand, New Brunswick will also reduce its exports to Quebec to meet domestic shortfall, and Quebec will scale down its exports to Ontario, in response to reductions in imports from New Brunswick.

Overall, the Amendments will result in an incremental impact on the electricity trade balance of $1.0 billion. This will comprise a reduction in electricity export revenues of $731 million and an increase in import expenditure by $291 million.

Table 6.A shows the net impact on electricity trade balances for affected provinces. This includes both import spending and lost revenue.

Table 6.A: Incremental impact on the electricity trade balance (millions of dollars, discounted to 2017 using a 3% discount rate)

	2019–2025	2026–2030	2031–2035	2036–2040	2041–2045	2046–2050	2051–2055	Total
Alberta	0	35	20	24	4	0	0	83
Saskatchewan	0	−31	−19	−21	−3	0	0	−74
New Brunswick	0	140	620	509	283	42	15	1,609
Nova Scotia	0	5	−44	−69	−49	−42	−15	−213
Rest of Canada	0	−148	−108	−85	−41	0	0	−382
Total	0	1	468	358	194	0	0	1,022

O&M costs

Natural gas-fired electricity generating units have lower fixed and variable O&M costs than coal-fired electricity generating units. The average undiscounted cost of fixed and variable O&M for a natural gas-fired combined cycle unit is expected to be approximately $6,210/MW, and $1.6/megawatt-hour (MWh), respectively in all provinces between 2019 and 2055. Whereas the average undiscounted costs for a coal-fired unit are $12,000/MW for fixed O&M and $2.1/MWh for variable O&M, over the same period.

The Amendments will result in lower O&M costs of about $287 million. Table 6.B shows the combined fixed and variable O&M savings as a result of the Amendments.

Table 6.B: Incremental operating and maintenance costs (millions of dollars, discounted to 2017 using a 3% discount rate)

	2019–2025	2026–2030	2031–2035	2036–2040	2041–2045	2046–2050	2051–2055	Total
Alberta	0	−44	−2	−3	−1	−1	−1	−53
Saskatchewan	0	−1	−11	−8	−3	0	0	−25
New Brunswick	0	−12	−51	−38	−20	−3	−2	−127
Nova Scotia	0	−9	−40	−22	−13	−5	0	−89
Rest of Canada	0	1	3	2	1	0	0	6
Total	0	−66	−102	−70	−36	−9	−3	−287

Fuel costs

Fuel costs account for most variable generating expenses for thermal units. The Amendments will result in net fuel costs totalling $1.3 billion.

Table 6.C shows the expected incremental fuel costs of the Amendments, which will total $1.3 billion over the time frame. While fuel costs for most affected provinces will increase, New Brunswick will experience fuel savings from shutting down the coal-fired electricity generating unit in 2030 and replacing the lost generation with imports from Quebec. Incremental fuel costs for Alberta include higher fuel costs incurred by coal-to-gas converted units. These units use more fuel (are less efficient) compared to new natural gas units.

Table 6.C: Incremental fuel costs (millions of dollars, discounted to 2017 using a 3% discount rate)

	2019–2025	2026–2030	2031–2035	2036–2040	2041–2045	2046–2050	2051–2055	Total
Alberta	0	346	−25	−14	0	0	0	307
Saskatchewan	0	68	153	140	46	0	0	407
New Brunswick	0	−51	−205	−156	−74	0	0	−486
Nova Scotia	0	108	535	403	160	−23	−73	1,109
Rest of Canada	0	0	0	0	0	0	0	0
Total	0	471	458	373	132	−23	−73	1,338

Fuel prices vary by province and over time, but as shown in Table 7, the expected price paid by electric utility generators for natural gas is expected to be approximately double the cost of coal when compared in terms of cost for delivered energy, measured as dollars per million British thermal units (MMBtu).

Coal prices are forecast based on historic prices adjusted using the growth rate of the average mine mouth coal price taken from the United States Energy Information Administration Annual Energy Outlook 2015 reference case.

Historical natural gas prices are based on data from Statistics Canada, and future prices are forecast according to the world natural gas price from the National Energy Board’s projection for the Henry Hub prices and adjusted regionally through consultation with stakeholders.

Table 7: Electricity fuel prices (dollars per MMBtu)

		Alberta	Saskatchewan	New Brunswick	Nova Scotia
2020	Coal	1.07	1.88	2.97	3.58
	Natural Gas	3.13	4.23	8.30	8.30
2030	Coal	1.23	2.05	3.14	3.75
	Natural Gas	3.85	4.60	8.32	8.32
2040	Coal	1.39	2.20	3.29	3.90
	Natural Gas	4.20	4.95	8.60	8.60
2050	Coal	1.39	2.20	3.29	3.90
	Natural Gas	4.20	4.95	8.60	8.60

Welfare loss from reduced electricity use

In 2016, Canadians consumed 577.1 TWh of electricity from utility generators.^{footnote 34} In the baseline scenario, domestic demand for electricity from utility generators is expected to increase to 602.3 TWh by 2040. In the policy scenario, electricity demand in 2040 will be 150 GWh lower than the baseline scenario.

Since, in most cases, compliance costs will be passed on to consumers, retail prices will be higher in the policy scenario relative to the baseline scenario. In response to higher prices, consumers will shift behaviour toward lower electricity-dependent activities or more efficient technologies. The quantified impact of the cost of reduced electricity-dependent behaviour is calculated as the change in domestic electricity consumption multiplied by the retail electricity prices in the policy scenario. This is a measure of how much consumers in the policy scenario will need to be compensated to use the same level of electricity as in the baseline scenario. In terms of welfare loss, this is similar to compensating variation. This measure may overstate the true welfare cost since it does not account for the welfare gained from the substitution toward lower electricity-dependent activities. As shown in Table 8, the value of the loss in welfare will be approximately $200 million.

Table 8: Incremental electricity welfare cost (millions of dollars, discounted to 2017 using a 3% discount rate)

	2019–2025	2026–2030	2031–2035	2036–2040	2041–2045	2046–2050	2051–2055	Total
Alberta	0	−1	14	3	0	0	0	16
Saskatchewan	0	0	12	17	7	0	0	36
New Brunswick	0	0	2	5	3	0	0	11
Nova Scotia	0	0	31	36	32	28	10	137
Rest of Canada	0	0	0	0	0	0	0	0
Total	0	−2	59	62	42	28	10	200

Government costs

There will be negligible incremental government costs associated with the administration, compliance promotion, and enforcement of the Amendments. Costs to government from the Regulations were identified in the 2012 Regulatory Impact Analysis Statement (RIAS).^{footnote 35} A minimal and reactive compliance promotion approach will be adopted by the Department within the first year after the publication of the Amendments. This will include posting information on the Government of Canada’s website, including the amended Regulations, this RIAS, frequently asked questions, and answers to information or clarification requests.

Summary of benefits and costs

Table 9: Summary of impacts (millions of dollars, discounted to 2017 using a 3% discount rate)

Quantified impacts	2019–2025	2026–2030	2031–2035	2036–2040	2041–2045	2046–2050	2051–2055	Total
Benefits
Avoided GHG damage	0	503	1,156	1,034	578	102	20	3,392
Air quality improvement	0	450	416	256	120	17	5	1,263
Total Benefits	0	952	1,572	1,290	698	119	24	4,655
Costs
Capital costs	−40	1,110	−419	−181	−553	−142	−79	−305
Electricity supply costs	0	406	824	661	290	−32	−76	2,073
Reduced electricity use	0	−2	59	62	42	28	10	200
Total costs	−40	1,515	464	543	−221	−146	−146	1,968
Net benefits	40	−562	1,108	747	919	265	170	2,687
Other quantified metrics
Reduction in GHG emissions (Mt CO2e)	0	13	31	29	17	3	1	94
Reduction in NOx emissions (kt)	0	37	73	56	34	5	1	206
Reduction in SOx emissions (kt)	0	90	223	150	75	13	5	555

The anticipated cumulative GHG emission reductions of about 94 Mt CO₂e will be achieved at an estimated cost of $2.0 billion, or $21 per tonne of CO₂e from 2019–2055, as shown in Table 10.

The Amendments are expected to reduce GHG emissions by 12.8 Mt CO₂e in 2030. To achieve these GHG emission reductions, it is expected that compliance costs of $874 million will be incurred, or $69 per tonne of CO₂e. This cost per tonne measure is skewed by high upfront costs, while the avoided costs are accrued in the following years.

Table 10: Cost per tonne of GHG emission reductions

	Costs (millions of dollars)	GHG emission reductions (Mt CO2e)	Cost per tonne
2019–2055	1,968	93.8	20.97
In 2030	874	12.8	68.55

Distributional impact analysis

The Maritime provinces will be most affected by the Amendments, with about three quarters of compliance costs (incremental costs excluding cost savings in the rest of Canada) occurring in Nova Scotia and New Brunswick. The majority of this cost will come from the increased cost to supply their customers with electricity, either through higher fuel costs or by purchasing power from another region. Table 11 shows the cost breakdown by province, as well as the share of total compliance cost.

Table 11: Distribution of compliance costs (millions of dollars, discounted to 2017 using a 3% discount rate)

	Capital cost	Supply costs	Welfare loss from reduced use	Total cost	Share of total compliance cost
Alberta	−69	338	16	285	12%
Saskatchewan	10	309	36	356	15%
New Brunswick	−171	996	11	835	36%
Nova Scotia	−79	807	137	865	37%
Rest of Canada	4	−377	0	−373	—
Total	−305	2,073	200	1,968	100%

Total compliance cost is the sum of incremental costs for Alberta, Saskatchewan, New Brunswick and Nova Scotia excluding cost savings in the rest of Canada.

Competitiveness impact

As discussed above, the Amendments will increase generation costs. These costs could be recovered through price increases, although these will have to be approved either by the Provincial Cabinet in Saskatchewan, or by electricity regulators for New Brunswick and Nova Scotia.

Alberta is not expected to be significantly affected by the federal policy since a coal phase out is already planned for 2030 as part of the province’s Climate Leadership Plan. The Amendments require coal-fired units to shut down one year earlier (by December 31, 2029), but the effects are expected to be minimal in Alberta since business decisions will be largely attributable to the provincial policy.

Residential retail price impacts

The Amendments could affect residential electricity consumers with a limited ability to accommodate higher electricity retail prices. As shown in Table 12, residential electricity prices could be up to 5% higher in affected provinces in the policy scenario compared to the baseline scenario. Based on 2016 prices, ^{footnote 36} such an increase will add up to $100 ^{footnote 37} to the average annual electricity bill, with the highest increase in Nova Scotia.

Table 12: Residential retail price impacts of the Amendments

	Estimated average monthly electricity bill (in 2016 $)	Highest percentage increase in policy scenario relative to baseline scenario (%)	Estimated annual increase in electricity spending ($)
Calgary, Alberta	104.00	4.1	51.03
Regina, Saskatchewan	146.45	1.1	19.38
Moncton, New Brunswick	124.98	1.4	21.64
Halifax, Nova Scotia	158.83	5.2	100.05

The estimated increase in electricity spending is presented in annual terms, as the period in which the Amendments are expected to impact on the expenditure varies by province.

Impacts on Canada’s interprovincial and international electricity trade

Canadian electricity exports are primarily from provinces with large amounts of low-cost, non-emitting electricity generation. For example, Quebec, Manitoba, and British Columbia — provinces that almost exclusively generate hydroelectricity — accounted for roughly two thirds of Canadian exports in 2016. Ontario accounted for approximately 28% of Canadian exports and has no coal-fired electricity generation. While Canadian and American electricity markets are integrated to some extent, limits on transmission systems between the two countries will moderate the impacts on trade flows between the two countries.

The Amendments will not impose any barriers for Canadian exports of electricity to the United States. However, the quantity of Canadian electricity surplus available to be exported could be affected. If provinces affected by the federal Amendments respond to lost capacity by purchasing electricity from other provinces, this may result in fewer exports to the United States. According to the Department’s modelling, the Amendments will cause an average of 5% of projected Canadian electricity exports destined for the United States to be redirected to provinces that have phased out coal-fired generation capacity annually between 2030 and 2044.

Market forces, tax incentives, United States state-level environmental policies and technology development will be more important determinants of electricity trade balance between Canada and the United States going forward, as these factors will dictate the long-term development of electricity generation in the United States.

Competitiveness of electricity intensive industries

Electricity price impacts induced by the Amendments could reduce the competitive position of certain manufacturing and extractive industries in the four provinces that will be affected by the policy. The cost exposure of sectors will vary, but will generally be influenced by the intensity of electricity use of the firms’ operations. Electricity-intensive sectors operating in these provinces include pulp, paper and paperboard mills; industrial gas manufacturing; pesticide and fertilizer manufacturing; and potash mining.

While costs for these sectors could increase as a result of electricity price increases, any impacts on the competitiveness position could be mitigated through a number of ways. For example, price increases could be passed on to consumers for firms that have sufficient market power. In addition, provincial utilities may have some discretion in the degree of electricity price increases faced by large electricity consumers. Meanwhile, electricity price impacts are expected to be reduced for industrial facilities that generate electricity on-site, which is currently the case, for example, at some pulp and paper and potash facilities in affected provinces. For context, it should be noted that other factors have a greater influence on the competitive environment faced by industry, including labour and capital costs, proximity to market, tax treatment, exchange rates, infrastructure, and rule of law.^{footnote 38}

Labour market considerations

Three sectors could experience direct labour market impacts from Amendments: coal mining; coal-fired electricity generation; and the coal transportation sector, including ports and railways.

In 2016, between 2 000 and 3 500 people were directly employed in the Canadian thermal coal mining sector, with mines located in British Columbia, Alberta, Saskatchewan and Nova Scotia. The sector’s labour force represents up to 0.02% of Canadian employment. ^{footnote 39, footnote 40} Employment in the Canadian coal mining sector, which includes employment in both thermal coal and metallurgical coal mines, has declined since 2013, concurrent with a 12% decrease in coal production between 2013 and 2016.^{footnote 41} The prospect of increasing exports of Canadian thermal coal is weak. In 2017, Westmoreland’s Coal Valley Mine was the only Canadian thermal coal mine exporting its product. ^{footnote 42} European markets are shrinking and are already being supplied by countries with lower production costs, while growth markets in Asia are expected to be supplied by their own domestic production as well as cost-competitive Indonesian, Russian and Australian exports. Consequently, Canadian thermal coal exports are unlikely to increase and most Canadian thermal coal mines that supply domestic consumption are not expected to continue to operate after the Amendments come into effect.

In 2016, up to 1 500 workers were directly employed at coal-fired electricity plants that will be affected by the Amendments.^{footnote 43} Many of these jobs could be at risk as a result of the Amendments. However, employment impacts in the utility sector are expected to be mitigated by the construction or conversion and operation of new generating capacity. For example, recently announced conversions of coal units to natural gas in Alberta will allow them to extend their operating lives beyond regulatory phase-out dates. To put the above-mentioned employment figures into context, the Canadian labour market’s average quarterly change has been more or less 61 300 jobs between the second quarter of 2007 and the first quarter of 2017. ^{footnote 44} Employment transitions for thermal coal mines and coal-fired electricity plants will occur gradually as operations are closed over time.

Employment estimates associated with transporting coal are not available. However, Canadian rail transportation is not expected to be significantly affected by the policy. In 2015, coal represented 13% of total tonnage shipped by rail in Canada. However, 87% of coal-by-rail shipments originated in British Columbia, which produces mostly metallurgical coal used for steel production that is not expected to be affected by the Amendments. Nearly 13% of coal-by-rail shipments originated in Alberta, virtually all of which were destined for British Columbia. Since British Columbia does not have coal-fired electricity generation, any thermal coal that is shipped from Alberta to British Columbia is likely exported, and is likely to be unaffected by the Amendments.

For provinces that import thermal coal, namely Nova Scotia and New Brunswick, the Amendments will eliminate demand for such imports, resulting in a decrease in traffic at domestic ports and reduced railway use. These ports and associated railways are relatively more vulnerable to changes in coal traffic than those of Canada’s Pacific Coast. While coal accounts for an important share of their current economic activity, a significant portion of tonnage flowing through these ports is not coal. Therefore, it is unlikely that these ports will cease operations, though employment and revenue could be affected, as they transition their operations and adjust to the new business environment over time.

Community-level impacts

Many of the jobs associated with coal-fired electricity generation are concentrated in small communities, and the economic effects for these communities could be significant given low coal prices and an unfavourable outlook for coal markets. As a result of the Amendments, most thermal coal mines currently in operation in Canada are not anticipated to operate past 2030 and some are expected to shut down before then. While aggregate employment effects caused by these closures are expected to be relatively small and often transitional as local labour markets adjust, layoffs could be concentrated in small communities that are heavily dependent on the coal mining and/or electricity generation industry and therefore have significant effects in such communities.

To ensure a just and fair transition to support Canadian workers, Canada has launched a task force, including labour and business, to hear from workers and communities. The Government of Canada is working with the Government of Alberta on a one-window approach to address the needs of workers. For example, with training and re-employment transition support, workforce adjustment programs, layoff prevention through the Work Sharing Program, and immediate assistance to displaced workers through employment insurance.

Uncertainty of impact estimates

Any model attempting to forecast the behaviour of millions of individuals over multiple decades is subject to uncertainty. A sensitivity analysis was conducted by changing one variable at a time while holding other variables constant to examine the risks and uncertainty of key parameters for the analysis. As shown in Table 13, altering the discount rate, increasing capital costs, and using the 95th percentile value for the social cost of greenhouse gases does not alter the overall conclusion that the impact of the Amendments is a net benefit to Canadians.

Table 13: Summary of key parameters used in the analysis (millions of dollars, discounted to 2017 using a 3% discount rate)

	Benefit	Cost	Net benefits	Benefit/Cost ratio
Central analysis	4,655	1,968	2,687	2.4
Discount rate 7%	2,333	1,214	1,119	1.9
Discount rate 0%	8,142	2,687	5,455	3.0
Capital costs 20% higher	4,655	1,997	2,659	2.3
Capital costs 50% higher	4,655	2,039	2,616	2.3
Capital costs 100% higher	4,655	2,110	2,545	2.2
Social cost of carbon (SCC) 95th percentile	15,986	1,968	14,018	8.1

Fuel price

The price of fuel is one of the main factors in determining the impact of the Amendments. Table 14 shows the estimated total cost of the Amendments with coal and natural gas prices 20% higher or lower than forecast.

Table 14: Fuel price sensitivity

TOTAL COST
Estimated average coal and natural gas prices (2020–2050)		Natural gas price
		−20%	Central ($6.37/MMBtu)	+20%
Coal price	+20%	597	1,478	2,359
	Central ($2.58/MMBtu)	1,087	1,968	2,849
	−20%	1,577	2,458	3,339

The bottom, right-hand cell of Table 14 shows the high incremental cost scenario where coal prices are 20% lower than expected and natural gas prices are 20% higher than expected. In this scenario, the total cost of the Amendments is nearly $3.2 billion. Since the benefits will not change, the net benefit will remain positive. In order for a deviation in fuel prices to lead to a negative net benefit, coal will have to be about 43% lower, and natural gas about 43% higher, than forecast. This scenario will result in a total cost of slightly higher than $4.7 billion.

Coal-to-natural-gas conversions

As stated above, some electricity firms in Alberta have indicated their intention to convert six coal-fired units to run on natural gas between 2020 and 2022. An electricity generating unit converted to run on natural gas will emit less CO₂ than when it ran on coal. According to the Department’s modelling, the six confirmed conversions will lower Alberta’s GHG emissions due to the Amendments by about 3 Mt CO₂e than without those conversions, over the analytical period. There will also be an increase in fuel costs and a decrease in the cost for commissioning replacement generating capacity as the converted units, which are less efficient, will replace the need for building new natural gas generating units when coal-fired plants shut down early due to the Amendments. It should be noted that the complete impact of coal-to-gas conversions is not known as more conversions of coal-fired plants could be announced after the Amendments come into effect.

Global GHG emission changes

Accounting for global GHG emission changes can have implications on the estimated climate change benefits of the Amendments. For simplicity, the central case of cost-benefit analysis includes only the domestic GHG emission changes. However, there is a possibility that increases in electricity imports from the United States due to the Amendments will contribute to global GHG emissions. Assuming various electricity generation mixes and emission intensities, the higher electricity imports from the United States are estimated to increase global GHG emissions by 13.9 Mt CO₂e cumulatively over the analytical period, which translates to climate change damages of about $500 million ($0.5 billion). This could reduce the net benefits of the Amendments from $2.7 billion to $2.2 billion. Thus, accounting for global GHG emission changes does not alter the overall conclusion that the impact of the Amendments is a net benefit to Canadians.

“One-for-One” Rule

The Amendments will not change the reporting requirements; therefore, there is no new incremental burden. The “One-for-One” Rule therefore does not apply. As a result, there is no requirement to remove an existing regulation.

Small business lens

The small business lens does not apply to this proposal, as none of the businesses that will be covered by the Amendments are small businesses. The Amendments will therefore produce no costs for small businesses.

Consultation

The Department of Environment (the Department) developed the Amendments in consultation with Indigenous organizations, environmental non-governmental organizations, industry and related professional associations, and provinces and territories. On December 17, 2016, the Notice of intent to develop greenhouse gas regulations for electricity generation in Canada (the Notice) was published in the Canada Gazette, Part I, for a 60-day public comment period. The Notice advised of the intent of the Government to amend the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations published on September 12, 2012, and to develop regulatory requirements for natural gas-fired electricity generation. During the 60-day public comment period, 8 comments were received on the Amendments from stakeholders. The Department addressed these comments in the consultation section of the Regulatory Impact Analysis Statement published with the proposed Regulations Amending the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations in the Canada Gazette, Part I, on February 17, 2018.

The Amendments were also subject to a 60-day public comment period. The Department received 22 comments from stakeholders including provinces, utilities, non-governmental organizations and industrial associations, on the policy objective, equivalency agreements, reporting requirements, overlapping policies and initiatives, and cost benefit analysis. Below is a summary of these comments and the responses by the Government.

Policy objective

One industry stakeholder suggested that the Amendments should align the timing of the federal phase-out of conventional coal (end of 2029) with Alberta’s phase-out (end of 2030). This stakeholder suggested that the federal phase-out date conflicts with the agreements between the Government of Alberta and provincial coal operators, which included transition payments to the companies under the Climate Leadership Plan. In addition, a province indicated that the Regulations require more flexible timelines to phase out coal and transition to renewable electricity alternatives. They proposed delaying the coal phase-out by a decade to allow enough time to deploy feasible and least-cost alternatives such as nuclear or hydro. However, the requests to delay the Amendments by either one year or a decade were not considered, as this will make it difficult for Canada to meet its GHG emission reduction targets. Accelerated coal phase-out is one of the mechanisms being used by the Government of Canada to meet its 2030 national and international targets of GHG reductions under the Paris Agreement. The Department also clarified that provinces may replace their phased-out coal-fired generation by selecting the generation options that best suits their circumstances. These may include, but are not limited to, importing electricity from neighbouring jurisdictions, building new natural gas plants, converting coal plants to operate on natural gas, building new wind capacity and other renewable energy sources, and pursuing equivalency agreements.

An environmental NGO stakeholder suggested that additional measures are required to ensure that a significant portion of retired coal-fired electricity is either replaced with renewable sources of electricity or energy storage capacity, or that replacement generation is not required due to reduced overall demand with increased efficiency and demand-side management. The Department noted that the Pan-Canadian Framework is being used to implement additional measures, such as carbon pricing, beyond these Amendments to reduce GHG emissions. In addition, there are other federal programs aimed at supporting storage, efficiency, and energy demand management.

Equivalency agreements

Multiple health and environmental NGOs proposed that any current or future equivalency agreements related to the amended regulations also consider air pollutants (such as mercury, sulphur dioxide, nitrogen oxides and fine particulate matter) in addition to GHGs. They also suggested that current or future equivalency agreements should not facilitate a transition to natural gas-fired electricity generation. Instead, they recommended requiring a transition that incorporates a majority generation mix of renewables (e.g. 70%) with a minority of natural gas-fired generation (e.g. 30%). Additionally, the NGOs recommended that the process to develop and implement equivalency agreements be made more transparent for all stakeholders and that a periodic review of such agreements be completed midway in their implementation. One environmental NGO noted that equivalency agreements, in general, can weaken the intended outcomes of regulations. These comments will be taken into account during the development of equivalency agreements.

The Department noted that the purpose of equivalency agreements is to avoid duplication among the various orders of government and to enable the best-positioned jurisdiction to ensure the highest environmental quality for Canadians. These agreements are important instruments for enabling the federal and provincial/territorial governments to work together effectively and efficiently to achieve broad environmental protection goals. These agreements are negotiated on a regulation-by-regulation basis and the Department cannot comment on ongoing or future negotiations. However, before every equivalency agreement comes into force, the Government provides a 60-day comment period during which any person may file comments or a notice of objection. The Minister will provide a report to the public on these submissions at the end of the 60 days.

Reporting requirements

One environmental NGO commented that all reported data (e.g. emissions of GHGs) should be made publicly available at the unit-level. The Department noted that reported compliance data is not available to the public. However, the federal GHG Reporting Program (GHGRP) and the National Pollutant Release Inventory (NPRI) are updating their reporting requirements to provide for unit-level data.

Overlapping policies and initiatives

One of the issues arising from the Department’s engagement with industry stakeholders was a concern that federal climate change policies affecting the electricity sector, including the accelerated coal phase-out, the clean fuel standard, and the output-based carbon pricing system, were being developed at a challenging pace and were overlapping each other. The Department established The Multi-Stakeholder Committee on GHG Regulatory Measures and Programs to serve as a forum for stakeholders to identify issues of interest or concern and share views on the interactions (synergistic and overlapping) among climate change programs and regulations, as well as on the cumulative GHG and economic impacts.

Cost-benefit analysis

Two provinces and two industry stakeholders claimed that the costs of the Regulations are underestimated in select provinces. This includes costs for operations and fuel, capital, and infrastructure. They stated that depreciation cycles for bridging/interim assets will be compressed, which will lead to higher incremental rates for ratepayers in the province. They also noted that the analysis may underestimate the cost of liquid natural gas and fuel transmission (pipeline) requirements, as well as the effects of extreme weather. An environmental NGO proposed that the cost-benefit analysis should consider increased utilization/development of renewables, provincial interconnections (interties) and hydro imports for some provinces instead of assuming new natural gas infrastructure.

The Department worked with stakeholders to incorporate their comments, where backed by suitable evidence. This included updating many cost assumptions including gas price forecasts, and the costs of refurbishment, maintenance and depreciation. The Department also updated provincial electricity generation mixes and distributions, in collaboration with provincial stakeholders. The Department notes that the pathway selected by its model to phase out coal-fired electricity is not meant to represent the only pathway available. Rather, the model selects the lowest cost pathway, given the model inputs, to meet the predicted future demand.

One industry stakeholder commented that the Amendments (as shown in the analysis) will have a significant impact on ratepayers in the province. The stakeholder requested additional information to better understand consumer-level impacts upon households and businesses in their jurisdiction. The Department followed up with this stakeholder to provide a more detailed breakdown of impacts. The stakeholder also commented that if their province opts to import electricity from a neighbouring province, that this could be viewed as a “wealth transfer” from one jurisdiction to another, without any ability to return these costs to the economy of origin. Therefore, they emphasized the importance of fully understanding the impacts of the Amendments and the possible unintended consequences. As well, the stakeholder stated that such imports from outside Canada may result in higher GHG emissions, if such generation is fired by fossil fuels. The Department clarified that the central case of cost-benefit analysis only captures the reductions of GHG emissions from domestic sources. Due to uncertainty associated with electricity generation mixes and emission intensities from outside Canada, the possible GHG emission impacts occurring in other jurisdictions are presented in the sensitivity analysis section (i.e. the section on uncertainty of impact estimates).

Regulatory cooperation

Canada’s approach to phasing out conventional coal-fired electricity generation was developed in coordination with provincial and territorial governments, industry, and Indigenous peoples and is a key commitment of the Pan-Canadian Framework. The Pan-Canadian Framework was adopted on December 9, 2016, by first ministers (except Saskatchewan). The Pan-Canadian Framework builds on the efforts of provincial and territorial governments to reduce GHG emissions and it identifies opportunities for further reductions.

The Government of Canada is working with the provinces to accelerate the transition to clean electricity. Potential transmission intertie projects will be identified through the Regional Electricity Cooperation and Strategic Infrastructure (RECSI) Program. The federal government has also made significant investments in clean growth, such as federal funding for projects under the $21.9 billion Green Infrastructure Fund as well as the Canada Infrastructure Bank.

Provincial equivalency agreements may be considered to support provincial transitions from coal towards non-emitting sources of electricity. Equivalency agreements provide flexibility to provinces, where there is an enforceable provincial regime that achieves an equivalent or better environmental outcome than the relevant federal regulation. When an equivalency agreement is in place with a province, the federal government may make an order declaring that its regulations in relation to which the equivalency agreement was signed do not apply in that province.

In December 2014, the Department and the Government of Nova Scotia finalized an equivalency agreement for the existing Regulations published in 2012 with the publication of an order in council in the Canada Gazette, Part II.

In November 2016, both governments announced an agreement in principle for a new equivalency on the Amendments in order to help Nova Scotia move directly from coal-fired electricity to renewable sources like wind and hydro. Similarly, in November 2016, the Province of Saskatchewan and the Government of Canada announced an agreement in principle regarding equivalency for the existing Regulations published in 2012 and covering the period from 2015 to 2029.

Regarding regulatory cooperation with the United States, the Canadian government moved ahead of the United States in regulating GHGs from the electricity sector with the existing Regulations published in 2012. Canada is now proposing to accelerate the phase-out of conventional coal-fired electricity by 2030, which will contribute to achieving Canadian commitments under the Paris Agreement. Trade exposure in the electricity sector is mitigated by capacity limits on transmission systems, with the result that most electricity is consumed in the same province in which it is generated. In addition, the generation mix and overall regulatory and market structure of the United States electricity sector is significantly different. Canada’s electricity generation mix has a significantly higher proportion of non-emitting generation (approximately 80%) compared to the United States, which relies on coal-fired electricity for approximately one third of total generation.

The United State’s approach, established under the Obama administration, included New Source Performance Standards for GHG emissions from electricity generating units, as well as the Clean Power Plan (CPP), which covered existing fossil fuel-fired generating stations. The intent of the United States’s approach was to reduce emissions from electricity generation, without specifically requiring the phase-out of coal-fired electricity. Differences in Canadian and United States performance standards for coal-fired electricity reflect these key differences in policy intent.

On October 10, 2017, the United States Environmental Protection Agency (EPA) published a Notice of Rulemaking proposing to repeal the CPP. The proposal to repeal complied with the United States President’s March 2017 Executive Order on Energy Independence, which directed federal agencies to reduce regulatory barriers to energy production. The EPA published the draft “Affordable Clean Energy” (ACE) rule on August 21, 2018, for a 60-day public comment period. The draft rule is intended to replace the CPP. The draft ACE rule would require states to develop and submit plans requiring modest on-site efficiency improvements at individual coal plants.

Despite United States’s actions at the federal level, market forces and state-level climate change policies are expected to continue driving a decrease in coal use in the United States’s power sector. Coal provided 30% of United States’s electricity generation in 2016, down from 48%, compared to 2008. As a result, carbon emissions from the United States power sector have declined by 24% since 2005. However, the Energy Information Administration predicts that repealing the Clean Power Plan could slow the rate at which existing coal-fired plants are retired. The EPA’s proposal to repeal is not expected to have significant implications for Canada’s climate change action or Canada’s ongoing role as a key supplier of clean electricity to the United States.

As Canada moves ahead with these Amendments aimed at phasing-out conventional coal-fired electricity by 2030, the international community is taking similar action.

In November 2017, the Government of Canada partnered with the Government of the United Kingdom to launch the Powering Past Coal Alliance, a global alliance which now has 74 members, including 28 national governments, 18 sub-national governments and 28 businesses or organizations, to phase out coal-fired electricity. ^{footnote 45}

Rationale

The Amendments will require coal units to meet a stringent performance standard in 2030, and will contribute to phasing out conventional coal-fired electricity and ensuring the permanent transition from high-emitting electricity sources to low- or non-emitting sources.

This will contribute to the protection of the environment and the health of Canadians, and help Canada fulfill its commitment to reduce GHG emissions by 30% below 2005 levels by 2030.

While existing and planned carbon pricing systems implemented by provincial and federal governments could reduce emissions from coal-fired electricity generation, the complete phase-out of conventional coal-fired electricity generation by 2030 is unlikely to occur without the Amendments.

The Department is open to considering equivalency agreements with interested provinces and territories to minimize regulatory duplication in support of the provinces’ transition to non-emitting electricity generation.

The Government of Canada’s approach to addressing climate change is based on the principle of maximizing environmental performance improvements while minimizing adverse economic impacts. The regulated performance standard approach provides necessary regulatory certainty for the electricity sector at a time when the sector is facing major capital stock turnover. As an update to an existing regulation, it is administratively simple, ensures the phase-in of lower- or non-emitting types of generation and it provides more certain economic signals to decision makers considering new or replacement power generation plants. In addition, through consultation, industry and provincial stakeholders, in spite of having specific concerns, have expressed broad support of the regulated performance standard approach. The Government considered all concerns raised during the consultation process and adjusted the Amendments, as appropriate.

A cost-benefit analysis was conducted for the Amendments, which indicated that it will result in a net reduction of approximately 94 Mt CO₂e of GHG emissions between 2029 and 2055. The incremental benefit of achieving these reductions is estimated to be $4.7 billion, while the incremental cost is estimated to be $2.0 billion over the same period. This results in a net present value of approximately $2.7 billion.

Strategic environmental assessment

The Regulations have been developed under the Pan-Canadian Framework on Clean Growth and Climate Change. A Strategic Environmental Assessment (SEA) was completed for this framework in 2016. The SEA concluded that proposals under the framework will reduce GHG emissions and are in line with the 2016–2019 Federal Sustainable Development Strategy. The Regulations are an important part of the Strategy and align with the clean energy goals for Canadians to have access to affordable, reliable and sustainable energy. ^{footnote 46}

Implementation, enforcement and service standards

Implementation strategy

Minimal compliance promotion activities are anticipated to be required as a result of the Amendments. Implementation activities will be minimal since the Amendments apply only to large enterprises and will not create any new requirements before the end of 2029. The units affected by the provisions of the Amendments will be those that have not reached their end of useful life by 2030, as defined by the Regulations.

Implementation activities may include adding or updating information on related departmental websites (responding to requests for information and clarification); reviewing information submitted for units that have their end of useful life before 2030; and sending reminder notifications in advance of the 2029 deadline and subsequent reporting requirements, as appropriate. Preliminary assessments of compliance with the Amendments will be carried out through the review and analysis of reports submitted, and may require a follow-up with regulatees, as appropriate.

Enforcement

Where the Department does not receive the prescribed information and/or there is a need to verify or correct such information, enforcement action may be required. The Regulations are adopted under CEPA, so enforcement officers will, when verifying compliance with the Amendments, apply the Compliance and Enforcement Policy (the Policy) for CEPA. This policy sets out the range of possible responses to alleged violations, including warnings, directions, environmental protection compliance orders, tickets, ministerial orders, injunctions, prosecution and environmental protection alternative measures (which are an alternative to a court prosecution after the laying of charges for a CEPA violation). In addition, the Policy explains when the Department will resort to civil suits by the Crown for cost recovery.

To verify compliance, enforcement officers may carry out an inspection to identify an alleged violation. Alleged violations may also be identified by the Department’s technical personnel, through information transmitted to the Department by other government organizations, including Statistics Canada and the Canada Border Services Agency, or through information received from the public. Whenever a possible violation of the amended Regulations is identified, enforcement officers may carry out investigations.

When, following an inspection or an investigation, an enforcement officer discovers an alleged violation, the officer will choose the appropriate enforcement action based on the following:

• Nature of the alleged violation: This includes consideration of the damage, the intent of the alleged violator, whether it is a repeat violation, and whether an attempt has been made to conceal information or otherwise subvert the objectives and requirements of CEPA;
• Effectiveness in achieving the desired result with the alleged violator: The desired result is compliance within the shortest possible time and with no further repetition of the violation. Factors to be considered include the violator’s history of compliance with CEPA, the violator’s willingness to cooperate with enforcement officers, and evidence of corrective action already taken; and
• Consistency: Enforcement officers will consider how similar situations have been handled in determining the measures to be taken to enforce CEPA.

Performance measurement and evaluation

The implementation strategy for the Amendments includes a section on performance measurement. This identifies the desired outcomes of the Amendments and includes indicators to assess the performance of the amended Regulations in achieving these outcomes. Performance of the amended Regulations will be monitored annually and reported on a five-year basis and/or as appropriate.

Performance indicator outcomes for the amended Regulations include the following:

• Regulatees are aware of the requirements under the Regulations;
• Regulatees understand the requirements of the Regulations;
• Regulatees comply with the regulatory requirements;
• Non-compliant regulatees become compliant with the regulations;
• Reduction of CO₂ emissions from the sector versus the baseline scenario; and
• Provinces with related Equivalency Agreements meet the requirements of those agreements.

The outcomes, such as anticipated reductions in CO₂ emissions, will take place progressively and accumulate over time.

Performance indicators and evaluation

The expected outcomes of the Amendments support the international and domestic priorities of reducing national GHG emissions, e.g. a 30% reduction from the 2005 levels by 2030. The performance of the Amendments in achieving these outcomes will be measured and evaluated.

Clear, quantitative indicators and targets, where applicable, were defined for each outcome — immediate, intermediate and final — and will be monitored annually. For example, one indicator is reduced sectoral CO₂ emissions versus emissions found in the baseline scenario. In addition, a compilation assessment will be conducted every five years starting in 2025 (for the period 2020–2025) to gauge the performance of every indicator against the identified targets. This regular review process will allow the Department to clearly detail the impact of the Amendments as units become subject to the regulatory requirements, and to evaluate the regulatory performance in reaching the intended targets. The five-year compilation review also respects the expected capital stock turnover timelines for this industry.

Contacts

Paola Mellow
Director
Electricity and Combustion Division
Energy and Transportation Directorate
Environment and Climate Change Canada
Email: ec.electricite-electricity.ec@canada.ca

Matt Watkinson
Director
Regulatory Analysis and Valuation Division
Economic Analysis Directorate
Environment and Climate Change Canada
Email: ec.darv-ravd.ec@canada.ca