Vol. 152, No. 7 — February 17, 2018

Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity

Statutory authority

Canadian Environmental Protection Act, 1999

Sponsoring departments

Department of the Environment
Department of Health

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the regulations.)

Issues

Significant investments in the electricity sector will be required as it phases out the use of coal to generate electricity in Canada. The investment decisions required to build electricity generation capacity are complex and involve analyses of several factors such as forecasts of energy/ capacity demand and market pricing/constraints, as well as economic comparisons (e.g. operating cost and opportunity cost (see footnote 1) of electricity generation alternatives). Clarity on regulatory requirements that may affect the sector is needed to help create a stable investment climate and incentivize sufficient investment in a new efficient electricity generation capacity.

Under the authority of the Canadian Environmental Protection Act, 1999 (CEPA), the Government of Canada (the Government) is proposing the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity (the proposed Regulations), which set clear performance standards to control carbon dioxide (CO2) emissions for new and significantly modified natural gas-fired electricity generation units in Canada.

Background

The Government is committed to reducing greenhouse gas (GHG) emissions (see footnote 2) to mitigate the impact of climate change. In 2016, Canada ratified the Paris Agreement, (see footnote 3) committing to a 30% reduction in overall GHG emissions below 2005 levels by 2030. In the same year, First Ministers from federal, provincial, and territorial governments released the Pan-Canadian Framework on Clean Growth and Climate Change, (see footnote 4) which includes a commitment to expand clean electricity sources, supported by infrastructure investments and regulations for coal and natural gas-fired electricity generation.

The Department of the Environment (the Department) published a notice of intent (NOI) in the Canada Gazette, Part I, (see footnote 5) on December 17, 2016, that communicated its intent to accelerate the phase-out of coal-fired electricity generation in Canada from 2044 to 2030 (see footnote 6) by amending the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations. (see footnote 7) This would be achieved by an amendment to existing regulations that would require coal-fired electricity generation units to meet an emissions limit of 420 tonnes of CO2 per gigawatt hour (420 t of CO2/GWh) (see footnote 8) of electricity produced by no later than 2030. The proposal to amend the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations and the proposed Regulations are being developed in parallel in order to ensure that the new electricity generation capacity built to replace coal units meets achievable performance standards.

Electricity generation in Canada

The generation, transmission and distribution of electricity in Canada are regulated primarily under provincial jurisdiction. Provincial governments exercise their jurisdiction through provincial departments of energy who regulate Crown utilities, and in some provinces through independent system operators who manage privately owned electricity-producing companies that operate within deregulated electricity markets. Some large industrial electricity users, such as oil and gas producers and aluminum manufacturers, have electricity generation facilities that meet their own electricity requirements. The federal government has a supporting role, including by investing in research and development and by supporting the commercialization of new technologies. In addition, the federal government has the authority under CEPA to regulate emissions of carbon dioxide. (see footnote 9)

The Canadian electricity sector is composed of utility and non-utility generators that produce electricity. (see footnote 10) In 2015, utilities in Canada generated approximately 580 terawatt hours (TWh) of electricity. It is estimated that by 2035, in a business-as-usual scenario, electric utility generation will be 634 TWh. (see footnote 11) In 2015, about 80% of the electricity generated was from sources that do not emit GHG emissions (e.g. nuclear, wind and hydro) and 20% was from sources that do (e.g. coal-fired and natural gas-fired). It is estimated that by 2035, in a business-as-usual scenario, about 82% of the electricity generated would be from non-emitting sources, with 18% from emitting sources in Canada.

In 2015, about 19% of Canada’s overall GHG emissions from the electricity sector came from natural gas-fired electricity generation. (see footnote 12) Due in large part to the phase-out of the use of coal to generate electricity in Canada, it is estimated that by 2035, in a business-as-usual scenario, that portion would rise to about 74%. However, GHG emissions are expected, in a business-as-usual scenario, to decrease from the electricity sector as a whole, from about 79 megatonnes (Mt) (see footnote 13) in 2015 to 33 Mt estimated in 2035, which is about a 46% decrease.

The Government of Canada has an aspirational goal of 90% of non-emitting electricity generation by 2030, and to help get there, it is accelerating the phase-out of coal-fired electricity by 2030, as well as investing in green infrastructure and research and development of clean energy technology. Canada is part of a global trend towards increased renewable electricity generation. According to Bloomberg New Energy Finance, renewable energy sources are set to represent almost three quarters of the $10.2 trillion the world will invest in new power generating technology until 2040. In 2015, more money was invested worldwide in renewable power (US$325 billion) than in new power from fossil fuels (US$253 billion). Since 2010, in the United States, the cost of onshore wind power has fallen over 50%, and globally, solar power costs have dropped by over 70%.

Natural gas-fired electricity generation capacity

Several factors suggest that natural gas-fired power generation in Canada will increase in the future. These include low natural gas prices due to increased North American shale and tight gas production, coal plant closures, a role for quick-ramping natural gas-fired units to support the integration of renewables into the electric grid, (see footnote 14) and an overall increase in electricity demand in Canada. Further, the Canadian natural gas supply infrastructure is well developed and the natural gas-fired generation capacity can be built in smaller increments to better match demand.

Summary of natural gas-fired electricity generation technologies

Natural gas can be combusted in a gas turbine, a boiler, or a reciprocating engine to produce electricity. The number of gas turbines in Canada is expected to grow in the near future as it is generally agreed that this technology is the most cost-effective option to replace coal-fired electricity generation capacity. The number of natural-gas fired boilers has been in constant decline, mainly due to gas turbines being more efficient. There are currently no reciprocating natural gas engines in Canada that would fall under the scope of the proposed Regulations. An overview of the technologies used to generate electricity using natural gas in Canada is presented below.

Boiler units: In these units, fuel is combusted in a boiler to convert water into steam. The steam produced spins a steam turbine that drives a generator to produce electricity. Boiler units can burn a variety of fuels, including coal, petroleum coke, heavy fuel oil, natural gas, and biomass, alone or in combination.

Combustion engines: There are two different types of combustion engines that may burn natural gas to generate electricity that are considered: (1) gas turbine engines; and (2) reciprocating engines:

(1) A gas turbine is an internal combustion engine that operates with rotary, rather than reciprocating motion. Gas turbines have four major components: a compressor, a combustor, a power turbine and a generator. These units make up the large majority of power generation from natural gas. A gas turbine can be used to generate electricity either alone (single-cycle configuration), or in combination with a steam turbine (combined-cycle configuration). Combined cycle systems are significantly more energy and emission efficient than single cycle units; however, single cycle units may be required in certain operational conditions.

(2) In reciprocating engines, fuel combusts in a cylinder, driving a piston connected to a crankshaft. The crankshaft transforms the linear motion of the piston into the rotary motion of the crankshaft. For electricity generation applications, reciprocating engines are connected to generators to produce power. These units do not represent much of Canada’s power generation from natural gas.

Conversions of coal boilers to burn natural gas (coal to gas) to generate electricity as a technological option

Recent announcements by TransAlta and ATCOenergy in Alberta on moving ahead with coal-to-gas conversions suggest this is a viable option to replace coal-fired electricity generation. This option is expected to provide a short- term (5 to 10 years) transition away from coal. During this period, Alberta plans to develop and bring online new renewable sources of electricity generation (see footnote 15) (e.g. hydro, wind and solar power generation) and new natural-gas fired electricity units. The conversions

Alberta’s announced plans to move to a capacity market framework in the future provides a key framework to support the short-term economic feasibility of coal-to-gas conversions. In a capacity market, units receive a certain amount of revenue even when they are not operating in exchange for guaranteed power availability when needed. Due to the estimated future supply of natural gas in Alberta, the announced coal-to-gas conversions are also expected to provide affordable ongoing access to natural gas. These factors combine to support the economic feasibility of coal-to-gas conversions in Alberta.

While the short-term return on investment for coal-to-gas converted units is considered adequate (within 2 to 5 years after converted units come online), there is a range of technical and market considerations that suggests these units, if converted between 2020 and 2023 as per announcements, may not continue operating for long beyond 2030. The expected upgrades at conversion, and subsequent maintenance of coal-to-gas converted units, suggest that the economic life of these units would extend by 5 to 10 years, depending on the coal boiler’s efficiency and age at the time of conversion. By 2030, the Province of Alberta expects to have 30% of its electricity generated from renewable sources and new natural gas-fired electricity generation units coming online (i.e. combined cycle). The expected economic life and shape of the electricity market in Alberta suggests less efficient forms of electricity generation such as coal-to-gas conversions would likely be replaced by more efficient forms of electricity generation.

Coal-to-gas conversions in other provinces affected by the proposed Regulations (i.e. New Brunswick, Nova Scotia and Saskatchewan) have not been announced and thus are considered unlikely. Factors that may influence coal-to-gas conversions in New Brunswick and Nova Scotia include the costs associated with securing additional, ongoing and affordable access to natural gas given that a natural gas infrastructure is not yet in place. In Saskatchewan, factors that may influence conversions may include lower operating costs of alternative generation and the opportunity cost of those alternatives, such as carbon capture and storage, co-firing with biomass, and renewables. However, it is expected that if coal-to-gas conversions were to take place in these provinces, the proposed Regulations would not have a significant impact, as the performance standards would align with those generally achievable by coal-to-gas conversions.

Objectives

The objectives of the proposed Regulations limiting CO2 emissions from natural gas-fired electricity generation are to ensure new and converted natural gas-fired electricity units would be subject to achievable emission performance standards. In doing so, the proposed Regulations would provide regulatory certainty on the level of stringency associated with the performance standards. This is expected to facilitate the planning and investment decision-making process associated with an overall strategy to phase out the use of coal-fired generation and the construction of new natural gas-fired electricity generation capacity in Canada.

Description

The proposed Regulations would impose performance standards (CO2 emission intensity-based limits) on new and significantly modified natural gas-fired electricity generating units, including combustion engines and boiler units. (see footnote 18) Significantly modified units include combustion engine units burning natural gas that are retrofitted to increase capacity, and units that burned coal which are converted to burn natural gas to generate electricity.

1. Performance standards for new and significantly modified combustion engines

The performance standard for new and significantly modified combustion engine units equipped with one or more combustion engines with a capacity larger than 150 megawatts (MW) (see footnote 19) would apply on an annual average basis and be 420 t of CO2 for each gigawatt hour of energy produced. The performance standard for new and significantly modified combustion engine units equipped with engines with a capacity of 25 MW or more and of 150 MW or less would also apply on an annual average basis and be 550 t of CO2 for each gigawatt hour of energy produced.

The proposed Regulations would apply to combustion engine units (including gas turbines and reciprocating engines) that meet all of the following conditions:

2. Performance standards for new natural gas boiler units

The performance standard for new natural gas boiler units would apply on an annual average basis and be 420 t of CO2 for each gigawatt hour of energy produced. The proposed Regulations would apply to new natural gas boiler units that meet the following conditions:

3. Performance standards for coal boilers significantly modified to burn natural gas to generate electricity

The performance standard for coal boilers that cease using coal as a fuel (see footnote 24) and continue operating using natural gas to generate electricity would not apply during a prescribed period. This approach differs from the approach for new and significantly modified combustion engines and from that for new natural gas boilers due to the uncertainty associated with the role of converted units in the future electrical generation system in Canada. Significantly modified coal boilers would be allowed to operate without meeting a performance standard for a period of time under certain conditions, after which they would have to meet a stringent performance standard. The timing for the application of the performance standard is based on the result of a performance test to be conducted once the unit stops burning coal. The performance test consists of a continuous test run, lasting at least two hours to determine the emission intensity (tonne of CO2/GWh) of the unit. The emission intensity determined from this test would need to be reported under the proposed Regulations. The emission intensity during the test would establish how many years the unit could operate without meeting a performance standard.

First annual performance test and associated years of operation

The CO2 emission intensity of a coal-to-gas converted unit must meet the performance standard of 420 t of CO2 /GWh of energy produced at the following moments:

Annual performance tests would need to be conducted to determine the CO2 emission intensity of a converted unit. The CO2 emission intensity of the converted unit during these tests must not show a 2% or more increase in the emission intensity from the previous performance test.

The proposed Regulations would apply to converted units if they meet the conditions below:

Reporting obligations

Owners or operators would be required to submit annual reports for units to which the proposed Regulations apply. The proposed Regulations provide two methods to quantify CO2 emissions: the Continuous Emission Monitoring System (CEMS) (see footnote 27) and a fuel-based method. (see footnote 28)

Owners or operators of converted units would also be required to submit annual performance test reports.

Emergency circumstances

A provision has been included in the proposed Regulations to ensure grid reliability during emergency circumstances. Should a unit be required to operate to mitigate the consequences of an emergency disruption or in the event of a significant risk of disruption to the electricity supply, such a unit could apply for a temporary exemption from the performance standard because during that period, it may need to operate outside of its regular emission performance parameters. This temporary exemption allows units to which the proposed Regulations would apply to operate above the performance standard for the period of exemption.

Regulations Designating Regulatory Provisions for the Purposes of Enforcement (Canadian Environmental Protection Act, 1999)

It is proposed to amend the Regulations Designating Regulatory Provisions for the Purposes of Enforcement (Canadian Environmental Protection Act, 1999) to list some provisions of the proposed Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity and make the contravention of these provisions punishable by appropriate penalties.

Summary of the proposed Regulations

Application

Rationale

The proposed Regulations would not apply to natural gas-fired electricity units that are in use in Canada before the adoption of the proposed Regulations.

Avoids costs associated with retrofitting existing units to meet performance standards. However, based on analysis of seven large units and three small units in use in Canada, GHG emissions from these units meet or out-perform the requirements set in the proposed Regulations.

The proposed Regulations would not apply to natural gas-fired electricity combustion engines that start producing electricity after the adoption of the proposed Regulations and that sell or distribute less than 33% of their potential electric output to the grid.

Avoids costs associated with units that are not expected to be a major source of GHG emissions in Canada, while providing flexibility for operators to meet demands during peak hours.

Emission performance standards

Rationale

The proposed Regulations would align emission performance standards for new and significantly modified natural gas-fired units — combustion engines expected to sell or distribute 33% or more of their potential electric output to the grid and new boilers — with those of available efficient technologies.

Historical annual
average emission intensity (tCO2/GWh) data on existing natural gas-fired electricity generation units, using efficient technologies, shows that the proposed emission standards can be met by new and significantly modified combustion engines.

The proposed Regulations would require significantly modified boilers converted to burn natural gas to generate electricity to meet a performance standard after a prescribed period.

Converted units are expected to meet this requirement as the emission performance parameters were based on information provided by operators on the likely upgrades required to convert these units based on the current efficiency of affected coal boilers. (see footnote 29)

“One-for-One” Rule

The proposed Regulations are expected to result in a minor increase in administrative burden; therefore, the proposal is considered an “IN” under the Rule. Following the Treasury Board’s standard costing model, and using a 7% discount rate, the expected annualized administrative cost to all business subject to the proposed Regulations is approximately $10,907 (in 2012 Canadian dollars) and $779 per business. These new costs would require equal and offsetting administrative cost reduction to existing regulations, and as these are new Regulations, the Department would also be required to repeal at least one existing regulations within two years.

One-time (upfront) costs
Ongoing (annual) costs

Small business lens

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

Consultation

Following the 2012 publication of the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations in the Canada Gazette, Part II, the Department began evaluating options to address GHG emissions from natural gas-fired electricity generation in Canada.

An initial regulatory design proposal was shared with the Canadian Electricity Association in 2013 to guide discussions. In 2013 and 2014, departmental officials solicited technical information from experts in the electricity sector to determine technological options to limit emissions from natural gas-fired electricity generation. Informal discussions were held with the Canadian Electricity Association, which represents Canadian electricity sector companies.

A series of refinements to the regulatory design proposal were made to address issues raised in consultations. For example, the date on which the proposed performance standards would begin to apply to combustion engines was modified to reflect the industry’s need for sufficient lead time for planning and building new natural gas generation that would meet the regulated performance standards.

Following the technical discussions, the Department developed a proposal that was shared with a diverse range of industry stakeholders (i.e. electricity generators outside of the traditional electricity sector, equipment manufacturers) in 2014 and 2015. Industry members not represented by the Canadian Electricity Association were informed of the Department’s intention to regulate natural gas-fired electricity generation and were invited to share initial feedback with the Department. Based on input received during these consultations, the proposal was adjusted slightly. For example, units operating as cogeneration units where both useful heat and electricity are produced are recognized for both the steam and electricity in their emission intensity calculation.

On November 21, 2016, the federal government announced that in order to support the transition away from coal towards cleaner sources of electricity generation, performance standards for natural gas-fired electricity would be developed. The Department held an information webinar with industry (specifically companies that currently own or operate natural gas-fired facilities, or had announced plans for natural gas-fired electricity), provincial governments, equipment manufacturers and non-governmental organizations to re-engage stakeholders and solicit early feedback. Comments were generally supportive for the proposed approach.

The Notice of intent to develop greenhouse gas regulations for electricity generation in Canada (the Notice) was published in the Canada Gazette, Part I, on December 17, 2016. Twenty-one comments were received during the Notice comment period. Comments were submitted by industry associations, organizations that generate electricity from natural gas or renewable sources, provinces, non-governmental organizations and others. Comments received sought additional detail or clarification about the proposed Regulations (e.g. regarding specific definitions), noted the importance of natural gas as a transitional fuel to a low carbon economy, proposed either reducing or increasing the performance standards’ stringency levels, and proposed specific exemptions.

Some comments received expressed concern, while others expressed support for the relationship of the proposed Regulations with potential future pathways for achieving deep decarbonization in the electricity sector and/or related mechanisms (e.g. carbon pricing or renewable fuel standards).

In early 2017, an informal technical working group was convened by the Department consisting of members from federal and provincial governments, system operators, industry, non-governmental organizations, and equipment manufacturers to facilitate a discussion of issues that would influence the design of the proposed Regulations. During the face-to-face meetings, members were encouraged to raise issues, present any data or analyses they had prepared, and provide conclusions and/or recommendations for the Department’s consideration. Issues discussed included the definition of a new unit and significantly modified unit, units with significant variability in their operations, the small/large combustion engine threshold and performance standards for boiler units converted from coal to natural gas.

With respect to comments received following the publication of the Notice, the Department reconsidered the stringency of each of the performance standards and made adjustments, where there were sufficient new data to support the change. For example, in the Notice, a 101 MW combustion engine was initially considered to be large and therefore subject to a performance standard of 420 t/GWh. Under the revised approach, this unit would now be considered to be small and therefore subject to an average annual emissions intensity of 550 t/GWh. Another example is for coal-fired boilers converted to burn natural gas to generate electricity, which were initially subject to a 550 t/GWh average annual emissions intensity performance standard. Under the revised approach, such units would be required to undertake a performance test and, depending on the results, no ongoing emissions intensity performance standard would be required to be met for the specific number of years determined by the results of the performance test on these units. With respect to proposed specific exemptions and requests to “grandfather” existing/permitted/already purchased units, the proposed Regulations would not apply to existing units that do not undergo significant modifications. The proposed Regulations would not come into force until two years after publication in the Canada Gazette, Part II, giving sufficient time for purchased units with current permits to meet the performance standard.

As a result of these discussions and the presentation of new data during the technical group meetings held in early 2017, the Department modified some aspects of the proposal. For example, the small/large combustion engine threshold was adjusted upward to reflect the most recent data on combustion engine technologies currently available for sale. In addition, the threshold for heat input for natural gas, which defines coverage for the proposed Regulations, was raised from 10% to 30% to address issues raised for units’ combusting biomass.

For new units, the proposed Regulations for natural gas-fired electricity emission performance standards are aligned with that of currently available efficient technologies. The Government will monitor developments in the sector, and, on an as-needed basis, amend the regulations to keep pace with new technologies. This would keep our performance standards for new turbines evergreen without impacting existing turbines that were installed in compliance with the regulatory standards of the day.

Rationale

In Canada, significant investment is expected in the electricity sector as it phases out the use of coal to generate electricity. Investment decisions to build electricity generation capacity are a complex process that involves analyses of several factors such as a forecast of energy/capacity demand and of market pricing/constraints. Other factors, such as lack of clarity of regulatory frameworks, could affect the sector in the future and influence investment decisions on how to replace coal-fired electricity generation capacity. As a result, the proposed Regulations would set GHG emission intensity limits for natural gas-fired electricity generation for new and significantly modified natural gas-fired electricity generation units in Canada. The proposed Regulations would ensure that new and converted natural gas-fired electricity units are subject to achievable performance standards and provide regulatory certainty on the level of stringency associated with such standards. This is expected to help ensure the transition to lower emitting electricity generation and is consistent with the Government’s overall strategy to reduce GHG emissions.

Impacts
Canadians

The proposed Regulations are not expected to have an impact on Canadians.

Government of Canada

Minor additional resources are anticipated to process annual emission reports as a result of the proposed Regulations. As affected units are expected to be compliant with the performance standards, no significant incremental costs associated with compliance promotion or enforcement activities are anticipated.

Businesses

The analysis assumes that operators would choose the most cost-effective option to replace coal-fired electricity generation capacity in Canada. It is generally agreed that this would entail investment in new natural gas-fired electricity generation units, which use efficient technologies that minimize fuel consumption. Since natural gas-fired electricity generation emits about 40% to 50% less GHG emissions than coal-fired electricity generation, it also responds to changes in market structure and carbon pricing or carbon reducing policies that provinces have implemented, or plan to implement.

Operators choosing to build new natural gas-fired electricity generation units in Canada are not expected to be impacted by the proposed Regulations, as the performance emission standards align with the performance of those available efficient technologies, used for natural gas-fired electricity generation. Based on available information, operators in Canada have already adopted these technologies and are expected to continue to do so in the future.

For each calendar year that natural gas-fired electricity generation units are subject to the proposed Regulations, owners and operators of new combustion engines and boilers, as well as significantly modified combustion engines, would be required to submit a report on these units’ average annual emissions. Similarly, for coal-to-gas conversion units, owners and operators would be required to submit annual performance test reports. To comply with the reporting of average annual emissions, the two methods to quantify emissions (i.e. CEMS and fuel-based) required by the proposed Regulations are not expected to have a significant impact on businesses. This is due to the alignment of these reporting requirements with those under the changes to the Greenhouse Gas Reporting Program (GHGRP), which are expected to come into force before the proposed Regulations. Incremental costs associated with annual performance test reports (a single test run, lasting at least two hours) for coal-to-gas conversions are also expected to be low. Regulatees would need to make and keep records of these reports for a period of seven years.

Based on available information provided by industry and generated by the Department, the proposed Regulations would set GHG emission intensity limits for natural gas-fired electricity generation in Canada and provide sought-after regulatory certainty for industry by setting achievable performance emission requirements associated with natural gas-fired electricity generation in Canada. This is expected to facilitate the planning and investment decision-making associated with choosing, as part of the overall strategy to phase out the use of coal to generate electricity, to build natural gas-fired electricity generation capacity in Canada.

Strategic environmental assessment

The proposed Regulations have been developed under the Pan-Canadian Framework for 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 help reduce GHG emissions and are in line with the 2016–2019 Federal Sustainable Development Strategy. The proposed 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. (see footnote 31)

Implementation, enforcement and service standards

Once the proposed Regulations come into force, the Department will develop and deliver implementation activities. This may include posting information on the Department’s website, advising stakeholders of the final regulatory publication, responding to information or clarification requests, sending reminder letters (as appropriate).

Enforcement

Enforcement officers would, when verifying compliance with the proposed Regulations, apply the Compliance and Enforcement Policy (the Policy) for CEPA. (see footnote 32) The 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 would resort to civil suits by the Crown for cost recovery.

To verify compliance, enforcement officers may conduct an inspection. An inspection may identify an alleged violation, and alleged violations may also be identified by the Department’s technical personnel, or through complaints received from the public. Whenever a possible violation of regulatory requirements is identified, enforcement officers may carry out investigations.

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

The proposed Regulations would also require related changes to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999). These Regulations designate the regulatory provisions from CEPA regulations that refer to an increased fine regime following a conviction of an offence involving harm or risk of harm to the environment, or obstruction of authority.

Contacts

Paola Mellow
Director
Electricity and Combustion Division
Environment and Climate Change Canada
351 Saint-Joseph Boulevard
Gatineau, Quebec
K1A 0H3
Email: ec.electricite-electricity.ec@canada.ca

Matthew Watkinson
Director
Regulatory Analysis and Valuation Division
Environment and Climate Change Canada
200 Sacré-Cœur Boulevard, 10th Floor
Gatineau, Quebec
K1A 0H3
Email: eccc.darv-ravd.eccc@canada.ca

PROPOSED REGULATORY TEXT

Notice is given, pursuant to subsection 332(1) (see footnote a) of the Canadian Environmental Protection Act, 1999 (see footnote b), that the Governor in Council, pursuant to subsections 93(1) and 330(3.2) (see footnote c) of that Act, proposes to make the annexed Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity.

Any person may, within 60 days after the date of publication of this notice, file with the Minister of the Environment comments with respect to the proposed Regulations or a notice of objection requesting that a board of review be established under section 333 of that Act and stating the reasons for the objection. All comments and notices must cite the Canada Gazette, Part I, and the date of publication of this notice and be sent to the Electricity and Combustion Division, Energy and Transportation Directorate, Department of the Environment, 351 Saint-Joseph Boulevard, 11th Floor, Gatineau, Quebec K1A 0H3 (fax: 819-938-4254; email: ec.electricite-electricity.ec@canada.ca).

Any person who provides information to the Minister of the Environment may submit with the information a request for confidentiality under section 313 of that Act.

Ottawa, January 10, 2018

Jurica Čapkun
Assistant Clerk of the Privy Council

Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity

Overview

Purpose

1 These Regulations establish a regime for limiting carbon dioxide (CO2) emissions that result from the generation of electricity by means of thermal energy from the combustion of natural gas, whether in conjunction with other fuels, except coal, or not.

Interpretation

Definitions

2 (1) The following definitions apply in these Regulations.

Act means the Canadian Environmental Protection Act, 1999. (Loi)

API means the American Petroleum Institute. (API)

ASTM means ASTM International, formerly known as the American Society for Testing and Materials. (ASTM)

auditor means a person who

authorized official means

biomass means a fuel that consists only of non-fossilized, biodegradable organic material that originates from plants or animals but does not originate from a geological formation, and includes gases and liquids that are recovered from the decomposition of organic waste. (biomasse)

boiler unit means a unit that consists of at least one boiler but does not have a combustion engine. (groupe à chaudière)

capacity means

combustion engine means an engine, other than an engine that is self-propelled or designed to be propelled while performing its function, that

combustion engine unit means a unit that consists of at least one combustion engine and, if applicable, a heat recovery system, but does not have a boiler. (groupe à moteur à combustion)

continuous emission monitoring system or CEMS means equipment for the sampling, conditioning and analyzing of emissions from a given source and the recording of data related to those emissions. (système de mesure et d’enregistrement en continu des émissions ou SMECE)

facility means all buildings, other structures and equipment, whether the equipment is stationary or not, that are located on a single site or adjacent sites and that are operated as a single integrated site. (installation)

fossil fuel means a fuel other than biomass. (combustible fossile)

heat recovery system means equipment, other than a boiler, that extracts heat from a combustion engine’s exhaust gases in order to generate steam or hot water. (système de récupération de la chaleur)

heat to electricity ratio means, in respect of a unit, the total useful thermal energy production in a calendar year, expressed in GWh, divided by the total gross electricity generation in that calendar year, expressed in GWh. (rapport chaleur-électricité)

natural gas means a mixture of hydrocarbons — such as methane, ethane or propane — that is in a gaseous state at standard conditions and that is composed of at least 70% methane by volume or that has a higher heating value that is not less than 35 MJ/standard m3 and not more than 41 MJ/standard m3. It excludes landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, producer gas, coke oven gas, gas derived from petroleum coke or coal — including synthetic gas — or any gaseous fuel produced in a process that might result in highly variable sulphur content or heating value. (gaz naturel)

operator means a person who has the charge, management or control of a unit. (exploitant)

performance test verifier means a person who

potential electrical output means the quantity of electricity that would be generated by a unit in a calendar year if the unit were to operate at capacity at all times during that calendar year. (production potentielle d’électricité)

Reference Method means the document entitled Reference Method for Source Testing: Quantification of Carbon Dioxide Releases by Continuous Emission Monitoring Systems from Thermal Power Generation, June 2012, published by the Department of the Environment. (Méthode de référence)

responsible person means an owner or operator of a unit. (personne responsable)

standard conditions means a temperature of 15°C and a pressure of 101.325 kPa. (conditions normales)

standard m3 means a volume expressed in cubic metres — at standard conditions. (m3 normalisé)

unit means an assembly comprised of a boiler or combustion engine and any other equipment that is physically connected to either, including duct burners and other combustion devices, heat recovery systems, steam turbines, generators and emission control devices and that operate together to generate electricity and, if applicable, produce useful thermal energy, from the combustion of natural gas. (groupe)

useful life, in respect of a boiler unit referred to in subsection 3(4), has the same meaning as in subsection 2(1) of the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations. (vie utile)

useful thermal energy means energy in the form of steam or hot water that is destined for a use — other than the generation of electricity — that would have required the consumption of energy in the form of fuel or electricity had that steam or hot water not been used. (énergie thermique utile)

Interpretation of documents incorporated by reference

(2) For the purposes of interpreting documents that are incorporated by reference into these Regulations, “should” must be read to mean “must” and any recommendation or suggestion must be read as an obligation.

Standards incorporated by reference

(3) Any standard of the ASTM, Gas Processors Association or the API that is incorporated by reference into these Regulations is incorporated as amended from time to time.

Application

New generation of electricity — boiler units

3 (1) These Regulations apply to any boiler unit that has a capacity of 25 MW or more, that begins generating electricity on or after the day on which these Regulations come into force, beginning on January 1 of the calendar year during which it meets the following conditions:

New generation of electricity — combustion engine units

(2) These Regulations apply to any combustion engine unit that has a capacity of 25 MW or more, that begins generating electricity on or after the day on which these Regulations come into force, beginning on January 1 of the calendar year during which it meets the following conditions:

Existing generation of electricity

(3) These Regulations also apply to any unit referred to in subsection (1) or (2) that generated electricity at a facility before the day on which these Regulations come into force and

Significantly modified — conversion to natural gas

(4) These Regulations also apply to any boiler unit referred to in subsection (1) that was registered under subsection 4(1) of the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, and that generated electricity before the day on which these Regulations are registered, beginning in the calendar year following that in which the unit ceases to combust coal.

Hybrid configuration

(5) If a combustion engine unit and a boiler unit share the same steam turbine, these Regulations apply

Non-application

(6) These Regulations do not apply to units with respect to a calendar year in which they generate electricity and, if applicable, produce useful thermal energy from the combustion of coal as defined in subsection 2(1) of the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations.

Requirements

Emission Intensity Limits

General

4 (1) A responsible person for a unit must not emit from the unit an amount of CO2 that is, during a calendar year, on average, greater than any of the following intensity limits, as applicable:

Significantly modified boiler units

(2) A responsible person for a boiler unit referred to in subsection 3(4) must not emit from the boiler unit an amount of CO2 that is, during a calendar year, on average, greater than 420 tonnes of CO2 emissions/GWh of energy produced, as applicable, starting the

Quantification of energy and emissions

(3) For the purposes of subsections (1) and (2),

Special Rules

(4) For the purposes of subsection (3), if, in the calendar year, one of the combustion engines of the unit is repaired or maintained and one or more replacement combustion engines are temporarily installed, the quantity of energy and CO2 emissions produced during the replacement period, to a maximum of 90 days per calendar year, are excluded from the calculation referred to in that paragraph.

Exception — boiler unit

(5) Despite subsection (1), a boiler unit that, in a calendar year, does not meet one of the conditions set out in subsection 3(1), is not subject to the emission intensity limit for that calendar year.

Exception — combustion engine

(6) Despite subsection (1), a combustion engine unit that, in a calendar year, does not meet one of the conditions set out in subsection 3(2), is not subject to the emission intensity limit for that calendar year.

Partial year application

(7) For greater certainty, if subsection (1) applies in respect of a unit for only part of a calendar year, that part is considered to be the full calendar year.

Performance Tests — Significantly modified boiler units

Initial performance test

5 (1) An initial performance test must be conducted in the presence of the performance test verifier and in accordance with subsection (4) to determine the CO2 emission intensity for a boiler unit referred to in subsection 3(4) within 12 months following

Annual performance test

(2) Performance tests are to be subsequently conducted annually to determine the CO2 emission intensity for the boiler unit in question, in accordance with subsection (3).

Conditions — test

(3) The initial and annual performance test must consist of a continuous test that lasts at least two hours and does not exceed 100% of the unit’s capacity.

Quantification

(4) For the purposes of subsections (1) and (2),

Adaptation

(5) For the performance test, the reference to “calendar year” in sections 11, 12, 15, 17 and 18 and in the Reference Method is replaced with a reference to “performance test period”.

Requirement

6 A responsible person for a unit referred to in subsection 3(4) must obtain an annual performance test result that shows less than a 2% increase in emission intensity from the previous performance test.

Emergency Circumstances

Application for exemption

7 (1) A responsible person for a unit may, under an emergency circumstance described in subsection (2), apply to the Minister for an exemption from the application of subsection 4(1) or (2) in respect of the unit if, as a result of the emergency, the operator of the electricity grid in the province in which the unit is located or an official of that province responsible for ensuring and supervising the electricity supply orders the responsible person to produce electricity to avoid a threat to the supply or to restore that supply.

Definition of emergency circumstance

(2) An emergency circumstance is a circumstance

Deadline for application

(3) The application for the exemption must be provided to the Minister within 15 days after the day on which the emergency circumstance arises. The application must include the information referred to in section 1 and paragraphs 2(a), (b) and (d) of Schedule 1 or the unit’s registration number, if any, the date on which the emergency circumstance arose and information, along with supporting documents, to demonstrate that the conditions set out in subsection (1) are met.

Minister’s decision

(4) If the Minister is satisfied that the conditions set out in subsection (1) are met, the Minister must, within 30 days after the day on which the application is received,

Duration of exemption

(5) The exemption becomes effective on the day on which the emergency circumstance arises and ceases to have effect on the earliest of

Application for extension of exemption

8 (1) If the conditions set out in subsection 7(1) will continue to exist after the day on which the exemption granted under paragraph 7(4)(a) is to cease to have effect, the responsible person may, before that day, apply to the Minister for an extension of the exemption.

Contents of application

(2) The application must include the unit’s registration number and information, along with supporting documents, to demonstrate that

Minister’s decision

(3) If the Minister is satisfied that the elements referred to in paragraphs (2)(a) and (b) have been demonstrated, the Minister must grant the extension within 15 days after the day on which the application is received.

Duration of extension

(4) The extension ceases to have effect on the earliest of

Accuracy of Data

Measuring devices — installation, maintenance and calibration

9 (1) A responsible person for a unit must install, maintain and calibrate a measuring device — other than a continuous emission monitoring system and a measuring device that is subject to the Electricity and Gas Inspection Act — that is used for the purposes of these Regulations in accordance with the manufacturer’s instructions or any applicable generally recognized national or international industry standard.

Frequency of calibration

(2) The responsible person must calibrate each of the measuring devices at the greater of the following frequencies:

Accuracy of measurements

(3) The responsible person must use measuring devices that enable measurements to be made with a degree of accuracy of ± 5%.

Certification of CEMS

10 The responsible person must certify the CEMS in accordance with section 5 of the Reference Method, before it is used for the purposes of these Regulations.

Quantification Rules

Production of Energy

Quantity of energy

11 (1) The quantity of energy produced by a given unit is determined by the formula

G + (0.75 × Hpnet)

where

Quantity of electricity — hybrid configuration

(2) The quantity of electricity generated by a given unit is determined by the formula

Gs − Gext

where

Formula - Detailed information can be found in the surrounding text.

Net quantity of useful thermal energy

(3) In the case of a unit that simultaneously generates electricity and produces useful thermal energy from the fuel combusted by a combustion engine or boiler, as the case may be, the net quantity of useful thermal energy produced by the unit in a calendar year, expressed in GWh, is determined by the formula

Formula - Detailed information can be found in the surrounding text.

where

CO2 Emissions

Quantification Methods

Choice of method

12 The quantity of CO2 emissions resulting from the combustion of fossil fuels in a unit in a calendar year must be determined

Continuous Emission Monitoring System

Unit not combusting biomass

13 Subject to section 15, the quantity of CO2 emissions resulting from combustion of fossil fuels in a unit that does not combust biomass that is measured using a CEMS must be calculated in accordance with sections 7.1 to 7.7 of the Reference Method.

Unit combusting biomass

14 (1) Subject to section 15, the quantity of CO2 emissions resulting from the combustion of fossil fuels in a unit combusting biomass in a calendar year that is measured using a CEMS must be determined in accordance with the following formula:

Eu − Ebio

where

Multiple CEMS per unit

15 (1) For the purposes of sections 13 and 14, the total quantity of CO2 emissions from a unit equipped with multiple CEMS is determined by adding together the quantity of emissions measured for each CEMS.

Units sharing common stack

(2) If a unit is located at a facility where there is one or more other units and a CEMS measures emissions from that unit and other units at a common stack rather than at the exhaust duct of that unit and of each of those other units that brings those emissions to the common stack, then the quantity of emissions attributable to that unit is determined based on the ratio of the heat input of that unit to the total of the heat input of that unit and of all of those other units sharing the common stack in accordance with the following formula:

Formula - Detailed information can be found in the surrounding text.

where

If using a CEMS

16 (1) A responsible person who uses a CEMS must ensure compliance with the Reference Method.

Auditor’s report

(2) For each calendar year during which the responsible person used a CEMS, they must obtain a report, signed by the auditor, that contains the information required by Schedule 3 and send it to the Minister with the report referred to in section 21.

Fuel-based Method

Quantification

17 The quantity of CO2 emissions resulting from the combustion of fossil fuels in a unit in a calendar year, that is not measured using a CEMS, is determined by the formula

Formula - Detailed information can be found in the surrounding text.

where

S × R × (44/MMs)

Measured carbon content

18 (1) The quantity of CO2 emissions, that is attributable to the combustion of a fossil fuel in a unit in a calendar year is determined by one of the following formulas, whichever applies:

Vf × CCA × (MMA⁄MVcf) × 3.664 × 0.001

Vf × CCA × 3.664

Mf × CCA × 3.664

Weighted average

(2) The weighted average “CCA” referred to in paragraphs (1)(a) to (c) is based on fuel samples taken in accordance with section 19, determined by the formula

Formula - Detailed information can be found in the surrounding text.

Sampling and Missing Data

Sampling

19 (1) The determination of the value of the elements related to carbon content referred to in section 18 must be based on fuel samples taken in accordance with this section.

Frequency

(2) Each fuel sample must be taken at a time and location in the fuel handling system of the facility that provides the following representative samples of the fuel combusted at the applicable minimum frequency:

Additional samples

(3) For greater certainty, the responsible person who, for the purposes of these Regulations, takes more samples than the minimum required under subsection (2) must make the determination referred to in subsection (1) based on each sample taken — and in the case of composite samples, each sub-sample taken — including those additional samples.

Significantly modified boiler units

(4) In the case of a boiler unit referred to in subsection 3(4), one fuel sample is required for the initial performance test and each subsequent performance test and it must be taken in accordance with one of the applicable standards set out in subparagraphs (2)(a)(i) to (iv).

Missing data

20 (1) Except in the case of an initial performance test or any subsequent performance test referred to in section 5, if, for any reason beyond the responsible person’s control, the emission intensity referred to in subsection 4(1) or 4(2) cannot be determined in accordance with a formula set out in any of sections 11, 17 and 18 because data required to determine the value of an element of that formula is missing for a given period in a calendar year, replacement data for that given period must be used to determine that value.

Replacement data — CEMS

(2) If a CEMS is used to determine the value of an element of a formula set out in section 17 but data is missing for a given period, the replacement data must be obtained in accordance with Section 3.5.2 of the Reference Method.

Replacement data — fuel-based methods

(3) If a fuel-based method is used to determine the value of any element — related to the carbon content or molecular mass of a fuel — of a formula set out in section 17 or 18 but data is missing for a given period, the replacement data is to be the average of the available data for that element, using the fuel-based method in question, during the equivalent period prior to and, if the data is available, subsequent to that given period. However, if no data is available for that element for the equivalent period prior to that given period, the replacement data to be used is the value determined for that element, using the fuel-based method in question, during the equivalent period subsequent to the given period.

Replacement data — multiple periods

(4) Replacement data may be used in relation to a maximum of 28 days in a calendar year.

Reporting, Sending, Recording and Retaining Information

Annual reports

21 (1) A responsible person for a unit must send one of the following reports, to the Minister on or before the June 1 that follows the calendar year that is the subject of the report:

Permanent cessation of electricity generation

(2) If a unit permanently ceases to generate electricity in a calendar year, a responsible person for the unit must so notify the Minister in writing not later than 60 days after the day on which the unit ceases generating electricity. A report is not necessary in respect of the calendar years following the calendar year in which the unit ceases generating electricity.

Registration number

(3) On receipt of a first report in respect of a unit referred to in paragraph (1)(a), the Minister must assign a registration number to the unit and inform the responsible person of that number.

Change of information

(4) If there is a change to the information referred to in section 1 of Schedule 1 that was provided in the most recent report, the responsible person must notify the Minister of the change in writing not later than 30 days after the day on which the change is made.

Performance test reporting

22 (1) A responsible person for a boiler unit referred to in subsection 3(4) must send, to the Minister, a report containing the information referred to in Schedule 4 in relation to the performance test identified in section 5 no later than 60 days after the performance test was conducted.

Performance test verifier’s report — initial test

(2) In the case of a boiler unit referred to in subsection 3(4), the responsible person must obtain a report, signed by the performance test verifier, on the initial performance test, that contains the information referred to in Schedule 5 and send it to the Minister with their report referred to in subsection (1).

Electronic report, notice and application

23 (1) A report or notice that is required, or an application that is made, under these Regulations must be sent electronically in the form specified by the Minister and must bear the electronic signature of an authorized official of the responsible person.

Paper report or notice

(2) If the Minister has not specified an electronic form or if the person is unable to send the report, notice or application electronically in accordance with subsection (1) because of circumstances beyond the person’s control, the report, notice or application must be sent on paper, in the form specified by the Minister, if applicable, and be signed by an authorized official of the responsible person.

Maintain copy

24 (1) A responsible person for a unit must make a record containing the following documents and information:

30 days

(2) The record referred to in subsection (1) must be made as soon as feasible but not later than 30 days after the day on which the information and documents to be included in it become available.

Retention of records and reports

25 A responsible person who is required under these Regulations to make a record or send a report or notice must keep the record or a copy of the report or notice, along with the supporting documents, at their principal place of business in Canada for at least seven years after they make the record or send the report or notice

Coming into Force

Registration

26 (1) Subject to subsection (2), these Regulations come into force on the day on which they are registered.

Deferred application

(2) These Regulations become applicable to combustion engine units on the second anniversary of the day on which they are registered.

SCHEDULE 1

(Subsection 7(3), paragraphs 21(1)(a) and (b) and subsection 21(4))

Annual Report — Information Required

1 The following information respecting the responsible person:

2 The following information respecting the unit:

3 The following information respecting the emission intensity referred to in subsection 4(1) of these Regulations resulting from the combustion of fossil fuel in the unit during the calendar year:

4 The following information:

5 A copy of the auditor’s report referred to in subsection 16(2) of these Regulations.

6 The following information respecting the replacement data referred to in section 20 of these Regulations that were used for a given period during the calendar year, if applicable:

SCHEDULE 2

(Subsections 14(2) and 15(2))

List of Fuels

Item

Column 1

Fuel type

Column 2

Default higher heating value (GJ/kL) see note 2

1

Distillate fuel oil No. 1

38.78

2

Distillate fuel oil No. 2

38.50

3

Distillate fuel oil No. 4

40.73

4

Kerosene

37.68

5

Liquefied petroleum gases (LPG)

25.66

6

Propane (pure, not mixtures
of LPGs) see note 1

25.31

7

Propylene

25.39

8

Ethane

17.22

9

Ethylene

27.90

10

Isobutane

27.06

11

Isobutylene

28.73

12

Butane

28.44

13

Butylene

28.73

14

Natural gasoline

30.69

15

Motor gasoline

34.87

16

Aviation gasoline

33.52

17

Kerosene-type aviation

37.66

18

Pipeline quality natural gas

0.03793 see note 3

SCHEDULE 3

(Subsection 16(2))

CEMS Auditor’s Report — Information Required

1 The name, civic address and telephone number of the responsible person.

2 The name, civic address, telephone number and qualifications of the auditor and, if any, the auditor’s email address and fax number.

3 The procedures followed by the auditor to assess whether

4 A statement of the auditor’s opinion as to whether

5 A statement of the auditor’s opinion as to whether the responsible person has ensured that the Quality Assurance/Quality Control manual has been updated in accordance with sections 6.1 and 6.5.2 of the Reference Method.

SCHEDULE 4

(Subsection 22(1))

Performance Test Report — Information Required

1 The following information respecting the responsible person:

2 The following information respecting the unit:

3 The following information respecting the emission intensity referred to in subsection 4(1) of these Regulations resulting from the combustion of fuel in the unit during the performance test period:

4 The date the test was performed.

SCHEDULE 5

(Subsection 22(2))

Initial Performance Test Verifier’s Report — Information Required

1 The name, civic address and telephone number of the responsible person.

2 The name, civic address, telephone number and qualifications of the performance test verifier and, if any, the performance test verifier’s email address and fax number.

3 The procedures followed by the performance test verifier to assess whether the performance test result was obtained in accordance with section 5 of these Regulations.

4 A statement of the performance test verifier’s opinion as to whether the performance test result was obtained in accordance with section 5 of these Regulations.

[7-1-o]