Canada Gazette, Part I, Volume 152, Number 7: Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity
February 17, 2018
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
- are expected to occur over 2020 to 2023, 7 to 10 years before coal units would be required to shut down under federal and provincial coal-fired electricity regulations and would result in early GHG emission reductions;
- can be completed within a shorter period (see footnote 16) and at less cost, (see footnote 17) while providing reliable back-up capacity; and
- may avoid the need to build large new natural gas-fired electricity units in the future as the sector transitions to non-emitting sources of electricity generation such as hydro, wind and solar power generation.
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:
- — the unit starts generating electricity two years after the adoption of the proposed Regulations or later, or the unit generated electricity before it is moved to a new facility after the adoption of the proposed Regulations or more than 50% of its capacity is installed after that date;
- — the unit has a capacity of 25 MW or more;
- — 33% or more of the potential electric output of the unit is sold or distributed to the grid; (see footnote 20) and
- — more than 30% of the heat input (see footnote 21) of the unit comes from the combustion of natural gas.
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:
- — the unit generates electricity after the adoption of the proposed Regulations;
- — the unit has a capacity of 25 MW or more;
- — electricity generated by the unit is sold or distributed to the grid;
- — more than 30% of the heat input (see footnote 22) of the unit comes from the combustion of natural gas; and
- — in the case of a cogeneration boiler unit, it has a heat-to-electricity ratio of 0.9 or less. (see footnote 23)
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:
- (i) starting the year which is after the unit's end of useful life, if the first annual performance test results in a CO2 emissions intensity that is greater than 600 t of CO2/GWh;
- (ii) starting the year which is 5 years after the unit's end of useful life, if the first annual performance test results in a CO2 emissions intensity that is less than or equal to 600 t of CO2/GWh but greater than 550 t of CO2/GWh;
- (iii) starting the year which is 8 years after the unit's end of useful life, if the first annual performance test results in a CO2 emissions intensity that is less than or equal to 550 t of CO2/GWh but greater than 480 t of CO2/GWh; or
- (iv) starting the year which is 10 years after the unit's end of useful life, if the first annual performance test results in a CO2 emissions intensity that is less than or equal to 480 t of CO2/GWh.
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:
- — the unit has been registered under the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations;
- — the unit ceased combusting coal and continues to generate electricity using natural gas as a fuel after the adoption of the proposed Regulations;
- — the unit has a capacity of 25 MW or more;
- — electricity generated by the unit is sold or distributed to the grid;
- — more than 30% of the heat input (see footnote 25) of the unit comes from the combustion of natural gas; and
- — in the case of a cogeneration boiler unit, it has a heat-to-electricity ratio of 0.9 or less. (see footnote 26)
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.
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 |
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
- The assumed wage rate for a chemical engineer or an employee with training in natural or applied science is $42/hour, for administrative support staff, $29/hour, and for senior managers, $120/hour. (see footnote 30)
- At each facility, a chemical engineer or an employee with training in natural or applied science would spend four hours to become familiar with the administrative requirements of the proposed Regulations in 2018, while senior management would spend one hour to do it.
- At each facility, a chemical engineer or an employee with training in natural or applied science would require 0.5 hours to produce the report for the initial emissions intensity test associated with coal-to-gas conversions.
- At each facility, administrative support staff would need an average of 0.5 hours to register facility information (e.g. name, address and contact information for the facility and representatives) with the Department in 2018.
Ongoing (annual) costs
- At each facility, a chemical engineer or an employee with training in natural or applied science (with the same wage rate assumptions as above) would need, on an annual basis, an average of 23.25 hours to complete the administrative requirements associated with annual reporting. This includes data retrieval and entry, sampling and analysis, calculations of net thermal energy produced, CO2 emission calculations, and other calculations.
- At each facility, a senior manager would be expected to spend two hours reviewing and approving the annual reports.
- Administrative support staff at each facility would spend one hour recording and filing the annual reports.
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:
- 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, willingness to cooperate with enforcement officers, and evidence of corrective action already taken; and
- Consistency: Enforcement officers would consider how similar situations have been handled in determining the measures to be taken to enforce CEPA.
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
- (a) is independent of the responsible person that is to be audited; and
- (b) has knowledge of and has experience with respect to
- (i) the certification, operation and relative accuracy test audit of continuous emission monitoring systems, and
- (ii) quality assurance and quality control procedures in relation to those systems. (vérificateur)
authorized official means
- (a) in respect of a responsible person that is a corporation, an officer of the corporation who is authorized to act on its behalf;
- (b) in respect of a responsible person that is an individual, that individual or an individual who is authorized to act on that individual's behalf; and
- (c) in respect of a responsible person that is another entity, a person authorized to act on that other entity's behalf. (agent autorisé)
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
- (a) in the case of a unit, the net electric power (the maximum gross electric power of the unit minus the electric power used to operate the unit) that can be sustained by the unit without the use of duct burners, expressed in MW; and
- (b) in the case of a combustion engine, the maximum gross electric power that can be sustained by the engine when it is connected to a generator, expressed in MW. (capacité)
combustion engine means an engine, other than an engine that is self-propelled or designed to be propelled while performing its function, that
- (a) operates according to the Brayton thermodynamic cycle and combusts natural gas to produce a net amount of motive power; or
- (b) combusts natural gas and uses reciprocating motion to convert thermal energy into mechanical work. (moteur à combustion)
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
- (a) is independent of the responsible person for which the performance test is being conducted; and
- (b) has knowledge of and has experience with respect to performance testing of boiler units. (vérificateur de l'essai de rendement)
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:
- (a) more than 30% of its heat input, on average, during the calendar year, comes from the combustion of natural gas;
- (b) its heat to electricity ratio is not more than 0.9; and
- (c) a quantity of the electricity that it generates is sold or distributed to the electric grid.
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:
- (a) more than 30% of its heat input, on average, during the calendar year, comes from the combustion of natural gas; and
- (b) 33% or more of its potential electrical output is sold or distributed to the electric grid, however the quantity of electricity sold or distributed to the electric grid coming from combustion engines, temporarily installed for a period of not more than 90 days, as part of repairs or maintenance is not to be taken into account.
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
- (a) was moved to another facility on or after that day; or
- (b) is a combustion engine unit, for which more than 50% of the total capacity of the combustion engines comes from combustion engines installed on or after the day on which these Regulations come into force, unless they are engines, with a capacity of 150 MW or less, installed to replace engines, with a capacity of 150 MW or less, as part of repair or maintenance.
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
- (a) in the case of a combustion engine unit, to the assembly comprised of combustion engines and any other equipment connected to them including the steam turbine that it shares with the boiler unit, and
- (b) in the case of a boiler unit, to the assembly comprised of boilers and any other equipment connected to them including the steam turbine that it shares with the combustion engine unit.
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:
- (a) 420 tonnes of CO2 emissions/GWh of energy produced
- (i) in the case of boiler units, other than those referred to in subsection 3(4); and
- (ii) in the case of combustion engine units that are equipped with at least one combustion engine that has a capacity of more than 150 MW; and
- (b) 550 tonnes of CO2 emissions/GWh of energy produced in the case of combustion engine units that are equipped only with combustion engines that have a capacity of 150 MW or less.
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
- (a) year after the unit's end of useful life, if the initial performance test conducted under subsection 5(1) indicates a CO2 emissions intensity greater than 600 t/GWh, ;
- (b) sixth year after the unit's end of useful life, if the initial performance test conducted under subsection 5(1) indicates a CO2 emissions intensity greater than 550 t/GWh and less than or equal to 600 t/GWh;
- (c) ninth year after the unit's end of useful life, if the initial performance test conducted under subsection 5(1) indicates a CO2 emissions intensity greater than 480 t/GWh and less than or equal to 550 t/GWh; or
- (d) eleventh year after the unit's end of useful life, if the initial performance test conducted under subsection 5(1) results in a CO2 emissions intensity less than or equal to 480 t/GWh.
Quantification of energy and emissions
(3) For the purposes of subsections (1) and (2),
- (a) the quantity of energy produced in the calendar year must be determined in accordance with section 11; and
- (b) the quantity of CO2 emissions produced in the calendar year must be determined in accordance with sections 12 to 18, as applicable.
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
- (a) in the case of a unit that has ceased to combust coal before the day on which these Regulations come into force, the day on which they come into force; or
- (b) in the case of a unit that ceases to combust coal on or after the day on which these Regulations come into force, the day on which electricity generated from the boiler unit was first sold or distributed to the electric grid, in the calendar year in which the unit becomes subject to these Regulations.
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),
- (a) the quantity of CO2 emitted by the unit must be determined in accordance with sections 12, 13, 15, 17 and 18, as applicable, however, all emissions must be quantified including those from the combustion of biomass; and
- (b) the quantity of energy produced by the unit must be determined in accordance with section 11.
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
- (a) that arises due to an extraordinary, unforeseen and irresistible event; or
- (b) under which one or more of the measures referred to in paragraph 1(a) of the Regulations Prescribing Circumstances for Granting Waivers Pursuant to Section 147 of the Act has been made or issued in the province where the unit is located.
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,
- (a) grant the exemption; and
- (b) if the unit has not been assigned a registration number, assign a registration number and inform the responsible person of that number.
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
- (a) the ninetieth day after that day,
- (b) the day specified by the Minister,
- (c) the day on which the circumstance referred to in paragraph (2)(a) ceases to cause a disruption, or a significant risk of disruption, to the electricity supply in the province where the unit is located, and
- (d) the day on which the measure, if any, referred to in paragraph (2)(b) ceases to have effect.
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
- (a) the conditions set out in subsection 7(1) will continue to exist after the day on which the exemption is to cease to have effect; and
- (b) measures — other than the operation of the unit while the exemption has effect — have been or are being taken to end, decrease the risk of or mitigate the consequences of the disruption.
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
- (a) the ninetieth day after the day on which the application for the extension was made,
- (b) the day specified by the Minister, and
- (c) the day referred to in paragraph 7(5)(c).
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:
- (a) at least once in every calendar year but at least five months after a previous calibration, and
- (b) the minimum frequency recommended by the manufacturer.
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
- G is
- (a) the gross quantity of electricity generated by the unit in the calendar year expressed in GWh, as measured at the electrical terminals of the generators of the unit using meters that comply with the requirements of the Electricity and Gas Inspection Act and the Electricity and Gas Inspection Regulations, or
- (b) in the case of a hybrid configuration, the quantity of electricity generated by the given unit in the calendar year expressed in GWh, if the unit is either a combustion engine unit that shares a steam turbine with a boiler unit or a boiler unit that shares a steam turbine with a combustion engine unit, determined by the formula in subsection (2); and
- Hpnetis the net quantity of useful thermal energy produced by the unit in a calendar year, expressed in GWh, determined by the formula in subsection (3).
Quantity of electricity — hybrid configuration
(2) The quantity of electricity generated by a given unit is determined by the formula
Gs − Gext
where
- Gsis the gross quantity of electricity that is generated by the generators of the shared steam turbine in the calendar year, expressed in GWh, as measured at the electrical terminals of the generators of the shared steam turbine using meters that comply with the requirements of the Electricity and Gas Inspection Act and the Electricity and Gas Inspection Regulations; and
- Gextis the quantity of electricity that is generated by the other unit, in the calendar year, expressed in GWh and that is determined by the formula
- where
- Gsis the gross quantity of electricity that is generated by the generators of the shared steam turbine in the calendar year, expressed in GWh, as measured at the electrical terminals of the generators of the shared steam turbine using meters that comply with the requirements of the Electricity and Gas Inspection Act and the Electricity and Gas Inspection Regulations,
- t is the tth hour, where "t" goes from the number 1 to p and where p is the total number of hours during which the generators of the shared steam turbine generated electricity in the calendar year,
- j is the jth external heat stream, originating from the other unit where "j" goes from the number 1 to m and where m is the total number of external heat streams that contributed to the electricity generated by the generators of the shared steam turbine of the unit,
- hext_jis the average specific enthalpy of the jth external heat stream, originating from the other unit that contributed to the electricity generated by the generators of the shared steam turbine, expressed in GJ/tonne, during period "t" and must be based on the measurement of the temperature and pressure of that heat stream and determined using a continuous measuring device,
- Mext_jis the mass flow of the jth external heat stream originating from the other unit that contributed to the electricity generated by the generators of the shared steam turbine, expressed in tonnes, during period "t", determined using a continuous measuring device,
- k is the kth internal heat stream originating from the given unit, where "k" goes from the number 1 to l and where l is the total number of heat streams that originated from the combustion of fuel in the unit and that contributed to the electricity generated by the generators of the shared steam turbine,
- hint_kis the average specific enthalpy of the kth internal heat stream originating from the given unit and having contributed to the electricity generated by the generators of the shared steam turbine, expressed in GJ/tonne, during period "t" and must be based on the measurement of the temperature and pressure of that heat stream and determined using a continuous measuring device, and
- Mint_kis the mass flow of the kth internal heat stream originating from the given unit that contributed to the electricity generated by the generators of the shared steam turbine, expressed in tonnes, during period "t", determined using a continuous measuring device.
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
where
- t is the tth hour, where "t" goes from the number 1 to p and where p is the total number of hours during which the unit produced useful thermal energy in the calendar year;
- i is the ith heat stream exiting the unit, where "i" goes from the number 1 to n and where n is the total number of heat streams exiting the unit;
- hout_iis the average specific enthalpy of the ith heat stream exiting the unit, expressed in GJ/tonne, during period "t" and must be based on the measurement of the temperature and pressure of that heat stream and determined using a continuous measuring device;
- Mout_iis the mass flow of the ith heat stream exiting the unit, expressed in tonnes, during period "t", determined using a continuous measuring device;
- j is the jth heat stream — other than condensate return — entering the unit, where "j" goes from the number 1 to m and where m is the total number of heat streams entering the unit;
- hin_jis the average specific enthalpy of the jth heat stream — other than condensate return — entering the unit, expressed in GJ/tonne, during period "t" and must be based on the measurement of the temperature and pressure of that heat stream and determined using a continuous measuring device; and
- Min_jis the mass flow of the jth heat stream — other than condensate return — entering the unit, expressed in tonnes, during period "t", determined using a continuous measuring device.
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
- (a) in accordance with section 13 or 14, using a CEMS; or
- (b) in accordance with sections 17 and 18, using a fuel-based method.
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
- Euis the quantity of CO2 emissions, expressed in tonnes, from the unit, "u", during the calendar year from the combustion of fuel, as measured by the CEMS, and calculated in accordance with sections 7.1 to 7.7 of the Reference Method; and
- Ebiois the quantity of CO2 emissions, expressed in tonnes, from the combustion of biomass in the unit during the calendar year, determined
- (a) by using the fuel-based method set out in sections 17 and 18 depending on whether the the biomass combusted is in a gaseous, liquid, or solid state, or
- (b) by using the following formula:
- ((Vbio⁄VT) × Eu) − Es
- where
- Vbiois the volume of CO2, expressed in standard m3, emitted from the combustion of biomass in the unit during the calendar year, determined in accordance with the formula set out in subsection (2),
- VTis the total volume of CO2 emitted from combustion of fuel in the unit for the production of electricity during the calendar year determined in accordance with the following formula:
- where
- t is the tth hour, where "t" goes from the number 1 to n and where n is the total number of hours during which the unit generated electricity in the calendar year,
- CO2w,tis the average concentration of CO2 in relation to all gases in the stack emitted from the combustion of fuel in the unit during each hour "t", during which the unit generated electricity in the calendar year — or, if applicable, a calculation made in accordance with section 7.4 of the Reference Method of that average concentration of CO2 based on a measurement of the concentration of oxygen (O2) in those gases in the stack — expressed as a percentage on a wet basis, and
- Qw,tis the average volumetric flow during that hour, measured on a wet basis by the stack gas volumetric flow monitor, expressed in standard m3,
- Euis the quantity of CO2 emissions, expressed in tonnes, from the unit "u" during the calendar year from the combustion of fuel, as measured by the CEMS, and calculated in accordance with section 7.1 to 7.7 of the Reference Method, and
- Esis the quantity of CO2 emissions, expressed in tonnes, that is released from the use of sorbent to control the emission of sulphur dioxide from the unit during the calendar year, determined in accordance with the following formula:
- S × R × (44/MMs)
- where
- S is the quantity of sorbent material, such as calcium carbonate (CaCO3), expressed in tonnes,
- R is the stoichiometric ratio, on a mole fraction basis, of CO2 released on usage of one mole of sorbent material, which is equal to 1 if the sorbent material is CaCO3, and
- MMsis the molecular mass of the sorbent material, which is equal to 100 if the sorbent material is CaCO3.
Vbio
(2) In subsection (1), Vbio is determined by the following formula:
VT − Vff
where
- VTis the total volume of CO2, determined in accordance with paragraph (b) of the description of Ebio in subsection (1); and
- Vffis the volume of CO2 emitted from combustion of fossil fuel in the unit during the calendar year, expressed in standard m3 and determined in accordance with the following formula:
where
- Qiis the quantity of fossil fuel type "i" combusted in the unit during the calendar year, determined
- (a) for a gaseous fuel, in the same manner used in the determination of Vf in the formula set out in paragraph 18(1)(a) and expressed in standard m3,
- (b) for a liquid fuel, in the same manner used in the determination of Vf in the formula set out in paragraph 18(1)(b) and expressed in kL, and
- (c) for a solid fuel, in the same manner used in the determination of Mf in the formula set out in paragraph 18(1)(c) and expressed in tonnes,
- i is the ith fossil fuel type combusted in the unit during the calendar year, where "i" goes from the number 1 to n and where n is the number of fossil fuels so combusted,
- Fc,iis the fuel-specific carbon-based F-factor for each fossil fuel type "i" — being the factor set out in Appendix A of the Reference Method, or for fuels not listed, the one determined in accordance with that Appendix — corrected to be expressed in standard m3 of CO2/GJ, and
- HHViis the higher heating value for each fossil fuel type "i" that is measured in accordance with subsection (3), or in the absence of a measured higher heating value, the default higher heating value, set out in column 2 of Schedule 2, for the fuel type, as set out in column 1.
Higher heating value
(3) The higher heating value of a fuel is to be measured
- (a) for a gaseous fuel,
- (i) in accordance with whichever of the following standards that applies:
- (A) ASTM D1826 - 94(2017), entitled Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter,
- (B) ASTM D3588 - 98(2017), entitled Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels,
- (C) ASTM D4891 - 13, entitled Standard Test Method for Heating Value of Gases in Natural Gas and Flare Gases Range by Stoichiometric Combustion,
- (D) Gas Processors Association Standard 2172 - 14, entitled Calculation of Gross Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer, and
- (E) Gas Processors Association standard 2261 - 13, entitled Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography, or
- (ii) by means of a direct measuring device that measures the higher heating value of the fuel, but if the measuring device provides only lower heating values, those lower heating values must be converted to higher heating values; and
- (i) in accordance with whichever of the following standards that applies:
- (b) for a liquid fuel that is
- (i) an oil or a liquid fuel derived from waste, in accordance with
- (A) ASTM D240 - 17, entitled Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, or
- (B) ASTM D4809 - 13, entitled Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), and
- (ii) any other liquid fuel type, in accordance with an applicable ASTM standard for the measurement of the higher heating value of the fuel type or, if no such ASTM standard applies, in accordance with an applicable internationally recognized method.
- (i) an oil or a liquid fuel derived from waste, in accordance with
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:
where
- Qu,jis the quantity of fuel type "j" combusted in that unit "u" during the calendar year, determined
- (a) for a gaseous fuel, in the same manner as the one used in the determination of Vf in the formula set out in paragraph 18(1)(a) and expressed in standard m3,
- (b) for a liquid fuel, in the same manner as the one used in the determination of Vf in the formula set out in paragraph 18(1)(b) and expressed in kL, and
- (c) for a solid fuel, in the same manner as the one used in the determination of Mf in the formula set out in paragraph 18(1)(c) and expressed in tonnes;
- HHVu,jis the higher heating value for each fossil fuel type "j" that is combusted in that unit "u" that is measured in accordance with subsection 14(3), or in the absence of a measured higher heating value, the default higher heating value, set out in column 2 of Schedule 2, for the fuel type, as set out in column 1.
- j is the jth fuel type combusted during the calendar year in a unit where "j" goes from the number 1 to y and where y is the number of those fuel types;
- Qi,jthe quantity of fuel type "j" combusted in each unit "i" during the calendar year, determined for a gaseous fuel, a liquid fuel and a solid fuel, respectively, in the manner set out in the description of Quj;
- HHVi,js the higher heating value for each fossil fuel type "j" that is combusted in that unit "i" that is measured in accordance with subsection 14(3), or in the absence of a measured higher heating value, the default higher heating value, set out in column 2 of Schedule 2, for the fuel type, as set out in column 1.
- i is the ith unit, where "i" goes from the number 1 to x, and where x is the number of units that share a common stack; and
- E is the quantity of CO2 emissions, expressed in tonnes, from the combustion of all fuels in all the units that share a common stack during the calendar year, measured by a CEMS at the common stack, and calculated in accordance with sections 7.1 to 7.7 of the Reference Method.
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
where
- i is the ith fossil fuel type that is combusted in the calendar year in a unit, where "i" goes from the number 1 to n and where n is the number of those fossil fuel types;
- Eiis the quantity of CO2 emissions that is attributable to the combustion of fossil fuels of type "i" in the unit in the calendar year, expressed in tonnes, as determined for that fuel type in accordance with section 18; and
- Esis the quantity of CO2 emissions that is released from the sorbent used to control the emission of sulphur dioxide from the unit in the calendar year, expressed in tonnes, as determined by the formula
S × R × (44/MMs)
- where
- S is the quantity of sorbent material, such as calcium carbonate (CaCO3), expressed in tonnes,
- R is the stoichiometric ratio, on a mole fraction basis, of CO2 released on usage of 1 mole of sorbent material, which is equal to 1 if the sorbent material is CaCO3, and
- MMsis the molecular mass of the sorbent material, which is equal to 100 if the sorbent material is CaCO3.
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:
- (a) for a gaseous fuel,
Vf × CCA × (MMA⁄MVcf) × 3.664 × 0.001
- where
- Vfis the volume of the fuel combusted in the calendar year, determined using flow meters, expressed in standard m3,
- CCAis the weighted average of the carbon content of the fuel, determined in accordance with subsection (2), expressed in kg of carbon per kg of the fuel,
- MMAis the average molecular mass of the fuel, determined based on fuel samples taken in accordance with section 19, expressed in kg per kg-mole of the fuel, and
- MVcfis the molar volume conversion factor of 23.645 standard m3 per kg-mole of the fuel at standard conditions;
- (b) for a liquid fuel,
Vf × CCA × 3.664
- where
- Vfis the volume of the fuel combusted in the calendar year, determined using flow meters, expressed in kL , and
- CCAis the weighted average of the carbon content of the fuel, determined in accordance with subsection (2), at the same temperature as that used in the determination of Vf, expressed in tonnes of carbon per kL of the fuel; and
- (c) for a solid fuel,
Mf × CCA × 3.664
- where
- Mfis the mass of the fuel combusted in the calendar year, determined, as the case may be, on a wet or dry basis using a measuring device, expressed in tonnes, and
- CCAis the weighted average of the carbon content of the fuel, determined in accordance with subsection (2), on the same wet or dry basis as that used in the determination of Mf, expressed in kg of carbon per kg of the fuel.
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
- where
- CCiis the carbon content of each sample or composite sample, as the case may be, of the fuel for the ith sampling period, expressed for gaseous fuels, liquid fuels and solid fuels, respectively, in the same unit of measure as that set out in CCA, as provided by the supplier of the fuel to the responsible person or, if not so provided, as determined by the responsible person, and measured
- (a) for a gaseous fuel,
- (i) in accordance with whichever of the following standards for the measurement of the carbon content of the fuel that applies:
- (A) ASTM D1945-14, entitled Standard Test Method for Analysis of Natural Gas by Gas Chromatography,
- (B) ASTM UOP539-12, entitled Refinery Gas Analysis by Gas Chromatography,
- (C) ASTM D7833-14, entitled Standard Test Method for Determination of Hydrocarbons and Non-Hydrocarbon Gases in Gaseous Mixtures by Gas Chromatography, and
- (D) API Technical Report 2572, 1st edition, published in May 2013 and entitled Carbon Content, Sampling, and Calculation, or
- (ii) by means of a direct measuring device that measures the carbon content of the fuel,
- (i) in accordance with whichever of the following standards for the measurement of the carbon content of the fuel that applies:
- (b) for a liquid fuel, in accordance with whichever of the following standards or methods for the measurement of the carbon content of the fuel that applies:
- (i) API Technical Report 2572, 1st edition, published in May 2013 and entitled Carbon Content, Sampling, and Calculation,
- (ii) ASTM D5291-16, entitled Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants,
- (iii) the ASTM standard that applies to the type of fuel, or
- (iv) if no ASTM standard applies, an applicable internationally recognized method, and
- (c) for a solid fuel, on the same wet or dry basis as that used in the determination of CCA, in accordance with,
- (i) for a solid fuel derived from waste, ASTM E777-08, entitled Standard Test Method for Carbon and Hydrogen in the Analysis Sample of Refuse-Derived Fuel, and
- (ii) for any other solid fuel, the following standard or method for the measurement of the carbon content of the fuel:
- (A) the ASTM standard that applies to the type of fuel, and
- (B) if no ASTM standard applies, an applicable internationally recognized method;
- (a) for a gaseous fuel,
- i is the ith sampling period that is referred to in section 19, where "i" goes from the number 1 to n and where n is the number of those sampling periods; and
- Qiis the volume or mass, as the case may be, of the fuel combusted during the ith sampling period, expressed
- (a) in standard m3, for a gaseous fuel,
- (b) in kL, for a liquid fuel, and
- (c) in tonnes, for a solid fuel, on the same wet or dry basis as that used in the determination of CCA.
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:
- (a) for natural gas, during each sampling period consisting of each year that the unit generates electricity or produces useful thermal energy, two samples taken that year, with each of those samples being taken at least four months after any previous sample has been taken, in accordance with whichever of the following standard that applies:
- (i) ASTM D4057-12, entitled Standard Practice for Manual Sampling of Petroleum and Petroleum Products,
- (ii) ASTM D4177-16e1, entitled Standard Practice for Automatic Sampling of Petroleum and Petroleum Products,
- (iii) ASTM D5287-08(2015), entitled Standard Practice for Automatic Sampling of Gaseous Fuels, and
- (iv) ASTM F307-13, entitled Standard Practice for Sampling Pressurized Gas for Gas Analysis;
- (b) for refinery gas, during each sampling period consisting of each day that the unit generates electricity or produces useful thermal energy, one sample per day that is taken at least six hours after any previous sample has been taken, in accordance with any applicable standard referred to in paragraph (a);
- (c) for a type of liquid fuel or of a gaseous fuel other than refinery gas and natural gas, during each sampling period consisting of each week that the unit generates electricity or produces useful thermal energy, one sample per week that is taken at least 72 hours after any previous sample has been taken, in accordance with any of the standards referred to in paragraph (a); and
- (d) for a solid fuel, one composite sample per month that consists of sub-samples, each having the same mass, that are taken from the fuel that is fed for combustion during each week that begins in that month and during which the unit generates electricity or produces useful thermal energy, and after all fuel treatment operations have been carried out but before any mixing of the fuel from which the sub-sample is taken with other fuels, and at least 72 hours after any previous sub-sample has been taken.
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:
- (a) a report containing the information set out in Schedule 1 in respect of each calendar year in which the unit meets the conditions set out in subsection 3(1) or (2), as the case may be;
- (b) a short report containing the information referred to in sections 1 and 2, except paragraph 2(h), of Schedule 1 in respect of each calendar year in which the unit no longer meets one of the conditions referred to in subsection 3(1) or (2), as the case may be.
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:
- (a) any notice referred to in subsection 21(4) that was sent to the Minister along with supporting documents;
- (b) any application referred to in subsection 7(3) or 8(2), whichever applies, along with supporting documents;
- (c) every measurement and calculation used to determine the value of an element of a formula used, for the purposes of section 4 and, if applicable, section 5 along with supporting documents necessary to determine the value of those elements;
- (d) an indication of which of the ASTM standards and methods referred to in the description of CCi in subsection 18(2) were used to determine the value of CCA in paragraph 18(1)(a), (b) or (c), as the case may be, or, for a sample of gaseous fuel, a statement that indicates that a direct measuring device was used to determine that value;
- (e) information demonstrating that any meter referred to in section 11 complies with the requirements of the Electricity and Gas Inspection Act and the Electricity and Gas Inspection Regulations, including a certificate referred to in section 14 of that Act;
- (f) information demonstrating that the installation, maintenance and calibration of the measuring devices referred to in subsection 9(1) were done in accordance with that subsection and subsection 9(2) and that the measuring devices used comply with subsection 9(3);
- (g) supporting documents that confirm the CEMS certification under section 10;
- (h) any document, record or information referred to in section 8 of the Reference Method, for each calendar year during which a responsible person used a CEMS;
- (i) the results of the analysis of every sample taken in accordance with section 19;
- (j) information demonstrating the unit capacity set out in the annual report;
- (k) in the case of a unit that has a combustion engine that is temporarily installed for a period of 90 days or less as part of repair or maintenance,
- (i) evidence that the combustion engine underwent repairs or maintenance and that a replacement combustion engine was temporarily connected to the unit for the duration of the repairs or maintenance,
- (ii) the number of days that a replacement combustion engine was connected to the unit, and
- (iii) the number of days that the repairs or maintenance lasted;
- (l) information demonstrating each combustion engine capacity set out in the annual report, the date that each combustion engine was installed and, in the case of a combustion engine with a capacity of 150 MW or less, information demonstrating that, if applicable, the combustion engine was installed to replace an engine, with a capacity of 150 MW or less, as part of repair or maintenance.
- (m) any report referred to in section 22, along with supporting documents; and
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:
- (a) an indication of whether they are the owner or operator of the unit and their name and civic address;
- (b) the name, title, civic and postal addresses, telephone number and, if any, email address and fax number of their authorized official; and
- (c) the name, title, civic and postal addresses, telephone number and, if any, email address and fax number of a contact person, if different from the authorized official.
2 The following information respecting the unit:
- (a) for each responsible person for the unit, other than the responsible person mentioned in paragraph 1(a), if any,
- (i) their name, title and civic address, and
- (ii) an indication of whether they are the owner or operator;
- (b) the unit's name and civic address, if any;
- (c) the unit's registration number, if any;
- (d) the name of the facility where the unit is located;
- (e) the facility's National Pollutant Release Inventory identification number assigned by the Minister for the purposes of section 48 of the Act, if any;
- (f) the unit's registration number, if any, assigned by the Minister under subsection 4(2) of the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations;
- (g) whether the unit is a boiler unit or a combustion engine unit;
- (h) a process flow diagram that shows
- (i) the unit's major equipment that operates together to generate electricity and, if applicable, produce thermal energy, including boilers, combustion engines, duct burners and other combustion devices, heat recovery systems, steam turbines, generators and emission control devices,
- (ii) the unit boundaries used to identify the unit,
- (iii) the electric flows crossing the unit boundaries, and
- (iv) the heat streams crossing the unit boundaries and an indication of their average temperature, pressure and hourly mass flow rate;
- (i) the unit's capacity;
- (j) for each of the unit's combustion engines, the engine capacity and the date that each combustion engine was installed, and in the case of combustion engine with a capacity of 150 MW or less, information demonstrating that, if applicable, the combustion engine was installed to replace an engine, with a capacity of 150 MW or less, as part of repair or maintenance;
- (k) the unit's potential electrical output, expressed in GWh;
- (l) as the case may be,
- (i) in the case of a combustion engine unit, the percentage of the unit's potential electrical output that is sold or distributed to the electric grid, and
- (ii) in the case of a boiler unit, the quantity of electricity that is sold or distributed to the electric grid;
- (m) the percentage of the unit's heat input that comes from natural gas, on average; and
- (n) in the case of a boiler unit, the value of the unit's heat to electricity ratio.
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:
- (a) the emission intensity for the unit — that is, the ratio of the quantity of CO2 emissions referred to in paragraph (c) to the quantity of energy referred to in subparagraph (b)(i) — expressed in tonnes per GWh;
- (b) in respect of the quantity of energy produced by the unit,
- (i) that quantity determined in accordance with section 11 of these Regulations, expressed in GWh,
- (ii) the value determined for G and Hpnet in the formula set out in subsection 11(1) of these Regulations, expressed in GWh, and
- (iii) the value determined for Gs and Gext in the formula set out in subsection 11(2) of these Regulations, expressed in GWh;
- (c) in respect of the quantity of CO2 emissions from the combustion of fuels in the unit,
- (i) if paragraph 12(a) of these Regulations applies, the result of the calculation made in accordance with sections 13 and 14 of these Regulations, expressed in tonnes, and
- (ii) if paragraph 12(b) of these Regulations applies, the result of the calculation made in accordance with sections 17 and 18 of these Regulations, expressed in tonnes; and
- (d) for each type of fuel combusted,
- (i) the type and, if that type is biomass, an explanation of why that type is biomass as defined in subsection 2(1) of these Regulations, and
- (ii) the quantity of fuel combusted.
4 The following information:
- (a) in the case of a unit that is granted an exemption under paragraph 7(4)(a) of these Regulations, the duration of the emergency circumstance, such as the day in the calendar year on which the circumstance arose and the day in the calendar year on which it ceased; and
- (b) in the case of a unit referred to in subsection 4(4) of these Regulations that is temporarily connected to one or more replacement combustion engines,
- (i) the duration of the repairs or maintenance, such as the day in the calendar year on which the repairs or maintenance began and the day in the calendar year on which they ended, and
- (ii) the reason why the replacement combustion engine was used.
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:
- (a) the reason why data required to determine the value of an element of a formula referred to in section 11, 14 or 15 of these Regulations was not obtained and an explanation why that reason was beyond the responsible person's control;
- (b) the element of the formula for which data was not obtained and the date of the day on which the data were not obtained and, if that data were not obtained for a period of several days, the dates of the days on which the period begins and ends; and
- (c) the value determined for the element referred to in paragraph (b) using replacement data, along with details of that determination, including
- (i) the data used to make that determination for each period of one or more days,
- (ii) the method used to obtain that data, and
- (iii) in the case of a determination of the value of an element referred to in subsection 20(3) of these Regulations, a justification for the given period being used as the basis of that determination.
SCHEDULE 2
(Subsections 14(2) and 15(2))
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 |
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 |
- Note 1 The default higher heating value and the default CO2 emission factor for propane are only for pure gas propane. The product commercially sold as propane is to be considered LPG for the purpose of these Regulations.
- Note 2 The default higher heating value for pipeline quality natural gas is expressed in GJ/standard m3
- Note 3 The default higher heating value for pipeline quality natural gas is expressed in GJ/standard m3
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
- (a) the responsible person's use of the CEMS complied with the Quality Assurance/Quality Control manual referred to in section 6.1 of the Reference Method; and
- (b) the responsible person complied with the Reference Method and the CEMS met the specifications set out in the Reference Method, in particular, in its sections 3 and 4.
4 A statement of the auditor's opinion as to whether
- (a) the responsible person's use of the CEMS complied with the Quality Assurance/Quality Control manual referred to in Section 6.1 of the Reference Method; and
- (b) the responsible person complied with the Reference Method and the CEMS met the specifications set out in the Reference Method, in particular, in its sections 3 and 4.
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:
- (a) an indication of whether they are the owner or operator of the unit and their name and civic address;
- (b) the name, title, civic and postal addresses, telephone number and, if any, email address and fax number of their authorized official; and
- (c) the name, title, civic and postal addresses, telephone number and, if any, email address and fax number of a contact person, if different from the authorized official.
2 The following information respecting the unit:
- (a) for each responsible person for the unit, other than the responsible person mentioned in paragraph 1(a), if any,
- (i) their name, title and civic address, and
- (ii) an indication of whether they are the owner or operator;
- (b) the unit's name and civic address, if any;
- (c) the unit's registration number, if any;
- (d) the name of the facility where the unit is located;
- (e) the facility's National Pollutant Release Inventory identification number assigned by the Minister for the purposes of section 48 of the Act, if any;
- (f) the unit's registration number, if any, assigned by the Minister under subsection 4(2) of the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations; and
- (g) the unit's capacity.
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:
- (a) the emission intensity for the unit — that is, the ratio of the quantity of CO2 emissions referred to in paragraph (c) to the quantity of energy referred to in paragraph (b) — expressed in tonnes per GWh;
- (b) in respect of the quantity of energy produced by the unit, the value determined for Gs;
- (c) in respect of the quantity of CO2 emissions from the combustion of fuel in the unit,
- (i) if paragraph 12(a) of these Regulations applies, the result of the calculation made in accordance with sections 13 and 14 of these Regulations, expressed in tonnes, or
- (ii) if paragraph 12(b) of these Regulations applies, the result of the calculation made in accordance with sections 17 and 18 of these Regulations, expressed in tonnes; and
- (d) in respect of each type of fuel combusted, the quantity combusted.
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]