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

Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations Whereas, pursuant to subsection 332(1)a of the Canadian Environmental Protection Act, 1999b, the Minister of the Environment published in the Canada Gazette, Part I, on August 27, 2011, a copy of the proposed Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, substantially in the annexed form, and persons were given an opportunity to file comments with respect to the proposed Regulations or to file a notice of objection requesting that a board of review be established and stating the reasons for the objection; S.C. 2004, c. 15, s. 31 S.C. 1999, c. 33 Whereas, pursuant to subsection 93(3) of that Act, the National Advisory Committee has been given an opportunity to provide its advice under section 6c of that Act; S.C. 2002, c. 7, s. 124 And whereas, in accordance with subsection 93(4) of that Act, the Governor in Council is of the opinion that the proposed Regulations do not regulate an aspect of a substance that is regulated by or under any other Act of Parliament in a manner that provides, in the opinion of the Governor in Council, sufficient protection to the environment and human health; Therefore, His Excellency the Governor General in Council, on the recommendation of the Minister of the Environment and the Minister of Health, pursuant to subsections 93(1)and 330(3.2)d of the Canadian Environmental Protection Act, 1999b, makes the annexed Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations. S.C. 2008, c. 31, s. 5 Purpose These Regulations establish a regime for the reduction of carbon dioxide (CO2) emissions that result from the production of electricity by means of thermal energy using coal as a fuel, whether in conjunction with other fuels or not. Contents These Regulations are divided into four Parts as follows: Part 1 sets out a performance standard for the intensity of CO2 emissions from regulated units and provides for exceptions based on the substitution of units and for temporary exemptions in relation to emergencies and units integrated with carbon capture and storage systems; Part 2 sets out requirements for the reporting, sending, recording and retention of information; Part 3 sets out quantification rules for determining the intensity of CO2 emissions from regulated units; and Part 4 provides dates for the coming into force of these Regulations and, in particular, delays the coming into force of the performance standard in respect of standby units until January 1, 2030. Definitions The following definitions apply in these Regulations. Act means the Canadian Environmental Protection Act, 1999. (Loi) ASTM means ASTM International, formerly known as the American Society for Testing and Materials. (ASTM) auditor means a person who is independent of the responsible person who is to be audited; and has demonstrated knowledge of and experience in the certification, operation and relative accuracy test audit (RATA) of continuous emission monitoring systems, and quality assurance and quality control procedures in relation to those systems. (vérificateur) authorized official means in respect of a responsible person that is a corporation, an officer of the corporation who is authorized to act on its behalf; in respect of a responsible person that is an individual, that person or a person authorized to act on that individual’s behalf; and 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 come from a geological formation, and includes gases and liquids recovered from organic waste. (biomasse) calendar year[Repealed, SOR/2018-263, s. 1] capacity factor, in respect of a unit in a calendar year, means the ratio of the quantity of electricity referred to in section 19 that is produced by the unit to the quantity of electricity that would be produced by the unit in the calendar year if it were to operate at its production capacity at all times during the calendar year. (facteur de capacité) coal includes petroleum coke and synthetic gas that is derived from coal or petroleum coke. (charbon) commissioning date means for an electricity generator that began producing electricity by means of thermal energy using a fuel other than coal, and not in conjunction with coal, but that was converted into a unit before June 23, 2010, the day on which that generator began to produce electricity for sale to the electric grid using fuel other than coal, and not in conjunction with coal; and in any other case, the day on which a unit begins to produce electricity for sale to the electric grid. (date de mise en service) existing unit means a unit that is neither an old unit nor a new unit. (groupe existant) fossil fuel means a fuel other than biomass. (combustible fossile) front end engineering design study means a collection of studies that provide the necessary details to support the carrying out of a construction project for the capture element of a carbon capture and storage system, including technical drawings and documents that describe the capture element in sufficient detail to permit the tendering of a contract for its construction; an estimation of the capital cost of the capture element with a margin of error of ± 20%; a safety review of the capture element; a risk assessment of the carbon capture and storage system, namely an assessment of the risks that may delay or prevent the completion of the construction of the system, including technical, economic, environmental, legal and labour-related risks; a strategy to mitigate those risks; and a detailed plan to carry out the construction of the carbon capture and storage system, including a schedule for the completion of its major steps. (étude d’ingénierie d’avant-projet détaillé) gasification system includes a gasification system that is in part located underground. (système de gazéification) GPA means the Gas Processors Association of the United States. (GPA) major equipment means a boiler, gasifier, shift reactor, turbine, air pollution control device, air separation unit, compressor, CO2 separation system or other equipment that is manufactured in accordance with specifications in its purchase order and takes more than 12 months after the date of the purchase order to be manufactured and delivered; or costs $10,000,000 or more. (équipement majeur) new unit means a unit, other than an old unit, whose commissioning date is on or after July 1, 2015. (groupe nouveau) old unit means a unit that has reached the end of its useful life but continues to produce electricity. (groupe en fin de vie utile) operator means the person that operates or has the charge, management or control of a unit. (exploitant) power plant means all units, buildings and other structures and all stationary equipment — including equipment for the separation and initial pressurization of CO2 of the capture element of a carbon capture and storage system — on a single site, or on adjacent sites that function as a single integrated site, whose primary purpose is the production of electricity for sale to the electric grid. (centrale électrique) production capacity, in relation to a unit and a calendar year, means the maximum continuous rating of the unit, expressed in MW, as most recently reported to a provincial authority of competent jurisdiction or to the electric system operator in the province where the unit is located; or if no report has been made, the most electricity that was produced for sale by the unit, expressed in MW, during two continuous hours in that calendar year. (capacité de production) 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 m3 has the meaning assigned to a cubic metre at standard pressure and standard temperature by the definition standard volume in subsection 2(1) of the Electricity and Gas Inspection Regulations. (m3 normalisé) standby unit means an old unit that, for a given calendar year, operates at a capacity factor of 9% or less. (groupe de réserve) unit means physically connected equipment located in a power plant — including boilers and other combustion devices, gasifiers, reactors, turbines, generators and emission control devices — that operates together to produce electricity by means of thermal energy using coal as a fuel, whether in conjunction with other fuels or not. (groupe) useful life, in respect of a unit, means the period that begins on the commissioning date and ends on for a unit other than a unit referred to in paragraph (a) of the definition commissioning date, in the case of a unit whose commissioning date is before 1975, the earlier of December 31 of the calendar year that is 50 years after the commissioning date, and December 31, 2019, and in the case of a unit whose commissioning date is after 1974, the earlier of December 31, 2029; and for a unit referred to in paragraph (a) of the definition commissioning date, 18 months after the applicable date described in paragraph (a). (vie utile) Interpretation of incorporated documents For the purposes of interpreting documents 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 Any standard of the ASTM or GPA that is incorporated by reference into these Regulations is incorporated as amended from time to time. Limit — 420t/GWh A responsible person for a new unit or an old unit must not, on average, emit with an intensity of more than 420 tonnes CO2 emissions from the combustion of fossil fuels in the unit for each GWh of electricity produced by the unit during a calendar year. Quantification of electricity and emissions The quantity of electricity referred to in subsection (1) is to be determined in accordance with section 19; and emissions referred to in subsection (1) are to be determined in accordance with the applicable provisions of sections 20 to 24. CO2 released from sorbent The CO2 emissions released from the use of sorbent to control the emission of sulphur dioxide from a unit are to be included as CO2 emissions from the combustion of fossil fuels in that unit for the purpose of subsection (1). Coal gasification systems Emissions from a gasification system that produces synthetic gas derived from coal or petroleum coke that is used as a fuel to produce electricity from a unit referred to in subsection (1) are to be included as emissions from that unit, for the purpose of subsection (1), if that coal gasification system has at least one responsible person in common with that unit. CCS excluded The CO2 emissions from a unit referred to in subsection (1) do not include emissions that are captured in accordance with the laws of Canada or a province that regulate that capture; are transported and stored in accordance with the laws of Canada or a province, or of the United States or one of its states, that regulate that transportation or storage, as the case may be; and are not subsequently released into the atmosphere. Partial year application For greater certainty, if subsection (1) applies in respect of a unit only for a period during a calendar year, that period is considered to be the calendar year for the purpose of that subsection. Registration A responsible person for a new unit must register the new unit by sending to the Minister, on or before 30 days after its commissioning date, a registration report that contains the information set out in Schedule 1. Registration number On receipt of the registration report, the Minister must assign a registration number to the unit and inform the responsible person of that registration number. Change of information If the information provided in the registration report changes or if the unit is decommissioned, the responsible person must, not later than 30 days after the change or decommissioning, send to the Minister a notice that provides the updated information or that indicates the unit has been decommissioned, as the case may be, along with the date of the decommissioning. Application of subsection 3(1) — substituted units For the purpose of subsection 3(1), a responsible person for a unit (referred to in this section as the “original unit”) that reaches the end of its useful life during a calendar year may apply to the Minister to have another unit (referred to in this section as the “substituted unit”) substituted for the original unit if the following conditions are satisfied: the substituted unit is an existing unit; the original unit and the substituted unit have a common owner who has an ownership interest of 50% or more in each of those two units; those two units are located in the same province; and the production capacity of the substituted unit, during the calendar year preceding the calendar year in which the application is made, was equal to or greater than the production capacity of the original unit during that preceding calendar year. Period of application The application must be made in the period that begins on January 1 and that ends on May 31 of the calendar year during which the unit reaches its end of life. Content of application The application must include the registration number of the original unit and of the substituted unit and information, with supporting documentation, to demonstrate that the conditions of paragraphs (1)(b) to (d) are satisfied. Granting of substitution The Minister must, within 30 days after receiving the application, grant the substitution if the following conditions are satisfied: the substituted unit is not a shut-down unit referred to in subsection 6(4); the substituted unit is not involved in an exemption granted under subsection 14(4); and the Minister is satisfied that the conditions of paragraphs (1)(a) to (d) are satisfied. Effect On the granting of the substitution, subsection 3(1) applies in respect of the substituted unit rather than the original unit as of the later of July 1, 2015, and the beginning of the calendar year that follows the calendar year in which the application is made. Cessation of effect The substitution referred to in subsection (5) ceases to have effect, and subsection 3(1) applies in respect of the original unit, as of the earliest of the calendar year that follows the day on which the responsible person for that unit and the substituted unit sends the Minister a notice indicating that they wish the substitution to no longer have an effect, the calendar year that follows the day on which the condition of paragraph (1)(b) is no longer satisfied, the calendar year that follows a calendar year during which the production capacity of the original unit was more than the production capacity of the substituted unit referred to in paragraph (1)(d), the calendar year that follows the end of the useful life of the substituted unit, and a calendar year during which electricity is produced by the substituted unit by means of thermal energy using fossil fuel other than coal, and not in conjunction with coal. Deferral of application of subsection 3(1) A responsible person for an existing unit that ceases to produce electricity after June 30, 2015 (referred to in this section as the “shut-down unit”) may apply to the Minister to have the application of subsection 3(1) deferred in respect of another unit or units (referred to in this section as the “deferred units”) for the number of years in the period that begins on January 1 of the calendar year that follows that cessation and that ends on December 31 of the calendar year in which the useful life of the shut-down unit ends. If the application is granted, the application of subsection 3(1) is, in respect of each calendar year in that period, deferred for the deferred unit and the calendar year that begins after the end of that deferred unit’s useful life that the responsible person specifies in their application. Conditions of application for deferral The application may be made only if the following conditions are satisfied: the shut-down unit and each of the specified deferred units have a common owner who has an ownership interest of 50% or more in the shut-down unit and in each of those specified deferred units; the shut-down unit and each of those specified deferred units are located in the same province; and the production capacity of the shut-down unit, during the calendar year preceding the day on which it ceased production, was greater than or equal to the production capacity of each of those specified deferred units during the calendar year preceding the day on which the application was made. The application must be made on or before May 31 of the calendar year preceding the earliest of the specified calendar years referred to in subsection (1) and must indicate the calendar years included in the period referred to in subsection (1); specify the deferred unit referred to in subsection (1) in respect of each of the calendar years referred to in paragraph (a); for each of those specified deferred units in respect of each of those calendar years, specify the calendar year that begins after the end of the useful life of the unit for which the application of subsection 3(1) is to be deferred; indicate the registration number of the shut-down unit and of each of the specified deferred units; and include information, with supporting documentation, to demonstrate that the conditions of paragraphs (2)(a) to (c) are satisfied. Granting of deferral The Minister must, within 30 days after receiving the application, grant the deferral if the following conditions are satisfied: the shut-down unit is not a substituted unit referred to in subsection 5(5); no deferred unit is a unit that is involved in a temporary exemption granted under subsection 9(3); and the Minister is satisfied that the conditions of paragraphs (2)(a) to (c) are satisfied; No recommencement of shut-down unit It is prohibited for any person to cause the shut-down unit to recommence producing electricity after the application of subsection 3(1) is deferred in respect of a specified deferred unit. Changes to deferred units The responsible person referred to in subsection (1) may change the specified deferred unit in respect of a specified calendar year referred to in paragraph (3)(c) by sending a notice to the Minister if that specified calendar year is not one for which the application of subsection 3(1) has been deferred. The notice must include the registration number of the proposed new specified deferred unit; the calendar year that begins after the end of the useful life of the proposed new specified deferred unit for which the application of subsection 3(1) is to be deferred; and information, with supporting documentation, to demonstrate that the conditions of paragraphs (2)(a) and (b) are satisfied in respect of the proposed new specified deferred unit and the condition of paragraph (2)(c) is satisfied in respect of each specified deferred unit, including the proposed new specified deferred unit, during the calendar year preceding the day on which the notification is sent. Allowance of changes The Minister must, within 30 days after receiving the notification, allow the change if the Minister is satisfied that the demonstration referred to in subsection (6) has been made. Despite subsection (1), the deferral ceases to have effect and subsection 3(1) applies in respect of the specified deferred units as of the earliest of the calendar year that follows the calendar year in which the application is made, if a shut-down unit referred to in subsection (1) has not ceased to produce electricity by January 1 of that following calendar year, any calendar year in which a shut-down unit referred to in subsection (1) recommences to produce electricity, the calendar year that follows the day on which the Minister receives a notice from the responsible person for the shut-down unit and the deferred units indicating that they wish the deferral to no longer have an effect, the calendar year that follows the day on which the condition of paragraph (2)(a) is no longer satisfied, and the calendar year that follows a specified calendar year referred to in paragraph (3)(c) in which the specified deferred unit referred to in that paragraph had a production capacity greater than the production capacity of the shut-down unit during the calendar year preceding the day on which it ceased production. Conditions for application A responsible person for a unit may, under emergency circumstances described in subsection (2), apply to the Minister for an exemption from the application of subsection 3(1) in respect of the unit if the following conditions are satisfied: as a result of the emergency circumstances, there is a disruption, or a significant risk of disruption, to the electricity supply in the province where the unit is located; and the operation of the unit will end, decrease the risk of, or mitigate the consequences of, the disruption. Criteria of emergency circumstances An emergency circumstance is a circumstance that arises due to an extraordinary, unforeseen and irresistible event; or 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. Application The responsible person must, within 15 days after the emergency circumstance arises, provide the Minister with their application. The application must include the unit’s registration number, the date on which the emergency circumstance arose and information, with supporting documentation, to demonstrate that the conditions of paragraphs (1)(a) and (b) are satisfied. Granting of exemption The Minister must, within 30 days after receiving the application, grant the exemption if the Minister is satisfied that the conditions of paragraphs (1)(a) and (b) are satisfied. Period of exemption The exemption has effect as of the day on which the emergency circumstance arose and ceases to have effect on the earliest of the day that is 90 days after that day, the day specified by the Minister, and the earlier of the day on which the event 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 the day on which the measure, if any, referred to in paragraph (2)(b) ceases to be in effect. Extension If paragraphs 7(1)(a) and (b) will continue to apply on and after the day on which an exemption granted under subsection 7(4) is to cease to have effect, the responsible person may, before that day, apply to the Minister for an extension of the exemption. The application must include the unit’s registration number and information, with supporting documentation, to demonstrate that paragraphs 7(1)(a) and (b) will continue to apply after the day on which the exemption is to cease to have effect; and steps — other than the operation of the unit during the period of the exemption — have been, and are being, taken to end, decrease the risk of, or mitigate the consequences of, the disruption. Granting of extension The Minister must, within 15 days after receiving the application, grant the extension if the Minister is satisfied that paragraphs (2)(a) and (b) have been demonstrated. Duration The extension ceases to have effect on the earliest of the day that is 90 days after the day on which the application for the extension was made, the day referred to in paragraph 7(5)(c). A responsible person for a new unit or an old unit may apply to the Minister for a temporary exemption from the application of subsection 3(1) in respect of the unit if in the case of a new unit, the unit is designed to permit its integration with a carbon capture and storage system that is to be constructed; and in the case of an old unit, the unit may be retrofitted to permit its integration with a carbon capture and storage system that is to be constructed. Granting and content of application The application must indicate the unit’s registration number and include the following supporting documents and information: a declaration that includes statements indicating that based on the economic feasibility study referred to in paragraph (b), the unit, when operating with an integrated carbon capture and storage system is, to the best of the responsible person’s knowledge and belief, economically viable, and based on the technical feasibility study referred to in paragraph (c) and the implementation plan referred to in paragraph (e), the responsible person expects to satisfy the requirements set out in section 10 and, as a result, to be in compliance with subsection 3(1) by January 1, 2025; an economic feasibility study that demonstrates the economic viability of the unit when it operates with an integrated carbon capture and storage system and that provides project cost estimates, with their margin of error, for the construction of the integrated carbon capture and storage system, and identifies the source of financing for that construction; a technical feasibility study that establishes — based on information referred to in Schedule 2 related to the capture, transportation and storage elements of the carbon capture and storage system — that there are no insurmountable technical barriers to carrying out the following activities: capturing a sufficient volume of CO2 emissions from the combustion of fossil fuels in the unit to enable the responsible person to comply with subsection 3(1), transporting the captured CO2 emissions to suitable geological sites for storage, and storing the captured CO2 emissions in those suitable geological sites; a description of any work that has been done to satisfy the requirements set out in section 10, along with the information referred to in Schedule 3 with respect to that work; and an implementation plan that provides a description of the work to be done, with a schedule for the steps necessary to achieve the following objectives: satisfaction of the requirements set out in section 10, and compliance of the responsible person with subsection 3(1) by January 1, 2025 when the unit is operating with an integrated carbon capture and storage system that captures CO2 emissions from the combustion of fossil fuels in the unit in accordance with the laws of Canada or a province that regulate that capture and that transports and stores those emissions in accordance with the laws of Canada or a province, or of the United States or one of its states, that regulate that transportation or storage, as the case may be. Granting of temporary exemption The Minister must, within 120 days after receiving the application, grant the temporary exemption if the application includes the documents referred to in subsection (2); and the information contained in those documents can reasonably be regarded as establishing that the unit, when operating with an integrated carbon capture and storage system, will be economically viable, the capture, transportation and storage elements of the carbon capture and storage system will be technically feasible, if applicable, a requirement set out in section 10 has been satisfied by work done before the application was made, and the responsible person will satisfy the requirements set out in section 10 and, as a result, will be in compliance with subsection 3(1) by January 1, 2025 when the unit is operating with an integrated carbon capture and storage system. A temporary exemption, unless revoked under section 13, remains in effect until December 31, 2024. Requirements A responsible person who has been granted a temporary exemption in respect of a unit under subsection 9(3) must satisfy the following requirements: carry out a front end engineering design study by January 1, 2020; purchase any major equipment that is necessary for the capture element by January 1, 2021; enter into any contract required for the transportation and storage of CO2 emissions from the unit by January 1, 2022; take all necessary steps to obtain all permits or approvals required in relation to the construction of the capture element by January 1, 2022; and ensure that the unit, when operating with an integrated carbon capture and storage system, captures CO2 emissions from the combustion of fossil fuels in the unit in accordance with the laws of Canada or a province that regulate that capture and transports and stores those emissions in accordance with the laws of Canada or a province, or of the United States or one of its states, that regulate that transportation or storage, as the case may be, by January 1, 2024. Implementation report A responsible person who has been granted a temporary exemption in respect of a unit must, for each calendar year following the granting of the temporary exemption, provide the Minister with an implementation report that indicates the unit’s registration number and includes supporting documents that contain the following information: the steps taken during that year to construct the capture, transportation and storage elements of the carbon capture and storage system and to integrate those elements with the unit; any requirement set out in section 10 that was satisfied during that year, along with the information and documents referred to in Schedule 3; a description of the manner in which those steps were carried out or those requirements were satisfied; any changes, with respect to the information most recently provided to the Minister, to the proposed engineering design for the capture element, to the preferred transportation methods or routes or to the preferred storage sites, for the carbon capture and storage system; and a description of any steps necessary, with a schedule for those steps, to achieve the following objectives: the satisfaction of any requirements set out in section 10 that remain to be satisfied, and the compliance of the responsible person with subsection 3(1) by January 1, 2025 when the unit is operating with an integrated carbon capture and storage system that captures CO2 emissions from the combustion of fossil fuels in the unit in accordance with laws of Canada or a province that regulate that capture and transports and stores those emissions in accordance with laws of Canada or a province, or of the United States or one of its states, that regulate, as the case may be, that transportation or storage. Due date The implementation report must be provided by March 31 of the calendar year that follows the calendar year in question. Updated information If any event occurs or any circumstance arises that may prejudice the ability of the responsible person to achieve an objective referred to in paragraph 11(1)(e), the responsible person must send to the Minister, without delay, a notice that indicates the unit’s registration number and contains the following information: a description of the event or circumstance and the nature of the prejudice; an explanation of how the prejudice is to be overcome in order to ensure that the objective will be achieved; and in relation to that explanation, an update to any information previously provided to the Minister under paragraphs 11(1)(c) to (e), together with any necessary supporting documents. Revocation — non-satisfaction or misleading information The Minister must revoke a temporary exemption granted under subsection 9(3) if the responsible person does not satisfy a requirement set out in section 10; or any information indicated or contained in the application for the temporary exemption, in an implementation report referred to in section 11 or in a notice referred to in section 12 is false or misleading. Revocation — implementation report or reasonable grounds The Minister may revoke the temporary exemption if the responsible person has not provided an implementation report in accordance with section 11; there are reasonable grounds for the Minister to believe that the carbon capture and storage system will not operate so as to capture, transport and store CO2 emissions as described in paragraph 10(e) by the date referred to in that paragraph; or there are reasonable grounds for the Minister to believe that the responsible person will not emit CO2 from the combustion of fossil fuels in the unit in accordance with subsection 3(1) by January 1, 2025. Reasons and representations The Minister must not revoke the temporary exemption under subsection (1) or (2) unless the Minister has provided the responsible person with written reasons for the proposed revocation; and an opportunity to be heard, by written representation, in respect of the proposed revocation. Exemption A responsible person for an old unit may, on application made to the Minister, be exempted from the application of subsection 3(1) in respect of the old unit for a period of 24 consecutive months that begins on January 1 of the calendar year that follows the calendar year in which the application is made if the following conditions are satisfied: an existing unit and the old unit have a common owner who has a ownership interest of 50% or more in each of those two units; the production capacity of the existing unit, during the calendar year preceding the calendar year in which the application is made, was equal to or greater than the production capacity of the old unit during that preceding calendar year; the existing unit and the old unit are located in the same province; the quantity of CO2 emissions from the combustion of fossil fuels in the existing unit is determined in accordance with a system or method referred to in subsection 20(1); the quantity of CO2 emissions from the combustion of fossil fuels in the existing unit that are captured, transported and stored is determined using a direct measure of the flow of, and the concentration of CO2 in, the emissions from that combustion of fuel; the emissions referred to in paragraph (e) are captured in accordance with the laws of Canada or a province that regulate that capture and are transported and stored in accordance with the laws of Canada or a province, or of the United States or one of its states, that regulate that transportation or storage, as the case may be; the emissions referred to in paragraph (e) are captured, transported and stored for a period of seven consecutive calendar years; the emissions referred to in paragraph (e) comprise at least 30% of the quantity of CO2 emissions produced from the combustion of fossil fuels in the existing unit for each calendar year during that seven-year period; and the existing unit does not reach the end of its useful life during that seven-year period. A responsible person for an old unit must apply for the exemption before September 1 of the calendar year preceding the calendar year for which the exemption is sought. The application must include the registration number of the old unit and of the existing unit and information, with supporting documentation, to demonstrate that the conditions of paragraphs (1)(a) to (f), (h) and (i) are satisfied; and at least 30 consecutive months of the period referred to in paragraph (1)(g) have occurred before the day on which the application is made. The Minister must, within 30 days after receiving the application, grant the exemption if no exemption referred to in subsection (1) has been previously granted in respect of the old unit; no exemption referred to in subsection (1) that involved the existing unit has been previously granted; the existing unit referred to in subsection (1) is not a substituted unit referred to in subsection 5(5); and the Minister is satisfied that the requirements set out in subsection (3) are satisfied. Obligation to capture 30% of CO2 emissions A responsible person who has been exempted under subsection (4) in respect of an existing unit must ensure that the conditions of paragraphs (1)(a) to (f), (h) and (i) are satisfied for the portion of the period referred to in paragraph (1)(g) that remains after the occurrence of the period of consecutive months described in paragraph (3)(b). Annual report For each calendar year, a responsible person for each of the following units must, on or before June 1 that follows that calendar year, send an annual report to the Minister that contains the information set out in Schedule 4: a new unit; an old unit; a substituted unit referred to in subsection 5(5); an existing unit referred to in subsection 14(1), if that calendar year is a calendar year included in the remaining portion of the seven consecutive calendar years referred to in subsection 14(5). Electronic report, notice and application A report or notice that is required, or an application that is made, under these Regulations must be sent electronically in the form and format specified by the Minister and must bear the electronic signature of an authorized official of the responsible person. Paper report or notice If the Minister has not specified an electronic form and format or if it is impractical 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, signed by an authorized official of the responsible person, and in the form and format specified by the Minister. However, if no form and format have been so specified, it may be in any form and format. Record-making A responsible person for a unit must make a record of any notice referred to in subsection 4(3), 5(6) or 6(6) or section 12 that was sent to the Minister and the information that was contained in it, as well as any supporting documents; of any application referred to in subsection 5(3), 6(3), 7(3), 8(2), 9(2) or 14(3) and the information referred to in the subsection, as well as any supporting documents; of every direct measure of the flow of, and the concentration of CO2 in, emissions referred to in paragraph 14(1)(e), subsection 20(2) and the descriptions of Enon-ccs in subsection 21(1) and of Eccs in section 22; of every measurement and calculation used to determine a value of an element of a formula set out in any of sections 19 and 21 to 24; that demonstrates that any meter referred to in section 19 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; for each calendar year during which a responsible person used a continuous emission monitoring system referred to in paragraph 20(1)(a), of any document, record or information referred to in section 8 of the Reference Method; that demonstrates that the installation, maintenance and calibration of measuring devices referred to in subsection 25(1) was in accordance with that subsection and subsection 25(3) and of every calibration referred to in subsection 25(2); and of the results of the analysis of every sample collected in accordance with section 27. When records made Records referred to in paragraphs (1)(c) to (h) must be made as soon as feasible but not later than 30 days after the information to be recorded becomes available. Retention of records and reports 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, as well as any supporting documents that relate to the information contained in that record or copy, for at least seven years after they make the record or send the report or notice. The record or copy must be kept at the person’s principal place of business in Canada or at any other place in Canada where it can be inspected. If the record or copy is kept at any of those other places, the person must provide the Minister with the civic address of that other place. Change of address If the civic address referred to in subsection (1) changes, the responsible person must notify the minister in writing within 30 days after the change. Electricity The quantity of electricity referred to in paragraph 3(2)(a) is to be determined in accordance with the following formula: is the gross quantity of electricity that is produced by the unit during the calendar year, expressed in GWh and 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; and is the quantity of electricity that is produced by the unit and used by the power plant in which the unit is located during the calendar year to operate infrastructure and equipment that is attributed to the unit for electricity generation and for separation, but not for pressurization, of CO2, expressed in GWh, determined in accordance with an appropriate method of attribution, based on data collected using meters that comply with the requirements of the Electricity and Gas Inspection Act and the Electricity and Gas Inspection Regulations. Same method of attribution in subsequent years Once a method of attribution is used to make the determination referred to in the description of Gaux for a calendar year, that method of attribution must be used to make that determination for every subsequent calendar year, unless during a subsequent calendar year, a unit located at the power plant ceases to produce electricity or a new unit is added to those located at the power plant; or during a subsequent calendar year, the operation of any unit located at the power plant is integrated with a carbon capture and storage system. Change of method of attribution If paragraph (2)(a) or (b) applies in a subsequent calendar year, the responsible person must, when making the determination referred to in the description of Gaux in subsection (1) for that subsequent calendar year, use a method of attribution that is appropriate to the circumstances described in that paragraph. Subsection (2) applies in respect of that appropriate method of attribution and that subsequent calendar year as if they were, respectively, the method of attribution and the calendar year referred to in that subsection. CEMS or fuel-based methods For the purposes of sections 3 and 15, the quantity of CO2 emissions from the combustion of fossil fuels in a unit for a calendar year is to be determined by using a continuous emission monitoring system (CEMS) in accordance with section 21; or by using a fuel-based method, based on the quantity of carbon in the fossil fuel fed for combustion, in accordance with section 22 and section 23 or 24. Emissions from coal gasification systems If a coal gasification system referred to in subsection 3(4) is used to produce fuel for a unit, the quantity of emissions from the unit referred to in subsection (1) must be determined in accordance with paragraph (1)(a). To the extent that the emissions from the coal gasification system are not captured, transported and stored as described in subsection 3(5), that quantity must be determined for the purpose of subsection 3(1) by using a direct measure of the flow of, and the concentration of CO2 in, those emissions. Quantification If paragraph 20(1)(a) applies, the quantity of CO2 emissions referred to in subsection 20(1) is to be determined in accordance with the following formula: is 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 in accordance with sections 7.1 to 7.7 of the Reference Method; is the quantity of CO2 emissions, expressed in tonnes, from the combustion of biomass in the unit during the calendar year, determined (a)by using a fuel-based method(i)in accordance with paragraph 24(1)(a) or (b), if the unit combusts solid biomass at an average daily rate of less than 3t/day during the given calendar year, and(ii)in accordance with the applicable formula set out in one of paragraphs 23(1)(a) to (c) for the type of biomass combusted, in any other case, or by using a fuel-based method (i)in accordance with paragraph 24(1)(a) or (b), if the unit combusts solid biomass at an average daily rate of less than 3t/day during the given calendar year, and in accordance with paragraph 24(1)(a) or (b), if the unit combusts solid biomass at an average daily rate of less than 3t/day during the given calendar year, and (ii)in accordance with the applicable formula set out in one of paragraphs 23(1)(a) to (c) for the type of biomass combusted, in any other case, or in accordance with the applicable formula set out in one of paragraphs 23(1)(a) to (c) for the type of biomass combusted, in any other case, or (b)by using the method, based on data from the CEMS, described in subsection (2); and by using the method, based on data from the CEMS, described in subsection (2); and is the quantity of CO2 emissions, expressed in tonnes, from the combustion of fuel in the unit, including those emissions referred to in subsection 3(4), during the calendar year — other than the quantity of those emissions as measured by the CEMS and set out in the description of Eu — that is determined using a direct measure of the flow of, and the concentration of CO2 in, the emissions from that combustion of fuel but that is not ultimately captured, transported and stored as described in subsection 3(5). Ebio based on CEMS data For the purpose of determining the value of Ebio, the method, based on data from the CEMS, consists of making the following sequence of determinations: the volume of CO2 emitted from combustion of fuel in the unit for each hour of production of electricity during the calendar year determined in accordance with the following formula: is the average concentration of CO2 in relation to all gases in the stack emitted from the combustion of fuel in the unit during a given hour, “h”, during which the unit produced 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, is the average volumetric flow during that hour, measured on a wet basis by the stack gas volumetric flow monitor, expressed in standard m3, and is the period during which the unit produced electricity, expressed in hours; the volume of CO2 emitted from combustion of fossil fuel in the unit during the calendar year, expressed in standard m3 and referred to in this subsection as Vff, determined in accordance with the following formula:

is the quantity of fossil fuel type “i” combusted in the unit during the calendar year, determined (a)for a solid fuel, in the same manner as the one used in the determination of Mf in the formula set out in paragraph 23(1)(a) and expressed in tonnes, for a solid fuel, in the same manner as the one used in the determination of Mf in the formula set out in paragraph 23(1)(a) and expressed in tonnes, (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 23(1)(b) and expressed in kL, and for a liquid fuel, in the same manner as the one used in the determination of Vf in the formula set out in paragraph 23(1)(b) and expressed in kL, and (c)for a gaseous fuel, in the same manner as the one used in the determination of Vf in the formula set out in paragraph 23(1)(c) and expressed in standard m3, for a gaseous fuel, in the same manner as the one used in the determination of Vf in the formula set out in paragraph 23(1)(c) and expressed in standard m3, is the ith fossil fuel type combusted in the unit during the calendar year, with “i” going from the number 1 to n, where n is the number of fossil fuels so combusted, is the fuel-specific carbon-based F-factor for each fossil fuel type “i” — being, as the case may be, the default value as set out in column 3 of the table to subsection (3) for that fuel type set out in column 2 or determined for that fuel type in accordance with Appendix A of the Reference Method — expressed in standard m3 of CO2/GJ, — expressed in GJ/tonne, for a solid fuel, in GJ/kL, for a liquid fuel, and in GJ/standard m3, for a gaseous fuel — is, for each fossil fuel type “i”, (a)the default higher heating value set out in column 2 of Schedule 5 for that fuel type set out in column 1, and the default higher heating value set out in column 2 of Schedule 5 for that fuel type set out in column 1, and (b)in the absence of a default higher heating value for that fuel type referred to in paragraph (a), a default higher heating value for that fuel type established by a body that is internationally recognized as being competent to establish default higher heating values for fuels; in the absence of a default higher heating value for that fuel type referred to in paragraph (a), a default higher heating value for that fuel type established by a body that is internationally recognized as being competent to establish default higher heating values for fuels; the volume of CO2 emitted from the combustion of biomass in the unit during the calendar year, expressed in standard m3 and referred to in this subsection as Vbio, determined in accordance with the following formula: is the sum of the volumes of CO2 emitted from combustion of fuel in the unit during each hour of production of electricity during the calendar year, as determined under paragraph (a), and is Vff determined in accordance with the formula set out in paragraph (b); and the quantity of the CO2 emissions from the combustion of biomass in the unit during the calendar year, namely Ebio determined in accordance with the formula set out in subsection (1), based on the following two determinations: the fraction of the volume of CO2 emissions from all fuel combusted in the unit attributable to the combustion of biomass in the unit during the calendar year, referred to in this section as Biofr, determined in accordance with the following formula: is the volume of CO2 emitted from the combustion of biomass in the unit during the calendar year determined in accordance with the formula set out in paragraph (c), is the value of VT determined in accordance with the formula set out in paragraph (c), and the quantity of CO2 emissions described by Ebio determined in accordance with the following formula: is the fraction of the volume of CO2 emissions from all fuel combusted in the unit attributable to the combustion of biomass in the unit during the calendar year determined in accordance with the formula set out in subparagraph (i), is the value of Eu determined in the formula set out in subsection (1), and is 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: is the quantity of calcium carbonate (CaCO3) or other sorbent material so used, expressed in tonnes, is the stoichiometric ratio, on a mole fraction basis, of CO2 released on usage of one mole of sorbent material, where R=1 if the sorbent material is CaCO3, and is the molecular mass of the sorbent material, where MMs = 100 if the sorbent material is CaCO3. Default F-factor The default value for the fuel-specific carbon-based F-factor for certain types of fossil fuel is set out in column 3 of the following table: Common stack — disaggregation Despite subsection (1), if there is one or more other units at a power plant where a unit is located and a CEMS measures emissions from that unit and from one or more of those 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 for the purpose of subsection (1) 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: is the quantity of fuel type “j” combusted in that unit “u” during the calendar year, determined (c)for a gaseous fuel, in the same manner as the one used in the determination of Vf in the formula set out in paragraph 23(1)(c) and expressed in standard m3; for a gaseous fuel, in the same manner as the one used in the determination of Vf in the formula set out in paragraph 23(1)(c) and expressed in standard m3; is the higher heating value, determined in accordance with section 24 and expressed in the applicable unit of measure referred to in that section of fuel type “j” combusted during the calendar year in that unit “u”; is the ith unit located at the power plant with “i” going from the number 1 to n, where n is the number of units that share a common stack; is the jth fuel type, including types of biomass, combusted during the calendar year in a unit located at the power plant with “j” going from the number 1 to m, where m is the number of those fuel types; is the quantity of fuel type “j” combusted in each unit “i” during the calendar year, determined for a solid fuel, a liquid fuel and a gaseous fuel, respectively, in the manner set out in the description of Quj; is the higher heating value, determined in accordance with section 24 and expressed in the applicable unit of measure referred to in that section, of fuel type “j” combusted during the calendar year in unit “i”; and is the quantity of CO2 emissions, expressed in tonnes, from the combustion of fuels in all the units during the calendar year, measured by a CEMS at the common stack in accordance with subsection 21(1). Determination If paragraph 20(1)(b) applies, the quantity of CO2 emissions referred to in subsection 20(1) is to be determined by the following formula: is the quantity of CO2 emissions attributable to the combustion of fossil fuel of type “i” in the unit during the calendar year, expressed in tonnes, determined for that fuel type in accordance with section 23 or 24; is the ith type of fossil fuel combusted in the unit during the calendar year, with “i” going from the number 1 to n, where n is the number of types of fossil fuel so combusted; is Es determined in accordance with the formula set out in subparagraph 21(2)(d)(ii); and is the quantity of CO2 in those emissions, expressed in tonnes, from the combustion of fuel in the unit, during the calendar year, that are captured in accordance with the laws of Canada or a province that regulate that capture and that are transported and stored in accordance with the laws of Canada or a province, or of the United States or one of its states, that regulate that transportation or storage, as the case may be, that quantity being determined using a direct measure of the flow of, and the concentration of CO2 in, those emissions. Measured carbon content Subject to section 24, the quantity of CO2 emissions attributable to the combustion of a fuel in a unit during a calendar year, expressed in tonnes, is determined in accordance with the applicable formula, as follows: for a solid fuel is the mass of the fuel combusted during the calendar year as determined, as the case may be, on a wet or dry basis, expressed in tonnes and measured by a measuring device, and is the weighted average, expressed in kg of carbon per kg of the fuel, of the carbon content of the fuel determined in accordance with subsection (2) on the same wet or dry basis as the one used in the determination of Mf; for a liquid fuel is the volume of the fuel combusted during the calendar year, expressed in kL, determined by using flow meters, and is the weighted average, expressed in tonnes of carbon per kL of the fuel, of the carbon content of the fuel determined in accordance with subsection (2) at the same temperature as the one used in the determination of Vf; and for a gaseous fuel is the volume of the fuel combusted during the calendar year, expressed in standard m3, determined by using flow meters, is the weighted average, expressed in kg of carbon per kg of the fuel, of the carbon content of the fuel determined in accordance with subsection (2), is the average molecular mass of the fuel, expressed in kg per kg-mole of the fuel, determined based on fuel samples collected in accordance with section 27, and is the molar volume conversion factor, namely 23.645 standard m3 per kg-mole of the fuel at standard conditions of 15°C and 101.325 kPa. Weighted average The weighted average referred to in paragraphs (1)(a) to (c) as CCA is, based on fuel samples collected in accordance with section 27, to be determined in accordance with the following formula: is the carbon content of, as the case may be, the composite sample, or the sample, of the fuel for the ith sampling period expressed for solid fuels, liquid fuels and gaseous fuels, respectively, in the same unit of measure as the one set out in CCA, as provided by the supplier of the fuel to the responsible person and, if not so provided, as determined by the responsible person, and measured (a)for a solid fuel, on the same wet or dry basis as the one used in the determination of CCA, in accordance with,(i)for coal, biomass or solid fuel derived from waste, ASTM D5373 - 08, entitled Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal, and(ii)for any other solid fuel,(A)an applicable ASTM standard for the measurement of the carbon content of the fuel, and(B)if no such ASTM standard applies, an applicable internationally recognized method for the measurement of the carbon content of the fuel, for a solid fuel, on the same wet or dry basis as the one used in the determination of CCA, in accordance with, (i)for coal, biomass or solid fuel derived from waste, ASTM D5373 - 08, entitled Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal, and for coal, biomass or solid fuel derived from waste, ASTM D5373 - 08, entitled Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal, and (ii)for any other solid fuel,(A)an applicable ASTM standard for the measurement of the carbon content of the fuel, and(B)if no such ASTM standard applies, an applicable internationally recognized method for the measurement of the carbon content of the fuel, for any other solid fuel, (A)an applicable ASTM standard for the measurement of the carbon content of the fuel, and an applicable ASTM standard for the measurement of the carbon content of the fuel, and (B)if no such ASTM standard applies, an applicable internationally recognized method for the measurement of the carbon content of the fuel, if no such ASTM standard applies, an applicable internationally recognized method for the measurement of the carbon content of the fuel, (b)for a liquid fuel, in accordance with any of the following standards or methods that applies for the measurement of the carbon content of the fuel:(i)ASTM D3238 - 95(2010), entitled Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method, along with either of the following applicable ASTM standards:(A)ASTM D2503 - 92(2007), entitled Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure, and(B)ASTM D2502 - 04(2009), entitled Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils From Viscosity Measurements,(ii)ASTM D5291 - 10, entitled Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants, and(iii)if no such ASTM standard applies, an applicable internationally recognized method, and for a liquid fuel, in accordance with any of the following standards or methods that applies for the measurement of the carbon content of the fuel: (i)ASTM D3238 - 95(2010), entitled Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method, along with either of the following applicable ASTM standards:(A)ASTM D2503 - 92(2007), entitled Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure, and(B)ASTM D2502 - 04(2009), entitled Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils From Viscosity Measurements, ASTM D3238 - 95(2010), entitled Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method, along with either of the following applicable ASTM standards: (A)ASTM D2503 - 92(2007), entitled Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure, and ASTM D2503 - 92(2007), entitled Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure, and (B)ASTM D2502 - 04(2009), entitled Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils From Viscosity Measurements, ASTM D2502 - 04(2009), entitled Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils From Viscosity Measurements, (ii)ASTM D5291 - 10, entitled Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants, and ASTM D5291 - 10, entitled Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants, and (iii)if no such ASTM standard applies, an applicable internationally recognized method, and if no such ASTM standard applies, an applicable internationally recognized method, and (c)for a gaseous fuel,(i)in accordance with either of the following ASTM standards that applies for the measurement of the carbon content of the fuel:(A)ASTM D1945 - 03(2010), entitled Standard Test Method for Analysis of Natural Gas by Gas Chromatography, and(B)ASTM D1946 - 90(2011), entitled Standard Practice for Analysis of Reformed Gas by Gas Chromatography, or(ii)by means of a direct measuring device that determines the carbon content of the fuel; for a gaseous fuel, (i)in accordance with either of the following ASTM standards that applies for the measurement of the carbon content of the fuel:(A)ASTM D1945 - 03(2010), entitled Standard Test Method for Analysis of Natural Gas by Gas Chromatography, and(B)ASTM D1946 - 90(2011), entitled Standard Practice for Analysis of Reformed Gas by Gas Chromatography, or in accordance with either of the following ASTM standards that applies for the measurement of the carbon content of the fuel: (A)ASTM D1945 - 03(2010), entitled Standard Test Method for Analysis of Natural Gas by Gas Chromatography, and ASTM D1945 - 03(2010), entitled Standard Test Method for Analysis of Natural Gas by Gas Chromatography, and (B)ASTM D1946 - 90(2011), entitled Standard Practice for Analysis of Reformed Gas by Gas Chromatography, or ASTM D1946 - 90(2011), entitled Standard Practice for Analysis of Reformed Gas by Gas Chromatography, or (ii)by means of a direct measuring device that determines the carbon content of the fuel; by means of a direct measuring device that determines the carbon content of the fuel; is the ith sampling period referred to in section 27, with “i” going from the number 1 to n, where n is the number of those sampling periods; and is the mass or volume, as the case may be, of the fuel combusted during the ith sampling period, expressed (a)for a solid fuel, in tonnes, on the same wet or dry basis as the one used in the determination of CCA, for a solid fuel, in tonnes, on the same wet or dry basis as the one used in the determination of CCA, (b)for a liquid fuel, in kL, and for a liquid fuel, in kL, and (c)for a gaseous fuel, in standard m3. for a gaseous fuel, in standard m3. Quantification based on HHV For an eligible fuel referred to in subsection (2), the quantity of CO2 emissions attributable to the combustion of the fuel in a unit during a calendar year, expressed in tonnes, may be determined in accordance with subsection (4) based on the following higher heating value of the fuel: the higher heating value of the fuel that is measured in accordance with subsection (6) as provided by the supplier of the fuel to the responsible person but, if not so provided, as so measured by the responsible person; and in the absence of a measured higher heating value of the fuel referred to in paragraph (a), the default higher heating value, set out in column 2 of Schedule 5, for the fuel’s type, as set out in column 1 but, in the absence of that default higher heating value, a default higher heating value for that fuel type established by a body that is internationally recognized as being competent to establish default higher heating values for fuels. Eligible fuels Eligible fuels are a fuel combusted in a unit in respect of which an exemption from the application of subsection 3(1) has been granted under subsection 7(4); a fuel referred to in section 23 that is combusted during the calendar year at less than any of the average daily rates referred to in subsection (3); a fuel listed in Table 4 to Schedule 5; and a fuel combusted in a standby unit. Average daily rates The average daily rates are for a solid fuel, 3 t/day; for a liquid fuel, 1900 L/day; and for a gaseous fuel, 500 standard m3/day. Quantity of emissions The quantity of emissions is to be determined in accordance with the following formula: is the quantity of the fuel combusted in the unit during the calendar year determined — expressed in GJ/tonne, for a solid fuel, in GJ/kL, for a liquid fuel, and in GJ/standard m3, for a gaseous fuel — is (a)if paragraph (1)(a) applies, the weighted average higher heating value of the fuel, determined in accordance with subsection (5), based on fuel samples collected in accordance with section 27, and if paragraph (1)(a) applies, the weighted average higher heating value of the fuel, determined in accordance with subsection (5), based on fuel samples collected in accordance with section 27, and (b)if paragraph (1)(b) applies, the default higher heating value, set out in column 2 of Schedule 5, for the fuel’s type, as set out in column 1 and, in the absence of that default higher heating value, a default higher heating value for that fuel type established by a body that is internationally recognized as being competent to establish default higher heating values for fuels; and if paragraph (1)(b) applies, the default higher heating value, set out in column 2 of Schedule 5, for the fuel’s type, as set out in column 1 and, in the absence of that default higher heating value, a default higher heating value for that fuel type established by a body that is internationally recognized as being competent to establish default higher heating values for fuels; and is the default CO2 emission factor, set out in column 3 of Schedule 5, for that fuel listed in column 1 and, in the absence of that default CO2 emission factor, a default CO2 emission factor for that fuel established by a body that is internationally recognized as competent to establish default CO2 emission factors for fuels. The weighted average higher heating value of the fuel is determined in accordance with the following formula: is the higher heating value of, as the case may be, each composite sample, or sample, of the fuel for the ith sampling period measured in accordance with subsection (6), as provided by the supplier of the fuel to the responsible person but, if not so provided, as so measured by the responsible person; (c)for a gaseous fuel, in the same manner as the one used in the determination of Vf in the formula set out in paragraph 23(1)(c) and expressed in standard m3. for a gaseous fuel, in the same manner as the one used in the determination of Vf in the formula set out in paragraph 23(1)(c) and expressed in standard m3. Measurement of HHV The higher heating value of a fuel is to be measured for a solid fuel that is coal or biomass, in accordance with ASTM D5865 - 13, entitled Standard Test Method for Gross Calorific Value of Coal and Coke, a fuel from waste, in accordance with ASTM D5865 - 13, and any other solid fuel type, in accordance with an applicable ASTM standard for the measurement of the higher heating value of the fuel, and if no such ASTM standard applies, in accordance with an applicable internationally recognized method; and for a liquid fuel that is an oil or a liquid fuel derived from waste, in accordance with ASTM D240 - 09, entitled Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, or ASTM D4809 - 09a, entitled Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), and any other liquid fuel type, in accordance with any of the following applicable ASTM or GPA standards: ASTM D1826 - 94(2010), entitled Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, ASTM D3588 - 98(2003), entitled Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels, ASTM D4891 - 89(2006), entitled Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion, GPA Standard 2172 - 09, entitled Calculation of Gross Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer, and GPA standard 2261 - 00, entitled Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography, or by means of a direct measuring device that determines 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 the corresponding higher heating values. Measuring devices — installation, maintenance and calibration A responsible person for a unit must install, maintain and calibrate any measuring device — other than a CEMS referred to in paragraph 20(1)(a) and any measuring device that is subject to the Electricity and Gas Inspection Act — that is used for the purpose of section 3 or 15 in accordance with the manufacturer’s instructions or any applicable generally recognized national or international industry standard. Frequency of calibration The responsible person must calibrate each of those measuring devices at the greater of the following two frequencies: at least once in every calendar year but at least five months after a previous calibration, and the minimum frequency recommended by the manufacturer. Accuracy of measurements Each of those measuring devices must enable measurements to be made with a margin of error of ± 5%. CEMS A responsible person who uses a CEMS referred to in paragraph 20(1)(a) for the purpose of section 3 or 15 must ensure that the Reference Method is complied with. Certification Before a CEMS referred to in paragraph 20(1)(a) is used for the purpose of that paragraph, it must be certified by the responsible person in accordance with section 5 of the Reference Method. Annual audit For each calendar year during which a responsible person uses a CEMS referred to in paragraph 20(1)(a), an auditor must assess, based on the review referred to in section 6.5.2 of the Reference Method, whether, in the auditor’s opinion, the responsible person’s use of the CEMS complied with the Quality Assurance/Quality Control manual referred to in section 6 of the Reference Method; ensure that the Quality Assurance/Quality Control manual has been updated in accordance with sections 6.1 and 6.5.2 of the Reference Method; and assess whether, in the auditor’s opinion, 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. Auditor’s report The responsible person must obtain a report, signed by the auditor, that contains the information set out in Schedule 6 and send the auditor’s report to the Minister with their annual report referred to in section 15. Fuel sampling The determination of the value for the elements related to carbon content and higher heating values referred to in sections 21 to 24 must be based on fuel samples taken in accordance with this section. Frequency Each fuel sample must be taken at a time and location in the fuel handling system of the power plant that provides the following representative sample of the fuel combusted at the following minimum frequency: for coal other than synthetic gas derived from coal or derived from petroleum coke, one composite sample, during each week that the unit produces electricity, that is prepared in accordance with ASTM D2013 / D2013M - 11, entitled Standard Practice for Preparing Coal Samples for Analysis, and that consists of sub-samples taken at least twice from coal that was fed for combustion during that week and at least 48 hours apart, in accordance with ASTM D2234 / D2234M - 10, entitled Standard Practice for Collection of a Gross Sample of Coal, or ASTM D7430 - 11ae1, entitled Standard Practice for Mechanical Sampling of Coal; for a type of solid fuel other than coal, one composite sample per month that consists of sub-samples of fuel of that type, each having the same mass, that were taken from fuel that was fed for combustion during each week that begins in that month and during which the unit produces electricity and that were taken at least 48 hours after any previous sub-sample and after all fuel treatment operations had been carried out but before any mixing of the fuel from which the sub-sample is taken with other fuels; for a type of liquid fuel and of a gaseous fuel other than natural gas, one sample per quarter, with each sample of fuel of that type being taken at least one month after any previous sample has been taken; and for natural gas, two samples per calendar year, with each sample being taken at least four months after any previous sample has been taken. Additional samples For greater certainty, the responsible person who takes, for the purpose of these Regulations, more samples than the minimum required under subsection (2) must make the determination referred to in subsection (1) based on each sample — and, in the case of composite samples, each sub-sample — taken, including those additional samples. Missing Data Subject to subsections (2) and (3), if, for any reason beyond the responsible person’s control, the emission-intensity referred to in subsection 3(1) cannot be determined in accordance with a formula set out in any of sections 19 and 21 to 24 because data required to determine the value of an element of that formula has not been obtained for a given period during a calendar year, replacement data for that given period obtained in accordance with an appropriate method must be used to determine that value. Replacement data — CEMS If a CEMS referred to in paragraph 20(1)(a) is used for the determination of an element of a formula set out in section 21 but data has not been obtained for that determination during a given period, the replacement data is to be obtained in accordance with section 3.5.2 of the Reference Method. Replacement data — Fuel-based methods If a fuel-based method referred to in paragraph 20(1)(b) is used for the determination of an element — related to the higher heating value, carbon content or molecular mass of a fuel — of a formula set out in any of sections 21 to 24 for which data has not been obtained during a given period, the replacement data is to be the average of the determinations for that element, using the fuel-based method in question, during the equivalent period prior to and, if available, subsequent to that given period. However, if the determination of that element is not available during the equivalent period prior to that given period, the replacement data is to be the determination for that element, using the fuel-based method in question, during the equivalent period subsequent to the given period. Replacement data — multiple periods During a calendar year, there may be more than one given period, but replacement data may be obtained under subsection (1) or (3) for a maximum of 28 days during the calendar year, distributed among any or all of those periods. July 1, 2015 Subject to subsections (2) and (3), these Regulations come into force on July 1, 2015. January 1, 2013 Sections 1, 2 and 4, subsections 5(1) to (4) and sections 9 to 14 and 29 come into force on January 1, 2013. January 1, 2030 Section 3, in respect of standby units, comes into force on January 1, 2030. The following information respecting the responsible person: an indication of whether they are the owner or operator of the unit and their name and civic address; the name, title, civic and postal addresses, telephone number and, if any, email address and fax number, of their authorized official; and 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. The following information respecting the unit: for each responsible person for the unit, other than the responsible person mentioned in paragraph 1(a), if any their name and civic address, an indication of whether they are an owner or operator, and in the case of an owner, their percentage of ownership interest; its name and civic address, if any; if applicable, its National Pollutant Release Inventory identification number assigned by the Minister for the purpose of section 48 of the Act; for an existing or old unit, the calendar year in which it reaches, or has reached, the end of its useful life; its commissioning date; and its production capacity. The following information respecting the capture element of the carbon capture and storage system: a description of how the emissions are to be captured, including a preliminary engineering design and a description of the preferred technology and processes to be used; a description of the principal modifications to the unit that are needed for its integration with the capture element to enable the responsible person to comply with subsection 3(1) of these Regulations; an identification of any major equipment to be installed and of any other significant equipment to be modified or replaced; process flow diagrams and mass and energy balances, including external energy inputs; a summary of auxiliary energy loads; an estimate of the unit’s production capacity when it is operating with an integrated capture element; an estimate of the unit’s gross quantity of electricity produced for a calendar year — set out in the description of Ggross in subsection 19(1) of these Regulations — when it is operating with an integrated capture element; an estimate of the rate of capture of CO2 emissions and of the volume of CO2 emissions, expressed in standard m3, to be captured for a calendar year and for the operating life of the unit; a preliminary resource analysis for the unit when it is operating with an integrated capture element, including water consumption, heat and power consumption, raw material consumption and fuel consumption; documents establishing that adequate space has been set aside at the power plant in which the unit is located and that adequate access is to be provided for the purpose of installing the required equipment, including site plans that show the outline and location of all significant electricity generating equipment, carbon capture equipment and compression equipment, as well as any ancillary equipment necessary, sized to capture the sufficient volume of CO2 referred to in subparagraph 9(2)(c)(i) of these Regulations, all areas that are to be used for carrying out the construction of the capture element, and the point of exit of the pipeline to transport the captured CO2 emissions from the power plant to the storage site, if the captured CO2 emissions are not stored at the power plant; an identification of the potential risks and obstacles, based on the preferred capture technology, to the construction and operation of the capture element integrated with the unit; a list of each environmental, safety and other approval or permit that is required for the construction or operation of the unit integrated with the capture element; and a list of potential suppliers of equipment, materials or services that are needed for the construction and operation of the unit integrated with the capture element. The following information respecting the transportation element of the carbon capture and storage system: an identification of, and justification for, one or more preferred transport methods and routes to an appropriate geological storage site referred to in paragraph 3(b), supported by a routing map and a geographic information system (GIS) file for each method and route; the expected location and size of pumping stations, of receipt and delivery points and of any interconnects on the pipeline for each preferred route; an estimation of the diameter of the pipeline for each preferred route that is required to transport the sufficient volume of CO2 referred to in subparagraph 9(2)(c)(i) of these Regulations; if applicable, a detailed description of how any tankers that are to be used to transport the captured CO2 emissions are to be obtained and, if required, commissioned and a plan detailing how any required port infrastructure for shipping the captured CO2 emissions on those tankers is to be developed; an identification of the potential risks and obstacles, for each preferred route, to the construction and operation of the pipeline or shipping network along that route, including any surface or subsurface land use that may conflict with that construction or operation, along with an explanation of how those risks and obstacles are to be overcome ; a list of each environmental, safety and other approval or permit that is required for the construction or operation of the transportation element; and a list of potential suppliers of equipment, materials or services that are needed for the construction and operation of the transportation element. The following information respecting the storage element of the carbon capture and storage system: an estimation of the volume of CO2 emissions, expressed in standard m3, to be captured and stored during each calendar year and over the anticipated operating life of the unit; an identification of one or more suitable geological sites for storage that are expected to be used to store the captured CO2 emissions, supported by a delineation of the geographical extent of each storage site and at least one study showing that the required capacity to store the sufficient volume of CO2 referred to in subparagraph 9(2)(c)(i) of these Regulations is available based on generally accepted national or international protocols for storage capacity estimation; an identification of any requirement under federal or provincial laws for the purity of captured CO2 emissions, along with an explanation of how that requirement is to be met; a preliminary assessment of the integrity of the storage element in preserving an impervious barrier to leakage of stored CO2 emissions and of any risk to breaching that integrity, at each feasible storage site referred to in paragraph (b), along with a preliminary strategy to mitigate the risk; a preliminary plan for measuring and verifying the volume of stored CO2 emissions and for monitoring any leak of the stored CO2 emissions from the storage element; an identification of any surface or subsurface land use that may conflict with the operation of the storage element at each feasible storage site referred to in paragraph (b), along with an explanation of how the conflict is to be resolved in order to ensure access to each of those sites; a list of each environmental, safety and other approval or permit that is required for the construction or operation of the storage element; and a list of potential suppliers of equipment, materials or services that are needed for the construction and operation of the storage element for each feasible site referred to in paragraph (b). If a front end engineering design study referred to in paragraph 10(a) of these Regulations has been carried out, the following information to summarize that study: an overall description of the construction project for the carbon capture and storage system, including technical drawings and documents that describe the configuration and layout of the power plant in which the unit is located when it is operating with an integrated capture element of the system, the transportation element of the system, and the site of the storage element of the system; an estimate of capital cost of the construction project, including a summary of the analysis that led to that estimate and a justification for the margin of error of that estimate; a summary of the safety review of the capture element of the carbon capture and storage system; a summary of the risk assessment of the carbon capture and storage system; a summary of the strategy to mitigate those risks; a summary of the plan to carry out the construction of the carbon capture and storage system, including a schedule for the completion of its major steps; an identification of potential persons with whom agreements can be entered into to carry out the construction of the carbon capture and storage system; the name and business address of the persons responsible for the development of the front end engineering design study and a description of their contribution to its development; a description of the capture technology selected in the front end engineering design study for the capture element of the carbon capture and storage system and of the capture element’s integration with the unit; an identification of any major equipment required to be purchased for the construction of the capture element of the carbon capture and storage system; an estimate of the performance of the unit when it is operating with an integrated carbon capture and storage system, supported by process flow diagrams and mass and energy balances, including an estimate of the rate of capture of CO2 emissions and the volume of CO2 emissions, expressed in standard m3, to be captured for a calendar year and for the operating life of the unit, the production capacity of the unit, the unit’s gross quantity of electricity produced for a calendar year — as set out in the description of Ggross in subsection 19(1) of these Regulations — when it is operating with an integrated capture element, a summary of auxiliary energy loads, the period during a calendar year during which a unit is expected to be available for producing electricity, and for a calendar year, the quantity of CO2 emissions from the combustion of fossil fuels in the unit and the quantity of emissions of nitrogen oxides, sulphur oxides, particulate matter, mercury and, if applicable, ammonia from the unit; and a summary of the resource analysis for the unit when it is operating with an integrated capture element of the carbon capture and storage system, including water consumption, heat and power consumption, raw material consumption and fuel consumption. If any major equipment that is necessary for the capture element referred to in paragraph 10(b) of these Regulations has been purchased, a copy of the purchase orders and receipts respecting the purchase of that equipment. A declaration, signed by all contracting parties to any contract referred to in paragraph 10(c) of these Regulations, that indicates that the contract has been entered into and the date on which it was entered into. A copy of any permit or approval referred to in paragraph 10(d) that has been obtained. A declaration — signed by the responsible person and, if applicable, any party contracting with the responsible person for the capture, transportation or storage elements of the carbon capture and storage system — that indicates the date on which CO2 emissions from the combustion of fossil fuels in the unit have been captured in accordance with the laws of Canada or a province that regulate that capture and have been transported and stored in accordance with the laws of Canada or a province, or of the United States or one of its states, that regulate that transportation or storage, as the case may be. its registration number and, if applicable, its National Pollutant Release Inventory identification number assigned by the Minister for the purpose of section 48 of the Act; if applicable, the number of other units located at the power plant in which the unit is located and, for each of those other units, the information referred to in paragraph (a); and if applicable, a statement that indicates that the unit shares a common stack with one or more of those other units, along with a statement that identifies each of those other units. The following information respecting the emission-intensity referred to in subsection 3(1) of these Regulations from the combustion of fuel in the unit — other than a unit referred to in paragraph 4(d) — during the calendar year: the emission-intensity for the unit, namely the ratio of the quantity of CO2 emissions referred to in paragraph (c) to the quantity of electricity referred to in subparagraph (b)(i), expressed in tonnes per GWh; in respect of the quantity of electricity produced by the unit that quantity determined in accordance with section 19 of these Regulations, expressed in GWh, the value determined for Ggross and Gaux in the formula set out in subsection 19(1) of these Regulations, expressed in GWh, the gross electricity produced by the units located at the power plant for the calendar year, namely the sum of the value determined for Ggross referred to in subparagraph (ii) and of the gross electricity produced by all other units located at the power plant determined in accordance with that description of Ggross, the quantity of electricity, expressed in GWh, that is used by the power plant in which the unit is located during the calendar year to operate infrastructure and equipment for electricity generation and for separation, but not pressurization, of CO2, based on data collected using meters that comply with the requirements of the Electricity and Gas Inspection Act and the Electricity and Gas Inspection Regulations, if that calendar year is the calendar year referred to in subsection 19(2) of these Regulations for which a method of attribution was first used, a detailed description of that method of attribution and an explanation of why it is appropriate, and if that calendar year is a subsequent calendar year referred to in subsection 19(3) of these Regulations, a detailed description of the method of attribution referred to in that subsection used for that subsequent calendar year and an explanation of why it is appropriate;

in respect of the quantity of CO2 emissions from the combustion of fuels in the unit, if paragraph 20(1)(a) of these Regulations applies for the determination of that quantity, that quantity, expressed in tonnes, determined in accordance with section 21 of these Regulations, the values, expressed in tonnes, determined for Eu, Ebio and Enon-ccs in the formula set out in subsection 21(1) of these Regulations, a statement that indicates which of paragraphs (a) and (b) of the description of that Ebio was used to determine the value of that element, and the value, expressed in tonnes, determined for Es in the formula set out in subparagraph 21(2)(d)(ii) of these Regulations, and if paragraph 20(1)(b) of these Regulations applies for the determination of that quantity, that quantity, expressed in tonnes, determined in accordance with section 22 of these Regulations and, as the case may be, section 23 or 24 of these Regulations, the values, expressed in tonnes, determined for Ei for each fuel combusted, and for Eccs, in the formula in section 22 of these Regulations, the value, expressed in tonnes, determined for Es in the formula set out in subparagraph 21(2)(d)(ii) of these Regulations, a statement for each fuel combusted that indicates which of section 23 and 24 of these Regulations was used to determine the quantity referred to in clause (A), if that quantity was determined in accordance with section 23 of these Regulations, the value of CCA in the formula set out in paragraph 23(1)(a), (b) or (c) of these Regulations, as the case may be, for each fuel combusted, and a statement that indicates which of the ASTM standards and of the methods referred to in the description of CCi in the formula in subsection 23(2) of these Regulations were used to determine the value of CCA referred to in subclause (I) or, for a sample of gaseous fuel, that indicates that a direct measuring device was used to determine that value, and if that quantity was determined in accordance with section 24 of these Regulations, for each fuel combusted, its type, a statement that indicates which of paragraphs 24(2)(a) to (d) of these Regulations describes the fuel, and in the case of a fuel described by paragraph 24(2)(b) of these Regulations, the average daily rate at which the fuel was combusted, if paragraph 24(1)(a) of these Regulations applies, the value of HHV, as described in paragraph (a) of that element, in the formula set out in subsection 24(4) of these Regulations, for each fuel combusted, if the fuel’s type is set out in column 1 of the applicable table to Schedule 5, its default CO2 emission factor as set out in column 3 and, if that fuel’s type is not so set out, the default CO2 emission factor for that fuel’s type established by a body that is internationally recognized as being competent to establish default CO2 emission factors for fuels and a statement that indicates the name of the body, and a statement that indicates which of the ASTM and GPA standards and of the methods referred to in subsection 24(6) of these Regulations were used to determine the measured value of HHV referred to in sub-subclause 1 or, for a gaseous fuel, that indicates that a direct measuring device was used to determine that measured value, and if paragraph 24(1)(b) of these Regulations applies the default value of HHV, as described in paragraph (b) of that element, in the formula set out in subsection 24(4) of these Regulations, for each fuel combusted, a statement that explains the absence of a measured higher heating value and that indicates, if that default higher heating value is established by a body that is internationally recognized as being competent to establish default higher heating values for fuels, the name of the body, and if the fuel’s type is set out in column 1 of the applicable table to Schedule 5, its default CO2 emission factor as set out in column 3 and, if that fuel’s type is not so set out, the default CO2 emission factor for that fuel’s type established by a body that is internationally recognized as being competent to establish default CO2 emission factors for fuels and a statement that indicates the name of the body; if applicable, documents that establish that the captured CO2 emissions were captured, transported and stored as described in subsection 3(5) of these Regulations; if applicable, the quantity of CO2 emissions that were captured, determined using a direct measure of the flow of, and the concentration of CO2 in, those emissions; and for each type of fuel combusted, 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 the quantity of fuel combusted. Information for the calendar year respecting the number of hours during which the unit produced electricity; if a substituted unit referred to in subsection 5(1) of these Regulations has been substituted for an original unit, the production capacity of that substituted unit; for a standby unit, the capacity factor for the standby unit; for a unit granted an exemption under subsection 7(4) of these Regulations, the emergency period for the calendar year, namely, the period that begins on the first day in the calendar year on which the emergency existed and that ends on the last day in the calendar year on which it existed, the number of hours in the emergency period during which the unit operated, and the information referred to in item 3 for each emergency period for, and any other period of, the calendar year; and for an existing unit referred to in subsection 14(4) of these Regulations, the percentage of CO2 emissions from the unit that are captured, transported and stored, along with supporting documents to establish the validity of that percentage. A copy of the auditor’s report referred to in subsection 26(4) of these Regulations. If replacement data referred to in section 28 of these Regulations was used for a day or days for a given period referred to in subsection 28(1) of these Regulations during the calendar year, the reason for which data required to determine the value of an element of a formula set out in section 19 or any of sections 21 to 24 of these Regulations was not obtained and an explanation as to why that reason was out of the control of the responsible person; the element of the formula for which data was not obtained and the date of the day on which the data was not obtained and, if that data was not obtained for a period of several days, the dates of the days on which the period begins and ends; and the value determined for that element using replacement data, along with details of that determination, including the data used to make that determination for each period of one or several days, the method used to obtain that data, and in the case of a determination of the value of an element referred to in subsection 28(3) of these Regulations for a given period, a justification for the given period being used as the basis of that determination. The default higher heating values for wood and wood waste, agricultural byproducts and peat are on a totally dry basis. The default higher heating values for the other types of fuel are on a wet basis. 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. The default higher heating value for pipeline quality natural gas is expressed in GJ/standard m3 The name, civic address and telephone number of the responsible person. The name, civic address, telephone number and qualifications of the auditor and, if any, the auditor’s fax number and email address. The procedures followed by the auditor to assess whether the responsible person’s use of the CEMS complied with the Quality Assurance/Quality Control manual referred to in section 6 of the Reference Method; and the responsible person complied with the Reference Method and the CEMS meets the specifications set out in the Reference Method, in particular, in its sections 3 and 4. A declaration of the auditor’s opinion as to whether the responsible person’s use of the CEMS complied with the Quality Assurance/Quality Control Manual referred to in section 6 of the Reference Method; and the responsible person complied with the Reference Method and the CEMS has met the specifications set out in the Reference Method, in particular, in its sections 3 and 4. A statement of the auditor’s opinion as to whether the responsible person has ensured that the Quality Assurance/Quality Control manual was updated in accordance with sections 6.1 and 6.5.2 of the Reference Method. The Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations3 are repealed. SOR/2012-167